COMMISSION STAFF WORKING DOCUMENT IMPACT ASSESSMENT Accompanying the document Proposal for a Directive of the European Parliament and of the Council on common rules for the internal market in electricity (recast), etc.

EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 3/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
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TABLE OF CONTENTS
1. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(A):
LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES......................4
1.1. Priority access and dispatch ..............................................................................................................4
Summary table.................................................................................................................................4
Description of the baseline ..............................................................................................................5
Deficiencies of the current legislation .............................................................................................6
Presentation of the options .............................................................................................................9
Comparison of the options ............................................................................................................11
Subsidiarity.....................................................................................................................................14
Stakeholders' opinions...................................................................................................................14
1.2. Regulatory exemptions from balancing responsibility.....................................................................17
Summary table...............................................................................................................................18
Description of the baseline ............................................................................................................19
Deficiencies of the current legislation ...........................................................................................20
Presentation of the options ...........................................................................................................22
Comparison of the options ............................................................................................................24
Subsidiarity.....................................................................................................................................25
Stakeholders' opinions...................................................................................................................26
1.3. RES E access to provision of non-frequency ancillary services .........................................................29
Summary table...............................................................................................................................30
Description of the baseline ............................................................................................................31
Deficiencies of the current legislation ...........................................................................................33
Presentation of the options ...........................................................................................................34
Comparison of the options ............................................................................................................35
Subsidiarity.....................................................................................................................................36
Stakeholders' opinions...................................................................................................................37
2. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(B)
STRENGTHENING SHORT-TERM MARKETS..................................................................39
2.1. Reserves sizing and procurement....................................................................................................41
Summary table...............................................................................................................................42
Description of the baseline ............................................................................................................43
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation) .........................47
Presentation of the options ...........................................................................................................48
Comparison of the options ............................................................................................................49
Subsidiarity.....................................................................................................................................50
Stakeholders' opinions...................................................................................................................50
2.2. Removing distortions for liquid short-term markets .......................................................................53
Summary table...............................................................................................................................54
Description of the baseline ............................................................................................................55
Deficiencies of the current legislation ...........................................................................................58
Presentation of the options ...........................................................................................................59
Comparison of the options ............................................................................................................60
Subsidiarity.....................................................................................................................................62
Stakeholders' opinions...................................................................................................................63
2.3. Improving the coordination of Transmission System Operation......................................................65
Summary table...............................................................................................................................66
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Detailed description of the baseline ..............................................................................................67
Deficiencies of the current legislation ...........................................................................................70
Presentation of the options ...........................................................................................................72
Comparison of the options ............................................................................................................76
Subsidiarity.....................................................................................................................................88
Stakeholders' opinions...................................................................................................................89
3. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(C);
PULLING DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE
MARKET....................................................................................................................................90
3.1. Unlocking demand side response....................................................................................................92
Summary table...............................................................................................................................93
Description of the baseline ............................................................................................................94
3.1.2.1. Smart Metering ......................................................................................................................94
3.1.2.2. Market arrangements for demand response.........................................................................96
Deficiencies of current legislation................................................................................................102
3.1.3.1. Deficiencies of current Smart Metering Legislation.............................................................102
3.1.3.2. Deficiencies of current regulation on demand response.....................................................103
Presentation of the options .........................................................................................................104
Comparison of the options ..........................................................................................................107
Subsidiarity...................................................................................................................................126
Stakeholders' opinions.................................................................................................................130
3.2. Distribution networks ...................................................................................................................143
Summary table.............................................................................................................................144
Description of the baseline ..........................................................................................................145
Deficiencies of current legislation................................................................................................150
Presentation of the options .........................................................................................................152
Comparison of the options ..........................................................................................................152
Subsidiarity...................................................................................................................................156
Stakeholders' opinions.................................................................................................................157
3.3. Distribution network tariffs and DSO remuneration......................................................................160
Summary table.............................................................................................................................161
Description of the baseline ..........................................................................................................163
Deficiencies of the current legislation .........................................................................................167
Presentation of the options .........................................................................................................168
Comparison of the options ..........................................................................................................169
Subsidiarity...................................................................................................................................171
Stakeholders' opinions.................................................................................................................172
3.4. Improving the institutional framework .........................................................................................177
Summary Table ............................................................................................................................178
Description of the baseline ..........................................................................................................179
Deficiencies of the current legislation .........................................................................................183
Presentation of the options .........................................................................................................187
Comparison of the options ..........................................................................................................194
Budgetary implications of improved ACER staffing .....................................................................197
Subsidiarity...................................................................................................................................199
Stakeholders' opinions.................................................................................................................200
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1. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(A): LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES
1.1. Priority access and dispatch
Summary table
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain
rules allowing priority
dispatch and priority
access for RES,
indigenous fuels and
CHP.
Abolish priority dispatch and priority
access
This option would generally require full
merit order dispatch for all technologies,
including RES E, indigenous fuels such as
coal, and CHP. It would ensure optimum
use of the available network in case of
network congestion.
Priority dispatch and/or priority access only for emerging
technologies and/or for very small plants:
This option would entail maintaining priority dispatch
and/or priority access only for small plants or emerging
technologies. This could be limited to emerging RES E
technologies, or also include emerging conventional
technologies, such as CCS or very small CHP.
Abolish priority dispatch and introduce clear
curtailment and re-dispatch rules to replace
priority access.
This option can be combined with Option 2,
maintaining priority dispatch/access only for
emerging technologies and/or for very small
plants
Pros
Lowest political
resistance
Efficient use of resources, clearly
distinguishes market-based use of
capacities and potentially subsidy-based
installation of capacities, making subsidies
transparent.
Certain emerging technologies require a minimum number
of running hours to gather experiences. Certain small
generators are currently not active on the wholesale market.
In some cases, abolishing priority dispatch could thus bring
significant challenges for implementation. Maintaining also
priority access for these generators further facilitates their
operation.
As Option 1, but also resolves other causes for
lack of market transparency and discrimination
potential. It also addresses concerns that
abolishing priority dispatch and priority access
could result in negative discrimination for
renewable technologies.
Cons
Politically, it may be criticized that
subsidized resources are not always used if
there are lower operating cost alternatives.
Adds uncertainty to the expected revenue
stream, particularly for high variable cost
generation.
Same as Option 1, but with less concerns about blocking
potential for trying out technological developments and
creating administrative effort for small installations.
Especially as regards small installations, this could however
result in significant loss of market efficiency if large shares
of consumption were to be covered by small installations.
Legal clarity to ensure full compensation and
non-discriminatory curtailment may be
challenging to establish. Unless full
compensation and non-discrimination is
ensured, priority grid access may remain
necessary also after the abolishment of priority
dispatch.
Most suitable option(s): Option 3. Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to
actively participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should
be combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or emerging
technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.
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Description of the baseline
Dispatch rules determine which power generation facilities shall generate power at which
time of the day. In principle, this is based on the so-called merit order, which means that
those power plants which for a given time period require the lowest payment to generate
electricity are called upon to generate electricity. This is determined by the day-ahead and
intraday markets. In most Member States, dispatch is then first decided by market results
and, where system stability requires intervention, corrected by the TSO (so-called self-
dispatch systems). In some Member States (e.g. Poland) the TSO integrates both steps,
directly determining on the basis of the system capabilities and market offers made which
offers can be accepted (so-called central dispatch).
Access rules determine which generator gets, in case of congestion on a particular grid
element, access to the electricity network. They thus do not relate to the initial network
connection, but to the allocation of capacity in situations where the network is unable to
fully accommodate the market result. Priority access can thus mean that in situations of
congestion, instead of applying the most efficient way of remedying a particular network
issue, the transmission system operator has to opt for less efficient, more complex and/or
more costly options, to maintain full generation from the priority power plant.
Currently, several Directives allow the possibility or even set the obligation for Member
States to include priority dispatch and priority grid access of certain technologies in their
national legislation:
- Article 15(4) of the Electricity Directive provides that Member States may foresee
priority dispatch of generation facilities using fuel from indigenous primary energy
fuel sources to an extent not exceeding, in any calendar year, 15 % of the overall
primary energy necessary to produce the electricity consumed in the Member State
concerned;
- Article 16(2)(a) of the Renewable Energies Directive obliges Member States to
provide for either priority access or guaranteed access to the grid-system of
electricity produced from renewable energy sources;
- Article 16(2)(c) of the Renewable Energies Directive obliges Member States to
ensure that when dispatching electricity generating installations, transmission
system operators shall give priority to generating installations using renewable
energy sources in so far as the secure operation of the national electricity system
permits and based on transparent and non-discriminatory criteria;
- Similarly to the provisions under the Renewable Energies Directive, Article 15 (5)
b) and c) of the Energy Efficiency Directive foresee priority grid access and priority
dispatch of electricity from high-efficiency cogeneration respectively.
The introduction of priority dispatch and priority access for renewable energies on the one
hand and for CHP on the other hand are closely related. According to the impact
assessment of the Energy Efficiency Directive, Article 15 (5) aims at ensuring a level
playing field in electricity markets and help distributed CHP. Thus, the obligation of
priority dispatch, and the right to priority access, already existing under its predecessor,
Directive 2004/8/EC, have been expanded in the Energy Efficiency Directive to include
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mandatory priority access for CHP1
. The new provision fully mirrored the provision under
the then new Renewable Energies Directive.
Already for Directive 2004/8/EC, priority dispatch and (the right for a Member State to
foresee) priority access were based on the "need to ensure a level playing field" and the
challenges for CHP being similar to those for renewable energies. The provision of priority
dispatch and priority access for CHP has thus since its beginning been closely related to
the provision of these rights to renewable energies. This is also reflected in the text of
Article 15(5) itself, which provides that "when providing priority access or dispatch for
high-efficiency cogeneration, Member States may set rankings as between, and within
different types of, renewable energy and high-efficiency cogeneration and shall in any case
ensure that priority access or dispatch for energy from variable renewable energy sources
is not hampered."
The current framework thus provides that the provision of priority dispatch and priority
access for CHP shall under no circumstance endanger the expansion of renewable energies.
Against this background, any change to the framework for renewable energies would
directly impact the justification underlying the introduction of priority dispatch and priority
access for CHP.
The degree to which Member States have made use of the right under Article 15 (4) of the
Electricity Directive differs significantly. Some Member States make no use of it whereas
other Member States provide for priority dispatch of power generation facilities using
national resources (most notably coal). The provisions in the Renewable Energy Directive
and Energy Efficiency Directive are mandatory and in principle applied in all Member
States, although the implementation can differ significantly due to differences in national
subsidy schemes.
Deficiencies of the current legislation
European legislation allows the option (as regards indigenous resources) or sets an
obligation (for RES E and CHP) to implement priority dispatch and (for RES E and CHP)
priority grid access. This creates a framework with very high predictability of the total
power generation per year, thus increasing investment security. In particular in view of the
increasing share of RES E, this has resulted in a situation where in some Member States
very high shares of power generation are coming from "prioritized" sources.
The EU has committed to a continued increase of the share of renewable generation for the
coming decades. Until 2030, at least 27 % of final energy consumption in the EU shall
come from RES E – this requires a share of at least 45 % in power generation2
. According
to the PRIMES EuCo27 scenario, decarbonisation of EU's energy system would require a
share of RES in power generation of close to 50%, wind and solar energy alone projected
to cover 29 % of power generation.
1
https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_0779_impact_assessment.pdf, p.58.
2
2030 Communication, COM(2014) 15 final, p.6.
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Today, investments in renewable generation make up the largest share of investments;
many RES E technologies can no longer be treated as marginal or emerging technologies.
The comparison of Germany and Denmark, two Member States with high shares both of
RES E and CHP, is helpful to assess the deficiencies of systems based on strong priority
dispatch and priority access principles. Taking the example of Denmark, an average of 62
% of power demand in the month of January 2014 has come from wind generation alone3
and the share of annual demand covered by wind power has risen from 19 % in 2009 to 42
% in 20154
. Adding to this the share of 50.6 % of CHP in total Danish power generation5
,
which makes Denmark one of the Member States with the highest share of CHP6
, in many
periods almost all generation would be subject to "priority dispatch". Finally, it may be
necessary to add certain generation assets which are needed to operate for system security,
e.g. because only they can provide certain system services (e.g. voltage control, spinning
reserves), further limiting the scope for fully market based generation. However, in
Denmark, market incentives on generators are set in a way that drastically reduces the
impact of priority dispatch. Almost all decentralized CHP plants and a large number of
wind turbines would be exposed to and are not willing to run at negative prices. As CHP
are not shielded from market signals by national support systems, they have strong
incentives to stop electricity generation in times of oversupply. The integration of a high
share of RES E and CHP in parallel has been successful to a significant extent because
CHP are not built and operated on the basis of a "must run" model, where heat demand
steers electricity generation. To the contrary, CHP plants have back-up solutions (boilers,
heat storage), and use these where this is more efficient for the electricity system as
expressed by wholesale prices.
Taking the example of another "renewables front runner", Germany, "must run"
conventional power plants have been found to contribute significantly to negative prices
in hours of high renewable generation and low load, with at least 20 GW of conventional
generation still active even at significantly negative prices7
. Financial incentives are so that
many conventional plants generate even at significantly negative prices, with many power
plants switching off electricity generation only at prices around minus 60 EUR/MWh. This
increases the occurrence of negative prices, worsening the financial outlook for both
renewable and conventional generators, and can increase system stress and costs of
interventions by the system operator. This is not due to technical reasons – also in
Germany, CHP plants generally have back-up heat capacities, which are already necessary
to address e.g. maintenance periods of the main plant, or could technically install these.
While it may be economically and environmentally efficient to run through short periods
of low prices (to avoid ramping up or down), this is no longer the case where the market
3
http://www.martinot.info/renewables2050/how-is-denmark-integrating-and-balancing-renewable-
energy-today.
4
http://www.energinet.dk/EN/El/Nyheder/Sider/Dansk-vindstroem-slaar-igen-rekord-42-procent.aspx.
5
https://ec.europa.eu/energy/sites/ener/files/documents/PocketBook_ENERGY_2015%20PDF%20final.
pdf, p. 183.
6
http://www.code2-project.eu/wp-content/uploads/Code-2-D5-1-Final-non-pilor-Roadmap-
Denmark_f2.pdf;
7
See: http://www.netztransparenz.de/de/Studie-konventionelle-Mindesterzeugung.htm
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is willing to pay a lot for electricity being not generated. Excess electricity is in these
situations not very efficiently generated, but essentially a waste product. While there is a
wide range of reasons for conventional generation to produce at hours of negative prices
(e.g. very inflexible technologies such as nuclear or lignite which need a long time to
reactivate), approximately 50 % of the plants in such a situation in Germany had at least
the capability for parallel heat production, and approximately 8-10 % of conventional
plants still producing at such moments were found to be heat-controlled CHP generation8
.
In view of the EU target for at least 27 % of renewable energies in final energy
consumption (which according to PRIMES EuCo27 projections would require 47 % of
gross final electricity consumption to come from renewable energy), the high share of
priority dispatch and priority access-technologies will increasingly occur in other Member
States. This can have very significant impact on the well-functioning of the electricity
market. In particular:
- Subsidy schemes based on priority dispatch (such as Feed-in Tariffs) often are
based on high running hours and a mitigation of market signals to the subsidized
generator. This means that non-subsidized generation is increasingly pushed out of
the market even where this is not cost-efficient;
- Situations in which more than 100 % of demand is covered by priority dispatch
become more prevalent. This lowers the investment security provided by priority
dispatch, and can lead to results contrary to policy interests such as unnecessary
curtailment of RES E;
- The internal energy market depends on steering the use of generation by price
signals. In a situation where the clear majority of power generation does not react
to price signals, market integration fails and market signals cannot develop;
- Incentives to invest into increased flexibility which would naturally result from
price signals on a functioning wholesale market do not reach a significant part of
the generation mix. Priority dispatch rules can eliminate incentives for flexible
generation (e.g. biomass, some CHP with back-up installations) to use the
flexibility potential and instead create incentives to run independent of market
demand;
- Priority dispatch and priority grid access limit the choice for transmission system
operators to intervene in the system (e.g. in case of congestion on certain parts of
the electricity grid). This can result in less efficient interventions (e.g. re-
dispatching power plants in suboptimal locations). The increased complexity with
high shares of priority dispatch could also lower system stability, although
emergency measures may also affect generation benefiting from priority dispatch;
- Priority dispatch rules for high marginal cost technologies can result in using costly
primary ressources to generate electricity at a time where other, cheaper,
technologies were available;
- Priority dispatch rules for generation installations using indigenous ressources
result in clear discrimination of cross-border flows and distortions to the internal
market.
8
Consentec, "Konventionelle Mindesterzeugung – Einordnung, aktueller Stand und perspektivische
Behandlung", Abschlussbericht 25. Januar 2016, p. vii and 25.
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Against this background, the provision of priority dispatch and priority grid access needs
to be reassessed in view of the main policy objectives of sustainability, security of supply
and competitiveness (see also Section 7.4.2 of the evaluation).
Presentation of the options
For the operation of generation assets, it is recognized that the wholesale market with
merit-order based dispatch and access ensures an optimal use of generation resources.
Especially in balancing, it also ensures optimal use of congested network capacities. Rules
which deviate from these provisions reduce system efficiency and result in market
distortions, as it can sometimes be economically more efficient to curtail RES and the
guarantee of non-curtailment significantly increases price volatility9
. Where financial
compensation on market-based principles is foreseen in case of re-dispatch, priority
dispatch also does not appear to be necessary to mitigate investor risk in low marginal cost
technologies. Thus, it is proposed to abolish or at least significantly limit the exceptions
foreseen under EU law from merit-order based dispatch and network access.
Option 0: do nothing
This option does not change the legislative framework. Priority dispatch and access
provisions remain unchanged in EU legislation and the above-described problems persist.
Option 0+: Non-regulatory approach
Stronger enforcement would not adress the policy objectives. In fact, as the objective is to
ensure market-based use of generation assets with limited exceptions, stricter enforcement
of existing obligations under EU law which make those exceptions mandatory would be
counter-productive.
Voluntary cooperation does not change the legislative framework and thus maintains the
currently existing obligations. The order of dispatch for power plants and access to the grid
has clear cross-border implications. Priority dispatch/access often results in lower
availability of cross-border capacities, and significant differences in these rules can thus
distort cross-border trade.
Option 1: Abolish priority dispatch and priority access
Under this option, priority dispatch / priority access provisions would be removed from
EU legislation, and replaced by a general principle that generation and demand response
shall be dispatched on the basis of using the most efficient resources available, as
determined on the basis of merit order and system capabilities.
This option would optimally achieve the defined objectives and thus be highly effective.
It would however result in additional administrative impact for very small RES E
installations which are currently not capable of controlling their feed-in into the grid
(notably rooftop solar) and micro-CHP installations. Furthermore, it could increase
complexity and prolong the development time for emerging technologies. As these
technologies would not yet be mature they would not be able to generate at competitive
9
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.183 f.
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prices and could thus not reach a number of running hours needed to generate sufficient
experience.
Option 2: Limit priority dispatch and/or priority access to emerging technologies and/or
small plants
Under this option, priority shall be given only where it can be justified to enable a certain
technology or operating model which is seen as beneficiary under other policy objectives.
As regards emerging technologies10
, this could in particular be linked to ensuring that the
technologies reach a minimum number of running hours as required to gather experience
with the non-mature technology. For particularly small generation installations11
, this
could reduce the administrative and technical effort linked to dispatching the power plant
for its owner, which may appear disproportionate for certain installations. This being said,
the administrative effort can be significantly reduced by ensuring the possibility of
aggregation, allowing the joint operation and management of a large number of small
plants. To mitigate negative impacts on market functioning, both possible exemptions
should be capped to ensure that priority dispatch and priority access does not apply to large
parts of total power generation.
This option would achieve the defined objectives, although certain trade-offs would be
made. Accepting priority dispatch and access for certain installations would reduce market
efficiency. If the share of exempted installations in the total electricity market remains low,
the negative market impact is however likely to remain very limited. On the other hand,
the positive impact of allowing the development of new technologies can provide a
significant benefit for the achievement of renewable energy targets in the medium to long-
term. Exempting very small installations would also increase public acceptance and reduce
administrative efforts required from the operators of these installations, which are often
households. This is thus the preferred option, although it has to be ensured that exemptions
remain limited to a small part of the market. The exact definition of the emerging
technologies could be left to subsidiarity.
Option 3: Abolish priority dispatch and introduce clear curtailment and re-dispatch rules
to replace priority access
This option (which can be combined with Option 2) would entail the abolishment of
priority dispatch. Priority grid access would be replaced by clear rules on how to deal with
situations of system stress, in particular as regards congestion of grid elements. In
principle, market-based ressources should be used first, thus curtailing or redispatching
first those generators which offer to do this against market-based compensation. In a
second step, where no market-based ressources can be used, minimum rules on
compensation are foreseen, ensuring compensation based on additional costs or (where this
is higher) a high percentage of lost revenues.
10
In the PRIMES EuCo27 scenario, the emerging technologies of tidal and solar thermal generation (other
technologies having insignificant shares) are projected to have a total installed capacity of 7.26 GW and
produce 10 TWh of electricity in 2030 (13 GW and 20 TWh in 2050, respectively).
11
In the PRIMES EuCo27 scenario, RES E small-scale capacity is projected in 2030 to be 85 GW (7.8 %
share) and produce 96 TWh of energy (2.9% share).
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It would mean that network operators would obtain a clear incentive to make an assessment
on the basis of costs as to the alternatives available to them to address the underlying
network constraints, thereby creating opportunities for more innovative solutions such as
storage.
The increase in transparency and legal certainty would notably also prevent discrimination
against certain technologies (particularly RES E) in curtailment and re-dispatch decisions.
RES E are often operated by smaller market players, who could otherwise be subject to
excessive curtailment or unable to achieve fully equal compensation. It would also foresee
principles on the financial compensation to be paid in case of curtailment or re-dispatch,
thus reducing the additional investment risk linked to losing priority access and thereby
reducing any increase in capital costs. In order to ensure effective implementation of the
new market rules prior to abolishment of priority dispatch and access, priority dispatch and
access may be maintained for an interim period after entry into force of the other measures
adressing Problem 1.
Increased transparency and legal certainty on curtailment and re-dispatch are a "no regret"
measure, in so far as they contribute to market functioning even in the absence of changes
to the priority dispatch and priority access framework. Ensuring sufficient compensation
for curtailment, notably for RES E, will increase costs to be borne by system operators. In
so far as these costs are currently integrated into renewable subsidy schemes, total system
costs will however remain similar. As regards priority grid access, this is the preferred
option, in order to ensure that the abolishment of priority grid access has no unwanted
negative consequences on the financial framework notably of RES E but also of CHP.
Comparison of the options
It should be noted that the removal of priority dispatch and priority access does not equally
affect different technologies and generators in different Member States:
- The removal of priority dispatch mostly affects high marginal cost technologies
(biomass, indigenous resources, some CHP), as low marginal cost technologies
(wind, PV) are generally dispatched when available already on the basis of the
merit order. Without priority dispatch, high marginal cost technologies thus take
up a role more generally associated with other high marginal cost plants, such as
gas-fired power plants, operating only in periods of high prices (high residual load).
Those generators are then incentivized to making best use of the inherent flexibility
that their technology can provide to a power system, and thus accompany the
change to an electricity system with a high share of variable low marginal cost
generation. For high marginal cost generation, removal of priority dispatch can
significantly reduce the number of running hours. Studies for the Commission have
shown a reduction of approximately 85 % in dispatch of wood-based biomass
generation, mostly to the benefit of gas-fired power plants12
. To the contrary, there
is a (more limited) increase in the running hours of low marginal cost generation,
including wind and solar;
12
For this assessment, biomass was assumed to consist of 22 % "must-run" waste incineration (OPEX: 3.6
EUR EUR/MWh) and 78 % wood-fired plants with high variable costs (around 90 EUR EUR/MWh)
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- The reduction in inefficient biomass dispatch would represent a major part of the
significant reductions of system costs presented in Figure 1 below, with annual
savings of 5.9 billion Euros, expected by the removal of market distortions under
Problem Area I, Option (1a) of the impact assessment13
;
Figure 1: Reduction in system costs by abolishment of priority rules
Source: METIS
- By achieving market-based dispatch, the removal of priority dispatch for all
technologies drastically reduces the occurrence of negative prices. Whereas
negative prices can be a normal occurrence in well-functioning markets which have
opportunity costs linked to not offering a service (as is the case on the electricity
markets), the occurrence of negative prices based on priority rules shows that
priority is given also in times where the system does not require additional
generation.
13
For more details please see Section 6.1.2 of the impact assessment.
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Figure 2: reduction of negative price occurrences by removal of priority
dispatch
Source: METIS
- The removal of priority access on the other hand mostly affects technologies which
are producing in areas and at times of network congestion. This will more often
concern low marginal cost technologies (especially wind) as periods of high wind
feed in are more likely to result in congested network elements, requiring
curtailment or re-dispatch;
- Providing clear and transparent rules on curtailment and compensation benefits all
market actors. This is particularly true for small and/or new market actors,
including RES E;
- While the change of biomass dispatch to reflect its role as flexible back-up
generation, to the benefit mostly of gas, but also of coal and nuclear generation
thus would drastically reduce future system costs, it could possible entail an
increase of CO2 emissions in the power sector, whereas total CO2 emissions under
the ETS framework would in principle remain identical over time14
.
Option 1 would be the most effective in achieving the objective of non-discrimination and
market efficiency. However, it could result in an increase of costs to achieve other policy
objectives, notably for decarbonisation of the energy system. Fully removing priority
dispatch and access would also result in an increased need for small generators, including
households (e.g. rooftop solar) to participate in the electricity market. While this would
allow strong economic incentives, it would thus increase the administrative impact for
households and SMEs. Thus, clear and transparent rules for the market participation of
RES E and CHP as well as limited exemptions for small and emerging technologies should
be included, to accompany the phase-out of priority access and priority dispatch. On the
other hand, remaining at the status quo would, with a growing share of priority
technologies in the system, seriously undermine effective price formation and dispatch in
the wholesale market. The preferred option is thus a combination of Options 2 and 3. This
14
The environmental impacts from the removal of priority dispatch for biomass are discussed in Section
6.1.6 of the impact assessment
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will allow a reduction of the administrative impact for households and SMEs while
ensuring the most efficient use of bigger mature power generators.
Subsidiarity
Priority dispatch is foreseen directly in EU law. Changing or removing those provisions
cannot be achieved on a national level. Furthermore, in an integrated electricity market,
the way to determine which power plant is operated has a direct impact on cross-border
trade. Applying discriminatory provisions for power plant dispatch in certain Member
States can thus negatively affect cross-border trade or even directly result in discrimination
against power generators in other Member States. Ensuring efficient market integration
and functioning investment signals, requires fundamental dispatch rules to be harmonized.
Stakeholders' opinions
In the public consultation, most stakeholders support the full integration of Renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods. Many
stakeholders note that the regulatory framework should enable RES E to participate in the
market, e.g. by adapting gate closure times and aligning product specifications. A number
of respondents also underline the need to support the development of aggregators by
removing obstacles for their activity to allow full market participation of renewables.
Also stakeholders from the renewable sector often recognize the need to review the priority
dispatch framework. They make this however subject to conditions; Wind Europe provided
views on curtailment of wind power and priority dispatch and stated that "countries with
well integrated day-ahead, intraday and balancing market and a good level of
interconnections, where priority of dispatch is not granted to CHP and conventional
generators, do not need to apply priority of dispatch for wind power." They argue that "in
general, priority dispatch should be set according to market maturity and liberalisation
levels in the Member State concerned, but also taking due account of progress in grid
developments and application of best practices in system operation." According to its
paper from June 2016 on curtailment and priority dispatch, in the view of Wind Europe15
,
some EU markets, such as Sweden and the UK, which have relatively high penetration
rates of wind, do not offer priority dispatch for wind producers16
and this does not place
any restrictions on market growth. However, a phase-out of priority dispatch for renewable
energies should only be considered if (i) this is done also for all other forms of power
generation, (ii) liquid intraday markets with gate closure near real-time, (iii) balancing
markets allow for a competitive participation of wind producers; (short gate closure time,
separate up/downwards products, etc.), and (iv) curtailment rules and congestion
management are transparent to all market parties. According to Wind Europe, these
requirements are already in 2016 fulfilled in certain markets such as the UK, Sweden and
Denmark, whereas other Markets currently still required priority dispatch. It is the view of
the Commission services that by entry into force of the present legislative initiative, the
above requirements are met in all Member States.
15
https://windeurope.org/wp-content/uploads/files/policy/position-papers/WindEurope-Priority-
Dispatch-and-Curtailment.pdf.
16
The Commission services interpret this to mean that, while priority dispatch may be foreseen under
national legislation, it has no practical impact.
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Regarding priority access, Wind Europe asks for curtailments to be valued by the market
as a service to ensure system security. It should be treated as downward capacity and its
price should be set via the balancing market. This would already be applied in the Danish
and UK markets. Participation of wind in the balancing markets could lead to a significant
reduction of curtailments. This is taken into account in Option 3, which ensures the primary
use of available market-based ressources prior to any non-market based curtailment.
Where balancing ressources are available, including from RES E, and capable of adressing
the system problem underlying the planned curtailment, they thus have to be used before
non-market based curtailment takes place. For this second step, transparent compensation
rules are foreseen. Wind Europe recognizes that "there may be a benefit from not
compensating 100% of the opportunity cost. Reducing slightly the income could send an
important incentive signal to investors to select locations with existing sufficient network
capacity, Curtailment would then be likely to occur less frequently. The exact % of the
opportunity cost needs to be carefully assessed in order to find a balance between an
increase in policy cost and the increase of financing costs due to higher market risk." This
position is reflected in the present proposal.
Stakeholders from the cogeneration sector underline the link to priority dispatch for
renewable energies. COGEN Europe submits that it is "important that at EU level CHP
benefits from at least parity with RES on electricity provisions, as long as there are no
additional policy measures that would compensate for the loss in optimal operation
ensured through priority of dispatch for certain types of CHPs." They also argue that
"while a significant fraction of the CHP fleet can be designed and/or retrofitted to operate
in a more flexible way (e.g. though partial load capabilities, enhanced design from the
electrical components, and the heat storage addition), this may come at the expense of the
site efficiency and industrial productivity." The parallelism to RES is maintained in all
options, whereas the additional costs and possible loss of efficiency have to be balanced
with the economic cost of significant amounts of inflexible conventional generation in a
high-RES system.
EUROBAT, association of European Manufacturers of automotive, industrial and energy
storage batteries, regards curtailing of energy as a system failure, as the "wasted" power
should be stored in batteries instead. It argues against any financial compensation to
renewable generators for being curtailed, as such a compensation would disincentivize the
installation of energy storage systems17
.
Transmission system operators would be directly affected, as they are responsible for
practical implementation of the priority rules. In May 2016, ENTSO-E has asked their
Members to provide answers to questions which had been discussed with the Commission
services. 29 TSOs from 25 countries have replied, though not all TSOs answered all
questions, which is also due to the limited impact of priority dispatch/access in some
Member States (with a low share of CHP and RES E). TSOs from 14 Member States
answered that priority dispatch increases the costs of pursuing stable, secure and reliable
system operations. TSOs from a smaller group of Member States (4 to 6) also stated that
priority dispatch limits the possibilities to keep the grid stable, secure and reliable. Only
the TSOs of three Member States answered that priority dispatch has no major effect on
system operations. Regarding the market impact, TSOs from 12 Member States raised
17
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf p.28.
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increased dispatching costs and 9 raised the occurrence of negative prices. On the other
hand, TSOs from one Member State argued that priority dispatch resulted in reduced costs
for the support of RES E. TSOs also stressed the cross-border impact of priority dispatch:
TSOs from 6 Member States referred to increased congestion of interconnectors, and an
example provided was that priority dispatch in neighbouring areas impacted the system
operation in the TSOs area. When asked how European legislation should adress the issues
mentioned, no TSO wanted to retain priority dispatch, 8 TSOs wanted to retain it with
exemptions, 4 TSOs wanted a phase out of priority dispatch, and 13 TSOs wanted priority
dispatch to be removed entirely.
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1.2. Regulatory exemptions from balancing responsibility
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Summary table
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances caused.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain the status
quo, expressly requiring financial
balancing responsibility only under
the State aid guidelines which
allow for some exceptions.
Full balancing responsibility for all parties
Each entity selling electricity on the
market has to be a balancing responsible
party and pay for imbalances caused.
Balancing responsibility with exemption
possibilities for emerging technologies
and/or small installations
This would build on the EEAG.
Balancing responsibility, but possibility to delegate
This would allow market parties to delegate the
balancing responsibility to third parties.
This option can be combined with the other options.
Pros
Lowest political resistance Costs get allocated to those causing them.
By creating incentives to be balanced,
system stability is increased and the need
for reserves and TSO interventions gets
reduced. Incentives to improve e.g.
weather forecasts are created.
This could allow shielding emerging
technologies or small installations from the
technical and administrative effort and
financial risk related to balancing
responsibility.
The impact of this option would depend on the
scope and conditions of this delegation. A
delegation on the basis of private agreements, with
full financial compensation to the party accepting
the balancing responsibility (e.g. an aggregator)
generally keeps incentives intact.
Cons
Financial risks resulting from the
operation of variable power generation
(notably wind and solar power) are
increased.
Shielding from balancing responsibilities
creates serious concerns that wrong
incentives reduce system stability and
endanger market functioning. It can increase
reserve needs, the costs of which are partly
socialized. This is particularly relevant if
those exemptions cover a significant part of
the market (e.g. a high number of small RES
E generators).
The impact of this option would depend on the
scope and conditions of this delegation. A full and
non-compensated delegation of risks e.g. to a
regulated entity or the incumbent effectively
eliminates the necessary incentives. Delegation to
the incumbent also results in further increases to
market dominance.
Most suitable option(s): Option 2 combined with the possibility for delegation based on freely negotiated agreements.
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Description of the baseline
Balancing responsibility refers to the obligation of market actors (notably power
generators, demand response providers, suppliers, traders and aggregators) to
deliver/consumer exactly as much power as the sum of what they have sold and/or
purchased on the electricity market. Predictions for demand and (to a more limited extent)
generation being not 100 % precise, market actors are often not fully balanced. The
Transmission System Operator then ensures that total demand and supply are maintained
in balance by activating (upward or downward) balancing energy, often coming from
dedicated balancing capacities.
Balancing responsibility implies that the costs of the balancing actions taken by the
transmission system operator are generally to be compensated by the market parties which
are in imbalance. In some Member States, certain types of power generation (notably wind
and solar, but possibly also other technologies such as biomass) are excluded from this
obligation or have a differentiated treatment. Most Member States foresee some degree of
balancing responsibility also for renewable generators; based on an EWEA (now Wind
Europe) study, in 14 out of 18 Member States with a wind power share above 2-3 % in
annual generation, wind generators had some form of balancing responsibility18
. This
however does not always translate into real financial responsibility of the generator for
imbalances it caused. In Austria for example, a public entity, OEMAG, acts as balancing
responsible party for all subzidized renewable generation, thus shielding individual
generators from imbalance risks of their power plants19
and collectively purchasing/selling
balancing energy for the renewable sector20
. On the other hand, in a small number of
Member States balancing costs imposed on renewable power generation can be
prohibitively high and almost reach the level of wholesale prices (e.g. incurred balancing
costs of up to 24 EUR/MWh in Bulgaria and 8-10 EUR/MWh in Romania)21
.
Article 28 (2) of the Balancing Guideline provides that "each balance responsible party
shall be financially responsible for the imbalance to be settled with the connecting TSO".
This does not, however, preclude frameworks in which market actors are (fully or partly)
shielded from the financial consequences of imbalances caused by having this
responsibility shifted to another entity. This is part of some current support schemes.
The EEAG provide that in order for State aid to be justified, RES E generators need to bear
full balancing responsibility unless no liquid intra-day market exists. The EEAG rules
however do not apply where no liquid intraday market exists, and and also do not apply to
installations with an installed electricity capacity of less than 500 kW or demonstration
projects, except for electricity from wind energy where an installed electricity capacity of
3 MW or 3 generation units applies. The exemption from balancing responsibility in the
absence of liquid intra-day markets is based on the reasoning that were liquid intra-day
18
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf, p. 5-6.
19
https://www.energy-
community.org/portal/page/portal/ENC_HOME/DOCS/2014187/0633975ACF8E7B9CE053C92FA8
C06338.PDF
20
http://www.oem-ag.at/de/oekostromneu/ausgleichsenergie/.
21
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf p. 8.
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markets do exist, they allow renewable generators to drastically reduce their imbalances
by trading electricity on short-term markets and thus taking account of updated wheather
forecasts. This shows that imposition of balancing responsibility is thus closely linked to
the creation of liquid short-term markets, one of the main objectives of the electricity
market design initiative.
The corollary to balancing responsibility is the possibility to participate in the balancing
market, offering balancing capacity to the TSO against remuneration. This is further
described under Section 5.1.1.4 and closely linked to the Balancing Guideline.
Deficiencies of the current legislation
Already today, the increased share of renewable energies in power generation
(approximately 29% in 2015) has significant impact on market functioning and grid
operation. This effect is most noticeable in Member States with RES E shares above the
EU average.
The below figure shows two relevant weeks, with production and consumption shown
together. In the left graph, generation exceeds the load (red line) in situation with lots of
solar power generation (yellow). In the right graph, less renewable power is generated
(blue, green, yellow, but minimal PV (yellow)). Supply and demand of electricity has to
match at all times despite changes in demand and variable renewable electricity
production. For both situations, flexibility options such as storage, demand side response,
flexible generation and interconnection import/export capacities are needed to take up
electricity.
Figure 1: Volatility in the German power market in June and December 2013
Source: Agora Energiewende 2013.
To integrate renewable production progressively and efficiently into a market that
promotes competitive renewables and drives innovation, energy markets and grids have to
be fit for renewables. This is not necessarily the case in many jurisdictions since markets
have traditionally been designed to cater the needs of conventional generation rather than
variable renewables. To make markets fit for renewables means developing adequately the
short-term markets such as intraday and balancing. This also means allowing, to the
maximum possible extent, renewables to participate in all electricity markets on equal
footing to conventional generation removing all existing barriers for renewable energy
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sources integration. Integrating RES E into the market and allowing them to generate a
large part of their revenues from market prices requires an increase of flexibility in the
system, which is also needed for absorbing cheap renewable electricity at times of high
supply. It is for this reason that the EEAG (para.124) requires generators to be subject to
standard balancing responsibilities only unless no liquid intra-day market exists. Liquid
intra-day markets should exist in all Member States at the expected date of entry into force
of the revised legislation, accompanying the present impact assessment. However, the
term "liquid intra-day market" allows significant margin of interpretation and can thus
cause uncertainty on the application of one of the fundamental rules on the electricity
market. It will be necessary to further clarify this exemption and ensure that market actors
have legal certainty as to whether they have to bear balancing responsibility or not.
Investment incentives should take into account the value of generation at different times
of the day or of the year. Progress has been made in this area, with support schemes relying
increasingly (but not everywhere or for all generation) on premiums instead of fixed feed-
in tariffs. Where premium-based support schemes are used, the degree of market exposure
depends on their exact implementation, differing e.g. between fixed and floating premium
models, and for the latter relative to the determination of the base price used for the
calculation of the premium. Full exposure to market signals may e.g. make a different
generation installation more efficient although it produces lower total output (such as
orienting PV to the west to increase output later in the day). By exposing generators to the
financial consequences of imbalances caused, the incentives given to generators do not
relate only to optimizing the expected generation of their power plant in view of market
needs, but also to ensuring that the electricity they sell on the market matches as closely as
possible the power produced at a certain point in time. In a questionnaire to TSOs
organized by ENTSO-E, the example was given that following the attribution of balancing
responsibility in a Member State, the average hourly imbalance of PV installations
improved from 11.2 % in 2010 to 7.0 % in March 2016, and the average hourly imbalance
of wind improved from 11.1 % to 7.4 % over the same period.
Where RES E generators do not assume balance responsibility identical to other generators
and participate in the balancing market, they lack incentives for efficient operational and
investment decisions22
. Part of this challenge is the need to avoid inacceptable risks for
RES E investors by imposing balance responsibilities without creating the market
flexibility which allows staying balanced23
. Whereas many Member States already foresee
some balancing responsibility for RES E generators (2013: 16 Member States)24
this is not
22
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.185
23
KEMA p. 185: "Experience from some EU countries has shown that RES generators are able to provide
less volatile and more predictable generation schedules if so incentivized by balancing arrangements."
24
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd04_en.pdf
Appendix I table 6.
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yet the case for all Member States, and the degree of balancing responsibility differs
considerably between Member States. This can result in market distortions, directing
investments to Member States with lower degree of responsibility rather than to those
Member States where electricity demand and renewable generation potential are optimal,
and can also result in lower liquidity of short-term markets.
Reduced balancing responsibility can also result in increasing imbalances in electricity
trades. Whereas the TSO will generally, via the balancing market, be capable of covering
imbalances, a high degree of imbalances reduces predictability of system operation and
can increase system stress (e.g. by reducing the volume of available reserves) or increase
costs for system stability (e.g. if higher reserve volumes are procured in advance).
Finally, it should be noted that the EEAG already foresees the need to phase out
exemptions from balancing responsibilities in the post-2020 period25
. The EEAG itself
provides in its paragraph 108 that the Guidelines "apply to the period up to 2020 but should
prepare the ground for achieving the objectives set in the 2030 framework, implying that
subsidies and exemptions from balancing responsibilities should be phased out in a
degressive way".
Refrence is also made to Section 7.4.2 of the evaluation.
Presentation of the options
Balancing responsibility of all market parties active on the electricity market is a
fundamental principle of EU energy law. This principle should not be included only in a
State aid guideline and in the Balancing Guideline but ensured at the level of secondary
law, thus increasing transparency and legal certainty. Exemptions currently foreseen in the
guidelines need to be reassessed and, where still necessary, further clarified. It should also
be further clarified in how far and under which conditions delegation of this responsibility
is possible. It is thus proposed to establish a general rule that all market-related entities or
their chosen representatives shall be financially responsible for their imbalances, and that
any such delegation/representation shall not entail a disruption of incentives for market
parties to remain balanced. Provisions in this direction are already included in the
Balancing Guideline which will be discussed in Comitology in the second half of 2016.
General principles and, where applicable, exemptions shall be integrated into the
Electricity Directive for added clarity and legal certainty.
Option 0: do nothing
This would mean that balancing responsibility remains subject only to State aid rules and
the rules in the Balancing Guideline. Fundamental principles of electricity market
operation should systematically not be decided upon only in acts adopted under the
Comitology process and guidelines which undergo no legislative process. Furthermore, the
25
Paragraph 108 EEAG reads: "These Guidelines apply to the period up to 2020. However, they should
prepare the ground for achieving the objectives set in the 2030 Framework. Notably, it is expected that
in the period between 2020 and 2030 established renewable energy sources will become grid-
competitive, implying that subsidies and exemptions from balancing responsibilities should be phased
out in a degressive way. These Guidelines are consistent with that objective and will ensure the transition
to a cost-effective delivery through market-based mechanisms."
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EEAG are limited in time to 2020 and uncertainty as to the extent of their exemptions and
their applicability post-2020 will persist. According to their paragraph 108, it is expected
that in the period between 2020 and 2030 established renewable energy sources will
become grid-competitive, implying that subsidies and exemptions from balancing
responsibilities should be phased out in a progressive way (and thus assuming liquid short-
term markets to develop). Finally The State aid guidelines only apply to those parts of
measures which are to be seen as State aid. This concerns most, but not necessarily all,
generation which may not be fully balancing responsible. For some aspects the
qualification as State aid could potentially be put into question.
Option 0+: Non-regulatory approach
As national law is extremely varied to date, without a clear and transparent framework
setting out the degree of balancing responsibility, enforcement of existing rules (e.g. State
aid rules) is unlikely to result in a uniform and non-discriminatory legal framework.
Voluntary cooperation can contribute to reducing the negative impact of imbalances.
Imbalance netting by transmission system operators already achieves significant cost
reductions. However, voluntary cooperation does not provide sufficient legal certainty and
the minimum degree of harmonization to avoid distortions in cross-border trade. In fact,
shielding certain market parties fully or in part from balancing responsibilities creates
economic advantages which can distort cross-border trade in electricity. Where a lack of
balancing responsibility results in increased imbalances, this will negatively impact the
whole synchronous area, and thus create costs and risks for system stability also in other
Member States.
Option 1: Full Balancing responsibility for all parties
This would entail that the principles of the Balancing Guideline imposing all market-
related entities and their representatives to be financially responsible for imbalances caused
would be integrated into the Electricity Directive.
This option would thus significantly increase transparency and legal certainty. Balancing
responsibility is already an accepted concept under the EEAG, so that the market impact
would be limited to those entities currently benefitting from exemptions or not subject to
State aid rules. While this option would optimally achieve the defined objective, the
complete abolishment of the existing exemptions could result in increased administrative
effort for small installations or demonstration projects using emerging technologies.
Option 2: Balancing responsibility with exemption possibilities for emerging technologies
and/or small installations
This would allow Member States to foresee that certain emerging technologies and/or
small installations (e.g. rooftop solar) are shielded from the direct financial impact of
imbalances they cause. As imbalances need to be covered by some entity, this could be
achieved by allocating it to public bodies (essentially meaning that these entities are acting
as sellers of RES E on the wholesale market), the costs of which are then socialized.
This option addresses the currently existing exemptions under EEAG, based on the
assumption that short-term markets have developed sufficiently by the time of entry into
force of the proposed legislation to require balancing responsibility of generators not
covered by the exemptions. Without introducing additional limitations, these exemptions
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would however risk reducing effectiveness in achieving the policy objective. This is
notably the case for small installations, which under some scenarios can account for a
significant part of total electricity supply.
Option 3: Possibility to delegate balancing responsibility
This option would entail the right to delegate balancing responsibilities to a third party.
Whereas the freely negotiated delegation to a third party against financial compensation
(e.g. an aggregator) can reduce administrative impact without reducing the incentive to
reduce imbalances (as their cost will be passed on to the generator in some way), regulated
delegations without compensation drastically reduce or eliminate the incentive to remain
balanced.
The possibility to delegate on the basis of free negotiation, against financial compensation,
(combined with exemptions notably for demonstration projects and possibly very small
installations) is the preferred option. It fully achieves the policy objectives, and allows
notably smaller installations to reduce administrative efforts without reducing market
incentives.
Comparison of the options
The requirement of full balancing responsibility does not affect all renewable technologies
in the same manner. Biomass and other non-variable technologies are generally capable of
being balanced to the same degree as conventional generators. Variable generators
(especially wind and PV) can increasingly predict their generation based on wheather
forecasts, but have a higher margin of error in those predictions than conventional
generators. To reduce the margin of error, those technologies need to improve wheather
forecasts, as well as sell electricity for shorter time periods in advance, when better
forecasts become available.
A study using METIS has shown very significant reductions in frequency restoration
reserve needs due to the introduction of balancing responsibilities for RES E. Whereas
FCR and aFRR needs relate to short-term frequency deviations and are thus not
significantly affected by balancing responsibility, mFRR needs are based on longer-lasting
deviations from indicated schedules. By creating incentives for improved forecasts and
more exact schedules, reserve needs are thus significantly reduced.
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Figure 2: reduction in reserve needs depending on balancing responsibility
Source: METIS
Option 1 would be most effective at achieving the objective of well-functioning markets.
All exemptions from balancing responsibility, even if only partly shielding against the
financial impact of imbalances, reduce the incentive to be balanced. The complete
abolishment of the existing exemptions would however result in increased administrative
effort for small installations or demonstration projects using emerging technologies. This
could slow down roll-out of new RES E technologies and could thus render the
achievement of the decarbonisation objective more costly. Options 2 and 3 can be
combined to ensure a maximum degree of balancing responsibility with the potential to
delegate this responsibility, which allows reduction of the additional administrative impact
imposed especially on small installations. This being said, small installations are currently
often not active on the market, and it could be excessive to require balancing responsibility
even taking into account the possibility to delegate. The preferred option is thus a
derogation from balancing responsibilities for demonstration projects and small generation
(e.g. rooftop solar), and the right for other projects to delegate their balancing responsibility
against financial compensation. This significantly reduces the administrative effort for
households and small and medium enterprises (who will often continue to benefit from
exemptions from balancing responsibilities) but takes account of the increased role
renewable generation plays in the market, and the improved capabilities particularly of
larger generators to predict their output and reduce or hedge remaining imbalance risks.
Subsidiarity
Balancing responsibility is a fundamental principle in every electricity market. It ensures
that market agreements are also reflected in the physical reality, and that the costs of
imbalances created are born by those creating them. Balancing responsibiltity impacts both
investment decisions and trading on electricity markets; every decision to sell electricity
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on the market entails the risk to be in imbalance, which thus has to be integrated into
bidding strategies. Deviations on a national level in an integrated market could result in
distortions of cross-border trade, e.g. by making investments into variable generation in
one Member State significantly more interesting than in other Member States, and basic
principles for balancing responsibility thus need to be harmonized.
Furthermore, increasing the share of RES E in the total energy consumption is an EU
target. For 2030, a target binding at EU level exists, without nationally binding targets;
therefore the EU has to ensure the EU target is reached. With an increasing share of RES
E, they become a relevant player on the power markets. As power markets are increasingly
integrated, this has direct cross-border impact. Equal treatment to all generation
technologies should be ensured to avoid market distortions. Markets should be fit to allow
all generation technologies and demand to compete on equal footing, while allowing the
EU to reach the policy objectives of sustainability, competitiveness and security of supply.
The increasing share of RES E also creates challenges for network operation. In
synchronous areas even exceeding the EU, this is an issue which cannot be resolved at
national level alone.
Stakeholders' opinions
In the public consultation, most stakeholders support the full integration of renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods. Many
stakeholders note that the regulatory framework should enable RES E to participate in the
market, e.g. by adapting gate closure times and aligning product specifications. A number
of respondents also underline the need to support the development of aggregators by
removing obstacles for their activity to allow full market participation of renewables. The
approach chosen in the State aid guidelines found broad support by most stakeholders.
Wind Europe's predecessor EWEA submitted26
that in 14 out of 18 Member States, wind
generators were already balancing responsible in financial or legal terms, generally subject
to the same rules as conventional generation. However, in some Member States, balancing
costs for renewable generators appeared discriminatorily high. Important considerations
for wind generators to accept balancing responsibility were, for EWEA: (i) the existence
of a functioning intra-day and balancing market, (ii) balancing market arrangements
providing for the participation of wind power generators, as e.g. shorter gate closure time
and procurement timeframes, (iii) market mechanisms that properly value the provision of
non-frequency ancillary services for all market participants including wind power, (iv) a
satisfactory level of market transparency and proper market monitoring, (v) sophisticated
forecast methods in place in the power system and (vi) the necessary transmission
infrastructure. While forecast methods should be developed by the market and cannot be
provided directly in policy (which can only give incentives for such methods to be
improved and used), the market design initiative aims at achieving all these points.
In its consultation of national TSOs, ENTSO-E also adressed questions on balancing
responsibility. TSOs in five Member States answered that after introduction of balancing
26 http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
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responsibilities, RES E generators were more motivated to conclude energy production
contracts which are close to the real production in each market time unit; for four Member
States, better forecasts were used by RES E generators. 1 TSO provided figures according
to which the average hourly imbalance of PV installations improved from 11.2 % in 2010
to 7.0 % in March 2016, and the average hourly imbalance of wind improved from 11.1 %
to 7.4 % over the same period.
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1.3. RES E access to provision of non-frequency ancillary services
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Summary table
Objective: transparent, non-discriminatory and market based framework for non-frequency ancillary services
Option 0 Option 1 Option 2
BAU
Different requirements, awarding procedures and
remuneration schemes are currently used across
Member States. Rules and procedures are often tailored
to conventional generators and do not always abide to
transparency, non-discrimination. However increased
penetration of RES displaces conventional generation
and reduces the supply of these services.
Description
Set out EU rules for a transparent, non-discriminatory and
market based framework to the provision of non-frequency
ancillary services that allows different market players
/technology providers to compete on a level playing field.
Description
Set out broad guidelines and principles for Member States for the
adoption of transparent, non-discriminatory and market based
framework to the provision of non-frequency ancillary services.
Stronger enforcement
Provisions containing reference to transparency, non-
discrimination are contained in the Third Package.
However, there is nothing specific to the context of non-
frequency ancillary services.
Pro
Accelerate adoption in Member States of provisions that
facilitate the participation of RES E to ancillary services as
technical capabilities of RES E and other new technologies is
available, main hurdle is regulatory framework.
Clear regulatory landscape can trigger new revenue streams
and business models for generation assets.
Pro
Sets the general direction and boundaries for Member States
without being too prescriptive.
Allows gradual phase-in of services based on local/regional needs
and best practices.
Con
Resistance from Member States and national
authorities/operators due to the local/regional character of
non-frequency ancillary services provided.
Little previous experience of best practices and unclear how
to monitor these services at DSO level where most RES E is
connected.
Con
Possibility of uneven regulatory and therefore market developments
depending on how fast Member States act. This creates uncertain
prospects for businesses slowing down RES E penetration.
Most suitable option(s): Option 2 is best suited at the current stage of development of the internal electricity market. Ancillary services are currently procured and sometimes used in very
different manners in different Member States, Furthermore, new services are being developped and new market actors (e.g. batteries) are quickly developing. Setting out detailed rules required
for full harmonisation would thus preclude unknown future developments in this area, which currently is subject to almost no harmonisation.
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Description of the baseline
The delivery of frequency related ancillary services by RES E assets is partly covered by
the Balancing Guideline.
Non-frequency ancillary services are services procured or mandated by TSOs that support
the electricity network, such as voltage support, short circuit power, black start capability,
synthetic inertia or congestion management. They are in most cases supplied by electricity
generators, but can in some cases also be supplied by demand facilities, electricity storage
or network equipment.
Currently, the procurement of non-frequency anciliary services is not regulated at EU-
level. The situation in Member States for the provision of non-frequency ancillary services
is determined by national grid codes that inter alia specify the rules for connection of
generation assets to the electric network infrastructure. Grid codes are evolving
continuously, but a snapshot taken recently through studies funded by the European
Commission27
, a survey commissioned by ENTSO-E28
and by examining the actual
national grid codes, reveals that several approaches are considered in Europe across more
than a dozen Member States (as well as Norway and Switzerland) surveyed. The snapshot,
summarized in Figures 1 to 3, focuses only on the provision of reactive power, i.e. voltage
related ancillary services, one of the most important non-frequency ancillary services. It is
important to point out that the overview is partial and does not cover all specific
arrangements TSOs might have. For instance in Denmark, these services are not generally
remunerated, however in certain periods of the year when thermal plants are not operating,
these services are remunerated to guarantee sufficient supply.
27 "REserviceS project" (2014) Intelligent Energy Europe programme, http://www.reservices-project.eu/
28 "Survey on Ancillary Services Procurement and Electricity Balancing Market Design" (2015) ENTSO-
E,
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
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Figure 1: Grid code requirements for generators on reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
Figure 2: Procurement procedure of reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
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Figure 3: Remuneration of reactive power delivery
Source: National grid codes, ENTSO-E survey, REserviceS project
Currently the practises with regard to requirements, procurement and renumeration of non-
frequency anciliary services can be summarised as follows:
- Requirements: most Member States demand mandatory provision from
conventional generators and in some cases specific provisions are considered for
RES E, mostly wind. The latter approach is in line with the Commission Regulation
(EU) 2016/631 establishing a network code on requirements for grid connection of
generators ('RfG');
- Procurement: a majority of Member States procure these services through bilateral
agreements and only in a small minority of Member States market based tenders
are used. In other Member States both bilateral agreements and market based
tenders are used;
- Remuneration: about half of the surveyed Member States do not have a mechanism
to remunerate the service, the other half does remunerate them either by capability,
utilisation or a combination of both. In some Member States, a bonus is given to
RES E for upgrading the infrastructure.
Deficiencies of the current legislation
The current EU regulatory framework defines in Article 12 lit. d) of the Electricity
Directive the role of the TSO: it includes ensuring the availability of all necessary ancillary
services. However, there is nothing specific with regard to non-frequency ancillary
services. The RfG specifies extensively requirements for the provision of reactive power
by different power modules. However, it does neither address the procedures by which
such services should be awarded (e.g; a market based mechanism), nor whether they should
be remunerated (as such or on the basis of what criteria e.g. capacity, utilisation or a
combination thereof). Additionally, the RfG is not likely to lead to an efficient deployment
of reactive power capability on the territory as voltage support services have a geographical
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dimension and need to be provided in specific locations. This might lead to an oversupply
of reactive power capability (with associated increased costs born by the generators) and
at the same time underutilization of installed capability because they are not suitably
located. The System Operation Guideline aims at ensuring that TSOs use market-based
mechanisms as far as possible to ensure network security and stability, but does not
articulate further this high level principle.
The current legislation is insufficient and needs to be adapted to trends observed in the
market where studies project that the demand for non-frequency ancillary services across
Europe will increase over the coming decades, mainly because of increased RES E
penetration. A technical and economical study by Électricité de France (EDF)29
concluded
that "it is essential that variable RES production which is displacing conventional
generation is also able to contribute to the provision of ancillary services and also
potentially provide new services (e.g. inertia)". A study commissioned by the German
Energy Agency Dena30
found that "due to increasing transport distances and international
power transit, the demand for reactive power in the transmission grid will increase
significantly by 2030."
Presentation of the options
Option 0 - BAU
In a business-as-usual scenario, non-frequency ancillary services are mainly provided by
large conventional generators. Although those services are currently not remunerated in all
Member States, TSOs would need those generators to run even if not profitable. Therefore
such generators would request additional revenues. This scenario prevent the access to
additional revenue streams for new types of generation assets, mainly being RES E.
Since RES E are displacing conventional generation assets, the supply of these services is
becoming scarcer. As a result, generation from RES E would be curtailed at certain times
to guarantee the safe operation of the electric network. This would likely slow down the
deployment of RES E and affect negatively the achievement of the European wide
renewable energy consumption targets by 2020 and 2030 and related climate goals.
Option 0+: Non-regulatory approach.
The Third Package does not address the provision of non-frequency ancillary services in a
way that could be used to enforce existing legislation stronger. Voluntary cooperation does
not provide the necessary minimum degree of harmonization and legal certainty to allow
for efficient cross-border trade. Even where non-frequency anciliary services have to be
provided on a local level, the provision of and revenues from these services can have a
significant impact on the competitiveness of electricity generation, which competes cross-
border.
29
"Technical and Economic analysis of the European Electricity System with 60% RES" (2015) Alain
Burtin & Vera Silva, http://www.energypost.eu/wp-content/uploads/2015/06/EDF-study-for-download-
on-EP.pdf
30
"Dena Ancillary Services Study 2030" (2014) German Energy Agency,
http://www.dena.de/en/projects/energy-systems/dena-ancillary-services-study-2030.html
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Option 1 - EU rules setting out a framework for a transparent, non-discriminatory, market
based framework
This option would imply setting EU wide harmonized rules in EU legislation on
requirements of generators for connection to the grid, on specifications and procurements
of products to ensure a level-playing field and fair remuneration of these services. This
would encounter a number of issues: even though the provision of non-frequency ancillary
services is necessary to run a European wide electricity market, due to the local/regional
character of these services, optimal solutions may vary across Member States.
Additionally, it would require the coordination of both transmission and distribution
system operators as a large fraction of RES E is installed at the distribution level. These
services are not generally remunerated at lower voltage levels and no clear framework is
yet available on how to regulate these services. Finally, there are still significant challenges
for market based integration of ancillary services from RES E due to limitations of
predictability of energy output.
Option 2 - Guidelines setting out the principles for the adoption of a transparent, non-
discriminatory, market based framework.
The aim is to provide a sound basis for the development of a non-discriminatory,
transparent and market based access to non-frequency ancillary services by RES E and to
allow the gradual phase-in of services based on local/regional needs and best practices.
This is a pre-requisite for a cost efficient allocation of resources to provide the necessary
supply of non-frequency ancillary services. The measures should be articulated along the
following main lines:
- ensure that the regulatory requirements for the provision of these services are
rational with respect to the expected needs (both in terms of quantity and location)
and non-discriminatory with respect to different assets capable of providing the
service.
- bring transparency to the way ancillary services are procured, for instance through
market-based tenders or auctions and allow sufficient flexibility in the process to
accommodate bids from assets with different technical characteristics;
- promote mechanisms for remuneration by system operators;
- consult stakeholders when establishing new rules to make sure all assets can
participate to these services while providing support for safe grid operation.
These measures are also conducive to a higher penetration of RES E in the electricity
network and could be further developed in a dedicated network code.
Comparison of the options
The BAU scenario would not be effective in designing a level-playing field for a non-
discriminatory, transparent and market based access to non-frequency ancillary services
and in achieving the objectives of increasingly integrated RES E in a European electricity
market. It would also be an obstacle for further increase of RES E in the generation mix
with a potential negative impact on the achievement of the 2030 targets. In the current
situation, where ancillary services are provided by conventional generators, curtailment of
RES E is required at times to assure the availability of generation assets capable of
providing ancillary services (so-called "must run"). The decision to keep these resources
online is not based on economic assessments, but only on operational considerations for a
safe operation of the grid. Such constraint would not exist or not to the same extent if RES
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E resources would be used to their fullest potential to provide non-frequency ancillary
services.
Options 1 and 2 would be more effective in providing a non-discriminatory, transparent
and market-based environment for RES E and new technologies to offer and compete for
the provision of non-frequency ancillary services. Companies, especially owners of RES
E assets would benefit from additional revenue streams from ancillary markets.
Extrapolating the European wide market size for non-frequency ancillary services from
national markets (typically in the range of tens of millions of euros) puts it roughly in the
range of a few billion euros.
In addition, the investment outlook for additional power plants would be better for owners
of RES E assets. Taking Ireland as a best practice case, regulators and TSOs are
redesigning the ancillary service market in such a way that RES E can participate. It
requires introducing new services and allowing these services to be remunerated. This has
the additional benefit that the electricity generation share of RES E in such a redesigned
market can be higher without compromising the safe operation of the grid and allows
system operators to make efficiency gains: the Irish All Island TSOs compared the
estimated costs of enhancing the operational capabilities of ancillary services with the
benefits of lower market prices coming from a larger share of wind energy generation.
They concluded that the benefit outwheighted the costs already at System Non-
Synchronous Penetration levels below 50%31
.
Based on the studies and sources mentioned in this and other Sections of this annexe, little
uncertainty exists about the benefits of more transparent provision of ancillary services,
one where RES E could participate. For certain services, especially those that have a
limited geographical scope, it is unclear if and how liquid markets could be established,
with regulated cost+ payments being a possible alternative.
The second Option is preferred over the first one, because at this moment there is not
enough evidence to support European wide harmonized rules for non-frequency ancillary
services. New services are being developed and new market players are emerging. The
first option could preclude unknown future developments in this area, whereas the second
option allows the gradual phase-in of services based on local/regional needs and best
practices.
Subsidiarity
Even though non-frequency anciliary services, such as voltage related ancillary services
have a local character, it does not prevent action through the market design initiative. The
efficient provision of these services is a critical enabler of an integrated European
electricity market and of higher RES E penetration. Also, the assets that provide non-
frequency ancillary services are largely the same ones providing frequency-related
services: a local problem due to voltage stability could have implications for the provision
of frequency-related services and the stability of the grid at a European level as a whole.
Finally, the assets providing ancillary services are generally competing in other markets
31
"Onshore wind supporting the Irish grid" (2013) Andrej Gubina, http://www.reservices-project.eu/wp-
content/uploads/D5.1-REserviceS-Ireland-case-study-Final.pdf
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with a larger geographical scope, including the day ahead and intraday electricity markets.
Conditions on voltage control thus have an impact on cross-border competition in
electricity markets.
Stakeholders' opinions
RES E32
and demand response33
industry associations and owners of storage34
assets assert
the technical availability to provide non-frequency ancillary services, but expose
difficulties accessing the market because of non-transparent rules for contracting,
minimum product size and other product specifications, as well as procurement lead times.
Younicos, a storage provider, states that "storage is not defined in regulatory framework
on national or EU level, creating uncertainty on market access and creating uncertainty
on ownership roles." Similarly, the Association of European Manufacturers of automotive,
industrial and energy storage batteries (EUROBAT), calls for a legislative definition of
storage which allows system operators to own and operate battery storage. The association
calls for the value of services offered by storage systems, including voltage control,
frequency control and ramp control, to be financially recognized. Anciliary services should
thus be compensated35
. The European Wind Energy Association points out that the reactive
power requirements at low active power set points imposed on RES E in the frame of the
RfG code could potentially have a substantial negative impact on the investment costs of
new wind power plants..
Energinet.dk considers increased competition for the supply of ancillary services "as a part
of the continuous development of the energy only market with the objective to create clear
price signals and creating socio economic benefits and security of supply on short and
long run". Geographical requirements for delivery of ancillary services is a challenge in
developing these markets as well as the fact that grid components such as "synchronous
compensators and HVDC VSC-convertors have a potential to deliver system supporting
services in competition with commercial power plants. This development demands
transparency in the procurement process to secure optimal planning, operations and
investments"36
.
Two joint papers by Statkraft and Dong Energy point out that "in the past, system services
have played a marginal role in total economics of power plants. In the future, however,
system services will be more important for the individual plant and the value (balance of
32
"Balancing responsibility and costs of wind power plants" (2015) European Wind Energy Association,
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
33
"Mapping Demand Response in Europe today" (2015) Smart Energy Demand Coalition,
http://www.smartenergydemand.eu/wp-content/uploads/2015/09/Mapping-Demand-Response-in-
Europe-Today-2015.pdf
34
"Technical and regulatory aspects of the provision of ancillary services by battery storage" (2015)
Younicos
35 "Battery Energy Storage in the EU: barriers, opportunities, services and benefits" (2016) EUROBAT,
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf p.30.
36
"Markets for ancillary and system supporting services in Denmark" (2016) Energinet.dk
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supply and demand of these services) to the system are likely to be markedly higher", and
that "requirements put into tenders are crucial for the outcome".37
37
"Does the wholesale electricity market design need more products, or more control?" Part 1 (2015) &
Part 2 (2016) Dong Energy & Statkraft
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2. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(B)
STRENGTHENING SHORT-TERM MARKETS
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2.1. Reserves sizing and procurement
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Summary table
Objective: define areas wider than national borders for sizing and procurement of balancing reserves
Option 0: business as usual Option 1: national sizing and procurement
of balancing reserves on daily basis
Option 2: regional sizing and procurement of
balancing reserves
Option 3: European sizing and procurement of
balancing reserves
Description
The baseline scenario consists of
a smooth implementation of the
Balancing Guideline. Existing
on-going experiences will
remain and be free to develop
further, if so decided. However,
sizing and procurement of
balancing reserves will mainly
remain national as foreseen in
the Balancing Guideline.
Active participation in the
Balancing Stakeholder Group
could ensure stronger
enforcement of the Balancing
Guideline.
This option consists in developing a
binding regulation that would require TSOs
to size their balancing reserves on daily
probablistic methodologies. Daily
calculation allows procuring lower
balancing reserves and, together with daily
procurement, enables participation of
renewable energy sources and demand
response.
This option foressees separate procurement
of all type of reserves between upward (i.e.
increasing power output) and downward
(i.e. reducing power output; offering
demand reduction) products.
This option involves the setup of a binding
regulation requiring TSOs to use regional
platforms for the procurement of balancing
reserves. Therefore this option foresees the
implementation of an optimisation process for
the allocation of transmission capacity between
energy and balancing markets, which then
implies procuring reserves only a day ahead of
real time.
This option would result in a higher level of
coordination between European TSOs, but still
relies on the concept of local responsibilities of
individual balancing zones and remains
compatible with current operational security
principles.
This option would have a major impact on the
current design of system operation procedures
and responsibilities and current operational
security principles. A supranational
independent system operator ('EU ISO') would
be responsible for sizing and procuring
balancing reserves, cooperating with national
TSOs. This would enable TSOs to reduce the
security margin on transmission lines, thus
offering more cross-zonal transmission
capacity to the market and allowing for
additional cross-zonal exchanges and sharing
of balancing capacity.
Pros
Pro – optimal national sizing and
procurement of balancing reserves
Pro –regional areas for sizing and procurement
of balancing reserves
Pro – single European balancing zone
Cons
Con – no cross-border optimisation of
balancing reserves
Con – balancing zones still based on national
borders but cross-border optimisation possible
Con – extensive standardisation through
replacement of national systems, difficult and
costly implementation
Most suitable option(s) Option 2. Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the
physical topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the
preferred option.
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Description of the baseline
Balancing refers to the situation after markets have closed (gate closure) in which a TSO
acts to ensure that demand is equal to supply. A number of stakeholders are responsible
for organising the electricity balancing market:
- Transmission system operators ('TSOs') keep the overall supply and demand in balance
in physical terms at any given point in time. This balance guarantees the secure
operation of the electricity grid at a constant frequency of 50 Hertz.
- Balance responsible parties ('BRPs') such as producers and suppliers; keep their
individual supply and demand in balance in commercial terms. Achieving this requires
the development of well-functioning and liquid markets. BRPs need to be able to trade
via forward markets and at the day-ahead stage. They also need to be able to fine-tune
their position within the same trading day (e.g. when wind forecasts or market positions
change).
- Balancing service providers ('BSPs') such as generators, storage or demand facilities,
balance-out unforeseen fluctuations on the electricity grid by rapidly increasing or
reducing their power output. BSPs receive a capacity payment for being available when
markets have closed ('balancing capacity' also referred to as 'balancing reserve') and an
energy payment when activated by the TSO in the balancing market ('balancing
energy'). Payments for balancing capacity are often socialized via the transmission
network tariffs, whereas payments for balancing energy usually shape the price that
BRPs who are out of balance have to pay ('imbalance price').
Currently, national balancing markets in Europe have significantly different market
designs and are operated according to different principles38
. To achieve efficiency gains
through a genuine European balancing market, it is essential to provide a set of common
principles. As one can expect the adoption of the Balancing Guideline in 2017, it is possible
to agree on the baseline, which can be built upon in the market design initiative.
The Balancing Guideline covers, in particular:
- Standardisation of balancing products39
used by TSOs to maintain their system in
balance. The starting point is a situation where, in Europe, the number of balancing
products is estimated at some hundred. TSOs will have to reduce this number as much
as possible to create a harmonised competitive market.
- Merit order activation of balancing energy based on European platforms, i.e.
operational within 4 years after the entry into force, where all TSOs will have access
while taking into account cross-zonal transmission capacity available or released after
intraday gate closure.
- Single marginal pricing ('pay-as-cleared') which reflects scarcity for the remuneration
of the participants in the balancing market (i.e. the payment that a participant receives
for providing balancing energy to be the same payment as the imbalance price). Thus
being individually in imbalance but contrary to the imbalance of the system as a whole,
38
ENTSO-E survey on ancillary services, May 2016:
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
39
The term "product" refers to different balancing services which can be traded, such as the provision of
balancing energy with different speeds of delivery.
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thus helping the system as a whole to stay balanced, gets rewarded rather than
penalized.
- Harmonisation of the length of the imbalance settlement periods ('ISP' i.e. the time over
which it is measured whether BRPs stay in balance, i.e. they did not sell more
electricity than they produced). Trading products are generally not shorter than, but
can be multiples of ISP. The length of the ISP is thus of relevance for all market
timeframes and not just for the balancing market. In cross-border trade, the biggest
common ISP has to be used. Thus, the smallest trading product across Europe is
currently 60 minutes which corresponds to the length of the longest ISP across Member
States. However, where two Member States have shorter ISPs, shorter products can be
traded across their border (e.g. 30 minutes between France and Germany). To increase
the trade of short products, the Balancing Guideline proposes a shift to harmonized 15
minutes ISPs40
.
The Balancing Guideline also provides the baseline for integrating renewable energy
sources and demand response in the balancing market, in particular:
- Balancing energy gate closure time (i.e. the point in time after which there can be no
more balancing energy offers from BSPs) as close as possible to physical delivery, and
at least after intraday cross-zonal gate closure (thus a maximum of 60 minutes before
real time). Shorter gate closure time allows wind or PV generators and demand
response aggregators to update their forecast and to offer remaining energy to the
electricity balancing market.
- Possibility to offer balancing energy without a balancing capacity contract. The
procurement timeframes for balancing capacity have generally long lead times for
which wind or PV power producers and demand response aggregators cannot secure
firm capacity.
- Shorter procurement timeframes for balancing capacity (close to real time).
It would be, however, out of the scope of the Balancing Guideline to aim for full
harmonization of the currently very diverse balancing markets. The Balancing Guideline
includes many exemptions (e.g. central dispatch systems, procurement rules for balancing
capacity) and possible derogations (e.g. dual pricing as opposed to single marginal
pricing). It is therefore essential that all national balancing markets adhere to a minimal set
of common principles.
In addition, balancing reserves are currently mainly sized and procured by TSOs on a
national level (except for the Nordic countries and the Iberian Peninsula). This contrasts
with the increasing demand for balancing reserves across Europe over the coming decades
which is mainly due to large-scale cross-border flows and high volumes of variable RES
E generation. Most of the TSOs are sizing their balancing reserves based on potential
outages of HVDC interconnectors and forecast errors of renewable energy sources. Despite
40
"Frontier Economics report on the harmonisation of the imbalance settlement period", April 2016
https://www.entsoe.eu/Documents/Network%20codes%20documents/Implementation/CBA_ISP/ISP_
CBA_Final_report_29-04-2016_v4.1.pdf
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trends observed in the market (see below figure from ELIA, the Belgian TSO)41
on the
evolution of balancing reserves needs from 2013 to 2018, no significant binding
harmonisation is achieved on this subject in the Balancing Guideline.
Graph 1: Interpolated ranges for the volume of reserves needed between 2013 and
2018
Source: Belgian TSO report on the evolution of ancillary services needs to balance the Belgian control
areas towards 2018, pp. 32)
In their Market Monitoring report 201442
, ACER points out that in most European markets,
the procurement of balancing capacity represents the largest proportion of the overall costs
of balancing. The excessive weight of the balancing capacity procurement costs may
suggest that the procurement of balancing capacity is not always optimised. ACER
emphasis the importance of optimising the procurement costs of balancing capacity,
including separate procurement of upward and downward balancing capacity and shorter
procurement timeframes.
41
Belgian TSO report on the evolution of ancillary services need to balance the Belgian control area
towards 2018, May 2013
http://www.elia.be/~/media/files/Elia/Grid-data/Balancing/Reserves-Study-2018.pdf
42
"Market Monitoring Report 2014" (2015) ACER, pp. 210.
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Graph 2: Overall costs of balancing (capacity and energy) and imbalance charges
over national electricity demand in a selection of European markets – 2014
(euros/MWh)
Source: "Market Monitoring Report 2014" (2015) ACER, pp. 209
Moreover, because only flexible generation assets can provide balancing reserves,
balancing markets tend not to be very competitive. Balancing markets are regularly rather
concentrated on the supply side as only assets able to adjust production or consumption
fast can participate. In their Market Monitoring report 2014, ACER also illustrates the very
high level of concentration in the procurement of balancing capacity.
Graph 3: Level of concentration in the provision of balancing services from automatic
Frequency Restoration Reserves (capacity and energy) for a selection of Member
States – 2014 (%)
Source: "Market Monitoring Report 2014" (2015) ACER, pp. 207
Integrating balancing markets will increase competition and hence will save overall costs.
These costs are largely determined by the size of the network area for which the balancing
reserves are being procured (also referred to as 'balancing zone' or 'load-frequency control
block') and the frequency with which this is done. The size of the reserves that need to be
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set aside depends on the size of unforeseen events within a given balancing zone. Larger
zones across TSO-control areas (effectively across Member States) will result in lower
total balancing reserve requirements and reduce significantly the need for back-up
generation, as the risks to be covered are smaller than with a simple addition of the risks
of two small zones. To this end, a limited number of wider balancing zones should be
defined by the needs of the network rather than national borders.
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation)
Recitals and provisions containing reference to transparent, non-discriminatory and
market-based procedures for the procurement of balancing capacity are contained in the
Electricity Directive. However, there is nothing more specific to the procurement rules. As
part of the regional cooperation of TSOs, Article 12.2 of the Electricity Regulation refers
to the integration of balancing and reserve power mechanism. However, no further details
are being developed concerning the sizing of balancing reserves at regional level.
The Guidelines on System Operation (approved in Comitology on 4th
of May 2016)
harmonise terms, methodologies and procedures for sizing balancing reserves, but it is
expected that balancing zones (or LFC Blocks) will remain unchanged and mainly based
on national borders (except for Nordic countries and Spain-Portugal) as illustrated below.
Figure 1: Synchronous Areas, LFC Blocks (or balancing zones) and LFC Areas
Source: ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves,
2013, pp. 42
The Balancing Guideline (not yet approved in Comitology) intends to set out rules for the
procurement of balancing capacity, the activation of balancing energy and the financial
settlement of BRPs. It would also require the development of a harmonised methodology
for the reservation of cross-zonal transmission capacity for balancing purposes. However
sharing and exchange of balancing capacity would not be mandatory under the Balancing
Guideline but encouraged.
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Presentation of the options
Option 0 - BAU
The baseline scenario consists of a smooth implementation of the Balancing Guideline
where sharing and exchange of balancing capacity are not mandatory. In this way, the
existing on-going experiences (such as the regional sizing and procurement of balancing
reserves in the Nordic countries and the Iberian Peninsula) will remain and be free to
develop further and integrate, if so decided by the participating parties. Isolated and likely
incompatible projects may be implemented across Europe.
Procurement arrangements such as shorter contracting period close to real time should be
enforced in line with the development of a methodology for the reservation of cross-zonal
transmission capacity for balancing purposes.
Option 0+: Non-regulatory approach
The Third Package does not address the provision of regional sizing and procurement of
balancing reserves in a way that could be used to stronger enforce existing legislation.
Specific parts dealing with transparency, non-discrimination and market based rules can
be found in the Article 15 of the Electricity Directive. Others parts dealing with the regional
cooperation of TSOs on balancing and the optimal allocation of capacity across timeframes
can be found in Article 12.2 and Annex 1.2.6 of the Electricity Regulation.
Voluntary cooperations between TSOs for sharing and exchaning balancing capacity could
be further supported thanks to an active participation in the Balancing Stakeholder Group
established by ACER and ENTSO-E for an early implementation of the Balancing
Guideline. However no mandatory provisions in the Balancing Guideline request TSOs to
size and procure reserves at regional level.
Option 1 – National sizing and procurement of balancing reserves on a daily basis
This option consists in developing a binding regulation that would require TSOs to size
their balancing reserves on daily probabilistic methodologies (i.e. based on different
variables such as RES E generation forecasts, load fluctuations and outage statistics). This
method is opposed to a deterministic approach which consists of sizing the balancing
reserves on the value of the single largest expected generation incident. Daily calculation
allows procuring lower balancing reserves and, together with daily procurement, enables
participation of renewable energy sources and demand response.
Shorter procurement timeframes for balancing capacity facilitate the participation of wind
generators and demand response aggregators which cannot secure firm capacity over long
lead times, or storage operators, which do not have to guarantee specific amounts of energy
stored over long periods. This option foresees separate procurement of all types of reserves
between upward (i.e. increasing power output; offering demand reduction) and downward
(i.e. reducing power output; offering demand increase) products.
Option 2 – Regional sizing and procurement of balancing reserves
This option involves the set up of a European binding regulation requiring TSOs to use
regional platforms for the procurement of balancing reserves. Mandatory sharing and
exchange of balancing capacity requires firm cross-zonal transmission capacity. Therefore
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this option foresees the development of an optimisation process for the allocation of
transmission capacity between energy and balancing markets, which then implies
procuring reserves only a day ahead of real time.
This option thus has the focus on a more integrated approach on the sizing and procurement
of balancing reserves themselves. Mandatory regional procurement of balancing reserves
would require changing and harmonizing adjacent business and related operational
processes. Mandatory regional sizing of balancing reserves might have an impact on
system operation procedures and responsibilities, at least procedurally shifting security of
supply-related tasks (such as system's state analysis) to a supranational level (possibly to
newly-established regional operational centres ('ROCs'), see also Section 2.3).
TSOs would still be responsible for real-time activation of the balancing capacity procured;
however they would only have access to the regional platforms for the procurement of
balancing capacity which would assume harmonized procurement timeframes and
centralised optimisation algorithm requiring firm cross-border transmission capacity to be
available. Balancing reserves would be estimated on a daily basis and based on
probabilistic methodologies.
Option 3 – European sizing and procurement of balancing reserves
This option would result in a significant evolution of the current design in which European
electricity systems are operated. This would have a major impact on the current design of
system operation procedures and responsibilities.
This option involves setting up a binding European framework to ensure that all Member
States implement a single market design for sizing and procurement of balancing reserves.
A supranational independent system operator ('EU ISO') would be responsible for sizing
and procurement of balancing reserves, cooperating with national TSOs. This would
enable TSOs to reduce the security margin on transmission lines, thus offering more
transmission capacity to the market and allowing for additional sharing and exchanges of
balancing capacity.
Comparison of the options
Economic impacts
All three options can capture some of the potential social welfare opportunities. Option 3
would be the most effective in achieving an optimal sizing and procurement of balancing
reserves at European level. However, it might not be feasible as sharing and exchanges of
balancing capacity require firm cross-zonal transmission capacity. Such reservation might
be limited by the physical topology of the European grid (e.g. geographical distribution of
the balancing reserves to maintain operational security43
). Option 1, which foresees daily
sizing of balancing reserves at national level and separate procurement of downward and
upward balancing capacity, would result in an increased participation of wind power
producers and demand response aggregators in the balancing market. While the
improvements of national rules regarding sizing and procurement of balancing reserves
43
ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves, 2013,
pp. 75
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would allow savings around EUR 1.8 billion, it would not reap the full potential of cross-
border exchanges. Daily sizing and procurement of balancing reserves could therefore be
optimally performed at regional level. The preferred option is thus Option 2, which brings
savings of around EUR 3.4 billion.
Table 1: Economic impacts by option
BAU Option 1 Option 2 Option 3
Balancing reserves needs (GW) 53.4 52.1 29.9 17.1
Balancing reserves needs reduction - 3% 44% 68%
Annual savings (EUR billion) - 1.8 3.4 4.5
Source: METIS
Regulatory impact
The costs of sizing and procuring balancing reserves at regional level are mainly linked to
the possibility to add a task to the newly-established regional operational centres ('ROCs')
(see also Section 2.3 of the present annexes to the impact assessment). System state
analysis would have to be performed on a daily basis and regional level by the ROCs,
together with the setting-up of regional plaforms for the procurement of balancing reserves.
The option entailing the smallest change (Option 1) involves costs significantly less than
the other two options. Option 2 is likely to be more expensive as a result of the additional
tasks to ROCs and the setting-up of several new platforms for the exchange or sharing of
balancing reserves.
Subsidiarity
The subsidiarity principle is fulfilled given that the EU is best placed to provide for a
harmonised EU framework for common sizing and procurement of balancing reserves.
Most Member States currently take national approaches to size and procure balancing
reserves including often not allowing for foreign participation. As common sizing and
procurement of balancing reserves requires neighbouring TSOs' and NRAs' full
cooperation, individual Member States might not be able to deliver a workable system or
only provide suboptimal solutions.
Providing mandatory regional sizing and procurement of balancing reserves would be also
in line with the proportionality principle given that it aims at preserving the properties of
market coupling and ensuring that the distortions of uncoordinated national balancing
mechanisms are corrected and the internal market is able to deliver the benefits to
consumers.
Stakeholders' opinions
Most respondents from the Market Design consultation agreed with the need to speed up
the development of integrated short-term (balancing and intraday) markets. A significant
number of stakeholders argue that there is a need for legal measures, in addition to the
technical network codes and guidelines under development, to speed up the development
of cross-border balancing markets, and provide for clear legal principles on non-
discriminatory participation in these markets.
In ENTSO-E's view a parallel harmonization of balancing energy and balancing capacity
procedures would lead to unreasonably high effort for TSOs and would introduce
additional uncertainty and insecurity for the operation of the electricity system if made
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mandatory. However ENTSO-E and ACER recognise that common cross-border
procurement of reserves is a good target in the long-term.
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following relevant
conclusion:
"The Forum stresses the importance of balancing markets for a well-integrated and
functioning EU internal energy market. It encourages the Commission to swiftly bring the
draft Balancing Guideline to Member States for discussion, ideally before the summer,
with a view to reaching agreeement in autumn this year. It considers, however, that there
may still be improvements needed and ask the Commission to consider the provisions of
the draft Guideline carefully before presenting a formal proposal.
The Forum supports the view that further steps are needed beyond agreement and
implementation of the Balancing Guideline. In particuler, further efforts should be made
on coordinated sizing and cross-border sharing of reserve capacity. It invites the
Commission to develop proposals as part of the energy market design initiative, if the
impact assessment demonstrates a positive cost-benefit, which also ensure the effectiveness
of intraday markets."
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2.2. Removing distortions for liquid short-term markets
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Summary table
Objective: to remove any barriers that exist to liquid short-term markets, specifically in the intraday timeframe, and to ensure distortions are minimised.
Option 0 Option 1 Option 2
Description
Business as usual
Local markets mostly unregulated, allowing for national
differences, but affected by the arrangements for cross-
border intraday and day-ahead market coupling.
Stronger enforcement and volunatry cooperation
There is limited legilsation to enforce and voluntary
cooperation would not provide certainty to the market.
Fully harmonise all arrangements in local
markets.
Selected harmonisation, specifically on issues relating to gate closure
times and products.
Pros
Simplest approach, and allows the cross-border
arrangements to affect local market arrangements. Likely to
see a degree of harmonisation over time.
Would minimise distortions, with very limited
opportunity for deviation.
Targets issues that are particularly important for maximising liquidity
of short-term markets and allows for participation of demand response
and small scale RES.
Cons
Differences in national markets will remain that can act as a
barrier.
Extremely complex; even the cross-border
arrangements have not yet been decided and
need significant work from experts.
Additional benefit unclear.
May still be difficult to implement in some Member States with
implication on how the system is managed – central dispatch systems
could, in particular, be impacted by shorter gate closure time.
Most suitable option(s): Option 2 – Provides a proportionate response targeting those issues of most relevance.
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Description of the baseline
Intraday markets usually open several hours before the day of delivery and allow market
participants to trade energy products i.e. discrete quantities of energy for a set amount of
time - close to real time and as short as five minutes before delivery.
Liquid intraday markets will form a critical part of a European energy market that is able
to cost-effectively accommodate an increasing share of variable renewable sources, allow
for more demand-side participation, and allow for energy prices to reflect scarcity.
"Liquidity is a measure of the ability to buy or sell a product – such as electricity -
without causing a major change in its price and without incurring significant
transaction costs. An important feature of a liquid market is the presence of a large
number of buyers and sellers willing to transact at all times"44
.
Maximising liquidity in the intraday market will increase competitive pressure, increase
confidence in the resulting energy prices, and allow adjustment of positions close to real
time, thus reducing the need for TSO actions in the balancing timeframes (although it
should be noted that this will not by itself reduce the need for remedial actions by TSOs to
address congestion in internal grids).
- The more variable source of renewable generation in the EU energy mix, the more
impact of errors in forecasting of weather and demand. Allowing close-to-real-time
trading will allow suppliers and producers to take account of the most up-to-date
information and, therefore, reduce risk of being out of balance.
- The more trading in this market, the more likely it is to reflect the overall value of
staying in balance, thereby increasing confidence in the price. This in turn will
affect price formation in the day-ahead market and in forward markets.
Most Member States have organised intraday markets. In their Market Monitoring Report,
ACER points out a general trend to an increase in the volumes traded in national intraday
markets.
44
Ofgem, https://www.ofgem.gov.uk/electricity/wholesale-market/liquidity
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Figure 1 – ID traded volumes in selection of EU markets – 2011-2014 (TWh).
Source: PXs and the CEER national indicators database (2015), as reported in "Market Monitoring Report
2014" (2015) ACER.
However, there remains significant scope for increasing liquidity. In the same report,
ACER analyse 13 markets that make up 95% of the liquidity in intraday markets, using as
a liquidity indicator the ratio of energy volumes traded to demand. The following shows
that only 5 markets had a ratio above 1%.
ES IT PT DE GB SI BE SE LT FR CZ NL PL
12.1
%
7.4
%
7.6
%
4.6
%
4.4
%
1.0
%
1.0
%
1.0
%
1.0
%
0.7
%
0.7
%
0.2
%
0.1
%
The organisation of national intraday markets is largely unregulated in EU law. A degree
of harmonisation has developed naturally, partially due to common actors in national
markets. However, significant differences still remain. In particular:
- whilst most countries operate a continuous trading approach, some have intra-day
auctions;
- gate closure times (i.e. when the market closes) vary from between 5 minutes (BE
and NL) to 120 minutes (HU) ahead of real time. In the Iberian market, which
operates auctions, the shortest gate closure time is just over two hours, and can
extend even further depending on the hour of delivery;
- the granularity of products varies between 60 minute products and 15 minute
products;
- the minimum size of bids varies between 0.1MWh to 1MWh;
- the types of orders vary considerably;
- demand response is not consistently allowed to participate;
- whether bidding is at unit-level or portfolio-level;
- whether the organised intraday-markets are exclusive (i.e. preventing bi-lateral
trading).
Currently, cross-border trading in the intraday timeframe is not harmonised, is generally
on a border-by-border basis and the total traded volumes are low: in 2014 only 4.1% of IC
capacity was used intraday, compared to 40% day-ahead.
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The CACM guideline45
envisages a new, EU-wide cross-border market in the intraday
timeframe. Local markets will be indirectly impacted by its introduction, essentially
because it provides an extra choice for market participants on which platform to trade.
There are important interactions, notably because the two markets co-existing in this way
has the potential to split liquidity (i.e. split the trading across two markets as opposed to
one, thereby reducing the benefits of a highly liquid market). The more differences that
exist between local markets and between local markets and the cross-border market, the
greater the impact is likely to be as arbitrage opportunities between them will be reduced.
One issue exists in particular – that of gate closure times. The below diagram is an
illustration of the potential interactions between local and cross-border markets. While
both are open for trading, market participants can chose the best one, most likely driven
by price and/or products which match their needs, but potentially also by functionality and
ease-of-use of the trading platform. As such there should be a general trend towards
convergence of prices in these two markets as they will effectively be in direct competition
with each other. The more similarities in the specificities of the markets the more likely
this is to be the case. However, if the local market closes before the cross-border market,
the arbitrage opportunities are reduced as the market participants cannot freely trade
between the two. There is also a risk that local rules will mean that continued cross-border
trading will not be possible once the local market has shut, for example because it is on
this basis which the suppliers and producers provide 'firm' details on their contracted
energy to the TSO. The existence of different products and arrangements, and even
different IT systems on which to trade, also bears the risk of splitting liquidity between
different markets. However, whilst the longer-term objective should be to have one,
common market where all trading takes place and where liquidity is 'pooled', given the
starting point it is not necessarily beneficial to deliver this by harmonising all arrangements
in the short-term, as it could involve moving to the 'lowest common denominator,' as
described further below.
45
Commission Regulation (EU) 2015/1222 establishing a guideline on capacity allocation and congestion
management.
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Figure 2 – Example co-existence of local and cross-border markets, where local
market closes before cross-border.
The design of some national markets may limit the ability for RES E or Demand Response
to participate, as they will prefer shorter products as this will help them accommodate more
variability in generation and demand. Also, if products do not at least reflect the imbalance
settlement period, then market participants will not have the ability to balance themselves
sufficiently frequently.
Finally, the closer to real time that market parties are allowed to trade, the more likely it is
that their supply and demand will be in balance when it comes to delivering and consuming
energy. This is especially relevant in a market sensitive to weather fluctuations where
changes can happen after the market has closed and the participants are not able to buy or
sell energy to make up for this. It therefore becomes the responsibility of the TSO as part
of the balancing market. However, the risk is that, if set too close, TSOs will not have the
time they need after being informed of the final market results to manage the system and,
in particular, deal with internal bottlenecks.
Deficiencies of the current legislation
As detailed above, there is very limited legislation in this area. The most significant piece
is the CACM Guideline, but this only indirectly addresses the operation of national markets
and, in most cases, will not directly lead to standardised trading within local markets,
which thereby potentially creates a barrier to cross-border trade and liquidity.
The Evaluation Report for market design concluded that "the Third Energy Package does
not ensure sufficient incentives for private investments in the new generation capacities
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and network because of the minor attention in it to effective short-term markets and prices
which would reflect actual scarcity."46
Presentation of the options
Option 0 – Business as Usual
This option would leave local markets mostly unregulated, allowing for national
differences, but influenced by the arrangements for cross-border intraday and day-ahead
market coupling. The CACM Guideline requires the definition of a gate closure time on
each bidding zone border, which can be a maximum of 60 minutes. This could impact
decisions taken at national level, but this is not certain and differences are likely to remain.
Further, the definition of the products that can be taken into account in the cross-border
system are to be determined under the CACM Guideline which could, again, impact the
products which are provided in local markets.
Option 0+ Non-regulatory approach
There is very limited legislation in this area. Stronger enforcement of current rules
therefore does not provide scope to achieve a larger degree of harmoninsation of intraday
trading arrangements.
Voluntary cooperation has resulted in significant developments in the market and a lot of
benefits. However it may not provide for appropriate levels of harmonisation or certainty
to the market and legisaltion is needed in this area to address the issues in a consistent way.
Option 1 – Fully harmonise all arrangements in local markets.
This option would see all arrangements harmonised, including gate opening times, gate
closing times, products to be offered, whether markets are exclusive, and mandatory
continuous trading rather than auctions. Gate closure time would be established as close to
real time as possible, to provide maximum opportunity for the market to balance its
positions before it became the TSO responsibility. Markets would be exclusive – i.e. no
bilateral trading – and power exchanges would be obliged to offer small products, in size
and duration – likely a minimum of 0.1MWh in 15 minute blocks. Demand response
would be able to participate in all markets.
Given the difference in technical characteristics of different markets (i.e. some have very
limited internal congestion so very short gate closure times are technically feasible, whilst
others need more time to take remedial actions), this option would likely see some markets
becoming larger (with gate closure times closer to real time) and some smaller (with gate
closure times having to move further away from real time, depending on the precise time
chosen). It would also mean that products would not necessarily reflect the difference in
national systems.
Given the technicalities of this option, it would likely be developed through implementing
legislation.
46
Section 7.3.2 of the Evaluation
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Option 2 - Selected harmonisation, with additional flexibility
This option would introduce standardisation of gate closure time and products in a more
flexible way, specifically allowing some flexibility in national markets to reflect their
differentiated nature. In particular, under this option, legislation would specify:
- that intraday gate closure time in national markets must not be longer than the cross-
border intraday gate closure time. This would ensure that national markets are not
'taken out of the picture' before the cross-border markets close, and would, in effect,
mean that at a minimum market participants are allowed to trade as close as one hour
ahead of real time.
- that power exchanges must offer products that reflect the imbalance settlement period.
This will ensure that market participants are able to trade at a frequency which allows
them to stay in balance.
- that barriers to demand response participating in intraday markets must be minimised
– specifically, minimum bid size should allow for participation and there should be no
administrative barriers put in place.
This option would also see more principles added to legislation, with the aim of progressive
harmonisation over time on those design features not touched.
Comparison of the options
Option 0 (Business as usual) would keep the status quo and leave intraday markets to
evolve within Member States, with no guarantees they would develop along the same lines,
except in some areas that existing legislation touches (for example, on minimum and
maximum bid prices). There would likely be an impact as a result of the implementation
of market coupling in the intraday time-frame. With significant differences, there is a risk
that liquidity is split and benefits of short-term markets to the integration of RES E and
demand response muted.
Option 1 – full harmonisation – would likely see significant changes in a number of
markets. It would involve selecting a gate closure time and applying that to all national
markets. Whilst the precise timing could vary, it would mean that some countries would
need to keep their markets open longer, and some would need to close their markets earlier
than they currently do (notably in Belgium and the Netherlands, where trades can currently
take place up to 5 minutes prior to delivery) – harmonising gate closure times to that of the
shortest in Europe would likely be unachievable for many Member States, particularly
larger ones where the TSO requires more time between knowing the market results and
real time in order to solve internal congestion (the market is blind to congestion within a
bidding zone).
This option would also involve harmonising other aspects, as detailed above. Power
exchanges can be seen as the conduit for energy trades across borders so harmonising the
rules on which trading takes place will minimise differences between national markets and
with the common cross-border market. By increasing the arbitrage opportunities across
these markets, the risk of splitting liquidity is reduced.
On the surface, this might seem like an appropriate response akin to other single market
measures that harmonise standards so that they can be traded within the EU with minimal
barriers. However, in reality this is likely to be much more complex. A significant amount
of the process is IT-driven, and the arrangements have not yet been put in place – it would
therefore be very difficult to determine what the local arrangements should be. Further,
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there is a lack of evidence that such harmonisation would indeed lead to more cross-border
trade – the costs associated with changing IT could be significant with little benefit.
Given that the common cross-border market will likely be more complex (e.g. given the
number of variables, Member States, the fact that calculations will need to consider
available cross-border capacity) in the immediate future this market, and the IT
infrastructure that supports it, may not be able to accommodate the more granular market
arrangements that exist in some Member States. As such, moving all national markets to
the same design details of that of the cross-border market could entail some having to
reduce their granularity, move gate closure time further away from real-time, etc. This
would not fit with the objectives of the present proposal, which aims for increased
flexibility.
Option 2, however, would provide a much more proportionate response. Rather than
specifying a value for the gate closure time in local markets it would specify that it should
be no longer than the cross-border gate closure time. It will provide more opportunity for
arbitrage between markets. It will also move gate closure times closer to real-time in many
markets, which will provide more opportunities for RES E to balance themselves and
demand response to participate in the market, without forcing those markets which already
apply very short-term trading rules to switch to longer timeframes. With regards to
products the markets should be able to accommodate demand-response and small-scale
RES E. It will also leave the most technical characteristics to the implementation of the
CACM Guideline, which has the advantage of allowing specifics to be discussed in detail
with market parties and for more flexibility, i.e. allowing for easy adaptation if and when
requirements need to change.
Whilst this option will not eliminate the risk of splitting liquidity, there is in fact some
evidence that two markets can co-exist and increase overall traded volumes. In a study
looking at the impact of the introduction of an intraday auction for 15 minute products in
Germany47
, it was found that, whilst the auction pulled some value away from the
continuous intraday market, the total traded volumes increased.
47
"Intraday Markets for Power: Discretizing the Continuous Trading" Karsten Neuhoff, Nolan Ritter,
Aymen Salah-Abou-El-Enien and Philippe Vassilopoulos (2016)
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Figure 3: Volumes on the 15mn intraday market and the share of quarters in total
trading volumes (quarters+hours), EPEX (DE)
Source: Neuhoff et al (2016)
The option will also provide a good starting point for progressively harmonising with the
longer-term aim of one, common intraday market with local specificities minimised to
situations where they are justified due to local differences.
Specific impacts relating to changes in short-term markets are discussed in Section 6.1.3.
With regards to intraday, the results of the modelling indicate positive impacts of
harmonising intraday arrangements in Europe, specifically allowing for the further
reduction of RES E curtailment and lesser use of replacement reserves by 460 GWh and
95 GWh, respectively
Subsidiarity
Given that the EU energy system is highly integrated, prices in one country can have a
significant effect on prices in another, as can arrangements in local markets. Differences
in the operation of local markets can present a barrier to the cross-border trade of energy,
and continuing differences between local markets, and between local markets and the
single cross-border market, risks splitting liquidty and constraining the benefits of a
common cross-border market This will impact on liquidity and the amount of trading
which can take place, as well as erode the benefits of competition and a larger market place
in which energy can be bought and sold.
EU-level action is, therefore, necessary to ensure that the national markets are comparable,
that they enable maximum cross-border trading to happen, and facilitate liquidity as much
as possible. .
There is also a critical link with the CACM Guideline, which establishes principles and
required further methodologies for the operation of intraday markets in the cross-border
context, as well as a link with the upcoming Balancing Guideline. EU-level action is
required to ensure that trading in local markets can reap maximum benefits of the cross-
border solution under development.
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Stakeholders' opinions
Most stakeholders agree on the importance of liquid short-term markets, particularly
intraday and balancing, to the efficient operation of the internal electricity market. They
are, in general, seen as a critical part of ensuring that RES E can be propely intergrated,
notably allowing renewable generators to trade closer to real-term, as well as to stimulating
investment in sources of flexibility such as demand response. Most call for speedy
implementation of common cross-border intraday trading (market coupling) via the XBID
project, whilst recognising the progress that has already been made in day-ahead market
coupling.
Wind Europe calls upon the EU to "ensure continuous intraday trading with harmonised
gate closure times closer to real time; complementary auctions may be introduced to
increase liquidity". They argue that "implementing well-functioning intraday markets
across borders with gate-closure close to real-time will 1) provide renewable producers
with opportunities to adjust their schedule in case of forecasts errors, 2) smooth out the
variability induced by renewable in-feed over broader geographical areas"48
.
In their publication "Electricity Market Design: fit for the low-carbon transmision",
Eurelectric state:
"The development of robust cross-border intraday and balancing markets will be crucial
to ensure that the system remains balanced as the share of renewables continues to grow.
It is therefore necessary to promote a liquid continuous implicit cross-border intraday
market with harmonised products in all member states, while capacity pricing shall not
drain liquidity nor reduce the speed of market processes. The market shall be enabled to
determine the most economic dispatch until a gate closure set as close to real-time as
possible (e.g. 15 minutes). TSOs shall only perform the residual balancing of the system."49
SolarPower Europe state "progress is needed in particular with a view to achieving better
liquidity and integration of intraday and balancing markets. These short-term markets are
crucial as variable renewable energy sources take a more important role in the power mix.
Products and services should be re-defined to improve the granularity of these markets
and enable the sale of different system services that solar power and other renewables, but
also storage and demand participation can provide." 50
ENTSO-E make the point that "Accurate short-term market price formation is needed to
reveal the value of flexibility in general and of DSR specifically"51
and ACER/CEER that
"it is imperative that everything is done to make sure that price signals reflect scarcity and
to create shorter-term markets which will reward those who provide the flexibility services
which the system increasingly needs." Further, they state that "the intraday and balancing
markets will be increasingly important to valuing flexibility and there needs to be a push
48
"A market design fit for renewables". Wind Europe submission of 27 June 2016
49
"Electricity Market Design: fit for the low-carbon transmision". Eurelectirc 2016, available at
http://www.eurelectric.org/media/272634/electricity_market_design_fit_for_low-carbon_transition-
2016-2200-0004-01-e.pdf
50
"Creating a competitive market beyond subsidies" July 2015,
51
Market Design of Demand Side Response" Policy Paper, November 2015
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to deliver the cross-border intraday (XBID) project and to implement the Network Code
on Electricity Balancing as soon as possible."52
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following relevant
conclusion:
"The Forum acknowledges that, whilst cross-border day-ahead and intraday markets will
see significant harmonisation as part of the implementation of the Capacity Allocation and
Congestion Management guideline, there is significant scope for ensuring that national
markets are appropriately designed to accommodate increasing proportions of variable
generation. In particular, the Forum invites the Commission to identify those aspects of
national intraday markets that would benefit from consistency across the EU, for example
on within-zone gate closure time and products that should be offered to the market. It also
requests for action to increase transparency in the calculation of cross-zonal capacity,
with a view to maximising use of existing capacity and avoiding undue limitation and
curtailment of cross-border capacity for the purposes of solving internal congestions."
52
Joint ACER-CEER response to European Commission’s Consultation on a new Energy Market Design,
October 2015
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2.3. Improving the coordination of Transmission System Operation
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Summary table
Objective: Stronger coordination of Transmission System Operation at a regional level
Option 0 Option 1 Option 2 Option 3
Description
BAU
Limit the TSO coordination efforts to the
implementation of the new Guideline on
Transmission System Operation (voted at the
Electricity Cross Border Committee in May
2016 and to be adopted by end-2016) which
mandates the creation of Regional Security
Coordinators (RSCs) covering the whole
Europe to perform five relevant tasks at regional
level as a service provider to national TSOs.
Enhance the current set up of existing RSC by
creating Regional Operational Centers (ROCs),
centralising some additional functions at regional
level over relevant geographical areas and
delineating competences between ROCs and
national TSOs.
Go beyond the establishment of ROCs
that coexist with national TSOs and
consider the creation of Regional
Independent System Operators that can
fully take over system operation at
regional level. Transmission ownership
would remain in the hands of national
TSOs.
Create a European-wide
Independent System Operator
that can take over system
operation at EU-wide level.
Transmission ownership would
remain in the hands of national
TSOs.
Pros
Lowest political resistance. Enlarged scope of functions assuming those tasks
where centralization at regional level could bring
benefits
A limited number (5 max) of well-defined regions,
covering the whole EU, based on the grid topology
that can play an effective coordination role. One
ROC will perform all functions for a given region.
Enhanced cooperative decsion-making with a
possibility to entrust ROCs with decision making
competences on a number of issues.
Improved system and market operation
leading to optimal results including
optimized infrastructure development,
market facilitation and use of existing
infrastructure, secure real time operation.
Seamless and efficient system
and market operation.
Cons
Suboptimal in the medium and long-term. Could find political resistance towards
regionalisation. If key elements/geography are not
clearly enshrined in legislation, it might lead to a
suboptimal outcome closer to Option 0.
Politically challenging. While this option
would ultimately lead to an enhanced
system operation and might not be
discarded in the future, it is not
considered proportionate at this stage to
move directly to this option.
Extremely challenging
politically. The implications of
such an option would need to be
carefully assessed. It is
questionable whether, at least at
this stage, it would be
proportionate to take this step.
Most suitable: Most suitable option(s): Option 1 (Option 2 and Option 3 constitute the long-term vision)
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Detailed description of the baseline
Operation of the transmission system
Traditionally, prior to the restructuring of the energy sector, most electricity utilities were
run by national and very often state-owned monopolies. These were in most cases
vertically integrated utilities that owned and operated all the generation and system assets
in their allocated territories.
The adoption and implementation of the three energy packages have led to the introduction
of competition in the generation and supply of electricity, the introduction of wholesale
electricity markets for the trading of electricity as well as to different degrees of unbundling
of transmission and distribution activities, which constitute monopoly activities.
Figure 1. The electricity value chain
Source: European Commission
The fact that the activity of electricity transmission system operation is mostly national in
scope derives from the past existence of vertically integrated utilities that were active
throughout the whole electricity supply value chain. Following the restructuring of the
electricity sector, Member States naturally tasked TSOs with the responsibility of ensuring
the secure operation of the electricity system at national level.
This approach is currently reflected in the EU legislation. Article 12 of the Electricity
Directive establishes that each TSO shall be responsible, inter alia, for managing the
electricity flows on the system, taking into account exchanges with other interconnected
systems. The Commission Implementing Regulation establishing a guideline on electricity
transmission system operation ('System Operation Guideline') specifies further this
obligation and sets out a requirement on TSOs to ensure that their transmission system
remains in the normal state and makes them responsible for managing violations of
operational security53
.
Coordination of transmission system operation: shift from a voluntary approach to a
mandatory framework
Driven by the lessons learnt from the serious electrical power disruption in Europe in 2006,
European TSOs have pursued enhancing further regional cooperation and coordination. To
this end, TSOs voluntarily launched Regional Security Coordination Initiatives (RSCIs),
53
The System Operation Guideline was voted on 4 May 2016 and is due to be adopted after scrutiny by
the Council and the European Parliament.
https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20final%28provisi
onal%2904052016.pdf
Übertragung Verteilung Vertrieb
regulierter Bereich
transmission distribution supply
monopoly activity
Erzeugung
competitive activity
generation Handel
trading
competitive activity
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entities covering a greater part of the European interconnected networks aiming at
improving TSO cooperation. The main RSCIs in Europe are Coreso and TSC, both
launched in 2008, followed by the ongoing development and establishment of additional
RSCIs, such as SCC in Belgrade (launched in 2015) and an RSCI to be launched by Nordic
TSOs by the end of 2017. Currently, RSCIs monitor the operational security of the
transmission system in the region where the TSOs with membership in the RSCIs are
established and assist TSOs proactively in ensuring security of supply at a regional level.
By performing these functions, RSCIs provide TSOs with detailed forecasts of security
analysis and may propose coordinated measures that TSOs may decide or not to
implement.
In December 2015, all European TSOs except for SEPS a.s., the Slovakian TSO, signed a
multi-lateral agreement to roll out RSCIs in Europe and to have them deliver core services
to support the TSOs carry out their functions and responsibilities at national level.
R&D results: Tools for TSOs to deal with an increase in cross-border flows and variability
of generation are being developed in European projects like ITESLA and UMBRELLA.
They show that coordinated operational planning of power transmission systems is
necessary to cope with increased uncertainties and variability of (cross-border) electricity
flows. These tools help decrease redispatching costs and the available cross-border
capacity and flexibility while ensuring a high level of operational security.
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Figure 2 State of play of the voluntary membership of TSOs in RSCIs across the
European Union.
Source: European Commission (June 2016)
The voluntary establishment of RSCIs has been widely recognised as a positive step
forward for the enhancement of cooperation of transmission system operation and has been
recently formalised in EU legislation with the new System Operation Guideline.
Building on the emerging regional initiatives, the System Operation Guideline takes a
further step and mandates the cooperation of EU TSOs at regional level through the
establishment of maximum six regional security coordinators (RSCs) which will cover the
whole EU to perform a number of relevant tasks at regional level as service providers to
national TSOs.
The tasks that RSCs will perform pursuant to the System Operation Guideline are: (i)
regional operational security coordination; (ii) building of the common grid model; (iii)
regional outage coordination; and (iv) regional adequacy assessment. The task of capacity
calculation follows from the implementation of the CACM Guideline and is not assigned
in the System Operation Guideline. The draft Commission Regulation establishing a
network code on Emergency and Restoration intends to extend the tasks of RSCs to include
a consistency assessment of the TSOs' system defence plans and restoration plans.
The framework set out in the System Operation Guideline is meant to build on the existing
voluntary initiatives of TSOs (Coreso and TSC). It requires each TSO to join a RSC and
allows a degree of flexibility to TSOs to organise the coordination of regional system
operation. In this regard, the TSOs of the different capacity calculation regions will have
the freedom to appoint more than one RSC for that region and to allocate the tasks, as they
deem most efficient, between them.
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Based on the deadlines for implementation envisaged in the System Operation Guideline,
RSCs should be fully operational around mid-2019.
Box 1: Support functions to be carried out by RSCs under the network codes and
guidelines
Common grid model: The common grid model provides an EU-wide forecasted view of all major grid assets
(generation, consumption, transmission) updated every hour. RSCs will participate in the iterative process
starting from the collection of individual grid models prepared and shared by TSOs and aiming at delivering
to all RSCs and TSOs, a common grid model adequate for the other functions listed below. This function is
required at least for timeframes from year-ahead to intraday (year-ahead, week-ahead, day-ahead, and
intraday).
Operational planning security analysis: RSCs will identify risks of operational security in any part of their
regional area (mainly triggered by cross-border interdependencies). They will also identify the most efficient
remedial actions (i.e., actions implemented by TSOs aimed at maintaining or returning the electricity system
to the normal system state) in these areas and recommend them to the concerned TSOs, without being
constraint by national borders. This function covers at least the day-ahead and intraday timeframes.
Coordinated capacity calculation: RSCs will calculate the available electricity transfer capacity across
borders, using flow-based (FB) or net transfer capacity (NTC) methodologies. These methodologies aim at
optimising cross-border capacities while ensuring security of supply. This function is carried out at least on
the D-2 (for day-ahead capacity allocation) and D-1/ intraday (for intraday capacity allocation) timeframes.
Short and very short-term adequacy forecasts: RSCs will provide TSOs with consumption, production
and grid status forecasts from the day-ahead up to the week-ahead timeframe. In particular, RSCs will
perform a regional check/update of short/medium term active power adequacy, in line with agreed ENTSO-
E methodologies, for timeframes shorter than seasonal outlooks. This function is carried out week-ahead
(until day-ahead only if scarcity is detected or if there are changes in relevant hypotheses compared to week-
ahead).
Outage planning coordination: This function consists in creating a single register for all planned outages
of grid assets (overhead lines, generators, etc.). RSCs will identify outage incompatibilities between relevant
assets whose availability status has cross-border impact and limit the pan-European consequences of
necessary outages in grid and electricity production by coordinating planning outages. RSCs will carry out
this function in the year-ahead timeframe with updates up to week-ahead (on TSO requests).
Consistency assessment of the TSOs' system defence plans and restoration plans: RSCs will assist TSOs
in ensuring the consistency of the system defence plans and restoration plan.
Deficiencies of the current legislation
The regional TSO cooperation model resulting from the adoption of electricity network
codes and guidelines constitutes a positive development compared to the existing voluntary
cooperation. However, as explained below, this step, while being effective in the short-
term, is not sufficient in the medium and long-term.
The unprecedented changes concerning the integration of the European electricity markets
and the European agenda for a strong decarbonisation of the energy sector, resulting in
increasingly higher shares of decentralized and often intermittent renewable energy
sources, have made the operation of the national electricity systems much more interrelated
than in the past.
The recently voted System Operation Guideline has not entered into force and been
implemented yet. Nonetheless, as highlighted in pp 32-33 of the Evaluation, the challenges
the EU power system will be facing in the medium to long-term are pan-European and
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cannot be addressed and optimally managed by individual TSOs, rendering the current
legal framework concerning system operation not adapted to the reality of the dynamic and
intermittent nature of the future electricity system and putting into question whether the
mandated cooperation of TSOs via RSCs is fit for purpose in the post 2020 context.
First, the functions envisaged for RSCs in the System Operation and in the CACM
Guideline will not suffice in the medium to long-term as there is an increasing need for
electricity systems to be operated on a regional basis. Furthermore, there is room to enlarge
the scope of functions that would increase the efficiency of the overall system, if performed
at regional level.
Second, the geographical scope of RSCs set out in the System Operation Guideline could
not be efficient in the post 2020 context. RSCIs have grown organically with political
considerations in mind, rather than following criteria solely based on the technical
operation of the grid. The degree of flexibility envisaged in the System Operation
Guideline will allow TSOs to maintain that status quo, undermining the goal of having a
regional entity that oversees system and market operation in the region. Figure 2
representing the current membership of TSOs in RSCIs across the Union reflects this
situation (e.g., membership of TenneT NL, the TSO of the Netherlands, in TSC as opposed
to Coreso). The coordination with other regional groupings of TSOs deriving from the
implementation of other network codes and guidelines is also an issue. For example, given
the degree to which the grid is meshed in the CWE and CEE regions, it is virtually
impossible to draw permanent lines dividing the regions and still respect the electrical
interdependencies. Hence, the presence of two RSCIs (Coreso and TSC) for this region
does not seem the optimal solution to play an effective coordination role.
Third, the implementation of the System Operation Guideline will entail that RSCs will
play an increasingly important support role for TSOs. However, the full decision-making
responsibility will remain with TSOs who will have to do the grid planning while taking
into consideration also new options to grid extensions (such as energy storage). RSCs will
not have executive powers and their activities will be limited to providing planning
services to individual TSOs, who can accept or reject those services and who will retail
full control of and accountability for the planning and operation of their individual
networks. For example, when deciding about the commercial cross-border capacities in a
given region which are already calculated at regional level, the decision taken by RSCs are
non-binding meaning that they can be considered as an input that can be changed by TSOs
based on national interest (e.g. in case of scarcity of supply in one country the TSO might
be tempted to reduce their export capacities but this might not be the best decision from a
regional system security perspective) or due to constraints in the national legal framework.
In this regard, the rejection of a recommendation by a TSO would suffice to put in question
the overall set of recommendations issued by a RSC. For example, if in a recommendation
for an optimal set of remedial actions a given TSO did not agree, this would imply the
whole recalculation of remedial actions for the region since such measures are usually
interdependent. There is additional evidence pointing out to this problem. The ACER
market monitoring report 2015 (to be published in 2016) remarks that there are strong
indications that during the capacity calculation process TSOs resort to unequally treating
internal and cross-zonal flows on their networks.
To conclude, while the enhanced regional TSO cooperation resulting from the adoption of
electricity network codes and guidelines constitutes a positive step forward, it is important
to note that it will not allow realising the full potential of these regional entities in the
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medium to long-term. If the benefits of market integration are to be fully realised, TSOs
will have to cooperate even more closely at regional level. This will require adjusting the
way in which the operation of the electricity system will be managed under the System
Operation Guideline.
Presentation of the options
Option 0 - BAU
Option 0 would be to stop the coordination efforts at this stage and limit it to the progress
achieved with the implementation of the System Operation Guideline.
The upcoming RSCs will have the following features:
i. Functions. Five main functions54
will be performed by the upcoming RSCs as
service providers to national TSOs under the network codes and guidelines (see
Box 1 above for a more detailed explanation of each of these functions).
a. Coordinated Security Analysis (including Remedial Actions-related
analysis)
b. Common Grid Model Delivery
c. Outage Planning Coordination
d. Short and Very Short Term Resource Adequacy Forecasts
e. Coordinated Capacity Calculation
The addition of new functions would mainly depend on the voluntary initiative of
TSOs, which in some instances could lead to inefficient outcomes given that they
would not always have the "regional" perspective in mind but rather their own
interest, particularly given the flexibility at the time of defining the geographical
scope.
Geographic scope. While RSCs will give full coverage across the EU, the size and
composition of the regions where they will be established may not always be
defined having the technical operation of the grid in mind. Business and political
criteria could also play a role. In particular, TSOs in a region would continue having
flexibility to decide which RSC provides a given service (including new ones
developed voluntarily) to that region. This would allow a given region to get
services from different RSCs. While this has been accepted as a valid compromise
in the short-term, it undermines the goal of having a regional entity with enhanced
overview over system and market operation in the region.
ii. Decision-making responsibilities. The upcoming RSCs will not have any decision-
making powers but a purely advisory role. The responsibility for system operation
will remain with TSOs at national level. The fact that RSCs issue recommendations
means that ultimately an individual TSO may be constrained by the national
framework and reject the implementation of such recommendation, against the
interest of all the other TSOs of the region. Hence, the set up of the RSC being able
54
Six functions with the adoption of the Emergency and Restoration network code ('Consistency
assessment of TSOs' system defence plans and restoration plans').
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to provide an added value at regional level would be compromised. For example,
as described above, if in a recommendation for an optimal set of remedial actions
a given TSO did not agree, this would imply the whole recalculation of remedial
actions for the region since these measures are usually interdependent.
iii. Institutional layout/governance. The interaction between the RSCs, NRAs, TSOs,
ACER and ENTSO-E would remain as set out in the System Operation Guideline.
Essentially, TSOs and NRAs would continue to be responsible for the direct
implementation and oversight of RSCs at national level. ACER and ENTSO-E
would remain responsible for ensuring the cooperation of NRAs and TSOs at EU
level, respectively.
Option 0+: Non-regulatory approach
Stronger enforcement would not suffice to address the needs of the electricity system
regarding stronger TSO cooperation at regional level.. As in option 0, any progress beyond
the framework in the System Operation Guideline and the application of other network
codes would depend on the voluntary initiatives of TSOs. However, the voluntary
initiatives would be limited due to the constraints resulting from differing legislation at
national level. Hence, stronger enforcement or a voluntary approach is not a possible
option.
Option 1: Enhance the current set up of existing RSCs by creating ROCs, centralising some
additional functions over relevant geographical areas and optimising competences between
ROCs and national TSOs
Option 1 would aim at enhancing the current set up of existing RSCs by creating ROCs.
ROCs are not meant to substitute TSOs but to complement their role at regional level. This
option would set out a number of basic elements in legislation but allow flexibility to
TSOs to work out the details on how the ROCs will function and perform their tasks. ROCs
will present the the following features:
i. Functions. Enlarged scope of functions, assuming new tasks where centralization
at regional level could bring benefits. These functions would not cover real time
operation which would be left solely in the hands of national TSOs. In addition to
the functions emanating from existing network codes and guidelines (see Box 1),
these functions would be:
a. Solidarity in crisis situations: Management of generation shortages;
Supporting the coordination and optimisation of regional restoration
b. Sizing and procurement of balancing reserves
c. Transparency: Post-operation and post-disturbances analysis and reporting;
Optimisation of TSO-TSO compensation mechanisms
d. Risk-preparedness plans (if delegated by ENTSO-E)
e. Training and certification (if delegated by ENTSO-E)
ii. Geographic scope. A limited number of well-defined regions, covering the whole
EU. TSOs establishing the ROCs will need to decide the scope of these regions
based on technical criteria (e.g. grid topology) to ensure that they can play an
effective coordination role. In contrast to what is currently in the System Operation
Guideline, each ROC would perform all functions for a given region. Larger
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regions could include, if necessary, back-up centres and/or sub regional desks when
for example some functions would require specific knowledge of smaller portions
of the grid.
iii. Cooperative decision-making. ROCs would have an enhanced advisory role for all
functions. In order to respect to the maximum possible extent the regional
recommendations, TSOs should transparently explain when and why they reject
the recommendation of the ROC. Given that a role limited to issuing
recommendations may lead to sub-optimal results as regards the performance of
some of the functions55
, decision-making powers could be entrusted to ROCs for
a number of relevant issues (i.e., remedial actions, capacity calculation) either
directly by a Regulation or subsquentely by mutual agreement of the NRAs or
Member States overseeing a certain ROC. By optimising decision-making
responsibilities between ROCs and national TSOs the seamless system operation
between the ROCs and the TSOs would be ensured.
iv. Institutional layout/governance. Enhanced cooperation between TSOs would be
accompanied by an increased level of cooperation between regulators and
governments as well as by an increased oversight from ACER and ENTSO-E.
55
This sub-optimal situation would derive from the fact that the rejection by a single TSO of the
recommendation issued by the ROC would put in question the overall set of recommendations.
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Box 2: Additional functions performed by ROCs under Option 1
Option 2: Creation of Regional Independent System Operators
Option 2 would be to go beyond the establishment of ROCs that coexist with national
TSOs and consider the creation of Regional Independent System Operators (RISOs) that
can fully take over system operation at regional level.
RISOs would have the following features:
i. Functions. RISOs would have an enlarged scope of functions compared to ROCs.
In addition to the functions under Option 1, RISOs would also be responsible for
real time operation of the electricity system (e.g., operation of real time balancing
markets) and for infrastructure planning. Infrastructure related functions could
include for example the identification of the transmission capacity needs:
proposing priorities for network investments based on the long-term resource
adequacy assessment, the situation in the interconnected system and identified
- Solidarity in crisis situations:
- Management of generation shortages. ROCs would optimise the generation park in a region while
attempting to increase transmission capacity to the Member State which suffers generation
shortage. The aim of this function is to avoid load cuts (energy non served situations) in a country
while other countries still optimise the market and/or enjoy high generation margins.
- Supporting the coordination and optimisation of regional restoration. ROCs would recommend the
regional necessities during restoration (e.g., resynchronisation sequence of large islands in case of
the split of a synchronous area).
- Sizing and procurement of balancing reserves:
- Regional calculation of daily balancing reserves. ROCs would carry out regional sizing of daily
balancing reserves (disregarding political borders and considering only technical limitations related
to geographical dispersion of reserves) on the basis of common probabilistic methodologies (i.e.
balancing reserve needs based on different variables such as RES generation forecast, load
fluctuations and outage statistics).
- Regional procurement of balancing reserves. ROCs would create regional platforms for the
procurement of balancing reserves, complementing the regional sizing of balancing reserves.
- Transparency:
- Post operation and post disturbances analyses and reporting. ROCs would carry out centralised
post-operations analyses and reporting, going beyond the existing ENTSO-E Incidents
Classification Scale (ICS).
- Optimisation of TSO-TSO compensation mechanisms. ROCs would administer common money
flows among TSOs, such as Inter-TSO Compensation (ITC), congestion rent sharing, re-dispatching
cost sharing, cross-border cost allocation (CBCA). Furthermore, ROCs should propose
improvements to the schemes based on technical criteria and aiming for the optimal overall
incentives.
- Risk-preparedness plans. If delegated by ENTSO-E, the ROCs' function would be to identify the
relevant risk scenarios in its region that the risk preparedness plans should cover. Based on ROCs'
proposals, Member States would develop the plans. ROCs could organise crisis simulations (stress
tests) together with Member States and other relevant stakeholders. During such crisis simulations the
plans would be tested to check if they are suited to address the identified cross-border or regional crisis
scenarios.
- Medium term adequacy assessments: if delegated by ENTSO-E, ROCs would complement the
ENTSO-E seasonal outlooks with adequacy assessments carried out in a regional context where
possible crisis scenarios (e.g. prolonged cold spell), including simultaneous crisis, should be identified
and simulated.
- Training and certification. The network code on staff training and certification as foreseen in the
ACER framework guideline on system operation is still pending. ROCs could cover functions related
to trainings between TSOs as well as centralise of some trainings in issues related to cross-border
system operation. Further, this function should allow regional training on simulators (IT system based
on a relevant representation of the system, including networks, generation and load).
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structural congestions, while considering an interconnected system without
political borders.
ii. Geographic scope. The scope of RISOs would be the same as for ROCs.
iii. Decision-making responsibilities. All system operation functions would be
performed by the RISOs, which would have decision-making powers. Existing
TSOs would remain as transmission owners and solely operate physically the
transmission assets and provide technical support to RISOs (e.g., collection and
sharing of data).
iv. Institutional layout/Governance. Additional changes in the institutional framework
would be required to enable the RISO approach. For example, it would be
necessary to amend the powers and competences of TSOs, of regulatory authorities
and of ACER in order to ensure the appropriate oversight of these entities. It would
also be necessary to consider aspects such as the financing of RISOs or the
applicability of unbundling rules.
Option 3: creation of a European-wide Independent System Operator
Option 3 would imply the creation of a European-wide Independent System Operation (EU
ISO) that would take over system operation at EU-wide level.
This entity would have the following features:
i. Functions. The functions would be the same as those proposed under Option 2 for
RISOs.
ii. Geographic scope. The EU ISO would be responsible for system operation at EU-
wide level.
iii. Decision-making responsibilities: The EU ISO would perform all system operation
functions and hence would have decision-making powers. TSOs would solely
operate physically the transmission assets and provide technical support to RISOs
(e.g., collection and sharing of data).
iv. Institutional layout/Governance: significant changes would be required in the
institutional framework to enable the creation of an EU ISO and an effective
oversight of its acitivities. It would be necessary to amend the powers and
competences of TSOs, of regulatory authorities and of ACER. It would also be
necessary to consider aspects such as its financing, monitoring of its performance,
etc.
Comparison of the options
The following Section provides a comparison of the options described above based on the
four main elements identified: (i) functions; (ii) geographical scope; (iii) decision-making
competences; and (iv) institutional layout/ governance. Given that only a few studies have
been carried out on this field, the assessment of the options will be mainly qualitative,
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based on the feedback received from stakeholders and on the content of the studies
published to date, and providing figures where they exist.
(i) Functions
It is not possible to provide a complete quantification of the costs and benefits of each of
the Options as regards the set of functions to be performed at regional or EU level given
that few studies have assessed these costs and benefits. However, the insights from several
previous studies cover the potential benefits of a supranational approach to system
operation.
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Table 1 Functions that would be covered under each of the options
RSCs
(Option
0)
ROCs
(Option
1)
RISOs/EU
ISO
(Options 2
and 3)
System Operation
Coordinated Security Analysis (including Remedial Actions-
related analysis)
x x56 x
Common Grid Model Delivery x x x
Outage Planning Coordination x x x
Short and Medium Term Resource Adequacy Forecasts x x x
Regional system defence and restoration plans x x x
Centralised post operation analyses and reporting x x
Training and certification x x
Market Related
Coordinated Capacity Calculation x57
x58 x
Coordinated sizing and procurement of balancing reserves x x
Network Planning
Identification of the transmission capacity needs x
Technical and economic assessment of CBCA cases x
Administration of TSO-TSO compensation mechanisms (ITC,
congestion rent sharing, redispatching cost sharing, CBCA)
x x
Risk-preparedness
Support Member States on development of risk preparedness
plans
x x
Source: DG ENER
56
It could include decision-making powers.
57
The CACM Guideline provides for regional capacity calculators. However, following the commitments
of ENTSO-E, this role could be already assumed for RSCs.
58
It could include decision-making powers.
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Table 2 Qualitative estimate of the economic impact of the Options:
Option 0: RSC
approach
Option 1: ROC
approach
Option 2: RISO
approach
Option 3: EU
ISO approach
Economic Impact
Enhancing security of supply by
minimising the risk of blackouts59
60
0/+ + ++ ++
Lowering costs through increased
efficiency in system operation61 62
63
0/+ ++ +++ +++
Maximising transmission capacity
offered to the market64
0/+ ++ +++ +++
Reducing the need of remedial
actions by coordinating and
activating in a coordinated way
redispatching65 66
0/+ ++ +++ +++
Minimising the costs of balancing
provision by taking a more
coordinated approach towards the
sizing of balancing reserves67 68 69
0/+ ++ +++ +++
Optimisation of infrastructure
planning70
0 0 ++ +++
Enhancing transparency71 0 0/+ + +
Costs of implementation72 0/- - --- ----
Other impacts
Administrative impacts/
governance
0/- - -- ---
Source: DG ENER.The assumptions in this table are based on the studies existing in this field as well as on
the feedback received from stakeholders in their response to the public consultation and from estimations
concerning the resources of RSCs and ENTSO-E.
In sum, as illustrated in Table 2, the set of functions in Option 0 will entail limited costs
and benefits, since many of these functions are already carried out by RSCIs in their
supporting role to TSOs. The implementation of the System Operation Guideline and
establishment of ROCs will not involve significant changes to the status quo. The set of
additional functions under Option 1 will entail efficiency gains and increase social welfare
that will derive from providing additional functions to ROCs to be optimised at regional
level (as opposed to national level)73
. In addition, it will entail costs related to the shift of
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59
The financial and social impact of wide area security breaches is enormous: as estimated by ENTSO-E,
the economic impact of wide area security breaches could be really important; the cost of a 20 GW load
disconnection during a large brownout is estimated to 800 million euros per hour (i. e. 40 euros / kWh).
Blackouts have an even higher impact. This provides quantified insight into the importance of optimised
emergency and restoration efforts with a central coordination of locally required efforts.
60
ENTSO-E (2014), "Policy Paper on Future TSO Coordination for Europe", Retrieved from:
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/141119_ENTS
O-E_Policy_Paper_Future_TSO_Coordination_for_Europe.pdf
61
The management of generation shortages should increase the regional social welfare as a result of a
decrease of financial losses that would otherwise result from disconnection of load. It would also
increase solidarity and promote trust in the internal energy market.
62
Also, some of the benefits will derive from the optimisation of training and certification. TSOs will gain
more practical experiences using same tools, practicing common scenarios and sharing best practices.
This should lead to faster system restoration and more efficient tackling of regional-wide system events.
63
A regional approach to adequacy assessment enhances the use of cross-border connections at critical
moments, resulting in an overall less required generating capacity in Europe. The enhancement is
expected to increase with increasing variable renewable energy in the system. The IEA mentions a
benefit of 1.4 euros/MWh based on the study of Booz & co. An example for regional adequacy
assessment is provided by the Pentalateral Energy Forum.
64
A supranational approach (moving local responsibilities to ROCs) to capacity calculation can bring
significant welfare benefits due to more efficient use of infrastructure and the consequent benefits
coming from the improved arbitrage between price zones. The CACM Guideline Impact assessment
estimates the welfare gains of a supranational approach to flow-based capacity calculation to be in the
region of 200-600 million euros per year. These benefits would only partially materialise (20% of
welfare gains would not be realised) on a voluntary basis, leaving significant parts of the capacities used
in a suboptimal manner.
65
Significant benefits are expected by the fact that enhanced TSO cooperation minimises the need for
redispatching, especially costly emergency actions. To illustrate, Kunz et al. quantified the benefits of
coordinating congestion management in Germany: in case each TSO is responsible to relief overflows
within its own zone with its own resources, which reflects the current situation in Germany closest,
redispatch costs of 138.2 million euros per year accrue. Coordinating the use of transmission capacities
renders costs of 56.4 million euros per year. As a benchmark, one single unrestricted TSO across all
zones would have to bear redispatch expenditures of 8.7 million euros per year. Kunz et al. also
quantified the benefits of coordinating congestion management cross-border (for the region comprising
Germany, Poland, Czech Republic, Austria, Slovakia): without coordination, total costs of congestion
management amount to 350 million euros per year, they decrease to 70 million euros per year for
optimised congestion management (including remedial actions and flow-based cross-border capacity
allocation).
66
Kunz et al., "Coordinating Cross-Country Congestion Management", DIW Berlin , 2016 and Kunz et
al., "Benefits of Coordinating Congestion Management in Germany", DIW Berlin, 2013
67
As regards the regional sizing and procurement of balancing reserves, the added value of this function
is gain in social welfare due to decreased size of needed balancing reserves and gains in techno-economic
optimisation of the procurement of the needed balancing reserves. Shared balancing has cost advantages
residing from netting of imbalances between balancing areas and from shared procurement of balancing
resources or reserves. This can be based on exchanging surpluses or based on a shared or common merit
order for all balancing resources. Mott Macdonald mentions potential overall benefits from allowing
cross-border trading of balancing energy and the exchanging and sharing of balancing reserve services
of the order of 3 billion euros per year and reduced (up to 40% less) requirements for reserve capacity.
This is for a European electricity supply system with roughly 45% renewable energy.
68
Mott MacDonald (2013), "Impact Assessment on European Electricity Balancing Market" Retrieved
from: https://ec.europa.eu/energy/sites/ener/files/documents/20130610_eu_balancing_master.pdf
69
According to the study carried out by Artelys on Electricity balancing: market integration & regional
procurement, regional sizing and procurement of reserves by ROCs could lead to benefits of 2.9 billion
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these functions from national to regional level (e.g., development of processes and tools at
regional level) and will have an impact on the institutional structures (i.e., need to adapt
the institutional framework to ensure the proper monitoring of implementation of the
functions). Option 2 will present additional gains and costs compared to Option 1. The
benefits will result from the more integrated operation of the system at regional level as
well as from the additional set of functions to be performed by RISOs, which will comprise
real-time operation of the electricity system. The costs will derive from the need to develop
new methodologies, processes and tools to ensure the performance of these additional
functions and the need to adapt the current oversight of the performance of these functions.
Option 3 is the option that will entail most economic gains (deriving from the efficiencies
of performance of the functions at EU level) and also most implementation costs.
(ii) Geographic scope
In the current context of the rolling out of RSCs (Option 0), there will be certain flexibility
for TSOs to decide which coordinator provides a given service to a region. This could
allow a given region to get services from different providers. While this is an acceptable
compromise in the short and medium term, it partly undermines the goal of having a
regional entity with enhanced overview over system operation and market operation in the
region. In addition, although there will be full European coverage by the RSCs (with a
maximum number of 6), the size and composition of the regions is not always defined
having the technical operation of the grid in mind. Business and political criteria play also
a role in it.
Euros (compared to 1.8 billion euros benefits from national sizing and procurement). An EU-wide sizing
and procurement of balancing reserves would lead to benefits of 3.8 billion Euros.
70
The added value as regards the identification of the transmission capacity needs at regional level is the
provision of neutral, regional view of investments needs. The industry represented by Eurelectric claims
that "Network investment planning and the coordination of TSOs' network investment decisions by the
RISOs are the next natural steps." As regards the technical and economic assessment of cross-border
cost allocation (CBCA) cases, benefits are expected from higher efficiency and quicker processes for
important transmission infrastructure projects.
71
As regards the optimisation of TSO-TSO compensation mechanisms, the added value is increased
transparency and step-by-step optimisation of the schemes, resulting in more cost-efficient operation of
the system. This is supported by Eurelectric which states that "Regarding coordination of network
investment decisions, this would require the development of mechanisms for inter-TSO money flows.
Development of inter-TSO money flows will also allow efficient coordinated redispatching, as requested
by the CACM Guideline. This is considered to be a key element for enabling efficient intraday capacity
(re-)calculation". See Eurelectric, "Develop a regional approach to system operation", June 2016. As
regards, post operation and post disturbances analyses and reporting, the added value is increased
transparency, better regional understanding and improvement process, as well as and potential efficiency
gains.
72
The costs of establishing ROCs, RISOs or an EU ISO are estimated to range between 9.9 and 35.6
million EUR per entity. See "Electricity Balancing" Artelys (2016). The study does not provide a break
out of the costs between Options 1, 2 and 3 but assumes that the costs will vary depending on the
functions and responsibilities attributed to these entities.
73
For instance, the management of generation shortages based on seasonal outlooks should increase the
regional social welfare as a result of a decrease of financial losses that would otherwise result from
disconnection of load.
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Option 1 would allow ROCs to play an effective coordination role leading to enhanced
system security and market efficiency – given that the ROCs would be able to optimise the
operations over larger regions74
. In contrast with Option 0, the regions would be defined
according to market and system operation criteria (e.g. grid topology). Having a limited
number of ROCs will also bring in savings in developing system operation tools. However,
there would be costs related to the need to adapt further the geographical scope from RSCs
to ROCs but this could be mitigated through a carefully planned implementation. In Option
1, ROCs would have the possibility to include back-up centres that ensure that one centre
can take over from the other if a problem arises and/or include sub-regional desks for
looking at issues where a more detailed assessment is needed. This could for example be
the case if a ROC is created for the Continental Europe synchronous area (or at least for
Central Western Europe and Central Eastern Europe) as a natural evolution of the existing
Coreso and TSC coordinators – in this case, it could be natural to have a set up with two
locations within a ROC (e.g. Munich and Brussels, if current coordinadors were to keep
existing locations).
The benefits and shortcomings of Option 2 would be similar to those of Option 1 as the
geographical scope of both options would be the same.
Option 3 would entail that the EU ISO is responsible for performing all the functions at
EU level. This approach would lead to efficiency gains, as it would no longer be necessary
to ensure the coordination and cooperation between entities at regional level and all the
functions could be performed seamlessly. However, it is questionable whether from a
technical point of view, at this stage, a single entity would be capable of carrying out all
these functions at EU level even if it envisages setting up sub-regional desks for the more
detailed assessment of regions.
(iii) Decision-making competences
In Option 0, RSCs have a purely advisory role i.e. the recommendations that they issue
can be overriden by TSOs75
. This would be the option less politically sensitive. However,
this can potentially lead to inefficient outcomes. For example, when deciding about the
commercial cross-border capacities in a given region which are already calculated at
regional level, the decision taken by RSCs in the form of recommendations are non-
binding. These decisions can be considered as an input that can be rejected by TSOs based
on national interest (e.g. in case of scarcity of supply in one country the TSO might be
tempted to reduce their export capacities but this might not be the best decision from a
regional system security perspective) or due to constraints in their national framework
(e.g., in the case of cross-border remedial actions, a TSO may be obliged to reject the
recommendations issued by the ROC given that the national framework requires a different
order of implementation of remedial actions).
74
This would also pave the way for a further long term evolution towards Regional Independent System
Operatiors.
75
Indeed, coordination between TSOs through RSCs could be successful if the national frameworks were
harmonised. However, since national frameworks may differ significantly, voluntary coordination is not
likely to be optimal in the medium term.
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In Option 1 ROCs would have an enhanced advisory role for all functions. Under this
option, ROCs could be entrusted with certain decision-making competences (as opposed
to a pure service provision role) to avoid the possibility of regional optimisation being lost
due to national constraints. This approach is likely to lead to more efficient outcomes since
there would be a margin for overcoming obstacles deriving from the national framework
(e.g. remedial actions, capacity calculation). In the case of the example above, when
deciding about the commercial cross-border capacities in a given region which are already
calculated at regional level, the decisions taken by ROCs could be final and binding. Whilst
this option is likely to bring more efficient outcomes, it is also likely to be more politically
controversial, especially with TSOs and Member States. However, other stakeholders have
expressed support for this option76
. This could be done either directly enshrining the
functions in legislation or subsequently by mutual agreement of the NRAs overseeing a
certain ROC.
In Option 2 with RISOs that can fully take over system operation at regional level, all
functions carried out by RISOs would be binding since they would fully replace the
functions performed at national level. Entrusting decision making powers to RISOs would
be justified based on the fact that system operation decisions might span well beyond the
area of a single TSO and affect the whole system. This would be the basis for a regional
system operation77
. However, this option would be extremely sensitive politically and
would likely be rejected by many Member States.
Option 3 would require entrusting the performance of the functions and associated
decision-making powers to a single entity, the EU ISO, who would take binding decisions.
This option would set the basis for a truly European operation of the electricity system.
While there would be additional efficiency gains compared to those resulting from Option
2 (e.g., it would no longer be necessary to ensure the coordination of operations of a
number of entities at regional level), it is unclear whether this option is technically feasible
at this stage. Option 3 would also be politically unacceptable.
76
Eurelectric has recently pointed out that "A step-wise regional integration of system operation and of
planning tasks relevant to cross-border trade therefore needs to happen. Such a process should build
upon the ongoing establishment of RSCs, which are executing a certain number of system operation
tasks on behalf of the national TSOs and could be a step towards gradually allocating the responsibility
for those tasks to regional entities". Eurelectric, "Develop a regional approach to system operation",
June 2016. Also, in response to the Commission Public Consultation on a new energy market design,
Acciona emphasised that "system operation should be coordinated at the same level as markets are, to
efficiently manage electricity systems as an integrated whole. Therefore, a regional responsibility for
system security should gradually replace national responsibilities". Also in its response to the Public
Consultation, Engie submitted that "current national responsibility for system operation indeed hampers
cross-border cooperation and is not mimicking the progress made on side of market integration:
different capacity calculation in the flow based approaches are leading to lower capacity" and that it
"favours closer cooperation of TSOs and RSCs taking over new functions progressively (eventually
replacing national TSOs in those functions). Stepwise approach is needed." In its response to the Public
Consultation, Business Europe has stated that "establishing regional system operators, based on a costs-
benefits analysis, could be a first step towards more operational coordination of TSOs in the future".
77
In this regard, Eurelectric has highlighted that "A truly regional system operation can however only be
based on a regional decision-making structure and a single operational framework. Establishing
regional integrated system operators performing system operation and planning tasks in all regions
should therefore be the end goal to allow for more operational coordination of TSOs". Eurelectric,
"Develop a regional approach to system operation", June 2016
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(iv) Institutional layout/Governance
Option 0 would not require significant institutional changes, as the interaction between
RSCs, NRAs, TSOs, ACER and ENTSO-E would remain as set out in the System
Operation Guideline. Option 1 would require increasing the level of cooperation between
NRAs and governments, as well as additional competences for ACER and ENTSO-E, to
ensure the oversight of ROCs. Options 2 and 3 would each require substantial changes to
the institutional framework in order to encompass the switch of decision-making powers
for system operation from a national to a regional or EU-wide level. The costs and speed
of implementation would also increase for each of the options, being Option 3 the most
costly and most timely.
(v) Conclusion of evaluation
The Table below provides a qualitative comparison of the Options in terms of their
effectiveness, efficiency and coherence of responding to specific criteria.
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Table 1: (The assumptions in this table are based on the feedback received from
stakeholders in their response to the public consultation and from additional submissions
from ACER).
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Criteria Option 0:
BAU
Option 1:
ROC
approach
Option 2:
RISO approach
Option 3;
EU ISO approach
Quality 0/+
Progress remains
limited due to
zones not based
on technical
operation of the
grid
+
More efficient
as optimisation
over zones
based on
technical
operation of the
grid
++
Very efficient
because of enhanced
system operation at
regional level
+++
Most efficient because
of seamless system
operation at EU level
Speed of
implementation
+
Can build upon
established
structures
(RSCIs)
0
Can partially
build upon
established
structures;
change in
geographical
scope and
functions
--
Can partially build
upon established
structures but it will
require a substancial
centralization at
regional level;
change in
geographical scope
of functions; it
would require a
substantial amount
of time for
implementation.
---
Cannot build on
established structures.
Substantial change in
geographical scope of
functions. It would
require a substantial
amount of time for
implementation
Use of
established
institutional
processes
++
Can build upon
established
structures (no
decision-making
responsibility)
-
Requires
building up
new structures/
processes
(possibly some
decision-
making
responsibility)
--
Requires building
up new structures/
processes (decision-
making
responsibility for all
regional relevant
functions)
---
Requires building
additional structures
and processes that are
adapted for the
operation of this entity
at EU level (decision-
making
responsibilities for all
functions at EU level)
Secure
operation of the
network
0/+
Mandated
cooperation;
slightly reduced
risk of blackout
+
Enhanced
cooperation via
ROCs; reduced
risk of blackout
++
Integration via
RISOs; significantly
reduced risk of
blackout
+++
Seampless operation
at EU level;
significantly reduced
risk of blackout
Efficient
organisational
structure
-
Sub-optimal
organisational
structure; a given
region can get
services from
different
providers
++
Efficient
organisational
structure can be
created; all
services for a
region carried
out by one
company
+++
Efficient
organisational
structure can be
created; all services
for a region carried
out by one company
+++
Efficient
organisational
structure can be
created; all services at
EU level carried out
by a single company
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Political
sensitivity
0
Politically most
acceptable as it
represents the
convergence
achieved during
discussions with
Member States
and stakeholders
for the System
Operation
Guideline
-
Politically
sensitive due to
shift in
decision-
making
responsibility
for relevant
functions
--
Extremely
politically sensitive
due to shift in
decision-making
responsibility
---
Politically
unacceptable at this
stage
In summary:
While Option 0 will allow achieving some progress in terms of regional coordination
which might be sufficient in the short to medium term, it risks falling short and being
suboptimal in the post 2020 context with the subsequent negative consequences in terms
of system security and market efficiency78
. It would also affect the effectiveness of many
of the other proposals of the market design initiative and be a missed opportunity to
propose legislation on the field that can shape the EU power system in the future.
Option 1 is the preferred option to respond to the post 2020 challenges in system operation.
Execution of the additional functions as outlined in Option 1 will lead to the ROCs
approach, featuring benefits in efficiency and security, but also leading to increased needs
for resources at regional level (data systems, experienced staff). Allowing ROCs to be
entrusted with certain decision-making responsibilities (as opposed to a pure service
provision role) will avoid the possibility of regional optimisation being lost due to
constraints resulting from differences in the national frameworks. This option enhances
the effectiveness of many other proposals of the market design initiative.
Option 2 and Option 3 would constitute the most preferable options from the point of
view of seamless system operation, efficiency and economic gains. While they should not
be discarded as a direction that should be followed in the future, none of these options are
considered proportionate at this stage. Moreover, the feasibility of Option 3 is
questionable. Option 2 is supported by some stakeholders as a long-term goal79
.
78
Eurelectric shares this view and has recently stated that "Current TSOs coordination initiatives such as
RSCs are steps in the right direction. The harmonisation and integration requirements developed in the
System Operation Guideline are nevertheless not ambitious enough. Indeed, these approaches remain
mostly national with the aim to protect the autonomy of individual system operators. Most importantly,
those initiatives do not fully equip system operators to cope with the challenges of a low-carbon power
power system". Eurelectric, "Develop a regional approach to system operation", June 2016
79
For example, Eurelectric declares that "A truly regional system operation can however only be based
on a regional decision-making structure and a single operational framework. Establishing regional
integrated system operators performing system operation and planning tasks in all regions should
therefore be the end goal to allow for more operational coordination of TSOs". Moreover, it states that
"The transistion towards a truly integrated and decarbonised elecricity market will be more efficient if
the electricity system is optimised on a regionla and ultimately a European basis (e.g. TSOs should
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Figure 3 below describes a stepwise approach for the implementation of the future
ROCs
Source: Commission.
Subsidiarity
The subsidiarity principle is respected given that the challenges the EU power system will
be facing in the post 2020 context are pan-European and cannot be addressed and optimally
managed by individual TSOs. While the mandated TSO cooperation via the establishment
of Regional Security Coordinators (RSCs) envisaged in the System Operation Guideline
constitutes a positive step forward because they will play an increasingly important support
role for TSOs, the full decision-making responsibility will remain with TSOs. This
framework will however not suffice to address the reality of the dynamic and variable
nature of the future electricity system, in which stressed system situations will become
more frequent. This is why it would be required to make the concept of RSCs further evolve
towards the creation of ROCs, centralising some functions over relevant geographical
areas.
The creation of ROCs and allocation of competences to these entities would also be in line
with the proportionality principle given that it does not aim at replacing national TSOs but
rather at complementing the functions which have regional relevance and cannot be
optimally performed in isolation any longer. The competences of ROCs will be limited to
operate the system as "one"). This will require a high degree of cooperation between system operators
and the harmonisation of system operation rules. […] Establishing regional integrated system operators
performing system operation and planning tasks in all regions should therefore be the end goal to allow
for more operational coordination of TSOs". Eurelectric, "Develop a regional approach to system
operation", June 2016. In addition, in response to the Commission public consultation on a new energy
market design, Fortum submitted that "the goal should be that the market, in practice, sees only one
TSO. It could be done by [an] European TSO or by current TSOs improving their cooperation".
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specific operational functions at regional level, for cross-border relevant issues in the high
voltage grid and will exclude real-time operation.
Stakeholders' opinions
Based on the results of the Public Consultation, as concerns the proposal to foster regional
cooperation of TSOs, a clear majority of stakeholders is in favour of closer cooperation
between TSOs. Stakeholders mentioned different functions which could be better operated
by TSOs in a regional set-up and called for less fragmentation in some important work of
TSOs. Around half of those who want stronger TSO cooperation are also in favour of
regional decision-making responsibilities (e.g. for Regional Security Coordinators). Views
were split on whether national security of supply responsibility is an obstacle to cross-
border cooperation and whether regional responsibility would be an option.
The participants to the European Electricity Regulatory Forum have also recently
emphasised the need for closer cooperation between TSOs, enlarging the scope of
functions and optimising the geographical coverage of regional centres. It recognised,
however, that there were divering opinions as regards the delineation of responsibilities
between regional centres and national TSOs and that further consideration was needed80
.
The creation of Regional Operational Centres will be likely seen with concern by TSOs
and a large number of Member States which seem to consider that the currently foreseen
cooperation via Regional Security Coordinators is fit for purpose. In particular, Member
States are likely to oppose any step oriented to entrust regional structures with decision
making powers under the assumption that security of supply is a national responsibility.
Regarding the regions, Member States might prefer geographical dimensions based on
governance rather than what would be optimal from a technical point of view.
80
See Florence Forum conclusions of March 2016:
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-%20Florence%20Forum%20-
%20Final.pdf
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3. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(C); PULLING
DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE MARKET
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3.1. Unlocking demand side response
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Summary table
Objective: Unlock the full potential of demand response
Option O: BAU Option 1: Give consumers access to
technologies that allow them to participate
in price based demand response schemes
Option 2: as Option 1 but also fully enable
incentive based demand response
Option 3: mandatory smart meter roll out and full
EU framework for incentive based demand
response
Stronger enforcement of existing
legislation that requires Member
States to roll out smart meters if a
cost-benefit analysis is positive and
to ensure that demand side resources
can participate alongside supply in
retail and wholesale markets
Give each consumer the right to request the
installation of, or the upgrade to, a smart
meter with all 10 recommended
functionalities.
Give the right to every consumer to request
a dynamic electricity pricing contract.
In addition to measures described under Option
1, grant consumers access to electricity markets
through their supplier or through third parties
(e.g. independent aggregators) to trade their
flexibility. This requires the definition of EU
wide principles concerning demand response
and flexibility services.
Mandatory roll out of smart meters with full
functionalities to 80% of consumers by 2025
Fully harmonised rules on demand response
including rules on penalties and compensation
payments.
No new legislative intervention. This option will give every consumer the
right and the means (fit-for-purpose smart
meter and dynamic pricing contract) to fully
engage in price based DR if (s)he wishes to
do so.
This option will allow price and incentive
based DR as well as flexibility services to
further develop across the EU. Common
principles for incentive based DR will also
facilitate the opening of balancing markets for
cross-border trade.
This guarantees that 80% of consumers across the
EU have access to fully functional smart meters by
2025 and hence can fully participate in price based
DR and that market barriers for incentive based
DR are removed in all Member States.
Roll out of smart meters will remain
limited to those Member States that
have a positive cost/benefit analysis.
In many Member States market
barriers for demand response may not
be fully removed and DR will not
deliver to its potential.
Roll out of smart meters on a per customer
basis will not allow reaping in full system-
wide benefits, or benefits of economies of
scale (reduced roll out costs)
Incentive based demand response will not
develop across Europe.
As for Option 1, access to smart meters and
hence to price based DR will remain limited.
Member States will continue to have freedom
to design detailed market rules that may hinder
the full development of demand response.
It ignores the fact that in 11 Member States the
overall costs of a large-scale roll out exceed the
benefits and hence that in those Member States a
full roll-out is not economically viable under
current conditions.
Fully harmonised rules on demand response
cannot take into account national differences in
how e.g. balancing markets are organised and may
lead to suboptimal solutions.
Most suitable option(s): Option 2. Only the second option is suited to untap the potential of demand response and hence reduce overall system costs while respecting subsidiarity
principles. The third option is likely to deliver the full potential of demand response but may do so at a too high cost at least in those Member States where the roll out of smart meters is not
yet economically viable. Options zero and one are not likely to have a relevant impact on the development of demand response and reduction of electricity system cost.
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Description of the baseline
For the purpose of this exercise a clear distinction has to be made between technological
prerequisites and market arrangements for demand response as those aspects are regulated
separately. As such chapter 3.2.1 will focus on the baseline for smart metering and 3.2.2
on dynamic prices and market regulation.
3.1.2.1. Smart Metering
Current Legislation on Smart Metering
Smart metering is a key element in the development of a modern, consumer-centric retail
energy system which encompasses active involvement of consumers. In recognition
hereof, provisions were included in the Gas Directive and in the Electricity Directive
fostering the smart metering roll-out and targeting the active participation of consumers in
the energy supply market. These provisions were then complemented with provisions
under the Energy Performance in Buildings Directive, and the Energy Efficiency Directive.
The Electricity and Gas Directives81
require Member States to ensure the implementation
of intelligent metering systems that shall assist the active participation of consumers in the
energy supply market, and encourage decentralised generation82
, and promote energy
efficiency. Article 3 (11) of the Electricity Directive and Article 3(8) of the Gas Directive
explicitly state that “in order to promote energy efficiency, Member States or, where a
Member State has so provided, the regulatory authority shall strongly recommend that
electricity (or natural gas) undertakings optimise the use of electricity (or gas), for
example by providing energy management services, developing innovative pricing
formulas, or introducing intelligent metering systems or smart grids, where appropriate.”
This implementation may be conditional, according to Annex I.2 of both the electricity and
gas Directive, on a positive economic assessment of the long-term cost and benefits to be
completed by 3 September 2012. For electricity, the roll-out can be limited to 80% by 2020
of those positively assessed cases as potentially indicated in a cost-benefit analysis ('CBA').
Furthermore, Member States, or any competent authority they designate, are obliged
according to the Electricity and Gas Directive (Annex I.2) to “ensure the interoperability
of those metering systems to be implemented within their territories” and to “have due
regard to the use of appropriate standards and best practice and the importance of the
development of the internal market” in electricity or natural gas, respectively.
The recast of the Energy Performance of Building Directive ('EPBD'), adopted in May
2010, obliges (Art 8(2)) Member States to "encourage the introduction of intelligent
metering systems whenever a building is constructed or undergoes major renovation,
whilst ensuring that this encouragement is in line with point 2 of Annex I to [the Electricity
Directive]".
81
Annex I.2 of the Electricity Directive and of the Gas Directive.
82
Specifically for electricity and linked to smart grid deployment - Electricity Directive, recital (27)
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To assist with the preparations for the roll-out, and based on lessons learned and good
practices identified through experiences accumulated in Member States, the Commission
adopted the Recommendation on preparations for the roll-out of smart metering systems83
.
It aimed at guiding Member States in their choices, drawing particular attention to: (i) key
functionalities for fit-for-purpose and pro-consumer arrangements84
; (ii) data protection
and security issues; and (iii), a methodology for a CBA that takes account of all costs and
benefits, to the market and the individual consumer, of the roll-out. Following this
Recommendation, complementary smart metering provisions were adopted as part of the
Energy Efficiency Directive85
.
Smart Metering Deployment in Member States
According to data from the Commission Report "Benchmarking smart metering
deployment in the EU-27", as also recently updated86
, to date 19 Member States have
committed to rolling out close to 200 million smart meters for electricity by 2020 at a total
potential investment of EUR 35 billion.
- 17 Member States - Sweden, Italy, Finland, Malta, Spain, Austria, Poland, UK-GB,
Estonia, Romania, Greece, France, Netherlands, Denmark, Luxembourg, Ireland,
and lately Latvia – are targeting a nation-wide roll-out to at least 80% of customers
by 2020 (with 13 of them going much beyond the target of the Electricity
Directive).
- 2 Member States – Germany, Slovakia - are moving to deployment in a selected
segment of consumers (to max. 23% by 2020).
- The rest 9 Member States have either decided against at least under current
conditions, or have not made a firm commitment yet for a mass-scale or even a
selective roll-out.
By 2020, it is projected that almost 72% of European consumers will have a smart meter
for electricity87
. Smart meters for electricity are already being rolled out across the EU. As
of 2013, nearly all consumers in Sweden, Finland and Italy, were equipped with smart
meters.
Despite the progress noted, these implementation plans are falling short of the legislation's
intentions. For various legal and technical reasons, the current advancement is rather slow
83
Commission Recommendation on preparations for the roll-out of smart metering systems (2012)
http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32012H0148
84
When it comes to functionalities for electricity smart metering, particularly important for residential
consumers are: a readings' update rate of 15 minutes and a standardised interface to transfer and visualise
individual consumption data in combination with information on market conditions and service or price
options.
85
Energy Efficiency Directive. Art 9(2), 12(2b)
86
"Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States" (2015) Smart Grids Task Force Expert
Group 1;
https://ec.europa.eu/energy/sites/ener/files/documents/EG1_Final%20Report_SM%20Interop%20Stan
dards%20Function.pdf
87
Report from the Commission "Benchmarking smart metering deployment in the EU-27 with a focus on
electricity" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN
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– particularly in view of the fast approaching 2020 target in the case of electricity – and
the progress gap to delivery may be further widened by recurring delays in national
programmes88
. In addition, there is a risk that the systems being rolled-out do not bring all
the desired benefits to consumers and the market as a whole as they do not include the
necessary functionalities to do so. Furthermore, they might not support in all cases
standardised interfaces89
– at home or station level – for the delivery of these
functionalities, nor be complemented with additional specifications for improving
interoperability on these interfaces and the smooth exchange of information and inter-
working between the metering infrastructure and devices or other network platforms in the
energy market.
In all cases, the successful roll-out is controlled to a large extent by Member States who
are ultimately responsible for the deployment and respective market arrangements90
, and
may or may not decide to follow the guidelines tabled by the Commission regarding
functionalities and implementation measures for data privacy and security (see Energy
Efficiency Directive (Art 9(2b)) and Commission Recommendations "on the preparations
for the roll-out of smart metering systems", and "on the data protection impact assessment
template for smart grids and smart metering systems" 91
).
3.1.2.2. Market arrangements for demand response
Legislative Background
Mechanisms to remove the barriers to demand flexibility are set out in the Electricity
Directive. The Energy Efficiency Directive ('EED') builds on those provisions and
elaborates further, promoting its access to and participation in the market and the removal
of existing barriers.
The Electricity Directive refers to demand response measures as a means to pursue a wide
range of system benefits. The Directive clearly identifies demand response as an alternative
to generation to be considered on an equal footing, e.g. when Member States are launching
tendering procedures for new capacity in situations where the resource adequacy is
insufficient to ensure security of supply (e.g. Art. 8 Electricity Directive). Demand
response, alongside energy efficiency, is viewed as one of the measures to combat climate
change and ensure security of supply. Demand response is recognised as a means to
provide ancillary services to the system in the provisions related to TSO tasks (Art. 12(d)
Electricity Directive), and demand side management/energy efficiency measures must be
considered as an investment alternative in the context of distribution network development
by DSOs planning for new grid capacity (Art. 25(7) Electricity Directive).
88
See the Smart Metering Annex of Market Design Evaluation.
89
"Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States" (2015) Smart Grids Task Force Expert
Group 1.
90
Commission Staff Working Document "Cost-benefit analyses & state of play of smart metering
deployment in the EU-27" (2014), sections 2.4 and 2.7
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A52014SC0189
91
"Commission Recommendation on the Data Protection Impact Assessment Template for Smart Grid and
Smart Metering Systems" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=uriserv%3AOJ.L_.2014.300.01.0063.01.ENG
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Effective price signals are important to encourage efficient use of energy and demand
response. In this context, recital 45 of the EED indicates that Member States should ensure
that national energy regulatory authorities are able to ensure that network tariffs and
regulations support dynamic pricing for demand response measures by final customers.
Under Art. 15(1) EED, Member States must ensure that network regulation and tariffs meet
criteria listed in Annex XI of the EED, which inter alia refer to different possibilities for
network and retail tariffs to support dynamic pricing for demand response and incentivise
consumers. According to Article 15(4) EED, Member States must ensure the removal of
those incentives in transmission and distribution tariffs that might hamper participation of
demand response in balancing markets and ancillary services procurement. Most relevant
in the context of this impact assessment is however, Article 15(8) EED. In summary,
Member States must comply with the following obligations:
- Ensure that national energy regulatory authorities encourage the participation of
demand side resources, including demand response, alongside supply in wholesale
and retail markets;
- Ensure – subject to technical constraints inherent in managing networks - that TSOs
and DSOs treat demand response providers, including demand aggregators in a
non-discriminatory way and on the basis of their technical capabilities;
- Promote - subject to technical constraints inherent in managing networks - access
to and participation of demand response in balancing, reserve and other system
services markets, requiring that the technical or contractual modalities to promote
participation of demand response in balancing, reserve and other system services
markets - including the participation of aggregators - be defined;
- Ensure the removal of those incentives in transmission and distribution tariffs that
might hamper participation of demand response in balancing markets and ancillary
services procurement92
.
Situation in Member States with regards to demand response
The EU demand response market is still in its early development phase. This early
development has proceeded very differently across Member States that have chosen
different approaches to make use of demand side flexibility and to implement demand
response. In fact, while Article 15.8 EED formulates principles for the market access of
demand service providers and demand side products it has left substantial freedom for
Member States to implement these.
While a full transposition check of Art 15.8 EED has not yet been carried out it can already
be seen that different national provisions have led to a fragmented European market on
demand response with different rules and market opportunities for (independent) demand
response service providers, different market arrangements between service providers and
balancing responsible parties (including compensation payments) and different rules for
trading flexibility in the balancing, wholesale and capacity markets.
Explicit (or incentive based) demand response
92
See guidance note on Energy Efficiency Directive Art 15 which also covered Industrial Emissions
Directive elements http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:52013SC0450
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For explicit demand response, full customer participation in the electricity markets is a
prerequisite as addressed in the relevant provisions of the EED. However, because of its
complexity only very large industrial consumers can directly engage in the electricity
markets while commercial and residential consumers will in most of the cases need to go
through demand response service providers (aggregators). These require fair market access
for such aggregators and open balancing, wholesale and capacity markets for flexibility
products.
a) Market Access for aggregators
The EED stipulates that demand response providers (including aggregators) have to be
treated in a non-discriminatory manner. However, market access and market rules for
aggregators are regulated differently across Europe. In order to ensure full access to the
market at least the following main features have to be addressed in national regulation:
- Clear definition of roles and responsibilities of aggregators within the energy
market to ensure legal certainty;
- Clear definition of the relationship between aggregators and Balancing
Responsible Parties ('BRPs') that ensures market access of the aggregators at fair
conditions. Such rules are essential to ensure that the BRP (which is usually the
supplier) has no means of stopping a competitor (e.g. independent aggregator) for
engaging with one of its customers and entering the market.
In many Member States such a framework for aggregators is effectively missing or
independent aggregation is legally banned. This applies for Bulgaria, Croatia, Cyprus,
Czech Republic, Estonia, Greece Italy, Malta, Portugal, Spain and Slovakia. But also in
Member States where legislation for aggregators and demand response has been
established many differences can be noted.
To date, France is the only Member State that developed a complete framework for demand
response explicitly enabling independent aggregation by guaranteeing contractual freedom
between the consumer and the aggregator without supplier's consent. A standardised
framework also exists for the compensation mechanisms, however, it is claimed by some
stakeholders that this mechanism greatly penalises the aggregator, overcompensates the
BRP and hence renders the business case for independent aggregators negative.
Other Member States allow (independent) aggregation but to varying degrees. Independent
aggregators are allowed in Belgium, Ireland, UK, Germany and Austria albeit not all
markets are effectively opened to them as rules, e.g. in Austria, effectively limit their
activity to aggregate loads of big consumers. In some Member States like Poland, the
Netherlands and in the Nordic markets aggregators have also to become suppliers or offer
their services jointly with suppliers but cannot act as completely independent service
providers. In all Member States, apart from France, the UK and Ireland, the explicit consent
of the consumer's supplier is required for aggregators to enter into the market. Equally in
those Member States, a clear framework for compensation payments is missing and
therefore such payments may need to be individually negotiated between the independent
aggregator and supplier as a precondition for accessing the consumer. As such, the
incumbent supplier can effectively block market access at least for independent
aggregators.
b) Access of flexibility to the markets
The EED requires Member States to promote access to and participation of demand
response in balancing, reserve and other system services markets inter alia by engaging
the national authorities (or where relevant, the TSOs and DSOs) to define technical
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modalities on the basis of the technical requirements of these markets and the capabilities
of demand response; these specifications must include the participation of aggregators.
Technical modalities or requirements can be for example the minimum size of a load, the
activation time or the duration for which a product needs to be provided. Traditionally,
requirements have been designed along the capacities of big generation units, e.g. coal
power plants. Demand side products naturally face problems to meet these requirements,
even if aggregated. Another aspect is that prequalification requirements often have to be
fulfilled per unit and not at the aggregated level. As the following stock-taking will show,
access of demand resources to the wholesale, balancing and recently capacity markets
varies considerably across Member States.
The analysis of the status quo suggests that in most of the Member States access to the
markets is either up-front restricted or preconditions make it difficult for demand side
products to qualify and compete. In roughly only a third of the Member States demand side
products have fair access to the markets and in even fewer Member States demand response
is actually happening. Generally, the balancing markets tend to be more open to demand
side products than the wholesale markets.
In many Member States demand side resources do not play any role in the markets.
Examples for this situation would be Cyprus, Malta and Croatia. But also in many other
Member States markets are practically closed and allow for only very restricted
participation of the demand side. Often it is only suppliers or big industrial actors that are
allowed to bid in the markets. In those cases, there are usually very specific demand
flexibility programmes for selected, mainly very large, actors. For example, in Italy, Spain
and Greece interruptibility programmes have been or are being introduced for large
industrial loads.
Other countries are one step ahead and have partly opened their markets, while practical
barriers still hamper the market access. The balancing market in Germany for example is
in principle open to demand loads, but heavy prequalification (e.g. extensive testing) and
programme requirements (e.g. bid size) block any major remand response-activity.
Similarly, practical barriers, in particular for aggregated demand, hamper access to the –
theoretically open – balancing markets in Slovenia and Denmark and to some degree also
in Sweden.
There is a group of countries where demand response has already assumed a more
important role. Belgium for example adapted their technical requirements and offers quite
a large range of possibilities for demand side resources to participate in the balancing and
ancillary services markets. In the UK, the market for ancillary services93
is open to demand
response and a dedicated 'Demand Side Balancing Reserve' mechanism was established in
2015. Meanwhile, France has become probably the Member State with the broadest general
access of demand response to both the balancing and the wholesale market. A general
framework is in place that facilitates demand side participation, which has caused demand
response providers to begin expanding onto this market.
The table below summarizes in which Member States markets are open to demand
response and the amount of incentive based demand response currently estimated in those
93
The range of functions which TSOs contract so that they can guarantee system security, including black
start capability, frequency response, fast reserve and the provision of reactive power.
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Member States. While demand response is allowed to participate in most Member States,
activated volumes of more than 100 GW can only be found in 13 Member States.
Table 1: Uptake of incentive-based demand response
Member State
Demand Side
Products (DSP) in
energy markets
DSP in balancing
markets
DSP in capacity
mechanisms
Estimated
demand
response for
2016 (in GW)
Austria Yes Yes 104
Belgium Yes Yes Yes 689
Bulgaria No No 0
Croatia No No 0
Cyprus No market No market 0
Czech Republic Yes Yes 49
Denmark Yes Yes 566
Estonia Yes No 0
Finland Yes Yes Yes 810
France Yes Yes Yes 1689
Germany Yes Yes Yes 860
Greece No (2015) No 1527
Hungary Yes Yes 30
Ireland Yes Yes Yes 48
Italy Yes No Yes 4131
Latvia Yes No Yes 7
Lithuania unclear No 0
Luxembourg No information No information
Malta No market No market
Netherlands Yes Yes 170
Poland Yes Yes No 228
Portugal Yes No 40
Romania Yes Yes 79
Slovakia Yes Yes 40
Slovenia No Yes 21
Spain Yes No Yes 2083
Sweden Yes Yes Yes 666
UK Yes Yes Yes 1792
Total 15628
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering"(2016) COWI
Implicit (price based) demand response
For implicit demand response, smart metering systems as well as the availability of
dynamic pricing contracts linked to the wholesale market are prerequisites. For smart
metering systems roll-out plans exist for 17 Member States, while in 2 Member States a
partial roll-out is planned and in a number of those Member States the functionalities of
the smart metering systems (enabling communication interfaces, frequent update intervals,
advanced tariffication, etc.) may not allow for automatically reacting to price signals (a
complete analysis is provided within the evaluation fiche on smart metering). EU
legislation does not currently impose any requirements on Member States to activate price
based (or implicit) demand response.
In order to activate price based demand response the availability of dynamic electricity
pricing contracts are a prerequisite as those contracts can incentivise consumers to adjust
their consumption according to the real time price signal. The ACER/CEER Market
Monitoring Report contains a dedicated analysis of the competition situation in all Member
States in the retail market and the different offers available to the customers. This analysis
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shows that only in Denmark, Sweden and Finland dynamic pricing contracts that are linked
to the spot market are available to residential consumers while only in Sweden and Norway
such contracts represent more than 10% of all consumer contracts. In terms of costs for the
consumers the ACER/CEER analysis shows that offers linked to the spot market are
slightly cheaper for the consumer than fixed or variable offers in the same country.
Graph 1: Type of energy pricing of electricity offers in EU Member States capital
cities,
Source: "Market Monitoring Report 2014" (2015) ACER
In addition to the three Member States addressed above also in Estonia, Spain, Austria,
Belgium, Netherlands and Germany dynamic pricing contracts are available on the market
– at least for certain consumer groups - which were not yet included in the ACER/CEER
analysis. However, the uptake of such tariffs is currently very low and no detailed data is
available yet.
As a high level estimate for the EU, studies and data support current load shifting due to
times of use tariffs and price based demand response ranging from negligible (most
Member States), to around 1% (most Northern European Countries) to 6-7% (Finland and
France). The overall load that is shifted due to Time-of-Use ('ToU') and dynamic tariffs to
date would be of the order of 5.7GW (or 1.2% of peak load in Member States where
dynamic tariffs are offered).
While data on current demand response levels is difficult to obtain, estimates from the
impact assessment study94
indicate the use of approx. 21.4 GW of demand response per
year in Europe including the 5.7GW from ToU and dynamic tariffs referred to above. This
is only a small fraction of the demand response potential that adds up to approx. 120.000
MW in 2020 and 160.000 MW in 2030 which will lay mainly with residential consumers.
However, this potential is purely theoretical (not taking into account commercial viability
and technology restriction) and for 2030 greatly depends on the uptake of flexible loads
such as electric vehicles and heat pumps in the residential sector.
94
"Impact Assessment support Study on downstream flexibility, demand response and smart metering",
(2016) COWI
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Graph 2: Theoretical demand response potential 2030
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
Deficiencies of current legislation
A detailed analysis of the existing legislation on smart metering systems and demand
response in European and national legislation has been carried out in the framework of the
evaluation. The detailed results of this analysis are reported in the annexes to the Market
Design Initiative evaluation (annexes on "Details on the EU framework for smart metering
roll-out and use of smart meters" and "Details on the EU framework for Demand Side
Flexibility")
3.1.3.1. Deficiencies of current Smart Metering Legislation
Looking at the current situation with smart metering deployment in the Member States,
despite the progress noted, EU-wide implementation is falling short of the legislator's
intentions, in terms of level of commitment, roll-out speed, and purpose. In the light of the
developments so far, the existing provisions can be assessed as follows.
In terms of effectiveness, the evidence available generally suggests that the smart metering
provisions currently in place have been less effective than intended. This is partly a result
of the 'soft'/unspecific nature of some obligations they lay (i.e. Article 8(2) of the EPBD.
Enforcing the recommended95
minimum functionalities for smart metering systems on an
EU level, and consistently promoting the use of available standards to ensure connectivity
and 'interoperability', as well as best practices, while having due regard to data security
and privacy, would guarantee a coherent, future-proof system able to support novel energy
services and deliver benefits to consumers, in line with the legislator's intentions.
95 Commission Recommendation on preparations for the roll-out of smart metering systems (2012)
http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32012H0148
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
Industrial
Commercial
Residential
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There is not enough evidence at the moment to evaluate the efficiency of the intervention
in terms of proportionality between impacts and resources/means deployed. This is due to
the fact that most of the large-scale roll-out campaigns have yet to start unfolding making
the field data available rather scarce; there are only projections available based on Member
States cost-benefit assessments.
In terms of relevance, the evaluated smart metering provisions, considering current needs
and problems, remain highly valid. This said, they could though be further enhanced, by
elaborating them as to: (i) spell out how the term of 'active participation' is to be
understood, and expected to be realised in practical terms, namely define requirements for
functionality, connectivity, interoperability, and standards to use; (ii) include an obligation
to Member States to officially set the minimum technical and functional requirements for
the smart metering systems to be deployed, the market arrangements, and clarify the
roles/responsibilities of those involved in the roll-out.
In terms of coherence – internally and with other EU actions – even though no clear
contradictions could be pointed out, the evaluation has identified some room for
improvement. Linking of the term 'actual time of use' in Article 9(2a) and Article 9(1) EED
to smart metering provisions erroneously restricts the functional requirements of the
targeted set-ups and raises questions about coherence with the framework for promoting
smart meters. There is therefore a need to clarify that a wide range of functionalities is in
fact promoted, as those recommended by the Commission, that go much beyond the
capability of just 'actual time of use' information which usually refers to advanced, and not
smart metering.
Finally, evidence points to the need to eliminate ambiguities and to further elaborate,
clarify, and even strengthen the existing provisions, in order to give certainty to those
planning to invest and ensure that smart metering roll-outs move in the right direction, and
regain EU added-value. This is to be done by: (i) safeguarding common functionality, and
share of best practices; (ii) ensuring coherence, interoperability, synergies, and economies
of scale, boosting competitiveness of European industry (both in manufacturing and in
energy services and product provision); and (iii), ultimately delivering the right conditions
for the internal market benefits to reach also consumers across the EU.
3.1.3.2. Deficiencies of current regulation on demand response
It was the objective of the existing European legislation to put demand response on equal
footing with generation and to ensure that demand response providers, including
aggregators, are treated in a non-discriminatory way. While provisions aiming at realising
those objectives have been put in place in many Member States, the development of
demand response across Member States varies significantly and has led to fragmented
markets. Especially the different treatment of independent aggregators across the EU is a
matter of concern. It can therefore be concluded that additional provisions further
specifying the existing provisions are needed to ensure a harmonised development and
enable price and incentive based demand response across Europe.
In terms of effectiveness, the evidence available generally suggests that the demand
response provisions currently in place have been less effective than intended. The
provisions have not been effective in removing the primary market barriers especially for
independent demand response service-providers and creating a level playing field for them.
Instead the heterogeneous development of demand response has led to fragmented markets
across the EU. This is mainly due to the high degree of freedom the existing provisions
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leave to Member States. The different treatment especially of independent demand
response service-providers in national energy markets as well as of flexibility products in
electricity markets risk undermining the large-scale deployment of demand response
needed as well as the functioning of the internal energy market.
There is not enough evidence at the moment to evaluate the efficiency of the intervention
in terms of proportionality between impacts and resources/means deployed.
In terms of relevance, the herein evaluated demand response provisions remain highly
valid. Full exploitation of demand response remains crucial to manage the energy transition
as it is an enabler for efficiently integrating variable renewables into the energy system.
However, as pointed out above, the existing provisions have not been effective in
deploying demand response sufficiently quickly across Europe.
In terms of coherence the evaluation has shown that the provisions on demand response
are fully coherent with other legislative provisions within the Electricity Directive, the
EED, the RED and the EPBD.
Finally, considering the EU added value, it remains crucial to ensure that harmonised
demand response provisions are in place across the EU to guarantee a functioning internal
energy market. Even more because under the upgrading of the wholesale market within
the market design initiative the Commission will also look into opening national balancing
markets where flexibility may then be traded across borders. Full availability of demand
response in all Member States will then be crucial for the functioning of those cross-border
balancing markets.
Presentation of the options
Option 0: BAU
As outlined in chapter 3 the existing provisions on smart meters and demand response have
not proven to be fully effective in reaching the goals of rolling out fully functional smart
metering systems to at least 80% of consumers EU-wide by 2020 and to put demand
response on equal footing with generation.
Option 0+: Non-regulatory approach
Considering non-legislative intervention and just resorting to Option 0+ of a potential
stronger enforcement and/or voluntary cooperation, would not allow for an improvement
of the current situation regarding the uptake of fit-for-purpose smart metering and of the
market conditions for demand response to flourish. Option 0+ is not expected to remove
market barriers for demand side flexibility to reach its full potential, and therefore will not
deliver the policy objectives.
According to the Commission's assessment, the provisions related to smart metering
systems have been correctly transposed in Member States and hence, as argued earlier, no
further enforcement leading to a greater roll out of such systems is realistic. The provisions
of Art 15(8) EED related to demand response have not yet been subject to a full
transposition check or any infringements. However, even in those Member States where
the provisions have been fully and correctly transposed market barriers for independent
service providers continue to exist. This suggests that the current provisions are not
sufficiently explicit to fully remove all remaining barriers to demand response. As such a
stronger enforcement of existing provisions may in some Member States lead to a greater
take up of demand response but this alone will not be sufficient to provide a full level
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playing field as intended by European legislation, and would not deliver the policy
objectives, which is the reason this option was not further considered.
Option 1: Enable price based demand response
Smart metering systems are the key prerequisite for properly accounting for, and then
rewarding, consumers' involvement in demand response or the use of distributed energy
resources. However, it is expected that a smart meter roll-out will be realised in only 17
Member States (plus a partial roll-out in 2 Member States). In some of those Member States
the roll-out may take place without all the functionalities identified in the Commission
Recommendation on the preparations for the roll-out of smart metering systems.
Our objective is to ensure that interoperable smart metering systems with the right
functionalities are available to all consumers. The policy measures to ensure that price
based demand response can develop include:
- Give consumers the right to request a meter with the full 10 functionalities when
roll-out without full functionality is taking place or has already been completed.
- Give consumers the right to request a smart meter with full functionalities when
wide scale roll-out is not carried out96
.
- Grant consumers the right to an electricity pricing contract linked to the
development of the spot market.
Option 2: Enable price and incentive based demand response across Europe
In addition to enabling price based demand response schemes as in Option 1, the objective
in this area is to remove the key barriers to incentive based demand response and flexibility
services in order to facilitate the market-driven deployment of these technologies to the
greatest practicable and economically viable extent. The new rules ensuring full market
access for independent aggregators will address the following:
- Ensuring full non-discriminatory market access for consumers to all relevant
markets either individually or through third part aggregators.
- Ensuring that each market participant contributes to the system costs according to
the costs and benefits (s)he induces to the system.
- Removal of barriers at wholesale, balancing at capacity markets for aggregated
loads and for flexibility.
Option 3: Mandatory smart meter roll-out and full EU framework for incentive-based
demand response across Europe
The third option goes beyond the provision in Option 2. Instead of the right for consumers
to request a smart meter, it contains an obligation for a mandatory roll-out of smart meters
with the 10 recommended functionalities by 2025, for 80% of consumers in every Member
State. In addition, it contains a detailed framework for demand response that no longer
only defines principles for this framework but also defines favourable financial rules for
aggregators: The financial arrangements between aggregators and BRPs explicitly exclude
any financial transfers between aggregators and BRPs. The provisions on access of
96
In both cases the requested systems must be able to ensure interoperability among the operators
responsible for metering and other participants in the electricity market and thus support the provision
of energy management and information services of benefit to the consumer.
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aggregated loads to wholesale, balancing and capacity markets remain unchanged from
Option 2.
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Comparison of the options
a. Effectiveness of options
In the context of this impact assessment two objectives are envisaged:
- The accelerated deployment of fit-for-purpose smart metering systems that will
enable consumers to receive timely and accurate information on which they can
promptly act and accordingly adjust their consumption – in volume and time –and
benefit from new energy services (e.g. demand response)
- The uptake of demand response for consumer and system benefit
Smart Metering uptake
Assuming that no new EU intervention takes place, apart from the stronger enforcement
of existing legislation which is foreseen under option 0, and deployment plans go ahead
as they currently stand, smart meters will be installed only in those Member States where
their deployment is currently positively assessed, leading to a maximum EU penetration
rate of close to 72% by 2020. However, the systems to be rolled out will not necessarily
be interoperable, nor equipped in all cases, as recent data have shown97,98
, with those
consumer benefitting functionalities (as listed in "Commission Recommendation on
preparations for the roll-out of smart metering systems") that support his participation in
novel energy services' programmes.
It is important to note here that increased functionality is directly associated to benefits,
but not to costs; it does not push up the overall cost of the deployment, given that it is
mainly software driven and its incremental cost is relatively low99
. Issues related to
economies of scale and customisation may be more important in driving overall costs. So,
selecting fewer items from the set of common minimum functionalities does not
necessarily translate into less expensive systems. This makes a compelling case for
adhering from the start of the roll-out to the full set of the recommended functionalities100
for the smart metering systems rolled-out.
Bearing in mind the intentions of the Member States regarding smart metering
functionalities, and for rolling out standardised interfaces to support the communication of
the metering infrastructure with devices and business platforms, in practice, much more
than 30% of EU customers by 2020 will be effectively denied the means – a fully functional
smart metering system - for getting involved in demand response schemes. Furthermore,
97
Commission Staff Working Document "Cost-benefit analyses & state of play of smart metering
deployment in the EU-27" (2014) Table 8
98 "
Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States" (2015) Smart Grids Task Force Expert
Group 1
99
"Cost benefit analysis of smart metering systems in EU Member States" (2015) ICCS-NTUA & AD
Mercados EMI ; "Impact Assessment support study on downstream flexibility, demand response and
smart metering" (2016) COWI
100
Report from the Commission "Benchmarking smart metering deployment in the EU-27 with a focus on
electricity" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN; supported with
data from the Commission Staff Working Document "Cost-benefit analyses & state of play of smart
metering deployment in the EU-27" (2014) .
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given that the meters installed will be in place for the next 15 years, which is their average
economic lifetime, the overall demand response potential will be significantly reduced up
to 2030.
For estimating the smart metering deployment for the alternative Option 1 (smart meter
or its functional upgrade on request by the consumer) the following assumptions are made:
- In countries with a reported large-scale roll-out of smart metering systems, the roll-
out occurs as planned, with the recommended functionalities not being though
throughout implemented. In all cases, customers will have access to dynamic tariffs
by 2020. This reflects greater customer and supplier awareness of the benefits of
smart meters;
- In countries with either a limited (in terms of customer coverage or functionality)
roll-out or no planned roll-out, fully functional smart meters (or their upgrade) will
be made available to customers on demand.
The extent to which customers will choose the installation of a smart meter (or its
functional upgrade) will depend on a range of factors, including the proportion of overall
benefits that it could capture for them. Where a customer is faced with the full cost of smart
metering installation, extremely low take up is envisaged in the relevant Member States
based on current technology and its cost.
The analysis of national cost-benefit analyses for the roll-out of smart meters in those
countries not proceeding with a large scale roll-out has shown that customer related
benefits from smart metering systems are generally significantly lower than corresponding
per metering point costs. In two cases (Germany and Slovakia) the national CBAs have
concluded that a mandatory roll-out to all consumers would not be beneficial but only for
consumers above a certain consumption threshold:
- In Germany a mandatory roll-out for all consumers with an annual consumption
above 6000kWh is proposed;
- In Slovakia, the CBA considers that consumers with annual consumption above
4000kWh (covering 23% of metering points and 53% of Low Voltage
consumption) will overall benefit from an installation.
For the purpose of analysis, it is assumed that for all countries without a full purpose (in
terms of scale - nationwide, and function) roll-out of smart meters, the uptake of a smart
meter paid for by the consumer will be low in the short to medium term (up to 2020), but
may well increase significantly in the subsequent period to 2030 as the costs of meters,
communications and information technology fall, and the spread of appliances conducive
to price-based demand response rises. Therefore, the following estimates are made:
- Take up of smart meters of around 10% of residential and small commercial
consumers by 2020 in Member States where no full purpose roll-out is planned;
- Take up of smart meters of 40% of residential and small commercial consumers by
2030 in Member States where no full purpose roll-out is planned.
While no additional smart metering related measures are foreseen under Option 2, under
Option 3 a mandatory roll-out of smart meters to at least 80% of consumers in all Member
States is included, and this is to materialise irrespectively of the result of their national
assessments for the cost-effectiveness and feasibility of this deployment. Such a mandatory
roll-out will eventually lead to approximately 90% of all consumers having a fully
functional smart metering system installed by 2030. This reflects current experience with
smart metering roll-out where some installations for technical reasons may be too
expensive and some consumers refusing to have a smart meter installed because of privacy
concerns.
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In the light of these assumptions, the resulting estimates of smart meter roll-out and access
to dynamic tariffs under Option 1, 2 and 3 are set out below.
Table 2: Overview smart meter uptake
BAU = Option
0
Option 1 Option 2 Option 3
2016
Smart meter 35% 35% 35% 35%
2020
Smart meter 71% 72% 72% 72%
2030
Smart meter 74% 81% 81% 90%
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Uptake of dynamic price contracts
In order to participate in price based demand response schemes, consumers not only have
to have a smart meter but also a dynamic electricity price contract. Under all options, it is
considered that the consumer must voluntarily opt in for such a contract. At this stage, only
estimates can be made on the number of consumer with a smart meter opting for dynamic
contracts, time of use contracts and static contracts. The following estimates have been
used for this analysis on the basis of various studies as well as pilot projects and initial
experience in the Nordic countries101
:
101
The core estimated figures are in line with international trial studies and practical evidence, including:
- The consumer survey of “Smart Energy GB survey”, which states that around 30% of the people
were either strongly or moderately in favour of switching to a ToU tariff;
- The take-up rate of the Critical Peak Pricing ("CPP") tempo tariff in France that was slightly less
than 20% of the total consumers.
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Table 3: Uptake of dynamic and ToU price contracts of consumers with smart meters
BAU Option 1 Option 2 Option 3
2016
ToU 10% 10% 10% 10%
Dynamic 0% 0% 0% 0%
2020
ToU 18% 18% 18% 18%
Dynamic 3% 3% 3% 3%
2030
ToU 26% 26% 26% 26%
Dynamic 16% 16% 16% 16%
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
The average uptake rate is identical for all options as for all options it is assumed that
dynamic tariffs are available for those consumers who wish to have one. In the case of
Member States not currently planning a large scale roll-out of smart metering systems and
for which optional take up applies under Option 1, a higher take up rate is assumed for the
calculation. This is done under the assumption that consumers actively opting for smart
meters are equally more likely to actively opt in for advanced price contracts. Hence the
take up rate for static ToU and Critical Peak Pricing (CPP) doubled in 2020 and 2030 for
customers with a smart meter (52% and 32% respectively in 2030).
Demand response uptake
The uptake of demand response was calculated on the basis of the smart meter roll-out and
uptake of dynamic price contracts as presented above taking into account the overall
demand response potential as presented in chapter 3.1.2.
Option 0 (BAU)
In case no additional measures are taken demand response will still develop across Europe.
The roll-out of smart meters will be carried out as planned and dynamic price contracts
will be available to consumers in Member States where mart meters are rolled out and
where the retail market is sufficiently competitive. Under the BAU, an increase of price
based demand response from 5.8 GW to 15.4 GW in 2030 is accepted.
It is important to note that the uptake of demand response depends heavily on the
appliances/loads residential consumers have in their possession:
- For normal appliances, 4.9% of potential demand response is captured, while
- For electric vehicles, heat pumps and smart appliances, 18.6% of potential demand
response is captured.
These figures are very sensitive to the take-up of new forms of price contracts. The
proportion of potential demand response for electric vehicles and heat pumps captured
ranges from around 13% for Member States not currently supporting a widespread roll-out
of smart metering systems to around 21% if it is planning a full scale roll-out.
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Incentive-based demand response will only develop very slowly as in the absence of a clear
enabling framework independent aggregation will remain limited and access of flexibility
to the markets limited. In total, under the BAU option demand response can increase from
21.4 GW in 2016 to 34.4 GW in 2030 or by 60%.
Option 1
In case only price based demand response is further enabled, the calculation shows that
total demand response would only increase compared to the BAU by approx. 2.5 GW by
2030 at an EU-wide level. This reflects the moderate additional uptake of smart meters
when each consumer has the right to have it installed.
Option 2
Incentive-based demand response is already represented in the wholesale energy markets
in half of the Member States. In policy Option 2, it is assumed that all Member States
having introduced some incentive based demand response already will reach a level of 5
per cent peak reduction in 2030, gradually increasing from today's level. The increased
level of demand response compared to Option 1 is due to adjustments in programme
requirements to better reflect the needs of demand side. This includes allowing aggregated
bids in the markets allowing aggregators enter the market as a service provider for industry
and large commercial consumers. There is also a standard process for settlements between
aggregators and suppliers to facilitate aggregation. Also, all Member States will introduce
incentive based demand response and the Member States not currently having incentive
based demand response, will reach a level of 3 per cent of peak load in 2030, the potential
gradually being introduced from 2021. The reasoning for take-up of demand response in
these Member States is the same, but they will start from a lower level than Member States
where demand response is already taking place.
Those measures will lead to an increase of incentive based demand response by approx.
15.6 GW or more than 80% compared to the BAU scenario. Under option 2 price based
demand response stays stable as no additional measures are introduced. Hence, total
demand response compared to the BAU scenario will increase by approx. 18GW or
52%102
.
Option 3
In policy Option 3 it is assumed that all Member States having already introduced some
incentive based demand response will reach a level of 8 per cent peak reduction in 2030,
gradually increasing from today's level. Also, all Member States will introduce incentive-
based demand response and the Member States not currently having incentive based
demand response, will reach a level of 5 per cent of peak load in 2030, the potential
gradually being introduced from 2021. The increased level of demand response compared
to Option 2 is due to aggregators entering the market as a service provider under more
favourable conditions. Also, the prices for balancing reserves have increased due to
increased imbalances in the energy market. Those measures will lead to an increase of
incentive based demand response by approx. 20 GW or approximately double compared
to the BAU scenario.
102 In this Impact Assessment only the impact demand response is being quantified. Other forms of
consumer flexibility such as self-generation are being assessed under the RED II Impact assessment.
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Under this option it is assumed that price based demand response will remain unchanged.
While more consumers will have access to a smart meter it is unlikely that those additional
consumers who have not opted for a smart meter in the first place will request a dynamic
tariff and hence they will not participate in demand response schemes. Total demand
response compared to the BAU scenario will therefore increase by approx. 23GW or 66%
or by 4.7GW compared to Option 2.
Table 4: Overview of demand response (in GW/year) uptake for different options
BAU Option 1 Option 2 Option 3
2016
Price-based 5.8 5.8 5.8 5.8
Incentive-
based
15.6 15.6 15.6 15.6
Total 21.4 21.4 21.4 21.4
2020
Price-based 6.4 6.9 6.9 6.9
Incentive-
based
16.3 16.3 20.3 21.4
Total 22.7 23.3 27.2 28.4
2030
Price-based 15.4 17.9 17.9 17.9
Incentive-
based
19.0 19.0 34.6 39.3
Total 34.4 36.8 52.4 57.1
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
b. Key economic impacts
Cost and benefits of smart metering
In this Section the cost-effectiveness and impact of smart metering is to be seen as part of
the bigger picture of delivering services to the consumer and enabling his participation in
price based demand response, and allowing him to offer his flexibility to the energy system,
and be rewarded for it.
Under option 0, the smart metering roll-out, following in most cases a positive CBA
undertaken by the Member States, is assumed to take place as planned. A complete listing
of costs and benefits associated with smart metering deployment in Member States can be
found in the Commission Benchmarking Report issued in 2014103
. Available data there
103
(see Table 25 in) Report from the Commission "Benchmarking smart metering deployment in the EU-
27 with a focus on electricity" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN;
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coming from the CBAs104
of Member States that are proceeding with the roll-out, indicate,
despite their divergence, that the cost of installing a smart metering system for electricity
is on average close to EUR 225 per customer, while the benefit (per customer) is EUR 309
accompanied by energy savings in the order of 3% and up to 9.9% of peak load shifting.
The peak load shifting expectations vary greatly across the Member States; namely from
0.75% (UK) and 1% (Poland) to 9.9% in Ireland in the cluster of Member States that are
preparing a roll-out, and from 1.2% (Czech Republic) to 4.5% quoted in Lithuania in the
batch of Member States that are not presently proceeding with large-scale deployment.
These significant differences may be due to: (i) different experiences coming from locally
run pilot projects and/or hypotheses adopted in building the scenarios;105
, and (ii), different
patterns considered in electricity consumption, e.g. presence of district heating, wide-
spread use of gas, etc.
On the cost side, meter costs (CAPEX and OPEX) are identified by the majority of Member
States as dominant followed by the capital and operational cost due to data communication.
In most countries (and relative to the electricity deployment arrangement of the country),
the smart metering investment and installation cost appears as an upfront cost for the
distribution system operator in the initial stage of the deployment; however, in most cases
they are later fully or partly passed to the final consumer through network tariffs.
Regarding benefits, data show that in a number of Member States – the Czech Republic,
Denmark, Estonia, France, Italy, Luxembourg and Romania – the distribution system
operator is the first/large direct beneficiary of the electricity smart metering, followed by
the consumer, and the energy supplier. The associated benefits have little to do with
demand response, and are related to administrative improvements in the areas of meter
reading, dis/re-connection, identification of system problems, fraud detection, as well as
increased customer services. Finally, other benefits can also be linked to smart metering
such as CO2 emissions reduction due to first energy savings, as well as more efficient
electricity network operation (reduced technical and commercial losses); these result in
benefits accrued to the whole society.
It is important to note that to obtain full benefits, particularly consumption-related ones,
greater meter functionality is required. Yet, the CBAs show no direct link between cost
and functionality106
. So, asking Member States to give under Option 1 and Option 2 the
entitlement to consumers to request a smart meter with full functionality, or the upgrade
of an existing one, should not pose any disproportionate costs on top of the meter unit cost.
However, the fact that smart meters will end up being rolled out on customer-per customer
and accompanying (i) Commission Staff Working Document "Cost-benefit analyses & state of play of
smart metering deployment in the EU-27" (2014), (ii) Commission Staff Working Document "Country
fiches for electricity smart metering" (2014)
104
idem
105
e.g. consumers' participation rate in demand response programmes (time-of-use pricing, etc.), different
consumer engagement strategies (e.g. indirect vs. direct feedback)
106
Report from the Commission "Benchmarking smart metering deployment in the EU-27 with a focus on
electricity" (2014); also confirmed in (i) "Cost benefit analysis of smart metering systems in EU Member
States" (2015) ICCS-NTUA & AD Mercados EMI; and (ii) "Steering the implementation of smart metering
solutions throughout Europe: Final Report" (2014) FP7 project Meter-ON, p.9 and p.11;
http://www.meter-on.eu/file/2014/10/Meter-ON%20Final%20report-%20Oct%202014.pdf
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basis will not allow reaping in full system-wide benefits or benefits of scale and will lead
to higher per unit cost/benefit ratios.
In those countries where a large-scale roll-out is currently not foreseen and additional
meters are to be installed on customers' request, under Option 1 and Option 2, the total
investment for installing additional meters could – as a first approximation - reach EUR 5
billion by 2030107
for a penetration rate of 81% (compared to 74% in BAU). Half of these
costs for the installation of additional meters could potentially be offset by benefits (for
example lower costs/avoided costs of meter reading and operation, reduced commercial
losses108
) other than those related to demand response109
. As a result, the total cost by 2030
for the installation of these additional meters requested by consumers within the EU –
under Option 1 and Option 2 – could go down to EUR 2.47 billion; this corresponds to an
annual cost of EUR 215 million, for a period of 15 years (which is the average economic
lifetime of smart meters) considering a discount rate of 3.5%.
A similar calculation could also be undertaken for Option 3 which will enforce the roll-
out of smart metering in all cases including those where deployment was found to be non-
beneficial according to the national economic assessment of long-term costs and benefits.
In this case, a mandatory roll-out throughout the EU could result in achieving ultimately a
penetration rate of 90% by 2030, and the additional smart metering installation costs could
rise beyond EUR 14 billion110
. This figure represents the additional cost should a
mandatory smart meter roll-out is obligated throughout the EU. Half of these costs, as
argued earlier, could potentially be balanced by benefits linked to lower costs for meter
reading and operation and avoided commercial losses111
. Consequently, the total additional
investment is halved, and the corresponding 'net' annual cost (for 15 years modelling
period, at 3.5% rate) is estimated at EUR 613 million (per year).
The tables below present the specific costs of additional meters installation, on consumer
request or obligated by legislation (Option 3), calculated per Member State, for the
alternative options considered.
107
The calculation is based on the projected smart metering penetration rate by 2030, and on an average
cost per metering point of EUR 279. This value is worked out from data of Member States' CBAs – both
positive and negative in their outcome - that were analysed under the "Study on cost benefit analysis of
Smart Metering Systems in EU Member States-Final Report" (2015) AF Mercados EMI and NTUA, and
presented on Table 8, p. 26 of the aforementioned report. This average value of EUR 279 per metering
point includes the smart meter costs, the information technology cost, communications costs and costs
for the installation of an In-Home Display (in the case of two Member States cost-benefit analyses).
Note – The accuracy of this calculation depends on the extent that a fixed cost (which is the total cost
for rolling-out to 80% of population) can be proportionately shared, and accordingly deployed to derive
the 'unit cost', which is then used to estimate, for any penetration rate, the cost of installation of smart
metering.
108
see Figure 4, page 34 of the "Study on cost benefit analysis of Smart Metering Systems in EU Member
States-Final Report" (2015) AF Mercados EMI and NTUA.
109
"Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI.
110
Idem
111
idem
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Table 5: Overview of estimated costs for additional smart meter installation by 2030,
considering options 1 and 2
BAU=Option 0 Option 1, Option 2
Country
Metering
points
Smart meter
penetration rate
by 2030
Additional meters
by 2030
(compared to BAU)
Indicative cost
(EUR million)
by 2030
Austria 5,700,000 95% - -
Belgium 5,975,000 0% 40% 667
Bulgaria 4,000,000 0% 40% 446
Croatia 2,500,000 0% 40% 279
Cyprus 450,000 0% 40% 50
Czech Republic 5,700,000 0% 40% 636
Denmark 3,280,000 100% - -
Estonia 709,000 100% - -
Finland 3,300,000 100% - -
France 35,000,000 95% - -
Germany 47,900,000 31% 10% 1,270
Greece 7,000,000 80% - -
Hungary 4,063,366 0% 40% 453
Ireland 2,200,000 100% - -
Italy 36,700,000 99% - -
Latvia 1,089,109 95% - -
Lithuania 1,600,000 0% 40% 179
Luxembourg 260,000 95% - -
Malta 260,000 100% - -
Netherlands 7,600,000 100% - -
Poland 16,500,000 100% - -
Portugal 6,500,000 0% 40% 725
Romania 9,000,000 100% - -
Slovakia 2,625,000 23% 17% 125
Slovenia 1,000,000 0% 40% 112
Spain 27,768,258 100% - -
Sweden 5,200,000 100% - -
UK 32,940,000 100% - -
TOTAL 276,819,733 74% 7% 4,942
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
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Table 6: Overview of estimated costs for additional smart meter installation by 2030
considering Option 3
BAU=Option 0 Option 3
Country
Metering
points
Smart meter
penetration rate
by 2030
Additional meters
by 2030
(compared to BAU)
Indicative cost
(EUR million)
by 2030
Austria 5,700,000 95% - -
Belgium 5,975,000 0% 80% 1334
Bulgaria 4,000,000 0% 80% 893
Croatia 2,500,000 0% 80% 558
Cyprus 450,000 0% 80% 100
Czech Republic 5,700,000 0% 80% 1272
Denmark 3,280,000 100% - -
Estonia 709,000 100% - -
Finland 3,300,000 100% - -
France 35,000,000 95% - -
Germany 47,900,000 31% 49% 6,615
Greece 7,000,000 80% - -
Hungary 4,063,366 0% 80% 907
Ireland 2,200,000 100% - -
Italy 36,700,000 99% - -
Latvia 1,089,109 95% - -
Lithuania 1,600,000 0% 80% 357
Luxembourg 260,000 95% - -
Malta 260,000 100% - -
Netherlands 7,600,000 100% - -
Poland 16,500,000 100% - -
Portugal 6,500,000 0% 80% 1451
Romania 9,000,000 100% - -
Slovakia 2,625,000 23% 57% 417
Slovenia 1,000,000 0% 80% 223
Spain 27,768,258 100% - -
Sweden 5,200,000 100% - -
UK 32,940,000 100% - -
TOTAL 276,819,733 74% 16% 14,127
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
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Table 7: Overview of estimated 'net' yearly costs for additional smart meter
installation by 2030 considering all alternative options
BAU = Option
0
Option 1, Option 2 Option 3
2030
Smart meter
(penetration rate)
74% 81% 90%
Additional 'net' cost
(considering 15 years,
at 3.5%)
EUR 215
million/year
EUR 613
million/year
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Cost of demand response
To make demand response and its benefits possible, certain investments in the system are
necessary and operational costs will incur. For the activation costs of demand response
three classes are defined:
Table 8: Overview of cost components for demand response
Parameter Cost component Unit
Variable costs
Costs for loss of production, inconvenience costs,
storage losses
EUR/kWh
Annual fixed costs Information costs, transaction costs, control costs EUR/kW
Investment costs
Installation of measurement-equipment, automatic
measurement for control, communication
equipment
EUR/kW
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Variable costs for demand response are the costs incurred at the consumer for offering
demand response. In case of load shifting these costs are considered to be zero since the
lost output can be produced later. However, it is possible that demand response causes
additional costs for inconvenience or efficiency losses due to partial load operations,
however these costs are expected to be minor and not possible to quantify and are therefore
not considered in this analysis.
The annual fixed costs are incurred on a regular basis and are not related to the actual use
of demand response. Predominantly, these costs relate to administration and to incentivise
consumers for demand response. This analysis only focusses on the system costs, therefore
the annual fixed costs are assumed zero.
Investment costs are incurred once the demand response potential is activated. Costs of
this type include
- Investments in communication equipment both at the consumer side as in the grid.
This enables remote sending of instructions to the consumers who then can provide
demand response.
- Investments in control equipment are needed to carry out load reductions
automatically. With control equipment it is possible to provide demand response
upon receipt of a signal.
- Metering equipment is required to be able to verify that the load reduction is
achieved.
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At the moment there is relatively little information available of these investment costs for
demand response. Per consumer type, the following assumptions were made:
- Industrial consumers often already have equipment installed that can activate
demand response. On average, it is however assumed that a very small investment
is still required. According to available literature112
, the investments are estimated
to be 1 EUR/kW.
- To enable demand response for residential consumers, smart appliances must be
installed. This means the costs of appliances will be higher. Currently, most new
appliances already have an electronic controller which can make the appliance
“smart”. However, the appliance also has to be equipped with a communication
module, which will typically be either a power line communication (PLC) or a
wireless module (such as WLAN or ZigBee). It is assumed that due to mass
production of smart appliances in the future, the additional costs will be between
1.70 EUR and 3.30 EUR for all appliances that enable smart operation.
Furthermore, costs incur for the smart appliance to communicate with a central
gateway in a building. This can be integrated into a smart meter or can be offered
as a separate device. The gateway enables communication between the residential
consumer and an external load manager or aggregator. The link between the
appliances and the gateway (power line or wireless communication) does not
require the installation of additional wires. Small additional costs can be assumed
due to electricity consumption as a result of standby mode of smart appliances. This
is assumed to increase the electricity consumption of the appliance between 0.1%
and 2%.
- For commercial consumers, the costs for demand response are not available in the
literature. Therefore, the costs are derived from the costs of demand response for
residential consumers. Because the electricity consumption of commercial
consumers is on average higher than the electricity consumption of residential
consumers, more load can be shifted. As a result, investments are lower per
kW/year. An assumption is made that the costs for commercial consumers will be
a factor 6 lower.
In the graph below, the costs of demand response are visualized per Option. As can be
seen, the costs are mostly related to the residential sector. This is a result of the higher price
per kW that is required to activate demand response.
112
"Quantifying the costs of demand response for industrial business" (2013) Anna Gruber, Serafin von
Roon
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Graph 3: Costs of demand response in 2030 – comparison of options
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Benefits of demand response
Demand response is expected to decrease the peak demand and thereby the maximum
needed back-up capacity in the electricity market. The value of a decrease in back-up
capacity is expressed as a decrease in yearly CAPEX and fixed OPEX as a function of
installed capacity. Demand response also diminishes variable OPEX. When residual
electricity demand113
is averaged (flattened) by demand response, less back-up power
needs to be generated by back-up units high in the merit order, and the variable costs of
electricity generation will be reduced. Together the decrease in fixed and variable costs
determine the estimated value of a demand response option in the electricity market.
Table 9: benefit of demand response for reduced back-up capacity in 2030
BAU Option 1 Option 2 Option 3
Total demand response
potential 2030 (GW)
34.4 36.8 52.4 57.1
Total Value demand
response (million
EUR/y)
3517 3772 4588 4736
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
In the distribution grids, demand response options can be deployed to reduce the peak, and
thereby the required capacity, in the distribution and transmission networks. These benefits
are reflected in a lower required investment in these grids. The benefits shown in the
column ‘distribution and transmission’ in the table below are estimated based on existing
literature on this topic in combination with the calculations of the overall possible peak
reduction as calculated for the system level. It is shown in modelling exercises that to a
large extent peak reduction at the system simultaneously reduces peaks in the distribution
113
Residual demand is the demand that remains after subtracting intermittent sources like solar and wind.
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grids. This makes this peak demand reduction a good starting point for estimating the
savings in the grids.
To estimate the savings per kW of peak capacity reduced, one needs to distinguish between
demand connected on the lower voltage and higher voltage grids. The savings on the higher
voltage are lower because only investments in transmission can be avoided. It is assumed
that industrial demand is on the higher voltage grids, while domestic and commercial
demand response is connected to the medium or lower voltage grids.
The average savings are used to calculate the savings that are made possible by the peak
reduction. The results are presented in the table below.
Table 10: Benefits of demand response in the distribution and transmission grid
BAU Option 1 Option 2 Option 3
Total peak decrease
2030 (GW)
25.8 28.1 36.4 38.0
Total benefit
demand response in
distribution and
transmission grid
(million EUR/y)
980 1068 1383 1444
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
Overall monetary cost and benefits for all Options
On the basis of the costs and benefits as presented above the net benefit of the different
options is calculated as summarised in the table below.
Table 11: Costs and benefits of Options for 2030 (in million EUR/year)
BAU Option 1 Option 2 Option 3
Costs 82 303 322 328
Benefits
Network 980 1068 1383 1444
Generation 3517 3772 4588 4736
Total 4497 4840 5971 6180
Net benefit
(compared to no
demand response)
4415 4537 5649 5852
Net benefit
(compared to
BAU)
122 1234 1437
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI
Using the approach described above, the net benefits of the alternative Options compared
to BAU amounts to about 120 MEUR/y for Option 1230 MEUR/y for Option 2 and around
1430 MEUR/y for Option 3. The net benefit includes the estimated savings in generation
and network capacity.
What is not included in the estimation of the benefits are the possible effects on system
costs, if the independent demand aggregators are free riders not baring any balancing
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responsibility and hence risk to activate the demand response in an inefficient way: for
example by bidding in the wholesale market but in the balancing markets where the price
might be higher. This could happen under Option 3 where no compensation between
aggregators and BRPs is foreseen, and hence the aggregators have no incentive to achieve
balance as early as possible in order to improve the overall efficiency.
What is equally not directly included in this calculation are reduced electricity prices in
the wholesale market due to demand response. However, those cost reductions are
indirectly included in the reduced generation costs.
The follow-on or indirect effects depend on how the savings are distributed among the
different actors. In competitive retail markets the major share of these savings will go into
lower electricity bills for the consumers. Lower electricity costs will increase welfare for
the residential consumers and increase competitiveness for industrial and commercial
consumers. However, in less competitive markets suppliers may profit from those price
reductions.
CO₂ emission reductions
Next to the monetary impact also CO₂ reductions can be achieved through a greater uptake
of demand response. Those impacts can add up to additional savings 1.5Mton/year by 2030
compared to the BAU scenario.
Table 12: Impact on CO₂ – reduction in CO₂ emissions in Mton/y
BAU Option 1 Option 2 Option 3
Reduction in CO₂ emissions
in Mton/y
12.4 13.0 12.7 12.4114
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
c. Simplification and/or administrative impact for companies and
consumers
The measures proposed under Option 2 and 3 are designed to reduce market barriers for
new entrants and provide a stable framework for them under which they can operate in the
market. This is a necessity for new entrants who currently face great difficulties entering
the markets as incumbent suppliers do not allow them to engage with their customers. The
removal of such barriers is especially important for start-ups and SMEs who typically offer
innovative energy services such as demand response.
Equally for consumers all measures are designed to facilitate their access to innovative
products and services. Those measures should reduce the administrative impact for
consumers to get a fully functional smart meter and sign service contracts with third
parties. At the same time the measures also require Member States to clearly define roles
and responsibilities of aggregators which also increases confidence for consumers in their
services and contributes to consume protection.
114
For options 2 and 3 the CO2 benefits are less than for option 1, even if their total DR potential is higher.
This can be explained as follows: By applying DR, the peak demand will be diminished and less power
is generated by back-up units high in the merit order (e.g. gas plants). But at the same time some low
demand values will become higher after DR is implemented (we assume the total demand does not
change) and more power is generated by back-up units lower in the merit order (e.g. lignite plants).
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Moreover, thanks to a wider deployment of smart metering, under options 1, 2, and
particularly Option 3, the distribution system operators will be in a position to lighten and
improve some of their administrative processes linked to meter reading, billing,
dis/reconnection, switching, identification of system problems, commercial losses, while
at the same time offer increased customer services. Furthermore, a wider roll-out of smart
metering would allow TSOs to better calculate, and improve their processes, for
settlements and balancing penalties as the consumption figures can be based on real
consumption data and not only on profiles.
d. Impacts on public administrations
Regarding smart metering, there will be impacts on public administration, namely on the
Member States' competent authorities including the national regulators.
Those 17 Member States that roll-out smart meters will not be affected by provisions on
smart meters, under all options, apart from the obligation to comply with the
recommended functionalities, which they may need to transpose into national legislation.
Similarly, those two Member States that opted for partial roll-out are not expected to face
any major additional impacts from allowing additional consumers to request smart meters,
under Option 1 and 2. However, they will be impacted when enforcing a mandatory roll-
out under Option 3 which will require substantial changes in their legislation as it currently
stands. The remaining Member States that currently do not plan to install smart metering
in their territory will need to establish legislation with technical and functional
requirements for the roll-out – under any of the options – and face some additional
administrative impact for re-evaluating their cost-benefit analyses.
Similarly, additional administrative impact may be created for the national regulatory
authorities (NRAs) for enforcing actions regarding the consumer entitlement to request a
fully functional smart meter. This includes assessing the costs to be borne by the consumer,
and overseeing the process of deployment. At the same time, improved consumer
engagement thanks to smart metering, would make it easier for NRAs to ensure proper
functioning of the national (retail) energy markets.
No additional impact on public administration is expected from facilitating incentive based
demand response as it is just a further specification/guidance on what is already an
obligation under EED.
e. Trade-offs and synergies associated with each option with other foreseen
measures
Promoting a wider-scale deployment of smart metering with fit-for-purpose functionalities
is in line with the Commission's policy objectives namely to put the consumer at the core
of the EU's energy system, given that:
- interoperable smart metering systems, equipped with the right functionalities, and
connectivity to support novel energy services, are considered essential under the
Energy Union Strategy for bringing tangible benefits to consumers and delivering
the "new deal";
- through smart metering, consumers can clearly experience the internal energy
market working for them based on their preferences/choices, as it:
- enables them to get accurate and frequent feedback on their energy
consumption;
- minimize errors and delays in invoices or in switching;
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- maximize their benefits from innovative solutions for consumption
optimization (e.g. via demand response) and from emerging technologies
(such as home automation); and ,
 reduce the costs of the operation and maintenance of energy distribution
infrastructure (ultimately born by consumers through distribution tariffs).
Mandating the minimum functionalities for smart metering will clarify the need to go
beyond the capability of delivering just 'actual time of use' information currently
mentioned in the related provisions of the Energy Efficiency Directive.
Furthermore, the proposed smart metering functionality to collect meter data at intervals
at least equal to the market settlement frequency will support trading and the harmonisation
of balancing markets.
In addition to bringing tangible benefits to consumers, further developing demand response
is fully coherent with the objectives of other priorities in the field of energy policy as an
appropriate market framework for demand response:
- is an enabler for integrating renewables efficiently into the electricity system. It
also contributes to render energy storage and self-consumption viable;
- is a key factor for increasing energy efficiency with savings of final but mainly
primary energy;
- is a key factor in promoting new products in balancing markets where new rules
are being elaborated under the Market Design Initiative to increase competition;
- may help to reduce the need for creating capacity markets and will therefore be
considered under the rules for capacity markets to be proposed under the Market
Design Initiative;
- will be needed to make efficient use of existing networks and thereby is at the core
of the proposal concerning new distribution tariff rules;
- will likely trigger the deployment of smart homes and smart buildings technologies
while these will vice-versa increase the interest of residential and commercial
consumers in participating in demand response programmes. This deployment is
foreseen to be supported by measures to be adopted under the Ecodesign/Energy
Labelling Framework and by new approaches for smart buildings to be proposed
in the context of the review of the EPBD in 2016.
f. Uncertainty in the key findings and conclusions and how these might
affect the choice of the preferred option
The analysis on smart metering systems and especially demand response contains a lot of
uncertainty. For smart metering systems detailed national cost-benefit analyses have been
carried out in 2012. However, the underlying assumptions especially with regard to
technology costs that are significantly decreasing may change over time. Also the potential
benefits in terms of system and consumer benefits are subject to change depending on
technology development, the further integration of decentralised renewable energy
generation and upcoming offers for consumers taking part in demand response schemes.
Considering the above it is not unlikely that currently the costs for smart metering are over-
and the benefits under-estimated in some national cost-benefit analyses.
For incentive based demand response the uncertainty is even greater. Relatively good
estimates can be made about the theoretical potential of demand response (see chapter 2 of
this annex) where most of the theoretical potential lies with the residential sector.
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However, the technical and economic potential in the residential sector depends on a
number of external factors that are hard to quantify:
- The willingness for residential consumers to engage in demand response. Pilot
projects have proven that consumers do engage in the market and adjust their
consumption if the incentives are right. These incentives are not always monetary
but can also be related to access to advanced information or energy managing tools.
However, it is impossible to transfer the results of pilots with engaged consumers
to the broad majority of consumers;
- The uptake of heat pumps and electric vehicles that provide considerable shift-able
load will most probably determine if a huge number of residential consumers will
engage in demand response schemes. However, the uptake of those technologies is
yet uncertain;
- Experiences from the Nordic market are not easily transferable to all EU markets
as the shifting potential in Finland is relatively high due to e.g. electric heating;
- Experiences from the US market are equally not easily transferable to Europe as
the US market design is different. Furthermore wholesale peak prices are higher
and more frequent than in Europe. Hence, the economic value of demand response
in the US is higher than in the Europe.
The above indicates that the amount of the monetary benefits under the different options
is rather uncertain. The figures therefore rather indicate the magnitude of the potential
benefits under the different options.
As outlined earlier in this chapter there is also great uncertainty about the results calculated
for Option 3 in this impact assessment:
- The analysis only covered the EU as a whole and did not look into national impacts
of a mandatory roll-out. It equally assumes the same cost of smart meters and their
roll-out across the EU. Therefore it cannot be excluded that in some Member States
the costs of a mandatory roll-out of smart meters exceeds its benefits as it was
concluded in some national cost-benefit assessments;
- The analysis also did not quantify the potential system impact if independent
aggregators are exempted from financially covering the distortions they induce to
the system, e.g. not having any balancing responsibilities.
Therefore, the results of Option 3 are even more uncertain than under the other Options
and may very well lead to additional system costs and in some Member States to costs for
smart metering systems that are not covered by benefits for the system and/or the
consumer.
The uncertainty about the uptake of demand response does, however, not affect the
assessment of the preferred option. This option (Option 2) does not foresee any enforced
measures on the roll-out of smart meters or on the uptake of demand response. Instead, all
measures foreseen under this option are just enabling consumers to have access to the right
technologies and access to third party service providers. They also foresee to improve
access of flexibility to the markets. Under those framework conditions it will be the market
that will show to which degree demand response can play a role as a competitive service.
Therefore, Option 2 can be considered as a no regret option.
g. Preferred Option
Flexibility is considered to be instrumental for allowing more renewables into the
European electricity system without having to make large investments in conventional
back-up generation capacity. Therefore, introducing flexibility to the energy system by
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accelerating the uptake smart metering systems and of demand response are key elements
for realising the Energy Union's objectives.
All three Options are fully coherent with the objectives of the Energy Union and other EU
policies. The analysis has proven that all options are suited to accelerate the uptake of smart
metering systems and demand response as well as this uptake will lead to significant
system benefits and cost savings.
Option 1 supports the objective of increasing efficiency of the energy system by
introducing smart meters and dynamic pricing contracts. The Third Package included the
promotion of smart meters by requesting Member States to undertake a CBA of smart
meters and where the benefit-cost ratio is positive to roll-out smart meters. The realisation
of Option 1 means also in Member States where there is no general roll-out, relevant
consumers can ask for the smart meter and a dynamic price contract. It hence provides the
framework to allow all consumers to take advantage of the technological developments.
However, while better enabling price based demand is crucial for incentivising residential
consumers to benefit, it is not suited to realise the full benefits demand response can offer.
As such realising Option 1 will only lead to increase total demand response in Europe by
approximately 7% and lead to net benefits of approximately 120 MEUR/y by 2030
(compared to BAU).
In addition to the measures proposed under Option 1, Option 2 is specifically addressing
incentive-based demand response. Article 15 of the Energy Efficiency Directive already
promotes demand flexibility and in that respect includes requirements for promotion of
demand response. The additional measures in Option 2 are based on the assessment that in
most Member States a complete legal framework for demand response is still missing. The
measures in Option 2 aim at providing this framework by creating fair market access for
independent aggregators and allow flexibility to be traded in organised markets. The
analysis has shown that those measures are indeed suited to increase the uptake of demand
response by approximately 52% which leads to system benefits of approximately 1230
MEUR/y by 2030 (compared to BAU).
Box X: Benefits and risks of dynamic electricity pricing contracts
The preferred option (Option 2) is to provide all consumers the possibility to voluntarily choose to sign up
to a dynamic electricity price contract and to participate in demand response schemes. All consumers will
have equally the right to keep their traditional electricity price contract.
Dynamic electricity prices reflect – to varying degrees – marginal generation costs and thus incentivise
consumers to change their consumption in response to price signals. This reduces peak demand and hence
reduces the price of electricity at the wholesale market. Those price reductions can be passed on to all
consumers. At the same time, suppliers can pass parts of their wholesale price risk on to those consumers
who are on dynamic contracts. Both aspects can explain why, according to the ACER/CEER monitoring
report 2015, on average existing dynamic electricity price offers in Europe are 5% cheaper than the average
offer.
While consumers on dynamic price contracts can realise additional benefits from shifting their consumption
to times of low wholesale prices they also risk to face higher bills in case they are consuming during peak
hours. Such a risk is deemed to be acceptable if taking this risk is the free choice of the consumer and if he
is informed accurately about the potential risks and benefits of dynamic prices before signing up to such a
contract.
Under Option 3 a mandatory roll-out of smart meters to at least 80% of consumers in all
Member States is included. In addition it is assumed that under this option aggregators do
not have to cover the costs they induce to the system and hence do not pay any
compensation to BRPs. In terms of uptake of demand response (more than 100% compared
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to BAU) and overall system benefits (1430 MEUR/y by 2030) this is the most favourable
option. However, there are also other impacts that need to be considered in this respect:
- This analysis did not take into account national differences in the costs/benefits of
smart meter roll-out but instead average figures were used. This approach does
hence not exclude the possibility that the overall economic impact of a mandatory
smart meter roll can be negative in some Member States as already suggested in
national cost-benefit analyses;
- The exclusion of any compensation mechanism introduces a possibility of demand
aggregators being free riders in the markets and therefore creating inefficiencies.
This is not in line with the EU target model and generally not in line with creating
a level playing field for competition.
Option 2 is considered to be the preferred option, considering that
- the modelling used for this Impact Assessment did not account for national
differences and did not calculate the impacts per Member State;
- national cost-benefit analyses suggests that in some Member States mandatory roll-
out of smart meters yields negative net benefits; and that,
- the overall banning of any financial obligations by independent aggregators may
lead to market distortions with unknown overall impacts.
Subsidiarity
The options envisage to give consumers the right to a smart meter with all functionalities
and access to dynamic electricity pricing contracts (Option 1) and in addition further
specify the roles and responsibilities of third parties offering demand response services
(Option 2). These actions promote the interests of consumers and ensure a high level of
consumer protection, and have their legal basis in Article 114 of the Treaty and Article 194
(2) TFEU. The policy measures considered under Option 3 can be based on the same
provisions.
Option1
- The principle of subsidiarity is respected and EU action is justified as access to
smart metering systems is fundamental to improving the functioning of the internal
electricity market;
- Ensuring universal consumer rights in the EU electricity markets includes the right
to actively engage in the market. This is only possible if technologies enabling
innovative energy services are available to all consumers across all Member States.
As stated earlier, for consumers to directly react to price signals on electricity markets, and
enjoy benefits coming from the provision of new energy services and products, they must
have access to both a fit-for-purpose smart metering system as well as an electricity supply
contract with dynamic prices linked to the spot market. However, today this is only a reality
in the Nordic Member States and Spain. In addition, under current national smart metering
rollout plans till 2020, more than 30% of EU consumers could be excluded from access to
such metering systems. The Commission's objective is to ensure that consumers have
access to all the prerequisites necessary to be rewarded for reacting to market signals.
This cannot be achieved sufficiently by Member States acting along. Therefore, it is herein
proposed to table provisions that will give each consumer, throughout the EU, the right to
request the installation of, or the upgrade to, a smart meter with all 10 functionalities
proposed in the Commission Recommendation on preparations for the roll-out of smart
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metering systems115
, while ensuring that consumers fairly contribute to associated costs.
Furthermore, it needs to be ensured that every consumer has the choice to select a dynamic
price contract linked to the prices at the spot market.
Action at EU level is relevant given that the current EU provisions, which leave the roll-
out of smart metering to the Member States' discretion based on the results of their cost-
benefit analysis, led to a fragmented, and even not necessarily functionally suitable in all
cases, deployment of smart metering.
Actions by Member States alone cannot ensure a harmonised level of consumer rights
(right to a smart meter that would enable customers access certain energy services) to the
extent to which under current national smart meter rollout plans for 2020, more than 30%
of EU consumers could be excluded from access to such metering systems. The right to a
smart meter with all the ten recommended functionalities is a precondition for consumers
to access energy services116
that require accurate and frequent billing information such as
demand response or electricity supply contract with dynamic prices linked to the spot
market.
The costs of rolling out smart meters - with all the benefits that this can bring for
consumers, network and energy companies, the energy system as well as society and the
environment more widely - will greatly increase if the economies of scale of the EU's
internal market are not properly leveraged. Regional differences have already risen with
respect to functionality and interoperability of the systems being rolled out, which may
result in set-ups that are not necessarily interoperable at national level, or within the EU.
This adds complexity and costs to those, be it for instance energy services/product
developers or aggregators, who would like to trade in different European countries and
optimise their business model. It points to the need to harmonise to a certain extent system
requirements and functionalities of smart electricity meters.
In the context of completing the EU's internal electricity market and making retail work
also for consumers, it is highly relevant to ensure at EU level a degree of consistency and
alignment, as well as gain momentum, in the deployment and use of smart metering
throughout Europe. Furthermore, ability to access novel energy services and products
should be indiscriminately offered to all EU citizens. This is what this action – giving the
right to request the installation of, or the upgrade to, a smart meter - is meant to deliver.
Such an action will eliminate ambiguities and strengthen the existing provisions, in order
to give certainty to those planning to invest, and ensure that smart metering roll-outs move
in the right direction, and regain EU added-value, by namely (i) safeguarding common
functionality and sharing best practices; (ii)ensuring coherence, interoperability, synergies,
and economies of scale, boosting competitiveness of European industry (both in
manufacturing and in energy services and product provision), and (iii) ultimately
delivering the right conditions for the internal market benefits to reach also consumers
across the EU.
115
For example, provide readings directly to the customer and any third party designated by the consumer,
include advance tariff structures, time-of-use prices and remote tariff control, provide secure data
communications, etc. These also carry a host of other benefits such as improved consumer information,
enabling self-generation to be rewarded, and delivering flexibility to the system.
116
e.g. demand response, self-consumption, self-generation
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Option 2
EU intervention can be justified for several reasons, among them are:
- To improve the proper functioning of the internal market and avoid the distortion
of competition in the field of retail energy services and hence fully enable demand
response
- To empower consumers by enabling them to take advantage of the well-functioning
retail energy markets by easily accessing demand response services under
transparent and fair conditions.
Divergent national approaches related to the development of demand response services, or
the lack thereof, led to different national regulatory frameworks, raising barriers to entry
across borders to demand response aggregators. This initiative complies with the principle
of subsidiarity, as Member States on their own initiative would not be able to remove the
barriers that exist between national legislations to independent demand response service-
providers and to create a level playing field for them.
Each Member State individually would not be able to ensure the overall coherence of its
legislation with other Member States' legislations. This is why an initiative at EU level is
necessary. It will reduce costs for businesses as they will no longer have to face different
national regimes. It will create legal certainty for businesses which want to provide demand
response services in other Member States. Common rules are also crucial when e.g.
balancing markets will be opened for cross-border trade of flexibility.
Moreover, the present initiative will add value to other measures in the Market Design
Initiative. Other measures aimed at empowering customers, such as right to a smart meter
and to a dynamic ricing contract, will create new opportunities for European consumers
and energy service companies. These opportunities can only be exploited to their
maximum extent if they are completed by an initiative on addressing market barriers to
aggregators, so that they are able to provide customers with access to demand response
services.
Action from Member States alone is likely to result in different sets of rules, which may
undermine or create new obstacles to the proper functioning of the internal market and
create unequal levels of consumer rights in the EU. For example, a framework for demand
response for households is currently being developed in France, while in other Member
States there are currently no established rules for demand response aggregators targeting
household consumers. Common standards at EU level are therefore necessary to promote
efficient and competitive conditions in the retail energy sector for the benefit of EU
consumers and businesses.
An initiative at EU level would ensure that consumers in all Member States would benefit
from demand response services under harmonised conditions. It would also help removing
entry barriers for new service providers (aggregators), including cross-border, therefore
stimulating economies of scale and setting the basis for developing flexibility markets at
regional level. Such services have a cross-border development potential (e. g. Energy Pool
is already active in more than one EU Member States – France, UK).
Option 3
The same arguments to justify EU action as for Option 1 and 2 can be used for the policy
measures under Option 3. However, what concerns smart metering there could be doubts
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that a mandatory roll-out of smart meters with all recommended 10 functionalities
conforms to the principles of subsidiarity and proportionality. This is especially relevant
as Member States have already conducted national cost-benefit analyses on smart meter
roll-out. In 11 Member States those CBAs have unveiled that under current conditions the
costs of a roll-out exceed the benefits. In the Commission's analyses no evidence has been
found that those national CBAs or their underlying assumptions could be contested or that
economies of scale realised by a European roll-out would render the roll-out economically
viable. Hence, a mandatory roll-out would effectively impose undue costs on those
Member States where the CBAs have been negative. However, the underlying assumptions
of those CBAs are likely to change over time with technology cost expected to decrease
which may lead to viable roll-outs in the near future.
The principle of proportionality may equally be contested for strict harmonisation of the
legislative framework for independent aggregators and demand response. A certain degree
of freedom for Member States to design the framework for demand response according to
the national design of the markets may indeed have a similar impact than fully harmonised
rules.
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Stakeholders' opinions
Outcome of the public consultation
Result of public consultation Energy Market Design
The consultation on the market design contained one question on demand response:
"Where do you see the main obstacles that should be tackled to kick-start demand
response (e.g. insufficient flexible prices, (regulatory) barriers for aggregators /
customers, lack of access to smart home technologies, no obligation to offer the
possibility for end customers to participate in the balancing market through a demand
response scheme, etc.)?"
Many stakeholders identified a lack of dynamic pricing (more flexible consumer prices,
reflecting the actual supply and demand of electricity) as one of the main obstacles to kick-
starting demand side response, along with the distortion of retail prices by taxes/levies and
price regulation. Other factors include market rules that discriminate consumers or
aggregators who want to offer demand response, network tariff structures that are not
adapted to demand response and the slow roll-out of smart metering. Some stakeholders
underline that demand response should be purely market driven, where the potential is
greater for industrial customers than for residential customers. Many replies point at
specific regulatory barriers to demand response, primarily with regards to the lack of a
standardised and harmonised framework for demand response (e.g. operation and
settlement). 117
In total, eleven Member States responded to the question with ten putting specific emphasis
on the need for effective price signals that reflect price developments at the wholesale
market and incentivise consumers to adjust their consumption. In addition, seven Member
States highlighted the need for market rules that allow demand response to participate in
wholesale, balancing and capacity markets on equal footing with generation. Also
environmental NGOs have been widely supportive of demand response stressing the need
for demand side measures to efficiently integrate renewables to the system. Therefore, they
call for opening the markets for flexibility. Some organisations call for intensified R&D in
the area and/or support schemes while one organisation also calls for targets for demand
response. However, Member States and other stakeholders see demand response as a
market driven service for which no specific support but fair market conditions is needed.
More detail on the opinion of main stakeholders is presented under the individual
stakeholder organisations.
Result on public consultation on the Review of Directive 2012/27/EU on Energy Efficiency
117
IEA "Re-powering markets" (2016) suggests: Reform of retail pricing is urgently needed to better reflect
the underlying cost level and structure. Current tariff and taxation structures which do not vary with
time can lead to inefficiencies. Investments in distributed resources are not always cost-effective as bill
savings do not properly reflect the avoided costs to the electricity system. The significant difference in
speed between installing solar PV and small-scale storage and building large-scale power infrastructure
can exacerbate this problem."
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The consultation addressed a number of questions on metering with one specifically
addressing electricity smart meters and hence is immediately relevant to this impact
assessment:
"Do you think that
- the EED requirements regarding smart metering systems for electricity and
natural gas and consumption feedback and
- the common minimum functionalities, for example to provide readings directly to
the customer or to update readings frequently, recommended by the Commission
together provide a sufficient level of harmonisation at EU level? "
37% shared the view that the EED requirements regarding smart metering systems for
electricity and natural gas and consumption feedback and that the common minimum
functionalities recommended by the Commission together provide a sufficient level of
harmonisation at EU level. 36% had no view, and 27% did not think that these provisions
would provide a sufficient level of harmonisation.
Several participants explained that smart meters would have to provide more useful
information to consumers, potentially in 15 minute intervals, or even in real time. Some
also suggested that consumers could receive a notification once every three months with
an overview on whether they are saving energy and hence money, or whether they are
consuming more than would be expected. Yet others noted that the above factors largely
depend on market conditions, and on how providers interact with customers. In general,
many participants shared the view that EU standards should only apply to minimum ones,
as any additional standards could significantly increase the enterprise's complexity.
Additionally, several stated that harmonisation must also take into account acceptance by
citizens. Finally, some also cited evidence that calls the effectiveness of smart meters in
general into question.
Of those 27% who think that the EED requirements regarding smart metering systems for
electricity and natural gas and consumption feedback and the common minimum
functionalities, recommended by the Commission together do not provide a sufficient level
of harmonisation at EU level, 48% share the view that common minimum functionalities
should be the basis for further harmonisation. 31% had no view, and 21% did not thing
that common minimum functionalities should be the basis for further harmonisation. Some
called for additional minimum functional standards to the current ones, for example,
monthly or three monthly electronic feedback for consumers on how much energy they are
savings. Some participants also argued that the interface of smart meters should be
standardised, to facilitate their use. Yet others voiced a shared perception that standards
across the EU would be overly determined by utilities.
More detail on the opinion of main stakeholders is presented under the individual
stakeholder organisations. While among all respondents the views on the need of additional
EU actions was balanced, the opinion of national ministries signal that the majority of
Member States believe that the existing provisions are sufficient. Out of 14 replies from
Member States only 2 were of the opinion that more harmonisation on EU level would be
good to ensure that consumers get the full benefit out of smart meters while 9 consider that
the level of harmonisation provided by existing legislation is sufficient and 3 do not state
a clear opinion.
European Institutions
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Council of the European Union, messages from the presidency on electricity market design
and regional cooperation, April 28, 2016, 7876/1/16 REV1
In addition to stakeholders also European Institutions in response to the communications
"Launching the public consultation process on new energy market design" (SWD(2015)
142 final) as well as "Delivering a new deal for consumers" (SWD(2015) 141 final) clearly
highlighting the need for smart metering systems, demand response and the importance of
allowing new market participants (aggregators) to compete in the markets.
European Parliament, Committee on Industry, Research and Energy, Rapporteur: Werner
Langen, DRAFT REPORT on ‘Towards a New Energy Market Design’, 27.1.2016,
2015/2322(INI)
"The future electricity retail markets should ensure access to new market players (such as
aggregators and ESCO’s) on an equal footing and facilitate introduction of innovative
technologies, products and services in order to stimulate competition and growth. It is
important to promote further reduction of energy consumption in the EU and inform and
empower consumers, households as well as industries, as regards possibilities to
participate actively in the energy market and respond to price signals, control their energy
consumption and participate in cost-effective demand response solutions. In this regard,
cost efficient installation of smart meters and relevant data systems are essential.
Barriers that hamper the delivery of demand response services should be removed."
European Parliament, Committee on Industry, Research and Energy, Rapporteur: Theresa
Griffin, REPORT on delivering a new deal for energy consumers, 28.4.2016, A8-
0161/2016
- "5. Recalls that the ultimate goal should be an economy based on 100%
renewables, which can only be achieved through reducing our energy
consumption, making full use of the ‘energy efficiency first / first fuel’ principle
and prioritising energy savings and demand side measures over the supply side
in order to meet our climate goals…"
- "6.b empower citizens to produce, consume, store or trade their own renewable
energy either individually or collectively, to take energy-saving measures, to
become active participants in the energy market through consumer choice, and to
allow them the possibility of safely and confidently participating in demand
response;"
- "33. Stresses that to incentivise demand response, energy prices must vary between
peak and off-peak periods, and therefore supports the development of dynamic
pricing on an opt-in basis, subject to a thorough assessment of its impacts on all
consumers; stresses the need to deploy technologies that give price signals which
reward flexible consumption, thus making consumers more responsive; … reminds
the Commission that when drafting the upcoming legislative proposals it should be
guaranteed that the introduction of dynamic pricing is matched by increased
information to consumers;
- "37. Emphasises that consumers should have a free choice of aggregators and
energy service companies (ESCOs) independent from suppliers";
Committee of the Regions, Opinion of the European Committee of the Regions – Delivering
a New Deal for Energy Consumers, 8 April 2016, ENVE VI -/009
- "3. notes the extremely high number of services and technical solutions that exist
or are currently being developed in the fields of management and demand
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response, as well as in the management of decentralised production. The European
Union must ensure that priority is given to encouraging and supporting the
development of these tools, assessing their value and impact, whether economic,
social, environmental or in terms of energy, and monitoring their usage to make
sure that energy is safe, easy and affordable";
- "24. observes that a level playing field should be created for all future players who
generate and supply energy and/or provide new services, in order to enable, for
example, grid flexibility and integration of energy produced by "prosumers"
(including aggregators)";
- "42. reiterates its call to speed-up the development of smart systems at both grid
and producer/consumer level, to optimise the system as a whole, as well as to
introduce smart meters, which are essential to the efficient management of
demand with the active involvement of the consumer";
- "43. calls for the adoption of a strict framework at European level on the
deployment of smart meters and their range of uses and features, whilst recalling
that the aim is to streamline and reduce consumption. In this regard, the Committee
calls for all new technology options to be evaluated prior to adoption, if they are
to be introduced as standard, with regard to their potential energy, economic,
social and environmental impact";
Selected Stakeholder's views
Florence Forum of electricity regulation – Conclusions of 31 meeting on June 13, 2016
The Forum recognises that the development of a holistic EU framework is key to unlocking
the potential of demand response and to enabling it to provide flexibility to the system. It
notes the large convergence of views among stakeholders on how to approach the
regulation of demand response, including:
- The nееd to engage consumers;
- The need to remove existing barriers to market access, including to third party
aggregators;
- The need to make available dynamic market-based pricing;
- The importance of both implicit and explicit demand response; and,
- The need to put in place the required technology.
Regulators (ACER/CEER)
The Agency for the Cooperation of Energy Regulators (ACER) and the Council of the
European Energy Regulators (CEER) both welcomed the Commission's energy market
design consultation paper of July 2015, and in particular the reinforced steer towards cross-
border and market-based solutions, and noted its "alignment in thinking" with their
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Bridge to 2025 proposals and sharing of "the common aim of establishing liquid,
competitive and integrated energy markets that work for consumers”118
.
They consider that "a well-functioning market is characterised by innovation and a
range of products offered to consumers", which "can be a sign of healthy competition and
innovation in the market". Key features of this new consumer-centric energy market model
advocated by the regulators119
rely on "near real time frequency of smart metering data
for all", and "demand response through flexible consumption". The latter translates into
"availability of time-of-use/hourly metering and different pricing schemes offers from
suppliers and availability of aggregation services from third-party companies". To assist
realising this, CEER amongst other works towards ensuring that "most customers have a
minimum knowledge of the most relevant features for engaging and trusting the market",
access to "empowerment tools" and "a minimum level of engagement", as well as that the
"regulatory framework allows and incentivises the availability of a range of offers"120
.
CEER when discussing121
implicit, or price-based demand response, it states that
"without smart meters (and optionally in addition other facilitators such as smart
appliances)" and in the absence of dynamic pricing contracts, there are "limited
possibilities for retailers to value demand side flexibility in their portfolio optimisation".
CEER further notes that "access to contracts that directly link the energy component to
wholesale markets with a possible granularity down to hourly-based prices create a bridge
between wholesale and retail markets, incentivising consumers to exploit opportunities
when prices are low and to adjust consumption when prices are high".
Furthermore, CEER affirms that "the availability of smart metering equipment and
systems which allow time-of-use meter readings is a pre-requisite for consumers to be
able to opt into implicit demand response schemes. Smart meters may also enable explicit
demand response services through a dedicated standard interface, either as mandatory
equipment or an option"122
. But for smart meters to be able to deliver this service, they
need to be fit-for-purpose, and therefore equipped with the right functionalities. CEER
notes that "there is a consistency and convergence between the work of European Energy
Regulators and the European Commission regarding smart meter functionalities, in
particular those which benefit consumers". At the same time, however, CEER does not
consider these elements sufficient for providing the necessary level of harmonisation
across the EU, "the issue being that Member States do not apply them". Consequently,
118
ACER/CEER common press release "Energy Regulators (ACER/CEER) welcome the market-based
solutions and cross-border focus of the European Commission’s energy market design", 15.07.2015;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/PRESS_RELEASES/201
5/PR-15-07_Joint-CEER-ACER%20PR%20%20-EnergyMarketDesignConsultation_FINAL.pdf
119
CEER presentation at the 12th EU-US Roundtable, 03.05.2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_INTERNATIONAL/EU-
US%20Roundtable/12th_EU-US_Roundtable/12th%20EU-US%20RT_S4-
International_deSuzzoni.pdf
120
idem
121
CEER discussion paper "Scoping of flexible response", 3 May 2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Electrici
ty/2016/C16-FTF-08-04_Scoping_FR-Discussion_paper_3-May-2016.pdf
122 CEER "Position paper on well-functioning retail energy markets", , 14 October 2015;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab5/C15-SC-36-03_V19_Well-functioning_retail_markets.pdf
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CEER are in favour of using the "minimum functionalities as a basis for further
harmonisation"123
.
TSOs (ENTSO-E)
ENTSO-E considers that "the development of demand-side response (DSR) should ensure
that demand elasticity is adequately reflected in short-term price building and long-term
investment incentives. DSR can deliver different types of products and participate in the
associated markets with large socio-economic welfare gains"124
. Furthermore, ENTSO-E
notes that "the organisation of, and timely access to, metering and settlement data which
will be made available by smart meters is essential for facilitating the uptake of DSR"125
.
Elaborating on that, ENTSO-E states that the full potential can be unleashed if the
following requirements126
are satisfied, namely:
(i)"price signals need to reveal the value of flexibility" for the electricity system;
(ii)"efficient use of DSR is based on an economic choice between the value of consumption
and the market value of electricity. This choice arises when the consumer is exposed to
variable prices or if the consumer can sell his flexibility on the market, possibly with the
help of an aggregator".
(iii) "access to price information, consumption awareness and DSR activation require
strong consumer involvement, which can be facilitated with automation or by delegating
the DSR process from the consumer to a company";
(iv) "regulatory barriers, when present, need to be removed to unlock full DSR potential,
including barriers related to the relationship between independent aggregators and
suppliers. Any evolution must preserve the efficiency and well-functioning of markets and
their design components, such as the pivotal role of balance responsible parties, their
information needs and balancing incentives. From a TSO perspective, the choice of the
market model results from a trade-off between the imperatives not to increase residual
system imbalance and to facilitate the development of additional resources";
(v)"DSR should develop itself based on viable business cases. Subsidies should remain
limited and clearly identified";
123
CEER Response to European Commission Public Consultation on the Review of the Energy
Efficiency Directive, 29 January 2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab6/C16-CRM-96-04_EC_PC_EED_Response_290116.pdf
124
ENTSO-E policy paper "Market design for demand response", November 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr
_web.pdf
125
ENTSO-E position paper "Towards smarter grids: Developing TSO and DSO roles and interactions for
the benefit of consumers", March 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/150303_ENTS
O-E_Position_Paper_TSO-DSO_interaction.pdf
126
ENTSO-E policy paper "Market design for demand response", November 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr
_web.pdf
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(vi)"Communication and control technologies need to enable DSR for small consumers
and provide guarantees on their reliability".
ENTSO-E also clarifies that "to enable dynamic pricing, settlements must be based on at
least hourly metering values", which means that "Member States must phase out static
consumption profiles, and introduce time-of-stamped (at least hourly) smart meter
readings for consumers"127
.
DSOs (CEDEC, EDSO for Smart Grids, EURELECTRIC, GEODE)
The four DSOs associations appreciate the contribution of demand response towards
achieving EU energy objectives, and recognise the need for active customers participating
in the markets. They state that128
"with the growing uptake of smart grids and distributed
energy connected to Europe’s distribution grids, DSOs are successfully embracing the
‘digitalisation’ transformation", and are in favour of "the procurement of flexibility
services in an open market context where everyone, including end users, is welcome to
take part.” They have also affirmed in different fora their conviction on the key role that
smart metering plays in delivering that function and the accompanying benefits, by
providing accurate and secure data on energy consumption, while enabling customers to
make smart choices helping them to also save money and energy.
CEDEC
CEDEC considers that129
"in order to implement effective demand-response programmes,
signals about demand and supply need to be received, managed and communicated to the
relevant parties. For this, the development of smart distribution grids is indispensable".
Moreover, "for the development of smart grids, cost-reflective regulatory frameworks need
to be in place… " giving the right incentives, that should amongst others, "allow for time-
differentiated prices, which will give price signals to consumers to shift their
consumption from peak to off-peak times"130
. Such settings are more complex and in fact
"only possible with a smart meter"131
.
EDSO for Smart Grids
127
ENTSO-E "Recommendations to the regulatory framework on retail and wholesale markets"; Input to
EC Market Design Package; 10 June 2016.
128
DSOs Associations' joint event "Innovative DSOs are needed in a Decentralised Energy System",
12.04.2016,
http://www.geode-
eu.org/uploads/GEODE%20Germany/Stellungnahme/2016/0411%20FINAL%20Joint%20PR%20-
%20Innovative%20DSOs%20in%20a%20decentralised%20energy%20system.pdf
129
CEDEC position " on EC Communication - Delivering the internal electricity market and making the
most of public Intervention", December 2013; http://www.cedec.com/files/default/cedec-position-ec-
guidance-package-final.pdf
130
CEDEC publication "Smart grids for smart markets", 2014;
http://www.cedec.com/files/default/cedec_smart_grids_position_paper-2.pdf
131
CEDEC publication "Distribution grid tariff structures for smart grids and smart markets", 2014;
http://www.cedec.com/files/default/cedec%20leaflet%20grid%20tariffs-final-140403-1.pdf
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EDSO considers that DSOs are at the core of the energy transformation and have "the
potential to empower consumers to take a more active part in the energy system, for
example, by rolling-out smart meters"132
. Furthermore, EDSO argues that "engaging
consumers will require appropriate incentives and technologies", as well as "clear price
signals", for flexibility markets to develop and demand response to deliver its full
benefits"133
. EDSO notes that incentives for "dynamic tariffs or incentive based demand
response" should be set up "in order for the consumer to make savings by offering
controllable loads to network operators". It also advocates that a "revision of grid tariffs
with time-dependent and site-dependent components or incentive based demand response,
is an essential step towards realising the benefits, as well as for passing on the costs of
flexibility"134
.
Furthermore, EDSO states that "DSOs could make the most of their grid provided that they
are allowed to use system flexibility services"135
. Moreover, "increasing flexibility in the
electricity market (when technically and economically appropriate) would result in a
number of benefits for DSOs, consumers (all grid users) and society as a whole". However,
according to EDSO "this implies that distribution networks are planned differently,
incorporating new risk margins and uncertainty, are not only managed as they used to be,
but rather as networks with enhanced observability, controllability and interactions with
market stakeholders".
Regarding smart metering functionalities, EDSO claims136
that the "EED requirements
and the EC recommendation" on common minimum functionalities "have been useful
in assisting the industry identify the most relevant functionalities for smart meters. Now
that most national deployments are underway or near launch, there is no need for further
action from the European Commission". Furthermore, it notes that "proposing to further
harmonise smart meter systems at this time, beyond the existing EC’s recommendations
on minimum smart metering functionalities, could further delay smart meter deployment
and thus consumers’ access to detailed and accurate information on their energy
consumption".
EURELECTRIC
Eurelectric acknowledges that "demand response will be one of the building blocks of
future wholesale and retail markets", and "the development of innovative demand response
services will empower customers, giving them more choice and more control over their
132
EDSO report "Data Management: The role of Distribution System Operators in managing data", June
2014; http://www.edsoforsmartgrids.eu/wp-content/uploads/public/EDSO-views-on-Data-
Management-June-2014.pdf
133
EDSO report "Flexibility: The role of DSOs in tomorrow’s electricity market", May 2014;
http://www.edsoforsmartgrids.eu/wp-content/uploads/public/EDSO-views-on-Flexibility-FINAL-
May-5th-2014.pdf
134
idem
135
System flexibility services: any service delivered by a market party and procured by DSOs in order to
maximise the security of supply and the quality of service in the most efficient way – Reference: EDSO
report " Flexibility: The role of DSOs in tomorrow’s electricity market", May 2014.
136
EDSO response to the Consultation on the Review of Energy Efficiency Directive, January 2016;
http://www.edsoforsmartgrids.eu/wp-content/uploads/160129_Public-consultation-Energy-Efficiency-
Review_final_EDSO.pdf
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electricity consumption. Phasing out regulated retail prices and rolling out smart meters
continue to be key prerequisites to advance demand response further"137
. As Eurelectric
explains138
it is "fit-for-purpose smart meters" that are needed and are "... a key tool to
empower consumers". And "…without prejudice to smart meter rollouts which are already
ongoing, it would be important to guarantee that all smart meters across the EU had a
minimum agreed common set of functionalities to make sure that they contribute to
consumer empowerment and efficient retail markets. Basic common functionalities would
include, for example, the possibility of performing remote operations, the capability to
provide actual, close to real-time meter readings to consumers, or the possibility to
support advanced tariff schemes"139
. Furthermore, Eurelectric supports the position that
"smart meters with a reading interval corresponding to the settlement time period are a
technical prerequisite for participation of users (with aggregated flexibility units) in
balancing markets"140
.
To untap the full demand response potential, Eurelectric recommends141
:
(i) "ensuring that the demand response value is market-based in order to avoid any extra
costs to the system, customers and other actors";
(ii) "implementing adequate communication between third party aggregators and balance
Responsible Parties (BRPs)/suppliers to ensure that demand response can take place
effectively";
(iii) "ensuring that BRPs/suppliers are compensated for the energy they inject and that is
re-routed by third party aggregators", and "to this end, third party demand response
aggregators and suppliers agree on the rules of compensation. Changes in market rules
and settlement adjustments could also be implemented. In addition, a clear balance
responsibility of third party aggregators is needed";
(iv) "ensuring that, on a commercial basis, BRPs/suppliers are able to renegotiate supply
contracts to take into account the indirect effects of demand response (e.g. rebound
effects) and consequent impacts on sourcing costs"; and
(v) "facilitating demand response aggregation at distribution network level through
information exchange between DSOs, TSOs and aggregators, for example using a system
that reflects network availability".
137
Eurelectric report "Designing fair and equitable market rules for demand response aggregation",
March 2015; http://www.eurelectric.org/media/169872/0310_missing_links_paper_final_ml-2015-
030-0155-01-e.pdf
138
Eurelectric report "The power sector goes digital - Next generation data management for energy
consumers", May 2016;
http://www.eurelectric.org/media/278067/joint_retail_dso_data_report_final_11may_as-2016-030-
0258-01-e.pdf
139
idem
140
Eurelectric report "Flexibility and Aggregation – requirements for their interaction in the market",
January 2014; http://www.eurelectric.org/media/115877/tf_bal-agr_report_final_je_as-2014-030-0026-
01-e.pdf
141
Eurelectric report "Designing fair and equitable market rules for demand response aggregation",
March 2015; http://www.eurelectric.org/media/169872/0310_missing_links_paper_final_ml-2015-
030-0155-01-e.pdf
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GEODE
The association for the local energy distributors GEODE identifies the non-wide
deployment of smart metering as one of the main barriers for demand response taking off,
stating that there is "…no demand response and actual consumption data without smart
meters - which are still being rolled-out in many Member States"142
. Furthermore, it argues
that "…demand side flexibility aggregators should have access to balancing markets on
a level playing field with other parties", and that "…the end customer should participate
[in demand response schemes] on a voluntary basis only".
Moreover, even though GEODE recognises the need, as stated in different fora, to ensure
that smart metering systems with the right functionalities are rolled out to support demand
response, it cautions on the making a set of functionalities binding without at least
foreseeing a transition period for implementation. Following a survey that the association
undertook among its members on the use of the common minimum functionalities for
smart metering systems recommended by the Commission, it acclaimed143
that "… in those
countries where the roll-out has just started or is still in a planning phase, almost all
requirements as recommended by the European Commission are implemented". However
it continues, "…if the European Commission is considering making binding the
recommendations on smart meter functionalities […] these should apply for the next
generation of meters to be rolled-out. At least, a sufficient transitional period should be
provided which is as long as the expected lifetime of the smart metering systems already
installed respectively smart metering systems which are going to be installed in the next
years - tenders are currently running or the roll-outs have recently started with the
objective to reach the 2020 target of 80%. Otherwise it would – once again - require huge
investments to be made by DSOs for replacing existing meters."
Suppliers (Eurelectric)
Suppliers state that "while demand response has been and could continue to be deployed
by suppliers without smart metering or connected appliances, these technologies will
facilitate more advanced dynamic pricing and new demand response services"144
. They
recognise the benefits that the advent of smart metering, smart devices and overall
digitisation of the energy sector will bring in this respect, and how it will change their
interaction with consumers taking into a new level "changing their traditional business
142
GEODE Comments to the European Parliament Draft Report on “Delivering a New Deal for Energy
Consumers",
http://www.geode-
eu.org/uploads/GEODE%20Germany/DOCUMENTS%202016/GEODE%20Final%20Comments%20
-%20EP%20Draft%20Report%20New%20Deal.pdf
143
GEODE Position paper sent to EC services, dated 20/04/2016, entitled: "GEODE Survey – to assess
whether EC common minimum functional requirements for smart metering systems for electricity - EC
Recommendation of 9 March 2012 on preparations for the roll-out of smart metering systems
(2012/148/EU) are implemented by GEODE member companies"
144
Eurelectric brochure "Everything you always wanted to know about Demand Response", 2015;
http://www.eurelectric.org/media/176935/demand-response-brochure-11-05-final-lr-2015-2501-0002-
01-e.pdf
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models, based on pure delivery of kilowatt-hours towards becoming full service
providers"145
. Suppliers will "have access to new data sources and tools to communicate
with their customers and better understand their needs". Furthermore, they "…will (also)
be able to provide consumers with information on - and prediction of - their energy usage
and consumption patterns, even breaking it down into close to real-time
information…through extra devices", and enable the delivery to them of "more
personalised offers and services by market players". This includes the proposition of
"innovative demand response or time of use tariffs which contribute to the efficient
operation of the energy system whilst being financially attractive, transparent and
guaranteeing a given level of comfort to consumers through remote steering of connected
appliances."
At the same time, utilities consider that despite their experience in collecting and
processing meter readings, "dealing with more granular data generated by smart grids and
meters will carry a higher level of complexity", while competition in shaping and trading
novel energy products to consumers "will intensify from all sides", including from new
actors. Suppliers welcome the changes that are coming but recognise that they "will have
to proactively find their place in this new ecosystem".
Aggregators (SEDC)
The Smart Energy Demand Coalition (SEDC) advocates that demand-side resources
can play a crucial role in making the transition to a decarbonised energy system efficient
and affordable, and also involving in this empowered energy consumers. SEDC believes
that "a precondition for consumer empowerment is giving them a choice: citizens,
commercial and industrial consumers should be able to opt for the energy services they
prefer, the services they wish to sell, and the service provider they wish to work with. This
includes the choice to valorise the flexibility of their devices and processes on the market,
the choice to self-generate electricity, or the choice for real-time electricity pricing to
adjust parts of their consumption – automated or not – to the variability on the market and
save costs. It also includes the choice to work with their energy supplier as well as an
independent energy service provider such as a demand response aggregator for different
services"146
. For this to happen, SEDC recommends a set of "coherent measures to remove
barriers currently in place and implement a long-term vision for consumer
engagement"147
, and advises that "the potential of demand-side flexibility (is) adequately
included in all European scenario calculations and planning for infrastructure
developments".
Amongst its recommendations, SEDC lists the following:
(i) "EU rules providing for access for demand-side flexibility to all energy markets
(wholesale, balancing, ancillary services and capacity) on an equal footing with
145
Eurelectric report "The power sector goes digital - Next generation data management for energy
consumers", May 2016;
http://www.eurelectric.org/media/278067/joint_retail_dso_data_report_final_11may_as-2016-030-
0258-01-e.pdf
146
Article by F. Thies SEDC Executive Director appearing under "Guest Corner" in EC DG ENER
Newsletter of May 2016; https://ec.europa.eu/energy/en/energy_newsletter/newsletter-may-2016
147
SEDC position paper "10 Recommendations for an Efficient European Power Market Design", 2016;
http://www.smartenergydemand.eu/wp-content/uploads/2016/02/SEDC-10-recommendations.pdf
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generation", and enabling "customers … to participate in all markets directly or through
an aggregator";
(ii) "third party aggregators should access all markets without prior agreement of the
respective customer’s energy retailer/Balance Responsible Party"; and "market prices
should reflect the real value of electricity at any moment";
(iii) "any customer should have the right to a smart meter and to choose hourly, and
where applicable quarter-hourly, market pricing; the retailer/BRP should be settled
accordingly";
(iv) "Distribution System Operators should be encouraged to make use of smart demand-
side flexibility solutions offered by market parties for system operations purposes.
Incentive structures should be revised to this end"…, "… network tariffs should support,
rather than hamper the use of demand-side flexibility, and perverse incentives must be
removed".
Consumer Groups
BEUC – the European Consumer Association, advocates that as we are moving towards a
consumer-centric energy market, we need to ensure that we address both old and new
challenges – with the latter being new technologies (smart meters, connected devices,
smart homes), friendly demand-side response and new business models and new market
players. BEUC believes that "increased consumer engagement is an important factor for
the future energy sector. This requires innovative ideas to empower consumers backed
by an appropriate legal framework". Also, "new products and services need to respond
to consumers’ demands rather than risk confusing them further. Moreover, as new
technologies148
make it technically possible to process much more data than as is current
practice in the energy sector, compliance with data protection rules and their enforcement
must be ensured"149
.
BEUC feels that these technologies "in general may offer a larger choice of products and
services as well as more information for consumers, yet the benefits for consumers are
not guaranteed"150
. It clarifies its rationale by noting that "although new technologies such
as smart meters may help those who consume large amounts of electricity …, smart meters
should not be understood as a necessity to achieve energy savings. Therefore, instead of
pushing through this technology, new services (facilitated by new technologies) or demand
response programmes should be based on understanding market opportunities and
consumer outcomes. Consumers should also have the right to opt out and have their meter
operated in dumb mode. A voluntary and consumer-centred roll-out of smart meters
rather than a mandatory one may increase consumer participation and public support as
it facilitates ownership, data protection, security and cost allocation issues. Moreover,
where smart meters are rolled out, minimum functionalities and interoperability are
essential to ensure consumers have easy access to the information they need to take
148
E.g. smart meters, varying user interfaces, smart appliances and home automation
149
BEUC website - http://www.beuc.eu/press-media/news-events/energy-union-what-it-consumers
150
BEUC position paper "Building a consumer-centric energy union", July 2015;
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
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informed decisions on their consumption, but this is only the starting point. Further work
is needed to build trust and encourage consumer engagement. Consumers urgently need
clear commitments that the investments to upgrade the infrastructure and the roll-out of
smart meters will deliver benefits to them as well as monitoring and enforcement of these
commitments". BEUC therefore calls for "a solid legal and regulatory framework" "…in
order to guarantee that the roll-out is cost efficient and that costs and benefits are fairly
shared among all stakeholders who benefit from the new technology". At this point
BEUC also notes that " the benefits to DSOs from smart meters in regard to running,
surveillance, repairing and planning the network is often undervalued when setting the
share of costs covered by consumers via their bills".
Regarding demand response, and looking at what the near future can bring to households
in terms of demand response, BEUC states that a "smart demand response scheme" that
can be of interest to consumers should be "transparent (simple and clear offers and
contracts); voluntary; rewarding flexibility and not penalising in-flexibility", "focus(ed)
on consumers' needs and experience"151
. In fact to guarantee consumers can benefit
from demand response, BEUC sees that152
(i) "transparency and comparability are key to the success of new dynamic tariffs";
(ii)it is important to assess "the degree to which consumers will likely rely on automation
to deliver the expected benefits and … how (novel energy) services (could) accommodate
consumers’ lifestyles";
(iii)"regulators should ensure consumers’ flexibility is properly rewarded and that there
are price safeguards when consumers are fully exposed to wholesale market
developments"; and
(iv) calls for the "European Commission to coordinate with Member States and national
regulators a distributional analysis on the impact of time-of-use tariffs on different social
groups and if/how these groups can access the benefits of new deals".
151
BEUC presentation at the EUSEW 2016 event "Engaged customers driving the energy transition",
16.06.2016 - http://eusew.eu/engaged-customers-driving-energy-transition
152
BEUC position paper "Building a consumer-centric energy union", July 2015;
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
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3.2. Distribution networks
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Summary table
Objective: Enable Distribution System Operators ('DSOs') to locally manage challenges of energy transition in a cost-efficient and sustainable way, without distorting the market.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding on the detail
tasks of DSOs.
- Allow and incentivize DSOs to acquire flexibility services from distributed
energy resources.
- Establish specific conditions under which DSOs should use flexibility, and
ensure the neutrality of DSOs when interacting with the market or consumers.
- Clarify the role of DSOs only in specific tasks such as data management, the
ownership and operation of local storage and electric vehicle charging
infrastructure.
- Establish cooperation between DSOs and TSOs on specific areas, alongside the
creation of a single European DSO entity.
- Allow DSOs to use flexibility under the conditions set in
Option 1.
- Define specific set of tasks (allowed and not allowed) for
DSOs across EU.
- Enforce existing unbundling rules also to DSOs with less
than 100,000 customers (small DSOs).
Pro
Current framework gives more
flexibility to Member States to
accommodate local conditions in their
national measures.
Pro
Use of flexible resources by DSOs will support integration of RES E in distribution
grids in a cost-efficient way.
Measures which ensure neutrality of DSOs and will guarantee that operators do not
take advantage of their monopolistic position in the market.
Pro
Stricter unbundling rules would possibly enhance competition
in distribution systems which are currently exempted from
unbundling requirements.
Under certain condition, stricter unbundling rules would also
be a more robust way to minimizing DSO conflicts of interest
given the broad range of changes to the electricity system, and
the difficulty of anticipating how these changes could lead to
market distortions.
Con
Not all Member States are integrating
required changes in order to support
EU internal energy market and targets.
Con
Effectiveness of measures may still depend on remuneration of DSOs and regulatory
framework at national level.
Con
Uniform unbundling rules across EU would have
disproportionate effects especially for small DSOs.
Possible impacts in terms of ownership, financing and
effectiveness of small DSOs.
A uniform set of tasks for DSOs would not accommodate local
market conditions across EU and different distribution
structures.
Most suitable option(s): Option 1 is the preferred option as it enhances the role of DSOs as active operators and ensures their neutrality without resulting in excess administrative costs.
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Description of the baseline
Legal framework
Article 25 ('Tasks of distribution system operators') of the Electricity Directive puts
forward provisions which describe the core tasks of DSOs, as well as, specific obligations
that DSOs have to comply with. Under these provisions, DSOs are mainly responsible to
operate, maintain and develop under economic conditions a secure, reliable and efficient
electricity distribution system.
Except these core tasks, the Electricity Directive sets under Article 25(6) some specific
obligations e.g. in cases where DSOs are responsible for balancing the distribution system.
Moreover, under Article 25(7), DSOs shall consider measures such as energy efficiency
and demand-side management, in order to avoid investing in new capacity.
According to Article 41 of the Electricity Directive Member States are responsible to
define roles and responsibilities for different actors including DSOs. These roles and
responsibilities concern the following areas: contractual arrangements, commitment to
customers, data exchange and settlement rules, data ownership and metering responsibility.
Article 26 of the Electricity Directive set also unbundling requirements for DSOs similar
to Directive 2003/54/EC (the previous Electricity Directive which was part of the Second
Package). The Electricity Directive sets unbundling requirements in terms of legal form
(legal unbundling) where the DSO is a legally separate entity with its own independent
decision making board, but remains under the same ownership of a vertically integrated
undertaking ('VIU'). Under this form of unbundling it is also required that DSOs implement
functional unbundling where the operational, management and accounting activities of a
DSO are separated from other activities in the VIU. Article 31 of the Electricity Directive
also requires the unbundling of accounts (accounting unbundling) where the DSO business
unit must keep separate accounts for its activities from the rest of the VIU in order to avoid
cross-subsidisation,.
Article 26(4) of the Electricity Directive gives the option to Member States not to apply
the unbundling rules (no legal/functional unbundling) for DSOs with less than 100,000
customers. Only accounting unbundling applies to DSOs below this threshold. Member
States may choose to apply this threshold or not, or to set a lower threshold. Article 26(3)
contains obligations which seek to strengthen regulatory oversight on vertically integrated
undertakings and to mitigate communication and branding confusion.
Assessment of current situation
Electricity distribution differs widely across EU Member States in terms of the number of
DSOs in each country, voltage level of the distribution system, and tasks. According to
CEER153
(data for 24 EU Member States) there is a total of 2,600 electricity DSOs
operating across EU (see figure 1). From these DSOs, 2,347 (around 90% of the total) fall
under the 100,000 rule and according to Article 26(4), for these DSOs, Member States are
not obliged to implement unbundling provisions under Article 26 of the Electricity
Directive.
153
"Status Review on the Transposition of Unbundling Requirements for DSOs and Closed Distribution
System Operators" (2013) CEER.
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Figure 1: Number of electricity DSOs per Member State
Source: CEER (2013)
Within the framework of the Electricity Directive, Member States have to determine the
detailed tasks of DSOs. There is number of factors which may affect those tasks such as:
the structure and ownership of electricity distribution (i.e. public/private, municipalities
etc.), development of the electricity sector, size of the DSOs, voltage level of distribution
grid. For instance, in Member States with a high number of DSOs two layers of distribution
systems usually exist, local distribution systems and regional distribution systems which
connect local networks with the transmission network.
According to the Electricity Directive the core tasks of DSOs are to maintain, develop and
operate the distribution network. The Electricity Directive does not allocate other specific
tasks to DSOs such as for instance metering or data management activities. The more
specific activities are left to Member States to decide, according for instance to Article 41.
According to the Electricity Directive DSOs may also perform balancing activity, this may
be the case in some Member States for regional or larger DSOs.
Therefore, as the EU legislation leaves a quite open framework, there is a variety of tasks
for which DSOs are responsible, depending on the Member State where they are operating.
For instance, even in activities such as metering and connection that in the majority of the
Member States is traditionally performed by the DSOs, there are cases (e.g. UK) where the
activity is open to competition.
When it comes to tasks which can be performed both by TSOs and DSOs there is a mixed
picture across the EU. In general, tasks such as dispatching of generation and use of
flexibility resources are part of TSO tasks. In the majority of Member States where DSOs
can be involved in dispatching activities, this is mostly in cases of emergency in order to
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ensure security of supply. Cases where flexibility resources or interruptible contracts can
be used by DSOs are rather limited154
.
In meeting the 2020 targets and 2030 climate and energy objectives155
, Member States will
have to integrate a high amount of RES with an increasing number of these resources being
variable RES E (wind and solar). A large share of these resources is connected to
distribution grids (low and medium voltage); according to available data156
this number is
estimated to be even higher than 90% in some Member States (e.g. Germany) and over
50% in others (Belgium, UK, France, Ireland, Portugal, and Spain).
Moreover, the electrification of sectors such as transport and heating will introduce new
loads in distribution networks. These elements will create new requirements and
possibilities157
for DSOs, who will have to manage higher peaks in demand while
maintaining quality of service and minimizing network costs.
The degree of the challenge of integrating high amounts of variable RES (VRES) in
networks differs among the Member States. A group of Member States such as for example
Germany, Denmark, Spain, Portugal already have integrated significant amounts of wind
and solar power in the grid and are expecting more moderate growths rates in VRES
capacity going forward to 2030 (see figure 2). The majority of Member States have
integrated a moderate amount of wind and solar power but will experience higher growth
rates of VRES compared to the group with a high VRES ratio. A minority of Member
States have VRES ratios of less than 5% but are expected to have the highest growth rates
going forward to 2030.
Figure 2: Wind and solar growth rates and ratio to total capacity
Source: Copenhagen Economics, VVA Europe (2016).
Distribution grids will also face an increasing challenge from the integration of new loads
resulting from electric vehicles (EV) penetration and heat pumps. Currently, penetration
154
"Study on tariff design for distribution systems" (2015) AF Mercados, refE, Indra.
155
COM(2014) 15 final "A policy framework for climate and energy in the period from 2020 to 2030".
156
EvolvDSO project (Deliverable 1.1) and other sources.
157
On the one hand EVs and heating/cooling loads will require more network capacity, on the other hand
this kind of loads offer a huge storage potential (i.e. battery and heat storage) which can be coordinated
in order to offer flexibility services to the system.
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rates for electric vehicles are low among the European countries ranging from around 700
cars in Portugal to 44,000 cars in the Netherlands (see table 1). However, the uptake of
electric vehicles is expected to increase by over 50% per year going forward to 2030 in
several EU Member States. Germany is expected to have the highest number of electric
vehicles with over 10 million cars in 2030.
Table 1: Number of Electric Vehicles in selected countries (2014 – 2030)
Country 2014 2030 (projected) Annual expected
increase
Portugal 743 867,000 55%
Denmark 2,799 436,000 37%
Spain 3,536 4,263,000 56%
Sweden 6,990 517,000 31%
Italy 7,584 6,638,000 53%
UK 21,425 3,735,000 38%
Germany 24,419 10,024,000 46%
France 30,912 5,431,000 38%
Norway 40,887 429,000 16%
Netherlands 43,762 982,000 21%
Source: Copenhagen Economics, VVA Europe (2016).
Cost-effectively adapting to these changes will require DSOs to use flexible distributed
energy resources (e.g. demand response, storage, distributed generation etc.) to manage
local congestion, which will also require enhancing DSO/TSO collaboration. The use of
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such flexibility for the operation and planning of the network has the potential to avoid
costly network expansions. For example, it may be significantly cheaper for a DSO to
overcome local network congestion by occasionally procuring demand response services
than to upgrade its entire network infrastructure in an area to be able to accommodate
relatively uncommon demand peaks. This is a pressing issue for the EU in light of the fact
that electricity network costs increased by 18.5% for households and 30% for industrial
consumers between 2008 and 2012158
.
For instance, a study159
conducted for the German distribution networks estimated that
under the current conditions and depending on different scenarios, a considerable
additional overall investment will be required. The study concludes that innovative
planning concepts in conjunction with intelligent technologies considerably reduce the
network expansion requirement160
.
In the majority of Member States presented in table 2, DSOs cannot currently procure
flexibility services partially because there is a lack of a legal framework or because the
services are not covered in the regulated cost base.
Table 2: Status Quo on DSOs incentives to procure flexibility services
Procurement of flexibility services Number of Member
States
Member state
DSOs cannot contract flexibility
services
8 FI, FR, IE, IT, PT, EL, NL, ES
DSOs can contract system flexibility
services for constraints management
in certain situations
3 UK, BE, DE
Source: Copenhagen Economics, VVA Europe (2016).
According to EvolvDSO project161
most DSOs surveyed (France, Ireland, Italy, Portugal)
are not able to contract flexibility for congestion management although discussions on the
topic take place in these countries. In Belgium and Germany, DSOs have the possibility to
obtain system flexibility services via the connection and distribution access contract. These
types of contracts provide for instance a reduced network fee in exchange for the control
of the unit.
158
COM(2014) 21 /2 "Energy prices and costs in Europe"
159
"Moderne Verteilernetze für Deutschland(Verteilernetzstudie)" (2014) E-Bridge, IAEW, OFFIS.
160
According to the study 90% of the capacity of installed renewable energy installations is connected up
to distribution networks. With an overall coverage of 1.7 million kilometres, these networks make up
about 98% of the overall national grid in Germany. An amount of 23 billion euros to 49 billion euros
depending on the scenario must be invested in distribution networks by 2032 for the integration of
renewable energy installations. The combination of innovative planning concepts with intelligent
technologies can halve the investment requirement and reduce by 20% the average supplementary costs.
161
EvolvDSO (“Development of methodologies and tools for new and evolving DSO roles for efficient
DRES integration in distribution networks”) is an FP7 collaborative project funded by the European
Commission (http://www.evolvdso.eu/Home/About).
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In Belgium, such contracts apply to new production units requesting connection at HV and
MV grids. The contract allows to temporarily limit the active power of the unit via distance
control. In Germany DSOs offer these "non-firm" access contracts to controllable thermal
loads, i.e. heat pumps and overnight storage heating (EvolvDSO, 2016). Both countries are
considering broadening these contracts to also include flexibility contracts for congestion
management under normal operation state and not just emergency situations (EvolvDSO,
2016).
From data presented in the study by AF Mercados et al (2015) regarding the responsibility
of DSOs in dispatching of embedded generation, use of interruptible contracts and other
sources of flexibility, it is concluded that in most of Member States where DSOs can be
involved in dispatching this is most of the times for coping with emergency situations
(security reasons). In less than 1/3 of the Member States DSOs are using solutions such as
flexibility resources or interruptible contracts in order to address grid problems.
Deficiencies of current legislation
According to the conclusions of "Evaluation of the EU's regulatory framework for
electricity market design and consumer protection in the fields of electricity and gas" one
of the main objectives of the Electricity Directive was to improve competition through
better regulation, unbundling and reducing asymmetric information. In general,
unbundling measures contribute to the contestability of the retail market and thus facilitate
market entry by third party suppliers.
The risks of less unbundling link to suboptimal switching procedures in order to deter
market entry, competitive advantage which may come from the use of the same brand name
or privileged access to network information, consumption data information and cross-
subsidies.
On the other hand, discrimination for distribution network access appears to be less
relevant than at transmission level, with a possible exception of small generation connected
at distribution level. DSO unbundling is less relevant with respect to cross-border flows as
flows are more local.
CEER finds that in general the implementation of unbundling rules has been
satisfactory162
. Regarding the implementation of the measures, CEER is reporting
problems in the implementation of the provisions related to branding and communication.
The Commission has taken action towards the proper implementation of the relevant
provisions through compliance checks and infringement procedures, requesting Member
States to ensure a clear separation of identity of the supply and distribution activities within
a vertically integrated undertaking.
Some of the factors that may influence and raise the impact of the foreseen risks are the
increased penetration of RES E generation at distribution level and introduction of smart
metering systems.
In terms of effectiveness, the intervention mainly aimed at the unbundling of vertical
integrated distribution companies with the objective to ensure non-discriminatory and
transparent third party access in distribution networks, in order to promote competition in
162 "Status Review on the Implementation of Distribution System Operators’ Unbundling Provisions of the
3rd Energy Package" (2016) CEER.
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the energy market. There is no evidence that the intervention within the boundaries of the
unbundling requirements, did not achieve the objective of promoting competition in the
market.
The Electricity Directive leaves it at the discretion of Member States to decide which level
of unbundling will apply for small DSOs (less than 100,000 customers) and the detailed
tasks that DSOs should carry out at a national level. There is a quite diverse situation across
EU Member States when it comes to responsibilities of DSOs across the EU.
Provisions which aimed to enhance the DSOs position in using demand side management
and energy efficiency measures in planning their networks did not prove to be effective.
Only in few Member States, DSOs are in position to use such tools in order to avoid costly
investments and operate their networks more efficiently.
In terms of relevance, the original objectives of DSO unbundling requirements and the
framework in which Member States can decide on the responsibilities of operators still
correspond to the EU objective of a competitive internal energy market. The
implementation of smart metering systems (wide scale roll-out in 17 Member States) will
generate more granular consumption data and new business opportunities in the retail
market. Moreover, the introduction of more RES E generation at distribution level will
require a more active management of the network from DSOs. Even if the measures under
the Electricity Directive had included to a certain extent these developments the focus of
the intervention was not on these new needs that are estimated to grow with the completion
of smart metering systems and the installation of distributed RES E.
In terms of coherence, the measures are fully coherent with the objectives of the internal
energy market. Unbundling provisions for DSOs complement the relevant requirements
for TSOs, by providing a transparent and non-discriminatory framework for third party
access also at retail market level. These provisions are fundamental for the promotion of
competition in the energy market, the entrance of new energy service providers and the
development of new services.
In terms of EU-added value, the requirements on unbundling are fundamental for the
promotion of competition in the internal energy market. Provisions which are relevant to
DSOs have the characteristic of a permanent effect.
Gap analysis
According to the conclusions of the "Evaluation of the EU's regulatory framework for
electricity market design and consumer protection in the fields of electricity and gas" with
the deployment of smart metering systems across EU Member States a large amount of
data will be available to DSOs. This development requires a closer assessment and
consideration of specific measures.
In terms of DSO responsibilities, it is clear that there is a wide variety of roles and tasks
for DSOs across the EU. This situation does not allow for the application of a uniform set
of responsibilities for all DSOs, as such measure would have a disproportionate effect on
DSOs across the EU, based mostly on the variety of distribution voltage levels and number
of connected customers.
It seems however appropriate to enhance the role of DSOs when it comes to additional
tools such as the use of flexible resources in order to improve their efficiency in terms of
costs and quality of service provided to system users. Such measures however could only
be introduced with the parallel introduction of suitable provisions which prohibit DSOs to
take advantage of their monopolistic position in the market by clarifying their role in
specific activities. In the absence of such measures, the DSOs could foreclose the market
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and reduce the benefits for the system users, leading to an inefficient allocation of
resources and reduction of social welfare.
Presentation of the options
Distribution system operators
Under Option 0 (BAU) existing provisions of the Electricity Directive will continue to
apply concerning the tasks of DSOs. In this case Member States are responsible for
deciding on a number of non-core tasks as well as on remuneration of DSOs.
Option 0+ (Non-regulatory approach) was discarded as the existing EU legislative
framework does not directly address flexibility in distribution networks. This needs to be
further codified in law in order to ensure, inter alia, a level playing field for the
achievement of the EU's RES E deployment objectives given new market conditions. In
addition, it is unlikely that voluntary cooperation between Member States would deliver
the desirable policy objectives in this case.
Under Option 1 the objective is to allow the DSOs to procure and use flexibility services.
Introduce specific conditions under which DSOs should procure flexibility in order to
ensure neutrality and enable longer term investments in flexibility. Moreover, the role of
DSOs regarding specific tasks such as data management, ownership and operation of
storage and electric vehicle charging infrastructure will be clarified under this option.
Measures under Option 1 will also seek to establish an enhanced cooperation between
TSOs and DSOs in terms of network operation and planning.
Under Option 2 measures will aim to define specific tasks that DSOs across the EU should
be allowed and not allowed to carry out. The tasks that DSOs should be allowed to carry
out would include their core tasks and tasks where there is no potential competition, while
activities which are open to competition or already forbidden (e.g. generation or supply)
should not be allowed. Also, under this option existing unbundling rules will apply also to
DSOs with less than 100,000 customers (small DSOs), abolishing the provision of the
Electricity Directive which allows Member States to exempt small DSOs from legal and
functional unbundling.
Comparison of the options
a. The extent to which they would achieve the objectives (effectiveness)
The main objective is to enable DSOs to locally manage challenges of the energy transition
in a cost-efficient and sustainable way, without distorting the market.
In general the current EU framework leaves to Member States the more detailed
identification of the distribution framework at national level in terms of the specific tasks
that DSOs should carry out and the tools available for operating and developing their grids.
However, in light of the major changes the electricity system is undergoing, Option 0 is
likely to be inadequate in ensuring a cost efficient grid operation.
DSOs may in some countries not have access to appropriate tools in order to operate
efficiently, for instance by procuring flexibility from their customers through aggregators
or local markets, while in many countries they are not adequately incentivised through the
remuneration schemes in place to do so. The Electricity Directive requires DSOs to take
into account demand-side management and energy efficiency measures or distributed
generation as well as conventional assets expansion when planning their networks.
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However, it is up to Member States (national authorities, NRAs and DSOs) to ensure that
this is carried out. While this option provides an open EU framework for Member States,
it is also likely to lead to national specific frameworks which are not conducive to the use
of demand side flexibility at DSO level.
Moreover, there are different approaches across Member States for the use of demand side
flexibility from DSOs and a lack of market rules under which DSOs shall procure
flexibility services, while there is no clear framework regarding the involvement of DSOs
in activities such as storage or electric vehicle charging infrastructure.
The measures under Option 1 will establish a clear legal basis for allowing DSOs to use
flexibility. Specific measures under this option will also clarify the role of DSOs in
competitive activities such as storage and electric vehicles charging, and set a specific
framework for DSO involvement. Such a regulatory framework should allow different
solutions in order to address specific needs of the network, based on market procedures
(e.g. long-term contracting of flexibility services such as large scale storage). Regarding
the involvement of DSOs in data handling, specific measures under Option 1 will ensure
neutrality of operators (see also Annexe 7.3 of the present annexes to the impact
assessment).
DSOs should harness flexibility from grid users without the risk of distorting or hampering
the development under competitive terms of distributed energy services, such as demand
response, storage, supply and generation, through discriminatory practices or monopolistic
behaviour. This Option will reduce the risk of competition distortions compared to Option
0. By defining a common framework on how DSOs can procure flexibility and perform
specific roles such as involvement in storage, a level playing field of a certain standard
will be ensured across Member States, unlike the situation where Member States adopt
different approaches to this issue. Moreover, cooperation with TSOs is important as
resources which provide flexibility to the system are located in the distribution system and
therefore coordinated operation and exchange of information between operators will be
required.
Effectiveness of this option can be limited by the fact that the differences among
distribution system structures and tasks of DSOs across the EU, will possibly require that
measures at EU level have to remain broad enough in order to accommodate diverse
situations.
Regarding the use of flexibility, the effectiveness of this option also depends on the
implementation in each Member State, as national remuneration schemes are important in
order to provide to DSOs the right incentives to use flexibility and be properly remunerated
(links to options under distribution tariffs and remuneration, see also Annexe 3.3 of the
present annexes to the impact assessment).
Option 2 foresees a uniform framework for DSOs in terms of tasks and level of unbundling
across the EU. The procurement of flexibility from DSOs will be similar to Option 1.
Stricter unbundling rules for small DSOs may lower the risk for discriminatory behaviour
and result in gains in retail competition. On the other hand, given that DSOs are natural
monopolies, such measures will not fully guarantee the avoidance of the dominant role of
DSOs in procuring flexibility from system users. Therefore, additional measures will be
needed in order to avoid monopolistic behaviour from DSOs which could lead to market
distortions.
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The definition of a uniform set of tasks applicable to all DSOs could lead to non-effective
arrangements depending on the different market conditions as such a framework would not
be able to account for the differences between distribution systems across the EU (e.g.
different retail market conditions or structural and technical differences of distribution
systems)163
.
b. Their respective key economic impacts and benefit/cost ratio, cost-effectiveness
(efficiency) & Economic impacts
Impacts of measures under Option 1 will be highly dependent on the detailed
implementation at national level, as for instance the extent to which DSOs under the
monitoring of the NRA will decide to supplant grid expansions with the use of flexibility
in network planning. The decision of such measures will be made on the basis of the most
beneficial solution for each distribution system taking into account avoided investments
and considering the costs of employing flexible resources.
Curtailment of RES E in grid planning as quantified in the E-Bridge et al (2014) study164
could help reducing the grid expansion requirements caused by new RES E installations in
the future by at least 22% in the higher voltage grid (>110 kV). Those savings of 22% can
be achieved when allowing for 3% curtailment in grid planning. Considered generation for
curtailment are wind and solar power installations larger than 7 kW; that affects 52% of
all installations, whose aggregated capacity accounts for more than 90% of the total
capacity installed. The benefits of curtailment are lower expansion requirements for the grids,
which do not have to be built to accommodate flows corresponding to the maximum
capacity of the connected RES E installations.
Copenhagen Economics, VVA Europe (2016)165
estimate that the total savings at EU level
from avoided distribution grid investments will be in the order of at least EUR 3.5 to 5
billion in yearly investments towards 2030 (table 3). This corresponds to a total of
approximately EUR 50-85 billion accumulated from 2016. In practice, the potential
savings could be significantly higher, to the extent which supply and demand side
flexibility measures can be used in combination rather than each measure in isolation.
163
CEER in its public consultation paper "The future role of DSOs" (2014), proposes a set of potential DSO
activities categorized under three broad areas (core activities, 'grey area' activities and forbidden
activities). In its conclusion paper (2015), CEER remarks that there is no single model for what a DSO
can and cannot do, but rather a number of grey areas where DSOs can participate under certain
conditions.
164
"Moderne Verteilernetze für Deutschland (Verteilernetzstudie)" (2014) E-Bridge, IAEW, OFFIS.
165
"Impact assessment support study on: Policies for DSOs, Distribution Tariffs and Data Handling"
(2016) Copenhagen Economics, VVA Europe..
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Table 3: Avoided grid investments from flexibility
Extra grid investment from increased DG and load growth (EUR billion) yearly at EU
level
11
Savings from demand flexibility alone (percent) 30 - 55
Savings from supply flexibility alone (percent) 44 - 55
Savings from combination of demand and supply flexibility (percentage) At least 30-44
Very conservative estimate of avoided extra grid investments from flexibility
yearly at EU level (EUR billion)
3.5 to 5
Source: Copenhagen Economics, VVA Europe (2016).
McKinsey & Company (2015)166
found that energy storage can absorb a large share of the
power that would otherwise been curtailed even in a scenario with high share of variable
renewable power, and most of the flexibility would be located on the distribution grid level.
Decisions on which source of flexibility is more efficient should be made on the basis of
the specific needs of the network according to transparent, non-discriminatory and market-
based procedures, under close regulatory control.
Related measures are expected to create net benefits for the electricity system as they will
lower distribution costs. Moreover, the use of flexibility from distribution system operators
will stimulate the introduction of new services and the market entrance of new players such
as aggregators. Consumers will benefit from lower network tariffs (reflecting lower
distribution costs) and directly by participating in demand response programmes or other
services to the DSO.
The clarification of the EU framework regarding the role of DSOs in specific tasks such
as data handling, storage and electric vehicle charging, is expected to have positive net
benefits for the electricity system and positive economic societal net benefits. The main
reason is that these tasks can be carried out more efficiently by market players rather than
natural monopolies. Measures under this option will allow certain exemptions in cases
where a market is new (e.g. electric vehicles) or where there is no interest from market
parties to invest in such activities.
Option 2 would result in higher costs as small DSOs (serving less than 100,000 customers)
would have to implement legal unbundling criteria. Such an option would lead small DSOs
to separate distribution from the supply activity of the VIU and possibly merge with larger
DSOs, resulting in one-off and structural costs which differ per Member State. On the other
hand, main benefits would result from more transparent third party access which could
potentially have positive impacts on competition. Such costs and benefits are hard to be
fully quantified as many parameters and different local conditions should be taken into
account.
c. Simplification and/or administrative impact for companies and consumers
Option 2 for distribution system operators is expected to have high administrative costs
on the concerned energy companies because of the unbundling requirement on small DSOs
166
"Commercialisation of energy storage in Europe" (2015) McKinsey & Company.
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(less than 100,000 customers) which is expected to require a restructuring of those energy
companies affected by the measures.
d. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
e. Trade-offs and synergies associated with each option with other foreseen measures
Option 1 for distribution system operators demonstrates multiple synergies with options
under demand response and smart metering. Demand response programmes through
aggregators can provide services to DSOs who wish to use flexibility in network operation
and planning.
f. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
g. Which Option is preferred and why
Option 1 is the preferred option as it demonstrates the higher potential net benefits for
electricity system and society and expected to demonstrate additional benefits compared
to Option 0 without resulting in excessive costs for the involved parties. Consumers will
benefit from lower distribution costs and improved competition in the market.
Subsidiarity
EU has a shared competence with Member States in the field of energy pursuant to Article
4(1) TFEU. In line with Article 194 of the TFEU, the EU is competent to establish
measures to ensure the functioning of the energy market, ensure security of supply and
promote energy efficiency.
Under the energy transition, distribution grids will have to integrate even higher amounts
of RES E generation, while new technologies and new consumption loads will be
connected to the distribution grid. Distributed generation has the potential directly or
through aggregation to participate in national and cross-border energy markets. Moreover,
other distributed resources such as demand response or energy storage can participate in
various markets and provide ancillary services to the system also with a cross-border
aspect.
Moreover, DSOs should have the ability to integrate new generation and consumption
loads under cost-efficient terms. The access conditions for RES E generation and other
distributed resources shall be transparent and the DSO's role should be neutral in order to
create a level playing field for these resources. As the amount of resources such as RES E
generation, but in the future also other resources such as storage, will increase, the
conditions under which these resources can access the grid and participate in the national
and cross-border energy markets is expected to become more relevant.
The neutrality of DSOs when they are using flexibility to manage local congestion is a
precondition for well-functioning retail market. While electricity distribution can be
considered a local business, harmonised rules ensuring neutrality of DSOs towards other
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market actors including new energy services providers create a level playing field for RES
E development across the EU, crucial in achieving the RES E targets, and support the
completion of internal energy market.
Distribution grid issues may affect the development of the internal energy market and raise
concerns over possible discrimination among system users from different Member States
who however have access in the same energy markets. Uncoordinated, fragmented national
policies at distribution level may have indirect negative effects on neighbouring Member
States, and distort the internal market. EU action therefore has significant added value by
ensuring a coherent approach in all Member States.
Stakeholders' opinions
3.2.7.1. Results of the consultation on the new Energy Market Design
According to the results of the public consultation on a new Energy Market Design167
the
respondents view active distribution system operation, neutral market facilitation and data
hub management as possible functions for DSOs. Some stakeholders pointed to a potential
conflict of interests for DSOs in their new role in case they are also active in the supply
business and emphasized that the neutrality of DSOs should be ensured. A large number
of the stakeholders stressed the importance of data protection and privacy, and consumer's
ownership of data. Furthermore, a high number of respondents stressed the need of specific
rules regarding access to data.
Governance rules for DSOs and Models of data handling
Question: "How should governance rules for distribution system operators and access to
metering data be adapted (data handling and ensuring data privacy etc.) in light of market
and technological developments? Are additional provisions on management of and access
by the relevant parties (end-customers, distribution system operators, transmission system
operators, suppliers, third party service providers and regulators) to the metering data
required?"
Summary of findings:
Regulators stress the importance of neutrality in the role of the DSOs as market facilitators.
To achieve this will require to:
- Set out exactly what a neutral market facilitator entails;
- When a DSO should be involved in an activity and when it should not;
- NRAs to provide careful governance, with a focus on driving a convergent
approach across Europe.
Regulators consider that consumers must be guaranteed the ownership and control of their
data. The DSOs, or other data handlers, must ensure the protection of consumers’ data.
IFIEC considers that DSOs should not play the role of market facilitator, the involvement
of a third party is perceived to better support neutrality and a level playing field. Moreover,
coordination of TSOs and DSOs and potentially extended role of DSOs with respect to
congestion management, forecasting, balancing, etc. would require a separate regulatory
167
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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framework. However, IFIEC express concerns that some smaller DSOs might be
overstrained by this. Extended roles for DSO should be in the interest of consumers and
only be implemented when it is economically efficient.
EUROCHAMBERS believes that due to different regional and local conditions a one size
fits all approach for governance rules for distribution system operators is not appropriate.
The EU could support Member States by developing guidelines (e.g. on grid infrastructures
and incentive systems).
Most energy industry stakeholders (CEDEC, EDSO, ESMIG, ETP, EUROBAT, EWEA,
GEODE) believe that the role of DSOs should focus on active grid management and neutral
market facilitation. Some respondents state that the current regulatory framework prevents
DSOs from taking on some roles, such as procurer of system flexibility services and to
procure balancing services from third parties, and such barriers should be eliminated.
Also SEDC envisages that DSOs should be neutral market facilitators where unbundling
is fully implemented. However, in this scenario DSOs should not be active in markets such
as for demand response, as this would undermine their neutrality.
3.2.7.2. Public consultation on the Retail Energy Market
According to the results of the 2014 public consultation on the Retail Energy Market168
the
majority of the respondents consider that DSOs should carry out tasks such as data
management, balancing of the local grid, including distributed generation and demand
response, and connection of new generation/capacity (e.g. solar panels).
According to the majority of the stakeholders these activities should be carried out under
good regulatory oversight, with sufficient independence from supply activities, while a
clear definition of the role of DSOs (and TSOs), but also of the relationship with suppliers
and consumers, is required.
3.2.7.3. Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31st
EU Electricity Regulatory Forum:
- "The Forum stresses the importance of innovative solutions and active system
management in distribution systems in order to avoid costly investments and raise
efficiencies in system operation. It highlights the need for DSOs to be able to
purchase flexibility services for operation of their systems whilst remaining neutral
market facilitators, as well as the need to further consider the design of distribution
network tariffs to provide appropriate incentives. The Forum encourages
regulators, TSOs and DSOs to work together towards the development of such
solutions as well as to share best practices."
168
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
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3.3. Distribution network tariffs and DSO remuneration
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Summary table
a. Table 1: Remuneration of DSOs
Objective: A performance-based remuneration framework which incentivize DSOs to increase efficiencies in planning and innovative operation of their networks.
Option: 0 Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible on deciding on the detailed
framework for the remuneration of
DSOs.
- Put in place key EU-wide principles and guidance regarding the remuneration of
DSOs, including flexibility services in the cost-base and incentivising efficient
operation and planning of grids.
- Require DSO to prepare and implement multi-annual development plans, and
coordinate with TSOs on such multi-annual development plans.
- Require NRAs to periodically publish a set of common EU performance indicators
that enable the comparison of DSOs performance and the fairness of distribution
tariffs.
Fully harmonize remuneration methodologies for all DSOs
at EU level.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Performance based remuneration will incentivise DSOs to become more cost-efficient
and offer better quality services.
It would support integration of RES E and EU targets.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards regulatory
schemes which incentivize DSOs and
raise efficiencies.
Con
Detailed implementation will still have to be realized at Member State level, which
may reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO remuneration schemes
would not meet the specificities of different distribution
systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting the subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective remuneration schemes and enhancing transparency
requirements
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b. Table 2: Distribution network tariffs
Objective: Distribution tariffs that send accurate price signals to grid users and aim to fair allocation of distribution network costs.
Option: O Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible for deciding on the detailed
distribution tariffs.
- Impose on NRAs more detailed transparency and comparability requirements
for distribution tariffs methodologies.
- Put in place EU-wide principles and guidance which ensure fair, dynamic, time-
dependent distribution tariffs in order to facilitate the integration of distributed
energy resources and self-consumption.
Harmonization of distribution tariffs across the EU; fully
harmonize distribution tariff structures at EU level for all EU
DSOs, through concrete requirements for NRAs on tariff
setting.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Principles regarding network tariffs will increase efficient use of the system and
ensure a fairer allocation of network costs.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards distribution
network tariffs which effectively
allocate costs and accommodate EU
policies.
Con
Detailed implementation will still have to be realized at Member State level, which
may reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO structures would not meet
the specificities of different distribution systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting the subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective distribution network tariffs and enhancing transparency
requirements
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Description of the baseline
Legal framework
According to Article 37(1) of the Electricity Directive, National Regulatory Authorities
(NRAs) are responsible for setting or approving distribution tariffs or their methodologies.
Article 37(6) and Article 37(8) of the Electricity Directive set some more specific
requirements for NRAs on tariff setting procedures and provide general principles. These
principles require tariffs or methodologies to allow the necessary investments in the
networks and ensure viability of the networks. NRAs shall also ensure that operators are
granted appropriate short and long-term incentives to increase efficiencies, foster market
integration and security of supply and support the related research activities.
Assessment of current situation
According to available data169
allowed revenues (remuneration) for DSOs are set or
approved by regulators in the majority of Member States, with the exception of Spain (ES),
where allowed revenues are set by the Government.
In most Member States tariffs are also being set by the national regulator. However in some
countries the responsibilities are shared between the regulator and the DSO, the regulator
mainly defines the rules and approves the tariffs proposed by the DSO. Spain is the only
country where the Government sets the tariffs. Distribution tariffs are published in all
Member States. However, in Spain distribution tariffs are bundled with other tariff
components, covering costs such as renewable generation fees.
There is a wide variety of remuneration schemes and tariff structures across the EU, which
partly reflects the different situations and local conditions in Member States. With the
exception of the UK, current incentive‐based regulatory schemes place little emphasis on
the output delivered by the distributor, but for quality of service schemes. Moreover, the
following conclusions can be derived from the assessment of the current regulatory
regimes across the EU:
- Typically DSOs are not exposed to volume risk and to the risk that their investment
turns out to be less useful than expected when they were decided, for example
because of lower than expected demand.
- Revenue setting mechanisms based on benchmarking are implemented in countries
where the distribution sector is highly fragmented.
- Regulators and stakeholders are generally less involved in the decision‐making
process on distribution network development, as compared to transmission.
- Traditional tariff structures reflect a situation of limited availability of information
on each consumer’s responsibility in causing distribution costs and are also affected
by affordability and fairness considerations.
- In most countries, the share of distribution revenues from tariff components based
on energy is large, resulting in an asymmetry between the structure of distribution
costs (mostly fixed) and the way they are charged to consumers.
- In the electricity sector the energy tariff component applied to households represent
on average 69% of the total network charge. This practice is common in most
169
"Study on tariff design for distribution systems" (2015) AF Mercados, refE, Indra..
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countries apart from three (The Netherlands, Spain and Sweden) where the energy
charge weights between 21% and 0%.
- In the case of industrial customers the weight of the energy component is still
dominant (around 60% for both small and large industrial clients) but there is more
variability among countries and the corresponding weight ranges between 13% and
100%.
The current distribution tariff structures have been inherited from previous regulatory
regimes, when tariff structures were a simple combination of distribution and supply costs,
including fixed and variable energy costs, for services provided by a single utility. The
distribution tariff is generally based on the distributed amount of energy, occasionally in a
way that varies across times of the day and across seasons, but only rarely linked to peak
load requirements. Historically, this type of volume based pricing structure was
appropriate, as consumers with high peak load requirements also tended to be those who
consumed most energy. Going forward the total costs on the system, which are correlated
with the size of peak demand, will be less linked to total energy consumption.
Currently, the majority of DSO revenue is collected through volumetric tariffs, i.e. 69% of
the revenue for household consumers, 54% for small industrial consumers and 58% for
large industrial consumers (table 3). This also shows that most EU Member States have a
two-part tariff with a capacity and/or fixed component and a volumetric element.
Table 3: Status quo on volumetric and capacity tariffs among Member States
Tariff structure elements Tariff component
for household
consumers
Tariff component
for small industrial
consumers
Tariff component
for large industrial
consumers
Member states where the
volumetric element weights
over 50% of the DSO tariff
AT, CY, CZ, FR, DE,
GR, HU, IT, LU, PL,
PT, RO, SK, SI, GB
CY, CZ, FI, FR,
DE, GR, HU, RO,
SE, SK, GB
AT, CY, FI, FR,
GR, HU, PL, RO,
SE, SK, SI, NL, GB
Member states where the
capacity element + fixed
charge weights over 50% of
the DSO tariff
ES, SE, NL
AT, IT, LU, PL, PT,
SI, ES, NL
CZ, DE, IT, LU,
PT, ES
EU capacity element + fixed
component average
31% 46% 42%
EU volumetric element
average
69% 54% 58%
Note: Bulgaria and Latvia are not included in the survey, Netherlands has a 100% capacity
based tariff for households and small industrial consumers as the only country in the EU.
In DK, Finland, Luxembourg and Malta time-of-use tariffs are not available for
household customers.
Source: Copenhagen Economics, VVA Europe (2016) based on Mercados (2015) and Eurelectric (2013).
Only 3 Member States (Spain, Sweden and the Netherlands) have a capacity and/or fixed
component that weighs over 50% of distribution tariff for household consumers. The
Netherlands have a 100% capacity based tariff for households and small industrial
consumers as the only country in the EU, while Romania has a 100% volumetric tariff.
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Between 6 and 8 Member States apply distribution tariffs where the capacity and fixed
tariff weighs over 50% of the tariff for small and industrial consumers.
In 17 countries a time‐of‐use distribution tariff is applied, typically for non‐residential
consumers and with daily (night/day) or seasonal (winter/summer) structure (Mercados
2015). France has implemented tariffs that can incite demand response by introducing
critical peak pricing. The critical peak pricing is for consumers with a three-phase
connection where up to 21 days a year could be selected with a 24 hours' notice signal.
Table 4: Status quo on time-of-use tariffs in Member States
Tariff elements Number of Member States Member State
Time-of-use tariffs 17
AT, HR, CZ, DK, FI, FR, EE,
GR, IR, LU, LT, MT, PL, PT,
SI, ES, UK
Critical peak pricing 1 FR
“Social tariff element” to
cross-subsidize low income
consumer
5 ES, IT, FR, GR, PT
Source: Copenhagen Economics, VVA Europe (2016) based on Mercados (2015) and Eurelectric
(2013).
Regarding charges applied to distributed generation there is a split picture among Member
States for which data were available. In 8 Member States, distributed generation is subject
to use of system charges while in 6 Member States no charges are applied. There is also
a diverse situation regarding the connection charges that distributed generators have to
pay with a wide variety of charging principles (i.e. shallow, deep, semi-deep or semi-
shallow).
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Table 5: Connection charges and use of system charges for distributed generation in
Member States
Member State Connection Charge Use of system charge
Austria Deep No
Belgium Shallow Yes
Bulgaria Deep N/A
Croatia N/A N/A
Cyprus N/A N/A
Czech Republic Deep N/A
Denmark Shallow Yes
Estonia Deep N/A
Finland N/A Yes
France Semi-deep No
Germany Shallow No
Greece Shallow N/A
Hungary Semi-shallow N/A
Ireland Shallow No
Italy Shallow Yes
Latvia Deep N/A
Lithuania Semi-shallow N/A
Luxembourg N/A Yes
Malta N/A N/A
Netherlands Shallow Yes
Norway Shallow N/A
Poland Shallow N/A
Portugal Deep No
Romania Semi-deep N/A
Slovakia Deep N/A
Slovenia Shallow N/A
Spain Deep No
Sweden Semi-deep Yes
UK Semi-shallow Yes
Source: THINK report "From distribution networks to Smart distribution systems" (2013).
The above data demonstrate a wide variety of distribution tariff structures for consumption
or generation across EU Member States. This wide variety of tariffs can be attributed to a
certain extent to the different local conditions and costs structures in each country;
however, distribution tariffs do not always follow specific principles or they introduce
different diverse conditions for investments for EU consumers who wish to invest in new
technologies including self-generation.
It is widely accepted170
that the developments which are taking place in the distribution
systems such as the integration of vast amounts of variable RES E generation or the
170
See for instance the CEER conclusions paper on "The future role for DSOs" (2015) and the THINK
report "From distribution networks to smart distribution systems: Rethinking the regulation of European
Electricity DSOs" (2013).
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integration of new loads (e.g. heat pumps, electric vehicles), require distribution tariffs
which provide the right economic signals for the use and development of the system,
allocate costs in a fair way amongst system users and provide stability for investments for
DSOs and connected infrastructure.
Regarding remuneration schemes, DSOs across EU are not always encouraged through
appropriate regulatory frameworks to choose the most cost-efficient investments and
innovative network solutions. In many EU Member States the current regulation of DSOs
does not always provide the right incentives to efficiently develop and operate the grid,
and to consider new flexible resources in network planning made possible by distributed
energy resources171
.
Moreover, different approaches are applied on how regulatory frameworks stimulate DSOs
to deploy innovative technologies. According to Eurelectric 172
in the majority of Member
States analysed (13 out of 20), the regulatory framework is either neutral or hampers
innovation and R&D173
in distribution systems.
Deficiencies of the current legislation
The Electricity Directive provides an open framework for NRAs in Member States for
setting distribution network tariffs. The current legislation already provides some
principles on the elements that national regulators should consider when deciding on the
remuneration methodology, the allocation of costs on different system users, tariff
structure etc.
In terms of governance this framework shall continue to exist, as tariff setting is one of the
expertise areas and core tasks of NRAs. However, in the context of the rapid transformation
of the energy system, new generation technologies and new consumption loads will alter
the traditional flows of energy in the system and impact the operation of distribution and
transmission grids. Distribution tariff structures will have to induce an efficient use of the
system, while remuneration schemes have to incentivise DSOs for efficient operation and
planning of their networks. This will require further steps to be taken in EU legislation in
order to create a common basis for the development of a competitive and open retail market
and support the effective integration of RES E generation and new technologies under
equal and fair terms across Member States.
CEER174
and ACER175
recognise that the current regulatory frameworks applied in many
Member States may not fully address the new challenges such as the complex electricity
flows caused by small scale generation. Addressing this kind of challenges through the
171
"From distribution networks to smart distribution systems: Rethinking the regulation of European
Electricity DSOs" (2013) THINK.
172
"Innovation incentives for DSOs – a must in the new energy market development" (2016)
EURELECTRIC.
173
'Research, innovation and competitiveness' has been identified as one of the five dimensions of the
Energy Union strategy (COM(2015) 80 final). In this context, smart grids and smart home technology
are listed in the core priorities in order promote growth and jobs through the energy sector and to create
benefits for the energy consumer.
174
"The future role for DSOs" (2015) CEER.
175
"A Bridge to 2025 Conclusions Paper" (2014) ACER.
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regulatory framework would require the remuneration of innovative investments and the
introduction of the right incentives for flexible solutions which can contribute in solving
short-term and long-term congestions in the distribution grids176
.
While NRAs have enough flexibility in setting distribution tariff structures which best fit
to their local conditions, often there is a lack of important principles which would lead to
a fair allocation of distribution costs amongst system users or the avoidance of implicit
subsidies amongst system users. Moreover, the right long-term economic signals to system
users which would allow for a more rational development of the network are often not in
place.
The diversity of tariff structures is also creating different conditions for system users such
as RES E generators who directly or indirectly through aggregation can participate in the
energy market. Different regulatory frameworks regarding the access conditions including
distribution tariffs of a variety of energy resources which participate in national and cross-
border energy markets could potentially distort competition in the internal energy market
and negatively affect the level of investment in RES E and new technologies.
Therefore, a further clarification of the overarching principles might be necessary
accompanied by measures which ensure the transparency of methodologies used and the
underlying costs. In this context, issues such as fees and tariffs that distributed energy
resources such as storage facilities have to pay would also need to be clarified.
A more detailed guidance to Member States should be decided on the basis of enhancing
further the effectiveness of the distribution network tariff schemes across the EU in order
to incentivise DSOs to raise efficiencies in their networks and to ensure a level playing
field for all system users connected to distribution networks.
Presentation of the options
Distribution tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
Under Option 0 (BAU) distribution tariffs and remuneration for DSOs will continue to be
set according to the current framework and principles set in the Electricity Directive.
Regulatory authorities set or approve distribution tariffs or methodologies in the
framework of the Third Package.
A stronger enforcement and/or voluntary cooperation (Option 0+) has not been considered
as the existing framework does not provide the necessary policy tools and principles for
providing further guidance to Member States, while voluntary cooperation between
Member States could only be used for sharing best-practices.
Under Option 1 in addition to the existing framework, measures on key EU-wide
principles and guidance regarding the remuneration of DSOs, including flexibility services
(e.g. energy storage and demand response) in the cost-base and incentivising efficient
176
The need for incentivising grid operators to enable and use flexibility, but also to improve distribution
tariffs in order to incentivise an efficient consumer response, was widely recognised amongst the
members of the Expert Group 3 (EG3) of the Smart Grids Task Force. The full analysis in included in
the 2015 report "Regulatory Recommendations for the Deployment of Flexibility"
(https://ec.europa.eu/energy/sites/ener/files/documents/EG3%20Final%20-%20January%202015.pdf).
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operation and planning of grids will be put in place. EU-wide principles will also ensure
fair, dynamic, time-dependent distribution tariffs in order to facilitate the integration of
distributed energy resources including storage facilities and self-consumption. Such
principles could be further detailed in an implementing act providing clear guidance to
Member States.
Moreover, DSOs will have to prepare and implement multi-annual development plans, and
coordinate with TSOs on such multi-annual development plans.
NRAs in addition to their existing competences will have to periodically publish a set of
common EU performance indicators that enable the comparison of DSOs performance and
the fairness of distribution tariffs. NRAs will also have to implement more detailed
transparency and comparability requirements for distribution tariffs methodologies.
Measures under Option 2 will aim to fully harmonize remuneration methodologies for all
DSOs at EU level, as well as distribution tariffs (e.g. structures and methodologies). Full
harmonization of tariff structures could include the definition of specific tariff elements
(capacity or energy component, fixed charge etc.), but also specific rules on the allocation
of distribution costs to the different tariff elements.
Comparison of the options
a. The extent to which they would achieve the objectives (effectiveness)
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
The main objective is to achieve distribution tariffs that send accurate price signals to grid
users and aim at a fair allocation of distribution network costs. Regarding remuneration of
DSOs the aim is incentivize DSOs to increase efficiencies in planning and innovative
operation of their networks.
Under Option 0 Member States (NRAs) will continue to set tariffs and remuneration
methodologies according to the framework provided in the Electricity Directive. However,
the current tariff structures and methodologies do not always fulfil the desirable results
under the main objective. The current tariff structure in most Member States does not
sufficiently achieve the economic purpose of network tariffs. For instance tariffs do not
always reflect the costs of the grid from a particular type of behaviour, such as additional
consumption during peak load, or in other instances from beneficial behaviour, such as
charging a storage or electric vehicle to absorb a peak in variable renewable generation. In
several Member States different generation resources face different tariffs, and therefore
create an uneven playing field between resources or between markets (national or cross-
border).
Additionally, Member States are not obliged to provide clear transparency requirements
regarding the costs and methodologies for network tariffs. This creates an information
asymmetry between various players in the market and the risk of not having a clear and
predictable framework.
Therefore, under this option the development of more advanced and transparent
distribution tariff frameworks is left to Member States, facing the risk that some Member
States will not develop the appropriate regulatory framework without clear guidance.
Moreover, it may also lead to various rules and solutions, which risk not dealing with the
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issues of cost reflective use of the grid, or transparent regulatory framework and
appropriate incentives for operators.
Measures under Option 1 aim to enhance the principles of the Electricity Directive for
setting network tariffs in order to provide a clearer guidance to Member States in achieving
the policy objectives. These principles will set a framework for fair, dynamic and time-
dependent tariffs which fairly reflect costs and facilitate the integration of distributed
energy resources.
This option could be more effective if in addition to measures to be included in the
Directive, more specific guidance will be provided to Member States through
implementing legislation. A more detailed guidance would set the framework under which
NRAs can establish fair and cost reflective tariffs and incentivise DSOs to raise efficiencies
in their networks.
Specific transparency requirements are expected to effectively enhance the level of
transparency regarding the underlying costs in tariff setting and the detailed
methodologies.
A full harmonization of distribution tariffs structures and methodologies under Option 2
would require a uniform structure of tariffs across EU distribution networks. This option
is deemed as not effective in capturing different cost structures and various differences in
terms of technical characteristics which determine the final tariff structure. For instance,
the possible definition of specific tariff structures under this option would imply the
introduction of specific rules for the allocation of distribution costs in different tariff
components (e.g. capacity and energy components); however, a uniform tariff structure
could not accurately reflect the different characteristics of individual distribution networks
and support general policy objectives under diverse energy systems.
This option would reduce flexibility for Member States, as specific tariff elements would
be harmonised at EU level. A potential risk of this Option is that NRAs cannot fully design
distribution tariffs tailored to local needs, as they would be bound to a fully harmonized
tariff framework. Another issue with harmonisation is that a "one-size-fit-all" framework
for distribution tariffs might not exist and this would most probably result in various
inefficiencies.
b. Their respective key economic impacts and benefit/cost ratio, cost-effectiveness
(efficiency) & Economic impacts
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
Under Option 1 Member States will be responsible for the detailed implementation of
distribution network tariffs and remuneration for DSOs. A more detailed guidance from
the Commission with EU-wide principles on tariff setting could enhance the benefits of
this option.
The adoption of distribution tariffs by NRAs which are cost-reflective and provide efficient
economic signals to system users will result in lower system costs. Moreover, the
introduction of time-dependent distribution tariffs across all Member States would aim at
incentivising demand response, the detailed implementation should be linked to specific
needs of each distribution system.
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Results of a 2015 study177
show that a well-defined ToU tariff can indeed provide benefits
in terms of CAPEX and OPEX for the distribution grid. The level of impact strongly
depends on the specific characteristics of the grid and of the load/generation conditions.
Measures on transparency in tariff setting and distribution costs would increase the
performance of the agents involved in the tariff setting process resulting in an overall
higher societal benefit.
Option 2 could potentially have similar benefits as Option 1; however, if not well
designed, a fully harmonized framework could have negative impacts in some Member
States or particular distribution systems as one particular tariff methodology could not
accommodate the specificities of different distribution systems.
c. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
d. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
e. Which Option is preferred and why?
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 3.3.1)
Option 1 (both for distribution tariffs and remuneration of DSOs) is the preferred option
as it will improve existing framework and provide to Member States and regulators more
concrete principles and guidance for tariff setting. Multiple benefits are expected for
consumers and resources connected to distribution systems.
Subsidiarity
EU has a shared competence with Member States in the field of energy pursuant to Article
4(1) of the Treaty on the Functioning of the European Union (TFEU). In line with Article
194 of the TFEU, the EU is competent to establish measures to ensure the functioning of
the energy market, ensure security of supply and promote energy efficiency.
Under the energy transition distribution grids will have to integrate even higher amounts
of RES E generation, while new technologies and new consumption loads will be
connected to the distribution grid. Distributed generation has the potential directly or
through aggregation to participate in national and cross-border energy markets. Moreover,
other distributed resources such as demand response or energy storage can participate in
various markets and provide ancillary services to the system also with a cross-border
aspect.
177
"Identifying energy efficiency improvements and saving potential in energy networks, including analysis
of the value of demand response" (2015) Tractebel, Ecofys.
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The access conditions, including distribution tariffs, for suppliers, aggregators, RES E
generation, energy storage etc. shall be transparent and ensure a level playing field. As the
amount of resources such as RES E generation, but in the future also other resources such
as storage, will increase, the conditions under which these resources can access the grid
and participate in the national and cross-border energy markets is expected to become more
relevant.
Putting in place EU-wide principles on remuneration schemes will contribute in lowering
the costs of distribution and support the deployment of flexibility services across the EU.
Incentivising efficient operation and planning of distribution networks will result to an
overall reduction of distribution costs which will facilitate the cost-efficient integration of
distributed generation and support the achievement of EU RES targets. Moreover, through
common principles for incentivising research and innovation in distribution grids, can have
positive for European industry and contribute to employment and growth in the EU.
Distribution tariff issues may affect the development of the internal energy market and
raise concerns over possible discrimination among system users of the same category (e.g.
tariffs applied asymmetrically in border regions). Uncoordinated, fragmented national
policies for distribution tariffs may have indirect negative effects on neighbouring Member
States and distort the internal market, while lack of appropriate incentives for DSOs may
slow down the integration of RES, and the uptake of innovative technologies and energy
services. EU action therefore has significant added value by ensuring a coherent approach
in all Member States.
Stakeholders' opinions
3.2.7.1. Results of the consultation on the new Energy Market Design
As concerns a European approach on distribution tariffs, the results of the public
consultation on a new Energy Market Design178
were mixed; the usefulness of some
general principles is acknowledged by many stakeholders, while others stress that the
concrete design should generally considered to be subject to national regulation.
Distribution tariffs
Question: "Shall there be a European approach to distribution tariffs? If yes, what aspects
should be covered; for example, framework, tariff components (fixed, capacity vs. energy,
timely or locational differentiation) and treatment of own generation?"
Summary of findings:
There are split views among the respondents regarding an EU approach to distribution
network tariffs. Some stakeholders (e.g. part of electricity consumers) believe that some
degree of harmonisation across EU would be beneficial and reduce barriers to cross-border
trade. However, only half of them advocate for a full harmonisation (e.g. specific tariff
structures), while the other half is more in favour of EU wide principles.
178
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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The electricity industry and few Member States are among those who consider that setting
out common principles at EU level is more advisable than a full harmonised framework
for distribution network tariffs.
On the other hand, regulators, the majority of Member States and some electricity
consumers, do not perceive that a "one fits all" solution is appropriate for distribution
network tariffs.
All stakeholders agree that future tariff design should ensure cost efficiency and a fair
distribution of network costs among grid users. The electricity industry supports the
importance of the capacity, time and location tariff components in order to enhance
network price signals and stimulate flexibility.
Member States:
National governments agree that distribution network tariffs should stimulate efficiency
and be cost-reflective, with the possibility to easily adapt to market developments. National
decisions on tariff structure and components are currently related to the division of network
costs among the different system users and to the national distribution system
characteristics (size and structure of the grid, demand profile of consumer, generation mix,
extent of smart metering, approach to distributed generation), as well as to the different
regulatory frameworks (number and roles of DSOs, national or regional distribution
tariffs). Therefore, the majority of Member States consider that no further harmonisation
of distribution tariffs at EU level is required (e.g. France, Sweden, Finland, Malta, Czech
Republic).
Some national governments are however more open to some common approach at EU
level. The Polish government proposes the possibility of continuous exchange of
regulatory experience between NRAs and information on specific tariff parameters. The
Slovak Republic would consider as beneficial a non-binding ACER recommendation on a
methodology for distribution tariffs for NRAs, which should incentivise innovation while
guaranteeing timely recovery of costs of distribution and efficient allocation of distribution
costs. The Danish government suggests that a common framework would increase market
transparency from a retail market perspective and would be a first step to harmonisation.
All national governments consider that any European harmonisation or framework for
distribution tariffs should not preclude the differences in national policies nor prevent
experimental tariff structures aiming at fostering demand side response.
Regulators:
Regulators do not perceive that “one size fits all” approach as appropriate for distribution
tariffs. According to them, future tariff designs need to meet the following objectives:
- To encourage efficient use of network assets;
- To minimize the cost of network expansion;
- To seek a fair distribution of network costs among network users;
- To enhance the security and resilience of existing networks;
- To work as a coherent structure, consistent with other incentives.
Electricity consumers:
Some electricity consumers (BEUC, CEPI) advocate a design of distribution grids tariffs
which encourage flexibility, reflecting the various profiles of demand response operators
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(e.g. ranging from industrial production sites to households running their solar PV unit).
They argue that a differentiated set of price signals would incentivise demand side
flexibility, but that distribution tariffs should comply with EU energy policy and that
regulators should have a common understanding of the reward benefits.
Other electricity consumers (CEFIC, IFIEC) believe that harmonising the tariff
methodology and structure would be beneficial and reduce barriers to cross-border trade.
They support a fair distribution of grid costs between grid users and not leading to cost
inefficiencies, and incentives to operators and system users in order to reduce total costs
of the electricity system.
European Aluminium is in favour of a harmonized methodology for grid tariffs for the
power intensive industry based on the properties and the contribution of the power
consumption profile to the transmission system. Such a tariff system must, however, take
into account national differences in grid system and market liquidity and maturity.
On the other hand, EURACOAL, EUROCHAMBERS and Business Europe disagree with
a harmonization approach because it would not take into account the geographic,
environmental, climate and energy infrastructure differences between Member States.
Energy industry:
Most of the stakeholders agree that an EU full harmonization approach to distribution
tariffs is not advisable, while some common EU principles are a more preferable approach.
In particular, EWEA advocates that the Commission should encourage NRAs in
identifying "best practices" rather than imposing a top down harmonisation of distribution
tariffs.
ESMIG, instead, believes that a more uniform approach across the EU would be beneficial.
A number of the respondents support the importance of the capacity (CEDEC, ENTSO-E,
Eurelectric, ETP, GEODE), time (CEDEC, EASE, ETP, EWEA, GEODE) and location
(CEDEC, ETP, EWEA, ENTSO-E) tariff components in order to enhance the network
price signals and stimulate flexibility.
The energy industry stakeholders consider that network tariffs shall reflect cost-efficiency
and fairness between consumers. They view self-generation as a positive development, but
support that prosumers should contribute to the costs of back-up generation and grid costs
and avoid that other consumers bear the burden of grid costs. In addition, they support that
system charges and other levies linked to policy costs should not artificially increase the
cost of electricity, acting as a bias penalizing consumption.
Network charges should provide DSOs with the required revenue to ensure that sufficient
network investments are realized and especially investments in smart grids and in
operational expenses improvements.
ESMIG advocates for the consideration of a "performance-based" approach, such that the
DSOs remuneration would be based on the performance of the network rather than the
volume of electricity.
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3.2.7.2. Public consultation on the Retail Energy Market
Regarding distribution network tariffs, 34% of the respondents to the 2014 public
consultation on the Retail Energy Market179
consider that European wide principles for
setting distribution network tariffs are needed, while another 34% are neutral and 26%
disagree.
Time-differentiated tariffs are supported by ca 61% of the respondents, while the majority
of stakeholders consider that cost breakdown (78%) and methodology (84%) of
distribution network tariffs should be transparent.
The majority of stakeholders also consider that self-generators/auto-consumers should
contribute to the network costs even if they use the network in a limited way. To this end,
ca 50% of the respondents consider that the further deployment of self-generation with
auto-consumption requires a common approach as far as the contribution to network costs
is concerned.
3.2.7.3. Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31st
EU Electricity Regulatory Forum:
- "The Forum stresses the importance of innovative solutions and active system
management in distribution systems in order to avoid costly investments and raise
efficiencies in system operation. It highlights the need for DSOs to be able to
purchase flexibility services for operation of their systems whilst remaining neutral
market facilitators, as well as the need to further consider the design of distribution
network tariffs to provide appropriate incentives. The Forum encourages
regulators, TSOs and DSOs to work together towards the development of such
solutions as well as to share best practices."
European Parliament resolution of 26 May 2016 on delivering a new deal for energy
consumers (2015/2323(INI)):
"24. Calls for stable, sufficient and cost-effective remuneration schemes to guarantee
investor certainty and increase the take-up of small and medium-scale renewable energy
projects while minimising market distortions; calls, in this context, on Member States to
make full use of de minimis exemptions foreseen by the 2014 state aid guidelines; believes
that grid tariffs and other fees should be transparent and non-discriminatory and should
fairly reflect the impact of the consumer on the grid, avoiding double-charging while
guaranteeing sufficient funding for the maintenance and development of distribution
grids; regrets the retroactive changes to renewable support schemes, as well as the
introduction of unfair and punitive taxes or fees which hinder the continued expansion of
self-generation; highlights the importance of well-designed and future-proof support
schemes in order to increase investor certainty and value for money, and to avoid such
changes in the future; stresses that prosumers providing the grid with storage capacities
should be rewarded;"
179
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
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3.4. Improving the institutional framework
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Summary Table
Objective: To adapt the Institutional Framework, in particular ACER's decision-making powers and internal decision-making to the reality of integrated regional markets and the proposals of
the Market Design Initiative, as well as to address the existing and anticipated regulatory gaps in the energy market.
Option 0 Option 1 Option 2
Description
Maintain status quo, taking into account that the implementation
of network codes would bring certain small scale adjustments.
However, the EU institutional framework would continue to be
based on the complementarity of regulation at national and EU-
level.
Adapting the institutional framework to the new
realities of the electricity system and to the
resulting need for additional regional cooperation
as well as to addressing existing and anticipated
regulatory gaps in the energy market.
Providing for more centralised institutional structures with
additional powers and/or responsibilities for the involved
entities.
Pros
Lowest political resistance. Addresses the shortcomings identified and
provides a pragmatic and flexible approach by
combining bottom-up initiatives and top-down
steering of the regulatory oversight.
Addresses the shortcomings identified with limited
coordination requirements for institutional actors.
Cons
The implementation of the Third Package and network codes is
not sufficient to overcome existing shortcomings of the
institutional framework.
Requires strong coordination efforts between all
involved institutional actors.
Significant changes to established institutional processes with
the greatest financial impact and highest political resistance.
Most suitable option(s): Option 1, as it adapts the institutional framework to the new realities of the electricity system by adopting a pragmatic approach in combining bottom-up initiatives
and top-down steering of the regulatory oversight.
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Description of the baseline
The institutional framework currently applicable to the internal energy market is laid out
in the Third Package. It strengthened the powers and independence of national regulatory
authorities (NRAs) and mandated the creation of an Agency for the Cooperation of Energy
Regulators (ACER) and the European Networks of Transmission System Operators
(ENTSOs)180
, with the overarching aim of fostering cooperation amongst NRAs as well as
between transmission system operators (TSOs) at regional and European level.
Figure 1 below illustrates the key actors in the energy market based on the institutional
framework introduced with the adoption of the Third Package.
Figure 1: Key actors in the energy market institutional framework
Source: European Commission
With the creation of ACER, the Third Package sought to cover the regulatory gap
concerning electricity and gas cross-border issues. Prior to the adoption of the Third
Package, this regulatory gap had been tackled with the Commission self-regulatory forums
like the Florence (electricity) forum and the Madrid (gas) forum as well as through the
180
As the current Impact Assessment and the related legislative proposals focus on the European electricity
markets, this Annex focuses on the assessment of the options with regard to the ENTSO for Electricity
(ENTSO-E).
European
Commission
Agency for the Cooperation of
Energy Regulators
(ACER)
European Networks for
Transmission System Operators
for Electricity and for Gas
(ENTSO-E and ENTSOG)
Council of
Ministers
European
Parliament
National regulatory
authorities (NRAs)
Transmission
system operators
(TSOs)
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independent regulatory advisory group on electricity and gas set up by the Commission in
2003, the "European Regulators Group for Electricity and Gas" (ERGEG). ERGEG's
work positively contributed to market integration. However, it was widely recognised by
the sector – and by ERGEG itself – that cooperation between NRAs should be upgraded
and should take place within an EU body with clear competences and with the power to
adopt regulatory decisions.
To this end, the Third Package entrusted ACER with a wide range of tasks and
competences, including:
- promoting cooperation between NRAs;
- participating in the development and implementation of EU-wide network rules
(network codes and guidelines);
- monitoring the implementation of EU-wide 10-year network development plans;
- deciding on cross-border issues if national regulators cannot agree or if they jointly
request ACER to intervene;
- monitoring the functioning of the internal market in electricity and gas; and
- oversight over ENTSOs.
Based on the adoption of subsequent legislation on market transparency181
and trans-
European infrastructures182
ACER has been given additional responsibilities in these areas.
The Third Package established ACER with the main mission to ensure that regulatory
functions performed by NRAs at national level are properly coordinated at EU level and,
where necessary, completed at EU level. As regards its governance structure183
, ACER
comprises a Director, responsible for representing the Agency, for the day-to-day
management and for tabling proposals for the favourable opinion of the Board of
Regulators184
. ACER's regulatory activities are formed in the Board of Regulators,
composed of senior representatives of the NRAs of the 28 Member States. Its
administrative and budgetary activities fall under the supervision of an Administrative
Board, whose members are appointed by European Institutions. The Board of Appeal is
part of the Agency but independent from its administrative and regulatory structures, and
deals with complaints lodged against ACER decisions185
. As regards the internal decision-
making, ACER decisions on regulatory issues (e.g. opinion on network codes) require the
favourable opinion of the Board of Regulators, which decides with two-thirds majority.
In relation to the creation of ENTSOs, the Third Package sought to enhance effective
cooperation among TSOs in order to address the shortcomings and limitations shown by
181
Regulation EU No 1227/2011 on Wholesale Energy Market Integrity and Transparency – REMIT; OJ
L 326, 8.12.2011, p.1
182
Regulation (EU) No 347/2013 on guidelines for trans-European energy infrastructure (TEN-E
Regulation).
183
See Article 3 of the ACER Regulation and related provisions.
184
Under Articles 5, 6, 7, 8 and 9 of the ACER Regulation.
185
The ACER Board of Appeal takes its decisions with qualified majority of at least four of its six members;
it convenes when necessary; its members are independent in their decisions; some of its costs are
envisaged in the ACER budget.
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the voluntary initiatives adopted by TSOs (the European Transmission System Operators
and Gas Transmission Europe). As a result, the Third Package tasked the ENTSOs with
EU-level functions such as contributing to the development of EU-wide network rules,
developing the 10-year network development plan and carrying out seasonal resource
adequacy assessments.
The establishment of ACER and the ENTSOs in order to enhance the cooperation among
NRAs and TSOs from 28 different Member States has undoubtedly been successful. Both
ACER and the ENTSOs are important partners in discussions on regulatory issues. Further,
the Third Package established a framwork for the ACER oversight of ENTSO-E, tasking
ACER e.g. with providing opinions on ENTSO-E's founding documents, on the network
code and network planning documents developed by ENTSO-E. In addition, the Agency
has the obligation to monitor the execution of the tasks of ENTSO-E186
.
As regards its financing, ACER benefits from a Union subsidy set aside specifically in the
general budget of the European Union, like most EU decentralised agencies. In addition,
ACER can collect fees for individual decisions187
.
Network Codes and Guidelines
The Third Package has set out a framework for developing network codes with a view to
harmonising, where necessary, the technical, operational and market rules governing the
electricity and gas grids. Under this framework, ACER, the ENTSOs and the European
Commission have a key role and need to work in close cooperation with all relevant
stakeholders on the development of network codes. The areas in which network codes can
be developed188
are set out in Article 8(6) of the Electricity Regulation and of the Gas
Regulation. Once adopted, these network codes become binding Commission Regulations,
directly applicable in all Member States.
The network code process is defined in Articles 6 and 8 of the Electricity and the Gas
Regulations and it can be essentially divided in two phases: (i) the development phase; and
(ii) the adoption phase.
Figure 2 below illustrates the main stages of the network code development phase. It is
important to note that during each of these stages, the Commission, ACER and the
ENTSOs consult the proposals with stakeholders189
.
186
Art. 6 of ACER Regulation.
187
Art. 22 of ACER Regulation. However, the fee has to be set by the European Commission, which did
not take place yet.
188
E.g., network connection, third party access, interoperability capacity allocation and congestion
management rules, etc.
189
These stakeholder consultations are not always required. For example, consultation is a requirement as
regards the preparation of the annual priority list (see Art. 6(1) Electricity Reg.) and the preparation of
the framework guidelines (Art. 6(3) Electricity Reg.). During the preparation of the network codes, the
ENTSOs have carried out stakeholder workshops, although this is not formally required in the Electricity
or Gas Regulations. In addition, the Agency may consult with stakeholders during the 3 months period
for revision of the ENTSO proposal and the preparation of the reasoned opinion (Art. 6(7) Electricity
Reg.).
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Figure 2: Main stages of the network code development process
Source: ACER
Once ACER submits a network code to the Commission recommending its adoption, the
Commission starts the adoption phase ("Commission adoption phase"), illustrated in
Figure 3190
.
190
Network codes are adopted according to Art. 5a (1) to (4) of Decision 1999/468/EC ("regulatory
procedure with scrutiny"), which requires a positive vote by a qualified majority of Member States and
agreement from Council and Parliament.
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Figure 3: Network code adoption phase
Source: unknown
The European Commission has also the possibility to develop "guidelines" which,
similarly to network codes, form legally binding Commission Regulations. The guidelines
have a different legal basis and follow a different development process191
, under which
there is no formal role for ACER or ENTSO-E, while their adoption phase is the same as
for the network codes.
Once adopted, network codes and guidelines are both acts implementing the Electricity
and the Gas Regulations. There is no difference as concerns their legally binding effects
and direct applicability.
Deficiencies of the current legislation
The Third Package institutional framework aims at fostering the cooperation of NRAs as
well as between TSOs. Since their establishment, ACER and the ENTSOs have played a
key role in the progress towards a functioning internal energy market. In 2014, the
Commission undertook its first evaluation of the activities of the Agency192
and concluded
that ACER has become a credible and respected institution playing a prominent role in the
EU regulatory field while focusing on the right priorities193
. Also, according to ACER194
,
191
The areas in which guidelines can be developed are set out in Art. 18 (1), (2), (3) Electricity Regulation
and Art. 23 (1) Gas Regulation.
192
In line with Art. 34 ACER Regulation. The Commission prepared this evaluation with the assistance of
an independent external expert and including a public consultation. The evaluation covered the results
achieved by the Agency and its working methods.
193
"Commission evaluation of the activities of the Agency for the Cooperation of Energy Regulators under
Article 34 of Regulation (EC) 713/2009" (22. 1. 2014), European Commission,
https://ec.europa.eu/energy/sites/ener/files/documents/20140122_acer_com_evaluation.pdf
194
"Energy Regulation: A Bridge to 2025 Conclusions Paper" (19 September 2014) ACER Report.
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both ENTSOs have achieved a good level of performance since their establishment by the
Third Package.
However, the recent developments in the European energy markets that the current Impact
Assessment reflects upon and the related proposals of the Market Design Initiative require
the adaptation of the institutional framwork. In addition, the implementation of the Third
Package has also highlighted areas with room for improvement concerning the framework
applicable to ACER and the ENTSOs.
The Agency has limited decision-making powers, as it acts primarily through
recommendations and opinions. With the integration of the European electricity markets
more and more cross-border decisions will be necessary (e.g. market coupling). Such
decisions however require a strong regulatory framework, for which a fragmented national
regulatory approach has proved to be insufficient195
. Ultimately this fragmented regulatory
oversight might constitute a barrier to the integration of the energy markets196
. In this
regard, there is consensus among market parties and stakeholders that ACER should indeed
be enabled to more efficiently deal with cross-border issues197
and to take decisions198
.
Moreover, as European energy markets are more and more integrated, it is crucial to ensure
that ACER can function as swiftly and as efficiently as possible. As most of the regulatory
decisions require the favourable opinion of the Board of Regulators, it is equally relevant
that the NRAs represented in the Board of Regulators can find agreements swiftly and
efficiently, which in the past was not always the case, leading to delays or to a situation
195
The existing competences of ACER for taking decisions set out in the ACER Regulation do not include
the implementation of network codes and guidelines. Many trading or grid operation methods to be
developed under network codes or guidelines require common EU-wide decisions or regional decisions.
Given that ACER does not have competence to take EU-wide or regional decisions relating to network
codes and guidelines, currently NRAs have to decide unanimously on the adoption of identical legal acts
in all national legal systems within a six-month period. This renders the implementation of network
codes and guidelines complex and inefficient.
196
"Energy Union. Key Decisions for the Realisation of a Fully Integrated Energy Market" (2016), Study
for the Committee for Industry, Research and Energy of the European Parliament: "In several regional
or EU-level projects (e.g. market coupling projects, see our case study in Annex 3) national authorities,
TSOs, regulators and energy exchanges of different Member States need to cooperate. However, as they
are primarily responsible for their own national gas and electricity system and market they are not
always sufficiently motivated to also take supranational interests into account. […] This leads to
complex and slow decisional and implementation processes for most cross-border projects, resulting in
delayed implementations (e.g. the intra-day markets’ coupling project)." In this context, different
stakeholders argue for stronger governance at EU level. For example, EPEX Spot states the need to
accompany the electricity EU target model by appropriate governance architecture at European level,
applicable on market coupling activities, which will be crucial to ensure an efficient day-to-day operation
of such complex mechanisms.
197
"Energy Union. Key Decisions for the Realisation of a Fully Integrated Energy Market" (2016), Study
for the Committee for Industry, Research and Energy of the European Parliament.
198
For instance, the Third Package does not define a regional regulatory framework beyond the generic
reference to the need for NRAs to cooperate at regional level supported by ACER, which would be
necessary to ensure proper oversight of regional entities or functions.
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where the sufficient majority could not be reached, making it impossible for ACER to fulfil
its role.
As mentioned in Section 2 above, the Third Package introduced network codes as tools for
developing EU-wide technical, operational and market rules. While this process has proved
very sucessful overall, the practice of the last 5 years has highlighted the existence of
structural insufficiences. As an example, ENTSO-E plays a central role in developing EU-
wide market rules. Therefore, the rules on its independence and transparency have to be
strong and have to be accompanied by appropriate oversight rules to ensure the transparent
and efficient functioning of the organisation. The reinforcement of these rules was also
strongly requested by a high number of stakeholders in the Commission's public
consultation on the market design initiative. Some stakeholders have mentioned that there
is a possible conflict of interest in ENTSO-E’s role – being at the same time an association
called to represent the public interest involved e.g., in network code drafting, and a lobby
organisation for TSOs with own commercial interests – and requested the adoption of
measures to address this conflict199
.
The Third Package also includes elements of oversight of ENTSO-E by ACER. However,
given the strong role ENTSO-E plays as a technical expert body, in particular in the
development and implementation of network codes and guidelines, ACER's oversight has
proved to be insufficient, for example as regards ENTSO-E's statutory documents or as
regards the delivery of data to the Agency200
. Moreover, the emergence of new entities and
functions of EU-level or regional relevance through the adoption of network codes and
guidelines has further enlarged this oversight gap. This is, for example, the case with the
nominated electricity market operators ('NEMOs'), the market coupling operator ('MCO')
function, which will together be responsible for performing cross-border day-ahead and
intraday trading, a role created under the CACM Guideline, and regional security
coordinators ('RSCs') in electricity. The creation of these new entities and functions has
not been accompanied by tailored regulatory oversight.
The ACER Board of Appeal has a crucial function in safeguarding the validity of the
Agency's decisions. Even though the Board of Appeals has been called upon only in a very
limited number of times since the establishment, it has proved that its independence is
crucial. Experience shows that its functioning and financing must be reaffirmed to ensure
its full independence and efficiency.
Like most of the EU decentralised agencies, ACER benefits from a Union subsidy set aside
specifically in the general budget of the European Union. As explained in Section 2, ACER
has been tasked with additional functions since its establishment. These tasks have been
199
For example by Eurelectric, EFET, CEDEC, Europex. This issue was also raised among the observations
of the European Court of Auditors in its report "Improving the security of energy supply by developing
the internal energy market: more efforts needed" (2015), which stated: "This is problematic because,
although the ENTSOs are European bodies with roles for the development of the internal energy market,
they also represent the interests of their individual members."
200
ACER exerts limited oversight (opinion on status, list of members and rules of procedures as per Art. 5
of the Electricity Regulation and monitoring of ENTSO-E’s tasks as per Art. 9 of the Electricity
Regulation.
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accompanied with additional staff. However, ACER is also subject to the programmed
reduction of staff in decentralised agencies by 5% over a period of 5 year set out in the
Commission's communication on "Programming of human and financial resources for
decentralised agencies 2014-2020"201
. It is clear that any additional tasks for ACER as
envisaged in the proposed initiatives will further tighten its financing and staffing and will
require further resources.
Another set of shortcomings can be tracked to insufficient participation of DSOs within
the institutional framework. Under the energy transition, a traditional top-down,
centralised electricity distribution system is being outpaced by more decentralised
generation and consumption. The integration of a significant share of variable solar and
wind generation capacity connected directly to distribution networks create new
requirements and possibilities for DSOs, who will have to deal with increased capacity
while maintaining quality of service and minimizing network costs. In addition, the
electrification of sectors such as transport and heating will introduce new loads in
distribution networks and will require a more active operation and better planning.
The problem is aggravated by the fact that specific requirements on TSO – DSO
cooperation as set forth in the different Network Codes and Guidelines, and new challenges
that TSOs and DSOs are jointly facing, will require greater coordination between system
operators.
For the time being, no provision at all is made for the formal integration of DSOs into the
EU institutional decision making. However, from a policy perspective a cohesive and
consistent participation of DSOs in the EU institutional framework is required. Future
electricity system will require a more coordinated approach of TSOs and DSOs on issues
of mutual concern. Regarding network codes, DSOs will need to display a common
approach, as many of the envisaged network codes are directly or indirectly concern
distribution grids.
As set out in the evaluation report202
, while the principles of the Third Package achieved
its main purposes, new developments in electricity markets led to significant changes in
the market functioning in the last five years. The existing rules defining the institutional
framework are not fully adapted to deal with the recent changes in electricity markets
effectively. Therefore, it is reasonable to update these rules so that they may be able to cope
with the reality of today's energy system.
The institutional framework currently applicable to the internal energy market as set out in
the Third Package is based on the complementarity of regulation at national and EU-wide
level. In view of the developments since the adoption of the Third Package as described in
the evaluation report, the institutional framework, especially as regards cooperation of
NRAs at regional level, will need to be adapted to ensure the oversight of entities with
regional relevance. Moreover, as the European energy markets are more and more
201
Communication from the Commission to the European Parliament and the Council, COM(2013)519
final of 10.07.2013.
202
Evaluation Report covering the evaluation of the EU's regulatory framework for electricity market
design and consumer protection in the fields of electricity and gas and evaluation of the EU rules on
measures to safeguard security of electricity supply and infrastructure investment (Directive 2005/89).
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integrated, it is crucial to ensure that ACER can function as swiftly and as efficiently as
possible. In addition, the implementation of the Third Package has highlighted areas with
room for improvement concerning the framework applicable to ACER and the ENTSOs.
Presentation of the options
Option 0: Business as usual
The business as usual (BAU) option does not foresee new, additional measures to adapt or
improve the institutional framework. Apart from the continued implementation of the
Third Package and the implementation of network codes and guidelines, this option would
leave the EU institutional framework unchanged, meaning that it would continue to be
primarily based on a close complementarity of regulation at national and EU-wide level.
The challenges arising through the changes to and the stronger integration of the European
energy markets could not be tackled and regulatory gaps arising from the adoption and
implementation of network codes and guidelines would also remain unaddressed. This
could potentially lead to delays in their implementation and ultimately act as a barrier to
achieving the electricity EU target model.
The BAU option would maintain the limitation of ACER's decision-making powers and
would not remedy the risks arising from the fragmented national regulatory approach.
NRAs and ACER would continue to face difficulties fulfilling their tasks that have
relevance at regional and EU level.
The business as usual option would leave ACER's current internal decision-making
unchanged. This would mean that where the favourable opinion of the Board of Regulators
is necessary, this would have to be reached with two-thirds majority facing the risk of
delays or lack of agreement.
Under this option the process of developing network codes would remain unchanged. This
would allow ENTSO-E to continue playing a very strong role in setting European market
rules, going beyond of that providing technical expertise. This option would neither
improve the rules on ENTSO-E's transparency and independence nor the rules of ACER's
oversight of ENTSO-E. The progress concerning ENTSO-E's transparency would depend
on the voluntary initiative of the association. The criticisms to the existence of conflicts of
interest regarding the roles of ENTSO-E, particularly as regards the development of
network codes, would not be addressed.
Under the Option business as usual, despite having been assigned additional
responsibilities since its establishment, ACER would still be constrained by the current
regulatory framework as regards the regulatory oversight of new entities and functions
performing at regional or EU level.
This Option would maintain the current framework for the functioning of ACER's Board
of Appeal. This means that its independent functioning and financing would continue to
be highly vulnerable.
The BAU also foresees no integration of DSOs into the institutional decision-making
setting as explained under the Section dealing with the shortcomings of current legislation.
It is true that in 2015, with the support of the Commission, the four European DSO
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associations and ENTSO-E established a cooperation platform203
between TSOs and DSOs
at EU level. This cooperation has the objective to work on issues of mutual DSO-TSO
concern such as coordinated access to resources, regulatory stability, grid visibility and
grid data. However, this cooperation remains purely voluntary in nature with no formal
expression in the wider EU decision making setting or ACER.
In sum, European DSOs collaborate through the existing DSO associations but without
any legal status at EU institutional level. There is no formal participation in drafting or
amending of network codes and guidelines.
Option 0+: Non-regulatory approach
Under this option a "stronger enforcement" approach and voluntary collaboration as a non-
legislative measure were considered without foreseeing any new, additional measures to
adapt the institutional framework. Improved enforcement of existing legislation would
entail the continued implementation of the Third Package and the implementation of
network codes and guidelines – as described under option business as usual – combined
with stronger enforcement. However, stronger enforcement would not provide any
improvement to the current institutional framework as it is already fully implementing the
existing legal framework.
Collaboration in the current institutional framework is based on legal obligation. While
voluntary cooperation might be possible in areas not covered under the Thrid Energy
Package, it would require establishing parallel structures and additional resources without
significantly improving the functioning of the current regulatory framework. Therefore,
voluntary collaboration is not considered a valid option.
Therefore, the Option 0+ would leave the EU institutional framework unchanged, meaning
that it would continue to be based, primarily, on a close complementarity of regulation at
national and EU-wide levels. Furthermore, any improvement compared to the current
situation would have to stem from voluntary initiatives of the involved bodies. In addition,
this option could not provide the necessary solutions arising from the changing market
reality as described in this impact assessment. Therefore, this option is discarded as not
valuable in providing solutions for the described shortcomings and overall developments.
Option 1: Upgrade the EU institutional framework
Option 1 foresees adapting the EU institutional framework to the new realities of the
electricity system204
and to the resulting need for additional regional cooperation and to
address the existing and anticipated regulatory gaps in the energy market, providing
thereby for flexibility by a combination of bottom-up and top-down approaches. Option 1
would adapt the institutional framework set out in the Third Package to address the
regulatory gaps materialising through the implementation of the Third Package and
resulting from the adoption and implementation of network codes and guidelines. It would
203
ENTSO-E, CEDEC, GEODE, EDSO, EURELECTRIC (2015), "General Guidelines for reinforcing the
cooperation between TSOs and DSOs" (http://www.eurelectric.org/media/237587/1109_entso-
e_pp_tso-dso_web-2015-030-0569-01-e.pdf)
204
As further detailed in Section 1 of the main body of this impact assessment.
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also adapt the institutional framework to the new realities of the electricity system and to
the resulting need for additional regional cooperation.
As regards ACER’s decision-making, Option 1 would largely entail reinforcing its powers
to carry out regulatory functions at EU level. In addition, in order to address the existing
regulatory gap as regards NRAs' regulatory functions at regional level, the policy
initiatives under this option would set out a flexible regional regulatory framework to
enhance the regional coordination and decision-making of NRAs. This Option would
introduce a system of coordinated regional decisions and oversight for certain topics by
NRAs of the region (e.g. ROCs and others deriving from the proposed market design
initiatives) and would give ACER a role for safeguarding the EU-interest.
Option 1, while giving ACER additional powers, would also ensure that the Agency can
swiftly and effectively reach these decisions in its Board of Regulators. To enable NRAs
to take decisions without delay in the BoR, this Option would adapt the BoR internal voting
rights. Option 1 also reflects on the necessity to ensure that all (existing and proposed)
ACER decisions are subject to appeal and that the ACER Board of Appeal can act fully
independently and effectively through adjusting its financing and internal rules.
Further, concerning ACER's competences, Option 1 entails strengthening ACER's role in
the development of network codes, particularly as regards giving the Agency more
responsibility in elaborating and submitting the final draft of the network code to the
Commission, while maintaining ENTSO-E's relevant role as a technical expert. This
Option would also involve strengthening ACER's oversight over ENTSO-E. In addition,
Option 1 would effectively distinguish ENTSO-E’s statutory mandate from defending its
member companies' interests by setting out a clear European mandate in the legislation and
ensuring more transparency in its decision-making processes.
Under this Option, ACER would receive additional competence to oversee new entities
and functions which are not currently subject to regulatory oversight at EU level. This is
the case for power exchanges operating in their cross-border functions; they play a crucial
role in coupled European electricity markets and perform functions that have
characteristics of a natural monopoly. Depending on the type of entity or function and their
geographical scope, this Option would either introduce NRAs’ coordinated regional
oversight with support and monitoring by ACER or ACER oversight with NRAs’
contribution.
As described in this Section, Option 1 would give ACER additional tasks and powers while
acknowledging that appropriate financing and staffing is key for ACER to perform its role.
Therefore, Option 1 foresees additional sources of financing which would be possible
either by increasing the EU financing or by introducing co-financing, complementary to
the Union financing the sector ACER is supervising205
.
205
The Commission’s aim for decentralised agencies is to eliminate EU and national budgetary
contributions and wholly finance them by the sector they supervise, see the Mission letter of
Commissioner Hill of 1 November 2014. In this sense ACER could be co-financed through the sector it
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This Option would also include a formal place for DSOs to be represented at EU level, in
line with an increase in their formal market responsibilities and role as has been mentioned
above. The establishment of an EU DSO entity will enable the development of new policies
which can positively affect the cost efficient integration of distributed energy resources
including RES E, and which will reinforce the representation and participation of EU DSOs
at an institutional European level.
Option 1 thus envisages the establishment of an EU DSO entity for electricity with an
efficient working structure. European DSOs will provide experts based on calls for
proposals issued by the EU-DSO. European DSOs will participate in financing the EU-
DSO entity through a Supporting Board based on the existing EU DSO associations
(Eurelectric, EDSO, CEDEC, GEODE).
Tasks of the EU DSO will include:
- Drafting network codes/guidelines following the existing procedures;
- Monitor the implementation of network codes on areas which concern DSOs;
- Deliver expert opinions as requested by the Commission;
- Cooperate with ENTSO-E on issues of mutual concern, such as data
management, balancing, planning, congestion, etc.
The EU DSO entity will also work on areas such as DSO/TSO cooperation, integration of
RES, deployment of smart grids, demand response, digitalisation and cybersecurity.
Option 2: Restructure the EU institutional framework
Option 2 would significantly restructure the institutional framework, going beyond
addressing the regulatory gaps identified above and moving towards more centralised
institutional structures with additional powers and responsibilities at European level,
particularly as regards the role of ACER and ENTSO-E.
Concerning ACER's powers, Option 2 would extend ACER's decision-making powers to
all regulatory issues with cross-border trade relevance. This would result in ACER taking
over most NRA responsibilities directly or indirectly related to cross-border and EU-level
issues. This Option would further give the ACER Director the power to become the main
decision-making instance in the Agency, as opposed to the BoR, possibly with veto powers
from the Board of Regulators on certain measures.
As regards ACER's competences, Option 2 would entail a direct oversight over ENTSO-E
and over other entities fulfilling EU level or regional functions, giving ACER the power
to take binding decisions.
In order for ACER to perform its role under Option 2, it would require a significant
reinforcement of ACER's budget and staff as this would make a strong concentration of
is supervising. In the light of ACER’s cruacial role in delivering on the common EU objectives and in
particular in protecting the Eurpean energy markets from fraud, the functioning of ACER could be co-
financed with contributions from market participants and/or public bodies benefitting from ACER’s
activities. This would contribute to guaranteeing ACER's full autonomy and independence.
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experts in ACER necessary. Therefore, this option would entail – as foreseen under Option
1 – reinforcing EU funding and the possibility to introduce in addition financing through
market players and/or public bodies. As Option 2 would give ACER such strong powers it
would also entail a significant reinforcement of the structural set-up of the Board of Appeal
to ensure that the appeal mechanism can function independently and effectively because it
would potentially face a significantly higher number of appeals due to the increasing
number of direct ACER decisions foreseen under this Option.
As regards to ENTSO-E's competences, this option would require a formal separation of
ENTSO-E from its members' interest. It would strengthen the independence of ENTSO-E
by introducing a European level decision-making body who would have powers to decide
on proposals and initiatives without requiring prior TSOs' approval.
With regards to the role of DSOs, the measures included under Option 1 would apply to
Option 2 as well. The move to an EU regulator with full powers would however mean that
ACER would have to also carry out the oversight of, and entertain relations with, DSOs in
a way that is now done at Member State level.
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Table 2: Detailed overview of the measures proposed under the three options
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ISSUE Option 0: Business as
usual
Option 1: Ugrade EU
insitutional framework to
address regulatory gaps
Option 2:
Restructur EU
institutional
framework
ACER decision-
making
Limited, through
recommendations and
opinions
Most regulatory decisions
with BoR favourable
opinion
ACER Director manages
ACER and tables
proposals for BoR
favourable opinion
ACER decisions with BoR
favourable opinion, also
replacing Guideline
implementing “all NRA”
decisions at EU and regional
levels
Framework of regional NRA
decision-making with ACER
oversight (complementary
role to safeguard EU interest)
ACER decision
without BoR
involvement, mainly
by ACER Director
BoR decision-
making
2/3rds
majority for the most
of ACER decisions
Simple majority for most of
ACER decisions
2/3rds
majority for
ACER decisions in a
limited instances
Board of Appeal Independent body for all
appeal cases
Some of its costs are
envisaged in the ACER
budget
Independent body for all
appeal cases with strengthend
framework and separate
budget line in the ACER
budget
Independent body for
all appeal cases with
strengthend line of
financing and
framework
ACER Financing Community/EU-funding
(separate budget line)
Possibility for ACER to
collect fees for individual
decisions
Need for increased financing
(possibly through increased
EU-funding and possibly co-
financing by contributions by
market participants and/or
national public authorities
Need for significantly
increased financing
(possibly through
increased EU-funding
and possibly co-
financing by
contributions by
market participants
and/or national public
authorities
Network Code
development
process
Based on ACER’s
framework guideline
ENTSO-E drafts network
code (strong role and
influence), ACER
provides opinion and
recommendation to the
Commission.
Based on ACER’s
framework guideline
ENTSO-E drafts network
code guided by a standing
stakeholder body and broad
general stakeholder
involvement, ACER
consolidates the network
code and submites the final
product to the Commission
Based on ACER’s
framework guideline
ENTSO-E drafts
network code with the
involvement of
standing stakeholder
body, ACER
consolidates the
network code (ACER
internal decision
without Board of
Regulators'
favourable opinion)
and submites the final
product to the
Commission
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Oversight of
ENTSO-E
Limited ACER oversight
of ENTSO-E
Strenghtened ACER
oversight of ENTSO-E
Strenghtened ACER
oversight of ENTSO-
E
Oversight of new
entities
None or limited regulatory
oversight (limited rules in
network codes and
guidelines)
Strenghtened regulatory
oversight by NRAs and
ACER
ACER direct
oversight
ENTSO-E’s
mission and
transparency
Lack of clear European
mission and voluntary
transparency rules
Codified clear European
mission and transparency
obligations on its decision-
making
Formal separation
from its members'
interests and creation
of a decision-making
body
DSO European DSOs
collaborate through the
existing DSO associations
but without any legal
status at EU institutional
level. There is no formal
participation in drafting or
amending of network
codes and guidelines
Establishment of an EU DSO
entity for electricity with an
efficient working structure;
European DSOs will provide
experts based on calls for
proposals issued by the EU-
DSO.
Same as Option 1,
plus an increased role
for coordination and
oversight on the part
of ACER
Source: European Commission
Comparison of the options
As stated above, the goal of the proposed initiatives is to adapt the institutional framework
to the reality of integrated regional markets. In this regard, as it will be further illustrated
below, Option 0, the business as usual option, would not contribute towards achieving this
objective and in some instances it may even be detrimental, since the institutional
framework needs to be able to provide tools for the different parties (ACER, NRAs,
ENTSO-E) to address the challenges arising from the integration of the markets.
Options 1 and 2 can capture the challenges and potential opportunities, but the efficiency,
effectiveness and economic impact of these options can vary significantly.
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Table 3: Qualitative comparison of Options in terms of their effectiveness, efficiency
and coherence of responding to specific criteria
Criteria Option 0:
Business as usual
Option 1:
Upgrade EU institutional
framework addressing
regulatory gaps
Option 2:
Restructure EU
institutional framework
Quality 0
Progress remains
limited and primarily
voluntary
+
Using expertise from
established actors
+
Efficient through limited
coordination requirements
Speed of
implemen-
tation
-
Slow, primarily
voluntary progress
0/+
Building upon established
structures
-
Delays resulting from
changed structure
Use of
established
institutional
processes
-
Efficiency of
established processses
limited.
++
Can build upon established
structures
-
Requires building up new
structures/processes
Efficient
organisational
structure
0
Existence of insufficient
rules and regualtory
gaps for organisation
++
Efficient organisational
structure can be created;
using expertise from
established actors further
improving it
+
Efficient because of limited
coordination requirements
Involvement
of
stakeholders
0
Process in the hands of
the main actors
+
Rules for effective,
reinforeced involvement
+
Rules for effective,
reinforced involvement
Source: European Commission.
The assumptions in this table are based on the feedback received from stakeholders in their response
to the public consultation and from additional submissions from ACER.
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Table 4: Qualitative estimate of the economic impact of the Options
Economic Impact
Internal
Market for
electricity
Transparency
and non-
discrimination
Administrative
impact and
implementation
costs
Option 0: Business as usual 0/+ - 0
Option 1: Upgrading EU institutional framework + + 0/-
Option 2: Restructuring EU institutional
framework
++ ++ --
Source: European Commission
The assumptions in this table are based on the feedback received from stakeholders in their response to the
public consultation and from estimations concerning the resources of ACER and ENTSO-E.
In summary, Option 0 – business as usual – will fall short in providing for an institutional
framework that can underpin the integration of the internal electricity market in a timely
manner.
Option 1, addressing regulatory gaps by upgrading the EU institutional framework would
be, according to the assessment of the options above, the most appropriate measure for
establishing an EU institutional framework that reflects and complements the increasingly
integrated and regional dimension of the electricity market. This option is favoured by
most of the stakeholders206
. It represents a flexible approach combining bottom-up
initiatives and top-down steering of the regulatory oversight, respecting the principle of
subsidiarity.
Option 2, significantly restructuring the EU institutional framework, while having
advantages in terms of requiring less coordination and being as efficient as Option 1, it has
the clear disadvantage of requiring significant changes to established institutional practices
and processes and of having the greatest economic impact. Some of the solutions proposed
under Option 2, such as those involving the extension and shifting of decision-making
powers and responsibilities, would raise severe opposition from stakeholders. That would
206
70% of stakeholders responding to the relevant questions of the Commission's public consultation on a
new market design were in favour of strengthening ACER's institutional role, e.g. some mentioning that
it may be efficient to enable ACER to take decisions on cross-border issues where EU network
codes/guidelines require decisions to be taken by all national regulatory authorities. Further, many
stakeholders asked for improving ENTSO-E's independence from its members' commercial interest.
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be for example the case for ACER and the transfer of decision-making powers from
NRAs207
. In summary, Option 2 did not receive support from stakeholders.
The Commission Services are of the view that Option 1 "upgrading the EU institutional
framework " is currently the most appropriate approach to achieve the main objective
pursued i.e., adapt the institutional framework and ACER's decision powers and internal
decision-making to the reality of integrated regional markets.
It is also relevant to note, that as the institutional framework for the European energy
market design initiative, the proposals discussed above in the options will be accompanied
by some further changes originating from the need to adapt ACER's funding Regulation to
the Common Approach on EU decentralised agencies208
and to incorporate some minor
improvements to streamline the institutional framework established in the Third Package.
Further, as the Third Package establishes an identical institutional framework for
electricity and for gas209
, changes to this system will be also applied to the gas sector where
relevant and reasonable to ensure that rules and processes are identical for the two sectors
in the future.
Budgetary implications of improved ACER staffing
This Section provides an estimate of budgetary implications from adjusting ACER staffing
to adequately meet new tasks and responsibilities envisaged under the preferred option
(Option 1) as well as under the highly ambitious Option 2.
As per the Agency's draft 2017 Work Programme, ACER employed on 31.12.2015 a total
of 54 Temporary Agents, of which 39 at AD level and 15 at AST level. The Agency further
employed an additional 20 Contract Agents and 6 SNE, raising the total ACER headcount
to 80.
It should be noted that the European Commission, in its latest opinion on the ACER Work
Programme210
did not agree to grant additional staff under the 2017 budget, judging that
current staff figures are adequate to meet current tasks and suggesting that ACER shifts
resources internally to meet priority objectives.
207
Most of the Member States responding to the relevant questions of the Commission's public consultation
on a new market design favored preserving the status quo as regards the institutional framework.
208
The Common Approach on EU decentralised agencies agreed in July 2012 by the European Parliament,
the Council and the Commission defines a more coherent and efficient framework for the functioning of
agencies. Although legally non-binding, it serves as a political blueprint not only guiding future
horizontal initiatives but also in reforming existing, individual EU agencies. Most importantly, the
implementation of the Common Approach requires the adaptation of the founding acts of existing
agencies, based on case by case analysis.
209
For example, the Third Package, in the Gas Regulation established the European Network for
Transmission System Operators for Gas (Art. 5).
210
Commission Opinion on the draft Work Programme of the Agency for the Cooperation of Energy
Regulators, C(2016)3826 of 24.6.2016
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In line with additional tasks foreseen under Option 1 and Option 2, ACER staffing
resources should however be adapted.
The tables below show the financial implications of Option 1 and Option 2 for extra staff.
The average cost per headcount is based on the latest DG BUDGET declared average
cost211
: for a Temporary Agent, total average costs including "bailage" costs (real estate
expenses, furniture, IT, etc.), stand at EUR 134.000 per year per individual.
Table 5: ACER staff: budgetary implications under Option 1
Function (a) No. extra
staff (MIN)
(b) No. extra staff
(MAX)
Budget of (a)
(million euros)
Budget of (b)
(million euros)
Network Codes and
Regulation
7 12 0.938 1.618
Regulatory
Oversight
6 10 0.804 1.340
Coordination
(Internal and
External)
2 3 0.268 0.402
DSO-related 2 3 0.268 0.402
Total + 17 + 28 2.278 3.752
Source: Own calculation based on DG BUDG figures
211
Circular note of DG BUDGET to RUF/2015/34 of 09.12.15
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Table 6: ACER staff: budgetary implications under Option 2
Function (a) No. extra
staff (MIN)
(b) No. extra staff
(MAX)
Budget of (a)
(million euros)
Budget of (b)
(million euros)
Network Codes and
Regulation
20 30 2.680 4.020
Regulatory Oversight 30 35 4.020 4.690
Dedicated national
desk offices
56 84 7.504 11.256
Reinforced Board of
Appeal
15 20 2.010 2.680
Coordination
(Internal and
External) &
Management
15 20 2.010 2.680
DSO-related 5 10 0.670 1.340
Total + 141 + 199 19.296 26.666
Source: Own calculation based on DG BUDG figures
These calculations are only approximate as they cannot take into account the grade level
of future recruited staff or the exact breakdown of future tasks. This is particularly true for
Option 2, which would entail a complete overhaul of the Agency and the appropriation of
full regulatory competences for 28 markets.
Subsidiarity
The current institutional framework for energy in the Union is based on the
complementarity of regulation at national and EU level. The Third Package mandated the
designation by Member States of national regulatory authorities and required that they
guarantee their independence and ensure that they exercise their role and powers
impartially and transparently at national level. The Third Package also created ACER and
ENTSO-E in order to enhance the coordination of national energy regulators and elecricity
TSOs at EU level.
The implementation of the Third Package through the adoption of Commission
implementing regulations has led to the creation of new entities and functions which have
changed the regulatory landscape. Some of these entities/functions have EU-wide
relevance (e.g., the market coupling operator function in the electricity sector) whereas
others have regional relevance (e.g., the regional security coordinators in the electricity
sector, capacity allocation platforms in the gas sector).
Moreover, the electricity markets have become more integrated due to increasing cross-
border electricity trade and more physical interconnections in the European electricity grid.
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This, together with progressively higher shares of decentralized and variable renewable
energy sources, have rendered the national electricity systems much more interdependent
than in the past.
Whereas the institutional framework envisaged in the Third Package has undoubtedly been
successful, the unprecedented changes described above have highlighted the existence of
regulatory gaps. These gaps appear, for example, where the creation of the
entities/functions with EU-wide or regional relevance has not been accompanied with the
necessary tools to equip ACER with powers to exercise regulatory oversight over them,
despite the fact that they will be carrying out monopoly or critical functions for the internal
energy market at EU or regional level. Other gaps relate to the lack of regulation ensuring
the consistent implementation of governance principles across regions or to the lack of
clarity concerning the roles and responsibilities of national regulatory authorities, ACER
and ENTSO-E following the adoption of Commission implementing regulations.
It is therefore necessary to adapt the institutional framework in the Third Package to meet
this new reality and provide a basis for realizing the full potential of the internal energy
market. This is why the roles of NRAs, ACER, and ENTSO-E need to further evolve,
clarifying their powers and responsibilities over relevant geographical areas. In addition,
it will be necessary to adapt the institutional framework to the changes in EU energy
legislation stemming from the proposed initiatives.
Proportionality
Option 1 would be in line with the proportionality principle given that it aims at clearly
defining the roles, powers and responsibilities of the main actors (NRAs, ACER, ENTSO-
E) so that they are adapted to the new realities of the electricity markets and to the need
for more regional cooperation. More specifically:
- The improvements to the ACER framework under this option do not aim at
replacing national regulatory authorities but rather at complementing their role as
regards issues which have regional/EU-wide relevance. The scope of ACER's
responsibilities will continue to be limited to cross-border relevant issues.
- The improvements concerning the regulatory oversight at regional level aim at
addressing the regulatory gap that has arisen with the implementation of the Third
Package through the adoption of Commission implementing regulations.
- The amendments of the ENTSO-E framework under this option principally aim at
improving and clarifying its mandate to ensure its European character and to
introduce more transparency in its internal decision-making processes.
- The improvements to the process for developing Commission implementing
regulations (network codes and guidelines) aim at addressing some of the
shortcomings identified in the past years.
- The establishment of an EU DSO entity will support EU policies and RES
integration in the electricity system, will support the swift implementation of
network codes and guidelines, and enhance cooperation between TSOs and DSOs.
Stakeholders' opinions
This Section provides a more detailed summary of the views expressed by stakeholders
regarding the adaptation of the institutional framework in the European Electricity
Regulatory Forum and in response to the Commission public consultation on a new market
design.
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The 29th
meeting of the European Electricity Regulatory Forum of 9 October 2015
underlined, as a conclusion, "the need for analyzing and further elaborating the roles,
tasks, responsibilities and consider possible governance structures of ACER and ENTSO-
E" and stressed "the need to observe and consider possible governance structures for other
bodies, including DSOs and power exchanges, and for NEMO cooperation."
As regards enhancing ACER's institutional role, in response to the Commission public
consultation on a new market design, 70% of all stakeholders who answered the questions
on ACER wanted to increase the powers or tasks of ACER (notably as regards oversight
of ENTSO-E). 30% supported to keep the status quo. Only a limited number of respondents
(5%) mentioned missing independence of ACER as a problem. In general, views differed
between Member States and NRAs on the one hand (rather for preserving status quo) and
other stakeholders (rather in favour of strengthening powers at regional/EU level).
Within the development of a robust regulatory framework for the entities performing
monopoly or near-monopoly functions at EU or regional level, ACER called for the power
to exercise regulatory oversight over such entities212
. With regard to regional cooperation,
which should be promoted by the NRAs, ACER can support NRAs' actions and should be
responsible for promoting and monitoring the consistency of regional implementation and
of the activities of entities performing monopoly or near-monopoly activities at regional
level.
As regards ENTSO-E, 38% of the respondents to the public consultation on a new market
design did not have or did not express any opinion or preference regarding the possible
strengthening of ENTSO-E. Looking at the respondents having an opinion on this topic,
59 % of the respondents were in favour of not to strengthen ENTSO-E while 41% asked
for a stronger ENTSO-E.
As regards power exchanges, 63% of the respondents to the consultation answering this
specific question were of the view that there is a need for enhanced regulatory oversight
of power exchanges.
As regards the process for development of Commission implementing regulations in the
form of network codes and guidelines, some of the respondents to the consultation
mentioned the existence of a possible conflict of interest in ENTSO-E’s role – being at the
same time an association called to represent the public interest, involved e.g. in network
code drafting, and a lobby organisation with own commercial interests – and asked for
measures to address this conflict. Some stakeholders suggested that the process for
developing network codes should be revisited in order to provide a greater a balance of
interests. Some submissions advocated for including DSOs and stakeholders in the
network code drafting process.
As regards DSOs, the establishment of an independent EU-level DSO entity has been
welcomed by stakeholders on multiple occasions. In particular, attention is drawn to the
Conclusions of the 31st
Energy Regulators Forum, whereby: "The Forum takes note of the
announcement from the Commission of the establishment of an EU‐ level DSO entity that
212
ACER's position on the regulatory oversight of (new) entities performing monopoly or near-monopoly
functions at EU-wide or regional level.
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can serve to provide expertise in advancing the EU market. The Forum invites the
Commission, in the design of any entity, to ensure a balanced representation of DSOs and
maximum independence and neutrality". Equally, regulators (ACER and CEER) suggested
considering whether DSOs should be encouraged to establish a single body through which
they can more efficiently participate in the process of new electricity market design.


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 4/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
207
TABLE OF CONTENTS
4. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(1);
(IMPROVED ENERGY MARKETS, NO CMS).................................................................. 209
4.1. Removing price caps......................................................................................................................209
Summary table.............................................................................................................................209
Description of the baseline ..........................................................................................................210
Deficiencies of the current legislation .........................................................................................215
Presentation of the options .........................................................................................................215
Comparison of the options ..........................................................................................................216
Subsidiarity...................................................................................................................................217
Stakeholders' opinions.................................................................................................................218
4.2. Improving locational price signals .................................................................................................220
Summary Table ............................................................................................................................221
Description of the baseline ..........................................................................................................222
Deficiencies of the current legislation .........................................................................................228
Presentation of the options .........................................................................................................229
Comparison of the options ..........................................................................................................230
Subsidiarity...................................................................................................................................231
Stakeholders' opinions.................................................................................................................232
4.3. Minimise investment and dispatch distortions due to transmission tariff structures ....................234
Summary table.............................................................................................................................235
Description of the baseline ..........................................................................................................236
Deficiencies of the current legislation .........................................................................................238
Presentation of the options .........................................................................................................238
Comparison of the options ..........................................................................................................240
Subsidiarity...................................................................................................................................244
Stakeholders' opinions.................................................................................................................245
4.4. Congestion income spending to increase cross-border capacity....................................................247
Summary table.............................................................................................................................248
Description of the baseline ..........................................................................................................250
Deficiencies of the current legislation .........................................................................................253
Presentation of new measures/options.......................................................................................253
Comparison of the options ..........................................................................................................255
Subsidiarity...................................................................................................................................257
Stakeholders' opinions.................................................................................................................258
5. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(2)
(IMPROVED ENERGY MARKETS - CMS ONLY WHEN NEEDED, BASED ON
COMMON EU-WIDE ADEQUACY ASSESSMENT ( AND OPTION 2(3) (IMPROVED
ENERGY MARKET, CMS ONLY WHEN NEEDED BASED ON COMMON EU-WIDE
ADEQUACY ASSESSMENT, PLUS CROSS-BORDER PARTICIPATION) ................. 260
5.1. Improved resource adequacy methodology ..................................................................................262
Summary table.............................................................................................................................263
Description of the baseline ..........................................................................................................264
Deficiencies of the current legislation .........................................................................................270
Presentation of the options .........................................................................................................271
Comparison of the options ..........................................................................................................272
Subsidiarity...................................................................................................................................279
208
Stakeholders' opinions.................................................................................................................279
5.2. Cross-border operation of capacity mechanisms...........................................................................282
Summary table.............................................................................................................................283
Description of the baseline ..........................................................................................................284
Deficiencies of the current legislation .........................................................................................285
Presentation of the options .........................................................................................................286
Comparison of the options ..........................................................................................................289
Subsidiarity...................................................................................................................................291
Stakeholders' opinions.................................................................................................................292
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4. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(1); (IMPROVED ENERGY MARKETS, NO CMS)
4.1. Removing price caps
Summary table
Objective: to ensure that prices in wholesale markets and not prevented from reflecting scarcity and the value that society places on energy.
Option 0: Business as usual Option 1: Eliminate all price caps Option 2: Create obligation to set price caps, where they exist, at VoLL
Description
Existing regulations already require harmonisation of
maximum (and minimum) clearing prices in all price
zones to a level which takes "into account an estimation
of the value of lost load".
Non-regulatory approach
Enforceability of "into account an estimation of the value
of lost load" in the CACM Guideline is not strong.
Enforcement action is unlikely to be successful or
expedient. Relying on stronger enforcement would leave
considerable more legal uncertainty to market
participants than clarifying the legal framework
directly.Voluntary cooperation not provide the market
with sufficient confidence that governments would not
step in restrict prices in the event of scarcity.
Eliminate price caps altogether for
balancing, intraday and day-ahead markets
Removes barriers for scarcity pricing
Avoids setting of VoLL (for the purpose of
removing negative effects of price caps)
Reinforced requirement to set price limits taking "into account an estimation of
the value of lost load"
Allow for technical price limits as part of market coupling, provided they do not
prevent prices rising to VoLL.
Establish requirements to minimise implicit price caps.
Pros
Simple to implement – leaves adminstration to technical
implementation of the CACM Guideline.
Measure simple to implement;
unequivocally and creates legal certainty.
Compatible with already existing requirement to set price limit, as provided for
undert the CACM regulation, provides concrete legal clarity
Cons
Difficult to enforce; no clarity on how such clearing
prices will be harmonised. Does not prevent price caps
being implemented by other means.
Can be considered as non-proportional;
could add risk to market participants and
power exchanges if there are no limits .
VoLL, whilst a useful concept, is difficult to set in practice. A multitude of
approaches exist.
Most suitable Option(s): Option 2 - this provides a proportionate response to the issue –, it would allow for technical limits as part of market coupling and this should not restrict the markets
ability to generate prices that reflect scarcity.
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Description of the baseline
Scarcity pricing is critical to investment in flexible generation and demand. Traditionally,
power plants have been built based on receiving a stable revenue and operating with high
levels of output for a significant proportion of time (i.e. high load factors). However, with
more variable renewable technologies entering on to the system, with generally very low
or zero marginal costs, the patterns that more conventional forms of generation operate
(e.g. gas) is changing. Investment will no longer be able to take place based on the
assumption that plants will operate at high load factors for a significant portion of their
working life; with more and more generation from renewables, with lower running costs,
these plants will operate less and less. However, they will remain critical in providing a
stable electricity system. They will need to operate to keep supply steady in times of low
renewable generation and flexibility will be key. There will be more and more occasions
when prices could reach very high levels (in times of scarcity) but for very short periods
of time. It is these peaking prices that can provide the signals and stimulate the investment
needed in flexible capacity so long as investors have the confidence that they will be able
to recoup their money based on such prices. Further, such prices are critical in stimulating
other forms of flexibility, notably in the form of demand response – in the case where a
consumer (industrial or residential) has a contract which reflects wholesale price
movements, the greater the price differences, the greater the incentive to respond by
reducing consumption and instead using energy at lower price periods.
It is not the case, however, that all consumers will necessarily see such short-term changes
in prices. In general, consumers will be more affected by the longer-term changes in
average prices; these will more likely feed through to energy bills for reasons explained
below.
Whilst different formulas exist, unit costs in a standard fixed or variable (monthly) retail
tariff will be an average of the wholesale price over a period of time, with additional costs
added, such as network costs, taxes, etc., along with any supplier margins. Consumers on
these tariffs will be shielded from period-by-period changes in the wholesale price, be they
up or down.
Whilst the development of demand response will be enhanced by dynamic tariffs which
better reflect the wholesale price, there is no proposal for this to be obligatory. If a
consumer were to choose a tariff that mirrored the wholesale price on a 1:1 ratio, overtime
they would likely pay less as their suppliers would face lower hedging costs, which they
could then pass on to those consumers as tariff savings (lower margins). This is illustrated
in the Nordic markets, where hourly tariffs are often the cheapest on the market for most
consumers. Nevertheless, consumers whose peak consumption consistently coincided with
price peaks on the market, and who chose a dynamic tariff, may end up paying more at the
end of the billing period, reflecting their cost to the system.
The formation of scarcity prices can be contained directly or indirectly and, in particular,
by caps on prices. These can be implemented for a number of reasons, including technical
(e.g. required as part of the operation of the programs which determine market results), to
improve the robustness of market operation (e.g. to prevent significant errors in bidding
affecting market outcomes), for competition reasons (i.e. to limit any abuse of a dominant
position), for consumer-related reasons (e.g. to limit consumer exposure to high prices)
and for financial reasons (e.g. to limit the collateral needing to be posted).
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In a perfect market, supply and demand will reach an equilibrium where the wholesale
price reflects the marginal cost of supply for generators and the marginal willingness to
pay for consumers. If generation capacity is scarce, the market price should reflect the
marginal willingness to pay for increased consumption. As most consumers do not
participate directly into the wholesale market, the estimated marginal value of
consumption is based on the value of lost load (VoLL). VoLL is a projected value which
is supposed to reflect the maximum price consumers are willing to pay to be supplied with
electricity. If the wholesale price exceeds the VoLL, consumers would prefer to reduce
their consumption, i.e. be curtailed. If, however the wholesale price is lower than the
VoLL, consumers would rather pay the wholesale price and receive electricity. If prices
are prevented from reaching the VoLL through the introduction of price caps, then short-
term prices will be too low in scarcity situations. This in turn can affect investment signals
- notably, it can reduce the incentive to investment in flexible capacity (i.e. of the type that
can respond to short-term peaks in prices) and demand response.
However, currently all Member States have specific restrictions on the price to which
wholesale prices can rise. In the day-ahead market, the most common cap is EUR
3000/MWh, which is by-and-large a technical constraint rather than implemented with the
intention of keeping prices below VoLL. Some Member States have values somewhat
lower, which could introduce distortions in the price signals.
Figure 1 – Day-ahead price caps
▪ Majority: +3000 EUR/MWh
▪ GB: +3000 or +6000 GBP/MWh
▪ Greece: 150 EUR/MWh
▪ Ireland: +1000 EUR/MWh
▪ Poland: 347 EUR/MWh, +3000
EUR/MWh (x-border)
▪ Portugal/Spain: 180 EUR/MWh
Source: "Market design: Barriers to optimal investment decisions" Impact Assessment support study, (2016)
COWI
These values have limited relationship to the value of lost load and, therefore, if maintained
would prevent prices rising to the level to which society values energy. For example, a
recent study commissioned for the UK's Department of Energy and Climate Change
estimated that VoLL for Electricity in Great Britain to be GBP 10,289/MWh for domestic
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users and GBP 35,488 for SMEs on a winter peak workday (approximately EUR
13,500/MWh and EUR 46,500/MWh at the time of writing)1
. Whilst VoLL will change
depending on the circumstances, the user and the location (it will not be the same in all
Member States), it is clearly much higher than the limits that currently exist in many day-
ahead markets. Price caps in the intraday markets show a lot less harmonisation - see map
below. Whilst the level is generally much higher - i.e. no caps in some countries, and up
to EUR 9999,99/MWh in others, and therefore are less likely to create distortions, some
Member States have price caps which will fall far below VoLL.
Figure 2 – Intraday price caps
▪ Green: No ID market
▪ Light blue: -9999,99 to +9999,99
EUR/MWh
- Stripes: DE: Discrete -
3000/+3000 EUR/MWh
▪ Dark blue: No price caps
▪ Czech: +3700 EUR/MWh
▪ Dark red:
- GB: 0/+2000 GBP/MWh
- IT: 0/+3000 EUR/MWh
- PT, ES: 0/+180 EUR/MWh
Source: "Market design: Barriers to optimal investment decisions" Impact Assessment support study,
(2016) COWI
With regards to the balancing timeframe, price caps apply to the activation (energy) part
of balancing services in several Member States. In some countries there are fixed price
caps, like +/-9999,99 EUR/MWh in Slovenia, +/-3700 EUR/MWh in Czech Republic, or
203 EUR/MWh for FRR in Lithuania. In Austria and the Nordic countries, the floor price
is equal to the day-ahead price, meaning that there is a guarantee that the payment for
energy injected for balancing is at least equal to the day ahead price. In Belgium, FRR
prices are capped to zero (downward regulation) and to the fuel cost of CCGT plus 40
1
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/224028/value_lost_load
_electricty_gb.pdf
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euros (upward regulation). Most Member States do not have price caps for capacity
(reserve) bids.
There is an important relationship between the price paid for balancing services and the
imbalance price – that is, the price determined by TSOs which producers and consumers
must pay as they use or produce too much or too little energy compared to their contracted
amount. As detailed further below, it is this real-time price which will have the biggest
impact on prices in the intraday, day-ahead and forward prices. However, it will be heavily
influenced by the price that TSOs pay for balancing services. In particular, under the
upcoming Balancing Guideline, there are restrictions on how it can be formed based on the
price paid for activation of balancing energy. The Guideline will also require that there are
no caps or floors to balancing energy prices.
Free formation of prices in the balancing market is perhaps the most important issue; day-
ahead and intraday markets effectively act as an opportunity to hedge against the expected
imbalance price - they will not buy or sell energy above this price as it will be cheaper to
be out of balance and pay the imbalance price. Therefore, the balancing price should not
mute scarcity pricing by capping prices below VoLL, else prices in the intraday and day-
ahead timeframes will not reflect scarcity, regardless of any caps put in place.
The following diagrams illustrate the relationship between prices in each of the three
market timeframes, using the example of the imbalance price in Belgium on the 22nd
September 2015. Figure 5 shows a high imbalance price caused by scarcity due to
unplanned outages.
Figure 3 – Day-ahead spot prices as a result from the matching of orders in and the
coupling of the bidding zones in the CWE-region on the 21st, 22nd and 23rd
September 2015
Source: Belpex, EEX, APX
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Figure 4 – Intraday prices in Belgium on 21st, 22nd and 23rd September 2015
Source: Belpex
Figure 5 – Imbalance prices in Belgium on 21st, 22nd and 23rd September 2015,
Source: Elia
From these, it can be seen that the market is behaving rationally - i.e. that parties are trading
in the day-ahead and intraday markets to hedge themselves. The prices are tracking the
imbalance price. If it was prevented from going above a set amount, this would have an
effect on bidding behaviour in the other two timeframes, which would also not go above
this price. As the imbalance price will change in real time, market participants can only
base their bidding in the day ahead and intraday markets based on what they expect the
price will be. Therefore, such tracking of prices across timeframes will not happen where
there are very short-term changes in the imbalance price, e.g. due to sudden tripping of
equipment.
It should be noted that there is a difference between price restrictions on the price paid for
activation of energy by TSOs in the balancing timeframe, and the imbalance price. The
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former will help inform the imbalance price, but it is generally the latter that has the most
impact on behaviour in the day-ahead and intraday market.
Two issues exist relating to harmonisation of caps. Firstly, given the above, that of
harmonisation between timeframes. If caps exist in the balancing timeframe, there is little
point in having a cap higher than this in intraday or day ahead, as there will be no reason
for market parties to bid or offer energy at a higher price - i.e. because it will be cheaper
to pay the imbalance price. It is therefore important that there is consistency across market
timeframes. The second issue relates to harmonisation between markets. If there are
different price caps each side of a border, this can interfere with how energy flows in times
of system stress. Take for example Member State A with a price cap of 1000, on a border
with a Member States B whose price cap is 100. In the absence of a cap, energy would
flow to the country who valued it the most, i.e. with the higher price. However, with these
caps if there was a concurrent scarcity event which led to prices going above 100, then
energy will always flow to Member State A, despite the fact that Member State B might
value energy as much or more (i.e. because the price cannot attract flows of energy more
than Member State A’s prices).
Implicit price caps can also exist. For example, in some Member States (around a third), a
shadow auction2
is triggered if prices reach 500 euros /MWh (or goes below -150 euros
/MWh). This can act as a disincentive to bid higher than EUR 500 . Other disincentives
that have been identified include: general fears about competition law – for example, the
market restricting itself out of fear of being seen to be abusing a dominant position; the
price at which strategic reserves are activated; and TSO actions based on market price.
Deficiencies of the current legislation
Current European legislation contains very little reference to wholesale market prices caps.
In fact, the only reference is contained in the CACM Guideline. Specifically, Articles 54
(covering intraday trading) and Article 41 (covering day-ahead) require power exchanges,
acting in their cross-border roles as NEMOs to propose harmonised maximum and
minimum bid prices. This needs to "take into account the value of lost load." This proposal
is due to be made to regulatory authorities by mid May 2017.
As pointed out in the Evaluation Report, normally, well-functioning wholesale markets
should provide price signals necessary to trigger the right investment. However, the ability
of markets to do so is debated today because today's electricity markets are characterised
by uncertainties as well as by a number of market and regulatory failures which affect price
signals. These include low price caps, renewable support schemes, the lack of short term
markets and lack of demand response operators.
Presentation of the options
Option 0: Business as usual
The option would allow for the continuation of limits on wholesale prices. This would in
principle allow for different price caps in different timeframes. However, under the terms
2
Auctions run to validate that the results of the first auction are correct and not abnormal prices due to
either technical issues during the execution of the market clearing algorithms, or bidding behaviour of
market participants.
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of the CACM Guideline it would bring harmonisation in day-ahead and intraday as there
is a requirement for a harmonised value in all bidding zones participating in market
coupling. This value would have to "take into account" the value of lost load. It would not,
however, have to represent this value and could be significantly lower. For example, as
part of the NWE market coupling project, there is a maximum clearing price of
3000euros/MWh in those bidding zones taking part in the project. This limit has been
applied to other markets, for example the German intraday auction (which takes place after
the cross-border auction) and the GB day-ahead auction (a similar process, again after the
cross-border auction, although the limit is expressed in GBP). This is most likely due to
issues of convenience and to prevent creating perverse incentives to trade in one of the
markets as opposed to another.
Option 1: Eliminate all price caps
This option would see a prohibition on all upper price restrictions in the wholesale market,
in all timeframes. It would mean that prices would be able to reach VoLL. It would also
involve a prohibition on any technical price limits imposed by power exchanges.
Option 2: Create obligation to set price caps, where they exist, at VoLL
This option would require that, where caps exist, they shall be no lower than VoLL in all
market timeframes. This would be coupled with a requirement that Member States
establish VoLL. This option would be compatible with a technical limit imposed by power
exchanges, but would include a trigger to raise such limits in order to prevent them
constraining acurate price formation coupled with a date by which the maximum must not
be below VoLL. It would also make clear that, once at VoLL, the value need not be
harmonised.
Comparison of the options
As detailed above, allowing prices to reflect scarcity, and investors having confidence that
this will be allowed to happen, is key to stimulating investment in a more flexible system.
The options must, therefore, be assessed in this context i.e. those options which would
prevent scarcity prices forming and, in particular, reflecting the true scarcity in terms of
willingness to pay for energy, would not be compatible with the objective of creating an
energy market that is able to face future challenges and stimulate the right investments.
The 'do nothing' option would not be consistent with the set objectives – even though
harmonised maximum clearing prices would be implemented, these only have to 'take into
account' the value of lost load and there would be no way to provide confidence that prices
could indeed reach values which reflect scarcity. It would allow for price caps to continue
existing within Member States. Whilst in practice, for most Member States, prices have
not been constrained by existing caps (there have been no instances yet where they have
hit the 3000 euros mark), this is not set to remain the case forever. Doing nothing, or relying
on voluntary cooperation at the Member State level, would not provide investors with any
confidence that restrictions would be removed (or raised) in the event they were hit and
the default position is that they would remain in place. It therefore has to be assumed that
such an option would shave off the peaks in pricing. Whilst the CACM Guideline contains
a reference to VoLL, ‘take into account' is not enforceable.
Option 1 – to eliminate any price caps - would be the option most in line with this specific
objective, in that it would allow prices to rise to any level, determined by supply and
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demand fundamentals. Making a strict, EU-level prohibition may provide investors with
confidence that Member States would not intervene to keep wholesale prices low for
political reasons – e.g. because of a negative perception of the impacts of peaking prices
on consumers. This option, however, entails risks. In particular, it would prevent any limits
being used in the market coupling system or by power exchanges. This could have
technical impact on the operation of the systems used to run the markets and may influence
the amount of collateral that market parties are required to post. Market parties are
generally required to provide cash or credit to cover their potential exposure. Without
limits in the clearing price, this could become more expensive or their credit more
restrictive (e.g. on how much they can trade), as the potential exposure would be higher.
Further, it could prevent the use of any explict price-based measure to detect errors in
bidding.
Option 2 would allow for the use of limits to exist in the context of trading on the power
exchanges and only in relation to maximum and minimum clearing prices developed in
accordance with the CACM Guideline. In order to prevent such limits restricting accurate
price formation, the option would also introduce a specific requirement that they be raised
when a trigger point is reached coupled with a requirement that they be set at the value of
lost load within a certain timeframe. The option would also prohibit Member States from
introducing legal caps on the wholesale price unless this reflects a calculation of the value
of lost load.
The advantage of this approach is that it would still allow for technical limits to be
introduced by power exchanges, but would not constrain price formation and would give
investors a clear signal that Member State authorities cannot step in artificially dampen
prices. The disadvantage as compared to Option 1 is that, in order for such limits to
continue to exist and to be effective, there may need to be a time lag between the trigger
and the limit being raised. This would need to be as short as possible so not to prevent
prices from rising.
A difficulty with this option is the complexity of establishing VoLL. It will change
depending on the circumstances and the user and so one value will only ever be an
estimation.
This option would also be bundled with a requirement placed on Member States to avoid
and, where possible, eliminate any implicit price caps so not to disincentives the offering
of high prices by market participants.
The benefits of better price signals and further articulated as part of the wider option to
address uncertainty on future investments (Problem Area II, which includes policies on
locational signals, scarcity pricing and price caps, resource adequacy planning and capacity
mechanisms) in Section 6.2.2.
Subsidiarity
Given that the EU energy system is highly integrated, prices in one country can have a
significant effect on prices in another. Further, if there are significant differences between
countries on the level to which wholesale prices can rise, then energy may flow in the
wrong direction during times of system stress. A coordinated and harmonised approach is,
therefore, necessary.
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This topic is, to an extent, already covered under the CACM Guideline – which notably
requires the setting of harmonised maximum clearing prices which take into account the
value of lost load.
Differences in national approaches could create significant distortions in the market and
prevent the most cost-effective supply of electricity. It could also distort investment
signals, for example those countries who have a higher cap would potentially attract more
investment thnt those with a lower cap.
EU action is therefore necessary to ensure a common approach is taken which minimises
distortions in the operation of markets between Member States.
Stakeholders' opinions
From the Market Design consultation, a large majority of stakeholders agreed that scarcity
pricing is an important element in the future market design. It is perceived, along with
current development of hedging products, as a way to enhance competitiveness. While
single answers point at risks of more volatile pricing and price peaks (e.g. political
acceptance, abuse of market power), others stress that those respective risks can be avoided
(e.g. by hedging against volatility).
Many submissions to the consultation highlighted the link between scarcity pricing and
incentives for investments/capacity remuneration mechanisms, as well as the crucial role
of scarcity pricing for kick-starting demand response at industrial and household level.
Key stakeholder comments included:
- "…energy prices that reflect market fundamentals, including scarcity in terms of
time and location, are an important ingredient of the electricity market design.
Undistorted prices (without regulatory intervention) should thus trigger optimal
dispatch and signal the need for investments/divestments… Price caps and other
interventions in the market hindering the appearance of scarcity prices should be
removed." Eurelectric
- "…we need to better valorize flexibility. Prices reflecting scarcity are crucial in
this context and should therefore be a key priority of the market reform… Prices
better reflecting scarcity will be more volatile and might be higher than today
during some periods of the day (assuming the end of price caps). Rather than a
challenge, this represents an opportunity as it will unlock new strategies to hedge
against risks on the wholesale market while triggering dynamic pricing offers on
the retail side." SolarPower Europe.
- "In principle, electricity prices should reflect actual scarcity so that the most cost-
efficient flexibility options on the supply and the demand side as well as the most
efficient storage solutions are employed. Prices should also reflect the scarcity of
transmission capacities within and across market borders" EUROCHAMBERS
- "In order to provide correct price signals for new investments (both generation and
consumption), and to provide security of supply, prices which reflect actual
scarcity are an important ingredient in the future market design." BusinessEurope
- "Citizens Advice supports efforts to move to market structures that more accurately
reflect scarcity. This is an important way of conveying price signals reflecting the
genuine value of consumption and production, at different times and in different
locations." Citizens Advice
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- "…energy prices should effectively reflect both temporal scarcity and surplus in
order to adequately reward flexibility. Such an approach to energy pricing would
better facilitate the investments required to address the European energy trilemma
of sustainability, security of supplies, and competitiveness." WWF
Further, in a position paper, Wind Europe state that "[i]t is important that market prices
are undistorted and allowed to move freely without caps. Transparent market prices must
be in place in all time horizons, i.e. forward, day-ahead, intraday and real time, and also
used for settlement of remaining imbalances. This will help to incentivise and reward the
provision of flexibility services. Policy makers should be aware that price spikes are
needed to trigger the right scarcity signals on both the supply and demand side; investment
decisions based on a certain expectation of price spikes will only be made if there is enough
trust by investors that politicians will not interfere and introduce price caps. " 3
The March 2016 Florence Forum made the following relevant conclusion:
"The Forum acknowledges the significant progress being made on the integration of cross-
border markets in the intraday and day-ahead timeframes, and considers that market
coupling should be the foundation for such markets. Nevertheless, the Forum recognises
that barriers may continue to exist to the creation of prices that reflect scarcity and invites
the Commission, as part of the energy market design initiative, to identify measures needed
to overcome such barriers. In doing so, it requests the Commission take proper account of
technical constraints that may exist."
3
https://windeurope.org/fileadmin/files/library/publications/position-papers/EWEA-Position-Paper-
Market-Design.pdf
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4.2. Improving locational price signals
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Summary Table
Objective: The objective is to have in place a robust process for deciding on the structure of locational price signals for investment and dispatch decisions in the EU electricity
wholesale market.
Option 0 Option 1 Option 2 Option 3
Description
Business as Usual – decision on bidding
zone configuration left to the arrangements
defined under the CACM Guideline or
voluntary cooperation, which has, to date,
retained the status quo.
Move to a nodal pricing system Introduce locational signals by new means,
i.e. through transmission tariffs
Improve currently existing the CACM
Guideline procedure for reviewing bidding
zones and introducing supranational
decision-making, e.g. through ACER.
This would be coupled with a strengthened
requirement to avoid the reduction of cross-
zonal capcity in order to resolve internal
congestions.
Pros
Approach already agreed. Theoretically, nodal pricing is the most
optimal pricing system for electricity
markets and networks.
Would unlock alternative means to provide
locational signals for investment and
dispatch decisions.
This improvement will render revisions of
bidding zones a more technical decision.
It will also increase the available cross-
zonal capacity.
Cons
Risks maintenance of the status quo, and
therefore misses the opportunity to address
issues in the internal market.
Nodal pricing implies a complete,
fundamental overhaul of current grid
management and electricity trading
arrangements with very substantial
transition costs.
Incentives would be not be the result of
market signals (value of electricity) but cost
components set by regulatory intervention
of a potentially highly political nature.
Does not address the underlying difficulty of
introducing locational price zones, namely
the difficulties to arrive at decisions that
reflect congestion instead of political
borders.
Does not address a situation where the
results of the bidding zone review are sub-
optimal. I.e. this option only covers
procedural issues.
Most suitable option(s): Option 3 – this option will rely on a pre-established process but improve the decision-making so that decisions take into account cross-border impact of bidding
zone configuration. Other options – e.g. tofundementally change how locational signals are provided, would be dispropritionate.
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Description of the baseline
The internal energy market is based on the concept of bidding zones, which are defined as
"the largest geographical area within which market participants are able to exchange
energy without capacity allocation."4
They are effectively market areas within which
energy is considered to be able to flow freely and within which, therefore, there will be a
single wholesale price for any given market timeframe.
Currently, bidding zones are based on national borders, although there are some
exceptions5
.
Figure 1, Curent bidding zone configuration
Source: Ofgem, 2014
The wholesale price will be the same in one part of France as it is in another, the same in
one part of Spain as it is another part of Spain, the same in Germany as it is in Luxembourg
and Austria, and so on. The wholesale price in Italy may be different in different parts, as
it may be in Sweden and Norway.
This is critical, as the wholesale price is a crucial part of determining when and where
people invest (and where there are no other revenue streams such as capacity mechanisms,
the only basis). Higher prices in one area will in theory attract investment into that area
4
Commission Regulation (EU) No 543/2013 of 14 June 2013 on submission and publication of data in
electricity markets
5
There is currently one German-Austrian-Luxembourg bidding zone, and Italy, Sweden and Norway are
split into several zones.
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over and above somewhere with lower prices. This locational signal in the energy price
will not exist within a bidding zone, and so will not encourage investment in one part as
compared to another and, in the case where bidding zone boundaries are based on Member
State borders, within one part of a Member State compared to another. This is despite the
fact that there may be bottlenecks within that Member State that prevent the free flow of
energy from one part to another and, hence, could create a greater need for investment in
certain geographical areas.
Further, wholesale energy prices will determine when generating plants dispatch and, to a
lesser degree (due to relative inelasticity in the demand-side) when load consumes energy.
i.e. where the price is higher than a generator's short-run marginal cost, bar any external
factors, they will run. If there are significant congestions within a bidding zone, and the
price is influenced by demand behind such congestion, generators on the other side may
still dispatch despite limited ability to transport the energy to the demand. This can result
in the so-called 'loop flow' phenomenon whereby energy will flow around the congestions
through another zone, against market price signals. These flows, as they have not been
scheduled, can have significant implications. More specifically, they can reduce the
amount of cross-border capacity made available to the market for trade and result in costly
remedial actions, for example the need to redispatch (the reduction in the amount of power
injected on one side of the congestion and, simultaneously, an equivalent increase in the
amount injected on the other side). As an example, in 2015 the total cost for redispatching
within the DE-AT-LU bidding zone was approximately 930 million euros6
. Overall, the
total welfare loss due to loop flows was estimated to be around 450 million euros in 20147
.
An improved configuration of bidding zones, one which takes account of structural
congestions within the European grid, would mitigate many of these issues, as it would
improve the locational price signals. In particular, in the short-term it would affect how
and where energy is dispatched and, for the longer-term, will improve the price signals on
where to locate new generation investments. Clearly investment in transmission capacity
is also critical, notably within a bidding zone so that energy can better flow from one area
to another. However, the bidding zone structure itself may not provide strong signals for
such investment; as Ofgem point out in its Bidding Zone Literature Review (2014)8
, impact
on investment may be muted by practical consideration, for example, due to economies of
scale, uncertainties about future generation investment, and difficulty in centralising
charges or reliability and quality of service.
The precise definition of bidding zones, and realising maximum benefit from it, is complex
and highly technical, and there are a number of variables which must be considered.
Therefore, a review process, to be undertaken by TSOs, has been formalised in legislation
under the CACM Guideline9
. More specifically, once a review is launched10
, TSOs are to
6
ENTSO-E Transparency Platform, at https://transparency.entsoe.eu/
7
"Market Monitoring Report 2014" (2015) ACER – social welfare losses for both unscheduled flows and
unscheduled allocated flows.
8
https://www.ofgem.gov.uk/sites/default/files/docs/2014/10/fta_bidding_zone_configuration_literature_
review_1.pdf
9
In practice, work has already started on this.
10
Which can be done by ACER, NRAs, Member States or TSOs, depending on specific criteria – Article
32
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review the existing bidding zone configuration and alternative bidding zone
configurations, and must submit this to Member States or, where so determined by a
Member State, NRAs for a decision on whether to amend or maintain the zones. Figure 2
below provides a summary of this process.
Figure 2, simplified flow chart of bidding zone review process under the CACM
Guideline
When undertaking a review, TSOs must consider issues relating to network security,
market efficiency, including any increase or decrease in economic efficiency of changes,
and stability and robustness of bidding zones.
A number of authors have already suggested alternative configurations, for example as
shown in figure 3.
Launch Review
ACER NRAs One NRA TSOs MS
TSOs: Develop methodology and assumptions NRAs
TSOs: Assess and compare, consult and submit proposal
MS (or
NRA)
MS/NRAs: Reach agreement on proposal to maintain or amend
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Figure 3, possible alternative configuration,
Source: Supponen, Influence of National and Company Interests on European Electricity Transmission
Investments, 2011
However, as pointed out by Supponen (2011), even price zones which reflect the most
congested parts of the European grid, will not provide as efficient price signals as a system
which is based on a more granular system, such as that of nodal pricing. Nodal pricing is
a method of determining prices in which market clearing prices are calculated for a number
of locations on the transmission grid called 'nodes'. These nodes would be determined
based on the most congested points in the system. The price at each node represents the
locational value of energy, which includes the cost of the energy and the cost of delivering
it11
. This model is used in much of North America. For example, the PJM’s system includes
over 10 000 price nodes across 20 transmission control zones, with trading available at
nodes, at aggregates of several nodes, at 12 hubs consisting of hundreds of nodes each, and
at 17 import and export external interfaces. The IEA conclude that "This nodal pricing
system facilitates adjustments to dispatch in the real-time market, efficient use of variable
resources and demand-side response, and limits to market power by individual
generators"12
.
In 2014, Breuer simulated the potential price differences based on a nodal system in
Europe, comparing average across the year with times of strong wind and high load in
continental Europe.
11
Phillips, Nodal Pricing Basics, Independent Electricity Market Operator, available at
http://www.ieso.ca/imoweb/pubs/consult/mep/LMP_NodalBasics_2004jan14.pdf
12
Repowering markets
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Figure 4 – Nodal prices, base case (2016)
Source: Breuer, Optimised bidding area delineations and their evaluation in the European Electricity
System, Brussels, April 2014 – Nodal prices (base case) 2016
As can be seen from the above, there could be significant changes in prices in a nodal
system compared to average prices across Europe on windy days with high demand. Such
a picture serves to illustrate what the prices should be if transmission capacity were fully
taken into account. This does not cluster around the current bidding zone configuration as
shown above and suggests inaccuracy of price formation in the current setup. It is also far
from clear just from the above how this could be best grouped into a bidding zone structure,
and several possibilities exist just from this one scenario. The complexity could be further
increased when looking at alternative scenarios (e.g. high wind/low demand, etc.).
It is therefore concluded that it is correct to rely on a technical analysis where the costs,
benefits and practical considerations (including those listed in the CACM Guideline) will
be considered – this is much more likely to result in a more optimal configuration than the
one currently seen. The issue at stake, therefore, is how to make any change based on the
outcome of the review pre-establishing under the CACM Guideline, or whether to move
to a wholly different arrangement for locational signals such as the mandatory introduction
of locational elements in transmission changes or moving to a nodal system
Cross-zonal capacity calculation
With a, theoretical, 'perfect' bidding zone configuration, the only congestion would be on
a bidding zone border. Therefore, there would be no internal constraints that would cause
reductions in cross-border capacity. However, even if and when a configuration is
implemented that better reflects structural congestion, there will still be internal
congestion. The Electricity Regulation states that:
"TSOs shall not limit interconnection capacity in order to solve congestion inside their
own control area, save for the abovementioned reasons and reasons of operational
security"13
There is, however, evidence that cross-zonal (interconnection) capacity is indeed being
limited in order to deal with internal issues. In its Market Monitoring Report, ACER
13
Annex I section 1.7
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analysed the ratio between thermal capacity (the theoretical maximum capacity) of
interconnectors and the capacity offered for trade (with Net Available Capacity – NTC
Capacity). The results showed that the ratios varied significantly and that on a number of
borders the NTC was significantly below the thermal capacity.
Figure 5 – Ratio between available NRC and aggregated thermal capacity of
interconnectors – 2014 (%, MW),
Source: ACER/CEER Market Monitoring Report 2015.
ACER concluded that "these results indicate that on the borders on the right side of the
figure either the internal congestions are shifted to the border, or those borders are affected
by a significant amount of unscheduled flows."
Regardless of the reason, the impact of this is the reduction of cross-border trade and has
resulted in the need to curtail capacity the other side of the border. The German-Danish
border provides an example of the sorts of impacts this can have. The below graph shows
the average interconnection capacity was 250MW on DK1-DE in 2015, 15% of the
maximum capacity. An investigation for the Danish TSO energinet.dk and the relevant
German TSO TenneT found that a minimum capacity of 1.000 MW will bring a social
economic benefit to the region of approximately 40 million euros per annum14
.
14
Investigation of welfare effects of increasing cross-border capacities on the DK1-DE interconnector.
Institute for Power Systems and Power Economics. RWTH Aachen University. June 2014. Study
commissioned by TenneT and Energinet.dk.
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Figure 6: Monthly average NTC as part of total transfer capacity (2009-2016).
Source: energinet.dk as reported by the Danish Energy Regulatory Authority15
Deficiencies of the current legislation
The most relevant legislation is the Electricity Regulation, which contains a detailed Annex
on congestion management. However, it does not define bidding zones. In Section 1.7 it
states that "when defining appropriate network areas in and between which congestion
management is to apply, TSOs shall be guided by the principles of cost-effectiveness and
minimisation of negative impacts on the internal market in electricity."
More detail is provided under the CACM Guideline, which contains a detailed approach
to reviewing and defining prices zones (Articles 32 through 34), as detailed above.
Following TSOs' review and proposals Member States are required to "reach an agreement
on the proposal to maintain or amend the bidding zone configuration."
This approach lends itself to the maintenance of the status quo as there are likely to be
competing interests at stake. In particular, some Member States are unlikely to want to
amend bidding zones where it would create price differentials within their borders; it is
sometimes considered to be right for all consumers to pay the same price within a Member
State, and for all producers to receive the same price. The current legislation does not,
therefore, provide for the socially optimal solution to be agreed.
With regards to cross-zonal capacity, the current terms of the Electricity Regulation are
unclear and allow for different interpretations and application.
The Evaluation Report concludes that "the Third Package clearly lacks rules for the
development and functioning of short markets as well as rules that would enable the
development of peak prices reflecting actual scarcity in terms of time and location," and
that "given the economic importance (and distributive effects) of the decisions TSOs have
to agree on, experience has shown that voluntary cooperation between TSOs was not able
15
"STUDY ON CAPACITY REDUCTIONS ON THE GERMAN – WESTERN DANISH BORDER (DE-DK1)
(Tender for Offers)" - http://f.industry-supply.dk/2bjt3mw1t748a8fa.pdf
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to overcome the problems that block progress in the internal electricity market (e.g.
definition of fair bidding zones, effective cross-border curtailments)"
Presentation of the options
Option 0: BAU and stronger enforcement
This option would entail relying on existing legislation to improve the configuration of
bidding zones. The likelihood of seeing any meaningful change as a result of this process
is minimal. Existing provisions under the Electricity Regulation are arguably not
sufficiently clear and robust to enforce a structure which reflects systematic constraints in
the interconnected system. The provisions of the CACM Guideline do not provide for a
clear decision-making process which provided any degree of certainty that the change will
be made, but rather it is left to individual Member States to make the decisions even though
these decisions have significant cross-border impacts.
Voluntary cooperation
As highlighted above, the evidence suggests that voluntary cooperation will not result in
progress in this area, as there has been to date already significant opportunity to effect the
necessary changes voluntarily.
Option 1: Move to a nodal-pricing system
A nodal pricing system would be the most granular way of determining location-based
energy prices. In theory, this would eliminate the need for remedial actions by the TSO to
alleviate congestion as the price of energy would determine exactly where it should be
dispatched from. It would also create more accurate investment signals in new generation
and infrastructure – in the case of the former in areas with higher prices, reflecting more
scarcity.
Moving to a nodal pricing system would require a fundamental change in the way
European energy markets are structured – current arrangements for cross-border trading
(market coupling) would need to be redeveloped, implying significant IT and procedural
changes. It would also be a significant change for market participants. The cost impact of
this would, in the short-term, likely out weight the benefits.
Option 2: Introduce locational signals through other means
It is possible to introduce signals for investment and/or dispatch through other means than
a market-based energy price. The main alternative method is through transmission tariffs
– i.e. charging generators less in areas where more capacity and energy is required, and
more where it is not. This can provide effective signals. It would mean a fundamental
change to the tariffs structure as around half (15) of Member States do not apply
transmission tariffs to generation. Further, this would not necessarily affect dispatch as, if
charges are based on capacity, it becomes part of a generators fixed cost and will not affect
when they generate. Moving to 'energy-based' charges could add distortions into the market
as it would be very difficult to engineer this in a way which reflected the congestion and
the dynamic-nature of production. Indeed, ACER has recommended the removal of energy
based transmission charging on generators.
Option 3: Improve bidding zone review and decision-making process
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As mentioned above, a review process is already detailed as part of the CACM Guideline.
There is a requirement to review both existing and possible alternative configurations, the
latter of which is triggered by specific circumstances. This option would see a
strengthening of the decision-making process as a result of the review, in particular to
ensure that the cross-border impacts of bidding zone configurations are appropriately taken
into account. This would be achieved explicitly clarifying existing requirements for price
zone borders to be based on congestion and not Member State borders. Procedurally, more
powers would be given to EU institutions to decide on price zone configuration following
the review. There could also be some amendments to the review process itself to ensure
that it can show the optimal solution.
The option would be coupled with strengthened legal provision that make clearer the
allowed derogations to the overriding rule that cross-zonal capacity must not be limited to
solve internal congestion, and make any derrogation subject to regualtory oversight.
Comparison of the options
Maintaining the current system of review, and leaving the final decision-making in the
hands of national authorities, would be the simplest option and the one which would yield
the least disruption. However, as highlighted above, the process lends itself to maintenance
of the status quo as decisions will be made on an individual, rather than collective basis.
Difficulties have already arisen in the process (relating to some ambiguities in the current
legislation). The benefits of price zone boundaries, reflecting structural congestions would
not be seen, or would only partially be realised, if there is no coordinated decision. These
have been estimated to be between 300-400 million euros per annum16
to around 800
million euros17
.
The second option (Option 1), to move to a nodal pricing system, would be the most
complex to implement. It would involve a complete redesign of the current system. It
would involve fundamentally moving away from the current market setup and would
significant changes to trading arrangements. By way of example, the current approach for
coupling national markets would likely need to change significantly, which would involve
large changes to IT and practices of traders, TSOs, power exchanges, suppliers and
generators. The costs of change would be significant. Burstedde, in an analysis of a number
of central European countries18
found that there would be overall savings in the total cost
of electricy supply from a nodal model, compared to a model based on bidding zones
around Member State borders, of around 940 million euros, mostly due to redispatch costs.
However, she also concluded that "the increase in overall system costs which results from
aggregating nodes into zones remains negligible in relative terms" and that there would be
savings from any move from nationally-based bidding zone borders19
.
The assessment of a nodal model will also form part of the review of bidding zones
structures by TSOs – it is therefore considered premature to conclude that Europe should
16
Bauer, ibid.
17
Duthaler, C. (2012): "A network and performance based zonal configuration algorithm for electricity
systems", Dissertation, EPFL, Lausanne (Switzerland)
18
Comprising of AT, CH, DE, NL, VE and FR
19
Around 280 million euros in the case of moving to 9 zones.
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move to such a model before this review has concluded; the process will allow a proper
assessment of the different options and a decision can be taken on the basis of this.
Option 2 would require the introduction of administered locational signals. It is very
unclear what the costs and benefits of this approach would be, given that it would depend
on the prices set. If it were done on a capacity basis it would only impact the investment
signals, and not dispatch signals. If it were done on an energy basis, then it could add
significant distortions, e.g. by changing the merit order between different plants. This
would be counter-productive and erode the benefits from the market design initiative.
Option 3 builds on the system already established in the EU, as well as processes already
developed as part of the CACM Guideline. However, by moving to a more coordinated
decision-making process, one which does not prejudice the assessment of the benefits and
the costs of potential alternatives by TSOs, the likelihood that decisions are taken which
reflect the cross-border impacts of the bidding zone structure is greatly increased. A more
appropriately defined bidding zone structure could reduce the need for remedial actions,
such as redispatch, reduce unscheduled flows in the form of loop flows, and improve
signals for investment. Even so, an improved bidding zone structure would not eliminate
internal congestion. Strengthened provisions in the Electricity Regulation to provide very
clear rules on when cross-border capacity can be limited will help alleviate the economic
impacts of this happening in order to address internal issues.
The benefits of better locational signals are further articulated as part of the wider option
to address uncertainty on future investments (Problem Area II, which includes policies on
scarcity pricing and price caps, resource adequacy planning and capacity mechanisms) in
Section 6.2.2.
Subsidiarity
Networks in the EU energy market are highly meshed and therefore energy trading in one
part has a significant part on another part. There are, however, naturally bottlenecks in the
system that prevent unhindered flow of energy – termed congestion. These do not
necessarily (and, in the case of the continental and Nordic synchronous areas) follow
Member State borders.
The Third Package already contains provisions relating to congestion management,
requiring procedures to be put in place, which is further elaborated by the CACM
Guideline. It is important to have a harmonised approach to the management congestion in
order to manage it cost-effectively across the market and allow for maximum cross-border
trading.
Markets are split based on price zones, where the wholesale price is the same for each
given timeframe. These provide locational signals for dispatch and investment.
Whilst the Third Package has achieved much, further action is needed at the EU-level –
price zones based on Member State borders do not reflect the actual locational need for
investment or demand for energy in a particular location. More coordinated action is
therefore necessary to direct dispatch of energy and investment in infrastructure based on
where it is needed and will provide most benefit to the EU interconnected system as a
whole. This will become increasingly important with more and more variable sources of
generation coming online over the coming years.
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Action is already underway reviewing the structure of price zones in the EU. However, the
decision-making is still left at the national level, which lends itself to maintenance of the
status quo, which can have negative cross-border impacts (such as unscheduled flows of
energy from one country to another as a result of inefficient price signals).
Stakeholders' opinions
A large number of respondents to the Energy Market Design consultation agreed that
energy prices should not only relate to time, but also locational differences in scarcity (e.g.
by meaningful price zones or locational transmission pricing). While some stakeholders
criticised the current price zone practice for not reflecting actual scarcity and congestions
within bidding zones, leading to missing investment signals for generation, new grid
connections and to limitations of cross-border flows, others recalled the complexity of
prices zone changes and argued that large price zones would increase liquidity.
WindEurope (formally EWEA) commented that "[w]holesale electricity prices reflecting
scarcity and physical constraints, including transmission capacity, are desirable in a fully
functional electricity market. This is already expressed in the present zonal pricing model
inside bidding zones and between bidding zones where price differentials signal the need
for transmission investments."
In their joint response to the consultation, ACER/CEER stated that "[p]rices reflecting
scarcity (both in terms of time and location) of generation resources in each bidding zone
of organised markets in the different timeframes (day-ahead, intraday and balancing)
should become a key ingredient of the future market design."
EURELECTRIC "generally favours larger bidding zones as they present more advantages
for the functioning of the market and its liquidity, however bidding zone configuration
should duly take into account the grid capacity. Zones should respect structural
bottlenecks that do not necessarily correspond to national borders."
The European Association for Storage of Energy (EASE) said that "[p]rices need to reflect
the physical limitations of the grid in order to deliver optimal locational signals for
investment, consumption and production."
Another is example is that of Norderegi, who view is that "[f]undamentally, the borders
between Bidding Zones should be based on the physical characteristics of the power
system. Bidding Zones should be aligned with where structural constraints occur. Leading
principle is that cross border trade must not be restricted. Moving internal national
transmission bottlenecks to national borders must not be used as a congestion management
method."
On the other hand, some stakeholders highlight risks to changes in price zone
configuration. For example, the European Energy Exchange (EEX) states that "The
development towards large, cross-border bidding zones supports the efficiency of the
power system by integrating markets. Supply and demand can be brought together more
efficiently. The prerequisite for this is grid expansion. Delayed or insufficient grid
expansion even in a national context has a negative impact on the market as a whole, as is
currently seen in the discussion of splitting the German/Austrian bidding zone. Such a
decision would be a huge step back in the creation of the internal market, splitting
Europe’s most liquid bidding zone, decreasing the possibilities of risk mitigation and
eventually causing higher energy prices for consumers."With regards to congestion
management, there have been significant concerns raised by industry about the practice of
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limiting cross-border capacity to deal with internal congestion. For example, Nordenergi
have said, in a public letter to the European Commission, that the "principle that
congestion needs to be managed where it occurs must be maintained as the governing rule
in an internal market, and this principle does not allow for congestion to be moved to
national borders in the extent and in the non-transparent manner that seems to be the case
on the mentioned Nordic borders" and that "besides the continuous welfare losses due to
curtailments of cross-border capacities, there are in addition severe long-term negative
effects through inefficient investment signals to both generators, consumers and TSOs."
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4.3. Minimise investment and dispatch distortions due to transmission tariff
structures
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Summary table
Objective: to minimise distortions on investment and dispatch patterns created by different transmission tariffs regimes.
Option 0: Business as usual Option 1: Restrict charges on
producers (G-charges)
Option 2: Set clearer principles for transmission
charges
Option 3: Harmonisation
transmission tariffs
Description
This option would see the status quo
maintained, and transmission tariffs set
according to the requirements under Directive
72 and the ITC regulation.
Stronger enforcement and voluntary
cooperation:
There is no stronger enforcement action to be
taken that would alone address the objective.
Voluntary cooperation would, in part, be
undertaken as part of implementation of
Option 2.
This option could see the prohibition of
transmission charges being levied on
generators based on the amount of energy
they generate (energy-based G-charges)
This option would see a requirement on ACER to
develop more concrete principles on the setting of
transmission tariffs, along with an elaboration of
exiting provisions in the electricity regulation where
appropriate.
Full harmonisation of
transmission tariffs.
Pros
Pros: Minimal change; likely to receive some
support for not taking any action in the short-
term.
Eliminating energy-based G-charges
would serve to limit distortionary effects
on dispatch of generation caused by
transmission tariffs. Social welfare
benefits of approximately EUR 8 million
per year. Would impact a minority of
Member States (6-8 depending on design).
Provides an opportunity to move in the right
direction whilst not risking taking the wrong
decisions or introducing inefficiencies because of
unknowns; consistent with a phased-approach; could
eliminate any potential distortions without the need
to mandate particular solutions; consistent with the
introduction of legally binding provisions in the
future, e.g. through implementing legislation.
Minimises distortion between
Member States on both
investment and dispatch;
creates a level-playing field.
Cons
In the longer-term, likely to be a drive to do
more and maintaining the status quo unlikely
to be attractive; risks of continued divergence
in national approaches.
Social welfare benefits relatively small –
could be outweighed by transitional costs
in the early years. Can be considered
'incomplete' as a number of other design
elements of transmission tariffs contribute
to distortionary effects.
Still leaves the door open for variation in national
approaches; will not resolve all potential issues.
Unlikely to a proportionate
response to the issues at this
stage; given the technicalities
involved, it could be more
appropriate to introduce such
measures as implementing
legislation in the future.
Most suitable option(s): Option 2 – aside from some high-level requirements, given the complexity of transmission charges, the precise modalities should be set-out as part of
implementing legislation in the future if and when appropriate. The value in Option 2 will be to set the path for the longer-term.
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Description of the baseline
Tariffs are charged on demand and/or production in order to recover the costs associated
with building, maintaining and operating transmission and distribution infrastructure. They
can be used merely as a cost recovery tool, but also as a means to incentivise investments
and behaviours. They also have the potential to have distortionary effects. In this annex,
the focus is on the design of transmission tariffs, with distribution tariffs discussed further
in Annex 3.3. However, there are potentially important interactions, which are touched on
further below.
There are a number of decisions that regulatory authorities can take on the design of tariffs.
These are summarised below:
Figure 1 – building blocks of transmission tariffs
Source: Cambridge Economic Policy Associates Ltd for ACER.
The Third Package, and more specifically the Electricity Directive and Electricity
Regulation, contain specific provisions for the charging of transmission tariffs.
Requirements under the Directive include that tariffs, or the methodologies for calculating
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them, must be fixed or approved by NRAs in accordance with transparent criteria20
and
sufficiently in advance of their entry into force21
.
Article 14 of the Electricity Regulation provides further requirements, which include:
- that "[c]harges applied by network operators for access to networks shall be
transparent, take into account the need for network security and reflect actual costs
incurred insofar as they correspond to those of an efficient and structurally
comparable network operator and are applied in a non-discriminatory manner;" and
- that, "[w]here appropriate, the level of the tariffs applied to producers and/or
consumers shall provide locational signals at Community level, and take into account
the amount of network losses and congestion caused, and investment costs for
infrastructure."
More specific requirements are provided for under the inter-transmission system operator
compensation mechanism ("ITC") regulation22
. This regulation sets down limits on the
average annual transmission charges that can be applied in each Member States to
electricity producers23
. The regulation also required ACER to provide an opinion to the
Commission regarding the appropriateness of the range of charges, which it did on 15th
April 2014.
In the opinion, ACER stated that it deemed it important that charges on generators ("G-
charges") are "cost-reflective, applied appropriately and efficiently and, to the extent
possible, in a harmonised way across Europe." It recommended that: G-charges based on
energy produced (energy-based) should not be used to recover infrastructure costs; energy-
based G-charges should be set at 0 euros/MWh, except where they are used for recovering
the costs of system losses or costs relating to ancillary services. They concluded, however,
that it was unnecessary to propose restrictions on charges based on connected capacity of
the generation (what they term power-based charges) or fixed (lump sum) charges.
However, prior to this opinion, a report by Frontier Economics for Energy Norway,
published in May 201324
, concluded that the potential for welfare loss is significant, with
effects on investment more significant than operational decisions, and strong welfare
losses result from a lack of harmonisation.
Subsequently, and with the possibility existing to develop a 'network code25
' to harmonise
transmission tariffs, ACER commissioned a scoping study from Cambridge Economic
Policy Associates Ltd (CEPA), which was finalised in August 2015. CEPA concluded that,
whilst there are theoretical distortions introduced by different charging regimes in different
Member States, the benefits of a short-term regulatory response (e.g. harmonising through
20
Art 37(1)(a)
21
Art 37(6)(a)
22
Commission Regulation (EU) No 838/210 of 23 September 2010 on laying down guidelines relating to
the inter-transmission system operator compensation mechanism and a common regulatory approach to
transmission charging, OJ L 250 24.09.2010, p5-11
23
0-2 EUR /MWh in Romania; 0-2.5 EUREUR /MWh in UK and Ireland; 0-1.2 EUR/MWh in Denmark,
Sweden and Finland; and 0-0.5 EUR/MWh in all other Member States.
24 "
Transmission tariff harmonisation supports competition", a report prepared for Energy Norway, May
2013
25
A Commission Regulation developed under procedures laid down in the Electricity Regulation.
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a network code) were unlikely to outweigh the potential costs of change. However, they
also concluded that in the longer-term, there is a stronger case for further harmonisation
"principally based on the need for greater consistency and application of "optimal" tariff
structure that reflect the costs generating by market participants' decisions."
Figure 2 – Connection and generation tariffs in various countries
Source: Cambridge Economic Policy Associates Ltd for ACER, based on analysis of ENTSO-E data.
Deficiencies of the current legislation
As detailed above, a framework for transmission tariffs is provided for in the Electricity
Directive, Electricity Regulation and in the ITC Regulation26
. These all provide significant
scope for national differences without a view on how any potential negative or
distortionary impacts can be resolved. Further, the ACER recommendation has not been
implemented into the ITC Regulation.
The Evaluation Report points out that "whilst the Third Package contains provision on
transmission tariffs, their level and design still differ significantly between Member States.
This has the potential to distort price signals."
Presentation of the options
Option 0 – BAU
This option would involve maintaining the status quo, and the provisions relating to tariffs
in the Third Package and associated legislation would remain the same.
26
Commission Regulation (EU) No 838/2010 of 23 September 2010 on laying down guidelines relating
to the inter-transmission system operator compensation mechanism and a common regulatory approach
to transmission charging, OJ L 250, 24.9.2010, p. 5–11
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Option 0+: stronger enforcement and voluntary cooperation
There is no additional enforcement action to take that would address the points above.
Option 2 would entail a level of voluntary cooperation as part of its implementation – i.e.
that regulatory authorities voluntarily work towards implementation of key principles
developed by ACER in advance of further legally binding obligations.
Option 1 - Restrict charges on producers (G-charges)
This option would involve eliminating energy-based transmission charges that can be
charged on producers (except where they are used for recovering the costs of system losses
or costs relating to ancillary services), as set out in the ACER opinion. It would have an
effect in the following Member States, who apply such charges27
.
- Denmark
- Finland
- France
- Portugal
- Romania
- Spain
In implementing this option, those Member States would have a choice as to how they then
treat generators. They could either remove charges on generators all together, meaning that
all tariffs would be charged to consumers, or they could replace them with alternative
tariffs, namely ones based on the capacity or a lump-sum tariff. For the purposes of this
analysis, it is assumed that these Member States continue to levy charges on generators.
Option 2 - Introduce more extensive and concrete principles on the setting of transmission
charges
This option would involve giving responsibility to ACER to develop guidance addressed
to national regulatory authorities, which would be developed over a time frame of 1-2
years. It would provide a basis on which NRAs could make their decisions with a view to
more concrete legal measures in the future, notably though implementing legislation such
as a network code or guideline. Such principles could relate to: the definition and
implementation of cost-reflectivity; charges applied to consumers versus charges applied
to producers; the types of costs which are to be included; locational and/or time-of-use
element of charges; and principles relating to transparency and predictability. It would be
accompanied by some higher-level principles in legislation, for example requiring
regulatory authorities to minimise any distortions between transmission and distribution
tariffs - e.g. on their impact on generators.
Option 3 - Full harmonisation
This option would not only see the process and criteria harmonised but also the components
and levels of transmission charges so that the charges on load and production and
comparable in each Member States. This would include the elaboration of a harmonised
27
Excluding Austria and Belgium, who apply energy-based charges for ancillary services and/or losses
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definition of cost-reflectivity, so that all Member States charge producers and/or
consumers on the same basis. Further, it would ensure that costs related to ancillary
services and losses are treated in the same way.
This option could be accompanied by a requirement that transmission charges include a
locational element reflecting, in particular, transmission constraints within a price zone.
Comparison of the options
G-Charges
The option to remove energy-based transmission tariffs on generators has been assessed
quantitatively based on ECN's COMPETES model28
. COMPETES is a power optimisation
and economic dispatch model that seeks to minimise the total power system costs of
European power market whilst accounting for the technical constraints of the generation
units, transmission constraints between the countries as well as transmission capacity
expansion and generation capacity expansion for conventional technologies for given
generation intermittency (e.g., wind, solar) and RES E penetration in EU Member States.
The model also decommissions the existing conventional power plants that cannot cover
their fixed costs.
In order to provide a frame of reference, three scenarios were assessed as regards the
change on total system costs29
, TSO surplus30
, payments by consumers31
and producer
surplus32
for a reference year of 2030:
- Reference case where no tariffs are charged. Implicitly, therefore, all the
transmission costs are covered by congestion income and electricity prices charged
to consumers - this was created for the purposes of assessing the options below, as
opposed to being an option itself.
- Option 0: Reflecting the current situation with different G-tariffs per country
(Euro/MWh or Euro/MW differing per country). The tariffs are taken from the
ACER internal G-charges monitoring report.
- Option 1: Implementing capacity-based tariffs only in which case energy-based
Euro/MWh tariffs of Option 0 are converted to Euro/MW capacity-based tariffs.
A figure for the total social welfare was calculated as {Change in TSO surplus + Change
in Producer surplus - Change in Consumer payments}. The results for the total and
comparison of the options are provided in table 1 and 2 respectively.
Table 1 – total values, all countries (million EUR)
System
Costs
TSO
surplus
Consumer
payments
Producer
surplus
Reference (no tariffs) 85,082.2 2,102.3 226,821.0 138,455.7
28
" Transmission Tariffs and Congestion Income Po6licies", ECN, DCision, Trinomics (Intermediate
Report)
29
Generation OPEX + Generation CAPEX + Fixed O&M + Transmission Investment
30
G-charge payments + Congestion income - Transmission CAPEX
31
Payments consumers make for their electricity use, i.e. electricity use (in MWh) x electricity price (in
Euro/MWh)
32
Short run profits - Gen CAPEX - G-charge payments
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Option 0 (current
situation) 85,094.7 3,044.6 227,617.6 138,282.9
Option 1 (cap.-based
tariffs) 85,094.0 2,875.1 227,298.2 138,141.1
Table 2 – option comparison, all countries (million EUR)
System
Costs
TSO
surplus
Consumer
payments
Producer
surplus
Social
welfare
Option 0 vs
Reference 12.5 942.3 796.6 -172.8 -27.1
Option 1 vs
Reference 11.8 772.8 477.2 -314.6 -19.0
Option 1 vs
Option 0 -0.8 -169.5 -319.4 -141.8 8.1
Moving from the current system (Option 0) would result in an increase in economic
efficiency of generation dispatch and investment decisions as well as overall competition
between generators. More specifically, there would be some limited effect on dispatch and
investment decisions of generators in countries that have to replace energy-based by
capacity-based or lump sum G-charges. On the other hand, decisions of generators in
countries that currently either have no energy-based G-charges or only non-energy based
G-charges in place would not be affected. Cross-border competition between generators is
likely to induce regulatory competition between Member States and, as such, likely to
serve as an implicit upper limit to all types of G-charges, preventing larger divergence of
within the EU. However, this this does not imply that G-charges will be set to their optimal
long-run cost-reflective level i.e. the level that stimulates generators and consumers to take
investment and siting decisions that minimise overall system costs, which is the sum of
generation, network, and societal costs. Rather it is likely that the G-charges of the largest
Member States in Continental Europe become the benchmark. In the absence of incentives
for multilateral coordination of country practices regarding transmission charges for
generators (either regional or EU-wide), this option can therefore be considered as
incomplete. As can be seen from the above, the social benefits of moving from the current
system would be in the region of EUR 8 million a year – a small proportion of overall
system costs. This risks being outweighed by implementation costs.
Principles for transmission charges
It is naturally more difficult to quantitatively assess the impacts of this option, as they will
by-and-large depend on the precise design of such principles and the extent to which they
are implemented prior to any legal mandate (e.g. from implementing legislation such as a
network code). Therefore this option is assessed qualitatively.
A harmonisation of the tariff principles to better reflect the grid costs will have a positive
impact on the efficiency of dispatch and investment decisions by generators. Concerning
the latter, harmonised tariff principles will improve the investment climate for power
generation by offering a higher predictability with regard to the expected tariff
development. It will overall reduce competition distortions amongst generators, but the
impact of tariff harmonisation on the competitiveness of individual generators can be
positive or negative depending on the current situation.
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As discussed above, there are a number of issues that need to be addressed in the design of
tariff structures. These include the extent to which charges are applied to generators as
compared to consumers (the Generation: Load or "G:L" split), the basis on which they are
charged, the interpretation of the principle of 'cost reflectivity,' whether there are signals
on location or time of use, etc. Whilst the discussion here has mostly been focused on
generators and the wholesale market, a significant proportion of transmission tariffs on are
charged on consumers/load – all Member States apply charges to load, with some applying
all of them (15). Therefore the design of tariff structures can have a significant impact on
consumers, both financially and economically, and on their behaviour. There are clearly a
number of complexities which will need discussion among regulators, TSOs and
stakeholders to determine the most beneficial approach.
Despite the fact that national tariff differences are only one of the drivers of current
distortions of dispatch and investment decisions between Member States, the focus on cost
reflectivity of transmission signals is key in an increasingly interconnected system in order
to prevent negative spill-over effects.
Harmonisation
Full harmonisation would involve decisions on many of the same topics as mentioned
above, but determining them in legislation immediately. It would require upfront decisions
on the 'optimal' tariff structure, something that so far has not been determined with a clear
articulation of the benefits. As mentioned above, there already exists a legal mechanism
for harmonising tariffs – Article 8 of the Electricity Regulation already provides the ability
to create implementing legislation, in the form of a network code, something that would
be developed collaboratively by TSOs, regulators, ACER and stakeholders. Doing this as
part of Market Design is very unlikely to elicit better results than could be achieved with
the detailed and ongoing participation of experts that the development of a network code
would involve. Further, flexibility would be compromised. Given the complexity and the
amount of 'unknowns' there is a significant risk that any attempt to fully harmonise would
result in issues that could only be identified once Member States start to implement the
requirements; a network code allows for significantly more flexibility to respond to such
issues if and when they arise. Requirements set out in an ordinary legislative act would
prove much more difficult to adapt.
There are two sub-issues that have also been considered as part of this option: that of
harmonised charges relating to ancillary services and grid losses; and locational-charging.
There is significant diversity in charging methodologies with regards to ancillary services.
For instance, in most Member States, all costs for balancing services are recovered via
charges on load. Only in a few Member States do generators pay grid charges that comprise
a specific contribution for the cost related to balancing services33
. With regards to grid
33
Austria (2.81 EUR/MWh in 2015), Belgium (0.9111 EUR/MWh, which represents 50 % of the overall
reservation cost for balancing services), Bulgaria (3.65 EUR/MWh to be paid only by wind and solar
generators to cover the cost for balancing services), Finland (0.17 EUR/MWh), Ireland (0.3 EUR/MWh),
Northern-Ireland (0.31 EUR/MWh), Norway (0.21 EUR/MWh – the costs for procuring balancing
services are in Norway divided equally between generation and load) and Sweden (0.087 EUR/MWh).
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losses, again most European countries recover them through charges on load, but in a few
countries the related cost is partly or fully charged to generators34
.
If charges for ancillary services were to be harmonised, the impact on short-term and long-
term electricity system efficiency would depend on the level of the charges and the
charging modalities but may not be substantial. If charges for ancillary services were to be
more correctly and transparently allocated to the market parties (generation and load) on
basis of needs of the parties, market operators would contribute to minimising the overall
need for such services, particularly frequency-related services, with more flexible demand
and supply. It could, however, contribute to a higher cost-reflectiveness and fairer cross-
border competition amongst generators as the currently diverging charging practices and
cost allocation can lead to competition distortions between power generators active in the
same integrated regional market.
The impact of a harmonised charging method of grid losses via a specific tariff on the
short-term and long-term electricity system efficiency would be very limited. Only if grid
losses are calculated and charged individually to grid users would there be a higher impact
on the short and long-term system efficiency. There is, however, scope to correct
competitive distortions on generators, although this will only have an impact in those few
Member States where losses are (partly) charged to generators; in the large majority of
Member States grid losses are entirely charged to load.
With regard to providing appropriate locational signals for investment and dispatch of
generation through tariffs, clearly this can only be achieved where generators are charged
tariffs (so in 12 Member States) and, with regards to the latter, only where there is energy-
based charging (8 Member States). Administratively setting tariffs to affect dispatch could
add significant distortions into the energy market and requiring this is not an option that is
explored further. As to investment signals, i.e. making it more expensive to locate in areas
of less need, and less expensive in areas of higher need, proponents would argue that it
gives economic signals about where to site new generation capacity and use existing
capacity, and that it reflects the costs to the transmission network that generators cause.
However, opponents believe that locational charging is designed to reflect a generating
mix predicated on generation close to centres of demand and not designed to encourage a
fundamental shift to more mixed and geographically spread energy supply. Any concrete
impact of location-based charging on economic efficiency will largely depend on the level
of the fee and its form, and it is not clear that this would override other factors influencing
siting (regulatory, planning, meteorological, etc.). Further, it is potentially complex to
implement and could add uncertainty to generators. If price zones are formed based on
structural congestion, part of an objective of Market Design (see Annex 4.2) this could
anyway remove the need to introduce locational signals by other means – i.e. as the energy
In Great Britain, the costs incurred by the TSO (NGET) in balancing the transmission system are
recovered through Balancing Services Use of System (BSUoS) Charges, which are shared equally
between generators and suppliers. ACER, Internal Monitoring Report on Transmission charges paid by
the electricity producers, May 2016.
34
Austria (0.45 EUR/MWh in 2015), Belgium (balancing responsible parties are obliged to inject,
depending on the time, 1.25 or 1.35 % more than their offtake from the grid), Greece (average = 1.08
EUR/MWh based on zonal Generation Losses Factors), Ireland and Northern-Ireland (1.36 EUR/MWh),
Norway (average = 0.57 EUR/MWh based on marginal loss rates which are different depending on the
location and the time), Romania (0.23 EUR/MWh) and Sweden (0.40 EUR/MWh) - ACER, Internal
Monitoring Report on Transmission charges paid by the electricity producers, (May 2016).
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price would provide such signals. This is not to say that the approach is not succeeding in
those countries that already employ it (e.g. GB, Sweden) or that it is definitely unsuitable
for the future, but rather that the first step should be to implement appropriate defined price
zones and that further, detailed consideration is needed at the regulatory level on whether
and how to implement such an approach. It is, therefore, not considered an appropriate
response to design or mandate its introduction as part of this legislative package.
Summary
Given the number of design features and complexities regarding transmission tariffs, and
the potentially small benefits associated with harmonising the less-complex aspects
individually, it is concluded that the most appropriate option is to leave any full
harmonisation to future implementing legislation as part of a network code or, if
appropriate, through an amendment to existing implementing legislation35
. This will
minimise disruption and implementation costs, allow the precise package to be worked up
over time and with full involvement of experts, and also allow for the interactions between
distribution tariffs and transmission tariffs, and their impacts on consumers and generators
at both connection-levels, to be more fully reflected. Further, it will allow time to
determine the most beneficial approach and tackle the most significant issues holistically.
The development of principles to guide NRAs when designing tariffs regimes (Option 2)
would provide the first step in this process, and facilitate early decisions and
implementation prior to any legally binding instrument. As the topic falls within the
regulators' field of competence, this would be appropriately led by ACER. Further,
augmentation of the high-level principles in the Electricity Regulation is necessary to
reflect evolution of the market since they were originally introduced, for example to avoid
any discrimination between distribution-connected and transmission-connected generation
when setting or approving tariffs.
Subsidiarity
Charges applied to generators in relation to their connection to, and use of, networks can
be significant. Differences in these charges can therefore have an effect on decision-
making, whether it is on investment locations or on dispatch of energy, and can therefore
add distortions into the market. Given the highly integrated nature of EU electricity
markets, this can add distortions between Member States.
EU-level action is therefore warranted, in order to ensure the minimum degree of
harmonisation needed to avoid distortion in investment and generation is achieved. The
Third Package already lays down a number of rules relating to these changes (notably
Article 14 of the Electricity Regulation), and also requires NRAs to take an active role
(under the Electricity Directive). Further provisions relating to transmission tariffs are
contained in the inter-transmission system operator completion mechanism (ITC)
Regulation, aimed at the issues mentioned above.
Whilst much has been achieved, there is still scope for improvement, particularly given the
importance of minimising distortions to the benefit of consumers. EU-action is needed to
addresses this as it needs to be coordinated across the EU.
35
E.g. changes to G-charges could be effected by amending the ITC regulation.
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Stakeholders' opinions
Stakeholder feedback suggests there is a case for change, particularly in the medium to
long-term. In 2015, ACER ran an exercise looking at potential harmonisation of tariffs
through the development of a network codes. This included stakeholder questionnaires
(run by Cambridge Economic Policy Associated – CEPA). In their report, CEPA
highlighted a number of points:
- The majority of stakeholders (79 responses) across European countries consider
that the current electricity transmission tariff structures do impact on the efficient
functioning of the European electricity market;
- Around 80% of respondents agreed that generators’ operational and investment
decisions are affected by transmission tariff structures;
- The majority of respondents also considered differences in current transmission
tariff structures across Europe to be a source, or a potential source, of regulatory
and market failure in the IEM. Differences in transmission tariff structures across
European countries were identified by stakeholders as a problem today and
potentially in the future, citing distortions to operational (as well as investment
decisions) as a source of regulatory or market failure;
- Over 60% of respondents also agreed or strongly agreed that differences in
transmission tariff structures across European countries could hamper cross-border
electricity trade and/or electricity market integration. Energy-based tariffs were
cited as a particular issue;
- Around 70% of respondents believed that there are benefits that can be achieved
through harmonisation of transmission tariff structures. Only 7% of all respondents
rejected the idea that harmonisation of transmission tariffs would be beneficial for
the IEM;
Further, Eurelectric, in their market design publication36
, state that "[r]egarding
transmission tariffs applied to generators, their structure and methodologies to compute
the costs need to be harmonised. Furthermore, their levels should be set as low as possible,
in particular the power based charges (€/MW) which act as a fixed cost for generation and
therefore distort investment decisions."
36
"Electricity market design: Fit for the low carbon transition," Eurelectric (2016)
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4.4. Congestion income spending to increase cross-border capacity
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Summary table
Objective: The objective of any change should be to increase the amount of money spent on investments that maintain or increase available interconnection capacity
Option 0: Business as usual Option 1 Option 2 Option 3
Description
This option would see the current situation
maintained, i.e. that congestion income can be
used for (a) guaranteeing the actual availability of
allocated capacity or (b) maintaining or
increasing interconnection capacities through
network investments; and, where they cannot be
efficiently used for these purposes, taken into
account in the calculation of tariffs.
Stronger enforcement: current rules do not allow
for stronger enforcement.
Voluntary cooperation: would offer no certainty
that the allocation of income would change.
Further prescription on the use of
congestion income, subjecting its use
on anything other than (a)
guaranteeing the actual availability of
allocated capacity or (b) maintaining
or increasing interconnection
capacities (i.e. allowing it to be offset
against tariffs) to harmonised rules.
Require that any income not used for (a)
guaranteeing availability or (b) maintaining
or increasing interconnection capacities flows
into the Energy part of CEF-E or its
successor, to be spent on relieving the biggest
bottlenecks in the European electricity
system, as evidenced by mature PCIs.
Transfer the responsibility of using the
revenues resulting from congestion and
not spent on either (a) guaranteeing
availability or (b) maintaining
capacities to the European
Commission. De facto all revenues are
allocated to CEF-E or successor funds
to manage investments which increase
interconnection capacity.
Pros
Minimal disruption to the market; consumers can
benefit from tariff reductions – unclear whether
benefits of better channelling income towards
interconnection would provide more benefits to
consumers, given that it may offset (at least in
part) money spent on interconnection from other
sources.
More guarantee that income will be
spent on projects that increase or
maintain interconnection capacity and
relieve the most significant
bottlenecks; could provide around
35% extra spend; approach reflects
the EU-wider benefits of electricity
exchange through interconnectors; can
be linked to the PCI process.
Guarantees that income will be spent on
projects that increase or maintain
interconnection capacity and relieve the most
important bottlenecks; could provide up to
35% extra spend; approach reflects the EU-
wider benefits of electricity exchange
through interconnectors; firm link with the
PCI process.
Best guarantee that income will be
spent on the biggest bottlenecks in the
European electricity system, ensuring
the best deal for European consumers
in the longer run; approach reflects the
EU-wider benefits of electricity
exchange through interconnectors; to
be linked to the PCI process.
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Cons
Missing a potentially significant source of income
which could be spent on interconnection and
removing the biggest bottlenecks in the EU.
Restricts regulators in their tariff
approval process and of TSOs on
congestion income spending.
Additional reporting arrangements
will be necessary.
Requires stronger role of ACER.
Restricts regulators in their tariff approval
process and of TSOs on congestion income
spending.
Could mean that congestion income
accumulated from one border is spent on a
different border or different Member States.
Additional reporting arrangements will be
necessary.
Requires stronger role of ACER.
Could prove complicated to set up such
an arrangement; could mean that
congestion income accumulated from
one border is spent on a different
border or different Member States.
Requires a decision to apportion
generated income to where needs are
highest in European system. Will face
national resistance.
Will require additional reporting
arrangements to be put in place.
Requires stronger role of ACER.
Most suitable option(s): Option 2 – provides additional funding towards project which benefit the EU internal market as a whole, while still allowing for national decision making in the
first instance. Considered the most proportionate response.
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Description of the baseline
Congestion37
income arises across an interconnection due to price differences on each side
of it. Such effects happen between price areas (i.e. bidding zones), as opposed to between
Member States. The higher the price difference, the greater the income generated.
Conversely, the greater the levels of interconnection, the more arbitrage opportunities and,
therefore, the lower the price differences each side. Congestion income per MW is
therefore lower.
The issue of optimising interconnection capacity from a private versus social cost-benefit
perspective has been analysed, among others, by De Jong and Hakvoort (2006; see also De
Jong, 2009).38
They show that, under certain assumptions (two-node network with perfect
competition and linear supply and demand curves), the capacity that maximises social
benefits is twice the capacity that maximises private benefits. This relationship changes a
bit, however, when investment costs are also taken into account. In that case, De Jong and
Hakvoort show that the interconnection capacity that maximises social value exceeds the
capacity that maximises private profits by even more than a factor of two.
Figure 1 - Optimum interconnection capacity from a social versus private benefit
perspective
37
The term ‘congestion’ means a situation in which an interconnection linking national transmission
networks cannot accommodate all physical flows resulting from international trade requested by market
participants, because of a lack of capacity of the interconnectors and/or the national transmission systems
concerned.
38
De Jong, H., and R. Hakvoort (2006), Interconnection Investment in Europe – Optimizing capacity from
a private or a public perspective ?, in : Proceedings of Energex 2006, the 11th international energy
conference and exhibition, 12-15 June 2006, Stavanger, Norway, pp. 1-8. De Jong, H. (2009), Towards
a single European electricity market – A structural approach to regulatory mode decision-making,
Ph.D.-thesis, Technical University Delft, the Netherlands.
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Source: De Jong (2009), p. 261 (see also De Jong & Hakvoort, 2006))
Congestion income from interconnection capacity is a major source of revenues for TSOs'
investment in network expansion. Therefore, in theory, TSOs will invest in new
interconnection capacity as long as the congestion income outweighs the investment and
operational costs (including a reasonable rate of return) and the potential decrease of
congestion income on existing cross zonal interconnectors in the case that the new
interconnector serves as a substitute to existing interconnectors. From a social point of
view, this may result in underinvestment in interconnection capacity and, hence, in a sub-
optimal level of cross-border transmission capacity.
Partly to address this, Article 16 of the Electricity Regulation seeks to restrict how
congestion income can be used39
. Specifically, it only allows it to be used to:
1. guarantee the availability of allocated interconnection capacity;
2. maintaining or increasing interconnection capacities through network
investments, in particular in new interconnectors;
3. to be offset against network tariffs; or
4. held on account until it can be spent on one of the above.
According to data from ENTSO-E, the total amount of TSO net revenues from congestion
management on interconnections was EUR 2.3 billion in 2014 and EUR 2.6 billion in
2015. Figure 2 presents the spending of congestion revenues in 2014-15 aggregated for all
members of ENTSO-E, both in million EUR and as a % of total annual revenues. These
revenues amounted to, on average, EUR 2.275 million per annum in 2014-2015. Figure 2
shows that out of this amount, on average, EUR 374 million was spent on capacity
guarantees (16%), EUR 817 million on capacity investments (36%), EUR 804 million on
reducing transmission tariffs (35%) and EUR 280 million saved on an account (12%). This
implies that, on average, about half of the congestion revenues in 2014-15 were used to
guarantee, maintain or increase interconnection capacity and, hence, that – in principle –
there is room for increasing this share by alternative Options.
It should be noted, however, that changing the rules on spending of congestion income
may not by itself be sufficient to stimulate investment in relieving the biggest bottlenecks
in the EU. There are a number of reasons why investment in interconnection capacity might
not be forthcoming: they are complex projects with a number of socio-economic impacts,
and often face barriers relating to, for example, planning; the decisions are complex, and
often require the involvement of two or more parties; additional investments may be
needed in national networks in order to accommodate new capacity. Further, TSOs are able
to cover the investment and operational costs of interconnectors – which are approved by
their NRAs – not only from congestion revenues but also, or even exclusively, from
regulated transmission tariffs. Therefore, there is theoretically already a source of funding
for such projects, although in practice the regulated tariff system may be considered too
restrictive for socially optimal investments in interconnection capacity, for instance
because certain costs may not be approved to be part of the regulated cost base, or because
39
In the case of new interconnectors, exemptions can be given to these requirements subject to a number
of conditions being fulfilled.
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the allowed rate of return may be considered too low to cover the risks, uncertainties or
other challenges involved.
Figure 2- Spending of congestion revenues in 2014-15 (in million EUR and as % of
total annual revenues for all countries)
Source: ENTSO-E (2014-15)
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Deficiencies of the current legislation
Current legislation is not providing for sufficient investments in bottlenecks within the
European electricity system. Whilst, as highlighted above, this is unlikely to be due, at
least solely, to how congestion income is spent, there is clearly scope for significantly more
funding to be directed toward this ends from congestion income. As demonstrated from
the above figures, the amount spent on increasing or maintaining interconnection capacity
is less than half of the available funds. Further, despite existing bottlenecks and
interconnection levels well below the optimum ones, the legislation offers incentives to
NRAs to retain congestions, as the income they generate can be used to lower national
tariffs. There are also significant deficiencies in transparency with regards to the spending
of congestion income. Whilst current legislation contains obligations relating to
transparency, this is ineffective in practice and it proves difficult to assess how the
provisions of Article 16 are being applied. For example, it is unclear:
- how the TSOs decide on the use of congestion revenues for either guaranteeing,
maintaining or increasing interconnection capacity;
- whether and how the NRAs check (i) that TSOs have used congestion revenues
efficiently for either guaranteeing, maintaining or increasing interconnection
capacity, and (ii) that the rest of the revenues cannot be efficiently used for these
purposes;
- on which criteria the NRA decides on the maximum amount used as income to be
taken into account when approving or fixing network tariffs;
- how the congestion revenues are used during the period they are put on a separate
account;
- the projects towards which the funds are being allocated, including the split
between investments towards capacity maintenance and capacity increases.
The Evaluation Report points out that "another problem is the lack of adequate and
efficient investment in electricity infrastructure to support the development of cross-border
trade. ACER's recent monitoring report and other reports on the EU regulatory framework
stress that the incentives to build new interconnections are still not optimal. In the current
regulatory framework, TSOs earn money from so-called congestion rents. If TSOs reduce
congestion between two countries, their revenues will therefore decrease. The Third
Package has identified this dilemma and addressed through obliging TSOs to use
congestion rents either for investments in new interconnection or to lower network tariffs.
Experience with this rule has, however, shown that most TSOs prefer to use congestion
rents to lower their tariff to investing into new interconnectors."
Presentation of new measures/options
Option 0 – Do nothing.
This would maintain the status quo, i.e. rules on spending covered by Article 16 of the
Electricity Regulation. The methodology currently being developed under the Capacity
Allocation and Congestion Management regulation (CACM) would provide the main rules
on how the income is allocated between TSOs on each border.
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Option 0+: Non-regulatory approach
Stronger enforcement of existing rules will not allow an improvement of the current
situation.
Voluntary cooperation will provide no certainty that there will be a change in the current
allocation of congestion income. Given there are already rules in place, a change to these
rules is needed to address the issue.
Option 1 – Harmonised use of congestion income
The first option would maintain all the options for the use of congestion income as already
provided for in the regulation, but be more prescriptive about when it can be taken into
account in the calculation/reduction of network tariffs. More specifically, it would require
that its use on anything other than (a) guaranteeing the actual availability of allocated
capacity or (b) maintaining or increasing interconnection capacities be subject to
harmonised rules developed by ACER.
These rules would clearly define the situation when, and when not, the alternative options
could be pursued. Indicatively, the possibility to decrease the network tariff through
congestion income would be allowed only when there is clear and justified evidence,
according to the ACER rules, that there are no cost-effective projects that would be more
beneficial for social welfare than tariff reduction. Rules would also detail how long/which
revenues could be kept in internal accounts until they can be effectively spent for the above
purposes.
This option would be combined with more transparency and additional rules for
publication and monitoring of this spending.
Option 2 – Harmonised use of congestion income with basic CEF option
The second option would, similarly, restrict spending to (a) guaranteeing availability or (b)
maintaining or increasing interconnection capacities. If the income cannot be effectively
used on (a) or (b), it would flow into the Connecting Europe Facility for Energy (CEF-E)
or its successor, and be spent on relieving the biggest bottlenecks in the European
electricity system, as evidenced by mature PCIs. Unlike Option 1, there would be no option
to use the income when calculating tariffs until such time that all the biggest bottlenecks
have been removed (which practically will not happen in the foreseeable future).
This option would, similarly to Option 1, include harmonised compliance rules to be set
out and monitored by ACER, and combined with more transparency.
Under this option, it is possible that congestion revenues that would normally be used to
lower the national network tariff accrued in one Member State will be spent in another
Member State allowing spending on those projects that would bring the greatest benefits
to the EU as a whole.
Option 3 – Harmonised use of congestion income with full CEF option
The third option is an extension of the second. TSOs would, at the national level, be
permitted to use income for (a) guaranteeing the actual availability of allocated capacity
or (b) maintaining interconnection capacities. However, they would not be permitted to
use it to increase interconnection capacity, and neither could it be used against tariffs.
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Instead, all income not spent on (a) and (b) above would be directed to the European
Commission, de facto to the CEF-E or successor funds, to manage interconnection
capacity. This way, the revenues that, up to now can be used by TSOs/NRAs for increasing
capacity or lowering network tariffs, would be spent on the biggest bottlenecks in the
European electricity system as evidenced by mature PCIs. Again, as with Option 2, if and
when all these are removed, income could then be taken into account when calculating
tariffs.
This option would, similarly to Option 1, include harmonised compliance rules to be set
out and monitored by ACER, and combined with more transparency.
Again, under this option it is possible that congestion revenues accrued in one Member
State will be spent in another Member State allowing spending on those projects that would
bring the greatest benefits to the EU as a whole.
Comparison of the options
The options have been compared against the following criteria:
- Effectivity. Effectivity implies that, as much as possible, congestion income is used
to maximise the amount of cross-border capacity available to market participants.
The criterion assesses whether and to what extent the Options achieve this
objective;
- Efficiency. Efficient use of congestion income means that the procedure for the
spending of congestion income provides a simple and straightforward approach to
guaranteeing that congestion income is used for maintaining or increasing the
interconnection capacity;
- Transparency. The spending of congestion income should be transparent and
auditable;
- Robustness. The spending rules should be set in such a way to avoid influence over
the rules beyond what it envisaged;
- Predictability. The spending rules should allow a forecast of the financial outcome
and allow for reasonable financial planning by the TSOs involved;
- Proportionality. Congestion income policy options should be commensurate with
the problem i.e. not going beyond what is necessary to achieve the objectives,
limited to those aspects that Member States cannot achieve satisfactorily on their
own, and minimise costs for all actors involved in relation to the objective to be
achieved;
- Smoothness of transition. The current congestion income spending should not be
changed in a radical way in the short-term in order to limit the financial impact on
all system participants.
Effectivity
With respect to the effectivity of the policy options, all three positively contribute in more
or less the same manner. Currently, congestion income may be taken into account by the
regulatory authorities when approving the methodology for calculating network tariffs
and/or fixing network tariffs. In all three options this type of usage will be strongly
restricted or forbidden causing a larger share of the congestion income to be allocated to
maintaining and/or increasing cross-border capacity. However, for the actual construction
of these links, there may be additional barriers like the licensing procedures for the new
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corridors, so the availability of more financial resources may not in all cases guarantee
interconnection expansion.
Efficiency
Currently, TSOs and NRAs have the possibility to allocate the congestion revenues in the
most economically efficient manner. However, due to flexibility at the national-level it
cannot be guaranteed that congestion income will always be spent on maintaining and/or
increasing the available interconnection capacity. In each of the three options the level of
freedom for TSOs and NRAs to decide otherwise will be significantly reduced.
Since in Option 2 congestion income for investments are managed at a European level,
whereas the operational measures to guarantee or maintain the interconnection capacity
are dealt with nationally, this Option might be less effective than the other two.
Furthermore, there is some possibility that Member States prefer to withhold funds from
being transferred to a European institution by previous spending on operational measures.
Transparency
There are currently reporting obligations for the TSO on the spending of congestion
income. It is nonetheless not entirely clear, which criteria are applied for allocating
congestion income to operational measures, investments in capacity expansion or inclusion
in the transmission tariffs. It is expected that each of the three options will increase the
transparency of the allocation and spending of congestion income.
Robustness
The present methodology for spending congestion income is monitored by the NRAs
whereas the revenues themselves are ring fenced. There is not much room to spend the
income for other purposes than that envisaged. Each of the three Options further narrows
down the discretion of TSOs and NRAs. In each Option a larger share of congestion
income will be used for investments, since decision making is either more heavily
regulated or transferred to the European level.
Predictability
Currently, it is not clear how congestion income will be spent. It does not only depend on
the operational costs needed to guarantee the cross-border capacity, but also to the
discretion of the TSOs (and the approval of the NRAs) in deciding how to spend the
income. Each of the three Options contributes to a better predictability. However, the first
option leaves more freedom to Member States to decide on new investments than the other
two options, under which the income is added to the CEF-E funds, which are only used for
PCI investment projects. In the latter case the predictability of the manner of spending is
very good.
With respect to spending congestion income on operational matters, clearer rules will
contribute to higher transparency on the amount of funds needed for it. This will
materialise in all three options.
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Proportionality
If the objective of the policy options is to enhance the actual availability of the
interconnection capacity by relieving the financial constraint, each option that effectively
increases the financing of investments can be considered as proportional. With respect to
the implementation differences between the three options, it is debatable which measure is
more (or less) proportional than the other: adding detailing regulation (as in Option 1) or
shifting decision making power from the national to the European level (as in Options 2
and 3).
Smoothness of transition
The smoothness of transition is assessed with respect to the amount of change involved
when implementing each Option with reference to the current situation. The
implementation of additional regulation does not significantly change the present powers
of TSOs and NRAs, which is why Option 1 is positive with respect to smoothness of
transition.
For Options 2 and 3 decision making on new investments and operational measures for
maintaining the interconnection capacity shifts to the European level, which will have a
larger impact. It is possible that there will be objections to such a change, especially the
third option where more congestion income is managed on this level.
Summary
Overall, do nothing is not considered an appropriate response, as it does not address the
deficiencies in the current legislation. Changing the current arrangements will not only
increase the incentives on TSOs, but also on Member States and NRAs – i.e. there is a sum
of money that must be spent on interconnection in some form. Whilst tariffs can always be
used to fund such developments, there are counter-incentives, i.e. to keep tariffs lower by
limiting development to that which is strictly necessary as opposed to being of longer-term
benefit and of benefit to the EU internal market as a whole.
Option 1 is the least change, and the most flexible. However, due to this flexibility it is
also the option which could see the least amount of money redirected from being used
when calculating tariffs or from internal accounts towards projects that increase
interconnection capacity. Option 3 would be a significant change and takes away all
national-level decision-making on new investment using congestion income. This may be
less proportionate than allowing some national autonomy, at least in the first instance if it
achieves broadly the same ends. Option 2 would see the same financial potential for new
network investments that increase interconnection capacity – i.e. up to EUR 1.14 billion
per annum. It is therefore considered the most proportionate response to achieve the ends
sought.
Subsidiarity
The use of congestion income by TSOs has already been addressed at EU-level as part of
the Third Package. The issue is very much one of a cross-border nature, as the majority of
congestion income is raised on infrastructure that crosses Member State borders. A
common approach across the EU is necessary to ensure a level-playing field between
Member States and leaving the issue at national, or bi-lateral, level risks inconsistent
application.
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35% of congestion income was used on average over 2014 and 2015 to reduce tariffs,
despite the increase of cross-border trade in electricity between most EU Member States
and the growing need to strengthen the physical connection of electricity markets. Also,
maintaining grid stability becomes more challenging as increasing shares of variable
renewables enter the energy mix; higher interconnection levels could decrease the
necessity for redispatch and lead to lower network tariffs. These issues, given their cross-
border impacts, can only be dealt with at an EU-level.
Given that the most common use of congestion income does not seem to address the current
needs of grid development and maintenance, further EU action is necessary to ensure that
there is an increase of the proportion of congestion income spent on maintaining or
increasing interconnection.
Stakeholders' opinions
Whilst there was not a specific question in the energy market design consultation on
congestion income, and many respondents did not comment on the issue, some did express
views. For example, comments included:
"… It should be a common European interest to reduce or remove permanent
bottlenecks between countries within the EU. Primarily it should be done by using the
congestion incomes for investments instead of simply managing the congested
transmission lines. There is no need for separate capacity pricing for the energy only
markets."
"At the moment, income from congestion management shall be used to mitigate the
bottleneck or decrease the end user tariffs. However clear mechanism for setting up
the financing of the new projects shall be in place (including needed change in
accounting standards and income tax rules). With the new investment the respective
bottleneck is dismissed and there is no further income from congestion management.
This makes the return on investment impossible."
"According to the Communication it is essential to achieve the previously established
target value of 10% for the interconnection of electricity networks, and its increase to
15%. To this end, the current effective EU regulation provides adequate support. At
the same time, according to the Commission’s concept the utilisation of fees currently
charged for congestion management should be regulated in a manner which would
facilitate the development of the electricity system. We would be in a position to support
this concept if there is guarantee that once the target value has been achieved by a
Member State the revenues could still be used for other purposes as well (e.g. tariff
cuts)."
"…funds [for cross-border redispatching] could come from congestion rents which are
not possible to be attached to a border anymore in a flow-based world. This common
TSO income should be spent commonly on costly coordinated actions."
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5. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(2) (IMPROVED
ENERGY MARKETS - CMS ONLY WHEN NEEDED, BASED ON COMMON EU-WIDE
ADEQUACY ASSESSMENT ( AND OPTION 2(3) (IMPROVED ENERGY MARKET, CMS ONLY
WHEN NEEDED BASED ON COMMON EU-WIDE ADEQUACY ASSESSMENT, PLUS CROSS-
BORDER PARTICIPATION)
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5.1. Improved resource adequacy methodology
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Summary table
Objective: Pan-European resource adequacy assessments
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
National decision makers would continue to
rely on purely national resource adequacy
assessments which might inadequately take
account of cross-border interdependencies.
Due to different national methodologies,
national assessments are difficult to
compare.
Binding EU rules requiring TSOs to
harmonise their methodologies for
calculating resource adequacy +
requiring Member States to exclusively
rely on them when arguing for CMs.
Binding EU rules requiring ENTSO-E to
provide for a single methodology for
calculating resource adequacy +
requiring Member States to exclusively
rely on them when arguing for CMs.
Binding EU rules requiring ENTSO-E to carry
out a single resource adequacy assessment for
the EU + requiring Member States to
exclusively rely on it when arguing for CMs.
Pros
Stronger enforcement:
Commission would continue to face
difficulties to validate the assumptions
underlying national methodologies including
ensuing claims for Capacity Mechanisms
(CMs).
National resource adequacy assessments
would become more comparable.
In addition to benefits in Option 1, it
would make it easier to embark on the
single methodology.
In addition to benefits in Options 1 & 2, it would
make sure that the national puzzles neatly add up
to a European picture allowing for national/
regional/ European assessments.
Results are more consistent and comparable as
one entity (ENTSO-E) is running the same
model for each country.
Cons
Even in the presence of harmonised
methodologies national assessment
would not be able to provide a regional or
EU picture.
Even in the presence of a single
methodology, national assessments
would not be able to provide a regional or
EU picture.
National TSOs might be overcautious
and not take appropriately cross-border
interdependencies into account.
Difficult to coordinate the work as the
EU has 30+ TSOs.
It would potentially reduce the 'buy-in' from
national TSOs who might still be needed for
validating the results of ENTSO-E's work.
Most suitable option(s): Option 3 - this approach assesses best the capacity needs for resource adequacy and hence allows the Commission to effectively judge whether the proposed
introduction of resource adequacy measures in single Member States is justified.
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Description of the baseline
Based on perceived or real resource adequacy concerns40
, several Member States have
recently introduced resource adequacy measures. These measures often take the form of
either dedicated generation assets kept in reserve or a system of market wide payments to
generators for availability when needed (Capacity mechanisms or 'CM's).
Figure 1: CMs in the EU
Source: ACER 2015 Monitoring report
National resource adequacy assessments
To determine whether these concerns require the introduction of a CM, Member States41
first need to carry out an assessment of the adequacy situation. Indeed, all Member States
that are part of DG COMP's Sector Inquiry on Capacity Mechanisms measure the security
of supply situation in their country by carrying out an adequacy assessment in which one
or more methodologies are applied that give an indication of the potential of the generation
fleet to meet demand in the system at all times and under varying scenarios.
40
The sector inquiry has shown that a clear majority of public authorities expect reliability problems in
the future even though today such problems have been extremely rare in the past five years. In nine out
of ten Member States, no such problems have occurred at all. The only exception is Italy, where such
issues have arisen on the islands of Sardinia and Sicily which are not well connected to the grid on the
mainland. Although the Member States do not experience reliability issues at present, many Member
States are of the opinion that reliability problems are expected to arise in the coming five years.
41
In most countries, TSOs are the responsible bodies for monitoring and reporting on long-term resource
adequacy. Other responsible institutions are NRAs or governments In the UK, the medium and long
term resource adequacy assessments are carried out by the NRA and government respectively. In
Estonia, the long term monitoring is managed by the government.
Strategic reserve
(since 2004 ) - gradual phase-
out 2020 and considering a
permanent market system
after 2020
New Capacity Mechanism
under assessment by COMP
(Capacity payments from 2006
to 2014)
Capacity payment (since 2008) –
Tendering for capacity
considered but no plans
No CM (energy only market)
CM operational
Reliability option
(first auction end 2016, first
delivery contracted capacity is
expected in 2021)
Strategic reserve
(from 2016 on, for 2 years,
with possible extension for 2
years)
CM proposed/under consideration
Capacity requirements
(certification started 1 April
2015)
Capacity auction
(since 2014 - first delivery in
2018/19)
Capacity payment
(since 2007)
considering reliably options
Capacity Payment (Since 2010
partially suspended between
May 2011 and December 2014)
Strategic reserve (since 2007)
Debate pending
Strategic reserves for DK2
region from 2016-2018 (and
potentially from 2019-2020)
Strategic reserve
(since 1 November 2014)
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The methodologies are however rarely comparable across Member States. Methods vary
significantly, for instance when it comes to the question whether to take into account
generation from other countries, but also regarding the scenarios and underlying
assumptions42
.
The Council of European Energy Regulators (CEER)43
performed a survey over European
countries showing that security of supply is dealt with at national level through quite
different approaches:
- Assessing resource adequacy requires the definition of one or more scenarios that
can affect generation and demand projections. These scenarios are elaborated
according to different assumptions about load (typically high vs. low demand
scenario), and type and amount of future installed capacity (e.g. conservative or
baseline vs. high RES penetration scenario). Regarding the scenarios44
used in the
different Member States, the methodologies differ greatly depending on the
targeted timeframe45
and the majority of them do not seem to be consistent
throughout most of the national resource adequacy assessments.
- Regarding load forecast, Member States base their projections on historical load
curves, with assumptions on the evolution of specific parameters. The most
exploited parameters are economic growth, temperature, policy, demography and
energy efficiency. The extent to which types of consumers are grouped to appraise
carefully different consumption patterns can be very different46
. Moreover demand
response is largely not included as a separate factor in load forecast methodologies,
even though it may appear that it is indirectly included in the projections through
the effects it has had on the historical load curves47
.
42
JRC (2016), "Generation adequacy methodologies review"
43
CEER (2014), "Assessment of electricity generation adequacy in European countries"
44
In at least 6 countries (including Sweden, Romania, Malta, Finland and Norway) resource adequacy is
assessed against a single pre-defined baseline scenario. For the other cases (UK, France, the Netherlands,
Estonia, Hungary, Lithuania, Belgium, Spain, Ireland and Italy), several possible scenarios are
considered on the basis of different assumptions about load as well as type and amount of future installed
capacity, such as a conservative scenario, a baseline scenario a RES penetration scenario, for example.
45
In at least 9 countries (France, Estonia, Malta, Hungary Lithuania, Belgium, Spain, Ireland and Italy)
the scenarios are compounded taking as a reference the short, medium and long-term horizons. In the
Netherlands and Finland, the long term is not considered, while in Sweden and Norway only the short-
term is taken into account. In Denmark, only the long-term scenario is considered. In the Czech Republic
and Switzerland, the only scenario considered is the very long term, while in Spain the latter scenario
completes the short, medium and long-term analyses. Finally, in Romania, no short-term analysis is
performed (only mid and long-term scenarios are considered).
46
In 10 national resource adequacy reports (the UK, France, Norway, Malta, Czech Republic, Hungary,
Lithuania, Ireland, Austria and Italy) more than one category of consumers (e.g. residential, industrial,
commercial, agriculture, etc.) serve as a basis for the forecasts; while in 4 reports (the Netherlands,
Estonia, Belgium and Sweden), load only is forecasted at an aggregate level.
47
Only 3 countries include demand response as a separate factor in their load forecast methodology i.e.
the UK, France and Spain. In Norway and Finland, the contribution from demand response is not
included as separate factor, but peak load estimation is based on actual load curves which include the
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- Regarding generation forecast, the most important inputs are the information
received by those intending to build new generation and rules on how to consider
existing infrastructure. All Member States take projected investments into account,
sometimes with very heterogeneous sources and assumptions48
. In addition, there
are also various ways generation from variable output (i.e. intermittent RES) is
modelled49
; from no consideration at all, to precise hourly estimations based on
sophisticated data. It is commonly agreed that there is a need to improve
methodologies to better address how variable output impacts adequacy.
- With an increasing proportion of variable renewable resources, electricity systems
have become more complex. To address this increased complexity, some Member
States have replaced relatively simple, ‘deterministic’ assessment metrics50
–
which simply compare the sum of all nameplate generation capacities with the peak
demand in a single one-off moment – by more complex ‘probabilistic’51
models,
which are able to take into account a wide range of variables and their behaviour
under multiple scenarios. This includes not only state of the art weather forecasts,
but also factors in less predictable capacity sources such as the contribution from
effect of demand response. Sweden does not consider demand response, and do not assume that
consumers respond to peak load in their analysis.
48
For instance, decommissioning (and mothballing) of investments is not systematically taken into account.
Most collected data come from generators, partly directly via the TSOs.
49
Some countries (Estonia, Romania, Malta and Denmark) still go with the approach of unavailable
capacity while there are also others like the Netherlands, Norway, Spain and Sweden, which take a
certain percentage as available generation. On the contrary, France and the UK go up to detailed
modelling based on climate data, hub heights (for offshore wind farms) and detailed coordinates for the
generation sites.
50
One of the simplest measures to determine the level of resource adequacy is the capacity margin. This
deterministic methodology simply expresses the relation between peak demand in the electricity system
and the total available supply, usually as a percentage. In only two of the eleven Member States analysed
in the sector inquiry, this relatively simple capacity margin is calculated. For instance in 2016, France
had 104,480 MW of production installed capacity whereas peak demand during winter 2015/2016 was
84,700 MW; from that, one could say that France has approximately a 23% capacity margin (RTE
figures). Of course, no form of generation can always output its full nameplate capacity with 100%
reliability. Therefore, each source of input needs to apply a de-rating factor in order to reflect its
likeliness to be technically available to generate at times of peak demand (e.g. in Ofgem's electricity
capacity assessment, a combined cycled gas plant is assumed to be available 85% of the time). In 2014,
CEER found that 6 Member States were using de-rated capacity margins: Estonia, Malta, Hungary,
Belgium, Spain and Sweden.
51
Around half of the Member States of the sector inquiry carry out a 'probabilistic' calculation that can be
either expressed in LOLP, LOLE or EENS: (i) Loss of load probability (LOLP) quantifies the probability
of a given level of unmet demand at any particular point in time; (ii) Loss of load expectation (LOLE)
sets out the expected number of hours or days in a year during which some customer disconnection is
expected. For instance, French TSO RTE expects some customer disconnection to happen during 1h45
over winter 2016-2017; (iii) Expected energy non served (EENS) measures the total shortfall in capacity
that occurs at the time when there are disconnections. EENS makes it possible to monetise where VoLL
has also been calculated.
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demand response, interconnectors or renewable energy sources. Nonetheless, these
adequacy methodologies52
still differ (deterministic vs. stochastic).
- Despite on-going developments, some assessments are still considering isolated
systems and/or developing ways to include interconnectors53
. Others use non-
harmonised methodologies to consider cross-border capacity, with no cross-border
coordination foreseen. The availability of interconnection capacity is mostly based
on historical data (export and import flows during various periods of time) and to
lesser extent, on estimated data (e.g. market component such as future prices
estimations). Generation and load data correlations at supranational levels are
rarely considered54
, and for country-wide modelling, the "copperplate approach"
prevails55
.
- It should be noted that monitoring and assessing resource adequacy is a very
complex process which requires defining robust concepts, criteria and procedures
in order to give a reference tool to decision-making bodies if problem are
encountered. In almost all EU countries, the body responsible for ultimately
ensuring resource adequacy is the national government. However, monitoring
responsibilities are usually shared among the TSO, the NRA and the government.
These responsibilities can evolve depending on the timeframe considered. For the
medium and long-term timeframes, TSOs are the responsible bodies for monitoring
and reporting in most Member States. Other responsible institutions are NRAs or
governments56
. In most cases, the assessment is carried out yearly.
52
Half of the national studies are based on a 'probabilistic' approach (the UK, France, the Netherlands,
Finland, Romania, the Czech Republic, Lithuania, Belgium, Ireland, Italy) while six of them are based
on a deterministic approach (Estonia, Malta, Hungary, Belgium, Spain and Sweden). Denmark uses a
deterministic approach, but takes into account the outage percentage of power plants which is based on
both historical observations and Monte Carlo simulations.
53
The extent to which current resource adequacy reports take the benefits of interconnectors into account
varies a lot: 4 reports still model an isolated system (Norway, Estonia, Romania, and Sweden); 2 reports
use both interconnected and isolated modelling (France and Belgium); 3 report methodologies are being
modified to include an interconnection modelling; 9 reports simulate an interconnected system (UK, the
Netherlands, Czech republic, Lithuania, Finland, Belgium and Ireland, while France and Italy use both
methods).
54
It is not obvious that national resource adequacy reports generally take interactions between generation
and demand profiles into account. Moreover, it seems that most reports do not consider correlated data,
which could be done (for example with the use of a common correlated climate database at regional
level, or a common methodology for load sensitivity to temperatures). One direct consequence is that
most reports do not intend to identify the impact on security of supply of potential simultaneous severe
conditions in different electricity systems.
55
In the process of assessing resource adequacy, transmission and distribution networks can be modelled
in a very different manner, from a highly realistic description of the technical parameters which constrain
the power flows in the system, to a simplified modelling where these networks are considered as a
copperplate grid. Some systems are said not to be subject to structural internal congestions (including
France and Romania).
56
In the UK, the medium and long term resource adequacy assessments are carried out by the NRA and
government respectively. In Estonia, the long term monitoring is managed by the government.
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Table 1: Deterministic vs probabilistic approaches to adequacy assessments
Source: European Commission based on replies to sector inquiry, see below for a description of capacity
margin, LOLP, LOLE, and EENS
ENTSO-E carries out an EU-wide resource adequacy assessments
In addition to resource adequacy assessments carried out by Member States, there are also
EU level rules foreseen by the Third Package (the Electricity Regulation) requiring
ENTSO-E to carry out a medium and long-term resource adequacy assessment (so-called,
Scenario Outlook and Adequacy Forecast or SO&AF) in order to provide stakeholders and
decision makers with a tool to base their investments and policy decisions.
ENTSO-E is currently moving from a deterministic approach to a probabilistic approach
(sequential Monte-Carlo). This evolution will be done progressively and is expected to be
completely implemented by 2018. The first steps of the new methodology were carried out
in the latest published report so-called SO&AF 2015.
The ENTSO-E SO&AF 2015 presents the following characteristics/ limitations57
:
- ENTSO-E uses a deterministic assessment which calculates for each country
deterministic security of supply indicators (namely 'remaining capacity' and
'adequacy reference margin') only at particular points in time (the 3rd
Wednesday
of each month on the 19th
hour in the pan-European assessment or at national peak
load time in the national assessments). The report presents results for the mid-term
and long-term timeframes (5-year and 10 years ahead, respectively)58
.
- Regarding load forecast, there is no explicit modelling of demand-side response in
the SO&AF 2015 but is expected to be taken into account from 2017 onwards.
- Regarding generation forecast, the analysis is based on two different scenarios for
generation (conservative and best estimate). The conservative scenario considers
only new capacity if it is considered as certain and for the decommissioning, it
considers the official notifications but also additional criteria as for example,
57
JRC Science for Policy Report (2016), "Generation adequacy methodologies review"
58
Since 2011, ENTSO-E performs a SO&AF annually, with a time horizon of 15 years until SO&AF 2014
and 10 years in SO&AF 2015.
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technical lifetime of generators (additional criteria which are not considered in the
best estimate scenario). RES (wind and solar PV) are taken into account for the
first time in the SO&AF 2015 assessment by estimating their load factor (with a
Pan-European Climate database of 14 climatic years).
- Regarding interconnection, the ENTSO-E SO&AF 2015 assessment only considers
import and export capacities for each country. There is no explicit modelling of
flow-based market coupling.
Voluntary initiatives to carry out regional resource adequacy assessments
Some Member States have voluntarily decided to cooperate and deliver a regional resource
adequacy assessment. This is the case of the seven TSOs in the Pentalateral Energy
Forum59
('PLEF') who have decided to move away from country specific point in time
assessments to an integrated chronological probabilistic assessment. The new
methodology is based on harmonised and detailed input data to capture the main
contingencies60
susceptible of threatening security of supply. This voluntary approach
developed by the PLEF TSOs is currently used as a test-lab for upgrading the ENTSO-E
methodology.
Table 2: PLEF vs ENTSO-E approaches to adequacy assessments
PLEF
ENTSO-E
Current Targeted
Approach Probabilistic Deterministic Probabilistic
Scale
Regional (at least direct
neighbours, up to
second degree
neighbours)
National – simplified
regional
Pan European
Network representation
Current (NTC61) and
targeted (PTDF62
)
None on small scale,
maximum flows on
regional scale
First, NTC
Later, possibly flow-
based
Security of supply
indicators
Loss of load (energy
duration, probability,
frequency,…), capacity
margin
Capacity margin Loss of load
Uncertainty
considerations
Monte Carlo
simulations
Additional margins
Monte Carlo
simulations
Source: Artelys (2016), "METIS Study S4: Stakes of a common approach for generation and system
adequacy"
59
An inter-governmental initiative designed to promote collaboration on cross-border exchange of
electricity in Austria, Belgium, France, Germany, Luxembourg, the Netherlands, Switzerland.
60
These contingencies include outdoor temperatures (which result in load variations, principally due to the
use of heating in winter), unscheduled outages of nuclear and fossil-fired generation units, amount of
water resources, and wind and photovoltaic power production.
61
Interconnectors are usually modelled as commercial flows with no network physical constraints, but
constrained by maximum net transfer capacities (NTC). In practice NTC values can vary quite often,
due to outages, maintenance and temperature affecting lines' physical properties.
62
Power Transfer Distribution Factor
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Deficiencies of the current legislation
As highlighted in Section 7.3.2 of the Evaluation, resource adequacy is not addressed in
the Third Package. The Commission's current tool to assess whether government
interventions in support of resource adequacy are legitimate is State aid scrutiny. The
EEAG require among others a proof that the measure is necessary. However, the
framework does not allow the Commission to effectively judge whether there is a resource
adequacy problem in the first place.
To date, the need for CMs are based on national adequacy assessments and Member States
rely on them when arguying for CMs. However, national assessments are undertaken in
different ways across Europe. These assumptions may substantially differ depending on
the underlying assumptions made and the extent to which foreign capacities as well as
demand side flexibility are taken into account in calculations. For example, the Council of
European Energy Regulators (CEER) recommends to "take into account the potential
benefit provided by interconnectors in national resource adequacy analyses in a
coordinated and consistent way across Member States"63
. In addition, CEER is of the
opinion that "these different procedures pose difficulties (especially for neighbouring
countries) as it is a challenge to understand the different procedures and processes from
one country to another"64
.
Art. 8 of the Electricity Regulation gives to ENTSO-E the responsibility for carrying out a
European resource adequacy outlook. It requires amongst others that the European
resource adequacy outlook should build on national resource adequacy outlooks prepared
by each individual TSO. Consequently the ENTSO-E assessment is rather a compilation
of national assessments than a genuine calculation based on raw data input. Also the
applied methodology needs a review in particular with regards to the input data and the
calculation method used. For example, the European Electricity Coordination Group
recommends that "The improvements in the existing ENTSO-E methodology should focus
on the consistent treatment of variable RES generation and interconnectors"65
.. In their
current form and granularity they are not suitable to assess whether certain Member States
are likely to face resource adequacy problems in the mid to long-term.
Further to the difference in approach, CEER highlights that "there are also differences
between the System Outlook & Adequacy Forecast (SO&AF) undertaken by ENTSO-E and
the national assessments that occur due to different quality of data and a more
sophisticated approach in some countries"66
.
All in all, neither national assessments nor ENTSO-E's European resource adequacy
outlook, in their current form a) appropriately inform investors, governments and the wider
public of the likely development of system margins and b) allow the Commission to
63
CEER (2014), Recommendations for the assessment of electricity generation adequacy
64
CEER report on “Assessment of generation adequacy in European countries” (published in 2014)
http://www.assoelettrica.it/wp-content/uploads/2014/10/Ceer_GenerationAdequacyAssessment.pdf
65
Report of the European Electricity Coordination Group on The Need and Importance of Generation
Adequacy Assessments in the European Union, Final Report, October 2013
66
CEER report on “Assessment of generation adequacy in European countries” (published in 2014)
http://www.assoelettrica.it/wp-content/uploads/2014/10/Ceer_GenerationAdequacyAssessment.pdf
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effectively judge whether the proposed introduction of resource adequacy measures in
single Member State is justified.
Presentation of the options
Option 0 - BAU
National decision makers would continue to rely on purely national resource adequacy
assessments which inadequately take account of cross-border interdependencies. In
addition, due to different national methodologies, national assessments are difficult to
compare.
The Commission would continue to face difficulties to validate the assumptions underlying
national methodologies including ensuing claims for CMs.
Option 0+ stronger enforcement
As the current legislation foresees that national resource adequacy plans are the basis for
ENTSO-E to draw up its resource adequacy assessments, stronger enforcement is not a
viable option.
Some Member States (e.g. PLEF) have voluntarily decided to cooperate and deliver a
regional resource adequacy assessment. However, the PLEF geographically covers only
part of the EU electricity market and hence its role cannot go beyond that of a test-lab for
upgrading the ENTSO-E methodology. Indeed, without a common methodology for all EU
Member States, the Commission would continue to face difficulties to effectively judge
whether the proposed introduction of resource adequacy measures in single Member States
is justified.
Option 1 – Binding EU rules requiring TSOs to harmonise their methodologies for
calculating resource adequacy + requiring Member States to exclusively rely on them when
arguing for CMs
Option 1 would require TSOs to harmonise their methodologies for calculating resource
adequacy and require Member States to exclusively rely on them when arguing for CMs.
TSOs would have to cooperate to upgrade their methodologies based on probabilistic
calculations, with appropriate coverage of interdependencies, availability of RES and
demand side flexibility and availability of cross-border infrastructure in times of stress.
In this option, Member States would be responsible for carrying out the assessment.
Option 2 - Binding EU rules requiring ENTSO-E to provide for a single methodology for
calculating resource adequacy + requiring Member States to exclusively rely on them when
arguing for CMs
Option 2 would require ENTSO-E to provide for a single methodology for calculating
resource adequacy and require Member States to exclusively rely on them when arguing
for CMs. The ENTSO-E methodology should be upgraded based on propabilistic
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calculations67
and should appropriately take into account foreign generation, RES and
demand response.
In this option, Member States would be responsible for carrying out the assessment based
on the ENTSO-E methodology & coordination.
Option 3 - Binding EU rules requiring ENTSO-E to carry out a single resource adequacy
assessment for the EU + requiring Member States to exclusively rely on it when arguing
for CMs
Option 3 would require ENTSO-E to carry out an EU-wide resource adequacy assessment
and Member States to exclusively rely on it when arguing for CMs. In other words, this
would mean that, ENTSO-E would be required to not only provide for the methodology
(similar to Option 2) but also carry out the assessment. The ENTSO-E assessment should
have the following characteristics:
i. It should cover all Member States
ii. It should have a granularity of Member State/ bidding zone level to enable the
analysis of national/ local adequacy concerns;
iii. It should apply probabilistic calculations that consider dynamic characteristics of
system elements (e.g. start-up and shut-down times, ramp up and ramp-down
rates…)68
iv. It should calculate resource adequacy indicators for all countries (LOLE, EENS,
etc.)
v. It should appropriately take into account foreign generation, interconnection
capacity, RES69
, storage and demand response
vi. The assessment should be carried out every year
vii. Time span of 5-10 years
It should be noted that under this option each Member State would be allowed to carry out
their national resource adequacy assessment if they wish to but they would not be able to
rely on these results when arguing for CMs.
Comparison of the options
Contribution to policy objectives
Under Option 0, proposed CMs would be based on national resource adequacy
assessments and projections. National assessments may substantially differ depending on
the underlying assumptions made and the extent to which foreign capacities as well as
demand side flexibility and variable renewable generation70
are taken into account in
67
The PLEF approach could serve as a pioneer for applying the advanced methodology for a wider
perimeter.
68
This means considering flexibility issues, temporal constraints and a realistic evaluation of the expected
role of interconnectors.
69
National but also foreign RES should be considered as the IEM and the interconnection capacity are the
basis for a more and better integration of RES allowing a higher capacity factor for RES. The same can
apply to storage.
70
Some countries still assume zero capacity value for wind and PV. Countries that do not assume a zero
value differ on the methodology to estimate the capacity value of RES.
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calculations. Some countries even use deterministic methodologies that are obsolete (they
do not consider the stochastic nature of forced outages and variable renewable generation).
In addition, these national assessments are often not in line with the current EU-wide
assessment carried out by ENTSO-E. All in all, this approach reinforces the national focus
of most mechanisms and prevents a common view on the adequacy situation. Remaining
in the status quo may therefore lead to significant capacity overinvestments. In
consequence, it creates more uncertainty in neighbouring countries as each Member State
takes individual actions in putting in place CMs.
In Option 1, proposed CMs would still be based on national resource adequacy
assessments but these would adopt harmonised methodologies including input data. The
assessments would thus become more comparable across Member States. However, even
though this approach is an improvement compared to Option 0, it seems likely that Option
1 would still lead to significant capacity overinvestments. Although this option provides a
minimum harmonization, the implementation time will take longer as some Member States
current methodologies are far from the target one. An entity or body needs to assure that
the harmonized methodology is properly implemented and check the consistency of the
results across countries. This option can produce significant delays.
Option 2 would make it easier to embark on a single methodology. Moreover, this
approach is likely to result in less over-investment in power infrastructure. However, it
would be difficult to coordinate the work of the 30+ TSOs in Europe. In addition, national
TSOs might be overcautious and not take appropriately into account cross-border
interdependencies. Even in the presence of a single methodology, national assessments
would not be able to provide an effective regional or EU picture.71
Indeed, national
interests could still play a role in the manner in which the assessments are done. There is
a risk that Member States would deviate from the single methodology when implementing
it which means that an enforcement and monitoring mechanism should be provided for.
Option 3 would most likely be the best option to reach the set objectives as it would make
sure that the national puzzles neatly add up to a European picture allowing for national/
regional/ European assessments. A major advantage is that ENTSO-E has already been
carrying out an EU-level resource adequacy assessment based on the Union legislation. By
requiring ENTSO-E to carry out the assessment, Option 3 appears to be appropriate to
overcome the main obstacles that prevent Option 1 and 2 from being effective. Indeed,
there would be less room for Member States to deviate in the implementation of the single
methodology. This would favour neutrality as it would avoid national interests playing a
role in the manner in which the assessments are done. Efficiencies would arise from a
reduced need for coordination between Member States and a reduced need for oversight
during the implementation of the methodology by the Member States. As a drawback,
71
For example the extent to which Member States can rely on each other for contributions to their own
security of supply depends, among other things, on the likelihood of scarcity situations occurring
simultaneously in those Member States. Even if Member States calculate their resource adequacy
assessment based on a single methodology it cannot be ensured that they arrive at exactly at the same
outcomes except if all Member States share all data sets generated by the other and if they carry out
exactly the same computational steps using those data sets.
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Option 3 would potentially reduce the 'buy-in' from national TSOs who might still be
needed for validating the results of ENTSO-E's work. All in all, this option would best
assess the capacity needs for resource adequacy and hence allow the Commission to
effectively judge whether the proposed introduction of resource adequacy measures in
single Member States is justified.
Key economic impacts
An expert study carried out using METIS72
assesses the benefits of cooperation for
resource adequacy. The study highlights that significant capacity savings can be obtained
from a European approach to security of supply with respect to a country-level resource
adequacy assessment. The reasons for these savings is that Member States have different
needs in terms of capacity with peak demands that are not necessarily simultaneous.
Therefore, they can benefit from cooperation in the production dispatch and in investments.
The model jointly optimises peak capacities for two reference cases for EuCO2773
–
without cooperation (capacities are optimised for each country individually, as if countries
could not benefit from the capacities of their neighbours) vs. with cooperation (capacities
are optimised jointly for all countries, taking into account interconnection capacities
(NTCs).
In both options, capacity dimensioning has the following characteristics: (i) removal of
peak fleets (CCGT, OCGT and oil) to avoid excessive overcapacity); (ii) Other units are
kept (including nuclear, coal and lignite), which creates overcapacity for CZ, SK and BG;
(ii) Optimisation of gas and peak fleats (modeled as OCGT) with VOLL = 15k EUR/MWh
and peak annual price = 60k EUR/MW/year.
The difference in installed capacity between the two cases reveals how much savings could
be made from cooperation in investments.
Results show that almost 80 GW of capacity savings (see figures 2 and 3) across th EU,
which represents 31% of the installed gas capacities, can be saved with cooperation in
investments. This represents a gain of EUR 4.8 billion per year of investments.
It should be noted that this figure does not assess at which stage Member States are
currently (i.e. whether some Member States already benefit from the capacities of their
neighbours), as the benefits have already been reaped by some. It should also be noted that
this figure does not include savings on production dispatch, which could lead to much
higher monetary benefits.
72
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016).
73
The scope of the model comprises EU28 + (CH, NO, BA, MK, ME, RS) and 50 years of weather data.
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Figure 2 – Capacity savings for METIS EuCO27 in GW
Source: METIS
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Figure 3 – Capacity savings for METIS EuCO27 in % of demand
Source: METIS
The main reasons for these capacity savings are twofold: (i) variability of peak demand
across Europe and (ii) variability of weather conditions (and consequently of RES
generation profiles) across Europe.
- Variability of power demand profiles across Europe: Energy end use practices are
different and the deployment of equipement using electricity (for instance electrical
heating) varies across Member States. In particular, the sensitivity of Member
States national demand with regards to temperature varies from one country to the
other. Moreover, low temperature events do not occur at the same time in all
Member States74
. As a consequence, the aggregated European demand peak is
lower than the sum of all national demand peaks (which do not occur at the same
time). A European electric system with cooperation in capacity dimensioning
would therefore face a lower capacity need – defined by the aggregated European
demand peak – than a set of isolated national systems, which would require a global
generation capacity as high as the sum of national peak demand.
74
For instance, extreme temperature conditions are often not correlated between Western Europe and
Northern Europe (Norway, Sweden, Finland and Estonia).
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Figure 4 – illustration of cooperation in variability of peak demand across Europe
(based on ENTSO-E v3 scenario)
Source: METIS
- Variability of RES generation profiles: Despite geographical correlations at the
regional scale, different climatic regimes produce different weather conditions
across Europe, which often compensate one another. This influences the RES
generation profiles. Indeed, aggregating European RES generation profiles leads to
higher load factors for RES than single country RES load factors.
Figure 5 – illustration of cooperation in variability of RES generation across Europe
(based on ENTSO-E v3 scenario i.e. high RES scenario)
Source: METIS
Impact for businesses and public authorities
The administrative costs75
are expected to be marginal compared to the economic benefits
that would be reaped. ENTSO-E currently employs two FTEs to carry out its resource
adequacy assessment and has a working group of 10 FTEs from national TSOs. In addition,
we assume approximately 100 FTEs working on national resource adequacy assessments
in TSOs across Europe (Option 0). Option 1 is assumed to require require 20-25 additional
FTEs for coordinating the harmonisation of national assessments. It is likely that Option 2
would be slightly less human intensive – only 15-20 additional FTEs would be needed.
Under Option 3, it is assumed that the same amount of FTEs would be needed as in Option
2 but these would be employed by ENTSO-E. In monetary terms, this can be translated
75
The economic costs linked to resource adequacy assessments are based on own estimations, resulting
from discussions with stakeholders and experts.
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into 2-3 million euros annually in terms of personnel costs for Option 3. In addition, IT
costs are equally likely to be small. For Option 3, IT costs are assumed to be in the range
from 2-3 million euros per year as ENTSO-E would need more calculatory power that has
IT implications. For options 1 and 2, they are likely to be lower than for Option 3 as TSOs
across Europe have already developed their own IT systems. All in all, the estimated
administrative costs of ENTSO-E providing for a single methodology and carrying out the
assessment (Option 3) would range from 4 to 6 million euros per year. This is marginal
compared to the estimated benefits presented above.
Table 3: Comparison of the Options in terms of their effectiveness, efficiency and
coherence of responding to specific criteria
Option 0: No
further action
Option 1:
Harmonisation of
national
assessments
Option 2: ENTSO-
E provides for
single
methodology,
Member States
carry out the
assessment
Option 3: ENTSO-
E provides for
single methodology
and carries out the
assessment
Quality of the
methodology
--
No progress or
uncertain progress
as it depends on
Member State
independent
initiatives
0
Progress remains
limited as only
harmonisation
++
Efficient as there is
a single
methodology
++
Coherence as
ENTSO-E runs the
same model for all
Member States and
the pan-European
assessments. Input
and output data are
more coherent.
Use of
established
institutional
processes
-
Unclear which
processes to be
used
+
Can build upon
established
processes
0/+
Can partially build
upon established
processes
-
Requires building
up new processes
(ENTSO-E to carry
out the assessment)
Efficient
organisational
structure
-
Each Member State
carries out its own
assessment
-
Each Member State
carries out its own
assessment
0/-
Each Member State
carries out its own
assessment based
on ENTSO-E
methodology
++
Efficient as
ENTSO-E carries
out the assessment
for all Member
States
Capacity
savings
--
Low capacity
savings
-
Higher capacity
savings due to
different treatment
of cross-border
capacity
+
Higher capacity
savings as single
methodology
++
Highest capacity
savings as single
methodology and
calculation
The assumptions are based on the Market Design Initiative consultations and other
meetings with stakeholders
In summary:
- Option 0, "No further action": will likely lead to significant over-investments and
hence will fall short in providing the adequate level of security of supply for Europe
for any given provision cost level.
- Option 1, "Harmonisation of national assessments": is likely to be more efficient
than Option 0, but cannot be expected to fully meet the specific objectives.
- Option 2, "ENTSO-E providing for a single methodology but Member States
carrying out the assessments": is likely to lead to less overinvestment. Nonetheless,
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national interests could still play a role in the way in which the assessments are
done.
- Option 3, "ENTSO-E providing for a single methodology and carrying out the
assessments": seems, according to the assessment of the options, to be the most
appropriate measure for assessing generation adequacy assessment.
Subsidiarity
The subsidiarity principle is fulfilled given that the generation adequacy challenges the
EU power system is facing cannot be optimally addressed based on national adequacy
assessments as is currently the case, as foreign contribution to national demand might not
be sufficiently taken into account. This can be the case because national assessments apply
different assumptions, calculatory approaches and data input. This is why it would be best
suited to require ENTSO-E to carry out a single updated generation adequacy assessment
for the EU based on a revamped methodology and high quality and granular data input
from TSOs including requiring Member States to exclusively rely on it when arguing for
CMs.
Requiring ENTSO-E to carry out a single generation adequacy assessment for the EU
would also be in line with the proportionality principle given that the total capacity
requirements for ensuring the same level of security of supply will be lower than in the
case of national adequacy assessments. This will strengthen the internal market by making
sure that resources are deployed and utilised efficiently across the EU.
Stakeholders' opinions
Replies to the public consultation on the Market Design Initiative
A majority of stakeholders (34%) is in favour of sticking to an "energy-only" market,
possibly with a strategic reserve. Many generators and some governments disagree and are
in favour of market-wide CMs (in total 22% of stakeholders replies). Many stakeholders
(31%) share the view that properly designed energy markets would make capacity
mechanisms redundant (21% disagree).
There is almost a consensus amongst stakeholders on the need for a more aligned method
for generation adequacy assessment (73% in favour, 2% against). A majority of
answering stakeholders (47% of all stakeholders) supports the idea that any legitimate
claim to introduce CMs should be based on a common assessment. When it comes to
geographical scope of the harmonized assessment a vast majority of stakeholders (86%)
call for regional or EU-wide adequacy assessment while only a minority (20%) favour a
national approach.
Most of the stakeholders including Member States agree that a regional/European
framework for CMs are preferable. Member States, however, might want to keep a large
degree of freedom when proposing a CM. They might claim that beyond a revamped
regional/ EU generation adequacy assessment there is legitimacy for a national assessment
based on which they can claim the necessity of their CM.
Sensibilities
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The CEER claims that "security of supply is no longer exclusively a national consideration,
but it is to be addressed as a regional and pan-European issue" and that "generation
adequacy needs to be addressed and coordinated at regional and European level in order
to maximise the benefit of the internal market for energy". As a conclusion to their survey,
the CEER published recommendations76
that emphasize the need for the implementation
of a single harmonised methodology. The PLEF has already used such a common approach
in a recent security of supply study77
. In addition, ENTSO-E's target methodology is
announced to be "fully in line with the methodology developed by the TSOs of the PLEF"78
.
EFET79
is of the opinion that "the current 'national approach' potentially leads to an over
procurement of capacity as Member States do not appropriately take into account what
capacity is available outside of their borders. As a medium step, regional assessments
based on clusters of countries that are highly interconnected can be efficient, as they will
effectively pool resources over a wider area. The ENTSO-E SO&AF reports are a first step
in the direction of a European approach to adequacy assessment. However, the reports so
far only consolidate the analysis of individual TSOs for their respective control
area/country. Market participants still expect a truly European adequacy assessment from
ENTSO-E, and national regulators should support the requests of ACER and the European
Commission in that regard."
On the ENTSO-E methodology, Wind Europe80
is of the opinion that "most national
adequacy assessments focus on the contribution of firm generation units, with little or no
consideration for the contribution of other energy sources such as demand-side response,
storage, imports/exports or renewables." It recommends that "developing a holistic
approach that systematically and realistically include renewables, demand response,
storage and interconnections' contribution to adequacy."
76
Recommendations for the assessment of electricity generation adequacy, CEER
77
Pentalateral Energy Forum [PLEF] – Support Group 2, Generation Adequacy Assessment
78
Energy Community Workshop: "Towards Sustainable Development of Energy Community", RES
integration: the ENTSO-E perspective
79
EFET answer to the public consultation on the market design initiative
80
Wind Europe, "Assessing resource adequacy in an integrated EU power system" (May 2016)
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5.2. Cross-border operation of capacity mechanisms
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Summary table
Objective: Framework for cross-border participation in capacity mechanisms
Option 0 Option 1 Option 2
Description
Do nothing.
No European framework laying out the details of an effective cross-
border participation in capacity mechanisms. Member States are likely to
continue taking separate approaches to cross-border participation,
including setting up individual arrangements with neighbouring markets.
Harmonised EU framework setting out procedures including
roles and responsibilities for the involved parties (e.g. resource
providers, regulators, TSOs) with a view to creating an effective
cross-border participation scheme.
Option 1 + EU framework harmonising
the main features of the capacity
mechanisms per category of mechanism
(e.g. for market-wide capacity
mechanisms, reserves, …).
Pros
Stronger enforcement
The Commission's Guidance on state interventions81
and the EEAG
require among others that such mechanisms are open and allow for the
participation of resources from across the borders. There is no reason to
believe that the EEAG framework is not enforced. To date, however,
there are not many practical examples of such cross-border schemes.
It would reduce complexity and the administrative impact for
market participants operating in more than one Member
States/bidding zone.
It would remove the need for each Member State to design a
separate individual solution – and potentially reduce the need for
bilateral negotiations between TSOs and regulators.
It would preserve the properties of market coupling and ensure
that the distortions of uncoordinated national mechanisms are
corrected and internal market able to deliver the benefits to
consumers.
In addition to benefits in Option 1, it
would facilitate the effective
participation of foreign capacity as it
would simplify the design challenge and
would probably increase overall
efficiency by simplifying the range of
rules market participants, regulators and
system operators have to understand.
Cons
As the conclusion of individual cross-border arrangements depend on the
involved parties' willingness to cooperate it is likely that this option will
cement the current fragmentation of capacity mechanisms. Arranging
cross-border participation on individual basis is likely to involve high
transaction costs for all stakeholders (TSOs, regulators, ressource
providers).
It would be a cost for TSOs and regulators which would have to
agree on the rules and enforce them across the borders. These
costs would be lower than in Option 0 though.
In addition to the drawback of Option 1,
it would limit the choice of instruments.
Most suitable Option(s): Options 1 and 2
81
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf
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Description of the baseline
DG COMP's sector enquiry on Capacity Mechanisms found that cross-border participation
is not yet enabled in the majority of CMs, and with different Member States developing
different solutions for their already different national capacity mechanisms there is an
emerging risk of increasing fragmentation in the market.
The exclusion of foreign capacity from CMs reduces the efficiency of the internal market
and increases costs for consumers. The most damage is done if Member States make no
assessment of the possibility of imports when setting the amount of capacity to contract
through a CM (in a volume-based model) or setting the price required to bring forward the
required volume (in a price-based mechanism). In this approach (no cross-border
participation), there would be greater distortion of the signals for where new capacity
should be built, and an increase in overall system costs due to overcapacity. In addition,
CMs would fail to adequately reward investment in interconnection that allows access to
capacity located in neighbouring markets. The potential unnecessary costs of this
overcapacity has been estimated at up to 7.5 billion euros per year in the period 2015-
203082
.
Some Member States have attempted to address the problem by taking account of expected
imports (at times of scarcity) when setting the volume to contract in their capacity
mechanism (defined as implicit participation) This reduces the risk of domestic
overprocurement and recognises the value to security of supply of connections with the
internal energy market. However, implicit participation does not remunerate foreign
capacity for the contribution it makes to security of supply in the CM zone. If only domestic
capacity recieves capacity payments, there will be a greater incentive for domestic
investment than investment in foreign capacity or interconnectors resulting in less than
optimal investment in foreign capacity and in interconnector capacity.
The best approach to this would be explicit participation which means that the
contribution of imports to the CM zone must not only be identified, but the providers of
this foreign capacity need to be remunerated for the security of supply benefits that they
deliver to the CM zone.
This approach has been formalised in the Commission's Guidance on state interventions83
and the EEAG which require among others explicit participation of foreign capacity in the
CM (EEAG 232).
However, putting in place a functioning explicit cross-border CM requires multiple
arrangements involving several parties (e.g. resource providers, TSOs, regulators). This is
a difficult exercise requiring willingness and cooperation from all parties which cannot be
taken for granted. This could explain why, to date, there are not many practical examples
of such cross-border schemes.
82
See Booz & co, 2013, 'Study on the benefits of an integrated European Energy market'
83
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf
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Member States who have implemented an explicit cross-border scheme have taken
different approaches. Portugal, Spain and Sweden appear to take no account of imports
when setting the amount of capacity to support domestically through their CMs. In
Belgium, Denmark, France and Italy, expected imports are reflected in reduced domestic
demand in the CMs. The only Member States that have allowed the direct participation of
cross-border capacity in CMs are Belgium, Germany and Ireland.
Foreign plants were allowed to participate in the Belgian tender for new capacity, provided
that they would subsequently become part of the Belgian bidding zone even if
geographically located in another Member State.
In the Irish tender, foreign capacity could participate if it could demonstrate its contribution
to Irish security of supply – no foreign capacity was selected in the tender. In the existing
Irish capacity payments model, foreign capacity can benefit from capacity payments.
However, the method for enabling this participation involves levies and premiums on
electricity prices and is not therefore compatible with market coupling rules which require
electricity prices, not capacity premiums/taxes, to provide the signal for imports and
exports84
.
None of the strategic reserves are open to generators located outside of the Member State
operating the reserve mechanism; except for the German network reserve which contracts
capacity outside of Germany provided that it can contribute to alleviating security of
supply problems in Southern Germany through re-dispatch abroad.
Despite the current lack of foreign participation, many Member States are trying to develop
cross-border participation in their mechanisms. France carried out last year a consultation
which outlined different options for the participation of interconnectors or foreign capacity
in the decentralised obligation scheme. Ireland published a consultation in December85
on
options for cross-border participation in its planned mechanism. Italy is apparently
considering future foreign participation in its capacity mechanism. Since December 2015
the British capacity mechanism has included interconnectors with Britain, which can
participate as price takers in capacity auctions.
Deficiencies of the current legislation
The Commission's current tool to assess whether government interventions in support of
generation adequacy are legitimate is State aid scrutiny. The EEAG require among others
a proof that the measure is necessary, technological neutral and allows for explicit cross-
border participation. Beyond the requirements of the Commission's guidance on state
intervention and the EEAG, there is no European framework laying out the details of an
effective cross-border participation in capacity mechanisms.
This could explain why few Member States have developed cross-border schemes with
explicit participation, which means that (at best) they only implicitly take into account
foreign capacities. If Member States limit participation in a national mechanism only to
capacity providers located within their borders, and make overly conservative assumptions
84
Note however that the Irish capacity mechanism does operate across the UK and Irish border because of
joint market arrangements and a single bidding zone covering Ireland and Northern Ireland.
85
https://www.semcommittee.com/overview?article=f254d505-16bc-4a66-b940-bf2cc7b614ae
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about their level of imports they should expect, this will lead to distorted locational
investment signals and over-capacity in areas with capacity mechanisms. These distortions
can benefit incumbent market participants which will further reduce competition in the
long run.
Member States wanting to comply with the EEAG requirements have to individually
arrange, for each of their borders separately, the necessary cross-border arrangements
involving a multitude of parties including regulators, resource providers and TSOs.
Arranging cross-border participation on individual basis is likely to involve high
transaction costs for all stakeholders. This is also a difficult exercise requiring willingness
and cooperation from all parties which cannot be taken for granted.
When developing solutions for explicit participation of interconnectors and foreign
capacity to their CM, Member States need to address a number of policy considerations.
For example, an explicit participation model needs to identify:
- Whether there should be any restriction on the amount of capacity that can
participate from each connected bidding zone;
- What type of capacity product (obligations and penalties) should apply to foreign
capacity providers; and
- Which foreign capacity providers are eligible to participate (DSR, generation,
storage).
It is therefore not surprising that 85% of market participant respondents and 75% of public
body respondents to the sector inquiry questionnaire felt that rules should be developed at
EU level to limit as much as possible any distortive impact of CMs on cross national
integration of energy markets.
The fact that cross-border participation is not yet enabled in the majority of CMs as
highlighted on p.30 of the Evaluation, and with different Member States developing
different solutions for their already different national CMs, there is an emerging risk of
increasing fragmentation in the market.
Presentation of the options
Option 0 - BAU
The Commission's Guidance on state interventions86
and the EEAG require among others
that such mechanisms are open and allow for the participation of resources from across the
borders.
The EEAG include the following requirements related to cross-border participation in a
generation adequacy measure:
i. Should take the contribution of interconnection into account (226);
ii. Should be open to interconnectors if they offer equivalent technical performance
to other capacity providers (232)
86
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf
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iii. Where physically possible, operators located in other members states should be
eligible to participate (232);
iv. Should not reduce incentives to invest in interconnection, nor undermine market
coupling (233).
As explained above, the EEAG requires among others explicit participation of foreign
capacity in the capacity mechanism (EEAG 232). However, Option 0 does not provide for
a European framework setting out harmonised rules of an effective cross-border
participation scheme.
Option 0+
Despite the EEAG requirements for Member States to individually arrange, for each of
their borders separately, the necessary cross-border arrangements, few Member States
have voluntraily collaborated to develop an effective cross-border scheme. This is a
difficult exercise requiring willingness and cooperation from all parties which cannot be
taken for granted.
Option 1 - Harmonised EU framework setting out procedures including roles and
responsibilities for the involved parties (e.g. resource providers, regulators, TSOs) with a
view to creating an effective cross-border participation scheme
Under this option there would be a requirement for Member States to allow for explicit
participation of foreign capacity in national CMs.
There would also be a harmonised EU framework setting out procedures including roles
and responsibilities for the involved parties (e.g. resource providers, regulators, TSOs)
with a view to creating an effective cross-border participation scheme. The framework
would:
a) Define the appropriate share of foreign participation (de-rating of resources);
b) Allocation of 'entry tickets' to foreign resource providers87
;
c) Same remuneration principles for domestic and foreign resource providers;
d) No booking (or setting aside) of cross-border capacities for cross-border
participation;
87
The contribution foreign capacity makes to a neighbour's security of supply is provided partly by the
foreign generators or demand response providers that deliver electricity, and partly by the transmission
(interconnection) allowing power to flow across borders. Depending on the border, there can be a relative
scarcity of either interconnection or foreign capacity. To ensure the right investment incentives, the
revenues from the mechanisms paid to the interconnection and/or the foreign capacity should reflect the
relative contribution each makes to security of supply in the zone operating the CM. Where
interconnection is relatively scarce but there is ample foreign capacity in a neighbouring zone, the
interconnectors should thus receive the majority of CM. This would reinforce incentives to invest in
additional interconnection, which is the limiting factor in in this case. Conversely, where there is ample
interconnection but scarcity of foreign capacity, the foreign capacity should receive most of the capacity
remuneration. In this case, foreign capacity is the limiting factor that should receive additional
incentives.
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e) Contribution of foreign capacity in parallel scarcity situations88
to be addressed by
de-rating factors;
f) No delivery obligation (only availability);
g) No adjustment of cross-border schedules;
h) No limitation of the participation of a capacity resource to a single CM where the
resource can contribute to security of supply in more than one CM zone.
More details regarding the harmonised EU framework
De-rating of resources: De-rating of interconnectors and/or foreign capacity refers to an evaluation of the
expected actual contribution of a capacity provider on average, over the long-term, at times when it is
required. This issue is critical as conservative assumptions will lead to overcapacity, and overly generous
assumptions will potentially lead to unmet demand (and potentially reduced confidence in the value of
interconnection).
Entry-tickets to foreign resource providers: Foreign capacity providers would have to acquire specific
"interconnection tickets" to allow them to explicitly participate in the CM. Foreign capacity bids to get access
to the capacity market via the interconnection, up to the level of available interconnection capacity. The
interconnection receives revenues from "interconnection tickets" auctioning. Foreign capacities receive
revenues at "local CM" clearing price. This would allow a priori a market-based split of value and the right
incentive for investments.
Same remuneration principles for domestic and foreign resource providers: In principle, if the
allocation process for capacity contracts allows interconnector or foreign capacity to compete directly with
domestic capacity, the obligation and penalties faced by the interconnector or foreign capacity providers
should be the same as the obligations and penalties faced by the domestic capacity providers.
No booking of cross-border capacity for cross-border participation: One of the basic features of capacity
mechanisms is that the participating resources (mainly generators) receive a payment for their availably in
times of expected system stress. Whether a participating resource actually generates electricity depends on
short-term market price signals (effectively intra-day and balancing market prices). This mechanism makes
sure that power flows to the area in Europe that needs it most. For example, if short-term prices in Belgium
turn out to be 2.000 EUR/MWh while prices around Belgium are only 250 EUR/MWh the market coupling
algorithm (and successive intra-day exchanges) will make sure that all available transmission capacities on
the Belgian border will be used to flow power into the country. The limiting factor to supply Belgium in
times of stress is (most likely) not the availability of generating assets in Europe but the relative scarcity of
transmission capacities towards Belgium. Setting aside transmission capacities for the purposes of cross-
border participation will therefore not improve the security of power supplies in Belgium but will only
interfere with the efficient functioning of power markets. Participation of resources from across the border
should therefore not be link to the effective delivery of electricity from that resource. Paying for capacity
(availability) across the borders can still make sense as this provides incentives to keep resources available
to produce if market prices signal so.
Contribution of foreign capacity in parallel scarcity situations to be addressed by de-rating factors: In
practice, it is extremely unlikely that scarcity events will be perfectly correlated between two neighbouring
countries. So, to avoid a situation where overall less contribution by imports to security of supply is assumed
than is truly the case, a statistical judgement – de-rating of the interconnectors on each border to reflect
expected long-run average import capacity at times of scarcity – is needed for each capacity mechanism. The
88
The extent to which an interconnector can reliably provide imports to the countries it connects depends
not just on the line's technical availability but also on the potential for concurrent scarcity in the
connected markets. If zone A only has a winter peak demand problem and connected zone B only has a
summer peak demand problem, each may expect 100% imports from the other at times of local scarcity.
However, if countries A and B are neighbours with similar demand profiles and some similar generation
types, there may be some periods of concurrent scarcity where neither can expect imports from the other.
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amount of capacity demanded domestically should be reduced by this amount, and this capacity is then
available for allocation to foreign capacity providers.
No delivery obligation (only availability): An availability cross-border product allows the internal market
to function unimpeded and avoids creating distortions to merit order dispatch that might be created with
delivery obligations. Moreover, an availability product provides an additional incentive for Member States
to correct regulatory failures and ensure their electricity prices reflect scarcity – which has further benefits
for market functioning as such prices provide a signal for investment in flexible capacity and enable demand
response. Lastly, establishing a relatively simple availability product – along with other common rules –
makes cross-border participation much more readily implementable.
No adjustment of cross-border schedules: Because of the potential for delivery obligations to create
distortions in neighbouring markets and the fact that anyway such obligations can only incentivise actions
which are likely to have a very limited effect on cross-border flows, delivery obligations are not appropriate
for interconnectors or foreign capacity.
No limitation of the participation of a capacity resource to a single CM where the resource can
contribute to security of supply in more than one CM zone: Without this requirement explicit
participation is likely to lead to overcapacity which would be a worse outcome than implicit participation.
Option 2: – Option 1 + EU framework harmonises the main features of the capacity
mechanisms per category of mechanism (e.g. for market-wide capacity mechanisms,
reserves, …)
In addition to Option 1, the EU framework would harmonise the main features of the
capacity mechanisms per category of mechanism (e.g. for market-wide capacity
mechanism, reserves, etc.), such as the properties of capacity product to be offered, the
duration of the obligation, etc.
Comparison of the options
Contribution to policy objectives
Option 0 already requires explicit participation of foreign capacity in the CM under the
EEAG rules. However, the EEAG framework does not set out harmonised rules of an
effective cross-border participation scheme. This explains why few Member States have
developed cross-border schemes with explicit participation, which means that (at best) they
only implicitly take into account foreign capacities. If Member States limit participation in
a national mechanism only to capacity providers located within their borders, and make
overly conservative assumptions about their level of imports they should expect, this will
lead to distorted locational investment signals and over-capacity in areas with capacity
mechanisms, and an increase in overall system costs. As the conclusion of individual cross-
border arrangements depend on the involved parties' willingness to cooperate it is likely
that this option will cement the current fragmentation of capacity mechanisms. Arranging
cross-border participation on individual basis for each of a Member States borders is likely
to involve high transaction costs for all stakeholders (TSOs, regulators, ressource
providers). This is also a difficult exercise requiring willingness and cooperation from all
parties which cannot be taken for granted.
Option 1 would facilitate explicit cross-border participation as already required by EEAG
by providing an EU framework with roles and responsibilities of the involved parties. This
option would remove the need for each Member State to design a separate individual
solution – and potentially reduce the need for bilateral negotiations between TSOs. It
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would also reduce complexity and the administrative impact for market participants
operating in more than one zone. Hence, it is likely that an increased number of Member
States would implement an effective cross-border scheme. Explicit participation would
lower overall system costs as it corrects investment signals and enables a choice between
local generation and alternatives. On one hand, the capacity in a CM zone will bid lower
into the domestic CM as a result of access to revenues from electricity and capacity in
neighbouring zones. On the other hand, this will lead to more investment in capacity in a
non-CM zone, and in transmission to neighbouring CM zones, if capacity in a non-CM
zone has access to neighbouring capacity and energy prices. All in all, with the design
options of an EU framework chosen above, Option 1 is likely to better preserve operational
market efficiencies (e.g. market coupling) and ensure that the investment distortions of
uncoordinated national mechanisms are corrected and the internal market able to deliver
the benefits to consumers.
Option 2 would facilitate the effective participation of foreign capacity as it would
simplify the design challenge and would probably increase overall efficiency by
simplifying the range of rules market participants, regulators and system operators have to
understand. At the same time there is a risk that it would limit the choice of instruments
and potentially the ability to answer a wider range of problems that capacity mechanisms
could address.
Key economic impacts
The economic impacts of the different options are analysed in the core document "Section
6 - Problem Area II".
Impact for businesses and public authorities
Although the cost of designing cross-border participation in CM depends to some extent
on the design of the CMs, an expert study89
estimated that such cost corresponds roughly
to 10%90
of the overal cost of the design of a CM91
. In addition, they estimate costs
associated with the operation of a cross-border scheme i.e. additional costs if cross-border
participation is facilitated to amount to 6-30 FTEs92
for TSOs and regulators combined.
TSOs and regulators have to check pre-qualification and registration (eligibility phase) and
ensure compliance i.e. monitoring, control, penalties (control/ compliance phase).93
Market participants participating in a cross-border scheme would potentially have
additional costs of 0-3 FTEs.
The expert study found that providing for a common framework for cross-border
participation (Option 1) would actually reduce the cost of cross-border participation when
89
Thema (2016), Framework for cross-border participation in capacity mechanisms (First interim report)
90
Costs in the design phase are one-time costs.
91
The same expert study also found that the overall cost of of the design are fairly small compared to the
overall cost of the CM (remuneration of the participation ressources).
92
FTEs in other phases refer to (annually) recurring costs.
93
There is a difference between a generator model for cross-border participation and an interconnector
model in relation to the costs. This difference can be explained by the number of participants and
jurisdictions. The more participants and countries participate, the greater the potential for increased
costs.
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compared with Option 0. This is because in Option 0 cross-border arrangements have to
be set up and operated based on indivdual arrangements which involve costs that can be
saved if these arrangements follow a template. For TSOs and NRAs, the study estimates
the cost saving for Option 1 to be 30% of eligibility costs and compliance costs compared
to Option 0.
In analogy to Option 1 we would expect that providing for a common template for capacity
mechanisms (Option 2) would actually reduce the design cost of CMs when compared with
Option 0 and Option 1. This is because in Option 0 and Option 1 CMs are designed
individually which involve costs that can be saved if the CM design follows a template.
For TSOs and NRAs, the study estimates the cost savings to be 50% of eligibility costs
and compliance costs compared to Option 0.
Table 1: Comparison of the Options in terms of their effectiveness, efficiency and
coherence of responding to specific criteria
Option 0:
do nothing (EEAG)
Option 1:
EU framework for
cross-border
participation
Option 2: EU
framework for cross-
border participation +
blueprint
Investment distortions
due to uncoordinated
CMs
-
More chance of
distorted locational
signals and over-
capacity in zones with
CM
+
Less chance of
investment distortions
due to effective cross-
border scheme
+
Less chance of
investment distortions
due to effective cross-
border scheme
Overall system costs
-
Higher overall system
costs
+
Lower overall system
costs due to reduction in
CM auction price
+
Lower overall system
costs due to reduction in
CM auction price
Speed of
implementation
-
Individual XB
arrangements for each
border
+
Harmonised XB
arrangements across the
EU
+
Harmonised XB
arrangements across the
EU
Complexity and
administrative impact
--
High administrative
impact for market
participants operating in
more than one zone
+
Reduced complexity
and administrative
impact due to
harmonised rules
+
Reduced complexity
and administrative
impact due to
harmonised rules
The assumptions are based on the Market Design Initiative consultations and other meetings with
stakeholders
Subsidiarity
The subsidiarity principle is fulfilled given that the EU is best placed to provide for a
harmonised EU framework with a view to creating an effective cross-border participation
scheme. Member States currently take separate approaches to cross-border participation
including often not allowing for foreign participation or only implicitly taking into account
foreign contribution to own security of supply. As cross-border participation in CMs
requires neighbouring TSOs' and NRA's full cooperation, individual Member States might
not be able to deliver a workable system or only provide suboptimal solutions.
Providing for a framework on cross-border participation in capacity mechanisms would be
also in line with the proportionality principle given that it aims at preserving the
properties of market coupling and ensuring that the distortions of uncoordinated national
mechanisms are corrected and the internal market is able to deliver the benefits to
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consumers. At the same time, it removes the need for each Member State to design a
separate individual solution – and potentially reducing the need for bilateral negotiations
between TSOs and NRAs.
Stakeholders' opinions
Public consultation on the Market Design Initiative
Stakeholders clearly support a common EU framework for cross-border participation in
capacity mechanisms (52% in favour, 10% against). Most of the stakeholders including
Member States agree that a regional/European framework for CMs are preferable.
Similarly, Member States might instinctively want to rely more on national assets and
favour them over cross-border assets. It is often claimed that in times of simultaneous
stress, governments might choose to 'close borders' putting other Member States who
might actually be in bigger need in trouble.
Sensibilities
EFET94
is of the opinion that "Member States with a CM need to explicitly take into account
the contribution of foreign capacities. This will likely require advanced TSO-TSO
cooperation, and will require more complex arrangement at EU or regional level. EFET
therefore supports the establishment of EU rules in this domain. One note of caution
though: in no case should the cross-border participation to national CMs result in any
reservation of cross-border transmission capacity or alteration of cross-border flows from
the market outcomes".
Wind Europe95
"acknowledges the need for a common set of indicators and criteria for
cross-border participation, as this is a necessary condition for the existence of capacity
markets where needed." […] In addition, they "call for a strong involvement of the
Commission to ensure that such a common European framework for cross-border
participation does not serve as a pretext for introducing potentially unneccesary CMs."
ACER and CEER96
"fully endorse that explicit participation of foreign capacity providers
into national CMs through a market-based mechanism should be allowed. In this respect,
[…] a few important prerequisites need to be fulfilled to make explicit cross-border
participation possible and beneficial: a) TSOs are incentivised to make a sufficient and
appropriate amount of cross-border capacities available for cross-border trade
throughout the year(s); b) TSOs are not allowed to adjust, limit or reserve these cross-
border transmission capacities at any point in time, including in case of shortage situation;
and c) TSOs agree ex ante on the treatment of local/ foreign adequacy providers in case
of a widespread shortage situation (i.e. when a shortage situation affects at least two
countries simultaneously)."
94
EFET response to the public consultation on the Market Design Initiative, 2015
95
WindEurope response to the public consultation on the Market Design Initiative, 2015
96
ACER-CEER response to European Commission Capacity Mechanism Sector Inquiry, July 2016


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 2/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
240
TABLE OF CONTENTS
ANNEXES................................................................................................................................ 241
Annex I: Procedural information ..................................................................................................241
Annex II: Stakeholder consultations.............................................................................................249
Annex III: Who is affected by the initiative and how....................................................................264
Annex IV: Analytical models used in preparing the impact assessment. .....................................281
Annex V: Evidence and external expertise used...........................................................................315
Annex VI: Evaluation.....................................................................................................................321
Annex VII: Overview of electricity network codes and guidelines ...............................................323
Annex VIII: Summary tables of options for detailed measures assessed under each main option
......................................................................................................................................................325
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ANNEXES
Annex I: Procedural information
Lead DG: DG Energy
Agenda planning/Work Programme references:
- AP 2016/ENER/007 (Initiative to improve the electricity market design)
- AP 2016/ENER/026 (Initiative to improve the security of electricity supply)
Publication of Inception Impact Assessment:
- October 2015 (Initiative to improve the electricity market design)
- October 2015 (Initiative to improve the security of electricity supply)
No feedback was received on the Inception Impact Assessments
Inter-service group:
An Inter-service group meeting was used comprising the Legal Service, the
Secretariat-general, DG Budget, DG Agriculture and Rural development, DG
Climate action, DG Communications Networks, Content and Technology, DG
Competition, DG Economic and Financial Affairs, DG Employment, Social affairs
and Inclusion, DG Energy, DG Environment, DG Financial stability, Financial
services and Capital markets, DG Internal market, Industry, Entrepreneurship and
SMEs, the Joint Research Centre, DG Justice and Consumers, DG Mobility and
Transport, DG Regional and urban development, DG Research and innovation, DG
Taxation and Customs Union.
Not all Directorate-generals did participate in each ISG meeting
Meetings of this ISG were held on: 28 October 2015, 25 April 2016, 20 June 2016
and 8 July 2016
Consultation of the RSB
The impact assessment was submitted to the RSB on 20 July 2016. On 14
September 2016, the impact assessment was discussed with the RSB. On 16 of
September 2016 the RSB issued it opinion, which was negative. It requested to
receive a revised draft of the IA report addressing its recommendations whilst
briefly explaining what changes have been made compared to the earlier draft. A
draft impact assessment was resubmitted on 17 October 2016. A positive RSB
Opinion, with reservations, was issued on 7 November 2016?
The opinions and the changes made in response are summarised in the tables below.
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Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
Issues cross cutting to other impact assessments
This IA and the IA on the revision of the
renewables directive need a coherent analysis
of renewable electricity support schemes.
They need to reconcile different expectations
of what the market will deliver in terms of the
share of renewable electricity and of the
participation of prosumers. Given uncertainty
on these issues, both IAs should incorporate
the same range of possible outcomes in their
analysis
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4. This vision includes a section on the
connection with the share of RES E and
prosumers.
The IA should clarify and explain the content
and assumptions of the baseline scenario in
relation to the other parallel initiatives
A dedicated section was included in Annex
IV clarifying all points raised concerning the
baseline, REF2016 and EUCO27.
The baseline description in 5.1.2, 5.2.2,
6.1.1.2 and 6.1.1.4 was improved and
references were made to its more detailed
description in the Annex.
Issues specific to the present impact assessment
The IA report is too long and complex to
make it helpful in informing political
decisions. The Board recommends that this
report begin with a concise, plain-language
abstract of approximately 10-15 pages. This
abstract should summarise the key elements
of the IA and identify the main policy trade-
offs
A plain-language abstract has been added at
the beginning of the document.
The report should present a clear vision for
the EU electricity market in 2030 and beyond
with a distinction between immediate
challenges and longer term developments.
This vision needs to be coherent with EU
policies on competition, climate and energy.
It also needs to be consistent with the parallel
initiatives, notably the revision of the RES
Directive. In particular, this applies to the
assumptions and expectations on what the
new electricity market design could deliver
on its own and whether the renewable target
requires complementary market intervention.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4 covering issues mentioned.
A detailed section on in RES E in connected
with the MDI is contained in a text box in
section 6.2.6.3. Another box is located in
Section 2.1.3.
Further clarifications have been added in
section 1.2.1 on interlinkages with RED II.
Based on a common (with other parallel
initiatives) baseline scenario, the report
should prioritise the issues to be addressed,
present an appropriate sequencing and
strengthen the treatment of subsidiarity
considerations such as for action related to
energy poverty and distribution system
operators.
A dedicated section was introduced in Annex
IV clarifying all points raised concerning the
baseline, REF2016 and EUCO27.
The baseline description in 5.1.2, 5.2.2,
6.1.1.2 and 6.1.1.4 was improved and
references were made to its more detailed
description in the Annex.
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Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
A dedicated section on sequencing was
introduced as section 7.5.3
Regarding the treatment of subsidiarity for
actions related to energy poverty, please see
sections 5.4.4; and 5.4.5. The report assesses
the options with regards to subsidiarity. It
argues that measures in Option 1 are
proportionate and in line with the subsidiarity
principle while measures in Option 2 entail
significant costs and may be better carried out
by national authorities.
When assessing the impacts of the different
options, the report should indicate whether
and how the models of “energy only markets”
will coexist with capacity mechanisms and
assess the risks of an uncoordinated
introduction of capacity remuneration
mechanisms across the EU. The impact
analysis should also report on the
effectiveness of the options to deliver the
adequate investment and price responses.
On how the models of "energy only markets"
will coexist with CMs, clarifications have
been introduced in section 2.2.2.
Section 6.2.6 now includes a sub-section on
investments, discussing all relevant issues.
Main recommendations for improvements
The analysis of support schemes for
renewable electricity should be consistent
across this impact assessment and the one
covering renewable energy sources. The
reports should clarify what support schemes
will be needed, and whether these are needed
only in case the market fails to deliver the
2030 EU target of at least 27% of RES in
final energy consumption, or will be used to
promote certain types of renewable energy.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4. This includes a vision on whether
outside-the- market measures to support for
RES E are needed up to 2030. The question
what type of out-of-market support
mechanisms are needed falls within the remit
of the RED II IA.
A dedicated section was included in Annex
IV clarifying all points raised concerning the
baseline. Via the definition of the baseline,
the impact assessment for the MDI and RED
II are fully compatible, including as regards
the assessment of support schemes.
The IA should take into account the tendering
procedure envisaged for procuring support
for renewable energy producers and assess its
impact on the electricity market.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4. This includes a vision on whether
outside-the- market measures to support for
RES E are needed. A detailed section on in
RES E in connected with the MDI is
contained in a text box in section 6.2.6.3.
Further clarifications have been added in
section 1.2.1 on interlinkages with RED II.
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Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
In addition, even though the report does not
present a blueprint for a capacity
remuneration mechanism (as it is in the remit
of the state-aid guidelines/EU competition
policy), it should analyse possible detrimental
effects of such mechanisms being introduced
in the EU in an uncoordinated fashion. In
particular, the IA should examine distortions
to investment incentives and price setting
mechanisms.
The clarification in Annex IV as regards the
baseline explains how, the impact
assessments for the MDI and RES E are fully
compatible, including as regards to the
tendering procedure (see section on current
market arrangements in Annex IV).
Text adapted in section 2.2.2 and included a
reference to forthcoming report by DG
Competition.
The expected involvement of consumers and
prosumers in supplying electricity and
managing its demand has to be consistent
across the two impact assessments.
The analysis should integrate the effects of
potentially more volatile electricity prices and
high fixed network costs on prosumer
involvement and on the long-term risk that
these might disconnect from the network as
local storage technology evolves.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4.
This includes a vision on prosumers and the
risk of disconnection, which is further
developed in a text box in Section 6.1.4.2.
Also the RED II IA has been adjusted.
In devising the options, the report should be
proportionate to the importance of the
problems/objectives and realistic in assessing
what can be achieved. For instance, options
linked to the issue of energy poverty (being
part of the social policy) should be built
around increasing transparency and peer
pressure among Member States rather than
the single market motive.
See section 2.4.1 and section 5.4.4. The
report clarifies the main objective of the
measures linked to energy poverty (i.e.
description of the term 'energy poverty' and
measurement of energy poverty), which
already apply to Member States (Member
States should address energy poverty where it
is identified). Better monitoring of energy
poverty across the EU will, on one hand, help
Member States to be more alert about the
number of households falling into energy
poverty, and on the other hand, peer pressure
encourages Member States to put in place
measures to reduce energy poverty.
The baseline scenario should be clarified,
including the link with the 2016 reference
scenario and underlying assumptions
A dedicated section was included in Annex
IV clarifying all points raised concerning the
baseline, REF2016 and EUCO27.
Some more technical comments have been
transmitted directly to the author DG and are
expected to be incorporated into the final
version of the impact assessment report
All technical comments have been addressed.
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Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
The IA report needs to be more reader-
friendly and helpful for decision-making. The
report should contain a 10-15 page abstract
that succinctly presents the main elements of
the analysis, the policy trade-offs and the
conclusions. The main text should be
streamlined to contain the crucial elements of
the analysis in the main part of the report
A reader friendly abstract that succinctly
presents the main elements of the analysis,
the policy trade-offs and the conclusions has
been added to the main text of the IA.
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Comments made by RSB in second
Opinion on 7 November 2016
Modifications made in reaction to
comments RSB
Opinion RSB on resubmission
Restoring price signals for investments is
one crucial element of the revised market
design. The report is clearer on its view
that undistorted markets deliver the right
price signals for investment. The report
should more convincingly explain how
adequate pricing could be achieved in the
presence of national capacity markets and
subsidies for renewables which might
exacerbate excess capacity in the market.
The report should assess the risk of
persistent low electricity wholesale prices
and associated consequences for the
effectiveness of the initiative. What would
be the effects for investment, demand
response, elimination of subsidies, and
consumer benefits?
Reference is made to the new Box 9
underneath Section 6.4.6 for further
explanations, which was added following
the RSB comments.
Further recommendations for improvements
Internal coherence and risks:
The analysis in the report demonstrates
that the vision for the EU electricity
market in 2030 and beyond relies on the
implementation of many different policies
and assumptions, and is subject to
numerous risks. The narrative of the report
should more clearly reflect these risks. The
report should propose modalities to review
assumptions and monitor implementation
at intermediate stages. The text of the
report should reflect the trade-off between
restoring the EU internal energy market in
its pure form and government intervention
to support renewable energy sources and to
maintain security of supply.
Text has been added to Sections 8.1 and
8.2.2 with regard to the reviewing of
assumptions and monitoring of
implementation.
The 2030 RES E objectives are part of the
base-line of the analyses. Trade-offs
between government interventions in
support of RES E are investigated in the
REDII impact assessment. However, in the
present report, it has been rendered more
clearly what elements of the RED II
initiative are important to the impacts of
the present initiative.
See in this regard Section 1.1.1, 1.2.1, Box
7 under section 6.2.6.3, Box 9 under
Section 6.4.6 and Annex IV.
It is noted that improving market
functioning reduces the need for
government intervention with regard to
both RES E (See Section 1.1.1.4, Box 7
below section 6.2.6.3 and section 7.5.1)
and resource adequacy (See section 6.2.2.1,
Section 6.2.6.3 and Section 7.5.1).
Impact analysis: The vision of an energy
Union places citizens at its core. The
report should therefore better address the
risks and benefits to consumers, especially
with regard to expected higher price
variability. It should discuss not just
possible long run benefits, but also costs
The risks of greater price variability have
been introduced in two new text boxes in
Section 5.1.4.3 (Box 4) of the main impact
assessment document, and in Section 3.1.5
of the Annexes to the Impact Assessment.
These specifically address the benefits and
risks of dynamic electricity pricing
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Comments made by RSB in second
Opinion on 7 November 2016
Modifications made in reaction to
comments RSB
(including switching fees) in the short and
medium term. In the same vein, the report
should examine the impact of the policy on
various groups of consumers
contracts, which are a frequent concern of
consumer groups.
The impacts of the measures in Problem
Area IV (Retail Markets) on different
groups of consumers have been addressed
in a text box in Section 6.4.3.2 of the
Impact Assessment Report (Box 8) and text
boxes in Sections 7.1.5, 7.2.5, 7.3.5, 7.4.6,
7.5.5, and 7.6.6 of the Annexes to the
Impact Assessment.
While the Board takes note that impacts
are based on modelling, the results of the
modelling should be critically reviewed to
avoid false expectations, in view of many
assumptions taken. For instance, the
modelling results in the average level of
wholesale prices at 74€/MWh already in
2020 and 103€/MWh in 2030). The
attainment of these price levels is hard to
imagine in reality, given that currently that
level is around 34€ and more renewable
capacity is being deployed into the system,
still benefitting from the current support
schemes for RES-E (based mostly on feed-
in tariffs). Lower than modelled wholesale
prices could seriously undermine the
investment outcome, the assumed
increased engagement of consumers and
demand response – the cornerstones of the
EU Energy Union.
To improve clarity, the new Box 9 includes
further explanations. Please also see new
footnotes 345 and 384
.
Similarly, the effectiveness of the revised
RES-E support schemes (as proposed in
the RED II IA) is not critically discussed.
First, the report needs to emphasize that
they would not be based on any type of
feed-in tariff but premiums on top of
market revenues and these premium will
be auctioned. Second, the report needs to
consider the fact that such auctions may
not necessarily be effective in reducing the
support to renewable energy sources. This
is particularly relevant in a situation where
the share of renewables in the electricity
generation mix is expected to grow
It has been made clearer that market based
support schemes, such as premium schemes
combined with auctions, are an underlying
premise of the impacts of the present
initiative. (See section 1.1.1, 1.2.1, Box 7
under section 6.2.6.3, Box 9 underneath
section 6.4.6 and Annex IV)
The phase-out of non-market based support
schemes has already commenced under the
EEAG adopted in 2014 and is further
reinforced by the measures proposed by
RED II. It is therefore assumed that non-
market based support schemes are fully
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Comments made by RSB in second
Opinion on 7 November 2016
Modifications made in reaction to
comments RSB
substantially and the wholesale prices will
be depressed at least until the current
support schemes for RES-E are reviewed
in 2024.
phased out by 2024, whereas the impact
assessment looks at the situation in 2030.
For more detail see Annex IV.
The cost effectiveness of the RES E
support schemes as such is the subject of
the RED II impact assessment.
Procedure and presentation
While the report is still very long, the
inclusion of the abstract has improved the
presentation of relevant information,
though the issue of policy trade-offs
(market vs. government interventions)
should be emphasized more explicitly
References to policy trade-offs (market
versus government intervention) have been
further emphasised. See for instance the
abstract, page 10 and 13 and Sections
6.2.2.1, 6.2.6.3 and 7.5.1. Furthermore,
Options 2 and 3 under problem area II
expressly seek to address the compatibility
of government intervention in a market
context.
An overview of evidence and external expertise used is provided in a separate annex.
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Annex II: Stakeholder consultations
Public consultations
In preparation of the present initiative, the Commission has conducted several public
consultations, in particular:
- public consultation on generation adequacy, capacity mechanisms, and the internal
market in electricity, conducted in 2013;
- consultation on the retail energy market, conducted in 2014;
- public consultation on a new energy market design, conducted in 2015;
- public consultation on risk preparedness in the area of security of electricity supply,
conducted in 2015.
These public consultation and their results are describe in more detail below.
Stakeholder opinions are also summarised in boxes for each main policy option in section
5 and, if appropariate, elsewhere of the present impact assessment. Even more detailed
representations of stakeholder opinions are contained in Section 7 of each the annexes
assessing the options for detailed measures.
Public consultation on generation adequacy, capacity mechanisms, and the internal
market in electricity
Resource adequacy related issues were the subject of a public consultation1
conducted from
15 November 2012 to 7 February 2013 through the "Consultation on generation adequacy,
capacity mechanisms, and the internal market in electricity". It was open to EU and
Member States' authorities, energy market participants and their associations, and any
other relevant stakeholders, including SMEs and energy consumers, and citizens. It aimed
at obtaining stakeholder's views on ensuring resource adequacy and security of electricity
supply in the internal market.
As regards the quality and representativeness of the consultation, the consultation received
148 individual responses from public bodies, industry (both energy producing and
consuming) and academia. Most responses (72%) came from industry. Responses were of
a high standard, not only engaging with the questions posed and the challenges being
addressed, but bringing valuable insights to the Commission's reflections of this important
topic. The consultation appears representative in comparison with similar consultations.
1
https://ec.europa.eu/energy/sites/ener/files/documents/20130207_generation_adequacy_consultation_d
ocument.pdf
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The following paragraphs provide a summary of the responses available on the
Commission's website2
. The responses and a summary thereof are also available on the
Commission's website3
.
(i) Government interventions. Respondents to the consultation responses repeatedly
highlighted the policy uncertainty and national uncoordinated interventions of
various kinds, in particular support for renewables, as being critical elements in
discouraging investment. This was highlighted frequently by industry and also by
academics and think tanks. The related issue of fixing the flaws of ETS was also
raised repeatedly by industry. For example Energy UK states that "national
measures often response to a lack of coherence in EU energy policy itself – in
particular there is a conflict between the market driven approach to liberalisation
and to EU ETS and the various sectoral targets in renewables, energy efficiency
etc." The Netherlands (Ministry of Economic Affairs) responded "the absence of a
credible carbon policy and a lack of proper market functioning cannot be
underestimated";
(ii) Market functioning. In the context of a weak demand and economic crisis, Europe's
energy markets today area was deemed characterised by two developments: the
integration of large amounts of renewables and the implementation of the EU target
model. This was clearly reflected in the responses to this consultation. Overall
respondents' opinions were split as to whether energy-only markets could deliver
investments needed to ensure generation adequacy and security of supply.
However, there is near unanimous support from respondents for the importance of
the completion of the integration of day-ahead, and close to real time markets as a
an important contributor to security of supply although, some respondents caution
that this will not address fundamental problems with whether energy-only markets
can deliver resource adequacy Similarly, there are strong calls facilitating demand
side response and the development of grids in line with the ten year network
development plan. Almost all responses to the consultation raised the impact of
RES E on the market. For example the UK response discusses the impact that more
low marginal cost pricing will have on the market, and the issue is discussed in
detail in the Clingendael paper submitted in response to the consultation. Industry
in particular raised the issue about the impact that RES E support schemes had on
the market. While many raise the issue of any out-of-market support creating
distortions, the position set out in the response of Eneco, a Dutch company is worth
quoting "In general, support for specific energy sources does not undermine
investments to ensure generation adequacy, it just changes the merit order. But
details of support mechanisms can, specifically if a support mechanism lowers the
value of flexibility". This consideration can be seen in the numbers of respondents
who cite priority dispatch or lack of balancing responsibility for RES E producers
as posing particular problems on the market, an issue which is separate from the
level of support for RES producers, as indeed recognised by Germany who stat in
2
https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E
nergy%20Market.pdf
3
https://ec.europa.eu/energy/en/consultations/consultation-generation-adequacy-capacity-mechanisms-
and-internal-market-electricity
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their response "Allerdigs ist ein Umstieg von der Festvergutuetung unter der
garantierten Abnahme des EE-Stroms auf ein System der Marktintergration
notwendig, in dem die Erneueuerbaren ihre Einspeisung an dem Marktpreissignal
orientieren…".
(iii) Assessing security of supply. There is widespread recognition of a need for
improved assessment of generation and security of supply in the internal market
given the impact of both RES E and market integration. Proposal have been made
suggesting a need for more scenario analysis based on different weather conditions,
different timespans for the assessment (long-term, short-term), more detailed
assessment of flexibility and more coordination between TSOs and more sensitivity
analysis. In this regard the existing ENTSO-E generation adequacy assessment is
not felt to meet future needs, without suggesting that ENTSO-E is not carrying out
its current role properly. There is particularly strong support for more regional
generation adequacy assessments combined with a common methodology for
undertaking such assessments. For example France in its response states "Il
pourrait notamment être utile de renforcer la cohérence à l’échelle régionale des
différentes méthodes d’analyse et des scénarios produits au niveau national,
souvent interdépendants. Ces analyses régionales viendraient ensuite alimenter un
exercice réalisé à l’échelle de l’Union". Support for binding standards is less strong
among respondents. Many of those who, in principle, would welcome common
standards point to the difficulties in establishing such standards while MS retain
responsibility for Security of Supply (and hence determining standards). Others
(such as the Oeko institute) consider that more harmonised activities of Member
states are essential in the internal market. There was limited support for a revision
of the Security of Supply directive, which was perceived to fulfil its limited role.
Again France states that "Il apparaît préférable de privilégier l’élaboration rapide
de ces codes et achever ainsi la mise en oeuvre des dispositions du 3ème
paquet
avant d’envisager des mesures nouvelles au travers de la refonte de cette
directive." However some stated that since the Directive was adopted before the
Third Package, the situation after the Third Package is different and therefore the
level of cooperation prescribed by the Directive does not correspond to today's
situation. Summarising, there was widespread support for a reassessment of how
generation adequacy and security of supply are assessed, and a recognition for the
need for actions to be coordinated. The question which stands out is what are the
best tools to do this. Here the electricity coordination group ('ECG') (explicitly
mentioned by several respondents) can play a critical role. The Commission will
continue to examine what are the best tools available to achieve the widely
supported aim of improved generation adequacy assessment.
(iv) Interventions to ensure security of supply. As already noted opinion is divided on
whether energy only markets can deliver the investments which will be needed to
ensure generation adequacy and security of supply in the future. However, there
were even more varied opinions on the effectiveness of different capacity
remuneration mechanisms. Given this divergence of opinion therefore there is only
limited support for a European blueprint, many respondents pointing to divergent
local circumstances and the need to address specific problems as militating against
such an approach. Against this there was very strong support, particularly among
industry and academica, for EU wide criteria, governing capacity mechanisms
extending also to the high level criteria which proposed in the consultation paper.
Among Member States the UK specifically called for criteria to be linked to State
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aid assessments, and notwithstanding caution about overly detailed assessment at
EU level its detailed comments on the individual criteria in the consultation paper
were broadly supportive. FR states "Il est toutefois utile et légitime que la
Commission européenne suive de près l’impact des choix des Etats membres sur le
marché intérieur" but also cautions that "Il semble prématuré à ce stade de définir
des critères détaillés de compatibilité avec le marché intérieur". DE states that the
Commission "im Bedarfsfall eintreten, der die Koordinierung zwischen den MS zu
einer stärker gemeinsamen …Gewährleistung der Versorgungssicherheit
erleichtert.".
Consultation on the retail energy market
A public consultation dedicated to electricity retail markets and end-consumers4
was
conducted from 22 January 2014 to 17 April 2014. It was open to all EU citizens and
organizations including public authorities, as well as relevant actors from outside the EU.
This public consultation aimed at obtaining stakeholder's views on the functioning of retail
energy markets.
As regards representativeness and quality, the Commission received 237 responses to the
consultation. About 20% of submissions came from energy suppliers, 14% from DSOs,
7% from consumer organisations, and 4% from NRAs. A significant number of individual
citizens also participated in the consultation.
The following paragraphs provide a summary of the responses, which are also available
on the Commission's website5
.
(v) Retail competition. Respondents to this public consultation felt that market-based
customer prices are an important factor in helping residential customers and SMEs
better control their energy consumption and costs (129 out of 237 respondents
considered that it was a very important factor while other 66 qualified it as
important for the achievement of the said objective). Moreover, out of 121
respondents who considered that the level of competition in retail energy markets
is too little, 45 recognised regulation of customer prices as one of the underlying
drivers.
81% of the respondents agreed that allowing other parties to have access to
consumption data in an appropriate and secure manner, subject to the consumer's
explicit agreement, is a key enabler for the development of new energy services for
consumers.
As regards whether it is sufficiently easy without facing disproportionate
permitting and grid connection procedures for a consumer to install and connect
renewable energy generation and micro-CHP pursuant to the provisions of the RES
and Energy performance in buildings Directives the views are split.
4
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
5
https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E
nergy%20Market.pdf
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(vi) Consumer issues. 222 out of 237 respondents to the retail market public
consultation believed that transparent contracts and bills were either important or
very important for helping residential consumers and SMEs to better control their
energy consumption and costs.
When asked to identify key factors influencing switching rates, 89 respondents out
of 237 stated that consumers were not aware of their switching rights, 110 stated
that prices and tariffs were too difficult to compare due to a lack of tools and/or due
to contractual conditions, and 128 cited insufficient benefits from switching.
178 out of 237 agreed that ensuring the availability of web-based price comparison
tools would increase consumers' interest in comparing offers and switching to a
different energy supplier. 40 were neutral and 4 disagreed.
Only 32 out of 237 respondents agreed with the statement: "There is no need to
encourage switching". 98 disagreed and 90 were neutral.
(vii) DSOs and network tariffs. The majority of the respondents consider that DSOs
should carry out tasks such as data management, balancing of the local grid,
including distributed generation and demand response, and connection of new
generation/capacity (e.g. solar panels). The majority of stakeholders thought these
activities should be carried out under good regulatory oversight, with sufficient
independence from supply activities, while a clear definition of the role of DSOs
(and TSOs), but also of the relationship with suppliers and consumers, is required.
Regarding distribution network tariffs, 34% of the respondents consider that
European wide principles for setting distribution network tariffs are needed, while
another 34% is neutral and 26% disagree. Time-differentiated tariffs are supported
by ca 61% of the respondents, while the majority of stakeholders consider that cost
breakdown (78%) and methodology (84%) of distribution network tariffs should
be transparent.
The majority of stakeholders also consider that self-generators/auto-consumers
should contribute to the network costs even if they use the network in a limited
way. To this end, ca. 50% of the respondents consider that the further deployment
of self-generation with auto-consumption requires a common approach as far as the
contribution to network costs is concerned.
Regarding self- consumption, self- consumers should contribute to network costs
even if they use the network in a limited way and further deployment would require
a common approach. Moreover, however the responders think that to this end a
common approach with simplified related administrative procedures is required.
Granting of financial incentives by Member States to promote self-generation and
auto-consumption splits views evenly.
(viii) Demand response. Over 50% of the responders think that residential consumers
lack sufficient information to use energy efficiently and make use of advances in
innovation that have enabled a broad range of distributed generation and demand
response for industrial and commercial consumers. While the views are split in
respect to the ESCOs role to facilitate the favourable contractual arrangements and
other related services and as regards the access to respective choices of energy
efficiency services consumers have. Similarly, responders' views diverge when
assessing whether there should be done more to support the establishment of
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ESCOs that are active in the field of energy efficiency. In particular, 44% of the
answers indicate that indeed there is more room to support ESCOs establishment
and 28% of the answers received point out that are satisfied with the related service.
Moving on, the overwhelming majority industrial consumers are satisfied by their
access to demand response and balancing services while on the same question the
views coming from SMEs and commercial suppliers are split. Further, 24 of the
residential consumers have access to demand response and balancing services
while this percentage is 35% for the commercial sector and SMES and reached the
66% for industrial customers. As to the entity of the demand response service
provider, over than 70% of the responders believe that this service should be
provided by the suppliers, though 50% thinks that aggregators are also fit to provide
the service while a minority would allocate this task to the DSOs.
Most responders view that they should be able to be participating in aggregation
programmes irrespective of their load size in primary balance markets. The best
way of making this happen is through aggregators and developing products taken
into account consumers flexibility characteristics and size. In addition, responders'
tend to agree that related demand response products should be hassle-free,
applicable to all consumers' profiles. People also disagree with the claim that very
specific data management tasks with regards to various distribution network actors
should be defined at European level.
Suppliers are perceived as having the most access to dynamic pricing and/or time
differentiated tariffs. They should first and aggregators, as a second choice, offer
demand response services and dynamic pricing to residential consumers, SMEs.
Unclear benefits, regulatory barriers and then unclear legal framework are
identified as the greatest barriers to limited dynamic pricing in a country. Some
respondents indicated that strengthening of infrastructure will allow greater retail
market competition
Responses agree that consumers should have a right to a smart meter installed at
their own request and at their expense also in regions without general rollout.
However, there is a slight tendency against having the choice of a smart meter with
functionalities of their own choice even if a different type is rolled out in their area.
In respect to smart appliances and energy management systems, responders
consider them as important to make the field of demand response accessible to a
broad range of consumers and that they can work as facilitators to this end. The
views also favour the display of consumption and consumption patterns by the
smart appliances and do not consider this as a detriment to the consumers' comfort.
Public consultation on a new energy market design
A wide public consultation6
on a new energy market design (COM(2015)340 was
conducted from 15 July 2015 to 9 October 2015. It was open to EU and Member States'
authorities, energy market participants and their associations, SMEs, energy consumers,
NGOs, other relevant stakeholders and citizens. This public consultation aimed at
6
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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obtaining stakeholder's views on the issues that may need to be addressed in a redesign of
the European electricity market.
As regards representativeness and quality, the Commission received 320 replies to the
consultation. About 50 % of submissions come from national or EU-wide industry
associations. 26% of answers stem from undertakings active in the energy sector (suppliers,
intermediaries, customers), 9% from network operators. 17 national governments and
several national regulatory authorities submitted also a reply. A significant number of
individual citizens and academic institutes participated in the consultation.
The first assessment of the submissions confirmed broad support of a number of key ideas
of the planned market design initiative, while views on other issues vary. The following
paragraphs provide a summary of the responses, also available on the Commission's
website7
.
(i) Electricity market adaptations. A large majority of stakeholders agreed that
scarcity pricing, i.e. price formation better reflecting actual demand and supply, is
an important element in the future market design. It is perceived, along with current
development of hedging products, as a way to enhance competitiveness. While
single answers point at risks of more volatile pricing and price peaks (e.g. political
acceptance, abuse of market power), others stress that those respective risks can be
avoided (e.g. by hedging against volatility). Regulated prices are perceived as one
of the most important obstacles to efficient scarcity pricing.
A large number of stakeholders agreed that scarcity pricing should not only relate
to time, but also to locational differences in scarcity (e.g. by meaningful price zones
or locational transmission pricing). While some stakeholders criticised the current
price zone practice for not reflecting actual scarcity and congestions within bidding
zones, leading to missing investment signals for generation, new grid connections
and to limitations of cross-border flows, others recalled the complexity of prices
zone changes and argued that large price zones would increase liquidity.
Many submissions highlight the link between scarcity pricing and incentives for
investments/capacity remuneration mechanisms, as well as the crucial role of
scarcity pricing for kick-starting demand response at industrial and household
level.
Most stakeholders agree with the need to speed up the development of integrated
short-term (balancing and intraday) markets. A significant number of stakeholders
argue that there is a need for legal measures, in addition to the technical network
codes under development, to speed up the development of cross-border balancing
markets, and provide for clear legal principles on non-discriminatory participation
in these markets.
Most stakeholders support the full integration of Renewable energy sources (RES)
into the market, e.g. through full balancing obligations for renewables, phasing-out
priority dispatch and removing subsidies during negative price periods. Many
stakeholders note that the regulatory framework should enable RES to participate
7
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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in the market, e.g. by adapting gate closure times and aligning product
specifications. A number of respondents also underline the need to support the
development of aggregators by removing obstacles for their activity to allow full
market participation of renewables.
As concerns phasing out of public support schemes for RES, stakeholders take
different positions. While some argue for phasing out support schemes as soon as
possible, others argue that they will remain an important tool until technologies
have fully matured. They point at existing fossil fuel subsidies and the need to
continue subsidizing RES and maintaining other market corrections as long as
subsidies for traditional fuels and nuclear are not removed. Certain stakeholders
underline that support could progressively take more and more the form of
investment aid (as opposed to operating aid). A large majority of stakeholders is in
favour of some form of coordination of regional support schemes. The need for an
ETS reform to allow full market integration of RES was mentioned very often.
Most stakeholders agree that diversified charges and levies are a source of market
distortions.
(ii) Resource adequacy. A majority of answering stakeholders is in favour an "energy-
only" market, possibly augmented with a strategic reserve. Many generators and
some governments disagree and are in favour of capacity remuneration
mechanisms. Many stakeholders share the view that properly designed energy
markets would make capacity mechanisms redundant.
There is almost a consensus amongst stakeholders on the need for a more aligned
method for resource adequacy assessment. A majority of answering stakeholders
supports the idea that any legitimate claim to introduce capacity remuneration
mechanisms should be based on a common methodology. When it comes to the
geographical scope of the harmonized assessment, a vast majority stakeholders call
for regional or EU-wide adequacy assessment, while only a minority favour a
national approach. There is also support for the idea to align adequacy standards
across Member States. Stakeholders clearly support a common EU framework for
cross-border participation in capacity mechanisms.
(iii) Retail issues. Many stakeholders identified a lack of dynamic pricing (more
flexible consumer prices, reflecting the actual supply and demand of electricity) as
one of the main obstacles to kick-starting demand side response, along with the
distortion of retail prices by taxes/levies and price regulation. Other factors include
market rules that discriminate consumers or aggregators who want to offer demand
response, network tariff structures that are not adapted to demand response and the
slow roll-out of smart metering. Some stakeholders underline that demand response
should be purely market driven, where the potential is greater for industrial
customers than for residential customers. Many replies point at specific regulatory
barriers to demand response, primarily with regards to the lack of a standardised
and harmonised framework for demand response (e.g. operation and settlement).
Regarding the role of DSOs, the respondents consider active system operation,
neutral market facilitation and data hub management as possible functions for
DSOs. Some stakeholders point at a potential conflict of interests for DSOs in their
new role in case they are also active in the supply business and emphasized that the
neutrality of DSOs should be ensured. A large number of the stakeholders stressed
the importance of data protection and privacy, and consumer's ownership of data.
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Furthermore, a high number of respondents stressed the need of specific rules
regarding access to data. As concerns a European approach on distribution tariffs,
the views are mixed; the usefulness of some general principles is acknowledged by
many stakeholders, while others stress that the concrete design should generally
considered to be subject to national regulation.
(iv) Regulatory framework/electricity market governance. Stakeholders' opinions with
regard to strengthening ACER’s powers are divided. There is clear support for
increasing ACER's legal powers by many stakeholders (e.g. oversight of ENTSO-
E activities or decision powers for swifter alignment of NRA positions). However,
the option to keep the status quo is also visibly present, notably in the submissions
from Member States and national energy regulators. While some stakeholders
mentioned a need for making ACER'S decisions more independent from national
interests, others highlighted rather the need for appropriate financial and human
resources for ACER to fulfil its tasks.
Stakeholders' positions with regard to strengthening ENTSO-E remain divided.
Some stakeholders mention a possible conflict of interest in ENTSO-E’s role –
being at the same time an association called to represent the public interest,
involved e.g. in network code drafting, and a lobby organisation with own
commercial interests – and ask for measures to address this conflict. Some
stakeholders have suggested in this context that the process for developing network
codes should be revisited in order to provide a greater a balance of in interests.
Some submissions advocate for including DSOs and stakeholders in the network
code drafting process.
A majority of stakeholders support governance and regulatory oversight of power
exchanges, particularly in relation to their role in market capacity. Other
stakeholders are skeptical whether additional rules are needed given the existing
rules in legislation on market coupling (CACM Guideline).
Stakeholders mention also that the role of DSOs and their governance should be
clarified in an update to the 3rd
Package.
(v) Regionalisation of System Operation. As concerns the proposal to foster regional
cooperation of TSOs, a clear majority of stakeholders is in favour of closer
cooperation between TSOs. Stakeholders mentioned different functions which
could be better operated by TSOs in a regional set-up and called for less
fragmentation in some important of the work of TSOs. Around half of those who
want stronger TSO cooperation are also in favour of regional decision-making
responsibilities (e.g. for Regional Security Coordination Centres). Views were split
on whether national security of supply responsibility is an obstacle to cross-border
cooperation and whether regional responsibility would be an option.
Public consultation on risk preparedness in the area of security of electricity supply
A public consultation on risk preparedness in the area of security of electricity supply was
organized between July 15th and October 9th 2015. This public consultation aimed at
obtaining stakeholder's views in particular on how Member States should prepare
themselves and co-operate with others, with a view to identify and manage risks relating
to security of electricity supply.
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The consulation resulted in 75 responses including public authorities (e.g. Ministries,
NRAs), international organizations (e.g. IEA), European bodies (ACER, ENTSO-E) and
most relevant stakeholders, including SMEs, industry and consumers associations,
companies and citizens. The following paragraphs provide a summary of the responses.
The responses themselves as well as a summary thereof are also available on the
Commission's website8
.
(i) Obligation to draw up risk preparedness plans. A large majority of respondents
(75 %) is in favour of requiring Member States to draw up risk preparedness plans,
covering results of risk assessments, preventive measures as well as measures to be
taken in crisis situations.
There is also a large support for having common templates, which should ensure
that a common approach is followed throughout Europe. Many respondents stress
the need for common definitions, common assessment methods, and common rules
on how to ensure security of supply.
In fact, most respondents acknowledge that in an increasingly interconnected
electricity market, characterised by an increasing amount of variable supply,
security of supply should be considered a matter of common concern (countries are
increasingly dependent on one another and measures taken in one country can have
a profound effect on what happens in neighbouring states and in electricity markets
in general). They also acknowledge that the current legal framework (Directive
89/2005) does not offer the right framework for addressing this inter-dependence.
Therefore, they take the view that risk preparedness plans based on common
templates can help ensure that each Member State takes the measures needed to
ensure security of supply whilst co-operating with and taking account of the needs
of others. Stakeholders, in particular from the industry, also stress that risk
preparedness plans should help ensure more transparency and reduce the scope for
measures that unnecessarily distort markets.
Whilst acknowledging the need for a common approach, a significant number of
stakeholders also state that there should be sufficient room for tailor-made, national
responses to security of supply concerns, as there are substantial differences
between national electricity systems.
Respondents further agree that plans should be drawn up on a regular basis,
proposals range from 2 to 5 years. The degree of transparency of the plans should
depend on its content and may vary in function of it (given the fact that plans
contain possibly sensitive information). Finally, respondents also warn against
creating new administrative burdens and on this basis argue that any obligation to
make risk preparedness plans should take account of already existing assessment
and reporting obligations.
The minority of stakeholders taking the view that there should be no new legal
obligation to draw up risk preparedness plans argue that such plans are already in
8
https://ec.europa.eu/energy/en/consultations/public-consultation-risk-preparedness-area-security-
electricity-supply
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place at the national level, that national electricity systems are profoundly different
from one another and that priority should be given to the process of adopting
network codes and guidelines.
(ii) Content of risk preparedness plans / substantive requirements plans should comply
with. Many stakeholders take the view that it is too early at this stage to decide on
the exact content of risk preparedness plans. They stress the need for more analysis,
as well as in-depth discussions on the issue, in particular within the Electricity
Coordination Group. In spite of this general caveat, consultation results already
contain many useful pointers about substantive requirements plans should comply
with:
- Definition of risks. Various stakeholders stress the need to develop a common
definition of what security of supply means and the various risks that should be
covered. Risk preparedness plans should be comprehensive in nature, covering
generation adequacy and grid adequacy issues, as well as issues related to more
short-term security issues (such the risk of a sudden unavailability of the grid
or a power plant as a result of a terrorist attack);
- Cybersecurity. Respondents generally acknowledge the importance of
preventing risks related to cyber-attacks but there is at this stage, no agreement
on the need for further specific EU measures;
- Risk assessments and standards. Whilst the public consultation did not raise a
specific question on risk assessment methods and standards (since these
questions where covered by the market design consultation), various
stakeholders make the case for a common methodology for assessing risks, to
ensure a comparability of results, and a more common and transparent approach
to the standards that are used to assess risks and define an acceptable level of
reliability (this is also confirmed by replies to the market design consultation).
Various stakeholders also take the view that risk preparedness plans should
contain the results of various assessments made as well as the indicators used
to make the assessments;
- Preventive measures. Stakeholders in favour of risk preparedness plans agree
that such plans should identify both demand-side and supply-side measures
taken to prevent security of supply issues, in particular situations of scarcity.
They also agree on the need to assess the impact of existing and future
interconnections and to take account of the import capacity when designing
preventive measures. Many stakeholders point in this context to the need to
ensure that markets function in an optimal way, thus allowing for flexibility in
demand and a mix of solutions to ensure that a sufficient level of supply is
guaranteed whilst keeping distortive measures at bay. Finally, stakeholders also
stress that any assessment of import capacity should take account of the
expected situation in neighbouring Member States;
- Dealing with emergency situations. A large majority of stakeholders agrees that
plans should identify actions (market and non-market based) to be taken in
emergency situations and rules on cooperation with other Member States. A
majority also believes that plans should include provisions on the suspension
of market activities, “protected customers” and cost compensation.
Additionally, some stakeholders suggest lists of specific content for the
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emergency plans. As regards the development of new EU rules, many
stakeholders state that due account should be taken of the network code on
Emergency and Restoration, which is under preparation. Most say this draft
network code should be considered as the basis, whilst acknowledging a
possible need for additional common rules. A minority of stakeholders argues
that the network code on emergency and restoration should be considered
sufficient, leaving no need for additional EU-level rules, or consider that the
issues not covered by the network code should not be addressed at the EU level;
- Definition/clarification of roles and responsibilities and what operational
procedures to be followed (e.g., who to contact in times of crisis)
(iii) Who should draw up risk preparedness plans, at what level, and with what kind of
'oversight'?
- Who should be responsible for drawing up risk preparedness plans? Whilst
most stakeholders recall that national governments have the ultimate
responsibility for ensuring security of supply, many stakeholders consider that
TSOs should take a lead role in drawing up risk preparedness plans. Most
however consider that TSOs need to co-operate however with national
ministries and/or national regulatory authorities, with the latter assuming a
monitoring or supervisory role. There is a large support for a stronger DSO
involvement in the preparation of the plans as well, as well as a clarification of
the responsibilities of DSOs in crisis situations. Whilst most stakeholders see
the added value of designating one 'competent authority' per Member States,
there is no agreement on who that competent authority should be (and some
argue that this choice should be left with the Member States).
- At what level should risk preparedness plans be drawn up? A large majority of
respondents take the view that plans should be made at national level; however
a large majority also stresses the need for more cross-border co-operation, at
least in a regional context. A significant group of respondents argues that plans
should be made at the regional level (for instance, as a complement to cross-
border co-operation by TSOs in the frame of the regional security coordination
initiatives) or call for plans at national and regional levels (or even 'multi-level'
plans).9
Those that argue in favour of national plans highlight the fact that
responsibilities (and liabilities) for security of supply issues are national.10
There is no agreement on how to 'define' regions for planning / co-operation
purposes; most stakeholders suggest that synchronous areas and/or existing
(voluntary) systems of regional co-operation should be used as a starting point.
Finally, whilst only a minority calls for European plans, many see the need for
some degree of co-ordination / alignment of plans in a European context (in
particular via the development of common rules and peer reviews leading to
best practice).
9
The rather cautious reaction to the idea of regional plans contrasts with the overwhelming support for
regional assessments of generation adequacy under the market design consultation.
10
A similar concern is reflected in the market design consultation results.
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- What oversight should there be? Most stakeholders are in favour of a system of
peer reviews, to be conducted either in a regional context, or in the frame of the
Electricity Coordination Group. The latter should in any event be convened on
a regular basis to serve as a forum for exchanging best practice. Some
stakeholders are also in favour of a stronger role for ACER/ENTSO-E, in
particular as regards more technical aspects of cross-border co-operation. As
regards the Commission, stakeholders mainly see a facilitating role, but are
often not in favour of a review system where the Commission takes binding
decisions.
Aspects of the present initiative were also part of the consultation on the preparation of a
new Renewable Energy Directive for the period after 202011
which was conducted from
18 November 2015 to 10 February 2016. It was open to EU and Member States' authorities,
energy market participants and their associations, SMEs, energy consumers, NGOs, other
relevant stakeholders and Citizens. The objective of this consultation was to consult
stakeholders and citizens on the new renewable energy directive (RED II) for the period
2020-2030, foreseen before the end of 2016. The bioenergy sustainability policy, which
will form part as well of the new renewable energy package, will be covered by a separate
public consultation. The stakeholder responses to this consultation are descibed in more
detail in the RED II impact assessment. A summary of the responses is however also
available on the Commission's website12
.
Targeted consultations
A High Level Conference on electricity market design took place on 8 October 2015 in
Florence.
The European Electricity Regulatory Forum convenes once or twice a year. The market
design initiative was discussed in this stakeholder forum at several occasions, notably the
Forum13
that took place on 4-5 June 2015, 9 October 2015, 3-4 March 2016 and 13-14
June 2016.
The consumer- and retail- related aspects of the market design initiative were also
discussed at the 8th Citizens' Energy Forum, which took place in London on 23 and 24
February 2016. The Commission established the London Forum to explore consumers'
perspective and role in a competitive, 'smart', energy-efficient and fair energy retail market.
It brings together representatives of consumer organisations, energy regulators, energy
ombudsmen, energy industries, and national energy ministries.
The Electricity Coordination Group provide a platform for strategic exchanges between
Member States, national regulators, ACER, ENTSOE and the Commission on electricity
11
https://ec.europa.eu/energy/en/consultations/preparation-new-renewable-energy-directive-period-after-
2020
12
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
13
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_WORKSHOP/Stakeholder%20Fora/Florenc
e_Fora
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policy. This group was used to discuss issues related to the present impact assessment on
16 November 2015 and 3 May 2016.
On demand response two specifc stakeholder workshops were organised by the
Commission: (i) Workshop on Status, Barriers and Incentives to Demand Response in EU
Member States, organised be the European Commission on 23 October 2015, and (ii)
Smart Grids Task Force, Expert Group 3 workshop on market design for demand response
and self-consumption, March 2, 2016; and Expert Group 3 workshop on smart homes and
buildings, April 26, 2016.
Member States' views
The support of Member States to the proposed initiatives is also apparent for instance from:
- The "Council conclusions on implementation of the Energy Union" of June 2015.
In this regard, the conclusions state that: "While STRESSING the importance of
establishing a fully functioning and connected internal energy market that meets
the needs of consumers, REAFFIRMS the need to fully implement and enforce
existing EU legislation, including the Third Energy Package; the need to address
the lack of energy interconnections, which may contribute to higher energy prices;
the need for appropriate market price signals while improving competition in the
retail markets; the need to address energy poverty, paying due attention to national
specificities, and to assist consumers in vulnerable situations while seeking
appropriate combination of social, energy or consumer policy; the need to inform
and empower consumers with possibilities to participate actively in the energy
market and respond to price signals in order to drive competition, to increase both
supply-side and demand-side flexibility in the market, and to enable consumers to
control their energy consumption and to participate in cost-effective demand
response solutions for example through smart grids and smart metres."14
- The "Messages from the Presidency on electricity market design and regional
cooperation" of April 2016.15
In these messages, the Presidency acknowledges the
challenges facing the electricity markets in Europe and emphasizes, inter alia: the
need to strengthen the functioning of the internal energy market; that correct price
signals in all markets and for all actors are essential; that an integrated European
electricity market requires well-functioning short-term markets and an adequate
level of cross-border cooperation with regard to balancing markets; that security of
supply would benefit from a more coordinated and efficient approach; that the
future electricity retail markets should ensure access to new market players and
facilitate introduction of innovative technologies, products and services.
Adherence to minimum Commission standards
The minimum Commission standards were all adhered to.
14
http://data.consilium.europa.eu/doc/document/ST-9073-2015-INIT/en/pdf
15
http://data.consilium.europa.eu/doc/document/ST-7879-2016-INIT/en/pdf
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Annex III: Who is affected by the initiative and how
The present initiative covers a large area of measures. The tables below provide an
overview of the parties affected, separately for each of the measures resulting from the
preferred policy options developed in the Annexes 1.1 through to 7.6.
Such matters are equally referred to in section 6 of the main text for the (more aggregated)
main policy options developed there.
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Table 1. Persons affected by measure for Problem Area I, Option 1(a) (level playing field)
Affected party Measure
1.1. Priority access and dispatch 1.2. Regulatory exemptions from balancing responsibility 1.3. RES E access to provision of non-frequency
ancillary services
Member States Need to change national legislation in so far as it contains priority dispatch; need to
include provisions on transparency and compensation of curtailment and redispatch
Need to change national legislation in so far as it contains
exemptions from balancing responsibility
They need to adapt national legislation to create
conditions for non-discriminatory procurement of non-
frequency ancillary services.
National
regulatory
authorities
(NRAs)
Need to oversee implementation of provisions, notably determination which generators
continue to benefit from priority rules, and ensure correct curtailment compensation.
Need to oversee implementation of provisions, notably oversight of
TSOs.
They need to oversee implementation and monitoring
of provisions, notably oversight of TSOs.
Transmission
System
Operators
(TSOs)
Reduction of priority dispatch and priority access facilitates grid operation and lowers
dispatch costs. Introduction of clear compensation rules on the other hand can increase
redispatch costs where such compensation is currently insufficient.
Implementation of balancing rules, notably settlement of parties in
imbalance.
They need to change the way non-frequency ancillary
services are contracted, procured and possibly
remunerated.
Distribution
System
Operators
(DSOs)
Where DSOs curtail generation to resolve local grid constraints, they are affected
identically to TSOs.
No direct impact, as balancing is the role of TSOs; indirectly,
increased balancing responsibility of generators increases system
transparency also to the benefit of DSOs.
DSOs very likely would also be affected, because most
RES are connected at distribution level and the DSO's
role in managing their network would have to change
in order to allow RES assets to participate to the
provision of ancillary services.
Generators Generators currently subject to priority rules will be exposed to increased curtailment
risks and lower likelihood of dispatch (for high marginal cost generators; likelihood of
dispatch actually increases for low marginal cost generators) unless they continue to
benefit from the exemptions. Generators not subject to exemptions will be less likely
to be curtailed and more likely to be dispatched where they are the most efficient
generator available. All generators will benefit from increased transparency and legal
certainty on redispatch and curtailment compensation.
Balancing responsible parties, including suppliers, traders and
generators currently subject to balancing responsibility are not
directly impacted. Generators currently exempted or partly shielded
from balancing responsibility will have to increase their efforts to
remain in balance (e.g. through better use of weather forecasts) or
will be exposed to financial risks.
Owners of generation assets (RES and not) would be
affected by changes in the rules of how non-frequency
ancillary services are procured. More transparent and
competitive procurement rules could enable market
entrance by new actors and technologies, such as
battery storage.
Suppliers Suppliers are not directly affected. Balancing responsible parties, including suppliers, traders and
generators currently subject to balancing responsibility are not
directly impacted.
Most likely not affected.
Power exchanges Power exchanges could benefit from the increased market liquidity particularly for
short-term products which results from market-based curtailment and redispatch.
Power exchanges could benefit from the increased market liquidity
particularly for short-term products which results from balancing
responsibility of RES E.
Most likely not affected.
Aggregators Aggregators are likely to benefit in particular by offering market-based resources to be
used by TSOs in redispatch or curtailment.
Aggregators are likely to benefit in particular by offering to small
generators services to fulfil their balancing responsibility.
Aggregators are likely to benefit from a more level
playing field and get access to additional remuneration
streams.
End consumers End consumers are not directly affected. End consumers are not directly affected. End consumers are not directly affected.
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Table 2. Persons affected by measure for problem Area I, Option 1(b) (Strengthening short-term markets)
Affected party Measure
2.1. Reserves sizing and procurement 2.2. Removing distortions for liquid short-term markets 2.3. Improving the coordination of Transmission System Operation
Member States Member State authorities define the country's overall
policy regarding energy mix and power grid investments.
Member States authorities generally play a limited direct role in the
operation of intraday markets. They will, however be impacted if they
are responsible for implementing/enforcing requirements.
Member States authorities will be impacted if they are responsible for
implementing/enforcing/monitoring the requirements. This topic is likely to have
a particularly political angle, as Member States may not be willing to entrust
ROCs with decision-making powers under the assumption that security of supply
is a national responsibility (although based on the TFEU, it constitutes a shared
responsibility between the EU and MS).
National
regulatory
authorities
(NRAs)
NRAs approve the methodology for sizing and
procurement of balancing reserves. They are also
responsible for any impact on TSOs' tariffs and how cross-
border infrastructure is allocated.
NRAs are responsible for regulatory oversight of intraday markets,
including as part of the implementation of the CACM Guideline, where
they are responsible for approving a number of methodology
developed by TSOs and power exchanges. They will, therefore, be
affected by changes in so far as it could alter the basis for their
regulatory decisions. However, the direct impact on NRAs is
anticipated to be relatively limited.
NRAs of each of the regions where a ROC is established would be required to
carry out the regional oversight of the concerned ROC. This would include
competences at least equivalent to those established for NRAs in the Third Energy
Package.
It may be necessary to entrust ACER with the EU-wide oversight of ROCs. It
would be necessary to set out a framework for the interaction between the regional
groupings of NRAs and ACER.
Transmission
System
Operators
(TSOs)
TSOs analyse system's state and propose the methodology
for sizing and procurement of balancing reserves in their
control areas.
Shifting responsibilities for sizing and procurement of
balancing reserves at regional level implies a need for
strong governance at regional level.
Existing physical constraints would still need to be taken
into account in the regional procurement platform.
Major impacts are expected on the current design of
system operation procedures and responsibilities. Cost
allocation and remuneration would have to be agreed,
requiring the development of a clear and robust framework
of responsibilities between national and regional TSOs.
TSOs are heavily involved in the operation of intraday markets,
notably in determining the cross-border capacity made available to the
market, and in using the results for operation of the system. They are
therefore likely to be significantly impacted by any changes.
National TSOs would be complemented by ROCs performing functions of
regional relevance, whilst real time operation functions would be left solely in the
hands of national TSOs.
ROCs could potentially be entrusted with certain decision making responsibilities
for a limited number of operational functions, whilst TSOs would retain their
responsibility as regards all other functions for which they are currently
responsible at national level. It may be necessary to entrust additional tasks to
ENTSO-E related to the cooperation and coordination between ROCs.
Generators Generators, as Balancing Service Providers, would have
additional opportunity to participate in the balancing
market even though significant operational impact might
increase due to the procurement frequency. Such
framework would, however, allow the participation of
renewable energy sources in the balancing market
potentially leading to a sharp decrease of balancing reserve
cost.
Generators will be affected by any changes in wholesale prices they
receive for their energy on the intraday market. More efficient price
signals, and more potential for trading, will open up the market to
smaller generators, particularly renewable.
Generators could benefit from a more secure power system and a more efficient
market leading to increased market opportunities.
Aggregators Smaller products and time units will give aggregators
more access to intraday markets.
Increased price fluctuations will give aggregators more opportunities
to operate, thereby helping to ensure that demand meets supply at any
point in time.
Limited impact on aggregators.
Suppliers Regional procurement of reserves would lead to regional
settlement of imbalances; therefore allowing for increase
competition of suppliers across borders.
Suppliers will be affected insofar as they are the ones who buy power
on the wholesale market. Any changes in intraday clearing prices will
change how much they pay for their power, the extent to which will
depend on how much trading they do in the intraday market.
Limited impact on suppliers.
Power
exchanges
In case an optimisation process for the allocation of
transmission capacity between energy and balancing
markets has to developed, day-ahead market coupling
algorithm currently operates by power exchanges might be
Power exchanges will be the most affected by any changes to intraday
arrangements, as they are the ones who operate the platforms on which
energy is traded in the intraday timeframe. They will therefore have to
adapt systems and process to meet new requirements.
Limited impact on power exchanges. It is expected that they could benefit power
exchanges as the optimisation of market-related functions such as capacity
calculation would entail more liquidity in the markets that could be exchanged.
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Affected party Measure
2.1. Reserves sizing and procurement 2.2. Removing distortions for liquid short-term markets 2.3. Improving the coordination of Transmission System Operation
impacted and solution will have to be found on sharing
transmission capacity in an optimal way for the markets
preceding the balancing market.
End consumers End consumers will be able to participate in balancing
markets via demand response aggregators allowing for
stronger supplier's competition at regional level.
End consumers will be affected insofar as changes to the wholesale
price are passed on to them in their retail price.
Regional TSO cooperation through the creation of ROCs would benefit
consumers through improved security of supply (by minimising the risk of wide
area events such as brownouts and blackouts), and lowering costs through
increased efficiency in system operation and maximised availability of
transmission capacity to market participants.
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Table 3. Persons affected by measure for Problem Area I, Option 1(c) (Pulling demand response and distributed resourced into the market)
Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
Member States Those 17 Member States that roll out smart meters
will not be affected by the new provisions on smart
meters, apart from the obligation to comply with the
recommended functionalities, which may need to
transpose into national legislation. Similarly for
those two Member States that opted for partial roll-
out and are not expected to face any other additional
burden from allowing additional consumers to
request smart meters.
However, those 9 Member States that currently do
not plan to install any smart meters will need to
establish legislation with technical and functional
requirements for the roll-out and face some
additional administrative impact by re-evaluating
their cost-benefit analyses.
What concerns market rules for demand response,
Member States are already obliged through the EED
to enable demand response. The new provisions will
rather provide additional guidance for Member
States on how to create the enabling framework
instead of imposing additional burden to them.
The competent ministries in each Member State who
will be involved in the transposition of the relevant
EU legislation and monitor the implementation and
effectiveness of the measures under the preferred
option.
The competent ministries in each Member State who
will be involved in the transposition of the relevant
EU legislation and monitor the implementation and
effectiveness of the measures under the preferred
option.
MS authorities will be in charge of national
implementation of the revised Third Package.
National
regulatory
authorities
(NRAs)
Additional administrative impact may be created for
the NRAs for enforcing actions regarding the
consumer entitlement to request a fully functional
smart meter. This includes assessing the costs to be
borne by the consumer, and overseeing the process
of deployment. At the same time, improved
consumer engagement thanks to smart metering,
would make it easier for NRAs to ensure proper
functioning of the national (retail) energy markets.
Already under the existing legislation NRAs are
obliged to encourage demand side resources to
participate alongside supply in markets. The new
provisions under the preferred option only further
specify which aspects have to be addressed by NRAs
but they do not create additional burden for them.
As DSOs are regulated entities is expected that NRAs
will have the main role of ensuring the effective
application of measures. NRAs will be mostly
involved in the application of the measures and in
designing the necessary rules for the practical
implementation. As the measures under the preferred
option are closely linked to a suitable remuneration
methodology, NRAs will also probably have to
modify existing schemes. This will require the
availability of the necessary human, technical and
financial resources.
According to the Electricity Directive NRAs have the
main role in fixing or approving network tariffs or
their methodologies. The overall aim is to move
towards more sophisticated network tariff
methodologies. To this end, some NRAs might have
to modify the existing methodologies for distribution
tariffs. The introduction of smarter regulatory
frameworks will require the availability of the
necessary human, technical and financial resources.
Their role, powers and responsibilities will be
further clarified, especially as regards issues
which are relevant at regional/EU level. This
will affect the way NRAs have cooperated at
regional and EU-level, including within
ACER, in order to enhance the collaboration
between NRAs and ACER.
In the context of clarifying the respective roles
of NRAs and ACER, some of the powers and
responsibilities currently conferred to NRAs
may be shifted to ACER.
Agency for the
cooperation of
energy
regulators
(ACER)
Apart from the minor changes necessary to ensure
effective market monitoring in the changed market
context, ACER will not be affected by changes in
unlocking demand side response..
ACER will be affected to the extent which will be
called to oversight the activities of EU DSO entity and
its involvement in relevant network codes or
guidelines.
ACER will be affected to the extent which will be
called to oversight the activities of EU DSO entity
and its involvement in network codes or guidelines
on network tariffs.
Its role, powers and responsibilities will be
further enhanced in order to ensure that ACER
can continue fulfilling its role of supporting
NRAs in exercising their functions at EU level
and to coordinate their actions where
necessary. For a number of specific and
defined instances, some of the powers and
responsibilities of NRAs will be shifted to
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Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
ACER, to ensure that it can carry out an EU-
level oversight.
ACER's role will be affected by the changes
envisaged for the process of development of
Commission implementing regulations in the
form of network codes and guidelines.
Transmission
System
Operators
(TSOs)
A greater roll-out of smart meters allows TSOs to
better calculate settlements and balancing penalties
as the consumption figures can be based on real
consumption data and not only on profiles.
TSOs are affected by opening markets for
aggregated loads and demand response. Those
effects are dealt with in the Impact Assessment on
markets. TSOs are not directly affected by the
proposed measures on removing market barriers for
independent aggregators. However, they are
indirectly affected: A greater participation of
flexibility products in ancillary service markets (e.g.
balancing markets) can help TSOs cost-effectively
manage the network.
TSOs will be involved as more coordination with
DSOs will be required. TSOs will have to allocate the
necessary human and technical resources in order to
achieve such coordination.
TSOs will not be affected by changes in distribution
tariffs.
Some of the transparency obligations imposed
on ENTSO-E as well as some of the
governance rules applying to this association
will indirectly affect TSOs.
Some of the proposed rules (e.g. co-financing
of ACER by contributions from market
participants) might directly impact on TSOs.
European
network of
transmission
system operators
(ENTSOs)
ENTSO-E will not be affected by changes in
unlocking demand response.
ENTSO-E will have to cooperate with the EU DSO
entity on issues which are relevant to both
transmission and distribution networks.
ENTSO-E will not be affected by changes in
distribution tariffs.
ENTSO-E's mandate will be mainly clarified,
whilst ensuring that its added value of
providing technical expertise is preserved.
Transparency of ENTSO-E will be further
improved.
The role of ENTSO-E will be affected by the
changes envisaged for the process of
development of Commission implementing
regulations in the form of network codes and
guidelines.
Distribution
System
Operators
(DSOs)
In most Member States, DSOs are responsible for
organising the installation of smart meters. The
additional costs to be determined by the NRAs can
however be charged to the users.
DSOs also benefit from access to real time data
coming from smart metering. It supports them in
their work on monitoring and controlling the
network, improving its reliability and power quality,
and its overall effectiveness, particularly in the
presence of distributed generation. This ultimately
contributes to the increased distribution network
efficiency and increased revenue for the DSOs (e.g.
via reduced technical and commercial losses)
DSOs are not directly affected by the proposed
measures on removing market barriers for
independent aggregators. However, DSOs can
DSOs will be directly affected by the possible
measures under the preferred option as they will have
to have in place the necessary human and technical
resources in order to implement the envisaged
measures. Additional personnel or infrastructure
might be necessary. However, DSOs will use
flexibility solutions in order to increase efficiencies,
only where benefits will outweigh additional costs.
It is expected that the envisaged measures under the
preferred option will positively affect DSOs as they
aim to a more efficient utilisation of the distribution
system and the incentivisation of DSOs towards more
optimal development and operation of their grids.
More advanced tariff schemes may require the
availability and monitoring of detailed data (financial
and technical) and the achievement of specific
targets. Any additional administrative costs should be
offset by the expected benefits.
DSOs will be able to participate more actively
as a result of the changes envisaged for the
process of development of Commission
implementing regulations in the form of
network codes and guidelines.
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Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
indirectly benefit from a better uptake of demand
response as the reduction in peaks it will reduce the
need to invest in distribution networks.
Generators Demand response is designed to reduce peak
demand and thereby effectively replace marginal
power plants and reduce electricity prices at the
wholesale market. As such generators are likely to
face reduced turnover from lower peak prices and
from operating reserve capacities.
Generators are not likely to be effected by an
accelerated smart meter roll out.
Generators will not be affected by the measures under
the preferred option.
The envisaged measures aim to the overall reduction
of network costs through the incentivisation of DSOs
to raise efficiencies, which will have an overall
positive impact to system users. The envisaged
measures also aim to a fair allocation of costs among
different system users. Therefore, to the extent to
which the envisaged measures will incite changes in
existing tariffs, generators or other system users may
be affected from any new tariffs which will result to
reallocation of costs.
Generators will be able to participate more
actively as a result of the changes envisaged
for the process of development of Commission
implementing regulations in the form of
network codes and guidelines.
Suppliers Smart meters can have a direct impact on suppliers,
as they enable consumers to easily switch.
Furthermore, there is one Member State where
suppliers are responsible for the roll-out. Moreover,
smart metering allows suppliers to offer dynamic
pricing contracts that reduce suppliers' risk of
changing wholesale prices.
The effect of demand response on suppliers can be
positive as suppliers will benefit from lower
wholesale prices. On the other hand demand
response will make it more difficult for suppliers to
calculate retail prices. Also as balancing responsible
parties they may face higher penalty payments for
imbalances incurred due to their customers changing
consumption patterns. Finally, new competition
from aggregators may reduce their income.
However, suppliers can also offer demand response
services to their customers and expand their range of
services and thereby turnover.
The overall financial impact of smart meters and of
more competition through demand response on
suppliers will hence depend on the ability of the
individual supplier to adapt to the new market with
innovative services and competitive pricing offers.
Suppliers will not be affected as the envisaged
measures will not affect their normal business.
It is not expected that the envisaged measures will
affect the suppliers.
Suppliers will be able to participate more
actively as a result of the changes envisaged
for the process of development of Commission
implementing regulations in the form of
network codes and guidelines.
Power exchanges No impact expected No impact expected No impact expected Power exchanges will be subject to an
enhanced regulatory oversight at EU level
exercised by ACER and NRAs.
Power exchanges will be able to participate
more actively as a result of the changes
envisaged for the process of development of
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Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
Commission implementing regulations in the
form of network codes and guidelines.
Aggregators (and
other new
market entrants)
Aggregators are likely to benefit from an accelerated
roll out of smart meters as this technology facilitates
market access for demand service providers and
aggregators. Equally all measures aimed at removing
market barriers and increasing competition in the
retail market will immediately facilitate market
access for aggregators and new energy service
providers and hence opens new business
opportunities for them.
Aggregators will be positively affected as DSOs will
request their services in order to use flexibility for
managing congestion in their networks.
Insofar as distribution tariffs incentivise grid users to
use the network more efficiently, aggregators will not
be called upon as much to help to manage network
congestion..
Aggregators and other new market entrants
will be able to participate more actively as a
result of the changes envisaged for the process
of development of Commission implementing
regulations in the form of network codes and
guidelines
End consumers End consumers will get the right to request smart
meters and have access to dynamic electricity
pricing contracts which clearly gives puts them in a
position to become active market participants.
Furthermore, provision of accurate and reliable data
flows due to smart metering would enable easier and
quicker switch between suppliers, access to choices,
smart home solutions and innovative automation
services, and can also lead to energy savings.
Consumers will equally benefit from more
competition, wider choice, and the possibility to
actively engage in price based and incentive based
demand response and hence from reduced energy
bills. But also those consumers who do not engage
themselves in demand response can profit from
lower wholesale prices as a result of demand
response if those price reductions are being passed
on to consumers.
Use of flexibility from DSOs will result to lower
network costs. This reduction will be reflected in
distribution tariffs and the final electricity bill of the
consumer.
The envisaged measures aim to the overall reduction
of network costs through the incentivisation of DSOs
to raise efficiencies, which will have an overall
positive impact to system users. The measures also
aim to a fair allocation of costs among different
system users. Therefore, to the extent to which the
envisaged measures will incite changes in existing
tariffs, consumers or other system users may be
affected from any new tariffs which will result to
reallocation of costs.
Consumers will be able to benefit from
enhanced transparency and in general from
well-functioning energy markets.
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Table 4. Persons affected by measure Problem Area II, Option 1 (Improved energy market without CMs)
Affected party Measure
4.1. Removing price caps 4.2. Improving locational price signals 4.3. Minimise investment and dispatch
distortions due to transmission tariff
structures
4.4. Congestion income spending to increase cross-
border capacity
Member States Member States authorities will be impacted if they
are responsible for
implementing/enforcing/monitoring the
requirements.
Member States authorities will be impacted if they are
responsible for implementing/enforcing/monitoring the
requirements. This topic is likely to have a particularly
political angle, as splitting price zones within a Member
State will result in different wholesale electricity in that
Member State depending on location (although not
necessarily retail prices).
Member States authorities will be impacted if
they are responsible for
implementing/enforcing/monitoring the
requirements.
Member States authorities will be impacted if they are
responsible for implementing/enforcing/monitoring the
requirements.
National
regulatory
authorities
(NRAs)
NRAs will be impacted if they are responsible for
implementing/enforcing/monitoring the
requirements.
Member States authorities will be impacted if they are
responsible for implementing/enforcing/monitoring the
requirements.
NRAs play a significant role in monitoring,
authorising, etc. tariffs and connection
charges. Any change would impact on how
they do this.
NRAs are currently responsible for reviewing the use
of congestion income, and for authorising it to be spent
on the reduction of tariffs. They will be affected by
Option 2 and 3 as they no longer need to authorise it to
be spent on the reduction of tariffs. Option 1 could
require them to make a more them to make a more
thorough assessment.
ACER will be affected by changes to monitoring and
transparency requirements and the requirement on
them to develop harmonised rules.
Transmission
System
Operators
(TSOs)
There will be limited impact on TSOs. TSOs will be affected as it will likely mean they hold
and operate networks over more than one price zone. It
will also change those transmission lines that
accumulate revenue from congestion.
Changes would have limited impact on TSOs
themselves, as proposals are not generally
looking at how TSOs are remunerated, but
rather how the money is collected.
It will change how transmission system operators are
able to use congestion income. Options 1-3 could lead
to more investment activity of the TSO.
Generators Increased price variability will impact the revenue
generators will see from the energy market – they
will likely see higher prices for short periods of
time, which will incentivise flexible generation.
Different price zones will change the prices that
generators receive depending on their location.
Changes would most affect generators – lower
connection charges or tariffs (where they are
applied to generators) would have a positive
impact on their revenues.
If Option 1, 2 and 3 lead to more investment in
networks, this would impact generators by delivering
more cross-border competition and present further
trading opportunities to sell energy by an increases in
the liquidity of cross-border markets.
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Affected party Measure
4.1. Removing price caps 4.2. Improving locational price signals 4.3. Minimise investment and dispatch
distortions due to transmission tariff
structures
4.4. Congestion income spending to increase cross-
border capacity
Suppliers Increased price variability will impact the price paid
by suppliers - – they will likely see higher prices for
short periods of time.
Different price zones will change the prices that
suppliers pay depending on their location.
Limited impact on suppliers. If Option 1, 2 and 3 lead to more investment in
networks, this would impact generators by delivering
more cross-border competition and present further
trading opportunities to buy energy by an increase in
the liquidity of cross-border markets.
Power
exchanges
Power exchanges will be required to implement the
requirements, which could require changes to
systems and practices.
Different price zone will change the practices of power
exchanges – currently they operate based on MS-level
markets (in general) – they would need to differential
markets based on different price boundaries.
Limited impact on power exchanges. If Option 1, 2 and 3 lead to more investment in
networks, this would impact power exchanges if it
leads to greater cross-border trade on their platforms.
End
consumers
End consumers will be affected insofar as changes
to the wholesale price are passed on to them in their
retail price. However, more variable prices will not
necessarily be felt by end-consumers as they may
be hedged (particularly household) against this
volatility in their retail contracts.
Different price zones could affect end-consumers
depending on their location. However, possibilities exist
to retail MS-level retail prices,
End consumers could be affected if more
tariffs were charged on load, as opposed to
production. However, overall the impact is
likely to be similar as the overall cost basis
would not changing.
End consumers may be affected by any reduction in the
amount that can be offset against tariffs. However, this
may be outweighed by the positive effect of more
cross-border capacity being available, and the benefit
this has on competition and energy prices.
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Table 5. Persons affected by measures of Problem Area II, Option 2 (Improved energy market, CMs based on an EU-wide adequacy assessment) and
Option 3 (Improved energy market, CMs based on an EU-wide adequacy assessment, plus cross-border participation
Affected party Measure
5.1. Improved generation adequacy methodology 5.2. Cross-border operation of capacity mechanisms
Member States Member States would be better informed about the likely development of security of supply indicators
and would have to exclusively rely on the EU-wide generation adequacy assessment carried out by
ENTSO-E when arguing for CMs.
Each Member State would not need to design a separate individual solution – and this would potentially
reduce the need for bilateral negotiations between TSOs.
National regulatory
authorities (NRAs)
NRAs/ ACER would be required to approve the methodology used by ENTSO-E for the generation
adequacy methodology and potentially endorse the assessment.
NRAs/ ACER would be required to set the obligations and penalties for non-availability for both
participating generation/ demand resources and cross-border transmission infrastructure.
Transmission System
Operators (TSOs)
TSOs would be obliged to provide national raw data to ENTSO-E which will be used in the EU-wide
generation adequacy assessment.
ENTSO-E would be required to establish an appropriate methodology for calculating suitable capacity
values up to which cross-border participation would be possible.
Based on the ENTSO-E methodology, TSOs would be required to calculate the capacity values for each
of their borders. They might potentially be penalized for non-availability of transmission infrastructure.
TSOs would be required to check effective availability of participating resources.
ENTSO-E may also be required to establish common rules for crediting foreign capacity resources for
the purpose of participation in CMs reflecting the likely availability of resources in each country/zone.
Generators ENTSO-E would also have to provide for an updated methodology with probabilistic calculations,
appropriate coverage of interdependencies, availability of RES and demand side flexibility and
availability of cross-border infrastructure.
Foreign capacity providers would participate directly into a national capacity auction, with availability
rather than delivery obligations imposed on the foreign capacity providers and the cross-border
infrastructure.
Foreign capacity providers/ interconnectors would be remunerated for the security of supply benefits
that they deliver to the CM zone and would receive penalties for non-availability.
Suppliers ENTSO-E would be required to carry out an EU-wide or regional system adequacy assessment based
on national raw data provided by TSOs (as opposed to a compilation of national assessments).
Limited impact on suppliers
Aggregators With the updated methodology provided by ENTSO-E, intermittent RES generators/ demand-side
flexibility would be less likely to be excluded from contributing to generation adequacy.
Just like generators they shall be able to participate in cross-border CMs.
Power exchanges Limited impact on suppliers Limited impact on power exchanges
End consumers Limited impact on aggregators Explicit cross-border participation in CMs would preserve the properties of market coupling and ensure
that the distortions of uncoordinated national mechanisms are corrected and the internal market is able
to deliver the benefits to consumers.
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Table 6. Persons affected by measures for Problem Area III
Affected party Measure
Member States Member States (i.e. responsible ministries) would bear the main responsibility of preparing Risk Preparedness Plans and coordinating relevant parts with other
Member States from their region, including ex-ante agreements on assistance during (simultaneous) crisis and financial compensation.
Member States would designate a ministry or the NRA as 'competent authority' as responsible body for preparing the Risk Preparedness Plan and for cross-border
coordination in crisis.
As members of an empowered Electricity Coordination Group they would consult and coordinate Plans.
The above described responsibilities might involve an increased administrative impact. However, most of the tasks are already carried out in a purely national
context and there might also be benefits from exploiting synergies of improved cooperation. In addition, existing national reporting obligations would be reduced
(e.g. repealing the obligation of Article 4 of Electricity Directive "Monitoring security of supply").
National regulatory
authorities (NRAs)
NRAs could possibly fulfil certain tasks as part of the Risk Preparedness Plan of their Member State.
Furthermore they might be appointed as 'competent authority' by Member States. In this case, they would be responsible for preparing the Risk Preparedness Plan
and for cross-border coordination during crisis, possibly requiring additional resources.
Transmission System
Operators (TSOs)
ENTSO-E would be responsible for identification of crisis scenarios and risk assessment in a regional context. A common methodology for short-term assessments
(ENTSO-E Seasonal Outlooks and the week-ahead assessments of the RSCs) should be developed by ENTSO-E.
This might require additional resources within ENTSO-E and within the RSCs, in case that ENTSO-E delegates all or part of these tasks to them. However,
additional costs would be limited as some of these tasks are already carried out today. Giving these bodies a clear mandate, it would however significantly improve
cross-border coordination.
Generators Generation companies and other market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from
clearer rules on crisis management and the prevention of unjustified market intervention.
Suppliers Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management
and the prevention of unjustified market intervention.
Aggregators Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management
and the prevention of unjustified market intervention.
Power exchanges Market operators would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management
and the prevention of unjustified market intervention.
End consumers As described above the impacts of blackouts on industry and society proved to be severe. Consequently, end consumers benefit extensively from improved risk
preparedness as it would help to prevent future blackouts more effectively.
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Table 7.a Persons affected by measure for Problem Area IV
Affected party Measure
7.1. Monitoring energy poverty 7.2. Options for phasing out regulated prices 7.3. Creating a level playing field for access to data
Member States Option 1 leads to an improved framework to measure energy poverty.
Member States will have a better understanding of energy poverty as a
result of a clearer conceptual framework (through the common
understanding of energy poverty) and better information on the level of
energy poverty (measuring energy poverty). Ultimately, this will contribute
to better identification and targeted public policies to alleviate energy
poverty.
Those Member States still practicing some form of price regulation will
have to make the necessary legislative and market changes in order to
ensure a smooth and effective phase out.
The competent ministries and authorities who will be
involved in the transposition of the relevant EU legislation
and will monitor the implementation and effectiveness of
the measures under the preferred option.
National regulatory
authorities (NRAs)
NRAs will need to monitor and report to the European Commission and
ACER the number of disconnections. According to ACER Market
Monitoring Report, only 16 Member States met this requirement.
In most countries with price regulation, NRAs are the bodies
responsible for setting the level of regulated prices for a defined
regulatory period. In few cases NRAs are only giving their opinion on
regulated prices set by the government. Phasing-out regulated prices
would remove these responsibilities of the NRAs therefore reducing
administrative costs and resource needs. However new tasks for the
NRAs might be defined by Member States in the follow-up of the price
deregulation process such as monitoring the level of market prices with
the possibility to intervene ex post in the price setting in case of market
abuse. The costs of carrying out such new tasks are likely to be less
important than the costs of setting regulated prices, resulting overall in
reduces resource needs for the NRAs.
The envisaged measures will partly affect the NRAs as most
probably will have a role in the implementation of the
measures at national level. Other authorities such as data
protection authorities may be involved in the
implementation of the envisaged measures at national level.
NRAs will have to monitor the data handling procedures as
part of the retail market functioning. The involvement of
NRAs is expected to be higher in Member States where
smart metering systems are deployed.
Transmission
System Operators
(TSOs)
The preferred option would not directly affect TSOs. The preferred option would not directly affect TSOs. TSOs might be affected in terms of costs in cases where
Member States will decide that they are responsible for the
operation of the data-hub. However, the envisaged measures
do not impose an obligation to Member States regarding the
data management model and the party responsible for acting
as a data-hub. The measures under the preferred option will
benefit TSOs and other operators as the will allow them,
under specific terms, to have access to aggregated
information which will be useful for network planning and
operation.
Distribution System
Operators (DSOs)
The preferred option would not directly affect DSOs. The preferred option would not directly affect DSOs. In the large majority of Member States DSOs will be
involved directly in the data handling process. DSOs will
have the same benefits as TSOs in terms of system operation
and planning. Under the preferred option DSOs which are
not fully unbundled (DSOs below the 100.000 threshold)
will have to implement measures which link to the non-
discriminatory treatment of information. The
implementation of such measures will most probably create
costs which will vary depending on the national framework.
It is not expected however that these costs will create a high
burden, as they can implemented through automated IT
systems.
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Affected party Measure
7.1. Monitoring energy poverty 7.2. Options for phasing out regulated prices 7.3. Creating a level playing field for access to data
Generators The preferred option would not directly affect generators. In countries where artificially low regulated end-user prices are backed
up by generation deliveries at non cost-reflective level agreed by long-
term contracts, deregulation of end user prices could trigger a rethinking
of such system by a renegotiation of long-term contracts which would
stimulate investment in efficient generation capacities with positive
effects on the competition on the generation market.
Generators will not be affected under the preferred option.
Suppliers The preferred option would not directly affect suppliers.
However, should the improved monitoring of energy poverty lead to
increased action to tackle the problem by Member States, then the costs of
these measures may be borne by suppliers. Depending on each Member
States, these costs may then be recovered as network charges, passed on to
consumers or taken against energy providers overall benefits.
Preventative measures, such as debt management or providing additional
information on where to find support, represent an additional cost to energy
retailers in those Member States where these measures are not yet in place.
A moratorium of disconnection will reduce energy retailers' revenue as
energy will be supplied free of charge. However, such costs will to some
extent be mitigated by lower numbers of bad debtors in the long run.
Alternative (non-regulated) suppliers would benefit from the
deregulation of prices by increased possibilities to compete on the price
and therefore to gain more market share. This is particularly true for
countries where regulated prices set at non cost-reflective levels prevent
alternative suppliers from contesting the regulated offer. For the
regulated suppliers (usually former incumbents) the removal of price
regulation would lead to increased operational costs related to the
implementation of the transition from the regulated offer to market
based offer for its customer base. Moreover, regulated suppliers are
likely to lose significant market shares if customers will switch to
competitive offers of alternative suppliers.
The availability of consumption data under non-
discriminatory terms and interoperability of data formats
will have positive effects on suppliers and other retailers.
The aim of the measures under the preferred option is to
bring down the administrative costs for the various retail
service providers including suppliers.
Power exchanges The preferred option would not directly affect power exchanges. The preferred option would not directly affect power exchanges.
However, power exchanges could benefit from increased liquidity due
to better functioning competition on retail and wholesale markets
following price deregulation.
-
Aggregators The preferred option would not directly affect aggregators. Removing price regulation would stimulate the development of energy
services which create market opportunities for aggregators.
In the preferred option aggregators and other retail service
providers will have equal access to data as suppliers in a
transparent and non-discriminatory way. This will allow
aggregators to develop new services for consumers and will
facilitate their entrance in the market.
Consumers Consumers in a situation of energy poverty or at risk of energy poverty will
be positively impacted by the preferred option. A clearer understanding and
measuring of energy poverty will have positive impacts on Member States
efforts to tackle energy poverty..
Phase-out of regulated prices for end customers would stimulate
competition on retail markets which translates for customers into more
choice and better offers in terms of price and service quality. Customers
would be able to better manage their own energy consumption by using
energy services and technologies such as demand response, self-
generation, and self-consumption. However, notably in countries where
prices are artificially regulated at low levels, price deregulation could
be followed by substantial increases in end user prices; to help
customers face such price increases, appropriate protection measures
for vulnerable customers should be in place prior to deregulation.
The envisaged measures under the preferred option aim to
support the development of a competitive retail market. It is
expected that the measures will bring developments which
will affect positively consumers through the availability of
wider choice of services, focusing on demand response and
energy efficiency.
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Table 7.b Persons affected by measures for Problem Area IV
Affected party Measure
7.4. Facilitating supplier switching 7.5. Comparison Tools 7.6. Improving Billing Information
Member States The preferred option may need to be transposed into national
law, resulting in administrative impacts.
Some Member States (e.g. BE, IT) have eliminated exit fees
already, the latter reporting increased consumer trust as a
result. Others with a relatively high preponderance of exit fees
(NL, IE, SI) are likely to be more reserved, particularly in light
of the fact that they may have relatively competitive markets
already.
The preferred option will need to be transposed into national law, resulting in
administrative impacts.
However, some 13 Member States already have at least one independent CT run by a
government or government-funded body. As these are free of conflicts of interest, we
can assume they are likely to meet the accreditation criteria.
The preferred option will need to be transposed into national
law, resulting in modest implementation costs.
National
regulatory
authorities
(NRAs)
The preferred option would likely lead to additional
stakeholder engagement and enforcement actions, resulting in
increased administrative impacts to NRAs.
However, any clarification and simplification of EU legal
provisions may lead to greater ease of enforcement, and
commensurate savings.
In addition, improved consumer engagement would make it
easier for NRAs to ensure the proper functioning of national
(retail) energy markets they are charged with.
The preferred option would likely lead to additional stakeholder engagement and
enforcement actions, resulting in increased administrative impacts. However, this
would not necessarily be a role for the NRAs as an independent body might be assigned
the task (e.g. GB where an independent auditor audits the CT).
However, any strengthening of EU legal provisions should lead to a reduction in the
number of consumer complaints.
In addition, improved consumer engagement would make it easier for NRAs to ensure
the proper functioning of national (retail) energy markets.
The preferred option would likely lead to additional
stakeholder engagement and enforcement actions, resulting
in increased administrative impacts to NRAs.
However, improved billing clarity would make it easier for
NRAs to ensure the proper functioning of national (retail)
energy markets they are charged with.
Transmission
System
Operators
(TSOs)
Not affected. Not affected. Not affected.
Distribution
System
Operators
(DSOs)
Any change in consumer switching behaviour resulting from
the preferred option would be reflected in switching
operations, and their associated administrative impacts.
However, as DSOs are regulated monopolies, these costs (or
savings, if switching decreases) will eventually be passed
through to end consumers.
Insofar as the measures lead to increased switching, this will result in increased
administrative costs to DSOs. However, these costs will be passed through to consumers
through network charges.
Not affected.
Suppliers Most suppliers are unlikely to welcome measures to further
restrict switching-related fees, as these limit their ability to
tailor tariffs to different consumers.
Some may also financially benefit from the increased
'stickiness' switching-related fees create amongst their
consumer base.
In addition, any change in consumer switching behaviour
resulting from the policy options would be reflected in
switching operations, and the associated administrative
impacts to suppliers.
Industry associations (EURELECTRIC and Eurogas) have publicly supported
consumer access to neutral and reliable comparison tools. In particular, increased
reliability and impartiality in comparison tools may encourage new market entrants,
thereby improving the likelihood of a level playing field.
However, some suppliers are unlikely to welcome measures to certify comparison tools
as this may have an impact on how and where their offers are published, and their ability
to tailor tariffs to different consumers (in terms of cost, etc.).
Some may also lose out financially if they are no longer able to influence the ranking
of search results to promote certain offers; this applies both to energy suppliers and to
CT providers.
Insofar as the measures lead to increased switching, this will result in increased
administrative costs to suppliers.
Most suppliers are unlikely to welcome EU legislation
addressing the content or format of energy bills, as this limit
their ability to tailor bills to different consumers.
Some may also benefit from the low awareness amongst
their consumer base of information that may be contained in
bills, such as switching information, consumer rights, and
consumption levels.
Comparison tool
providers
Not affected. More stringent requirements in terms of reliability and impartiality may increase their
costs, as may the need for accreditation. However, such costs may be offset by an
increase in sales due to improved trustworthiness of the comparison tool.
Not affected.
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Affected party Measure
7.4. Facilitating supplier switching 7.5. Comparison Tools 7.6. Improving Billing Information
End consumers Some end consumers would benefit from contract exit fees
(permitted in the preferred option) if such fees mean that
suppliers are able to offer them lower prices or better levels of
service.
However, all consumers are likely to benefit from a complete
ban on other switching-related fees (as per the preferred
option), as well as greater transparency around any switching-
related fees they may be charged.
More generally, the majority of consumers would benefit from
further restricting the use of switching-related charges. Such
charges are a financial barrier to accessing better deals,
disproportionately affect decision making, foster uncertainty
on the benefits of switching, and reduce retail-level
competition.
The preferred option would benefit many consumers, as the offers displayed would be
more representative of the best ones (e.g. those offering the best value for money and
the best service levels) available on the market. Asymmetric access to information
would be reduced. Consumers would have greater trust in their ability to select the best
offer through improvements in levels of service, and they would be better protected.
They will be better able to make informed choices, and to benefit from the internal
market.
Some end consumers would benefit from contract exit fees
if such fees mean that suppliers are able to offer them lower
prices or better levels of service.
However, all consumers are likely to benefit from a complete
ban on other switching-related fees, as well as greater
transparency around any switching-related fees they may be
charged.
More generally, the majority of consumers would benefit
from further restricting the use of switching-related charges.
Such charges are a financial barrier to accessing better deals,
disproportionately affect decision making, foster uncertainty
on the benefits of switching, and reduce retail-level
competition.
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Annex IV: Analytical models used in preparing the impact assessment.
Description of analytical models used
In order to perform the quantitative analysis for the various Problem Areas, most notably
Problem Areas I and II, as well as for the evaluation of certain individual measures
described in the Annexes, a number of specialized energy modelling tools were used. The
selection of the modelling tool to be used in each case was made based on its ability to
answer the specific questions raised in each Problem Area.
METIS
For assessing the benefits of specific market design measures and their effect to power
system operation and market functioning, a new optimization software – METIS – was
used, currently being developed for the Commission16
.
METIS was presented to the Member States' Energy Economists Group on April 5th
2016.
The Commission will be eventually the owner of the final tool. For transparency reasons,
all deliverables related to METIS, including all technical specifications documents and
studies, are intended to be published on the website of DG ENER17
.
Global Description
METIS is an on-going project initiated by DG ENER for the development of an energy
modelling software, with the aim to further support DG ENER’s evidence-based policy
making, especially in the areas of electricity and gas. The software is developed by a
consortium (Artelys, IAEW (RWTH Aachen University), ConGas, and Frontier
Economics) and a first version covering the power and gas system has already been
delivered to DG ENER.
It is an energy model covering with high granularity (geographical, time etc.) the whole
European energy system for electricity, gas and heat. In its final version it should be able
to simulate both system and markets operation for these energy carriers, on an hourly level
for a whole year and under uncertainty (capturing weather variations and other stochastic
events). METIS works complementary to long-term energy system models (like PRIMES
and POTEnCIA), as it focuses on simulating a specific year in greater detail. For instance,
it can provide hourly results on the impact of higher shares of intermittent renewables or
additional infrastructure built, as determined by long-term energy system models.
Upon final delivery, METIS will be able to answer a large number of questions and
perform highly detailed analyses of the electricity, gas and heat sectors. A number of topics
will be possible to tackle with METIS for the whole EU and/or specific regions, like:
- The impacts of mass Renewable Energy Sources integration to the energy system
operation and markets functioning (for one or all sectors);
16
http://ec.europa.eu/dgs/energy/tenders/doc/2014/2014s_152_272370_specifications.pdf
17
Once operational, the envisaged link is expect to be the following:
https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis
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- Cost-benefit analysis of infrastructure projects, as well as impacts on security of
supply;
- Studying the potential synergies between the various energy carriers (electricity,
gas, heat).
On the other hand METIS is not designed to answer (at least in its first stage) questions
like:
- Optimal investment planning (capacity expansion) for the EU generation or
transmission infrastructure;
- Impacts of measures on network tariffs and retail markets;
- Short-term system security problems for the electricity and gas system (requiring a
precise estimation of the state of the network and potential stability issues);
- Flow-based market coupling and measures on the redesign of bidding areas;
- Any type of projection for the energy system.
Description of the Power Markets and System Models
The software replicates in detail market participant's decision processes, as well as the
operation of the power system. For each day of the studied year, all market time frames
are modelled in detail: day-ahead, intraday, balancing. Moreover METIS also simulates
the sizing and procurement of balancing reserves, as well as imbalances.
Uncertainties regarding demand and RES E power generation are captured thanks to
weather scenarios taking the form of hourly time series of wind, irradiance and
temperature, which influence demand (through a thermal gradient), as well as PV and wind
generation. The historical spatial and temporal correlation between temperature, wind and
irradiance are preserved.
Calibrated Scenarios – METIS has already been calibrated to a number of scenarios of
ENTSO-E's Ten-Year Network Development Plan ('TYNDP') and PRIMES. METIS
versions of PRIMES scenarios include refinements on the time resolution (hourly) and unit
representation (explicit modelling of reserve supply at cluster and Member State level).
Data provided by the PRIMES scenarios include: demand at Member State-level, primary
energy costs, CO2 costs, installed capacities at Member State-level and interconnection
capacities.
Geographical scope – In addition to EU Member States, METIS scenarios incorporate
ENTSO-E countries outside of the EU (Switzerland, Bosnia, Serbia, Macedonia,
Montenegro and Norway) to model the impact of power imports and exports to the EU
power markets and system.
Market models –METIS market module replicates the market participants’ decision
process. For each day of the studied year, the generation plan (including both energy
generation and balancing reserve supply) is first optimized based on day-ahead demand
and RES E generation forecasts. Market coupling is modeled via NTC constraints for
interconnectors. Then, the generation plan is updated during the day, taking into account
updated forecasts and asset technical constraints. Finally, imbalances are drawn to simulate
balancing energy procurement.
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Figure 1: Simulations follow day-ahead to real-time market decision process
Source: METIS
Reserve product definition – METIS simulates FCR, aFRR and mFRR reserves. The
product characteristics for each reserve (activation time, separation between upward and
downward offers, list of assets able to participate, etc.) are inputs to the model.
Reserve dimensioning – The amount of reserves (FCR, aFRR, mFRR) that has to be
secured by TSOs can be either defined by METIS users or be computed by METIS
stochasticity module. The stochasticity module can assess the required level of reserves
that would ensure enough balancing resources are available under a given probability.
Hence, METIS stochasticity module can take into account the statistical cancellation of
imbalances between Member States and the potential benefits of regional cooperation for
reserve dimensioning.
Balancing reserve procurement – Different market design options can also be compared
by the geographical area in which TSOs may procure the balancing reserves they require.
METIS has been designed so as to be able to constrain the list of power plants being able
to participate to the procurement of reserves according to their location. The different
options will be translated in different geographical areas in which reserves have to be
procured (national or regional level). Moreover, METIS users can choose whether demand
response and renewable energy are allowed to provide balancing services.
Balancing energy procurement – The procurement of balancing energy is optimized
following the same principles as described previously. In particular, METIS can be
configured to ban given types of assets, to select balancing energy products at national
level, to share unused balancing products with other Member States, or to optimize
balancing merit order at a regional level.
Imbalances – Imbalances are the result of events that could not have been predicted before
gate closure. METIS includes a stochasticity module which simulates power plant outages,
demand and RES E generation forecast errors from day-ahead to one hour ahead. This
module uses a detailed database of historical weather forecast errors (for 10 years at hourly
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and sub-national granularity), provided by the European Centre for Medium-Range
Weather Forecasts ('ECMWF'), to capture the correlation between Member State forecast
errors and consequently to assess the possible benefits of imbalance netting. The
stochasticity module will be further extended in the coming year to include generation of
random errors picked from various probability distributions either set by the user or based
on historical data.
Figure 2: Example of wind power forecast errors for a given hour of the 10 years of
data.
Source: METIS
PRIMES suite of models
In order to assess the impacts of the various market design options on generator profits and
investments, as well as the impact of capacity remuneration mechanisms and their different
designs, a suite of models built by NTUA were used, with PRIMES model being at its
core.
PRIMES
PRIMES18
is a partial-equilibirum model of the energy system. It has been used extensively
by the European Commission for settting the EU 2020 targets, the Low Carbon Economy
and the Energy 2050 Roadmaps, as well as the 2030 policy framework for climate and
energy.
PRIMES is a private model which has been developed and is maintained by E3MLab/ICCS
of National Technical University of Athens19
in the context of a series of research
programmes co-financed by the European Commission. The model has been peer reviewed
successfully, most recently in 201120
.
18
http://ec.europa.eu/clima/policies/strategies/analysis/models/docs/primes_model_2013-2014_en.pdf.
19
http://www.e3mlab.National Technical University of Athens.gr/e3mlab/.
20
https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_1569_2.pdf'.
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The PRIMES model is suitable for analysing the impacts of different sets of climate,
energy and transport policies on the energy system as a whole, notably on the fuel mix,
CO2 emissions, investment needs and energy purchases as well as overall system costs. It
is also suitable for analysing the interaction of policies on combating climate change,
promotion of energy efficiency and renewable energies. Through the formalised linkages
with GAINS non-CO2 emission results and cost curves, it also covers total GHG emissions
and total non-ETS sector emissions. It provides details on the Member State level, showing
differential impacts across Member States.
Decision making behaviour is forward looking and grounded in micro-economic theory.
The model also represents in explicit way energy demand, supply and emission abatement
technologies, and includes technology vintages. The core model is complemented by a set
of sub-modules modelling specific sectors. The model proceeds in five year steps and has
been calibrated to Eurostat data for the years 2000 to 2010.
For the electricity sector, the PRIMES model quantifies projection of capacity expansion
and power plant operation in detail by Member State distinguishing power plant types
according to the technology type (more than 100 different technologies). The plants are
further categorised in utility plants (plants with as main purpose to generate electricity for
commercial supply) and in industrial plants (plants with as main purpose to cogenerate
electricity and steam or heat, or for supporting industrial processes). The model finds
optimal power flows, unit commitment and capacity expansion as a result of an inter-
temporal non-linear optimisation; non-linear cost supply functions are assumed for all
resources used by power plants for operation and investment, including for fuel prices
(relating fuel prices non-linearly with available supply volumes) and for plant development
sites (relating site-specific costs non-linearly with potential sites by Member State); the
non-linear cost-potential relationships are relevant for RES E power possibilities but also
for nuclear and CCS.
The simulation of plant dispatching considers typical load profile days and system
reliability constraints such as ramping and capacity reserve requirements. Flow-based
optimisation across interconnections is simulated by considering a system with a single
bus by country and with linearized DC interconnections. Capacity expansion decisions
depend on inter-temporal system-wide economics assuming no uncertainties and perfect
foresight.
The optimisation of system expansion and operation and the balancing of demand and
supply are performed simultaneously across the EU internal market assuming flow-based
allocation of interconnecting capacities. The outcome of the optimisation is influenced by
policy interventions and constraints, such as the carbon prices (which vary endogenously
to meet the ETS allowances cap), the RES E feed-in tariffs and other RES E obligations,
the constraints imposed by legislation such as the large combustion plant directive,
constraints on the application of CCS technologies, policies in regard to nuclear phase-out,
etc.
The optimality simulated by the model can be characterised either by a market regime of
perfect competition with recovery of stranded costs allowed by regulation or as the
outcome of a situation of perfectly regulated vertically integrated generation and energy
supplying monopoly. This is equivalent of operating in a perfect way a mandatory
wholesale market with marginal cost bidding just to obtain optimal unit commitment and
a perfect bilateral market of contracts for differences for power supply through which
generators recover the capital costs.
According to the model-based simulations, the capital costs of all plants, taken all together
as if they belonged to a portfolio of a single generating and supplying company, are exactly
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recovered from revenues based on tariffs applied to the various customer types. This result
does not guarantee that the optimal capacity expansion fleet suggested by the model-based
projections cam be delivered in the context of more realistic market conditions with
fragmentation and imperfections.
PRIMES was not directly used in this impact assessment, although the PRIMES EUCO27
setup was the basis for all analyses, with all inputs exogenous to the power sector, as well
as generation capacities, coming from it. The main obstacle in using PRIMES for this
impact assessment was that it assumes a perfectly competitive and well-functioning
market.
For this scope two sub-modules closely linked to PRIMES were used instead:
- PRIMES/IEM is a day-ahead and unit commitment simulator, modelling the
operation of the European electricity markets and system for a given year, being
able to capture different market designs and market participant behaviours.
- PRIMES/OM is a variant of PRIMES, modifying the use of PRIMES in order to
simulate investments under various competition regimes and with the possibility to
capture the effect of CMs.
The two models are described below in more detail21
.
PRIMES / IEM
PRIMES/IEM aims at simulating in detail the sequence of power markets - Day-ahead,
Intraday, Balancing and Reserve Procurement - in the EU for one year, covering all EU 28
Member States and their interconnections (also linked to non-EU European countries).
PRIMES/IEM is calibrated to PRIMES projections, taking as exogenous inputs:
- Load (hourly);
- Power plant capacities (as projected) and their technical-economic characteristics,
including old plants as available in projection period, new investments and
refurbishments as projected by PRIMES;
- Fuel prices, ETS carbon prices, taxes, etc.;
- Resource availability for intermittent renewables;
- Interconnection capacities;
- Heat or Steam serving obligations of CHP plants having production of heat or
steam as main purpose;
- Restrictions derived from policies, e.g. operation restrictions on old plants,
renewable production obligations, if applicable, support schemes of renewables,
biomass and CHP.
PRIMES/IEM disaggregates the interconnection network, considering more than one node
per country, with connecting grids within the countries, in order to represent intra-country
grid congestions. The assumptions about the grid within each country and across the
countries change over time, reflecting an exogenously assumed grid investment plan. It
21
The detailed methodology followed, along with results, is described in a relevant report prepared for the
scope of the impact assessment: "Methodology and results of modelling the EU electricity market using
the PRIMES/IEM and PRIMES/OM models", NTUA (2016)
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also uses a more disaggregated hourly resolution than PRIMES, in representing load and
availability of intermittent RES E resources, as well as more disaggregated technical and
economic data for each plant than PRIMES, to represent cyclical operation of plants,
possible shut-downs and start-ups. Finally, PRIMES-IEM uses detailed data on ancillary
services (reserves) and the capability of plants to offer balancing services.
The day-ahead algorithm (GAMS program, written by E3MLab) is based on the
EUPHEMIA22
algorithm. The code runs for all countries and the user can select countries
to simulate market coupling. The power plant capacities, demand (hourly for the days
selected) and other information (e.g. grid) come from PRIMES database and projections.
The linkage of data to PRIMES is fully automatic. The user can define rules for bidding
by the plants, and the power plants (production hourly) which are 'must-take' and/or
nominations. Available transfer capacities between countries can also be specified in the
interface.
The unit commitment algorithm (GAMS program written by E3MLAB and solved as a
mixed integer linear program) is a fully detailed plant operation scheduling algorithm. It
includes the technical features of the power plants (technical minimum, minimum up-time,
minimum down-time, ramp-up rates, ramp-down rates, time to synchronize, time to shut
down and capability of providing ancillary reserve services to the system), the technical
features of the interconnectors (applying DC linear power flows) and the reserve
requirements of the system (primary, secondary, spinning tertiary, non-spinning tertiary
and optionally ramping-flexibility reserves). The program runs simultaneously for the
selected countries, which are assumed to operate under a coordinated-synchronized unit
commitment. The program runs on an hourly basis and simultaneously for the sequence of
typical days; runs fully one day having assumed next day, and so on. The code is fully
consistent with the unit commitment codes ran by TSOs in Europe and in the USA
(compatible with the recommended code by FERC in the USA).
The day-ahead market Simulator (DAM_Simul) runs all EU countries simultaneously,
solving market clearing by node (one node per country) and calculating interconnection
flows restricted by DC power flows and by Available Transfer Capacities (defined by pair
of countries).
Market participant bidding23
is based on marginal costs plus mark-up reflecting scarcity.
Must take CHP, RES and nominated capacities are included in DAM simulation as fixed
(unchanged) hourly amounts. Similarly the reservation of cross-border capacity for
nominations is fixed. In some policy-options these assumptions are relaxed. The wholesale
prices of DAM are calculated from the relaxed problem, after having run the mixed integer
problem. The DAM-Simulator runs pan-European and includes interconnection flows
subject to limitations of power flow and NTC/ATC restrictions as applicable and if
applicable in each policy option.
22
EUPHEMIA (Pan-European Hybrid Electricity Market Integration Algorithm) is the single price
coupling algorithm used by the coupled European PXs (http://energy.n-side.com/day-ahead/).
23
Bidding functions are defined by plant in DAM on the basis of the marginal fuel cost of the plant,
increased by a mark-up defined hourly as depending on scarcity. The modelling of the bidding behavior
of generators, similar in PRIMES/IEM and PRIMES/OM, is discussed in detail in the PRIMES/OM
Section.
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The unit commitment simulator (UC_Simul) includes exogenously defined reserve
requirements, the outcomes of the event generator, the operation schedule of all units, the
bids in DAM and penalty factors for slack variables (re-dispatching). Operation of small-
RES E and must-take CHP is fixed. The unit commitment simulator runs pan-European
limited by power flows and NTC values.The purpose of this run is to determine the
deviations from DAM schedule, to be used in the intraday and balancing simulator.
The Intraday and Balancing Simulator (IDB_Simul) runs the above intraday and balancing
market (once for 24-hours all together) and determines a price for deviations, the financial
settlement of deviations and a revised schedule for operation of units and interconnectors.
In IDB_Simul, eligible resources can bid for supplying power to meet the deviations. The
bids can differ for upward and for downward changes of power supplied by the eligible
resources. Eligibility is defined specifically for each policy option. Capacity from
interconnectors may be eligible but only if remaining capacities (beyond the schedule of
the unit commitment) allow for this.
Figure 3: Modelling Sequence in PRIMES/IEM
Source: PRIMES/IEM
In the Reserve and ancillary services procurement Simulator (RAS-Simul) demand for
reserves is defined exogenously (equal to demand used in the UC_Simul). The outcome of
RAS-Simul is the remuneration of the resources for providing reserves and a possible
(small) modification of the schedule of units and interconnection flows.
For each policy option the demand for reserves is differentiated. Eligible resources can bid
for supplying power to meet the demand for the different types of frequency reserves. Also,
a subset of plants are eligible in each market for reserve. When the bids are endogenous
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and market-based, the prices include scarcity markups, with scarcity referring to the market
for reserves. Eligibility of resources is defined differently for each policy option. Resources
available cross-border can participate (differently constrained by policy option) in the
markets for reserves subject to limitation from availability of interconnection capacity,
which is the capacity remaining after the schedule of the unit commitment and intraday.
Resources not scheduled after the unit commitment and the intraday can submit bids to the
markets for reserves (only for tertiary reserve) but only gas turbines are eligible for this
purpose.
For the finalisation of the simulation, the unit commitment simulator is run again assuming
as given the schedule of units and interconnection flows resulted from previous steps and
the load (hourly). The objective function includes only penalties for deviation from the
schedule resulted from the previous step. The ascending order of penalties is RES E,
interconnection flows, gas, solids, nuclear, demand or another order defined specifically
by policy option. If must-take CHP and small-RES E can be curtailed then they are also
included with penalties, otherwise they are fixed. The unit commitment simulator runs at
this stage pan-European and applies flow based allocation of interconnections. The
purpose of this run is to calculate the production by plant, consumption of fuel, operation
cost by plant and emissions.
Demand response is modelled similarly to pumping transferring power from peak- to
baseload; the amount of energy reduced in peak hours is compensated in the same day by
additional energy consumption in other time segments, chosen endogenously. Therefore
demand response bids for differential demand reduction and demand increase at different
times, the bidding price reflecting costs (exhibiting decreasing return to scale), scarcity
cost opportunity and the bidding quantity being subject to potential. Demand response
(defined differently for each policy option) can be incorporated in all stages, i.e. DAM,
intraday, reserves.
The simulation cycle closes by the reporting of financial balances (load payments,
revenues and costs) for each generator, load and the TSO and calculating unit cost
indicators (e.g. for reserves, etc.). As the simulation is stochastic, the expected values of
the outcomes are calculated as the average of results by case of random events weighted
by the frequency of the case.
PRIMES / OM
PRIMES/OM is a modified version of the power sector model of PRIMES, tailored to the
needs of the impact assessment. It uses the PRIMES database, as well as its scenario
assumptions. By departing from the usual perfect competition assumption of PRIMES, it
can simulate investment behavior and the influence of CMs under various competition
regimes and bidding behaviours. Simulations are dynamic, demand is price elastic and
cross-border flows endogenous.
The model variant covers the power sector of all EU Member States linked together. The
model simulates an organized wholesale market, calculating prices, revenues and costs,
and estimating the probability of eventual mothballing of old plants and the cancelling
(partially or entirely) of investment in new plants as a consequence of the revenues
associated to the individual plant.
The model includes as an option a stylized CM auction, with or without cross-border
participation, which is general in scope in terms of eligibility and covers all dispatchable
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generators. The inclusion or not of national CMs varies by scenario simulated. The model
considers that the presence of a CM leads to lower risk premium factors which are used by
generators to decide mothballing of old plants or cancelling of investments. However, the
CM demand functions, as specified according to the logic of the model, are such that they
may grant unnecessarily capacity payment to some plant categories.
Figure 4: Modelling Sequence in PRIMES/OM
Source: PRIMES/OM
The model runs dynamically from 2020 until 2050, in 5-year steps. It uses a full PRIMES
model scenario as starting point, from where it takes the first input for load, renewables
and the projection of power plant capacities. Subsequently it modifies load based on
demand response, capacity availability and investment (except for renewables, industrial
and district heating CHP) as a result of the mechanism described above.
A fundamental assumption of the oligopoly model is that the economics on which capacity-
related decisions are made by generators are specified individually for each plant.
However, the standard PRIMES model looks at the economics of portfolios of plants to
determine the outcome of capacity-related decisions. It also, enables us to quantify the
differences between market outcomes in perfect competition, where marginal cost bidding
is applied, and under the oligopoly market structure where uplift is applied to the bids of
market participants.
Main characteristics of PRIMES/OM
Investment Evaluation – A stochastic analysis is performed with respect to the main
uncertainty factors affecting investments or early retirement of old plants, thus introducing
a probability space for the simulation of investment decision under uncertainty. These
factors have been identified as follows: (a) ETS carbon prices, (b) natural gas prices in
relation to coal prices, and (c) the volume of demand for electricity net of renewables. In
addition to the uncertainties pertaining to the framework conditions, the heterogeneity of
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decision makers in the investment evaluation process has also been taken into account.
This is accomplished by considering a distribution probability of the hurdle rates that an
investor considers (subjectively) for undertaking an investment. The hurdle rates are
equivalent to the minimum Internal Rate of Return value for deciding positively upon an
investment. The frequency distribution is modified in terms of mean and standard deviation
dependent upon the certainty or lack thereof of revenues; revenues coming from the energy
only market compared to those coming from a CM imply higher mean and standard
deviation of the distribution of hurdle rates.
Combining all of the above, a sample of about 100 combinations is generated around the
EUCO27 trajectory for the three stochastic factors for the whole time period (as vectors
over time) and 100 hurdle rate cases with combined probabilities. For the purposes of
investment evaluation, the pan-EU energy-only market is run for each sample of the
stochastic factors and revenues and costs for each plant are calculated for their total
lifetime, including possible extension of operation. Two sources of revenues are accounted
for: from operation in the energy-only market and from supplying reserve to the system.
For the cost calculation, capital annuity payments were excluded. Using the revenues and
costs calculated as such, the economic performance of each power plant is found, defined
as the present value of future earnings above operation costs for each sample of uncertain
factors and each hurdle rate case. The expected economic performance of a plant is the
result of an average of performances weighted by the probabilities.
Heterogeneous decision makers, identified by the distribution of the hurdle rates as
mentioned above, have a different threshold probability in order to decide whether or not
to continue operating a plant or cancelling investment. In other words, there is an
association of expected economic performance of each plant, as represented by its present
value, with investment cost of new plants or with salvage value (remaining capital value)
for plants, which are distributed across the decision makers according to a normal
probability distribution function. Therefore, the frequency of decision about survival of a
plant’s capacity as a function of the economic performance indicator is used as the
probability of survival. The capacity volume of the plant as projected by PRIMES in the
context of the EUCO27 scenario multiplied by the probability of survival provides us with
an update of the capacity volume.
Modelling of CMs – When a CM is assumed to be in place, it is modelled in a stylized
manner. All capacities are eligible, if dispatchable, including hydro lakes and storage,
provided that they are not under a different support scheme. For example, CHP, biomass,
etc. are excluded. Also, plants in the process of decommissioning or operating few hours
per year due to environmental restrictions as projected in PRIMES are excluded. All
capacities are remunerated for the available capacity excluding outages.
The CM payment is a result of an auction. The CM price is derived from the intersection
of demand for capacity and the offers, sorted in ascending price order. Demand for capacity
is defined as a negative-sloped linear line depending upon a price cap and linking two
capacity points: the minimum and maximum requirements. For all capacity offered up to
the minimum requirement the auction clearing price is equal to the price cap, while for the
maximum requirement it is equal to zero. The definition of the demand curve takes into
account trusted imports at peak load times and the guaranteed proportion of exports.
Therefore, implicit participation of flows over interconnections is taken into account.
Cross-border participation, when applicable, increases capacity offering. Removal of
capacities (due to mothballing or cancelling of investment, or because the capacity is
offered to a foreign CM) also decreases capacity offering. The CM winners sign a
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reliability option (one way option) which has a strike price. If the wholesale market price
is above the strike price they are assumed to return the revenues above strike price. The
results of the CM auctions, namely the stream of revenues they provide to generators, are
taken into account by the oligopoly model in the final step of investment evaluation.
Bidding Behaviour - The model assumes a scarcity bidding function as a means to mimic
the strategic behaviour of market players in an oligopoly. The bidding function is specific
to each individual plant and it takes into account hourly demand, plant technology and
plant fixed costs in order to evaluate the hourly bid price of each generator.
In order to model the bidding behaviour of plants, they are assigned to one of four different
types of merit order: no-merit, baseload, mid-load, and peak load. Hydro-reservoirs
consider also water availability. The assignment of plants takes place based on their
technology as well as on whether they participate in the energy only market; non-
dispatchable generators are considered as must-take, and therefore are assumed to bid at
zero price. The no-merit order type is intended to include this type of plants. The baseload
category includes mainly nuclear and coal/lignite plants, the mid-load CCGTs, and the
peak load of GTs and Reservoir Hydro.
Subsequently, the capacities of all plants within a merit order type are summed up in order
to determine the total capacity of every type, developing a merit stack. Then the hourly
demand is compared with the merit stack in order to estimate for every hour which merit
order type is expected to be on the margin. This is the type on which a scarcity mark-up
will be applied, assuming this is the market segment in which all strategic behaviour of
market participants takes place for a specific hour. The marginal cost which sets the basis
for the price at which each plant offers its energy is calculated based on variable cost data
from the PRIMES database. The mark-up is calculated based on the following equation:
𝑝 = 𝑝 + 𝐼 𝑚 ∗ e
− 𝐀 𝒑∙[
𝐏𝐏𝒎
𝐌 𝒎
−1]
P is the plant identifier, the merit order type, the Marginal cost, 𝑃𝑃 the total
supply (capacity) of merit order type, the hourly demand specific to merit order
type, 𝐼 the price ceiling for merit order type, the (inverse) rate of mark-up and
the scarcity bid. The demand specific to a generation type is calculated as the residual
of hourly demand minus the capacity of the merit order types which lie below the marginal.
The price ceiling is specific to every merit order type and is applied in order to guarantee
that the merit order is never reversed, i.e. peak load plants being dispatched before mid-
load plants, mid-load before baseload, etc. Also, the rate specific to each plant is dependent
upon the fixed costs of the plant, which comprise mainly of capital costs, in a risk averse
manner. This convention is in place so that plants with high fixed costs are more reluctant
to apply a mark-up to their marginal cost in fear of staying out-of-merit and not being
dispatched due to the mark-up being too high. Finally, if in post-calculation the scarcity
bid exceeds the price ceiling, it is set equal to the ceiling.
Description of methodological approach followed concerning baseline
PRIMES EU Reference Scenario 2016
A common starting point to all Impact Assessments is the EU Reference Scenario 2016
('REF2016'). It projects greenhouse gas emissions, transport and energy trends up to 2050
on the basis of existing adopted policies at national and EU level and the most recent
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market trends. This scenario was prepared by the European Commission services in
consultation with Member States. All other PRIMES scenarios build on results and
modelling approach of the REF2016.
Although REF2016 presents a comprehensive overview of the expected developments of
the EU energy system on the basis of the current EU and national policies, and could be
considered as the natural baseline for all impact assessments, it fails doing so for an
important reason. This scenario does not have in place the policies to achieve the 2030
climate and energy targets that are already agreed by Member States in the European
Council Conclusions of October 2014. It also does not reflect the European Parliament's
position on these targets.
Therefore, although it was important for all initiatives to have a common "context" in order
to ensure coherent assessments, each Impact Assessment required the preparation of a
specific baseline scenario, which would help assess specific policy options relevant for the
given Impact Assessment.
Central Policy Scenario: PRIMES EUCO27
Because of the need to take into account the minimum agreed 2030 climate and energy
targets (and the 2050 EU's decarbonisation objectives) when assessing policy options for
delivery of these targets, a central policy scenario was modelled ('EUCO27').
This scenario is the common policy scenario for all Impact Assessments. Additional
baseline and policy scenarios were prepared for each Impact Assessment, addressing the
specific issues to be assessed by each initiative, notably which measures or arrangements
have to be put in place to reach the 2030 targets, how to overcome market imperfections
and uncoordinated action of Member States, etc. A summary of the approach followed in
each respective impact assessment can be found in the Annex IV of the RED II impact
assessment.
This approach of separating a central policy scenario reaching the 2030 targets in a cost-
effective manner and other scenarios that look into specific issues related to
implementation of cost effective policies enables to focus on "one issue at a time" in the
respective separate analysis. It enabled to assess in a manageable manner the impacts of
several policy options and provide elements of answers to problem definitions listed in the
2016 impact assessment, without the need to consider the numerous possible combinations
of all the options proposed under each respective initiative.
PRIMES EUCO27 scenario is based on the European Council conclusions of October
201424
. In particular, the following were agreed among the heads of states and
governments:
- Substantial progress has been made towards the attainment of the EU targets for
greenhouse gas emission reduction, renewable energy and energy efficiency, which
need to be fully met by 2020;
- Binding EU target is set of an at least 40% domestic reduction in greenhouse gas
emissions by 2030 compared to 1990;
24 http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdata/en/ec/145397.pdf.
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- This overall target will be delivered collectively by the EU in the most cost-
effective manner possible, with the reductions in the ETS and non-ETS sectors
amounting to 43% and 30% by 2030 compared to 2005, respectively;
- A well-functioning, reformed ETS with an instrument to stabilise the market in line
with the Commission proposal will be the main European instrument to achieve
this target; the annual factor to reduce the cap on the maximum permitted emissions
will be changed from 1.74% to 2.2% from 2021 onwards;
- An EU target of at least 27% is set for the share of renewable energy consumed in
the EU in 2030. This target will be binding at EU level;
- An indicative target at the EU level of at least 27% is set for improving energy
efficiency in 2030 compared to projections of future energy consumption based on
the current criteria. It will be delivered in a cost-effective manner and it will fully
respect the effectiveness of the ETS-system in contributing to the overall climate
goals. This target will be reviewed by 2020, having in mind an EU level of 30%;
- Reliable and transparent governance system is to be established to help ensure that
the EU meets its energy policy goals, with the necessary flexibility for Member
States and fully respecting their freedom to determine their energy mix;
The above requirements, with a minimum energy saving level of 27%, are reflected in
EUCO27. Concrete specifications on assumptions were made by the Commission in order
to reach the relevant targets by using a mix of concrete and yet unspecified policies. A
detailed description of the construction of this scenario is presented in Section 4 of the EE
impact assessment and its Annex IV.
As this scenario is not directly used in the present impact assessment, the reader is referred
to the relevant technical annexes of the EE and RED II impact assessments for more details
on its main assumptions and results. Table 1 below presents the main projections for 2030
related to the power system for EU28.
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Table 1: PRIMES EUCO27 Modelling Results for the power system (EU28)
2000 2015 2030
Share in
total for
2030 (%)
% diff
2015-
2010
% diff
2030-
2015
Electricity consumption (in TWh) 3,029.0 3,271.8 3,525.6 8% 8%
Final energy demand 2,530.7 2,802.4 3,081.3 11% 10%
Industry 1,061.1 1,001.4 1,054.8 30% -6% 5%
Households 713.8 833.6 899.7 26% 17% 8%
Tertiary 683.5 899.3 982.2 28% 32% 9%
Transport 72.3 68.2 144.6 4% -6% 112%
Energy branch 281.7 262.6 231.2 7% -7% -12%
Transmission and distribution losses 216.2 206.7 213.1 6% -4% 3%
Net Installed Power Capacity (in
GWe)
683.5 965.6 1,131.0
41% 17%
Nuclear energy 139.6 120.8 109.9 10% -13% -9%
Renewable energy 129.0 366.7 652.2 58% 184% 78%
Hydro (pumping excluded) 115.8 127.5 133.3 12% 10% 5%
Wind on-shore 12.7 130.6 246.1 22% - 88%
Wind off-shore 0.1 11.0 37.9 3% - 246%
Solar 0.2 97.4 233.8 21% - 140%
Biomass-waste fired 12.7 27.9 53.1 5% 121% 90%
Other renewables 0.8 1.1 2.1 0% 32% 86%
Thermal power 414.9 478.1 368.9 33% 15% -23%
Solids fired 194.5 176.6 99.4 9% -9% -44%
Oil fired 83.3 53.1 15.3 1% -36% -71%
Gas fired 123.8 219.6 200.1 18% 77% -9%
Net Electricity generation by plant
type (in TWh)
2,844.0 3,090.0 3,396.7
9% 10%
Nuclear energy 893.9 825.7 738.4 22% -8% -11%
Renewable energy 374.5 736.2 1,372.8 40% 97% 86%
Hydro (pumping excluded) 351.6 357.7 375.1 11% 2% 5%
Wind on-shore 22.2 241.4 564.4 17% - 134%
Wind off-shore - 32.8 127.3 4% - 288%
Solar 0.1 103.8 303.6 9% - 193%
Biomass-waste fired 42.9 130.6 238.1 7% 204% 82%
Other renewables 5.0 7.1 9.7 0% 42% 37%
Thermal power 1,575.6 1,528.0 1,285.6 38% -3% -16%
Solids fired 866.3 780.3 448.6 13% -10% -43%
Oil fired 178.4 30.2 14.6 0% -83% -52%
Gas fired 483.4 580.4 576.8 17% 20% -1%
Source: PRIMES
Baseline: Current Market Arrangements ('CMA')
The Market Design Initiative addresses four different Problem Areas. The first two,
addressing market functioning and investments, share a common baseline which is highly
dependent on the context (e.g. based on REF2016 or EUCO27). The other two Problem
Areas, concerning risk preparedness and retail markets, are more independent of the overall
context, as in each case the envisaged baseline and options can apply in either context
(moreover the assessment tends to be mainly qualitative). Therefore the discussion on the
baseline is meaningful mainly for the first two Problem Areas.
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Similar to the other 2016 Energy Union initiatives, EUCO27 was chosen as the starting
point (i.e. context) of the baseline for the Market Design Initiative (so-called "Current
Market Arrangements" – CMA). The EUCO27 scenario is the most relevant to the
objectives of the initiative, as it provides information on the investments needed and the
power generation mix in a scenario in line with the EU's 2030 objectives.
As all analysis focuses on the power sector, all assumptions exogenous to the power sector
were taken from the EUCO27 scenario. This also applied for the energy mix, the power
generation capacities for each period, the fuel and carbon prices, electricity demand,
technology costs etc. The main obstacle in further using the EUCO27 as a baseline for this
impact assessment was that it assumes a perfectly competitive and well-functioning
European electricity market, more matching the end point than the starting point of the
analysis. Therefore CMA differs from the EUCO27 scenario by including existing market
distortions, as well as current practices and policies on national and EU level.
The CMA assumes implementation of the Network Codes, including the CACM and the
EB Guidelines (the later in their proposed form). It is assumed that the CACM Guideline
will bring a certain degree of harmonisation of cross-border intraday markets, gate closure
times and products for the intraday, as well as a market clearing. National intraday and
balancing markets will be created across EU and a certain degree of market-coupling of
intraday markets will be achieved. At the same time, the EB Guideline is expected to bring
certain improvements to the balancing market, namely the common merit order list for
activation of balancing energy, the standardisation of balancing products and the
harmonisation of the pricing methodology for balancing. Nonetheless, other important
areas like harmonisation of intraday markets and balancing reserve procurement rules will
not be affected by the guidelines.
The baseline does not consider explicitly any type of existing support schemes for power
generation plants, neither in the form of RES E subsidies nor in the form of CMs25
. This is
governed to a large degree from the 2014 EEAG applicable as of 1 July 2014. Aid schemes
existing at that moment have to be amended in order to bring them into line with EEAG
no later than 1 January 2016. This with the exception of schemes concerning operating aid
in support of energy from renewable sources and cogeneration that only need to be adapted
to the EEAG when Member States prolong their existing schemes, have to re-notify them
after expiry of the 10 years-period or after expiry of the validity of the Commission
decision or change them. This implies that all existing schemes will expire by 2024 at the
latest and will be adapted to the EEAG, applicable at the time of their notification. Current
guidelines allows operational aid only as feed-in premium, not attributed for the hours with
negative prices and with its level determined via tenders. In essence this means that non-
market based support schemes are fully phased out by 2024 assuming that the rules as
regards RES E and CHP aid schemes well remain unaltered when the EEAG is reviewed
in 2020.
25
Admittedly this assumption is strong, but necessary to simplify the analysis. Otherwise a riskier (for the
analysis) assumption would need to be made on the future share, type and level of support for the various
support schemes per Member States in the end becoming a major driver for the results and complicating
their interpretation.
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Moreover, the RED II proposals (part of the baseline of the present impact assessment)
will enshrine and reinforce the market-based principles for the design of support schemes.
As it is reasonable to assume that the RED II will enter into force prior to 2024, assuming
that all support to RES E by 2030 is market based is a prudent assumption.
The effect of RES E subsidies is relevant to the MDI impact assessment only when it
directly affects the merit order. Overall the cost-efficient level of investments in RES E26
is taken as given across all assessed options, as projected in EUCO27, without examining
how the costs of these investments are recuperated (topic addressed in the RED II impact
assessment). The baseline assumes one of the main objectives of the RED II initiative is
achieved and a framework strengthening the use of tenders as a market-based phase-out
mechanism for support is in place, gradually reducing the level of subsidies over the course
of the 2021-2030 period (still support schemes would exist for all non-competitive RES E
technologies). Moreover it is assumed that existing FiT contracts have been phased-out by
2030 to a large degree, most importantly the ones targeted on biomass, being the ones most
distorting to the merit order. As a result the assumption of not considering any non-market
based support for RES E generation is reasonable and not significantly affecting the results.
As for CMs, existing or planned, they are mainly relevant for Problem Area II and did not
need to appear in the common baseline of the two Problem Areas. The analysis for Problem
Area I did not touch issues related to investments, thus the assumption of CMs (which
would be present in all assessed options) would have a limited influence on the impacts
and the ranking of the options27
. As far as Problem Area II is concerned, again their
inclusion was avoided, as any results would be highly dependent on the specific CM
assumptions over the examined period. Moreover, in line with the results of the analysis
in section 6.2.6.2, the effect of adding a CM would most likely be to further increase the
cost of the power system. As the baseline was already a very costly scenario compared to
the preferred energy-only market one, the conclusion from the comparison of the options
would remain the same.
METIS calibration to EUCO27
As mentioned above, for the scope of this impact assessment METIS was calibrated to the
PRIMES EUCO27 scenario. In fact, as the calibration needed to take place much before
the finalisation of the PRIMES EUCO27, it was performed on one of its preliminary
versions. The main elements of the calibration process, as well as the most important
differences between the preliminary and the final version of EUCO27 are described below.
A significantly more detailed description of the calibration has been reported on a separate
document, to be found on the METIS website28
.
Preliminary EUCO27
26
The same applies for CHP, when the main use of those plants is the production of heat/steam.
27
The CMs would not affect the merit order in problem area I, as the analysis assumes bidding based on
marginal costs (not scarcity pricing, which is introduced in problem area II).
28
Once operational, the envisaged link is expect to be the following:
https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis
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The two versions of EUCO27 are in general quite close from an EU energy system
perspective. Two differences can be found in 2030, one in the RES E shares and the other
in CO2 prices, slightly affecting power generation capacities and production.
RES E overall share is in both cases 27%, with a differentiation in the sectoral contribution:
in the preliminary version the share of RES E is at 48.4%, while being 47.3% in the final
EUCO27 version. This was mainly driven by differences in off-shore wind deployment.
There is more switching from coal to gas in the final version. This is translated to 2 p.p.
increase of gas in the share of power gas generation, while solids decreased by 0.5 p.p. and
RES E by 1.3 p.p.. The CO2 price, which was 38.5 EUR/tCO2 in the preliminary version
is 42 EUR/tCO2 in the final EUCO27 version.
The effect of these differences is not very significant on the EU level, although it does have
some implication on the results of specific Member States with a projected high capacity
of off-shore wind in the preliminary version, e.g. the UK.
METIS calibration to PRIMES EUCO27
For the scope of this impact assessment, simulations adopted a country level spatial
granularity and an hourly temporal resolution of year 2030 (8760 consecutive time-steps
year), capturing also the uncertainty related to demand and RES E power generation.
Modelling covered all ENTSO-E countries, not only EU Member States, as follows:
 All ENTSO-E countries for the day-ahead market;
 EU28+NO+CH for intraday, balancing and reserve procurement29
;
 EU28+NO for regional co-operation for reserve procurement, CH reserve assumed
to be procured nationally.
For configuring METIS to match the (preliminary) PRIMES EUCO27 projections, a
number of steps were taken, the most important of which are described in the following.
Details can be found in the relevant METIS report30
.
1. The data provided for the calibration concerned only EU28. Missing data for other
countries modelled with METIS (i.e. Bosnia, Switzerland, Montenegro, FYROM,
Norway and Serbia) were complemented by other sources, mainly ENTSO-E 2030
vision 1 of TYNDP 2016.
2. The hourly power demand time series were based on ETNSO-E's 2030 vision 1
scenario. Data were adjusted so that on average (over 50 weather data realizations)
the power demand of each country corresponds to the PRIMES EUCO27
projections.
3. Installed capacities were computed based on PRIMES EUCO27 scenario31
. For
certain EU28 countries the split between hydro lake and run-of-river of PRIMES
was reviewed based on historical data form ENTSO-E, due to differences in the
29
Actually reserve procurement was not modelled for other non-EU28 Member States, as well as for Malta,
Cyprus and Luxembourg.
30
"METIS Technical Note T04: Methodology for the integration of PRIMES scenarios into METIS", Artelys
(2016)
31
CHP units were treated as electricity-only gas plants, as currently METIS does not model the heat sector.
Division of RES to small and large scale (e.g. rooftops solar) was also not captured.
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definitions used in PRIMES (based on Eurostat) and METIS (based on ENTSO-
E).
4. Generation of ten historical yearly profiles for wind and solar power was performed
according to the methodology depicted in Figure 5. The methodology followed
delivered annual load-factors closely matching the ones of PRIMES EUCO27.
Figure 5: PV and wind generation profiles
Source: METIS
5. Thermal plant fleets comprised of the following technologies: hard coal, lignite,
CCGT, OCGT, oil, biomass. The various fleets, except oil and biomass, were
divided into two or three classes (only CCGT were divided into three). Thermal
installed capacities were based on PRIMES EUCO27, without though enforcing
any type of constraint on the net electricity generation of these plants (which was
a pure result of the modelling). The technical-economic assumptions of PRIMES
were used for the power plants, complemented by other sources or databases when
missing.
6. Water inflow profiles, as well as storage parameters, required important
reconciliation work combing data from ENTSO-E, TSOs and PRIMES.
7. The international fuel price assumptions of PRIMES EUCO27 were used for
calculating the marginal production costs of the thermal fleets. Specifically for coal
and biomass, end-user fuel prices coming again from PRIMES EUCO27–
including also transportation costs – were used instead.
8. METIS used the same NTC values as in PRIMES EUCO2732
. NTC values between
European and non-European countries are completed using ENTSO-E 2030 v1
scenario.
9. As METIS focuses in particular on the economics of security of supply, a key point
is that installed capacity is consistent with peak demand. Consequently, provided
OCGT capacities were optimized to satisfy security-of-supply criteria. To optimize
OCGT capacities, supply-demand equilibrium was computed with “State of the art”
32
- Regarding grid development and the interconnectors between countries, they are based on the ENTSO-
E TYNDP, following the respective timelines. After the end of the TYNDP, expansions are based on
known plans and the development of RES E.
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OGCT capacities as variables over 50 years of weather data. Capacities of “oldest”
OCGT fleets remain fixed to the installed capacities in 2000 which have not been
replaced by 2030. Table 2 presents the results of the OCGT capacity optimization
consisting in the added OCGT installed capacities per country. These additional
capacities are added to the installed capacities in 2030 excluding the investment
between 2000 and 2030.
Table 2: Additional OCGT capacities needed to satisfy security of supply standards
Source: METIS, Artelys Crystal Super Grid
METIS policy scenarios for the options of Problem Area I
This section provides information on the market design options that were modelled and
assessed using METIS. Each scenario was run using the full capabilities of METIS. In fact
certain aspects of METIS were further developed in order to be possible to better assess a
number of the measures covered in the impact assessment.
Each scenario was intended to match the setup of one assessed option. For this purpose the
options were first decomposed into a number of "fields", reflecting existing market
distortions or design features that were addressed within each option. Following
subsequent analysis, these fields were then narrowed down to the twelve presented in Table
3 below. For each of these fields, two or three sub-options were considered across the
different scenarios. The sub-options considered (entitled "a"/"'b"/"c") are identified on the
right had columns of Table 3, while their description is provided in Table 4.
For all fields, sub-option "a" reflects current practices and existing market distortions, as
well as the possible evolution of markets in the near future in the absence of new policies.
The identification and methodology for the quantification of current practices was
supported by a study performed specifically for this purpose33
.
33
"Electricity Market Functioning: Current Distortions, and How to Model their Removal", COWI (2016).
BE DK FI FR IE NO SE UK
OCGT added capacity
(GW)
5 2 4 6 1 4 3 19
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Table 3: Overview of MDI impact assessment Problem Area I scenarios as modelled
by METIS (read in conjunction with Table 4)
Action Field
MDI options
0 1(a) 1(b) 1(c) 2
1 DR deployment a b b c c
2 RES E priority dispatch a b b b b
3 Biomass reserve procurement a b b b b
4 Coal/lignite unit commitment at intraday a b b b b
5 Balance responsibility a b b b b
6 Intraday coupling a a b b b
7 Time granularity for reserve sizing a a b b b
8 Reserve procurement methodology a a b b b
9 Joint/separate upward/downward reserve a a b b b
10 Use of NTC a a b b c
11
Reserve dimensioning and risk sharing
a a b b c
12 PV, Wind and RoR reserve procurement a a a b b
Source: METIS
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Table 4: Overview of the sub-options for each measure modelled in METIS
Measure Topic Description of the options
1 DR deployment
Three levels of DR deployment (sub-options a, b and c, with increasing
economic potential, based on COWI BAU and PO2 scenarios34
) were
considered.
In sub-option "a" DR can considered only for countries where DR has
currently access to the market and only for industrial resources based
on BAU potentials. In sub-option "b" DR by industrial resources
appears in all countries based on BAU potentials. In sub-option "c" all
DR resources participate based on the potential of the PO2 scenario,
adjusted to better match EUCO27 projections and the activation limits
of DR potential.
2
RES E priority
dispatch
Two options were considered:
a. Penalty factor for PV and Wind curtailment, priority dispatch
for Biomass
b. No penalty factor or priority dispatch for PV, Wind and
Biomass
For sub-option "a", modelling RES E priority dispatch for wind and
PV was performed via a penalty factor and not by explicit priority
dispatch. The reason was that there were a number of hours for certain
Member States that if an explicit priority dispatch was enforced for all
RES E, their power system collapsed (solution was infeasible). In
reality this would most likely be addressed by the TSOs via the
curtailment of RES E.
3
Biomass reserve
procurement
Two options for participation of biomass in reserve procurement:
a. Biomass does not participate in FCR or FRR
b. Participation of Biomass (the absence of priority dispatch is
a prerequisite)
4
Coal/lignite unit
commitment at
intraday
Two options for coal and lignite unit commitment:
a. The day-ahead unit commitment decision (i.e. which plants
are turned on or off) for coal and lignite power plants cannot
be refined during intraday, i.e. coal and lignite plants are
treated as must-runs in intraday once scheduled in day-ahead.
b. Coal and Lignite can re-optimise their commitment in
intraday (subject to their technical constraints).
5
Balance
responsibility
By making RES E producers financially responsible for the
imbalances they are encouraged to improve their generation forecasts.
Two options were considered:
a. H-2 forecasts were used for Wind and PV generation for
reserve dimensioning and generation of imbalances.
b. H-1 forecasts were used for demand and PV, while 30 min
forecasts were used for Wind, leading to lower imbalances
and lower reserve requirements.
34
"Impact Assessment support Study on downstream flexibility, demand response and smart metering",
COWI (2016)
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Measure Topic Description of the options
6 Intraday coupling
Auctions for interconnections capacity can either be explicit, captured
in METIS as if assuming the flows are fixed in H-4, or implicit, in
which case flows can be updated in H-1. Two options were considered:
a. Auctions were mostly explicit, except in specific areas based
on current practices.
b. Auctions were implicit for all interconnections.
In any case, the reserve procured at day-ahead remained fixed during
intraday.
7
Time granularity
for reserve sizing
Two options were considered for aFRR reserve sizing:
a. Fixed reserve size computed as 0.1% and 99.9% centiles of
imbalance distribution over the year. While some Member
States have different reserve sizes depending on demand
variation, this option assumes that the reserve size is constant
over the year for all Member States.
b. Variable reserve size depending on the hour of the day and
wind energy generation. Size is computed with 0.1% and
99.9% centiles of imbalance conditional distribution
8
Reserve
procurement
methodology
Reserve can be procured either day-ahead (which was modelled in
METIS as a joint optimization of power and reserve hourly
procurement at day-ahead) or on a fixed basis per year (in which case
the mean annual value of optimal reserve procurement is used). The
options were:
a. Current practices
b. Day-ahead procurement
9
Joint/separate
upward/downward
reserve
Two options were considered for upwards and downwards reserve:
a. Joint procurement according to current practices
b. Being two separate products which can be procured
independently
10 Use of NTC
To model the process of interconnection allocation, three options were
considered:
a. National TSOs need to have a high security margin. For the
scope of METIS, EUCO27 NTCs were reduced by 5%.
b. Collaboration between TSOs reduces the need for security
margins. EuCo NTC values were used.
c. The introduction of a supranational entities will result in a
further reduction of the security margins, leading to an
increase by 5% of the EuCO NTCs.
11
Reserve
dimensioning and
risk sharing
To assess whether risk sharing can reduce the needs for national
reserves, three options were considered. Reserve was sized using a
probabilistic approach:
a. At national level
b. At regional level
c. At EU level
In order to ensure Member States can face similar security of supply
risks when less reserves can be procured (Options b. and c.), part of
the interconnections' capacity was reserved for mutual assistance
between Member States.
12
PV, Wind and RoR
reserve
procurement
Two options:
a. PV, Wind and Hydro RoR do not participate in FCR or FRR
b. Participation of PV, Wind and Hydro RoR in FCR or FRR
Source: METIS
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A more detailed description of the scenarios, how each option/measure was modelled and
what were the identified relevant current practices, can be found in an explanatory
technical report35
.
It is important to highlight that the scenarios under Problem Area I do not consider
explicitly the possible existence of capacity mechanisms nor support schemes for RES E,
focusing strictly on the wholesale market operation over the various time frames (day-
ahead, intraday, balancing). Nevertheless, certain assumptions (like priority dispatch for
biomass) would make economic sense only in the case of existing economic subsidies.
Figure 6: Regions used for cooperation in reserve sizing and procurement
Source: METIS
35
"METIS Technical Note T05: METIS market module configuration for Study S12: Focus on day-ahead,
intraday and balancing markets", Artelys and THEMA Consulting (2016).
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Figure 7: DR deployment in METIS for options a, b and c and current practices in
DR participation in balancing markets
Source: METIS
PRIMES/IEM policy scenarios for the options of Problem Area II
PRIMES/IEM scenarios were setup very similarly to the METIS scenarios. As can be
deduced from the description of the model, PRIMES/IEM puts more emphasis on the
simulation of the bidding behaviour of market participants and the modelling of the grid,
thus making it a better tool to capture the additional measures considered in Option 1 of
Problem Area II (on top of Option 1(c) of Problem Area I), i.e. the removal of low price
caps and the addition of locational price signals.
The consideration of market participant bidding behaviour and internal grid congestion,
made it necessary to re-run the baseline (Option 0) also of Problem Area I under these new
assumptions, in order to be used as the baseline of Problem Area II, with one caveat: similar
to METIS, PRIMES/IEM cannot model CMs. On one hand this implies an underestimation
of the benefits of the energy only market (Option 1) related to the more efficient operation
of the system. On the other hand the modelled baseline could not be used for the
comparison with Options 2 and 3. The approach followed to resolve this issue is described
in the next section.
In order to enrich the analysis, and provide more comparability with the analysis performed
for Problem Area I, it was decided to run also Options 1(a) (level playing field) and Option
1(b) (strengthening short-term markets) of Problem Area I. For the better understanding of
the reader, the construction of these options is presented in a similar manner as for the
METIS scenarios, highlighting that Option 0 corresponds to the baseline and Option 1(c)
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to Option 1 of Problem Area II. Options 1(a) (level playing field) and 1(b) (strengthening
short-term markets) do not correspond to any specific option of Problem Area II, but are
presented for completeness. The identification and methodology for the quantification of
current practices was supported by the same study used for the METIS modelling.
Table 5: Overview of MDI impact assessment Problem Area II scenarios as modelled
by PRIMES/IEM (read in conjunction with Table 4)
Action Field
MDI options
0 1(a) 1(b) 1
1 DR deployment a b b c
2 RES E priority dispatch a b c d
3 Day-ahead and intraday liquidity a b c c
4 Intraday coupling a b c c
5 Reserve dimensioning a b c c
6 Reserve procurement methodology a a b b
7 Use of NTC and bidding zones assumption a a b b
8 Price Caps a b b b
Source: PRIMES/IEM
Table 6: Overview of the sub-options for each measure modelled in METIS
Measure Topic Description of the options
1 DR deployment
Three levels of DR deployment (sub-options a, b and c, with increasing
economic potential, based on COWI BAU and PO2 scenarios) were
considered. Assumptions were similar to METIS. As load shifting and
load reductions could be captured in PRIMES/IEM, DR was modelled
also for the day-ahead (not only for balancing / reserves as in METIS).
2
RES E priority
dispatch
Four sub-options were considered:
a. Priority dispatch for must take CHP, RES E, biomass and
small-scale RES E
b. As in (a), but biomass bids at marginal costs.
c. As in (b), with no priority dispatch of RES E except small
scale. RES E bidding at marginal costs minus FIT (wherever
applicable).
d. As in (c) but with no priority of small-scale RES E thanks to
aggregators.
Note that removal of priority dispatch is assumed to imply balance
responsibility and capability to participate in intraday and offer
balancing services. Thus for sub-option (d) all resources participate in
intraday, offer balancing services and have balancing responsibilities.
3
Day-ahead and
intraday liquidity
Three options were considered:
a. Low liquidity. DAM covers part of the load, with many
bilateral contracts nominated. ID illiquid in certain countries,
in which case TSO has significant RR.
b. Improved liquidity. DAM covers the large majority of the
load, no nominations. ID illiquid in certain countries, in which
case TSO has significant RR.
c. Liquid markets. DAM covers the whole load. Liquid and
harmonised ID markets.
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Measure Topic Description of the options
4
Intraday
coupling
Three options were considered:
a. Very limited participation of flows over interconnectors (as
available capacity for intraday is restricted to the minimum –
defined by country)
b. Limited participation of flows over interconnectors
c. Entire physical capacity of interconnectors allocated to IDM
and flow-based allocation of capacities, after taking into
account remaining capacity of interconnectors.
5
Reserve
dimensioning
Reserve was sized exogenously (own calculations). Three options were
considered:
a. High reserve requirements (national)
b. High reserve requirements (national) but slightly reduced than
in Option 0
c. EU-wide reserve requirements (nonetheless taking into
account areas systematically congested)
6
Reserve
procurement
methodology
The options were:
a. Current practices
b. Day-ahead procurement(which was modelled in
PRIMES/IEM as a joint optimization of power and reserve
day-ahead procurement)
7
Use of NTC and
bidding zones
assumption
Two options were considered:
a. Restrictive ATC (NTC – bilateral contracts – TSO reserves) –
defined by country. National Bidding Zones (NTC values are
given on existing border basis)
b. Entire physical capacity of interconnectors allocated to DAM
and flow-based allocation of capacities
8 Price Caps
Two options:
a. Reflecting current practices
b. Equal to VoLL, being the same for all Member States.
Source: PRIMES/IEM
PRIMES/OM policy scenarios for the options of Problem Area II
As already discussed in the previous section, the technical difficulty to model
simultaneously specific wholesale market measures (removal of low price caps, locational
signals for investments) with the issues on the coordination of CMs led to a two-step
approach:
- Initially PRIMES/IEM was used to model Option 0 and Option 1 of Problem Area
II. This was sufficient to show the benefit of Option 1.
- Subsequently PRIMES/OM was used to model Options 1 to 3 of Problem Area II,
but not Option 0, this time the focus being on CMs. Comparison was performed
among these three Options.
Due to the limitations of PRIMES/OM, all the detailed measures and assumptions under
Option 1 could not be captured. Concerning bidding behaviour, the same approach as in
PRIMES/IEM was followed. Table 7 presents a short comparison of the main results
related to power generation for 2030 for the three models (PRIMES, PRIMES/IEM and
PRIMES/OM).
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Table 7: Comparison of results for PRIMES EUCO27, PRIMES/IEM Option 1(b)
and PRIMES/OM Option 1 for 2030.
PRIMES
EUCO27
PRIMES/IEM
Option 1(b)
PRIMES/OM
Option 1
Net Installed Power Capacity (in MWe) 1,131,045
as in
EUCO27
1,094,290
Nuclear energy 109,905 109,905
Hydro (pumping excluded) 133,335 133,335
Wind on-shore 246,064 246,064
Wind off-shore 37,949 37,949
Solar 233,813 233,813
Biomass-waste fired 53,073 53,073
Other renewables 2,079 2,066
Solids fired 99,396 80,844
Oil fired 15,304 15,930
Gas fired 200,127 181,312
Net generation by plant type (in GWh) 3,396,680 3,339,769 3,378,950
Nuclear energy 738,363 678,318 737,365
Hydro (pumping excluded) 375,138 364,089 375,020
Wind on-shore 564,407 552,893 564,539
Wind off-shore 127,334 126,953 127,388
Solar 303,625 266,644 299,070
Biomass-waste fired 238,108 231,813 200,828
Other renewables 9,732 9,732 9,268
Solids fired 448,640 368,460 469,182
Oil fired 14,572 28,81636 11,754
Gas fired 576,760 712,051 584,537
Source: PRIMES
Apart from the differences in the installed capacities for solids and gas plants, explained
in more detail in Section 6.2.6.3, the main difference is the increased generation of gas
plants in detriment of solids and nuclear in PRIMES/IEM, most likely due to the better
capturing of the flexibility needs of the system.
With Option 1 described above, Options 2 and 3 assume on top the inclusion of CMs for
specific countries. Both Options assume CMs only in the case of Member States foreseeing
adequacy problems in their markets. Therefore certain Member States needed to be chosen
indicatively for this role. For the scope of this assessment, four countries were assumed to
be in the need of a CM: France, Ireland, Italy and UK. This assumption was not based on
a resource adequacy analysis, but on the CMs examined under DG COMP's Sector Inquiry,
focusing specifically on countries with market-wide CMs.
When a country was assumed to have a CM in place, it was assumed that generators no
longer followed scarcity pricing bidding behaviour, but shifted to marginal cost bidding.
Therefore in Options 2 and 3 a hybrid market was considered for EU28, with 24 Member
States having an energy only market (with scarcity pricing behaviour), while 4 Member
36
As the reported technology categories of PRIMES do not entirely match PRIMES/IEM, for PRIMES/IEM
the reported figure in the table for oil fired generation includes peak units, steam turbines (both oil and
gas) as well as CHP with oil as main fuel.
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States having and energy market (with marginal pricing behaviour) supplemented with a
capacity mechanism.
Finally the only difference between Options 2 and 3, is that in Option 3 the CM is assumed
to include rules foreseeing explicit participation of cross-border capacities. Cross-border
capacities were assumed to participate to a CM up to a certain upper bound. The main idea
for this calculation of this upper bound was similar to the concept of unforced available
capacity, which is used in CMs for the generation capacities. Note though that using this
concept for calculating unforced available capacity (or de-rated capacity) of
interconnectors during system stress times is more complex because the probability of non-
delivery is not due only to technical factors but it is mainly due to congestion factors, which
can considerably vary depending on power trade circumstances during system stress times.
To do this calculation it was necessary to dispose simulation results of the operation of the
multi-country system. Alternatively, the calculation could be based on statistical data on
system operation in past years. In both cases, the simulation requires calculation of power
flows over the interconnection system.
Data collection and data gaps
The modelling performed for the impact assessment had significant data requirements. For
example METIS requires about twenty different types of data (such as installed capacities,
variable costs, availabilities, load factors and such). Depending on the type of simulation,
over 25 million individual data points can be required for each single test case, mostly
coming from hourly data (such as hourly national demands). For the NTUA models an
ever larger set of data was required (multiple times larger), as PRIMES covers the whole
European energy sector and all existing or emerging technologies, from household
appliances to industrial processes and means of transport. The respective data were
collected from public and commercial databases, as well as DG ENER EMOS database.
Moreover, in order to assess the impact of various measures and regulations aimed at
improving the market functioning, one needs to compare the market outcome in the
distorted situation, i.e. under current practices, with the market outcome after the
implementation of new legislative measures. These distortions should be based on the
current situation and practices and form the baseline for the impact assessment.
For this purpose the Commission requested assistance in the form of a study providing the
necessary inputs, i.e. facts and data for the modelling of the impacts of removal of current
market distortions. Although a significant amount of data was collected, a large number of
desired data sets was either unavailable or undisclosed. This unavailability of data
sometimes applied only for specific Member States for certain series, creating difficulties
in using the collected data for the rest of the Member States. In these cases proxies need to
be defined that could fill in the data gaps37
.
Modelling limitations
Every model is a simplification of reality. Thus, a model itself is not able to capture all
features and facets of the real world. While one may be tempted to include as many features
and options as possible, one has to be careful in order to avoid over-complication of
37
"Electricity Market Functioning: Current Distortions, and How to Model their Removal", COWI (2016).
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models. This can very quickly result in overfitting (i.e. modelling relationships and cause
and effects that do in this way not apply to reality, but yielding a better fit), and
transparency issues (i.e. understanding in the end not the model results, or drawing wrong
conclusions). It is therefore essential to find the right balance between complexity and
transparency, taking the strengths and weakness of each modelling approach into account.
For these reasons, considering the limitations of each modelling approach, a number of
compromises were made. There was an effort these compromises to retain the complexity
of the modelling at the lowest possible level, in order to allo interpretability of results. The
aforementioned study on market distortions also contributed in identifying the best
modelling approaches to capture all major distortions.
One should also expect that the different models used, although all of them focus on the
power sector, can produce different results due to the varying methodological approaches
followed. As long as these differences are well-founded on the underlying methodology
and scope of each model, while being based on the same underlying assumptions and input
data, they can be considered as complementary, as they give a better overview of the
impacts of the various policy options and help producing a more robust assessment.
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Tool
Concerned
Main Modelling Limitations
Leading to a possible overestimation of
benefits
Leading to a possible underestimation of
benefits
With an unclear effect
METIS &
PRIMES/IEM
The baseline assumes current practices for a number
of market design related measures and policies, not
considering their possible evolution and the expansion
of existing initiatives.
As the situation is very unclear how these will advance
in the coming years, and since modelling requires a
specific assumption for each of these measures, it was
decided for these cases (e.g. DR participation in the
markets) to reflect a more pessimistic view, where
only few advancements are made. In this respect the
costs of the baseline are quite likely overestimated.
The detrimental effects of capacity mechanisms or
support schemes for RES E to the efficiency of the
electricity market operation over the various time
frames, as well as the external costs to the power
system (in relation to the energy market), were not
considered.
Still these are touched in Problem Area II and the
RED II impact assessment, as well as strong
indication on the impacts of RES E subsidies can be
deduced by the effect of the removal of priority
dispatch for biomass plants.
The softer approach used for the modelling of
priority dispatch of variable RES E (wind, solar)
underestimates the relevant cost of the baseline
scenario. Similarly for the balancing responsibility,
where H-2 forecasts for RES E are used, even when
balance responsibility is not assumed to apply to
them.
METIS did not model CHP and small scale RES E
separately, which would further enhance the impacts
of priority dispatch, currently assessed only for
biomass.
Modelling of the day-ahead and reserve procurement is
based on the so-called co-optimization of energy and
reserves. This approach was the one implemented for
simplicity and transparency. At the same time though it
does lead to the optimal scheduling of units. This on one
hand underestimates the costs of the baseline (in the case
of METIS), but at the same time possibly over-estimates
the benefits of the policy options.
Still overall the specific choice should not be considered
pivotal. Well-designed markets should lead to the same
efficient operation of the power system. Liquid intraday
and balancing markets should optimize operation and
resolve possible infeasibility issues resulting from the DA
schedule.
METIS
The yearly dimensioning and procurement of reserves
overestimates the cost of current practices, not even
considering their possible evolution, based on which
are very likely to be brought even closer to real time in
the coming years.
This is partially compensated by assuming that
dimensioning is performed based on the more accurate
probabilistic approach (despite currently performed in
many Member States based on the deterministic one).
Also by the fact that in all sub-options dimensioning
of mFRR and FCR does not vary (thus no benefits are
reported for this).
The issue of the limited liquidity currently observed
in intraday and balancing markets is not captured in
the modelling. Thus METIS assumed that markets
would be liquid in 2030, which may very well be
indeed the case without any policy action. Note
though that in certain Member States these markets
may not even exist today,
Continuous intraday trading was modelled as consecutive
hourly implicit auctions.
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Tool
Concerned
Main Modelling Limitations
Leading to a possible overestimation of
benefits
Leading to a possible underestimation of
benefits
With an unclear effect
METIS
Even in the baseline, interconnector capacity is
assumed to be allocated and used relatively
efficiently.
Moreover the absence of network modelling implied
that all relevant (and in many cases significant) costs
were not considered, especially related to internal
congestion (within Member States).
The assumed effect of the measures on the interconnector
capacities (i.e. the increase of NTC capacities) for the
various options was performed in a stylized manner. It was
based on very rough estimations due to the significant lack
of relevant data.
METIS
DR was modelled as if participating only in
balancing markets and reserves, but not in day-ahead
/ intraday.
Benefits from load shifting or load reductions were
not assessed due to the lack of sufficient detailed
data.
A standard load profile was used for demand, based
on ENTSO-E's TYNDP 2016 assumptions. A
dynamic profile for demand and storage would better
capture the reactions of demand to market prices (and
the associated benefits).
Stylized modelling approach concerning costs of DR.
METIS
Competition issues, effects of nominations and
block-bids, as well as possible strategic behaviour of
the market participants were not considered. On the
contrary, perfect competition was assumed based on
marginal pricing.
PRIMES/IEM
& PRIMES/OM
Assumed bidding behaviour on behalf of market
participants was not considered very aggressive, with
the electricity price rarely reaching the price caps.
Modelling required a significant amount of inputs and
exogenous assumptions, e.g. on market behaviour etc.,
with data not necessarily available (generally, not just
publicly).Moreover significant amount of data (e.g.
detailed data on RR, nominations, technical details on the
transmission grid) were missing, so had to be estimated by
the modellers. Thus results are quite dependant on these
inputs. Still every effort was made to confirm assumptions
based on currently observed market operation data.
PRIMES/OM
The fact that the baseline does not capture the
possible overcapacity in the power markets, e.g. due
to existing CMs or RES E support schemes or due
The selection of the countries assumed to have a CM may
be influencing the results (in an uncertain direction). Each
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Tool
Concerned
Main Modelling Limitations
Leading to a possible overestimation of
benefits
Leading to a possible underestimation of
benefits
With an unclear effect
to unrealised forecasts of the market participants,
takes away part of the benefits that would be
realised from well-functioning markets (and CMs).
combination of countries could possibly lead to different
results.
For this reason a sensitivity was performed assuming the
existence of CMs for all countries, and then performing
the comparison of Options 2 and 3 in this context.
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Annex V: Evidence and external expertise used
The present impact assessment is based on a large body of material, all of which is
referenced in the footnotes. A number of studies have however been conducted mainly or
specifically for this impact assessment. These are listed and described further in the table
below.
The Commission (DG Competition) has also been conducting a sector inquiry into national
capacity mechanisms and organised Working Groups with Member States with a view to
help them implement the provisions in the EEAG related to capacity mechanisms and to
share experience in the design of capacity mechanisms38
.
38
http://ec.europa.eu/competition/sectors/energy/state_aid_to_secure_electricity_supply_en.html
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Study
Study serve to study/substantiate
impact of
Contractor Published
METIS
Study 12: Assessing Market Design
Options in 2030.
Assessing elements for upgrading the market
(all options under Problem Area I) with a focus
on the more efficient operation of the power
system:
- Removing Market Distortions
- Allocating interconnection capacity
across time frames
- Procurement and Sizing of Balancing
Reserves
Impacts of the participation of Distributed
Generation in the market
Modelling tool DG ENER/METIS
Consortium
To be published39
METIS
Study 04: Stakes of a common approach
for generation and system adequacy.
Assessing the benefits from a coordinated
approach in Generation and System Adequacy
Analysis
Modelling tool DG ENER/METIS
Consortium
To be published
METIS
Study 16: Weather-driven revenue
uncertainty for power producers and ways to
mitigate it .
Effect of weather related uncertainty to
revenues. Capacity savings due to cooperation.
CM coordination/cross-border participation.
Modelling tool DG ENER/METIS
Consortium
To be published
METIS
Technical Note T04: Methodology for the
integration of PRIMES scenarios into
METIS.
Technical note providing details on the
methodological approach followed with METIS.
METIS Consortium To be published
METIS
Technical note providing details on the
methodological approach followed with METIS.
METIS Consortium / Thema
Consulting
To be published
39
Once operational, the envisaged link is expected to be the following: https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis. Same applies for all METIS studies.
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Study
Study serve to study/substantiate
impact of
Contractor Published
Technical Note T05: METIS market module
configuration for Study S12 - Focus on day-
ahead, intraday and balancing markets.
"Methodology and results of modelling the
EU electricity market using the
PRIMES/IEM and PRIMES/OM models"
A. Assessing elements for upgrading the market
(main options under Problem Area I) with a
focus on the revenues for the market players,
including:
- Scarcity pricing
- Bidding Zones
B. Assessing investment incentives and the
need for coordination of CMs:
- Profitability of power generation
investments
Coordination of CMs
NTUA To be published
Electricity Market Functioning: Current
Distortions, and How to Model Their
Removal
Impact removing market distortions:
- Identifying market distortions
Providing data input and support for the
modelling
COWI / Thema / NTUA To be published
Framework for cross-border participation in
capacity mechanisms
CM cross-border arrangements COWI/Thema/NTUA To be published
Transmission tariffs and Congestion income
policies
Options for locational signals/regulatory
framework IC construction
Trinomics To be published
Integration of electricity balancing markets
and regional procurement of balancing
reserves
Main study supporting Balancing Guidelines
IA. For MDI: regional sizing and procurement
balancing reserves40
COWI/Artelys To be published
40
Examines in more detail issues that are going to be examined also on METIS Study S12.
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Study
Study serve to study/substantiate
impact of
Contractor Published
Impact Assessment support Study on
downstream flexibility, demand response
and smart metering
Costs and benefits of measures to remove
market barriers to demand response and make
dynamic price tariffs more accessible
COWI / ECOFYS / THEMA /
VITO
To be published
Study on future European electricity system
operation Future model TSO collaboration Ecorys, DNV-GL,ECN
https://ec.europa.eu/energy/sites/ener/files/documents/
15-
3071%20DNV%20GL%20report%20Options%20for
%20future%20System%20Operation.pdf
System adequacy assessment Methodology for system adequacy assessments JRC To be published
Identification of Appropriate Generation
and System Adequacy Standards for the
Internal Electricity Market
System adequacy standards practises and
methods
Mercados, E-bridge, ref4e
https://ec.europa.eu/energy/sites/ener/files/documents/
Generation%20adequacy%20Final%20Report_for%2
0publication.pdf
Impact assessment support study on:
“Policies for DSOs, Distribution Tariffs and
Data Handling”
Cost and benefits of different options
concerning DSO roles, distribution network
tariffs, data handling models
Copenhagen Economics, and VVA To be published
Second Consumer Market Study on the
functioning of retail electricity markets for
consumers in the EU
Billing information; contract exit fees; price
comparison tools; disclosure and guarantees of
origin
Ipsos, London Economics, and
Deloitte
To be published
National policies on security of electricity
supply
Review of current national rules and practices
relating to risk preparedness in the area of
security of electricity supply
VVA Consulting & Spark
https://ec.europa.eu/energy/sites/ener/files/documents/
DG%20ENER%20Risk%20preparedness%20final%2
0report%20May2016.pdf
Measures to protect vulnerable consumers
in the energy sector: an assessment of
disconnection safeguards, social tariffs and
financial transfers
Removing market distortions by phasing-out
regulated prices
Appraisal of disconnection safeguards across
the EU.
INSIGHT_E To be published
Energy poverty and vulnerable consumers
in the energy sector across the EU: analysis
of policies and measures
Review of measures to protect energy poor and
vulnerable consumers
INSIGHT_E
https://ec.europa.eu/energy/sites/ener/files/documents/
INSIGHT_E_Energy%20Poverty%20-
%20Main%20Report_FINAL.pdf
Selecting indicators to measure energy
poverty
Review, appraisal and computation of indicators
to measure energy poverty
Trinomics, University College
London, and 7Seven
https://ec.europa.eu/energy/sites/ener/files/documents/
Selecting%20Indicators%20to%20Measure%20Energ
y%20Poverty.pdf
Fuel poverty in the European Union: a
concept in need of definition?
Critical assessment of the pros and cons of an
energy poverty definition at the EU level
Harriet Thomson, Carolyn Snell
and Christine Liddell
http://extra.shu.ac.uk/ppp-online/wp-
content/uploads/2016/04/fuel-poverty-european-
union.pdf
The role of DSOs in a Smart Grid
environment
Assessment of the future role of DSOs in
specific activities
ECN & Ecorys
https://ec.europa.eu/energy/sites/ener/files/documents/
20140423_dso_smartgrid.pdf
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Study
Study serve to study/substantiate
impact of
Contractor Published
Study on the effective integration of
Distributed Energy Resources for providing
flexibility to the electricity system
Assessment of distributed energy resources and
their effectiveness in providing flexibility to the
energy system
PwC, Sweco, Ecofys, Tractebel
https://ec.europa.eu/energy/sites/ener/files/documents/
5469759000%20Effective%20integration%20of%20
DER%20Final%20ver%202_6%20April%202015.pdf
From Distribution Networks to Smart
Distribution Systems: Rethinking the
Regulation of European Electricity DSOs
Assessment of the DSO role in the context of
four regulatory areas including remuneration,
network tariff structure and DSO activities
THINK
http://www.eui.eu/projects/think/documents/thinktopi
c/topic12digital.pdf
Options on handling Smart Grids Data
Description of different data handling options
for smart grids
EC Smart Grids Task Force
https://ec.europa.eu/energy/sites/ener/files/documents/
xpert_group3_first_year_report.pdf
Regulatory Recommendations for the
Deployment of Flexibility
Description of the flexibility context,
commercial and regulatory arrangements,
incentives for the development of flexibility,
policy recommendations
EC Smart Grids Task Force
https://ec.europa.eu/energy/sites/ener/files/documents/
EG3%20Final%20-%20January%202015.pdf
Identifying energy efficiency improvements
and saving potential in energy networks and
demand response
Analysis of different options for improving
efficiency in energy networks according to
Article 15 of the EED
Tractebel, Ecofys
https://ec.europa.eu/energy/sites/ener/files/documents/
GRIDEE_4NT_364174_000_01_TOTALDOC%20-
%2018-1-2016.pdf
Study on tariff design for distribution
systems
Benchmarking of different distribution tariff
structures and levels for electricity and gas
across EU
AF Mercados, refE, Indra
https://ec.europa.eu/energy/sites/ener/files/documents/
20150313%20Tariff%20report%20fina_revREF-
E.PDF
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Annex VI: Evaluation
The evaluation is presented as a self-standing document.
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Annex VII: Overview of electricity network codes and guidelines
This annex provides an overview of electricity network codes and guidelines adopted or
envisaged under Articles 6, 8 and 18 of the Electricity Regulation as well as a brief
description to the present initiative, if any.
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Electricity network codes
and guidelines adopted
or envisaged under
Articles 6, 8 and 18 of the
Electricity Regulation
State of play Brief description of contents
I
Link to MD
Commission Regulation
establishing a Guideline on
capacity allocation and
congestion management
Adopted on 24 July
2015
Legal implementation of day-ahead
and intraday market coupling, flow-
based capacity calculation
Linked to short-term
markets
For more details, see
Annex 2.2
Commission Regulation
establishing a Network code on
requirements for grid
connection of generators
Adopted on 14 April
2016
Defines the necessary technical
capabilities of generators in order to
contribute to system safety and to
create a level playing field.
No direct link with MD
Commission Regulation
establishing a Network Code on
High Voltage Direct Current
Connections and DC-connected
Power Park Modules
Adopted on 26 August
2016
Technical connection rules for
HVDC lines, e.g. used for
connections of offshore wind farms
No direct link with MD
Commission Regulation
establishing a Network code on
demand connection
Adopted on 17 August
2016
Defines the necessary technical
specifications of demand units
connected to a grid and DSOs in
order to contribute to system safety
and to create a level playing field.
Link to demand response
and to measures on
ancillary services For
more details, see Annex
3.1
Commission Regulation
establishing a Guideline on
Forward Capacity Allocation
Adopted on 26
September 2016
Creation of hedging opportunities
for the electricity market; important
to facilitate cross-border trade;
capacity to be allocated through
auctions on a central booking
platform; harmonisation of capacity
products
Link to short-term
markets, scarcity pricing
and locational signals.
See Annexes 2.2, 4.1,
4.2
Commission Regulation
establishing a Guideline on
electricity transmission System
Operation
Text voted favourably
by MS on 4 May
Target date for
launching scrutiny:
December 2016
Rules to react to system incidents
(TSO interaction when the system
goes beyond acceptable operational
ranges)
Creation of a framework for TSO
cooperation in the preparation of
system operation (i.e. planning
ahead of real time).
Guidance for how TSOs should
create a framework for keeping
system frequency within safe
operational ranges
Linked to TSO
cooperation in the
planning and operation
of transmission systems.
For more details, see
Annex 2.3
Draft Commission Regulation
establishing a Guideline on
Electricity Balancing
('Balancing Guideline')
Target for vote in
comitology: by end
2016
First step to the development of
common merit order lists for the
activation of balancing energy and
the start of a harmonisation of
balancing products.
Linked to procurement
rules and sizing of
balancing reserves.
For more details, see
Annex 2.1
Draft Commission Regulation
establishing a Network code on
Emergency and Restoration
Target for vote in
comitology: first
quarter 2017
Defines requirements of the plans to
be adopted by TSOs concerning
procedures to be followed when
blackouts happen
Linked to security of
supply measures.
For more details, see
Annex 6
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Annex VIII: Summary tables of options for detailed measures assessed
under each main option
The tables provided here reflect the in-depth assessment made of the options for detailed
measures described in the Annexes to the impact assessment Chapter 1.1 through to 7.6
The manner in which they correspond to the main options assessed in the present document is
set out in Table 6, Table 7, Table 8 and Table 9 in the present document
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Measures assessed under Problem Area 1, Option 1(a): level playing field amongst participants and resources
Priority access and dispatch
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain
rules allowing priority
dispatch and priority
access for RES,
indigenous fuels and
CHP.
Abolish priority dispatch and priority
access
This option would generally require full
merit order dispatch for all technologies,
including RES E, indigenous fuels such as
coal, and CHP. It would ensure optimum
use of the available network in case of
network congestion.
Priority dispatch and/or priority access only for emerging
technologies and/or for very small plants:
This option would entail maintaining priority dispatch
and/or priority access only for small plants or emerging
technologies. This could be limited to emerging RES E
technologies, or also include emerging conventional
technologies, such as CCS or very small CHP.
Abolish priority dispatch and introduce clear
curtailment and re-dispatch rules to replace
priority access.
This option can be combined with Option 2,
maintaining priority dispatch/access only for
emerging technologies and/or for very small
plants
Pros
Lowest political
resistance
Efficient use of resources, clearly
distinguishes market-based use of
capacities and potentially subsidy-based
installation of capacities, making subsidies
transparent.
Certain emerging technologies require a minimum number
of running hours to gather experiences. Certain small
generators are currently not active on the wholesale market.
In some cases, abolishing priority dispatch could thus bring
significant challenges for implementation. Maintaining also
priority access for these generators further facilitates their
operation.
As Option 1, but also resolves other causes for
lack of market transparency and discrimination
potential. It also addresses concerns that
abolishing priority dispatch and priority access
could result in negative discrimination for
renewable technologies.
Cons
Politically, it may be criticized that
subsidized resources are not always used if
there are lower operating cost alternatives.
Adds uncertainty to the expected revenue
stream, particularly for high variable cost
generation.
Same as Option 1, but with less concerns about blocking
potential for trying out technological developments and
creating administrative effort for small installations.
Especially as regards small installations, this could however
result in significant loss of market efficiency if large shares
of consumption were to be covered by small installations.
Legal clarity to ensure full compensation and
non-discriminatory curtailment may be
challenging to establish. Unless full
compensation and non-discrimination is
ensured, priority grid access may remain
necessary also after the abolishment of priority
dispatch.
Most suitable: Option 3. Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to actively
participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should be
combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or emerging
technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.
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Regulatory exemptions from balancing responsibility
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus
ensuring that the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances caused.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain the status
quo, expressly requiring financial
balancing responsibility only
under the state aid guidelines
which allow for some exceptions.
Full balancing responsibility for all
parties
Each entity selling electricity on the
market has to be a balancing responsible
party and pay for imbalances caused.
Balancing responsibility with exemption
possibilities for emerging technologies
and/or small installations
This would build on the EEAG.
Balancing responsibility, but possibility to
delegate
This would allow market parties to delegate the
balancing responsibility to third parties.
This option can be combined with the other
options.
Pros
Lowest political resistance Costs get allocated to those causing them.
By creating incentives to be balanced,
system stability is increased and the need
for reserves and TSO interventions gets
reduced. Incentives to improve e.g.
weather forecasts are created.
This could allow shielding emerging
technologies or small installations from the
technical and administrative effort and
financial risk related to balancing
responsibility.
The impact of this option would depend on the
scope and conditions of this delegation. A
delegation on the basis of private agreements, with
full financial compensation to the party accepting
the balancing responsibility (e.g. an aggregator)
generally keeps incentives intact.
Cons
Financial risks resulting from the
operation of variable power generation
(notably wind and solar power) are
increased.
Shielding from balancing responsibilities
creates serious concerns that wrong
incentives reduce system stability and
endanger market functioning. It can
increase reserve needs, the costs of which
are partly socialized. This is particularly
relevant if those exemptions cover a
significant part of the market (e.g. a high
number of small RES E generators).
The impact of this option would depend on the
scope and conditions of this delegation. A full and
non-compensated delegation of risks e.g. to a
regulated entity or the incumbent effectively
eliminates the necessary incentives. Delegation to
the incumbent also results in further increases to
market dominance.
Most suitable: Option 2 combined with the possibility for delegation based on freely negotiated agreements.
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RES E access to provision of non-frequency ancillary services
Objective: transparent, non-discriminatory and market based framework for non-frequency ancillary services
Option 0 Option 1 Option 2
BAU
Different requirements, awarding procedures and
remuneration schemes are currently used across MS.
Rules and procedures are often tailored to conventional
generators and do not always abide to transparency,
non-discrimination. However increased penetration of
RES displaces conventional generation and reduces the
supply of these services.
Description
Set out EU rules for a transparent, non-discriminatory and
market based framework to the provision of non-frequency
ancillary services that allows different market players
/technology providers to compete on a level playing field.
Description
Set out broad guidelines and principles for MS for the adoption of
transparent, non-discriminatory and market based framework to the
provision of non-frequency ancillary services.
Stronger enforcement
Provisions containing reference to transparency, non-
discrimination are contained in the Third Package.
However, there is nothing specific to the context of non-
frequency ancillary services.
Pro
Accelerate adoption in MS of provisions that facilitate the
participation of RES E to ancillary services as technical
capabilities of RES E and other new technologies is available,
main hurdle is regulatory framework.
Clear regulatory landscape can trigger new revenue streams
and business models for generation assets.
Pro
Sets the general direction and boundaries for MS without being too
prescriptive.
Allows gradual phase-in of services based on local/regional needs
and best practices.
Con
Resistance from MS and national authorities/operators due to
the local/regional character of non-frequency ancillary
services provided.
Little previous experience of best practices and unclear how
to monitor these services at DSO level where most RES E is
connected.
Con
Possibility of uneven regulatory and therefore market developments
depending on how fast MS act. This creates uncertain prospects for
businesses slowing down RES E penetration.
Most suitable option(s): Option 2 is best suited at the current stage of development of the internal electricity market. Ancillary services are currently procured and sometimes used in very
different manners in different Member States, Furthermore, new services are being developped and new market actors (e.g. batteries) are quickly developing. Setting out detailed rules required
for full harmonisation would thus preclude unknown future developments in this area, which currently is subject to almost no harmonisation.
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Measures assessed under Problem Area 1, Option 1(b) Strengthening short-term markets
Reserves sizing and procurement
Objective: define areas wider than national borders for sizing and procurement of balancing reserves
Option 0: business as usual Option 1: national sizing and
procurement of balancing reserves on
daily basis
Option 2: regional sizing and procurement
of balancing reserves
Option 3: European sizing and procurement
of balancing reserves
Description
The baseline scenario consists of a
smooth implementation of the
Balancing Guideline. Existing on-
going experiences will remain and
be free to develop further, if so
decided. However, sizing and
procurement of balancing reserves
will mainly remain national,
frequency of procurement as
foreseen in the Balancing Guideline.
Active participation in the
Balancing Stakeholder Group could
ensure stronger enforcement of the
Balancing Guideline.
This option consists in developing a
binding regulation that would require
TSOs to size their balancing reserves on
daily probablistic methodologies. Daily
calculation allows procuring lower
balancing reserves and, together with
daily procurement, enables participation
of renewable energy sources and
demand response.
This option foressees separate
procurement of all type of reserves
between upward (i.e. increasing power
output) and downward (i.e. reducing
power output; offering demand
reduction) products.
This option involves the setup of a binding
regulation requiring TSOs to use regional
platforms for the procurement of balancing
reserves. Therefore this option foresees the
implementation of an optimisation process for
the allocation of transmission capacity between
energy and balancing markets, which then
implies procuring reserves only a day ahead of
real time.
This option would result in a higher level of
coordination betwRReen European TSOs, but
still relies on the concept of local
responsibilities of individual balancing zones
and remains compatible with current
operational security principles.
This option would have a major impact on the
current design of system operation procedures
and responsibilities and current operational
security principles. A supranational
independent system operator ('EU ISO') would
be responsible for sizing and procuring
balancing reserves, cooperating with national
TSOs. This would enable TSOs to reduce the
security margin on transmission lines, thus
offering more cross-zonal transmission
capacity to the market and allowing for
additional cross-zonal exchanges and sharing
of balancing capacity.
Pros
Optimal national sizing and
procurement of balancing reserves.
Regional areas for sizing and procurement of
balancing reserves.
Single European balancing zone.
Cons
No cross-border optimisation of
balancing reserves.
Balancing zones still based on national borders
but cross-border optimisation possible.
Extensive standardisation through replacement
of national systems, difficult and costly
implementation.
Most suitable: Option 2. Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the physical
topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the preferred
option.
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Removing distortions for liquid short-term markets
Objective: to remove any barriers that exist to liquid short-term markets, specifically in the intraday timeframe, and to ensure distortions are minimised.
Option 0 Option 1 Option 2
Description
Business as usual
Local markets mostly unregulated, allowing for national
differences, but affected by the arrangements for cross-
border intraday and day-ahead market coupling.
Stronger enforcement and volunatry cooperation
There is limited legislation to enforce and voluntary
cooperation would not provide certainty to the market
Fully harmonise all arrangements in local
markets.
Selected harmonisation, specifically on issues relating to gate closure
times and products.
Pros
Simplest approach, and allows the cross-border
arrangements to affect local market arrangements. Likely to
see a degree of harmonisation over time.
Would minimise distortions, with very limited
opportunity for deviation.
Targets issues that are particularly important for maximising liquidity
of short-term markets and allows for participation of demand response
and small scale RES.
Cons
Differences in national markets will remain that can act as a
barrier.
Extremely complex; even the cross-border
arrangements have not yet been decided and
need significant work from experts.
Additional benefit unclear.
May still be difficult to implement in some Member States with
implication on how the system is managed – central dispatch systems
could, in particular, be impacted by shorter gate closure time.
Most suitable: Option 2 – Provides a proportionate response targeting those issues of most relevance.
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Improving the coordination of Transmission System Operation
Objective: Stronger coordination of Transmission System Operation at a regional level
Option 0 Option 1 Option 2 Option 3
Description
BAU
Limit the TSO coordination efforts to the
implementation of the new Guideline on
Transmission System Operation (voted at the
Electricity Cross Border Committee in May 2016
and to be adopted by end-2016) which mandates the
creation of Regional Security Coordinators (RSCs)
covering the whole Europe to perform five relevant
tasks at regional level as a service provider to
national TSOs.
Enhance the current set up of existing RSC by
creating Regional Operational Centers (ROCs),
centralising some additional functions at regional
level over relevant geographical areas and
delineating competences between ROCs and
national TSOs.
Go beyond the establishment of ROCs
that coexist with national TSOs and
consider the creation of Regional
Independent System Operators that can
fully take over system operation at
regional level. Transmission
ownership would remain in the hands
of national TSOs.
Create a European-wide
Independent System Operator
that can take over system
operation at EU-wide level.
Transmission ownership would
remain in the hands of national
TSOs.
Pros
Lowest political resistance. Enlarged scope of functions assuming those tasks
where centralization at regional level could bring
benefits
A limited number (5 max) of well-defined regions,
covering the whole EU, based on the grid topology
that can play an effective coordination role. One
ROC will perform all functions for a given region.
Enhanced cooperative decsion-making with a
possibility to entrust ROCs with decision making
competences on a number of issues.
Improved system and market operation
leading to optimal results including
optimized infrastructure development,
market facilitation and use of existing
infrastructure, secure real time
operation.
Seamless and efficient system
and market operation.
Cons
Suboptimal in the medium and long-term. Could find political resistance towards
regionalisation. If key elements/geography are not
clearly enshrined in legislation, it might lead to a
suboptimal outcome closer to Option 0.
Politically challenging. While this
option would ultimately lead to an
enhanced system operation and might
not be discarded in the future, it is not
considered proportionate at this stage
to move directly to this option.
Extremely challenging
politically. The implications of
such an option would need to
be carefully assessed. It is
questionable whether, at least
at this stage, it would be
proportionate to take this step.
Most suitable option(s): Option 1 (Option 2 and Option 3 constitute the long-term vision)
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Measures assessed under Problem Area 1,Option 1(c); Pulling demand response and distributed resources into the market
Unlocking demand side response
Objective: Unlock the full potential of Demand Response
Option O: BAU Option 1: Give consumers access to
technologies that allow them to
participate in price based Demand
Response schemes
Option 2: as Option 1 but also fully enable
incentive based Demand Response
Option 3: mandatory smart meter roll out and
full EU framework for incentive based demand
response
Stronger enforcement of existing
legislation that requires MS to roll
out smart meters if a cost-benefit
analysis is positive and to ensure that
demand side resources can
participate alongside supply in retail
and wholesale markets
Give each consumer the right to request the
installation of, or the upgrade to, a smart
meter with all 10 recommended
functionalities.
Give the right to every consumer to request
a dynamic electricity pricing contract.
In addition to measures described under Option
1, grant consumers access to electricity markets
through their supplier or through third parties
(e.g. independent aggregators) to trade their
flexibility. This requires the definition of EU
wide principles concerning demand response
and flexibility services.
Mandatory roll out of smart meters with full
functionalities to 80% of consumers by 2025
Fully harmonised rules on demand response
including rules on penalties and compensation
payments.
No new legislative intervention. This option will give every consumer the
right and the means (fit-for-purpose smart
meter and dynamic pricing contract) to fully
engage in price based DR if (s)he wishes to
do so.
This option will allow price and incentive
based DR as well as flexibility services to
further develop across the EU. Common
principles for incentive based DR will also
facilitate the opening of balancing markets for
cross-border trade.
This guarantees that 80% of consumers across the
EU have access to fully functional smart meters by
2025 and hence can fully participate in price based
DR and that market barriers for incentive based
DR are removed in all MS.
Roll out of smart meters will remain
limited to those MS that have a
positive cost/benefit analysis.
In many MS market barriers for
demand response may not be fully
removed and DR will not deliver to
its potential.
Roll out of smart meters on a per customer
basis will not allow reaping in full system-
wide benefits, or benefits of economies of
scale (reduced roll out costs)
Incentive based demand response will not
develop across Europe.
As for Option 1, access to smart meters and
hence to price based DR will remain limited.
Member States will continue to have freedom
to design detailed market rules that may hinder
the full development of Demand Response.
It ignores the fact that in 11 MS the overall costs
of a large-scale roll out exceed the benefits and
hence that in those MS a full roll out is not
economically viable under current conditions.
Fully harmonised rules on demand response
cannot take into account national differences in
how e.g. balancing markets are organised and may
lead to suboptimal solutions.
Most suitable option(s): Option 2. Only the second option is suited to untap the potential of demand response and hence reduce overall system costs while respecting subsidiarity
principles. The third option is likely to deliver the full potential of demand response but may do so at a too high cost at least in those Member States where the roll out of smart meters is not
yet economically viable. Options zero and one are not likely to have a relevant impact on the development of demand response and reduction of electricity system cost.
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Distribution networks
Objective: Enable DSOs to locally manage challenges of energy transition in a cost-efficient and sustainable way, without distorting the market.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding on the detail
tasks of DSOs.
- Allow and incentivize DSOs to acquire flexibility services from distributed
energy resources.
- Establish specific conditions under which DSOs should use flexibility, and
ensure the neutrality of DSOs when interacting with the market or consumers.
- Clarify the role of DSOs only in specific tasks such as data management, the
ownership and operation of local storage and electric vehicle charging
infrastructure.
- Establish cooperation between DSOs and TSOs on specific areas, alongside the
creation of a single European DSO entity.
- Allow DSOs to use flexibility under the conditions set in
Option 1.
- Define specific set of tasks (allowed and not allowed) for
DSOs across EU.
- Enforce existing unbundling rules also to DSOs with less
than 100,000 customers (small DSOs).
Pro
Current framework gives more
flexibility to Member States to
accommodate local conditions in their
national measures.
Pro
Use of flexible resources by DSOs will support integration of RES E in distribution
grids in a cost-efficient way.
Measures which ensure neutrality of DSOs and will guarantee that operators do not
take advantage of their monopolistic position in the market.
Pro
Stricter unbundling rules would possibly enhance competition
in distribution systems which are currently exempted from
unbundling requirements.
Under certain condition, stricter unbundling rules would also
be a more robust way to minimizing DSO conflicts of interest
given the broad range of changes to the electricity system, and
the difficulty of anticipating how these changes could lead to
market distortions.
Con
Not all Member States are integrating
required changes in order to support
EU internal energy market and targets.
Con
Effectiveness of measures may still depend on remuneration of DSOs and regulatory
framework at national level.
Con
Uniform unbundling rules across EU would have
disproportionate effects especially for small DSOs.
Possible impacts in terms of ownership, financing and
effectiveness of small DSOs.
A uniform set of tasks for DSOs would not accommodate local
market conditions across EU and different distribution
structures.
Most suitable option(s): Option 1 is the preferred option as it enhances the role of DSOs as active operators and ensures their neutrality without resulting in excess administrative costs.
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Remuneration of DSOs
Objective: A performance-based remuneration framework which incentivize DSOs to increase efficiencies in planning and innovative operation of their networks.
Option: O Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible on deciding on the detailed
framework for remuneration of DSOs.
- Put in place key EU-wide principles and guidance regarding the remuneration of
DSOs, including flexibility services in the cost-base and incentivising efficient
operation and planning of grids.
- Require DSO to prepare and implement multi-annual development plans, and
coordinate with TSOs on such multi-annual development plans.
- Require NRAs to periodically publish a set of common EU performance indicators
that enable the comparison of DSOs performance and the fairness of distribution
tariffs.
- Fully harmonize remuneration methodologies for all
DSOs at EU level.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Performance based remuneration will incentivise DSOs to become more cost-efficient
and offer better quality services.
It would support integration of RES E and EU targets.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards regulatory
schemes which incentivize DSOs and
raise efficiencies.
Con
Detail implementation will still have to be realized at Member State level, which may
reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO remuneration schemes
would not meet the specificities of different distribution
systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective remuneration schemes and enhancing transparency
requirements
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Distribution network tariffs
Objective: Distribution tariffs that send accurate price signals to grid users and aim to fair allocation of distribution network costs.
Option: 0 Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible on deciding on the detailed
distribution tariffs.
- Impose on NRAs more detailed transparency and comparability requirements
for distribution tariffs methodologies.
- Put in place EU-wide principles and guidance which ensure fair, dynamic, time-
dependent distribution tariffs in order to facilitate the integration of distributed
energy resources and self-consumption.
- Harmonization of distribution tariffs across EU; fully
harmonize distribution tariff structures at EU level for all
EU DSOs, through concrete requirements for NRAs on
tariff setting.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Principles regarding network tariffs will increase efficient use of the system and
ensure a fairer allocation of network costs.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards distribution
network tariffs which effectively
allocate costs and accommodate EU
policies.
Con
Detail implementation will still have to be realized at Member State level, which
may reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO structures would not meet
the specificities of different distribution systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective distribution network tariffs and enhancing transparency
requirements
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Improving the institutional framework
Objective: To adapt the Institutional Framework, in particular ACER's decision-making powers and internal decision-making to the reality of integrated regional markets and the
proposals of the Market Design Initiative, as well as to address the existing and anticipated regulatory gaps in the energy market.
Option 0 Option 1 Option 2
Description
Maintain status quo, taking into account that the implementation
of network codes would bring certain small scale adjustments.
However, the EU institutional framework would continue to be
based on the complementarity of regulation at national and EU-
level.
Adapting the institutional framework to the new
realities of the electricity system and to the
resulting need for additional regional cooperation
as well as to addressing existing and anticipated
regulatory gaps in the energy market.
Providing for more centralised institutional structures with
additional powers and/or responsibilities for the involved
entities.
Pros
Lowest political resistance. Addresses the shortcomings identified and
provides a pragmatic and flexible approach by
combining bottom-up initiatives and top-down
steering of the regulatory oversight.
Addresses the shortcomings identified with limited
coordination requirements for institutional actors.
Cons
The implementation of the Third Package and network codes is
not sufficient to overcome existing shortcomings of the
institutional framework.
Requires strong coordination efforts between all
involved institutional actors.
Significant changes to established institutional processes with
the greatest financial impact and highest political resistance.
Most suitable: Option 1, as it adapts the institutional framework to the new realities of the electricity system by adopting a pragmatic approach in combining bottom-up initiatives and top-
down steering of the regulatory oversight.
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Measures assessed under Problem Area 2, Option 2(1); Improved energy-only market without CMs)
Removing price caps
Objective: to ensure that prices in wholesale markets are not prevented from reflecting scarcity and the value that society places on energy.
Option 0: Business as usual Option 1: Eliminate all price caps Option 2: Create obligation to set price caps, where they
exist, at VoLL
Description
Existing regulations already require harmonisation of
maximum (and minimum) clearing prices in all price zones to
a level which takes "into account an estimation of the value of
lost load".
Stronger enforcement/non-regulatory approach
Enforceability of "into account an estimation of the value of
lost load" in the CACM Guideline is not strong. Enforcement
action is unlikely to be successful or expedient. Relying on
stronger enforcement would leave considerable more legal
uncertainty to market participants than clarifying the legal
framework directly.
Voluntary cooperation would not provide the market with
sufficient confidence that governments would not step in
restrict prices in the event of scarcity
Eliminate price caps altogether for balancing,
intraday and day-ahead markets.
Removes barriers for scarcity pricing Avoids setting
of VoLL (for the purpose of removing negative
effects of price caps).
Reinforced requirement to set price limits taking "into account
an estimation of the value of lost load"
Allow for technical price limits as part of market coupling,
provided they do not prevent prices rising to VoLL.
Establish requirements to minimise implicit price caps.
Pros
Simple to implement – leaves administration to technical
implementation of the CACM Guideline.
Measure simple to implement; unequivocally and
creates legal certainty.
Compatible with already existing requirement to set price limit,
as provided for undert the CACM regulation, provides concrete
legal clarity
Cons
Difficult to enforce; no clarity on how such clearing prices will
be harmonised. Does not prevent price caps being
implemented by other means.
Can be considered as non-proportional; could add
significant risk to market participants and power
exchanges if there are no limits.
VoLL, whilst a useful concept, is difficult to set in practice. A
multitude of approaches exist and at least some degree of
harmonisation will be required.
Most suitable: Option 2 - this provides a proportionate response to the issue –, it would allow for technical limits as part of market coupling and this should not restrict the markets ability
to generate prices that reflect scarcity..
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Improving locational price signals
Objective: The objective is to have in place a robust process for deciding on the structure of locational price signals for investment and dispatch decisions in the EU electricity
wholesale market.
Option 0 Option 1 Option 2 Option 3
Description
Business as Usual – decision on bidding
zone configuration left to the arrangements
defined under the CACM Guideline or
voluntary cooperation, which has, to date,
retained the status quo .
Move to a nodal pricing system. Introduce locational signals by new means,
i.e. through transmission tariffs.
Improve currently existing the CACM
Guideline procedure for reviewing bidding
zones and introducing supranational
decision-making, e.g. through ACER.
This would be coupled with a strengthened
requirement to avoid the reduction of cross-
zonal capcity in order to resolve internal
congestions.
Pros
Approach already agreed. Theoretically, nodal pricing is the most
optimal pricing system for electricity
markets and networks.
Would unlock alternative means to provide
locational signals for investment and
dispatch decisions.
This improvement will render revisions of
bidding zones a more technical decision.
It will also increase the available cross-
zonal capacity.
Cons
Risks maintenance of the status quo, and
therefore misses the opportunity to address
issues in the internal market.
Nodal pricing implies a complete,
fundamental overhaul of current grid
management and electricity trading
arrangements with very substantial
transition costs.
Incentives would be not be the result of
market signals (value of electricity) but cost
components set by regulatory intervention
of a potentially highly political nature.
Does not address the underlying difficulty of
introducing locational price zones, namely
the difficulties to arrive at decisions that
reflect congestion instead of political
borders.
Does not address a situation where the
results of the bidding zone review are sub-
optimal. I.e. this option only covers
procedural issues.
Most suitable: Option 3 – this option will rely on a pre-established process but improve the decision-making so that decisions take into account cross-border impact of bidding zone
configuration. Other options – e.g. tofundamentally change how locational signals are provided, would be dispropritionate.
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Minimise investment and dispatch distortions due to transmission tariff structure
Objective: to minimise distortions on investment and dispatch patterns created by different transmission tariffs regimes.
Option 0: Business as usual Option 1: Restrict charges on producers
(G-charges)
Option 2: Set clearer principles for transmission
charges
Option 3: Harmonisation
transmission tariffs
Description
This option would see the status quo
maintained, and transmission tariffs set
according to the requirements under
Directive 72 and the ITC regulation.
Stronger enforcement and voluntary
cooperation:
There is no stronger enforcement action to
be taken that would alone address the
objective. Voluntary cooperation would, in
part, be undertaken as part of
implementation of Option 2.
This option could see the prohibition of
transmission charges being levied on
generators based on the amount of energy
they generate (energy-based G-charges)
This option would see a requirement on ACER to
develop more concrete principles on the setting of
transmission tariffs, along with an elaboration of
exiting provisions in the electricity regulation
where appropriate.
Full harmonisation of
transmission tariffs.
Pros
Pros: Minimal change; likely to receive
some support for not taking any action in
the short-term.
Eliminating energy-based G-charges would
serve to limit distortionary effects on dispatch
of generation caused by transmission tariffs.
Social welfare benefits of approximately EUR
8 million per year. Would impact a minority
of Member States (6-8 depending on design).
Provides an opportunity to move in the right
direction whilst not risking taking the wrong
decisions or introducing inefficiencies because of
unknowns; consistent with a phased-approach;
could eliminate any potential distortions without
the need to mandate particular solutions; consistent
with the introduction of legally binding provisions
in the future, e.g. through implementing legislation.
Minimises distortion between
Member States on both
investment and dispatch;
creates a level-playing field.
Cons
In the longer-term, likely to be a drive to do
more and maintaining the status quo
unlikely to be attractive; risks of continued
divergence in national approaches.
Social welfare benefits relatively small –
could be outweighed by transitional costs in
the early years. Can be considered
'incomplete' as a number of other design
elements of transmission tariffs contribute to
distortionary effects.
Still leaves the door open for variation in national
approaches; will not resolve all potential issues.
Unlikely to a proportionate
response to the issues at this
stage; given the technicalities
involved, it could be more
appropriate to introduce such
measures as implementing
legislation in the future.
Most suitable option(s): Option 2 – aside from some high-level requirements, given the complexity of transmission charges, the precise modalities should be set-out as part of
implementing legislation in the future if and when appropriate. The value in Option 2 will be to set the path for the longer-term.
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Congestion income spending to increase cross-border capacity
Objective: The objective of any change should be to increase the amount of money spent on investments that maintain or increase available interconnection capacity
Option 0: Business as usual Option 1 Option 2 Option 3
Description
This option would see the current situation
maintained, i.e. that congestion income can be
used for (a) guaranteeing the actual
availability of allocated capacity or (b)
maintaining or increasing interconnection
capacities through network investments; and,
where they cannot be efficiently used for these
purposes, taken into account in the calculation
of tariffs.
Stronger enforcement: current rules do not
allow for stronger enforcement.
Voluntary cooperation: would offer no
certainty that the allocation of income would
change.
Further prescription on the use of
congestion income, subjecting its use on
anything other than (a) guaranteeing the
actual availability of allocated capacity or
(b) maintaining or increasing
interconnection capacities (i.e. allowing it
to be offset against tariffs) to harmonised
rules.
Require that any income not used for (a)
guaranteeing availability or (b)
maintaining or increasing interconnection
capacities flows into the Energy part of
CEF-E or its successor, to be spent on
relieving the biggest bottlenecks in the
European electricity system, as evidenced
by mature PCIs.
Transfer the responsibility of using the
revenues resulting from congestion and not
spent on either (a) guaranteeing availability
or (b) maintaining capacities to the
European Commission. De facto all
revenues are allocated to CEF-E or
successor funds to manage investments
which increase interconnection capacity.
Pros
Minimal disruption to the market; consumers
can benefit from tariff reductions – unclear
whether benefits of better channelling income
towards interconnection would provide more
benefits to consumers, given that it may offset
(at least in part) money spent on
interconnection from other sources.
More guarantee that income will be spent
on projects that increase or maintain
interconnection capacity and relieve the
most significant bottlenecks; could
provide around 35% extra spend; approach
reflects the EU-wider benefits of
electricity exchange through
interconnectors; can be linked to the PCI
process.
Guarantees that income will be spent on
projects that increase or maintain
interconnection capacity and relieve the
most important bottlenecks; could
provide up to 35% extra spend; approach
reflects the EU-wider benefits of
electricity exchange through
interconnectors; firm link with the PCI
process.
Best guarantee that income will be spent
on the biggest bottlenecks in the European
electricity system, ensuring the best deal
for European consumers in the longer run;
approach reflects the EU-wider benefits of
electricity exchange through
interconnectors; to be linked to the PCI
process.
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Cons
Missing a potentially significant source of
income which could be spent on
interconnection and removing the biggest
bottlenecks in the EU.
Restricts regulators in their tariff approval
process and of TSOs on congestion
income spending.
Additional reporting arrangements will be
necessary.
Requires stronger role of ACER.
Restricts regulators in their tariff approval
process and of TSOs on congestion
income spending.
Could mean that congestion income
accumulated from one border is spent on
a different border or different MS.
Additional reporting arrangements will be
necessary.
Requires stronger role of ACER.
Could prove complicated to set up such an
arrangement; could mean that congestion
income accumulated from one border is
spent on a different border or different MS.
Requires a decision to apportion generated
income to where needs are highest in
European system. Will face national
resistance.
Will require additional reporting
arrangements to be put in place.
Requires stronger role of ACER.
Most suitable option(s): Option 2 – provides additional funding towards project which benefit the EU internal market as a whole, while still allowing for national decision making in the
first instance. Considered the most proportionate response.
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Measures assessed under Problem Area 2, Option 2(2) CMs based on an EU-wide resource adequacy assessment
Improved resource adequacy methodology
Objective: Pan-European resource adequacy assessments
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
National decision makers would continue to
rely on purely national resource adequacy
assessments which might inadequately take
account of cross-border interdependencies.
Due to different national methodologies,
national assessments are difficult to
compare.
Binding EU rules requiring TSOs to
harmonise their methodologies for
calculating resource adequacy +
requiring MS to exclusively rely on them
when arguing for CMs.
Binding EU rules requiring ENTSO-E to
provide for a single methodology for
calculating resource adequacy +
requiring MS to exclusively rely on them
when arguing for CMs.
Binding EU rules requiring ENTSO-E to carry
out a single resource adequacy assessment for
the EU + requiring MS to exclusively rely on it
when arguing for CMs.
Pros
Stronger enforcement:
Commission would continue to face
difficulties to validate the assumptions
underlying national methodologies including
ensuing claims for Capacity Mechanisms
(CMs).
National resource adequacy assessments
would become more comparable.
In addition to benefits in Option 1, it
would make it easier to embark on the
single methodology.
In addition to benefits in Options 1 & 2, it would
make sure that the national puzzles neatly add up
to a European picture allowing for national/
regional/ European assessments.
Results are more consistent and comparable as
one entity (ENTSO-E) is running the same
model for each country.
Cons
Even in the presence of harmonised
methodologies national assessment
would not be able to provide a regional or
EU picture.
Even in the presence of a single
methodology, national assessments
would not be able to provide a regional or
EU picture.
National TSOs might be overcautious
and not take appropriately cross-border
interdependencies into account.
Difficult to coordinate the work as the
EU has 30+ TSOs.
It would potentially reduce the 'buy-in' from
national TSOs who might still be needed for
validating the results of ENTSO-E's work.
Most suitable option(s): Option 3 - this approach assesses best the capacity needs for resource adequacy and hence allows the Commission to effectively judge whether the proposed
introduction of resource adequacy measures in single Member States is justified.
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Cross-border operation of capacity mechanisms
Objective: Framework for cross-border participation in capacity mechanisms
Option 0 Option 1 Option 2
Description
Do nothing.
No European framework laying out the details of an effective cross-
border participation in capacity mechanisms. Member States are likely
to continue taking separate approaches to cross-border participation,
including setting up individual arrangements with neighbouring
markets.
Harmonised EU framework setting out procedures including roles
and responsibilities for the involved parties (e.g. resource
providers, regulators, TSOs) with a view to creating an effective
cross-border participation scheme.
Option 1 + EU framework harmonising
the main features of the capacity
mechanisms per category of
mechanism (e.g. for market-wide
capacity mechanisms, reserves, …).
Pros
Stronger enforcement
The Commission's Guidance on state interventions41
and the EEAG
require among others that such mechanisms are open and allow for the
participation of resources from across the borders. There is no reason to
believe that the EEAG framework is not enforced. To date, however,
there are not many practical examples of such cross-border schemes.
It would reduce complexity and the administrative impact for
market participants operating in more than one MS/bidding zone.
It would remove the need for each MS to design a separate
individual solution – and potentially reduce the need for bilateral
negotiations between TSOs and regulators.
It would preserve the properties of market coupling and ensure that
the distortions of uncoordinated national mechanisms are corrected
and internal market able to deliver the benefits to consumers.
In addition to benefits in Option 1, it
would facilitate the effective
participation of foreign capacity as it
would simplify the design challenge
and would probably increase overall
efficiency by simplifying the range of
rules market participants, regulators
and system operators have to
understand.
Cons
As the conclusion of individual cross-border arrangements depend on
the involved parties' willingness to cooperate it is likely that this option
will cement the current fragmentation of capacity mechanisms.
Arranging cross-border participation on individual basis is likely to
involve high transaction costs for all stakeholders (TSOs, regulators,
ressource providers).
It would be a cost for TSOs and regulators which would have to
agree on the rules and enforce them across the borders. These costs
would be lower than in Option 0 though.
In addition to the drawback of Option 1,
it would limit the choice of instruments.
Most suitable Option(s): Options 1 and 2
41
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf
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Options for measures assessed under Problem Area 3: a new legal framework for preventing and managing crises situations
Objective: Ensure a common and coordinated approach to electricity crisis prevention and management across Member States, whilst avoiding undue government intervention
Option 0: Do nothing Option 0+: Non-
regulatory
approach
Option 1: Common minimum EU
rules for prevention and crisis
management
Option 2: Common minimum EU rules plus regional
cooperation, building on Option 1
Option 3: Full
harmonisation and full
decision-making at regional
level, building on Option 2
- This option was
disregarded as no
means for enhanced
implementation of
the existing acquis
nor for enhanced
voluntary
cooperation were
identified
-
Assessments
Rare/extreme risks and
short-term risks related
to security of supply are
assessed from a national
perspective.
Risk identification &
assessment methods
differ across Member
States.
- - Member States to identify and assess
rare/extreme risks based on common
risk types.
-
ENTSO-E to identify cross-border electricity crisis
scenarios caused by rare/extreme risks, in a regional
context. Resulting crisis scenarios to be discussed in the
Electricity Coordination Group.
Common methodology to be followed for short-term risk
assessments (ENTSO-E Seasonal Outlooks and week-
ahead assessments of the RSCs).
All rare/extreme risks
undermining security of
supply assessed at the EU
level, which would be
prevailing over national
assessment.
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Plans
Member States take
measures to prevent and
prepare for electricity
crisis situations
focusing on national
approach, and without
sufficiently taking into
account cross-border
impacts.
No common approach
to risk prevention &
preparation (e.g., no
common rules on how
to tackle cybersecurity
risks).
a)
- - Member States to develop mandatory
national Risk Preparedness Plans
setting out who does what to prevent
and manage electricity crisis situations.
-
- Plans to be submitted to the
Commission and other Member States
for consultation.
-
- Plans need to respect common
minimum requirements. As regards
cybersecurity, specific guidance would
be developed.
Mandatory Risk Preparedness Plans including a national
and a regional part. The regional part should address
cross-border issues (such as joint crisis simulations, and
joint arrangements for how to deal with situations of
simultaneous crisis) and needs to be agreed by Member
States within a region.
Plans to be consulted with other Member States in each
region and submitted for prior consultation and
recommendations by the Electricity Coordination Group.
Member States to designate a 'competent authority' as
responsible body for coordination and cross-border
cooperation in crisis situations.
Development of a network code/guideline addressing
specific rules to be followed for the cybersecurity.
Extension of planning & cooperation obligations to
Energy Community partners.
Mandatory Regional Risk
Preparedness Plans, subject to
binding opinions from the
European Commission.
Detailed templates for the
plans to be followed.
A dedicated body would be
created to deal with
cybersecurity in the energy
sector.
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Crisis
management
Each Member State
takes measures in
reaction to crisis
situations based on its
own national rules and
technical TSO rules.
No co-ordination of
actions and measures
beyond the technical
(system operation)
level. In particular, there
are no rules on how to
coordinate actions in
simultaneous crisis
situations between
adjacent markets.
No systematic
information-sharing
(beyond the technical
level).
Minimum common rules on crisis
prevention and management (including
the management of simultaneous
electricity crisis) requiring Member
States to:
(i) not to unduly interference with
markets;
(ii) to offer assistance to others where
needed, subject to financial
compensation, and to;
(iii) inform neighbouring Member
States and the Commission, as of the
moment that there are serious
indications of an upcoming crisis and
during a crisis.
Minimum obligation as set out in Option 1.
Cooperation and assistance in crisis between Member
States, in particular simultaneous crisis situations, should
be agreed ex-ante; also agreements needed regarding
financial compensation. This also includes agreements on
where to shed load, when and to whom. Details of the
cooperation and assistance arrangements and resulting
compensation should be described in the Risk
Preparedness Plans.
Crisis is managed according to
the regional plans, including
regional load-shedding plans,
rules on customer
categorisation, a harmonized
definition of 'protected
customers' and a detailed
'emergency rulebook' set forth
at the EU level.
Monitoring
Monitoring of security
of supply predominatly
at the national level.
ECG as a voluntary
information exchange
platform.
- - Systematic discussion of ENTSO-E
Seasonal Outlooks in ECG and follow
up of their results by Member States
concerned.
Systematic monitoring of security of supply in Europe, on
the basis of a fixed set of indicators and regular outlooks
and reports produced by ENTSO-E, via the Electricity
Coordination Group.
Systematic reporting on electricity crisis events and
development of best practices via the Electricity
Coordination Group.
A European Standard (e.g. for
EENS and LOLE) on Security
of Supply could be developed
to allow performance
monitoring of Member States.
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Pros
Minimum requirements for plans
would ensure a minimum level of
preparedness across EU taking into
account cyber security.
EU wide minimum common principles
would ensure predictability in the
triggers and actions taken by Member
States.
Common methodology for assessments would allow
comparability and ensure compatibility of SoS measures
across Member States. Role of ENTSO-E and RSCs in
assessment can take into account cross-border risks.
Risk Preparedness Plans consisting of a national and
regional part would ensure sufficient coordination while
respecting national differences and competences.
Minimum level of harmonization for cybersecurity
throughout the EU.
Designation of competent authority would lead to clear
responsibilities and coordination in crsis.
Common principles for crisis management and
agreements regarding assistance and remuneration in
simultaneous scarcity situations would provide a base for
mutual trust and cooperation and prevent unjustified
intervention into market operation.
Enhanced role of ECG would provide adequate platform
for discussion and exchange between Member States and
regions.
Regional plans would ensure
full coherence of actions taken
in a crisis.
Cons
Lack of cooperation in
risk preparedness and
managing crisis may
distort internal market
and put at risk the
security of supply of
neighbouring countries.
Risk assessment and preparedness
plans on national level do not take into
account cross-border risks and crisis
which make the plans less efficient and
effective.
Minimum principles of crisis
management might not sufficiently
adress simultaneous scarcity situations.
The coordination in the regional context requires
administrative resources.
Cybersecurity here only covers electricity, whereas the
provisions should cover all energy sub-sectors including
oil, gas and nuclear.
Regional risk preparedness
plans and a detailed templates
would have difficulties to fit in
all national specificities.
Detailed emergency rulebook
might create overlaps with
existing Network Codes and
Guidelines.
Most suitable: Option 2, as it provides for sufficient regional coordination in preparation and managing crisis while respecting national differences and competences.
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Measures assessed under Problem Area 4: The slow deployment of new services, low levels of service and poor retail market performance
Addressing energy poverty
Objective: Better understanding of energy poverty and disconnection protection to all consumers
Option: 0 Option: 0+ Option 1 Option 2
BAU: sharing of good practices. BAU: sharing of good
practices and increasing the
efforts to correctly implement
the legislation.
Voluntary collaboration across
Member States to agree on
scope and measurement of
energy poverty.
Setting an EU framework to monitor
energy poverty.
Setting a uniform EU framework to monitor energy
poverty, preventative measures to avoid disconnections
and disconnection winter moratorium for vulnerable
consumers.
Energy poverty EU Observatory of Energy
poverty (funded until 2030).
- Option 0+: EU Observatory of Energy
Poverty (funded until 2030).
Generic description of the term energy
poverty in the legislation. Transparency
in relation to the meaning of energy
poverty and the number of households in
a situation of energy poverty
Member States to measure energy
poverty.
Better implementation of the current
provisions.
- Option 0+: EU Observatory of Energy Poverty
(funded until 2030).
Specific definition of energy poverty based on a share
of income spent on energy.
Member States to measure energy poverty using
required energy.
Better implementation and transparency as in Option 1.
Disconnection
safeguards
NRAs to monitor and report
figures on disconnections.
NRAs to monitor and report figures on
disconnections.
NRAs to monitor and report figures of disconnections.
A minimum notification period before a disconnection.
All customers to receive information on the sources of
support and be offered the possibility to delay payments
or restructure their debts, prior to disconnection.
Winter moratorium of disconnections for vulnerable
consumers.
Pros Continuous knowledge exchange. Stronger enforcement of
current legislation and
continuous knowledge
exchange.
Clarity on the concept and measuring of
energy poverty across the EU.
Standardised energy poverty concept and metric which
enables monitoring of energy poverty at EU level.
Equip MS with the tools to reduce disconnections.
Cons - Existing shortcomings of the
legislation are not addressed: lack
of clarity of the concept of energy
poverty and the number of energy
poor households persist.
Insufficient to address the
shortcomings of the current
legislation with regard to
energy poverty and targeted
protection.
New legislative proposal necessary.
Administrative costs.
New legislative proposal necessary.
Higher administrative costs.
- Potential conflict with principle of subsidiarity.
Specific definition of energy poverty may not be
suitable for all MS.
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Energy poverty remains a vague
concept leaving space for MS to
continue inefficient practices such
as regulated prices.
Indirect measure that could be
viewed as positive but insufficient
by key stakeholders.
Safeguards against disconnection may result in higher
costs for companies which may be passed to
consumers.
Safeguards against disconnection may also result in
market distortions where new suppliers avoid entering
markets where risks of disconnections are significant
and the suppliers active in such markets raise margins
for all consumers in order to recoup losses from unpaid
bills.
Moratorium of disconnection may conflict with
freedom of contract.
Most suitable option: Option 1 is recommended as the most balanced package of measures in terms of the cost of measures and the associated benefits. Option 1 will result in a clear
framework that will allow the EU and Member States to measure and monitor the level of energy poverty across the EU. The impact assessment found that the propose disconnection safeguards
in Option 2 come at a cost. There is potential to develop these measures at the EU level. However, Member States may be better suited to design these schemes to ensure that synergies between
national social services and disconnection safeguards can be achieved. Please note that Option 1 and Option 2 also include the measures described in Option 0+.
5
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Phasing out regulated prices
Objective: Removing market distortions by achieving the phase-out of supply price regulation for all customers.
Option: 0 Option 1 Option 2a Option 2b
Making use of existing acquis to continue
bilateral consultations and enforcement
actions to restrict price regulation to
proportionate situations justified by general
economic interest, accompanied by EU
guidance on the interpretation of the current
acquis.
Requiring MS to progressively phase out price
regulation for households by a deadline
specified in new EU legislation, starting with
prices below costs, while allowing
transitional, targeted price regulation for
vulnerable customers (e. g. in the form of
social tariffs).
Requiring MS to progressively phase
out price regulation, starting with prices
below costs, for households above a
certain consumption threshold to be
defined in new EU legislation or by
MS.
Requiring MS to progressively phase out below
cost price regulation for households by a deadline
specified in new EU legislation.
Pros:
- Allows a case-by-case assessment of the
proportionality of price regulation, taking into
account social and economic particularities in
MS
Pros:
- Removes the distortive effect of price
regulation after the target date.
- Ensures regulatory predictability and
transparency for supply activities across the
EU.
Pros:
- Limits the distortive effect of price
regulation.
- Would reduce the scope of price
regulation therefore limiting its
distortive impact on the market.
Pros:
- Limits the distortive effect of price regulation and
tackles tariff deficits where existent.
Cons:
- Leads to different national regimes
following case-by-case assessments. This
would maintain a fragmented regulatory
framework across the EU which translates
into administrative costs for entering new
markets.
Cons:
- Difficult to take into account social and
economic particularities in MS in setting up a
common deadline for price deregulation.
Cons:
- Difficult to take into account social
and economic particularities in MS in
defining a common consumption
threshold above which prices should be
deregulated.
Cons:
- Defining cost coverage at EU level is
economically and legally challenging.
- Implementation implies considerable regulatory
and administrative impact.
- Price regulation even if above cost risks holding
back investments in product innovation and service
quality.
Most suitable option(s): Option 1 - Setting an end date for all price intervention would ensure the complete removal of market distortions related to end-user price regulation and help create
a level playing field for supply activities across the EU while allowing targeted protection for vulnerable customers and/or energy poor.
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Level playing field for access to data
Objective: Creating a level playing field for access to data.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding roles and
responsibilities in data handling.
- Define responsibilities in data handling based on appropriate definitions in the
EU legislation.
- Define criteria and set principles in order to ensure the impartiality and non-
discriminatory behaviour of entities involved in data handling, as well as timely
and transparent access to data.
- Ensure that Member States implement a standardised data format at national
level.
- Impose a specific EU data management model (e.g. an
independent central data hub)
- Define specific procedures and roles for the operation of
such model.
Pro
Existing framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
The above measures can be applied independently of the data management model
that each Member State has chosen.
The measures will increase transparency, guarantee non-discriminatory access and
improve competition, while ensuring data protection.
Pro
Possible simplification of models across EU and easier
enforcement of standardized rules.
Con
The current EU framework is too
general when it comes to
responsibilities and principles. It is not
fit for developments which result from
the deployment of smart metering
systems.
Con Con
High adaptation costs for Member States who have already
decided and implementing specific data management models.
Such a measure would disproportionally affect those Member
States that have chosen a different model without necessarily
improving performance.
A specific model would not necessarily fit to all Member
States, where solutions which take into account local
conditions may prove to be more cost-efficient and effective.
Most suitable option(s): Option 1 is the preferred option as it will improve current framework and set principles for transparent and non-discriminatory data access from eligible market
parties. This option is expected to have a high net benefit for service providers and consumers and increase competition in the retail market.
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Facilitating supplier switching
Objective: Facilitating supplier switching by limiting the scope of switching and exit fees, and making them more visible and easier to understand in the event that they are
used.
Option 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Stronger enforcement, following the
clarification of certain concrete
requirements in the current legislation
through an interpretative note.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers, apart from: 1) exit fees
for fixed-term supply contracts; 2) fees
associated with energy efficiency or other
bundled energy services or investments. For
both exceptions, exit fees must be cost-
reflective.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers.
Pros:
- Evidence may suggest a degree of non-
enforcement of existing legislation by
national authorities.
- No new legislative intervention necessary.
Pros:
- Non-enforcement may be due to complex
existing legislation.
- No new legislative intervention necessary.
Pros:
- Considerably reduces the prevalence of
fees associated with switching suppliers,
and hence financial/psychological barriers
to switching.
Pros:
- Completely eliminates one
financial/psychological barrier to switching.
- Simple measure removes doubt amongst
consumers.
- The clearest, most enforceable
requirement without exceptions.
Cons:
- Continued ambiguity in existing
legislation may impede enforcement.
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
Cons:
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
- Certain MS might ignore the interpretative
note.
Cons:
- Marginally reduces the range of contracts
available to consumers, thereby limiting
innovation.
- An element of interpretation remains
around exceptions to the ban on fees
associated with switching suppliers.
Cons:
- Would further restrict innovation and
consumer choice, notably regarding
financing options for beneficial investments
in energy equipment as part of innovative
supply products e.g. self-generation, energy
efficiency, etc.
- Impedes the EU's decarbonisation
objectives, albeit marginally.
Most suitable option(s): Option 1 is the preferred option, as it represents the most favourable balance between probable benefits and costs.
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Comparison tools
Objective: Facilitating supplier switching by improving consumer access to reliable comparison tools.
Option 0+ Option 1 Option 2
Cross-sectorial Commission guidance addressing the applicability of the
Unfair Commercial Practices Directive to comparison tools
Legislation to ensure every Member State has at
least one 'certified' comparison tool that complies
with pre-specified criteria on reliability and
impartiality
Legislation to ensure every Member State appoints
an independent body to provide a comparison tool
that serves the consumer interest
Pros:
- Facilitates coherent enforcement of existing legislation.
- Light intervention and administrative impact.
- Cross-sectorial consumer legislation already requires comparison tools to be
transparent towards consumers in their functioning so as not to mislead
consumers (e.g. ensure that advertising and sponsored results are properly
identifiable etc.).
- Cross-sectorial approach addresses shortcomings in commercial comparison
tools of all varieties.
- Cross-sectorial approach minimizes proliferation of sector-specific
legislation.
Pros:
- Fills gaps in existing legislation vis-à-vis energy
comparison tools.
- Limited intervention in the market, in most cases.
- Allows certifying all existing energy comparison
tools regardless of ownership.
- Proactively increases levels of consumer trust.
- Ensures EU wide access.
- The certified comparison websites can become
market benchmarks, foster best practices among
competitors
Pros:
- NRAs able to censure suppliers by removing their
offers from the comparison tool.
- No obligation on private sector.
- Reduces risks of favouritism in certification
process.
- Proactively increases levels of consumer trust.
Cons:
- Does not apply to non-profit comparison tools.
- Does not proactively increase levels of consumer trust.
- The existing legislation does not oblige comparison tools to be fully
impartial, comprehensive, effective or useful to the consumer.
Cons:
- Existing legislation already requires commercial
comparison tools to abide by certain of the criteria
addressed by certification.
- Requires resources for verification and/or
certification.
- Significant public intervention necessary if no
comparison tools in a given MS meet standards.
Cons:
- To be effective, Member States must provide
sufficient resources for the development of such
tools to match the quality of offerings from the
private sector.
- Well-performing for-profit tools could be side-
lined by less effective ones run by national
authorities.
Most suitable option(s): Option 1 is the preferred option because it strikes the best balance between consumer welfare and administrative impact. It also gives Member States control over
whether they feel a certification scheme or a publicly-run comparison tool best ensures consumer engagement in their markets.
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Improving billing information
Objective: Ensuring that all consumer bills prominently display a minimum set of information that is essential to actively participating in the market.
Option: 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Commission recommendation on
billing information
More detailed legal requirements on the key
information to be included in bills
A fully standardized 'comparability box' in bills
Pros:
- 77% of energy consumers agree or strongly
agree that bills are "easy and clear to
understand".
- Allows 'natural experiments' and other
innovation on the design of billing information
to be developed by MS.
- Recent (2014) transposition of the EED
means premature to address information on
energy consumption and costs.
Pros:
- Low administrative impact
- Gives MS significant flexibility to
adapt their requirements to national
conditions.
- Allows best practices to further
develop.
Pros:
- Ensures that the minimum baseline of
existing practices is clarified and raised.
- Allows best practices to further develop,
albeit less than Option 0.
- Improves comparability and portability of
information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
- Bill design left free to innovation.
Pros:
- Highest legal clarity and comparability of
offers and bills.
- A level playing field for all consumers and
suppliers across the EU.
- Very little leeway for suppliers to differently
interpret the legislation with regards to the
presentation of information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
Cons:
- Poor consumer awareness of market-relevant
information can be expected to continue.
- Does not respond to stakeholder feedback on
need to ensure minimum standards.
Cons:
- A recommendation is unenforceable
and may be ignored by MS/utilities.
- Poor consumer awareness of market-
relevant information can be expected to
continue.
- Does not respond to stakeholder
feedback on need to ensure minimum
standards.
Cons:
- Limits innovation around certain bill
elements.
- Remaining leeway in interpreting legal
articles may lead to implementation and
enforcement difficulties.
Cons:
- Challenging to devise standard presentation
which can accommodate differences between
national markets.
- Highest administrative impact.
- Prescriptive approach prevents beneficial
innovation.
- Difficult to adapt bills to evolving
technologies and consumer preferences.
Most suitable option(s): Option 1 is the preferred option as it likely to leads to significant economic benefits and increased consumer surplus without significant administrative costs or the
risk of overly-prescriptive legislation at the EU level.
-


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 1/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
2
Abstract of the Impact Assessment of the Market Design Initiative
I. POLICY CONTEXT AND KEY CHALLENGES
The Energy Union framework strategy puts forward a vision of an energy market 'with
citizens at its core, where citizens take ownership of the energy transition, benefit from
new technologies to reduce their bills, participate actively in the market, and where
vulnerable consumers are protected'.
Well-functioning energy markets that ensure secure and sustainable energy supplies at
competitive prices are essential for achieving growth and consumer welfare in the
European Union and hence are at the heart of EU energy policy.
To live up to this vision, a series of legislative proposals have been prepared, following the
objectives of secure and competitive energy supplies and building on the EU's 2030 climate
commitments reconfirmed in Paris last year.
The electricity sector will be one of the main contributors to decarbonise the economy.
Currently, 27.5% of Europe's electricity is produced using renewable energy and the
modelling shows that close to half of our electricity will come from renewables by 2030.
With increasing use of electricity in sectors like transport or heating and cooling,
traditionally dominated by fossil fuels, it is ever more important to further increase the
share of renewable energies in electricity and to unlock flexible demand, generation and
storage solutions.
A new regulatory framework is needed to address these challenges and opportunities. The
new proposals for a revised Renewable Energy Directive and for a new Market Design
will precisely do this, by deepening integration of the internal energy market, empowering
consumers, stepping up regional and EU-wide cooperation and providing the right signals
for investment, thus ensuring secure, sustainable and competitive electricity systems.
A successful transition of the energy system delivering on the ambition to become world
leader in renewables will require substantial investment in the sector, and in particular
investments in low-carbon generation assets as well as network infrastructure. This
requires a revised Emissions Trading System in order to address the current surplus of
allowances and to deliver a strong investment signal to reach 40% greenhouse gas
emissions reductions by 2030, but also specific rules to complement market revenues if
those are not sufficient to attract investments in renewable electricity. In addition, measures
to promote renewable energies in sectors like transport or heating and cooling are also
crucial. Reaching the 2030 framework targets and achieving an Energy Union will be
underpinned by a strong Energy Union governance, which will ensure the necessary
ambition level in an iterative dialogue between the Commission and all Member States.
Finally, a successful transition of the energy system will also require continued
commitment and support for infrastructure development both locally as well as across
borders.
3
At the same time the transition will only be successful if consumers are given the
information, opportunities and rewards to actively participate in it. The availability of new
technologies that allow consumers to both consume electricity in a smarter way as well as
produce it themselves at costs which are more and more competitive opens up manifold
possibilities. What is still needed to fully reap these opportunities is the appropriate
regulatory framework accompanying the digital transformation and technological
development that will empower consumers to take part in the energy transition by
becoming active market participants. Empowering consumers in this way will also
contribute to a more efficient use of energy and is therefore an integral part of
implementing the efficiency first principle.
Finally, the EU will only be able to manage the energy transition successfully and cost-
effectively in a more deeply integrated internal electricity market. Only a more competitive
and better interconnected market will allow Europe to drive cost-efficient investment and
in particular to integrate the rising share of renewable energy production in a cost-efficient
and secure manner into the system, profiting fully from complementarities between
Member States and broader regions.
Such a deeply integrated and competitive market is also a key building block for
guaranteeing security of supply and policies and mechanisms intended to reach this
objective should follow a cooperative logic. National security of supply policies need to
be better coordinated and aligned. This will ensure that Member States are duly prepared
to tackle possible crisis situations, in particular those that affect several countries at the
same time.
The present package of legislative measures directly contributes to the Energy Union
dimensions of energy security, solidarity and trust, a fully integrated internal energy market
as well as decarbonisation of the economy, while also indirectly contributing to the other
two.
II. LESSON LEARNED AND PROBLEM DEFINITION
Three consecutive legislative packages have transformed what used to be fragmented
energy markets in Europe into a more integrated Internal Electricity Market, thus
increasing competition. However, Europe's energy markets are undergoing further
profound changes.
The transition towards a low-carbon electricity production poses a number of
challenges for the secure and cost-effective organisation and operation of Europe’s power
grids and electricity markets. The increasing penetration of variable and decentralised
renewable energy – driven inter alia by the EU’s goals for climate change and energy in
line with the 2020 and 2030 targets – requires the electricity sector to be operated more
flexibly and efficiently.
Today, most new installed capacity is based on wind and solar power which are inherently
more variable and less predictable when compared to conventional sources of energy
4
(predictable central, large-scale fossil fuel-based power plants) or flexible renewable
energy technologies (e.g. biomass, geothermal or hydropower). By 2030, this trend is
expected to be ever more pronounced. As a result, there will be times when variable
renewables could cover a very large share - even 100% - of electricity demand and times
when they only cover a minor share of total consumption. The overall electricity supply
and demand needs to be in balance in physical terms at any given point in time (including
production or storage of electricity). This balance is a precondition for the secure operation
and stability of the electricity grid, thus avoiding the risk of black-outs.
Current market arrangements do not adequately incentivize all market participants –
including renewable energy generation - to adjust their portfolios by revising production
and consumption plans on short notice. The manner in which the trading of electricity is
arranged and in which the methods for allocating the network capacity to transport
electricity are organized, allow only for efficient trading of electricity in timeframes of one
or more days ahead of physical delivery. Yet, the increasing penetration of variable
renewable sources of electricity ('RES E') requires efficient and liquid short-term markets
that can operate as close to real time as possible – until very shortly before the time of
physical delivery (i.e. the moment when electricity is consumed). Indeed, most renewable
generation can only be accurately predicted shortly before the actual production (due to
weather uncertainties). Flexibility is essential to deal effectively with an increased share
of variable renewable generation. Besides, these markets do not fully take into account
possible contribution of cross-border resources.
Retail markets for energy in most parts of the EU suffer from persistently low levels
of competition, consumer choice and engagement. In spite of falling prices on wholesale
markets, retail prices have risen steadily for households as a result of significantly
increased network charges, taxes and levies in recent years. Market concentration remains
generally high due to persisting barriers to new entrants. Switching related fees such as
contract termination charges continue to constitute a significant financial barrier to
consumer engagement. In addition, the high number of complaints related to billing
suggests that there is still scope to improve the comparability, clarity and accuracy of
billing information.
Despite technical innovations that allow consumers to better and more easily manage their
energy use – smart grids, smart homes, rooftop solar panels and storage, for example –
consumers are not sufficiently able to actively participate in electricity markets and match
demand with supply during peak times, particularly through demand-response. This is
because households and businesses often have scarce knowledge and little or no incentive
to change the amount of electricity they use or produce in response to changing prices in
the markets. Indeed, a host of issues such as a slow roll out of fully functional smart
metering systems, regulated prices, lacklustre competition between retailers and an
increasing portion of fixed charges in energy bills mean that real-time price signals are
usually not passed on to final consumers.
In some Member States, up to 90% of renewable electricity generation is connected at
distribution level, putting more pressure on distribution system operators ('DSOs') to
5
actively manage their grids and to efficiently adjust to the increasing share of variable and
decentralized renewable electricity injected into their networks. However – in contrast to
transmission system operators ('TSOs') – the current regulatory framework does not always
provide appropriate tools to DSOs to do this, resulting in network charges that are often
higher than they could be for end consumers. Ensuring that all DSOs become more flexible
would create a level playing field for the deployment of renewable generation that would
make attaining the EU's climate and energy objectives easier.
The deployment of information technology offers the possibility to address these issues,
facilitating the development of new services, improving consumer's comfort and making
the market more contestable and efficient. However, to fully benefit from the digitalisation
of the electricity market we need a non-discriminatory data management framework that
makes the right information immediately available to the right market actors, while at the
same time ensuring a high level of data protection.
With regard to consumer protection, there is a need to ensure that the move towards more
efficient retail markets does not lead to any group of consumers being left behind. In
particular, rising energy poverty as well as a lack of clarity on the most appropriate means
of tackling consumer vulnerability and energy poverty can hamper the further deepening
of the internal energy market.
In the current context, wholesale electricity prices have been decreasing due to number
of coinciding drivers: a decline in primary energy prices, a surplus of carbon allowances
and an overcapacity of power generation facilities in some regions of the EU caused by a
drop in electricity demand, rising investments in renewables driven by EU policies and
increased sharing of resources among Member States through market coupling.
For most regions in Europe, current electricity wholesale prices do not indicate the
need for new investments into electricity generation. However, in the current market
arrangement, prices often do not reflect the real value of electricity due to regulatory
failures such as the lack of scarcity pricing and inadequately delimited price (or bidding)
zones. These regulatory failures, taken together with the increasing penetration of
electricity generated from renewable sources with low operating costs, affect the
remuneration of conventional electricity generation units that operate less often but
contribute to providing security and flexibility to the system – alongside non-conventional
flexible generation, interconnections, storage and demand response.
In light of the 2030 objective for renewable energy, considerable new investment in
electricity generation capacity will be required. The largest part will be provided by
variable renewable generation, complemented to a certain extent by more predictable,
flexible, less carbon-intensive forms of power generation. Independently of current
overcapacities, there are growing concerns in some areas of Europe that current average
wholesale prices may not provide appropriate signals for the necessary investments into
future generation or for keeping sufficient capacity in the market. A number of Member
States anticipate inadequate generation capacity in future years and introduce capacity
mechanisms at national level to support investment in capacity and ensure system
6
adequacy (i.e. the ability of the electricity system to serve demand at all times). When
uncoordinated and designed without a proper assessment of the appropriate level of
supply security, capacity mechanisms may risk affecting cross-border trade, distorting
investment signals, affecting thus the ability of the market to deliver any new investments
in conventional and low-carbon generation, and strengthening market power of
incumbents by not allowing alternative providers to enter the market.
Despite best efforts to build an integrated and resilient power market, crisis situations can
never be excluded. The potential for crisis situation increases with climate change (e.g.
extreme weather conditions) and the emergence of new areas that are subject to criticalities
such as malicious attacks and cyber-threats. Such crises tend to often have an immediate
cross-border effect in electricity. Where systems are interconnected, incidents that start
locally can rapidly spread beyond borders and crisis situations might also affect several
Member States at the same time (e.g. prolonged heat waves or cold spells).
Today, risk assessments as well as plans and actions for dealing with electricity crisis
situations focus on the national context only and there is insufficient information-sharing
and transparency across Member States. In addition, there are different views on what is
to be considered as a risk to security of supply. In an increasingly inter-connected
electricity market, the lack of common approach and coordination can seriously imperil
security of supply across borders and dangerously undermine the functioning of the
internal electricity market.
In addition, missing opportunities to exchange energy with neighbours remains a key
obstacle to the internal energy market. Even where interconnectors are in place, they often
remain unused due to a lack of coordination between Member States. Rules are therefore
needed that ensure that the use of interconnection is not unduly limited by national
interventions.
Based on the above-mentioned shortcomings and underlying drivers, the present impact
assessment has identified four key problem areas that are addressed in the proposed
initiative: i) the current market design is not fit for integrating an increasing share of
variable, decentralised generation and for reaping the potential of technological
developments; ii) uncertainty about sufficient future generation investments and
uncoordinated capacity mechanisms; iii) Member States do not take sufficient
account of what happens across their borders when preparing for and managing
electricity crisis situations; and iv) as regards retail markets, there is a slow
deployment and low levels of services and poor market performance are wide-spread
in the EU.
III. SUBSIDIARITY
Article 194 of the Treaty of the Functioning of the EU consolidated and clarified the
competences of the EU in the field of energy and is the legal basis of the current proposal.
Electricity markets have become more integrated and interdependent physically,
economically and from a regulatory point of view, due to increasing cross-border
7
electricity trade, growing share of renewable energy sources and more interconnections in
the European electricity grid. The challenges can no longer be addressed as effectively by
individual Member States. New frameworks to further integrate the internal energy market
and improve the conditions for competition while at the same time adjusting to the
decarbonisation targets and ensuring a more coordinated policy response to security of
supply, can most effectively be achieved at European level.
IV. SCOPE AND OBJECTIVES
Against this background and in line with the Union's policy on climate change and energy,
the general policy objective of the present initiative is to make electricity markets more
secure, efficient and competitive, while ensuring that electricity is generated in a
sustainable way and remains affordable to all consumers. The present impact assessment
reflects and analyses the need and policy options for a possible revision of the main
framework governing electricity markets and security of supply policies in Europe.
There are four specific objectives: i) adapt the market design for the cost effective
operation of variable and often decentralised generation, taking into account technological
developments; ii) facilitate investments in generation capacity in the right amount and type
of resources for the EU: iii) improve Member States' resilience on each other in times of
system stress and reinforce their coordination and cooperation regarding crisis situations;
and iv) address the root causes of weak competition on energy retail markets and improve
consumer protection and engagement.
Interlinkages with parallel initiatives
The proposed initiative is strongly linked to other energy and climate related legislative
proposals brought forward in parallel, including the renewable energy package which
covers a number of measures deemed necessary to attain the EU binding objective of
reaching a level of at least 27% renewables in final EU energy consumption by 2030. The
renewable energy directive has synergies with the present initiative, which seeks to adapt
the current market design to the increasing share of variable decentralised generation and
technological development and to create an environment conducive for investments in
renewables.
In particular, the reflections on a revised Renewables Energy Directive will include
framework principles on support schemes for market-oriented, cost-effective and more
regionalised support to RES E up to 2030, in case Member States were opting to have them
as a tool to facilitate target achievement. Conversely, measures aimed at the integration of
RES E in the market, such as provisions on priority dispatch and access previously
contained in the Renewables Directive are part of the present market design initiative. The
Renewable Package also deals with legal and administrative barriers for self-consumption,
whereas the present package addresses market related barriers to self-consumption.
Both the market design and renewable energy impact assessments come to the conclusion
that the improved electricity market, supported through a revised Emission Trading System
('ETS'), could, under certain conditions, by 2030 deliver investments in the most mature
low-carbon technologies (such as PV and onshore wind). However, until such conditions
8
materialise, market-based support schemes will still be needed in order to provide
investment certainty. Less mature RES E technologies, such as offshore wind, will likely
need some form of support throughout the transitional period.
The Energy Union governance initiative also has synergies with the present initiative and
will contribute to ensure policy coherence and reduce administrative impact. It will also
streamline the reporting obligations by Member States and the Commission that are
presently enshrined in the Third Package.
In general terms, energy efficiency measures also interact with the present initiative as they
affect the level and structure of electricity demand. In addition, energy efficiency measures
can alleviate energy poverty and consumer vulnerability. Besides consumer income and
energy prices, energy efficiency is one of the major drivers of energy poverty. The
provisions previously contained in the energy efficiency legislation on demand response,
billing and metering will be set out in the present initiative.
The present initiative is furthermore consistent with the findings of the sector inquiry on
capacity mechanisms. Pointing out that there is a lack of adequate assessment of the actual
need for capacity mechanisms, the sector inquiry emphasizes that where needed capacity
mechanisms need to be designed with transparent and open rules of participation that does
not undermine the functioning of the electricity market, taking into account cross border
participation.
The Commission Regulation establishing a Guideline on Electricity Balancing ('Balancing
Guideline') is also closely related to the present initiative as it aims to harmonise certain
aspects of the EU's balancing markets and to optimise cross-border usage. Indeed, efficient,
integrated balancing markets are an important building block for the consistent functioning
and flexibility of the market which in turn is needed for a cost effective integration of RES
E into the electricity market.
V. DESCRIPTION OF POLICY OPTIONS AND METHODOLOGY
In assessing all possible options (ranging from non-regulatory to legislative policy options)
the following approach was taken:
- Identification of a set of high level options for each problem area. Each of these high
level options contains sub-options for specific measures;
- Assessment of each specific measure, comparing a number of options in order to select
the preferred approach.
The following policy options have been considered:
Regarding Problem Area I: the need to adapt the market design to the increasing
share of variable decentralised generation and technological developments,
Option 0+ (Non-regulatory approach) provides little scope for improving the market and
the level-playing field among resources. Indeed, the current EU regulatory framework is
limited in certain areas (e.g., balancing and intraday markets) and even non-existent for
9
other areas (e.g., role of DSOs in data management). Besides, voluntary cooperation may
not provide for the appropriate levels of harmonisation or certainty to the market and
legislation. This option was therefore discarded.
Two possible paths going beyond the baseline scenario were however identified and
assessed: (i) enhancing current market rules through EU regulatory action in order to
increase the flexibility of the system, retaining to a certain extent the national operation of
the systems (Option 1) and, (2) moving to a fully integrated approach via relatively far-
reaching changing to the current regulatory framework (Option 2).
Option 1 of enhancing the current market rules comprises three different sub-options:
Option 1(a) Creating a level-playing field among all generation technologies and
resources and remove existing market distortions. It addresses rules that
discriminate between resources and which limit or favour the access of
certain technologies to the electricity grid (such as so-called 'must-run'
provisions and rules on priority dispatch and access). In addition, all market
participants would bear financial responsibility for the imbalances caused
on the grid and all resources would be remunerated in the market on equal
terms. Barriers to demand-response would be removed. Exemptions from
certain regulatory provisions may, in some cases, be required, notably for
certain small-scale installations and emerging technologies.
Option 1(b) (In addition to sub-option (a)) Strengthening the short-term markets by
bringing them closer to real-time in order to provide maximum opportunity
to meet the flexibility needs and balance the market. The sizing of balancing
reserves and their use would be harmonised in larger balancing zones in
order to optimally exploit interconnections and cross-border exchange in
shorter term markets.
Option 1(c) (In addition to sub-option (a) and (b)) Pulling all flexible distributed
resources concerning generation, demand and storage, into the market via
proper incentives and a market framework better adapted to them. This
would be based on smart-metering allowing consumers to directly react to
price signals and measures to incentivise DSOs to manage their networks in
a flexible and cost-efficient way.
Option 2 (fully integrated market) considers measures that would aim to deliver a truly
integrated pan-European electricity market through the adoption of far-reaching measures
changing the current regulatory framework.
Regarding Problem Area II: uncertainty about sufficient future generation
investments and uncoordinated capacity mechanisms, four options were considered.
As regards Option 0+ (Non-regulatory approach), existing provisions under EU legislation
are not sufficiently clear and robust to cope with the challenges facing the European
electricity system. In addition, voluntary cooperation may not provide for appropriate
levels of harmonisation across all Member States or certainty to the market. Legislation is
10
needed in this area to address the issues in a consistent way. This Option was therefore
discarded.
Various policy options going beyond the baseline scenario were assessed. They differ
according to which extent market participants can rely on energy market payments. Each
policy option also considers varying degrees of alignment and coordination among
Member States at EU-level.
Option 1 (energy-only market without capacity mechanisms) builds upon Option 1(a) to
1(c) under problem area I and would be based on additional measures to further strengthen
the internal electricity market. Under this option, it is assumed that European markets, if
sufficiently interconnected and undistorted, can provide for the necessary price signals to
incentivise investments in new generation thus also reducing the need for government
interventions in support thereof. This option consists of improving price signals by
removing price caps in order to allow scarcity pricing during peak time. At the same time,
price signals could drive the geographical location of new investments and production
decisions, via price zones aligned with structural congestion in the transmission grid.
Option 2 and 3 include the measures presented in Option 1, but allow capacity mechanisms
under certain conditions and propose possible measures to better align them among
Member States in order to avoid negative consequences for the functioning of the internal
market. These options build on the European Commission's 'EEAG' state aid Guidelines
and the Sector Inquiry on capacity mechanisms. In Option 2, capacity mechanisms are
based on a transparent and EU-wide resource adequacy assessment carried-out by the
European Network of Transmission System Operators for electricity ('ENTSO-E'). Such
EU-wide assessment would also allow for effective cross-border participation.
Additionally, Option 3 would provide for common design features for better compatibility
between national capacity mechanisms and harmonised cross-border cooperation.
Under Option 4 based on regional or EU-wide generation adequacy assessments, entire
regions or ultimately all EU Member States would be required to roll out capacity
mechanisms on a mandatory basis. This option was found to be disproportionate and was
discarded.
Regarding Problem Area III: the lack of coordination among Member States when
preparing for and managing electricity crisis situations, five policy options ranging
from the baseline scenario (Option 0) to the full harmonization and decision making at
regional level have been identified.
Option 0+ (Non-regulatory approach). As current legislative provisions do not prescribe
how Member States should prevent and manage crisis situations nor mandate any form of
cross-border co-operation, better implementation and enforcement actions will be of no
avail. In addition, whilst there is some voluntary cross-border cooperation in this area, it is
limited to a few regional parts of the EU. This option was discarded.
Under Option 1 (Common minimum EU rules), Member States would have to respect a
set of common rules and principles regarding crisis prevention and management, agreed at
11
the European level ('minimum harmonisation'). Accordingly, non-market measures should
only be introduced as a means of last resort, when duly justified. Member States would be
obliged to address electricity crisis situations, in particular situations of a simultaneous
crisis, in a spirit of co-operation and solidarity. Member States should inform each other
and the Commission without undue delay when they see a crisis situation coming or when
being in a crisis situation. Member States would be obliged to develop national Risk
Preparedness Plans ('Plan') with the aim to avoid or better tackle crisis situations. Plans
could be prepared by TSOs, but need to be endorsed at the political level. On cyber-
security, Member States would need to set out in the Plan how they will prevent and
manage cyberattack situations.
Option 2 (EU rules + regional cooperation) would include all common rules included in
Option 1. In addition, it would put in place rules and tools to ensure that effective cross-
border co-operation takes place in a regional and EU context. Thus, there would be a
systematic assessment of rare/extreme risks at the regional level. The identification of
crisis scenarios would be carried out by ENTSO-E in a regional context and tasks would
be delegated to Regional Operation Centres (ROCs). For cybersecurity, the Commission
would propose the development of a network code/guideline which would ensure a
minimum level of harmonization in the energy sector throughout the EU. The Risk
Preparedness Plans would contain two parts – a part reflecting national measures and a
part reflecting measures to be pre-agreed in a regional context (including regional 'stress
tests', procedures for cooperation in different crisis scenarios and agreement on how to deal
with simultaneous electricity crisis situations).
Option 3 (Full harmonisation) entails full harmonisation and decision-making at regional
level. The risk preparedness plans would be developed on regional level in order to allow
a harmonised response to potential crisis situation in each region. On cybersecurity, Option
3 would go one step further and nominate a dedicated body (agency) to deal with
cybersecurity in the energy sector. Crisis would have to be managed according to the
regional plans agreed among Member States. A detailed 'emergency rulebook' for crisis
handling would be put in place, containing an exhaustive list of measures that can be taken
by Member States in crisis situations.
Regarding Problem Area IV: retail markets and the slow deployment and low levels
of services and poor market performance, four policy options have been considered
ranging from baseline scenario (Option 0) to full harmonization and extensive safeguards
for consumers.
Option 0+ (Improved implementation/enforcement and non-regulatory approach) consists
in sharing of good practices and increasing the efforts to correctly implement the
legislation. This non-regulatory approach addresses competition and consumer
engagement issues by strengthening the enforcement of the existing legislation as well as
through bilateral consultation with Member States to progressively phase-out price
regulation, starting with prices below costs. It also considers developing a
Recommendation on energy bills. However, this option does not tackle the third problem
driver of the market failures that prevent effective data flow between market actors.
12
Under Option 1 (Flexible legislation), all problem drivers are addressed through new
legislation. To improve competition, Member States progressively phase-out blanket price
regulation by a deadline specified in new EU legislation, starting with prices below costs,
while allowing transitional price regulation for vulnerable consumers. To increase
consumer engagement, the use of contract termination fees is restricted. Consumer
confidence in comparison websites is fostered through national authorities implementing
a certification tool. In addition, high-level principles ensure that energy bills are clear and
easy to understand, through minimum content requirements. A generic adaptable,
definition of energy poverty based on household income and energy expenditure is
proposed in the legislation for the first time. Finally, to allow the development of new
services by new entrants and energy service companies, non-discriminatory access to
consumer data is ensured.
Building on Option 1, Option 2 (Full harmonisation and extensive consumer safeguards)
aims to provide maximum safeguards for consumers and extensive harmonisation of
Member States action throughout the EU. Exemptions to price regulation are defined at
EU level on the basis of either a consumption threshold or a price threshold. A standard
data handling model is enforced and assigns the responsibility to a neutral market actor
such as a TSO. All switching fees including contract termination fees are banned and the
content of energy bills is partially harmonized. Finally, an EU framework to monitor
energy poverty based on an energy efficiency survey done by Member States of the
housing stock as well as preventive measures to avoid disconnections are put in place.
VI POLICY TRADE-OFFS
The measures considered in this impact assessment are highly complementary. Most of the
different options considered in each problem area would reinforce the effect of options in
other problem areas, with little trade-offs between the different areas. The overall
beneficial effects will be achieved only if all measures are implemented as a package
The measures under Problem Area I and II are strongly linked in that they collectively aim
at improving market functioning, including the delivery of investment by the market.
Measures under Problem Area I and Option 1 of Problem area II thus reduce the need for
market government intervention by means of capacity mechanisms. The other measures
under Problem Area II reduce their distortive effects if such mechanisms are nonetheless
justified.
Scarcity pricing and capacity mechanisms can to a certain degree be seen as alternative
measures to foster investments. With assets remunerated by capacity mechanisms, the
effectiveness of scarcity prices may be reduced. It needs also to be noted that scarcity prices
and market-wide capacity mechanisms incentivise different investment decisions: whereas
such capacity mechanisms may reward any firm capacity, scarcity pricing will improve
remuneration of flexible capacity in particular.
The measures aiming at providing adequate price signals (measures under Problem Area I
and Problem Area Option 1) are no-regret options. Until these conditions are achieved and
under specific circumstances (like energy isolation), State intervention in the form of some
13
type of capacity mechanism may be necessary. That is why it is essential that such
mechanisms are properly designed, taking into account the wider regional and European
resources and allowing cross-border participation in a technology-neutral manner.
The measures assessed under various options in the impact assessment seek to improve the
overall flexibility of the electricity system. However, they do this by employing different
means. Investment in new interconnection capacity may reduce the need for new
generation and vice-versa, new generation can reduce the incentives for new interconnector
capacity. Similarly, pulling demand response into the market will reduce the profits of
generation capacity. Ultimately, the efficient markets should opt for the most cost-efficient
solutions.
Energy poverty safeguards whose costs directly accrue to suppliers – particularly, the
disconnection safeguards considered in Option 2 (Harmonization and extensive consumer
safeguards) of Problem Area IV (Retail markets) – may act as a barrier to retail-level
competition, and diminish the associated benefits to consumers, including lower prices,
new and innovative products, and higher levels of service. Although the implementation
costs of these safeguards will be passed on to consumers, and therefore socialized, different
energy suppliers may have different abilities to do this, and to deal with the additional
consumer engagement costs. Some may therefore choose not to enter markets with such
safeguards in place.
VII. ANALYSIS OF IMPACTS AND CONCLUSIONS
All options have been compared against each other using, the baseline scenario as a
reference and applying the following criteria:
- Effectiveness: the options proposed should first and foremost be effective and thus be
suitable to addressing the specified problem;
- Efficiency: this criterion assesses the extent to which objectives can be achieved at the
least cost (benefits versus the costs).
Policy options regarding the need to adapt the market design to the increasing share
of variable decentralised generation and technological developments (Problem Area
I)
Options 1(a) (level playing field), 1(b) (strengthening short-term markets) and 1(c)
(demand response/distributed resources) represent an interlinked set of measures regarding
the integration of the national electricity markets and present a compromise between
bottom-up initiatives and top-down steering of the market development, without
substituting the role of national governments, regulators and TSOs by a centralised and
fully harmonised system.
However, Option 1(a) (level playing field) and Option 1(b) (strengthening short-term
markets) do not cover measures to pull all distributed flexible resources (demand-response,
renewable electricity and storage) into the market. These options do not take advantage of
the potential offered by these resources to efficiently operate and decarbonise the
electricity market.
14
In this context, Option 1(c) (demand response/distributed resources) provides a more
holistic, effective and efficient package of solutions. While this option may lead to minor
additional administrative impacts for Member States and competent authorities regarding
the implementation and monitoring of the measures, these impacts will be offset by lower
barriers to entry to start-ups and SMEs, by the benefits to market parties from more stable
regulatory frameworks and new business opportunities as well as by the benefits to
consumers from more competition and access to wider choice.
As regards Option 2 (fully integrated market), while having advantages in terms of less
coordination requirements (i.e., a fully integrated EU-market can be operated more
efficiently), the results of the assessment indicate that the move towards a more integrated
European approach has less significant economic added value since most of the benefits
will have already been reaped under the regional, more decentralised approach under
option. In addition, it has significant impacts on stakeholders, Member States and
competent authorities since it requires significant changes to established practices.
Preferred option for Problem Area I: Option 1(c) (demand response/distributed
resources, also encompassing options 1(a) (level playing field) and 1(b) (strengthening
short-term markets))
Policy options regarding uncertainty about sufficient future generation investments
and uncoordinated capacity mechanisms (Problem Area II)
Option 1 (reinforced energy only market without capacity mechanisms) can in principle
provide the right signals for market operation and ensure system adequacy and ensure
better utilisation of resources across borders, demand participation and renewable
integration without subsidies. Improving the functioning of electricity markets will
improve the conditions for investment in the electricity market to ensure reliable and
effective supply of electricity, even in times of scarcity. This will in turn decrease the need
for capacity mechanisms.
However, markets are today still characterised by manifold regulatory distortions today
and removing the distortive effects will not be possible with immediate effects in many
Member States. Besides under such option, uncertainty about future policy directions or
governmental interventions still exists. Such uncertainty may hamper investment and in
turn create the need for mechanisms that address the lack of investments ('missing money').
It should be noted that undistorted energy price signals are fundamental irrespective of
whether generators are solely relying on energy market incomes or also receive capacity
payments. Therefore the measures aimed at removing distortions from energy-only
markets discussed under Option 1(a) to 1(c) (e.g. scarcity pricing or reinforced locational
signals) are 'no-regrets' and assumed as being integral parts of Options 2, 3 and 4.
Option 2 (Improved energy markets – Capacity Mechanisms ('CM's) only when needed,
based on a common EU-wide adequacy assessment can improve the overall cost-efficiency
of the electricity sector through establishing an EU-wide approach to system adequacy
assessments as opposed to national-based adequacy assessments. At the same time Option
15
2 does not allow reaping the full benefits of cross-border participation in capacity
mechanisms.
A more coordinate approach to state interventions across Member States is needed and is
a clear priority for reform. Placing capacity mechanisms into a more regional/EU context
is a pre-requisite to reduce market distortions. It is indeed necessary that the schemes
Member States introduce are compatible with internal market rules.
Option 3 (Improved energy market – CMs only when needed, plus cross-border
participation) proposes additional measures to avoid fragmentation of capacity
mechanisms and ensures that foreign resource providers can effectively participate in
national capacity mechanisms and avoids competition and market distortions resulting
from capacity payments which are reserved to domestic participants. As a result, it reduces
investment distortions that might be present in Option 2 because of uncoordinated
approaches to cross-border participation.
Preferred option for Problem Area II: Option 3 (Improved energy market – CMs
only when needed, plus cross-border participation) (encompassing also Options 1 and
2)
Policy options regarding the lack of coordination among Member States when
preparing for and managing electricity crisis situations (Problem Area III)
Based on a set of clear common rules, Option 1 (Common minimum EU rules) would
improve the level of transparency and crisis management across Europe and is likely to
reduce the chances of premature market intervention. The policy tools proposed under this
option would bring economic benefits to businesses and consumers by helping to prevent
costly blackout situations. However, this option does not solve the issue of uncoordinated
planning and preparation ahead of a crisis since Member State are not required to take into
account cross-border risks and crisis.
Under Option 2 (EU rules + regional cooperation), the regionally coordinated plans ensure
the regional identification of risks and the consistency of the measures for prevention and
managing crisis situations while respecting national differences and competences. This
significantly improves the level of preparedness (compared to Option 1) at national,
regional and EU level, as the cross border considerations are duly taken into account since
the beginning. A regional approach to security of supply results in a better utilisation of
power plants and guarantees risk preparedness at a lesser cost.
Under Option 3 (Full harmonisation), the estimated impact on cost is likely to be high
(notably with the creation of an EU agency on cyber-security) and the measures put
forward appear disproportionate compared to the expected effectiveness. Indeed, this
option represents a highly intrusive approach – with significant administrative impact - by
resorting to a full harmonisation of principles and the prescription of concrete solutions.
Preferred option for Problem Area III: Option 2 (EU rules + regional cooperation)
Policy options regarding retail markets and the slow deployment and low levels of
services and poor market performance (Problem Area IV)
16
Given its low implementation costs, Option 0+ (Non-regulatory approach) is a highly
efficient option. However, the effectiveness of Option 0+ is significantly limited by the
fact that non-regulatory measures are not suitable for tackling the poor data flow between
retail market actors that constitutes both a barrier to entry and a barrier to higher levels of
service to consumers. In addition, shortcomings in the existing legislation make it
impossible to significantly improve consumer engagement and energy poverty safeguards.
They also introduce great uncertainty around the drive to phase out price regulation which
does not provide sufficient incentives to consumers to play an active role in the market and
which also limits competition and new entrants into the market.
Option 1 (Flexible legislation) would lead to substantial economic benefits. Retail
competition would be improved as a result of the progressive phase-out of blanket price
regulation, non-discriminatory access to consumer data, and increased consumer
engagement. In addition, consumers would see direct benefits through improved switching.
In Option 2 (Harmonization and extensive consumer safeguards) there is uncertainty over
the size of the economic benefits. This uncertainty stems from the tension some of the
measures in Option 2 may have with competition (stronger disconnection safeguards, an
outright ban on all switching-related charges), and from the difficulty of prescribing EU-
level solutions in certain areas (defining exceptions to price deregulation, implementing a
standard EU bill design). Besides, a single EU data management model would have high
implementation costs, thus reducing the efficiency of the option.
Preferred option for Problem Area IV: Option 1 (Flexible legislation)
***
TABLE OF CONTENTS
1. INTRODUCTION.............................................................................................................22
1.1. Background and scope of the market design initiative .............................................................22
Context of the initiative.............................................................................................................22
1.1.1.1. The gradual process of creating an internal electricity market .......................................22
1.1.1.2. The Union's policy concerning climate change ................................................................22
1.1.1.3. Paradigm shift in the electricity sector ............................................................................23
1.1.1.4. The vision for the EU electricity market in 2030 and beyond..........................................24
Scope of the initiative................................................................................................................30
1.1.2.1. Current relevant legislative framework ...........................................................................30
1.1.2.2. Policy development subsequent to the Third Package....................................................31
1.1.2.3. Scope and summary of the initiative ...............................................................................32
Organisation and timing ............................................................................................................33
1.1.3.1. Follow up on the Third Package.......................................................................................33
1.1.3.2. Consultation and expertise ..............................................................................................34
1.2. Interlinkages with parallel initiatives........................................................................................34
The Renewable Energy Package comprising the new Renewable Energy Directive and
bioenergy sustainability policy for 2030 ('RED II') ...................................................................................34
Commission guidance on regional cooperation ........................................................................36
The Energy Union governance initiative....................................................................................36
17
The Energy Efficiency legislation ('EE') and the related Energy Performance of Buildings
Directive ('EPBD') including the proposals for their amendment. ...........................................................36
The Commission Regulation establishing a Guideline on Electricity Balancing ('Balancing
Guideline')................................................................................................................................................37
Other relevant instruments.......................................................................................................38
2. PROBLEM DESCRIPTION.............................................................................................38
2.1. Problem Area I: Market design not fit for an increasing share of variable decentralized
generation and technological developments .........................................................................................38
Driver 1: Short-term markets, as well as balancing markets, are not efficiently organised......40
Driver 2: Exemptions from fundamental market principles ......................................................42
Driver 3: Consumers do not actively engage in the market and demand response potential
remains largely untapped ........................................................................................................................44
Driver 4: Distribution networks are not actively managed and grid users are poorly
incentivised..............................................................................................................................................50
2.2. Problem Area II: Uncertainty about sufficient future generation investments and
uncoordinated capacity markets............................................................................................................51
Driver 1: Lack of adequate investment signals due to regulatory failures and imperfections in
the electricity market...............................................................................................................................55
Driver 2: Uncoordinated state interventions to deal with real or perceived capacity problems
58
2.3. Problem Area III: Member States do not take sufficient account of what happens across their
borders when preparing for and managing electricity crisis situations...................................................63
Driver 1: Plans and actions for dealing with electricity crisis situations focus on the national
context only .............................................................................................................................................65
Driver 2: Lack of information-sharing and transparency...........................................................67
Driver 3: No common approach to identifying and assessing risks ...........................................68
2.4. Problem Area IV: The slow deployment of new services, low levels of service and questionable
market performance on retail markets ..................................................................................................69
Driver 1: Low levels of competition on retail markets ..............................................................70
Driver 2: Possible conflicts of interest between market actors that manage and handle data 74
Driver 3: Low levels of consumer engagement .........................................................................75
2.5. What is the EU dimension of the problem? ..............................................................................76
2.6. How would the problem evolve, all things being equal? ..........................................................77
The projected development of the current regulatory framework...........................................77
Expected evolution of the problems under the current regulatory framework........................78
2.7. Issues identified in the evaluation of the Third Package...........................................................79
3. SUBSIDIARITY................................................................................................................80
3.1. The EU's right to act .................................................................................................................80
3.2. Why could Member States not achieve the objectives of the proposed action sufficiently by
themselves?...........................................................................................................................................80
3.3. Added-value of action at EU-level ............................................................................................82
4. OBJECTIVES.....................................................................................................................83
4.1. Objectives and sub-objectives of the present initiative ............................................................83
18
4.2. Consistency of objectives with other EU policies......................................................................84
5. POLICY OPTIONS ...........................................................................................................87
5.1. Options to address Problem Area I (Market design not fit for an increasing share of variable
decentralized generation and technological developments) ..................................................................88
Overview of the policy options..................................................................................................88
Option 0: Baseline Scenario – Current Market Arrangements ..................................................89
Option 0+: Non-regulatory approach ........................................................................................90
Option 1: EU Regulatory action to enhance market flexibility ..................................................91
5.1.4.1. Sub-option 1(a): Level playing field amongst participants and resources .......................93
5.1.4.2. Sub-option 1(b): Strengthening short-term markets .......................................................95
5.1.4.3. Sub-option 1(c): Pulling demand response and distributed resources into the market..98
Option 2: Fully Integrated EU market......................................................................................102
For Option 1 and 2: Institutional framework as an enabler ....................................................104
Summary of specific measures comprising each Option.........................................................106
5.2. Options to address Problem Area II (Uncertainty about sufficient future generation
investments and uncoordinated capacity markets)..............................................................................110
Overview of the policy options................................................................................................110
Option 0: Baseline Scenario – Current Market Arrangements ................................................111
Option 0+: Non-regulatory approach ......................................................................................112
Option 1: Improved energy market - no CMs..........................................................................112
Option 2: Improved energy market – CMs only when needed, based on a common EU-wide
adequacy assessment) ...........................................................................................................................114
Option 3: Improved energy market - CMs only when needed, based on a common EU-wide
adequacy assessment, plus cross-border participation.........................................................................116
Option 4: Mandatory EU-wide or regional CMs ......................................................................117
Discarded Options ...................................................................................................................117
Summary of specific measures comprising each Option.........................................................117
5.3. Options to address Problem Area III (When preparing or managing crisis situations, Member
States tend to disregard the situation across their borders) ................................................................120
Overview of the policy options................................................................................................120
Option 0: Baseline scenario – Purely national approach to electricity crises..........................120
Option 0+: Non-regulatory approach ......................................................................................121
Option 1: Common minimum rules to be implemented by Member States...........................122
Option 2: Common minimum rules to be implemented by Member States, plus regional co-
operation ...............................................................................................................................................124
Option 3: Full harmonisation and decision-making at regional level ......................................127
Discarded Options ...................................................................................................................128
Summary of specific measures comprising each Option.........................................................128
5.4. Options to address Problem Area IV (Slow deployment and low levels of services and poor
market performance)...........................................................................................................................132
Overview of the policy options................................................................................................132
Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer
engagement and poor data flows..........................................................................................................132
Option 0+: Non-regulatory approach to address competition and consumer engagement ...133
Option 1: Flexible legislation addressing all problem drivers..................................................134
Option 2: EU Harmonization and extensive safeguards for consumers addressing all problem
drivers 136
Summary of specific measures comprising each Option.........................................................137
6. ASSESSMENT OF THE IMPACTS OF THE VARIOUS POLICY OPTIONS ....... 139
6.1. Assessment of economic impacts for Problem Area I (Market design not fit for an increasing
share of variable decentralized generation and technological developments ......................................139
19
Methodological Approach .......................................................................................................139
6.1.1.1. Impacts Assessed ...........................................................................................................139
6.1.1.2. Modelling and use of studies .........................................................................................140
6.1.1.3. Summary of Main Impacts .............................................................................................140
6.1.1.4. Overview of Baseline (Current Market Arrangements) .................................................141
Policy Sub-option 1(a) (Level playing field amongst participants and resources) ...................144
6.1.2.1. Economic impacts ..........................................................................................................144
6.1.2.2. Who would be affected and how...................................................................................147
6.1.2.3. Administrative impact on businesses and public authorities.........................................147
Impacts of Policy Sub-option 1(b) (Strengthening short-term markets) .................................147
6.1.3.1. Economic Impacts ..........................................................................................................147
6.1.3.2. Who would be affected and how...................................................................................150
6.1.3.3. Administrative impact on businesses and public authorities.........................................150
Impacts of Policy Sub-option 1(c) (Pulling demand response and distributed resources into the
market) 151
6.1.4.1. Economic Impacts ..........................................................................................................151
6.1.4.2. Who would be affected and how...................................................................................152
6.1.4.3. Impact on businesses and public authorities.................................................................153
Impacts of Policy Option 2 (Fully integrated EU market) ........................................................154
6.1.5.1. Economic Impacts ..........................................................................................................154
6.1.5.2. Who would be affected and how...................................................................................155
6.1.5.3. Impact on businesses and public authorities.................................................................155
Environmental impacts of options related to Problem Area I.................................................155
Summary of modelling results for Problem Area I ..................................................................156
6.2. Impact Assessment for Problem Area II (Uncertainty about future generation investments and
fragmented capacity mechanisms).......................................................................................................164
Methodological Approach .......................................................................................................164
6.2.1.1. Impacts Assessed ...........................................................................................................164
6.2.1.2. Modelling .......................................................................................................................164
6.2.1.3. Overview of Baseline (Current Market Arrangements) .................................................165
Impacts of Policy Option 1 (Improved energy markets - no CMs )..........................................166
6.2.2.1. Economic Impacts ..........................................................................................................166
6.2.2.2. Who would be affected and how...................................................................................167
6.2.2.3. Administrative impact on businesses and public authorities.........................................167
Impacts of Policy Option 2 (Improved energy markets – CMs only when needed, based on a
common EU-wide adequacy assessment) .............................................................................................168
6.2.3.1. Economic Impacts ..........................................................................................................168
6.2.3.2. Who would be affected and how...................................................................................169
6.2.3.3. Impact on businesses and public authorities.................................................................169
Impacts of Policy Option 3 (Improved energy market – CMs only when needed, plus cross-
border participation)..............................................................................................................................170
6.2.4.1. Economic Impacts ..........................................................................................................170
6.2.4.2. Who would be affected and how...................................................................................170
6.2.4.3. Impact on businesses and public authorities.................................................................171
Environmental impacts of options related to Problem Area II................................................171
Overview of modelling results for Problem Area II .................................................................171
6.2.6.1. Improved Energy Market as a no-regret option ............................................................171
6.2.6.2. Comparison of Options 1 to 3 ........................................................................................173
6.2.6.3. Delivering the necessary investments............................................................................178
6.2.6.4. Level and volatility of wholesale prices..........................................................................185
6.3. Impact Assessment for problem Area III (reinforce coordination between Member States for
preventing and managing crisis situations) ..........................................................................................187
Methodological Approach .......................................................................................................187
Impacts of Policy Option 1 (Common minimum rules to be implemented by Member States)
188
6.3.2.1. Economic impacts ..........................................................................................................188
6.3.2.2. Who would be affected and how...................................................................................189
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6.3.2.3. Impact on businesses and public authorities.................................................................189
Impacts of Policy Option 2 (Common minimum rules to be implemented by Member States
plus regional co-operation)....................................................................................................................190
6.3.3.1. Economic impacts ..........................................................................................................190
6.3.3.2. Who would be affected and how...................................................................................192
6.3.3.3. Impact on businesses and public authorities.................................................................192
Impacts of Policy Option 3 (Full harmonisation and full decision-making at regional level)...193
6.3.4.1. Economic impacts ..........................................................................................................193
6.3.4.2. Who would be affected and how...................................................................................193
6.3.4.3. Impact on businesses and public authorities.................................................................194
6.4. Impact Assessment for Problem Area IV (Increase competition in the retail market).............194
Methodological Approach .......................................................................................................194
Impacts of Policy Option 0+ (Non-regulatory approach to improving competition and
consumer engagement).........................................................................................................................194
6.4.2.1. Economic Impacts ..........................................................................................................194
6.4.2.2. Who would be affected and how...................................................................................195
6.4.2.3. Impact on businesses and public authorities.................................................................196
Impacts of Policy Option 1 (Flexible legislation addressing all problem drivers) ....................196
6.4.3.1. Economic Impacts ..........................................................................................................196
6.4.3.2. Who would be affected and how...................................................................................197
6.4.3.3. Impact on businesses and public authorities.................................................................198
Impacts of Policy Option 2 (Harmonization and extensive safeguards for consumers
addressing all problem drivers) .............................................................................................................199
6.4.4.1. Economic Impacts ..........................................................................................................199
6.4.4.2. Who would be affected and how...................................................................................200
6.4.4.3. Impact on businesses and public authorities.................................................................201
Environmental impacts............................................................................................................202
Impacts on fundamental rights regarding data protection .....................................................202
6.5. Social impacts.........................................................................................................................205
7. COMPARISON OF THE OPTIONS............................................................................ 208
7.1. Comparison of options for adapting market design for the cost-effective operation of variable
and often decentralised generation, taking into account technological developments........................208
7.2. Comparison of Options for facilitating investments in the right amount and in the right type of
resources for the EU.............................................................................................................................210
7.3. Comparison of options for improving Member States' reliance on each other in times of system
stress and reinforcing coordination between Member States for preventing and managing crisis
situations.............................................................................................................................................213
7.4. Comparison of options for addressing the causes and symptoms of weak competition in the
energy retail market ............................................................................................................................215
7.5. Synergies, trade-offs between Problem Areas and sequencing ..............................................217
Synergies..................................................................................................................................217
Trade-offs ................................................................................................................................219
Sequencing of measures..........................................................................................................220
8. MONITORING AND EVALUATION.......................................................................... 220
8.1. Future monitoring and evaluation plan..................................................................................220
8.2. Annual reporting by ACER and evaluation by the Commission ...............................................221
Annual reporting by ACER .......................................................................................................221
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Evaluation by the Commission ................................................................................................221
8.3. Monitoring by the Electricity Coordination Group..................................................................221
8.4. Operational objectives ...........................................................................................................222
8.5. Monitoring indicators and benchmarks..................................................................................223
9. GLOSSARY AND ACRONYMS.................................................................................... 225
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1. INTRODUCTION
1.1. Background and scope of the market design initiative
Context of the initiative
1.1.1.1.The gradual process of creating an internal electricity market
Well-functioning energy markets that ensure secure energy supplies at competitive prices
are key for achieving growth and consumer welfare in the European Union.
Since 1996, the European Union has put in place legislation to enable the transition from
an electricity system traditionally dominated by vertically integrated national incumbents
that owned and operated all the generation and network assets in their territories to
competitive, well-functioning and integrated electricity markets. The first step was the
adoption of the First Energy Package (1996 for the electricity sector and 1998 for the gas
sector), which allowed for the partial opening of the market where the largest consumers
were given the right to choose their supplier. The Second Energy Package (2003)
introduced changes concerning the structure of the vertically integrated companies (legal
unbundling), the preparation of the full opening of the market by 1 July 2007 and the
reinforcement of the powers of the national regulators. The most recent comprehensive
reform of European energy market rules, the Third Internal Energy Market Package
(2009)1
('Third Package') has principally aimed at improving the functioning of the internal
energy market and resolving structural problems.
Since the adoption of the Third Package, electricity policy decisions have enabled
competition and increasing cross-border flows of electricity, notably with the introduction
of so called "market coupling"2
and "flow-based" capacity allocation. In spite of significant
differences in the maturity of markets in Europe, overall electricity wholesale markets are
increasingly characterised by fair and open competition, and – though still insufficient –
competition is also taking root at the retail level.
1.1.1.2.The Union's policy concerning climate change
The decarbonisation of EU economies is at the core of the EU’s agenda for climate change
and energy. The targets in the Climate and Energy Package (2007) require Member States
to cut their greenhouse gas emissions by 20% (from 1990 levels), to produce 20% of their
energy from renewable energy sources (RES), and to improve energy efficiency by 20 %
(the '2020 targets').3
In 2011, the European Union committed to reduce greenhouse gas emissions to 80-95%
below 1990 levels by 2050. For this purpose, the European Commission adopted an Energy
1
Section 1.1.2.1 provides a more detailed explanation of the Third Energy Package.
2
A mechanism that manages cross-border electricity flows in an optimal way, smoothing out price
differences between Member States.
3
http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52008DC0030&from=EN
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Roadmap4
and a roadmap for moving to a competitive low carbon economy5
exploring
the transition of the energy system in ways that would be compatible with this greenhouse
gas reductions target while also increasing competitiveness and security of supply. The
2050 roadmap will require a higher degree of decarbonisation from the electricity sector
compared to other economic sectors.
These ambitions were reaffirmed by the European Council of October 2014, which
endorsed targets for 2030 of at least 40 % for domestic greenhouse gas emissions reduction
(compared to 1990 levels), at least 27 % for the share of renewable energy consumption,
binding at EU level and at least 27 % energy savings, to be reviewed by 2020, having in
mind an EU level of 30% (the '2030 targets').6
At the Paris climate conference (COP21) in December 2015, 195 countries adopted the
first-ever legally binding global climate deal. The European Council of March 2016
confirmed the EU's commitment to implement the 2030 targets. The Paris Agreement was
ratified by the European Union and entered into force on 4 November 2016..
1.1.1.3.Paradigm shift in the electricity sector
The Union's goals for climate change and energy have led to a paradigm shift in the means
employed to generate electricity: since the adoption of the Third Package, there has been
a move towards the deployment of capital-intensive low marginal cost, variable and often
decentralised electricity from RES E (mostly from solar and wind technologies) that is
expected to become more pronounced by 2030.
The increasing penetration of RES E is driven inter alia by the objective to reduce
greenhouse gas emissions in line with the 2020 and 2030 targets. The 2030 greenhouse gas
emission reduction target is to be delivered through reducing emissions by 43% compared
to 2005 for the sectors in the EU's ETS7
(including the electricity sector and industry) and
by 30% compared to 2005 for the sectors outside the ETS. Within the electricity sector,
the reduction of greenhouse gas emissions is supported by the Renewable Energy
Directive8
, the ETS and the additional national policies by Member States to increase the
share of renewables in the energy mix.
The Renewable Energy Directive established a European framework for the promotion of
renewable energy, setting mandatory national renewable energy targets for achieving a
20% EU share of renewable energy in the final energy consumption and a 10% share of
4
http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52011DC0885&from=EN
5
COM (2011) 112; http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:52011DC0112
6
http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdata/en/ec/145397.pdf
7
The ETS works on the 'cap and trade' principle. A 'cap', or limit, is set on the total amount of certain
greenhouse gases that can be emitted by the factories, power plants and industrial installations in the
system. The cap is reduced over time so that total emissions fall. This policy instrument equally fosters
penetration of RES E as it renders production of electricity from non- or less-emitting generation
capacity comparatively more economical in relation to more carbon intensive capacity.
8
Directive 2009/28/EC on the promotion of the use of energy from renewable sources, OJ L 140/16,
5.6.2009
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energy from renewable sources in transport by 2020. These objectives have translated into
a need to foster the increased production of electricity from reneweble energy sources.9
In parallel with the increased deployment of variable and decentralized RES E, the
increasing digitalisation of electricity networks and the environment behind the meter now
enables many elements of the electricity system to be operated more flexibly and
efficiently in the context of RES E generation. It also allows smaller actors to play an
increasingly important part in the market on both the supply side and – crucially – the
demand side, potentially untapping a vast new system resource.
From the consumer's perspective, increasingly intelligent grids unlock a host of other
possibilities, including innovative new products and services, lower entry barriers for new
suppliers, and improved billing and switching. This promises to unlock value and improve
the consumer experience – provided the legislative framework adapts to the changing
needs and possibilities. Indeed, fully engaging end consumers will be essential to realizing
the full benefits that the digital transformation can bring in terms of grid flexibility.
Moreover, electricity demand will progressively reflect the increasing electrification of
transport and heating.
The challenges the EU's electricity systems face are reflected in the European Commission
Communication of February 2015 on “A Framework Strategy for a Resilient Energy Union
with a Forward-Looking Climate Change Policy”10
where the Commission announced a
new electricity market design linking wholesale and retail markets. As part of the
legislative reform process needed to establish the Energy Union, it also announced new
legislation on security of electricity supply.
In the light of the Energy Union Framework Strategy, the present impact assessment
reflects and analyses the need and policy options for a possible revision of the main
framework governing electricity markets and security of electricity supply policies in
Europe. The new electricity market design contributes strongly to the overall Energy Union
objectives of securing low carbon energy supplies to the European consumers at least costs.
1.1.1.4.The vision for the EU electricity market in 2030 and beyond
The Energy Union Framework Strategy sets out the vision of an Energy Union "with
citizens at its core, where citizens take ownership of the energy transition, benefit from
new technologies to reduce their bills, participate actively in the market, and where
vulnerable consumers are protected". Well-functioning energy markets that ensure secure
energy supplies at competitive prices are important for achieving growth and consumer
welfare in the European Union. The future of the entire energy sector will, to a significant
extent, be shaped by the evolution of the electricity sector, which is key to addressing
climate change. With the quick ratification of the global Paris Agreement on climate
change and its subsequent entry into force, it becomes clear how important it is for all
9
Moreover, following the 2030 targets set by the European Council in October 2014, the Commission
published a Communication on A Framework Strategy for a Resilient Energy Union with a Forward-
Looking Climate Change Policy of February 2015 confirming the political commitment for the European
Union to become the world leader in renewable energy.
10
EC (2015a) - COM(2015) 80 final
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parties to the agreement, including the EU, to deliver on the clean energy transition on the
ground. In fact, amongst all sectors that make up our energy system, electricity is the most
cost-effective to decarbonise. Currently 27.5% of Europe's electricity is produced from
renewable energy sources. The share of RES E in electricity generation needs to almost
double by 2030 in order for the EU to meet its 2030 energy and climate targets cost-
effectively. This will require creating the right conditions for the massive amount of
investment needed for this energy transition to come about. At the same time electricity
markets will have to adapt to the radical change in the structure of the generation pattern
which will foremost require creating a more flexible market, going across borders, that is
able to allow more active participation of a much wider range of actors.
The EU's vision of the electricity system in 2030 is therefore based on a functioning market
that is adapted to implementing the decarbonisation agenda at least cost together with a
revised EU ETS. A well-functioning electricity market is also the most efficient tool to
ensure secure electricity supplies at the lowest reasonable cost.
The transition of the energy system towards the 2030 vision
The starting point is the existing reality, which dates back to an era with large-scale,
centralised power plants, largely fuelled by fossil fuels, had the key aim of supplying every
home and business in a delineated area – typically a Member State – with as much
electricity as they wanted, and in which consumers – households, businesses and industry
– were passive users.
However, the electricity market is undergoing profound change and requires a new set of
rules to ensure secure supplies, competitiveness while enabling cost-effective
decarbonisation. The electricity market of the next decade will be characterised by more
variable and decentralised electricity production, an increased interdependence between
Member States and new technological opportunities for customers to reduce their bills and
actively participate in electricity markets through demand response, self-consumption or
storage.
The electricity market design initiative aims to improve the functioning of the internal
electricity market in order to allow electricity to move freely to where and when it is most
needed, empower consumers, reap maximum benefits for society from cross-border
competition and provide the right signals and incentives to drive the right investments
compatible with climate change, renewable energy and energy efficiency ambitions.
The proposed initiative constitutes a next-step in a wider and longer evolutionary process
that will guide the EU's electricity markets towards the 2030 vision.
The 2030 electricity market is highly flexible and provides a level playing field amongst
all forms of generation as well as demand response…
The bulk of the new generation capacity is likely to come from renewable sources, mainly
wind and sun that are variable and predictable only to a limited extent. The future
electricity market will therefore need to be more flexible and liquid than today and allow
for integrated short-term trading. This would also set the ground for renewable energy
producers – who will over time acquire increasing share in generation - to equally access
energy wholesale markets and to compete on an equal footing with conventional energy
producers. Short-term markets will also allow Member States to share their resources
across all "time frames" (forward trading, day-ahead, intraday and balancing), taking
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advantage of the fact that peaks and weather conditions across Europe do not occur at the
same time. This would provide maximum opportunity to meet the flexibility needs and
balance the market. The sequence of forward markets and spot markets - day-ahead,
intraday and balancing - will optimise prices and the system in the short-run and will reveal
the true value of electricity and, therefore, provide appropriate investments signals in the
long-run.
The closer to real time electricity is traded (supply and demand matched), the less the need
for costly interventions by TSOs to maintain a stable electricity system. Although TSOs
would have less time to react to schedule deviations and unexpected events and forecast
errors, the liquid, better interconnected balancing markets, together with the regional
procurement of balancing reserves and more balancing actors and products available from
both demand and supply side, would be expected to provide them adequate and more
efficient resources in order to manage the grid and facilitate RES E integration.
All this will help to create a level playing field not only among all modes of generation but
also the demand side. At the same time market distortions and rules that artificially limit
or favour the access of certain technologies to the grid would be removed. All market
participants would become gradually responsible for balancing their position in the market,
bearing financial responsibility for the imbalances they cause and would, therefore, be
incentivised to reduce the risk of such imbalances. The most cost-efficient sources of
electricity would be used first, curtailment of generation due to limited transmission and
distribution infrastructure would be a measure of last resort and confined to situations in
which no market-based responses (including storage and demand response) are available,
and subject to transparent rules known in advance to all market actors and adequate
financial compensation. All resources would be remunerated in the market on equal terms.
…and active consumers.
Ensuring that all consumers – big and small – can actively participate in the energy market
would unlock a vast system resource that could play an important role in reducing system
costs. Technology – including smart grids and smart homes - is already available and will
further develop to enable consumers to modulate their demand while maintaining comfort
and reducing costs.
In the future, consumers would be sufficiently incentivised to benefit from these
opportunities and thus demand response would be provided by all willing consumer
groups, including residential and commercial consumers either directly or through
intermediaries (like aggregators). This would further increase the flexibility of the
electricity system and the resources for the TSOs and DSOs to manage it. At the same time
it should lead to a much more efficient operation of the whole energy system.
Consumers would be able to react to price signals on electricity markets both in terms of
consumption and production; they would consume when prices are low, when there is
plenty of electricity available, and reduce their consumption at times of low electricity
production and high prices. To make this possible, consumers have access to a fit-for-
purpose smart metering system, smart homes and storage as well as electricity supply
contracts with prices linked dynamically to the wholesale markets.
More and more consumers would produce their own electricity. Such decentralised
production further strengthens security of supply and helps to implement the
decarbonisation agenda as most of this production comes from renewable sources. If
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combined with local storage solutions, consumers could significantly contribute to
balancing the distribution grids at local level. Analysis suggests that this development will
be progressive, and that most consumers would still remain connected to the distribution
grid to use it as back-up for when the prosumers' own generation is inadequate (e.g. for
sustained periods of low sunlight) or for the opportunity to sell excess electricity to the
market (e.g. during prolonged sunny periods when their installed storage is at full
capacity).
Reducing barriers to market entry for electricity suppliers and consumer engagement –
notably phasing out price regulation – results in increased competition at the retail level
allowing consumers to save money through better information and a wider choice of action.
This also helps drive the uptake of innovative new products and services that increase
system flexibility through demand response whilst catering to consumers' changing needs
and abilities.
In addition, DSOs would be enabled and incentivised, without compromising their
neutrality as system operators, to manage their networks in a flexible and cost-efficient
way – inter alia through revised tariff structures.
Increased cross-border trade is a pillar of the electricity market.
Competition and cross-border flows of electricity would further increase, with fully
coupled markets where price differences between Member States are smoothened out.
Electricity wholesale markets will be characterised by fair and open competition, including
across borders. Cooperation between TSOs will be enhanced by regional operational
centres. The cross-border cooperation of TSOs would be accompanied by an increased
level of cooperation between regulators and governments. An adequate cross-border
infrastructure remains crucial to underpin a well-functioning electricity market.
Increasingly investments are triggered by the market with a decreasing need for state
subsidies.
The enhanced market design, the revised renewables directive and the strengthened ETS
will all help to improve the viability of RES E investments, in particular as follows:
- Where the marginal producer is a fossil fired power plant, a higher carbon price
translates into higher average wholesale prices. The existing surplus of
allowances is expected to decrease due to the implementation of the Market
Stability Reserve and the higher Linear Reduction Factor, reducing the current
imbalance between supply and demand for allowances;
- greater system flexibility will be critical for better integration of RES E in the
system, reducing their hours of curtailment and the related forgone revenues;
improving overall system flexibility is equally essential to limit the merit-order
effect11
and thus in avoiding the erosion of the market value of RES E produced
electricity;
- the revision of priority dispatch rules, removal of must-run units, increasing
demand response and storage, together with the better functioning of the short-
term markets will strongly reduce or even eliminate the occurrence of negative
11
Also occasionally referred to as the 'cannibalisation effect'.
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prices – leading again to higher average wholesale prices (especially during the
hours with significant variable RES E generation);
- improved rules for intraday and balancing markets will increase their liquidity
and allow access to those markets for all resources, thus helping generators
reduce their balancing costs;
- removing existing (explicit or implicit) restrictions for the participation of all
resources to the reserve and ancillary services markets will allow RES E to
generate additional revenues from these markets;
- price signals reflecting the actual value of electricity at each point of time, as
well as the value of flexibility, will ensure that the flexible assets most needed
for the system are invested in or, at least, are less likely to be decommissioned.
- Low exit barriers to facilitate exit of overcapacities.
The above mentioned changes will all help to improve the competitive situation of RES E
and reduce the need for dedicated support.
The results of the modelling for this Impact Assessment indicate that investments in the
most mature renewable technologies could be driven by the market by 2030 (such as
certain solar PV and onshore wind). At the beginning of the period, generation over-
capacity in certain areas, weaker investment signal from the ETS and low wholesale market
prices and still high RES E technology costs, make the case for investments in RES E
technologies more difficult. The underpinning modelling and analysis, points that the RES
E funding gap in 2020 is gradually reducing towards 2030 as the market conditions
improve. Less mature RES E technologies, needed for meeting the 2030 and 2050 energy
and climate objectives, such as off-shore wind, will likely need some form of support to
cover at least a fraction of total project costs (complementing the revenues obtained from
the energy markets) throughout the 2021-2030 period.
The picture also depends on regions. RES E technologies could be more easily financed
by the market in the regions with the highest potential (e.g. onshore wind in the Nordic
region or solar in Southern Europe), while RES E could continue to require support in the
British Isles and in Central Europe. Conditions however also depend on the cost of capital.
At the same time it has to be acknowledged that whether and what point in time financing
of RES E through markets alone will actually take off remains difficult to predict. This is
because financing of capital intensive technologies such as most RES E through markets
based on marginal cost pricing will remain challenging. In the absence of measures that
address system flexibility, higher penetration of RES with low marginal cost could reduce
the market value that such RES E can actually achieve. Removing barriers to the
flexibilisation of demand and improving the responsiveness of demand and supply to price
signals stands out as a key measure in this regards in order to further stabilise the revenue
of RES E producers from the market.
On the other hand the future capacity of RES to be financed through the market will also
depend on certain conditions outside of the market design and ETS prices, such as
continued decrease in the costs of technologies, availability of capital at a reasonable price,
social acceptance and sufficiently high and stable fossil fuel prices.
While the market reforms described above are therefore no regret options to facilitate RES
investment, support schemes will still be needed at least for a transitional period. It is
therefore essential to further reform such schemes to make them as market-oriented as
possible.
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… with a market-based and more Europeanised approach to support schemes to cover any
investment gap .
Where needed, support will be (i) cost-effective and kept to a minimum, and (ii) will create
as little distortions as possible to the functioning of electricity markets, and to competition
between technologies and between Member States. The legal frame for RES E support
schemes would ensure sufficient investor certainty over the 2021-2030 period and require
the use (where needed) of market-based and cost-effective schemes, based on the design
of emerging best practices. Auctions could introduce competitive forces to determine the
level of support needed on top of market revenues and incentivise RES E producers to
develop business models that maximise market-based revenues. The use of tenders would
imply a natural phase-out mechanism for support, determining the remaining level of
support required to bridge any financing gap. The continued participation of small and
local actors, including energy communities, in the energy transition should be ensured in
this process.
The market should also provide, as a principle, security of supply.
By 2030, the market, as described above, could in principle successfully attract the required
investments to ensure adequate matching of supply and demand.
Today, most of the EU's power markets have more capacity than needed. However, with
demand increasing, e.g. due to E-Mobility and heat pumps, and older power plants retiring
supply margins are likely to get tighter. Therefore, a legal framework needs to be in place
to allow for the formation of electricity prices that send the signals for tomorrow's
investments. In this context, scarcity prices will become more and more important to
provide the right incentives for the operation of resources (including for demand response)
when they are most needed. Hedging products which suppliers can buy to protect
themselves against peaks are already available now and more innovative tools are expected
to be brought forward by market participants without the need for additional intervention
by national authorities. This will also provide opportunities for generators (who will be
natural provider of such hedging tools) to secure further revenues.
In the new market framework capacity mechanisms might only be considered if a residual
risk to security of supply can be proven after underlying market distortions have been
removed and the contribution of market integration to security of supply has been taken
into account.
The legal framework will provide tools to facilitate an objective case-by-case judgement
on whether the introduction of capacity mechanisms is needed and set out measures to
ensure that their potentially distortive effects are kept at a minimum, while placing them
in a more regional context. Accordingly, their need would have to be proven against an
EU-wide system adequacy assessment and they would have to allow for cross-border
participation to minimise distortions of investment incentives across the borders. Capacity
mechanisms would be designed in a way as to not discriminate against different generation
technologies and demand side capacities. Additionally, where need has been demonstrated
for such mechanisms, Member States should take into account how such mechanisms
would impact the achievement of the decarbonisation objectives.
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Member States should regularly review their resource adequacy12
situation and phase out
capacity mechanisms once the underlying market or regulatory concerns have been
resolved.
Despite best efforts to build an integrated and resilient power market, crisis situations can
never be excluded. The potential for crisis situation increases with climate change (i.e.
extreme weather conditions) and with the emergence of new areas that are subject to
criticalities (i.e. malicious attacks, cyber-threats). Such crises tend to often have an
immediate cross-border effect in electricity. The legal framework would provide tools to
ensure that national security of supply policies are better coordinated and aligned to tackle
possible crisis situations, in particular those that affect several countries at the same time.
Scope of the initiative
1.1.2.1.Current relevant legislative framework
EU's electricity markets are currently regulated at EU level by a series of acts collectively
referred to as the "Third Package"13
.
The main objectives of the Third Package were:
- Improving competition through better regulation, unbundling and reducing
asymmetric information;
- Improving security of supply by strengthening the incentives for sufficient
investment in transmission and distribution capacities; and,
- Improving consumer protection and preventing energy poverty.
The Third Package mainly focused on improving the conditions for competition as
resulting from previous generations of legislation by improving the level playing field. The
most important root cause for the lack of competition identified at the time14
was the
existence of vertically integrated companies, which not only controlled essential facilities
(such as electricity transmission systems) but also enjoyed significant market power in the
wholesale and, often, retail markets. Many of the measures associated with the Third
Package sought to directly or indirectly address this issue, such as by improving the
12
As not only generation, but also demand response or storage can solve problems of situations in which
demand exceeds production, this Impact Assessment uses the term "resource adequacy" instead of
"generation adequacy" (other authors refer to "system adequacy").
13
The relevant elements of the Third Package as regards electricity are Directive 2009/72 of the European
Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in
electricity and repealing Directive 2003/54/EC, OJ L 211, 14.8.2009, p. 55–93; Regulation (EC) No
714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the
network for cross-border exchanges in electricity repealing Regulation (EC) No 1228/2003. OJ L 211,
14.8.2009, p. 15–35 and Regulation (EC) No 713/2009 of the European Parliament and of the Council
of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators. OJ L 211, 14.8.2009,
p. 1–14. The Third package also covered other acts, in particular acts related to the regulation of gas
markets. However, only one of these acts is pertinent for the present impact assessment – the Gas
Directive.
14
In the impact assessment for the Third Package (SEC(2007) 1179/2 http://ec.europa.eu/smart-
regulation/impact/ia_carried_out/docs/ia_2007/sec_2007_1179_en.pdf.
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unbundling regime, strengthening regulatory oversight, improving the conditions for cross-
border market integration and lowering entry barriers such as by improving transparency.
The Third Package also created the possibility to enact secondary legislation concerning
cross-border issues, often referred to as network codes or guidelines ('network codes')15
,
and provided a mandate for developing these network codes (as well as other tasks related
to the EU's electricity markets) to transmission system operators within the ENTSO-E16
and to national regulatory authorities, within the Agency for the Cooperation of Energy
Regulators ('ACER')17
.
The main framework for electricity security of supply in the Union is currently Directive
2005/89/EC ("Security of Electricity Supply Directive' or 'SoS Directive'")18
. This SoS
Directive requires Member States to take certain measures with the view to ensuring
security of supply, but leaves it by and large to the Member States how to implement these
measures. The Third Package complemented the SoS Directive and superseded de facto
some of its provisions.
1.1.2.2.Policy development subsequent to the Third Package
The present initiative builds on previous related policy initiatives and reports that
intervened since the adoption of the Third Package and the Security of Electricity Supply
Directive, in particular:
- "Report on the progress concerning measures to safeguard security of electricity
supply and infrastructure investment" COM (2010) 330 final19
;
- "Delivering the internal electricity market and making the most of public
interventions" (C(2013) 7243). This Communication was accompanied inter alia
by a Commission Staff working document (SWD(2013)438) entitled "Generation
Adequacy in the internal electricity market – guidance on public intervention";
- Communication on the "Progress towards completing the Internal Energy Market"
COM(2014) 634 final. This Communication emphasized that energy market
integration has delivered many positive results but that, at the same time, further
steps are needed to complete the internal market;
- "Communication on Energy Security" (COM(2014)330). This Communication
emphasised inter alia the need achieve a better functioning and a more integrated
energy market;
- Special Report by the European Court of Auditors "Improving the security of
energy supply by developing the internal energy market: more efforts needed". This
15
For an overview of these network codes and guidelines and their pertinence to the present initiative,
please refer to Annex VII.
16
https://www.entsoe.eu/about-entso-e/inside-entso-e/official-mandates/Pages/default.aspx
17
http://www.acer.europa.eu/en/The_agency/Mission_and_Objectives/Pages/default.aspx
18
Directive 2005/89/EC of the European Parliament and of the Council of 18 January 2006 concerning
measures to safeguard security of electricity supply and infrastructure investment, OJ L 33, 4.2.2006, p.
22–27.
19
http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52010DC0330&from=EN
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special report made nine recommendations to reap the benefits of market
integration20
;
- "Communication on energy prices and costs in Europe" (COM(2014) 21 /2) and
the accompanying "Energy prices and costs report" (SWD(2014)020 final 2)
highlighting inter alia the competiveness of the EU's retail electricity markets, the
missing link between wholesale and retail prices and the need for EU cooperation
by DSOs as well as the Energy prices and costs report (SWD(2016)XX21
, this
report inter alia that shed light on the drivers of retail and wholesale price
developments;
- "Delivering a new deal for energy consumers" (COM(2015) 339). This
Communication laid out the Commission's intention to enable all consumers to
fully participate in the energy transition, taking advantage of new technologies that
enable wholesale and retail markets to be better linked.
- The Commisison published a study on "Investment perspectives in electricity
markets"22
- Technical Report23
by the European Commission on "The economic impact of
enforcement of competition policies on the functioning of EU energy markets". The
report includes an assessment of the intensity of competition in the energy
markets24
(both wholesale and retail) and points out that, between 2005 and 2012,
the intensity of competition in European energy markets may have declined25
.
- The Commission Staff working document (SWD(2015)249) entitled "Energy
Consumer Trends 2010 - 2015" presents market research into the problems that
energy consumers continue to be confronted with.
- The Commission launched a a sector inquiry into national capacity mechanisms,
The resulting "Interim Report of the Sector Inquiry on Capacity Mechanisms"
(SWD SWD(2016) 119 final)26
points out that there is a lack of adequate
assessment of the actual need for capacity mechanisms. It also appears that some
capacity mechanisms in place could be better targeted and more cost effective. It
emphasizes the need to design capacity mechanisms with transparent and open
rules of participation and a capacity product that does not undermine the
functioning of the electricity market, taking into account cross-border participation.
1.1.2.3.Scope and summary of the initiative
In line with the Union's policy on climate change and energy, the proposed initiative aims
at deepening energy markets and setting a framework governing security of supply policies
that enables the transition towards a low carbon electricity production.
20
http://www.eca.europa.eu/en/Pages/DocItem.aspx?did=34751
21
Report to be published in conjunction with the present impact assessment..
22
"Energy Economic Developments, Investment perspectives in electricity markets". Institutional paper
003, 1 July 2015 http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf
23
Published on 16.11.2015, at http://ec.europa.eu/competition/publications/reports/kd0216007enn.pdf
24
Ibid Section 3.3 of the non-technical summary at p. 23.
25
Based on the productivity dispersion and the Boone indicator over this period, ibid Section 3.4
"Summary of key findings" at p. 25.
26
Published on 13.04.2016 at: :
http://ec.europa.eu/competition/sectors/energy/capacity_mechanism_report_en.pdf
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The transition towards a low carbon electricity sector as well as technical progress will
have profound implications on the manner in which the electricity sector is organised and
the roles of market actors and consumers, not all of which can be foreseen with accuracy
today. As it cannot be predicted how the electricity markets and progress of innovation
will look like in a few decades from now, the proposed initiative constitutes a next step in
a wider and longer evolutionary process that will guide the EU's electricity markets
towards the future. The initiative will consequently not address the challenges that might
arise when operating a fully decarbonised power system.27
This initiative also aims at improving consumer protection and engagement for both
electricity and gas consumers28
.
Organisation and timing
1.1.3.1.Follow up on the Third Package
Full and timely transposition of the Directives of the Third Package has been a challenge
for the vast majority of the Member States. In fact, by the end of the transposition deadline
(March 2011), none of the Member States had achieved full transposition. However,
progess has been made and at present all of the infringement proceedings29
for partial
transposition of the Electricity Directive have been closed as the Member States achieved
full transposition in the course of the proceedings.
In addition to ensuring compliance of national rules with the Third Package, the
Commission has carried out assessments to identify and resolve problems concerning
incorrect transposition or bad application of the Third Package. On this basis, the
Commission has opened EU Pilot cases against a number of Member States. As of 7th July
2016, 8 of these EU Pilot cases have resulted in infringement procedures where, inter alia,
the violation of the EU electricity market rules is at stake.
In January 2014 the Directorate General for Energy of the European Commission ('DG
ENER') launched a public consultation on retail markets for energy.
Whilst preparing the single market progress report (COM(2014) 634 final), published on
13 October 2014, DG ENER decided to study a number of changes to the current
legislation.
The Commission (DG ENER) started in 2015 the preparatory work for the present impact
assessment to assess policy options related to the internal energy market for electricity and
27
For some of the arising issues and challenges see Chapter 2.3 in Investment Perspectives in Electricity
Markets, European Commission, DG EFCIN, 2015
http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf
28
With regards to gas consumers, only the consumer-related provisions of the Gas Directive are concerned:
Article 3 and Annex I. These address issues such as public service obligations, metering, billing and a
broad range of consumer rights that Member States shall ensure.
29
The Commission opened 38 infringement cases against 19 Member States for not transposing or for
transposing only partially the Directives.
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to security of electricity supply and consulted in July 2015 the public on a new energy
market design (COM(2015) 340 final)30
.
In April 2015, the Commission (DG Competition) launched a sector inquiry into national
capacity mechanisms. The Commission interim report and the accompanying Commission
staff working document, adopted on 13 April 2016 have provided a significant input for
the proposed initiative. This will be further completed by the final report.
1.1.3.2.Consultation and expertise
The Commission has conducted a number of wide public consultations on the different
policy areas covered by the present Impact assessment which took place between 2014 and
2016. In addition to the public consultations, it has organised a number of targeted
consultations with stakeholders throughout 2015 and 201631
.
Given the cross-cutting nature of the planned impact assessment work, the Commission
set up an inter-service steering group which included representatives from a selected
number of Commission Directorate Generals. The inter-service steering group held regular
meetings to discuss the policy options of the proposed initiatives and the preparation of the
impact assessment32
.
In parallel, the Commission has also conducted a number of studies mainly or specifically
for this impact assessment33
.
1.2. Interlinkages with parallel initiatives
The proposed initiatives are strongly linked to other energy and climate related legislative
proposals brought forward in parallel with the present initiative equally aimed at delivering
upon the five dimensions of the Energy Union, namely energy security, solidarity and trust,
a fully integrated European energy market, energy efficiency contributing to moderation
of demand, decarbonisation, research, innovation and competitiveness. These other energy
related legislative proposals include:
The Renewable Energy Package comprising the new Renewable Energy Directive
and bioenergy sustainability policy for 2030 ('RED II')
The RED II covers a number of measures deemed necessary to attain the EU binding
objective of reaching a level of at least 27% RES in final energy consumption by 2030
across the electricity, heating and cooling, and transport sectors. As regards electricity in
particular, the Renewables Directive proposes a framework for the design of support
schemes for renewable electricity, a framework for renewable self-consumption and
renewable energy communities, as well as various measures to reduce administrative costs
and burden.
30
https://ec.europa.eu/energy/sites/ener/files/documents/1_EN_ACT_part1_v11.pdf and
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
31
For more information on the consultation process, please refer to Annex 3
32
For more information on inter-service steering group, please refer to Annex 1.
33
For the list of studies and a summary description, please refer to Annex 5.
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Conversely, measures aimed at the integration of RES E in the market, such as provisions
on priority dispatch and access previously contained in the renewables directive are part
of the present market design initiative. The reflections on a revised Renewables Energy
Directive will include specific initiatives on support schemes for market-oriented, cost-
effective and more regionalised support to RES up to 2030 in case Member States were
opting to have them as a tool to facilitate target achievement. The Renewable Package is
expected to deal with legal and administrative barriers for self-consumption, whereas the
present package will address market related barriers to self-consumption.
The Renewable Energy package has synergies with the present initiative as it seeks to adapt
the current market design, optimised for large-scale, centralised power plants, to a suitable
one for the cost-effective operation of variable, decentralised generation of electricity
whilst taking into account technological progress creating the conditions for a cost efficient
achievement of the binding EU RES target in the electricity sector.
The enhanced market design will improve the viability of RES E investments, but
electricity market revenues alone might not prove sufficient in attracting renewable
investments in a timely manner and at the required scale to meet EU's 2030 targets. The
MDI and RED II impact assessments thus jointly come to the conclusion that the improved
electricity market, in conjunction with a reformed EU ETS could, under certain conditions,
deliver investments in the most mature renewable technologies (such as solar PV and
onshore wind). The underpinning modelling and analysis, points that the RES E funding
gap in 2020 is gradually reducing towards 2030 as market conditions improve. Less mature
RES E technologies, needed for meeting the 2030 and 2050 energy and climate objectives,
such as off-shore wind, will likely need some form of support to cover at least a fraction
of total project costs (complementing the revenues obtained from the energy markets)
throughout the 2021-2030 period. These technologies are required if RES E technologies
are to be deployed to the extent required for meeting the 2030 and 2050 energy and climate
objectives, and provide an important basis for the long-term competitiveness of an energy
system based on RES E.
Similarly, the progressive reform of RES E support schemes as proposed by the RED II
initiative, building on the Guidelines on State aid for environmental protection and energy
2014-2020 ('EEAG'), is a prerequisite for the results of the present initiative to come about.
In order to ensure that a market can function, it is necessary that market participants are
progressively exposed to the same price signals and risks. Support schemes based on feed-
in-tariffs prevent this and would need to be phased-out – with limited exemptions – and
replaced by schemes that expose all resources to price signals, as for instance by means of
premium based schemes. Such schemes would be made even more efficient by setting aid-
levels through auctioning as RES E investments projects will then be incentivised to
develop business models that optimise market based returns34
.
The issue is explored in more detail in section 6.2 of the present impact assessment and, in
particular, the RED II impact assessment.
34
See Box 7 and Annex IV for more information
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Commission guidance on regional cooperation
The forthcoming guidance on regional cooperation may set out general principles for
regional cooperation across all five dimensions of the Energy Union, described how these
principles are being addressed in this initiative and other legislative proposal for
Renewables and Energy Union governance, and will offer suggestions on how regional co-
operation, where it applies, can be made to work in practice.
The present initiative seeks to improve market functioning, and calls for a more regional
approach to system operation and security of supply. The guidance document should help
Member States best achieve regional co-operation, including in areas where the present
initiative mandates effective co-operation (e.g. the initiative calls on Member States to
prepare risk preparedness plans in a regional context, cf. infra).
The Energy Union governance initiative
The Energy Union governance initiative aims at ensuring a coordinated and coherent
implementation of the Energy Union Strategy across its five dimensions with emphasis on
the EU's energy and climate targets for 2030. This is established through a coherent
combination of EU-level and national action, a strengthened political process and with
reduced administrative burden.
With these objectives in mind, the draft Regulation is based on two pillars:
- Streamlining and integration of existing planning, reporting and monitoring
obligations in the energy and climate fields, in order to reduce unnecessary
administrative burden;
- A political process between Member States and the Commission with close
involvement of other EU institutions to support the achievement of the Energy
Union objectives, including notably the 2030 targets for greenhouse gas emission
reductions, renewable energy and energy efficiency.
In relation to this initiative the governance initiative will also streamline reporting
obligations by Member States and the Commission that are presently enshrined in the Third
Package.
The Energy Efficiency legislation ('EE')35
and the related Energy Performance of
Buildings Directive ('EPBD')36
including the proposals for their amendment.
In general terms, energy efficiency measures interact with the present initiative as they
affect the level and structure of electricity demand. In addition, energy efficiency measures
can alleviate energy poverty and consumer vulnerability. Besides consumer income and
energy prices, energy efficiency is one of the major drivers of energy poverty.
35
Directive 2012/27/EU of the European Parliament and of the Council of 25 October 2012 on energy
efficiency, amending Directives 2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and
2006/32/EC; OJ L 315, 14.11.2012, p. 1–56.
36
Directive 2010/31/EU of the European Parliament and of the Council of 19 May 2010 on the energy
performance of buildings. OJ L 153, 18.6.2010, p. 13–35.
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The provisions currently still in the current energy efficiency legislation concerning
metering and billing (to the extent related to electricity) may become part of the present
initiative as these relate to consumer conduct and their participation in the market which
are important issues in the context of the present initiative. This logic is reinforced by the
fact that the Third Package already contains closely related provisions on smart metering
deployment and fuel mix and comparability provisions in billing.
Similarly, all provisions on priority dispatch for Combined Heat and Power ('CHP')
previously contained in the energy efficiency legislation will be set out in the present
initiative as these provisions relate to the integration of these resources in the market and
as they are very similar to the priority dispatch provisions for RES E, also dealt with in the
present initiative.
The provisions previously contained in the energy efficiency legislation on demand
response will be set out in the present initiative37
because these relate to incentivising
flexibility in the market and participation of consumers in the market, both core subjects
of the present initiative. This logic is reinforced by the fact that the Third Package already
contains related provisions on demand response.
The Commission Regulation establishing a Guideline on Electricity Balancing
('Balancing Guideline')
The Balancing Guideline constitutes an implementing act that will be adopted using the
Electricity Regulation as a legal basis. The Balancing Guideline is closely related to the
present initiative. This is because efficient, integrated balancing markets are an important
building block for the consistent functioning of wholesale markets which in turn are needed
for a cost effective integration of RES E into the electricity market.
The Balancing Guideline aims at harmonising certain aspects of the EU's balancing
markets, with a focus on optimising the cross-border usage that TSOs make of the
balancing reserves that each have decided to contract individually, such as harmonisation
of the pricing methodology for balancing; standardisation of balancing products and merit-
order activation of balancing energy.
The present initiative seeks in contrast to focus on a more integrated approach to deciding
and contracting of the balancing reserves, as opposed to their usage, which touches upon
the optimal allocation of the cross-border transmission capacities and a regional approach
to balancing reserves.
Thus, the Balancing Guideline deals principally with exchanges of balancing energy
whereas the present initiative focusses on the exchange and sharing of balancing capacity.
The latter issue is much more political than the exchange of balancing energy and closely
related to other questions dealt with in the present initiative, such as regional TSO
cooperation or the reservation of transmission capacities. The assessments of the two
37
In a manner that will preserve DG Energy's ability to continue infringing Member States that have not
correctly implemented what is now Article 15(8) of the Energy Efficiency Directive.
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initiatives are fully coherent. Indeed, the implementation of the guidelines on electricity
balancing is part of the baseline for the present impact assessment38
.
Other relevant instruments
Other relevant instruments are the Commission proposal for setting national targets for
2030 for the sectors outside the EU's ETS, the revision of the EU's ETS for the period after
2020, EU's competition instruments and the EU state aid rules applicable to the energy
sector and clarified in the EEAG. and the decarbonisation of the transport sector initiative.
The manner in which this policy context is interacting with the present initiative is explored
further in section 4.2.
2. PROBLEM DESCRIPTION
2.1. Problem Area I: Market design not fit for an increasing share of variable
decentralized generation and technological developments
The European Union's policy to fight global warming will require the electricity systems
to shift from a generation mix that is mostly based on fossil fuels to a virtually decarbonised
power sector by 2050. Indeed, with the 2030 targets agreed by the October 2014 European
Council (EuCo 169/14) the share of electricity generated from renewable sources is
projected to be close to 49% of total electricity produced, while their share in total net
installed capacity is projected to be 62.45%39
.
Table 1: RES E % share in total net electricity generation
Year 2000 2005 2010 2015 2020 2025 2030
RES E total (TWh) 422 467 683 916 1,193 1,443 1,654
Total net generation (TWh) 2,844 3,119 3,168 3,090 3,221 3,317 3,397
RES E 15% 15% 22% 30% 37% 43% 49%
Source: PRIMES; based on EUCO27 scenario
Whereas renewable electricity can be produced by a variety of technologies, most new
installed capacity today is based on wind and solar power. By 2030, this is expected to be
even more pronounced.
Table 2: Share of variable RES E (solar and wind power) in RES E and total net
generation
Year 2000 2005 2010 2015 2020 2025 2030
Variable RES E (TWh) 22 72 171 378 618 820 995
Total RES E (TWh) 422 467 683 916 1,193 1,443 1,654
Variable RES E in RES E 5% 16% 25% 43% 52% 57% 62%
Variable RES E in total net generation 1% 2% 5% 12% 19% 25% 29%
Source: PRIMES; based on EUCO27 scenario
The patterns of electricity production from wind and sun are inherently more variable and
less predictable when compared to conventional sources of energy (e.g. fossil-fuel-fired
38
See also Section 5.1.2 of the present impact assessment and in the Annex IV on the modelling
methodology.
39
These figures are based on the PRIMES EUCO27 results.
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power stations) or flexible RES E technologies (e.g. biomass, geothermal or hydropower).
Weather-dependent production also implies that output does not follow demand.
Consequently, there will be times when renewables could cover a very large share – even
100% – of electricity demand and times when they only cover a minor share of total
consumption. While the demand-side and decentralized power storage could in theory
react to the availability of renewable energy sources and even to extreme variations, current
market arrangements do not enable most consumers to actively participate in electricity
markets either directly through price signals or indirectly through aggregation.
While renewable technologies and individual projects differ significantly in size (from
rooftop solar on households with 5 to 20 kW to several hundreds of MW for large offshore
wind parks), the majority of renewable investments are developed at comparatively small
scale. Given that the typical installation size of an onshore wind farm or a solar park is
generally multiple40
times smaller than of a conventional power station, the number of
power producing units and operators will increase significantly. Consequently, the
transition towards more renewables implies that more and more power will be generated
in a decentralised way. Market roles and responsibilities will have to be adapted.
Finally, these new installations will not necessarily be located next to consumption centres
but where there are favourable natural resources. This can create grid congestion and local
oversupply.
The transition towards a low carbon electricity production poses a number of challenges
for the cost-effective organisation and operation of Europe's power system and its
electricity markets. The existing market framework was designed in an era in which large-
scale, centralised power stations, primarily fired by fossil fuels, supplied passive customers
at any time with as much electricity as they wanted in a geographically limited area –
typically a Member State. This framework is not fit for taking up large amounts of variable,
often decentralised electricity generation nor for actively involving more consumers in
electricity markets.
The main underlying drivers are: (i) the inefficient organisation of short-term electricity
markets and balancing markets, (ii) exemptions from fundamental market principles, (iii)
consumers that do not actively engage in the market, (iv) consumers do not actively engage
in the market and demand response potential remains largely untapped; and (v) distribution
networks that are not actively managed and grid users are poorly incentivised.
40
The largest solar PV park in the EU is the 300 MW Cestas Park in France, http://www.pv-
magazine.com/news/details/beitrag/frances-300-mw-cestas-solar-plant-
inaugurated_100022247/#axzz4Cxalbrhc. The largest wind farm is the offshore farm "London array"
with 630 MW distributed over 175 turbines. By comparison, the largest nuclear power plant in Europe
is the Gravelines plant in France, with a net capacity of 5460MW. The largest coal-fired power station
in Europe is the Polish Bełchatów plant with a capacity of 5420 MW.
40
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Driver 1: Short-term markets, as well as balancing markets, are not efficiently
organised
Today's short-term markets are not efficiently organised, because they do not give all
resources – conventional power, renewables, the demand-side, storage – equal
opportunities to access these markets and because they do not fully take into account the
possible contribution of cross-border resources. The latter problem often originates from a
lack of coordination between national entities and a lack of harmonisation of rules, while
the former relates to the trading products themselves, e.g. their commitment period, which
sometimes are too restrictive to allow for a level playing field of all kinds of resources41
.
Short-term markets play a major role in any liberalised power system due to the
characteristics of electricity as a product. Electricity must be generated and transmitted as
it is consumed. The overall supply and demand needs to be in balance in physical terms at
any given point in time. This balance guarantees the secure operation of the electricity grid
at a constant frequency. Imbalances between injections and withdrawals of electricity
render the system unstable and, ultimately, may give rise to a black-out.
As a consequence, market participants need to be incentivised to have a portfolio of
electricity injections into and withdrawals from the network that net-out. Market
participants can adjust their portfolio by revising production and consumption plans and
selling or buying electricity42
. Efficient and liquid markets with robust price signals are
crucial to guide these decisions43
.
The fact that the production patterns from weather dependent RES E can only be predicted
with acceptable accuracy within hours, creates challenges for market parties and for system
operation. In the absence of efficient and liquid short-term electricity wholesale markets,
system operators have to take actions to balance the system and manage network
41
EPRG Working paper 1614 (2016) "Overcoming barriers to electrical energy storage: Comparing
California and Europe" by F. Castellano Ruz and M.G. Pollitt concludes: "In Europe, there is a need
to clarify the definition of EES, create new markets for ancillary services, design technology-neutral
market rules and study more deeply the necessity of EES."
42
Depending on the delivery period, bulk electricity can be traded on "spot markets" or "forward markets".
Spot markets are currently mainly "day-ahead markets" on which electricity is traded up to one day
before the physical delivery takes place. On "forward markets", power is traded for delivery further
ahead in time.
43
IEA "Re-powering markets" (2016) suggests: "A market design with a high temporal and geographical
resolution is therefore needed".
41
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congestions once the production forecasts become more precise. Moreover, operators of
RES E are unable to adjust their portfolios once the production forecasts become more
precise, leaving them exposed to risks and costs, when they deviate from their plans. An
increasing penetration of RES E thus requires efficient and liquid short-term markets that
can operate until very shortly before the time of physical delivery i.e. the moment when
electricity is consumed. The entire electricity system must become more flexible, also
through the progressive introduction of new flexible resources such as storage, to
accommodate variations in RES E production.
Current trading arrangements are however not optimised for a world in which market
participants have to adjust portfolios on short notice. The manner in which the trading of
electricity is arranged and the methods for allocating the network capacity to transmit
electricity are organised, allow for efficient trading of electricity in timeframes of one or
more days ahead of physical delivery. These arrangements befit well a world of
conventional electricity production that can be predictably steered but not the new
electricity landscape with a high share of renewables with limited forecasting abilities in a
day-ahead timeframe.
The current market framework already envisages that these short-term adjustments can be
made in intraday markets to correct. However, whilst liquidity has increased over the past
few years, there remains significant scope for further increases in these markets44
. As way
of illustration, in 2014, in the intraday timeframe, only five markets in Europe had a ratio
of traded energy to demand of greater than 1%45
. Further, progress remains in connecting
('coupling') national intraday markets in the same way as day-ahead markets. This can lead
to a low level of cross-border competition in intraday markets. In 2014 only 4.1% of
available interconnection capacity at the intraday stage was used, compared to 40% at day-
ahead.
Improving liquidity of intraday markets requires addressing various issues, including
removing the barriers that today exist for trading power across borders as well as providing
proper incentives to rebalance portfolios by trading until short notice before markets close.
In addition, technical rules of the market (i.e. products, bid sizes, gate closure times) are
often not defined with renewables or demand response in mind creating de facto barriers
for its participation.
Specific issues include a variation in commitment periods across Europe, with some
Member States choosing 15-minute and other Member States choosing 60-minute
products, and the time to which market participants can trade, which can be as short as 5
minutes or, in some instances, upto several hours before real time. There is also a difference
in how markets are organised: in continuously traded markets, transactions are concluded
throughout the trading period every time there is a match between bids and offers.
Transactions are concluded differently in auction markets, where previously collected bids
and offers are all matched at once at the end of the trading period.
The last market-based measure to net out imbalances between injections and withdrawals
of electricity is the balancing market. As such, the balancing market is not solely a
44
See Annex 2.2 for further details.
45
Spain (12.1%) Portugal (7.6%), Italy (7.4%) Germany (4.6%) Great Britain (4.4%). ACER, Market
Monitoring Report 2015
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technicality ensuring system stability but has significant commercial implications and, in
turn, implications for competition. Procurement rules often fit large, centralised power
stations but do not allow for equal access opportunities for smaller (decentralised)
resources, renewables, demand-side and batteries. ACER's market monitoring reports
revealed high levels of concentration within national balancing markets. TSOs are often
faced with few suppliers or (in case of vertically integrated TSOs) procure balancing
reserves from their affiliate companies. This, combined with a low degree of integration,
enables a limited number of generators to influence the balancing market outcome.
Moreover, the procurement rules can lower the overall economic efficiency of the power
system by creating so-called must-run capacity, i.e. capacity that does not (need to) react
to price signals from other markets, because it generates sufficient revenues from balancing
markets.
Beside procurement rules, there is a potential issue with procurement volumes due to
national sizing of reserves. Possible contributions of neighbouring resources are not
properly taken into account, thus over-estimating the amount of reserves to be procured
nationally.
Driver 2: Exemptions from fundamental market principles
Two fundamental principles of today's market framework are that (i) market participants
should be financially responsible for any imbalance in their portfolio and that (ii) the
operation of generation facilities should be driven by market prices. For a number of
reasons a wide range of exceptions from these principles exist today which could lead to
distortions, thus diminishing market efficiency.
The principle of financial responsibility for imbalances is often referred to as balancing
obligation. In many Member States, some market participants are fully or partly exempted
from this obligation, notably many renewable energy but also CHP generators. Exemptions
are typically granted on policy grounds, e.g. the existence of policy targets for renewables.
Such a special treatment constitutes a challenge for the cost-effective functioning of
electricity markets, because these technologies represent a significant share in total power
generation already and are expected to further grow in importance in the forthcoming
decade. For RES E, exemptions from balancing responsibility were initially justified on
the basis of significant errors in production forecasts being unavoidable (as production for
many RES E technologies is based on wheather) and on the absence of liquid short-term
markets which would have allowed RES E generators to trade electricity closer to real
time, thus reducing the error margin. Significant improvements have been made in
wheather forecasts, reducing the error margin. Part of these improvements was based on
financial incentives from increased balancing responsibilities46
. Furthermore, cross-border
integration and liquidity of short-term markets has improved over the last years, with
further progress expected over the coming years, such as through the progressive
penetration of storage, and following the present proposal. Thus, the underlying reasons
for the exemption of RES E from this principle have to be revisited.
46
ENTSO-E provided figures that following the introduction of balancing responsibility in one Member
States, the average hourly imbalance of PV installations improved from 11.2 % in 2010 to 7.0 % in
March 2016, and the average hourly imbalance of wind improved from 11.1 % to 7.4 % over the same
period.
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A consequence of this lack of balancing obligation is that plant operators have no incentive
to maintain a balanced portfolio. The balancing obligation is typically passed on to the
responsible system operator, a regulated party, meaning that their balancing costs will be
socialised. This represents a market distortion and lowers the liquidity and efficiency of
short-term markets as the concerned market operators do not become active on the short-
term market to balance their portfolio. So the absence of full balancing responsibility is in
fact a major driver preventing the emergence of liquid and efficient short-term markets.
Moreover, costs arising from forecast errors for renewables are likely higher than
necessary due to a lack of incentive to minimise them by short-term market operations.
This creates a higher than necessary burden on consumers' electricity bills.
The principle that the operation of generation facilities should be driven by market prices
is also referred to as economic dispatch. When a unit's variable production costs are below
market price, it is economically efficient to dispatch it first, because the operator generates
(gross) profits from selling electricity. This principle guarantees that power is produced at
the lowest cost to reliably serve consumers, while taking into account operational limits.
However, priority dispatch deviates from this principle, by giving certain technologies
priority independent of their marginal cost. This represents a market distortion and leads
to a sub-optimal market outcome.
Given the expected massive increase in share of wind and solar technologies, it is likely
that unconditional dispatch incentives for these technologies will aggravate the situation,
as will the fact that certain RES E technologies and often CHP have positive variable
production costs. The review of priority dispatch rules for RES E is thus closely related to
the review of rules on public support in the RED II. Compared to the impact on RES E
from low marginal cost technologies, fully merit order-based dispatch has more significant
impact on conventional generation (CHP and indigenous fuels) and high marginal cost
RES E (e.g. RES E based on biomass), as these technologies will not be dispatched first
under the normal merit order. Achieving merit order based dispatch will in these cases
allow to use flexibility resources to their maximum extent, creating e.g. incentives for CHP
to use back-up boilers or heat storage to satisfy heat demand in case of low electricity
demand, and use flexible biomass generation to satisfy demand peaks rather than
producing as baseload generation.
Similarly, the principle of priority access reduces system efficiency in situations of
network congestion. When individual grid elements are congested, the most efficient
solution is often to change the dispatch of power generation or demand located as closely
as possible to the congested grid element. Priority rules deviate from this principle, forcing
the use of other, potentially much less efficient resources. With sufficient transparency and
legal certainty on the process for curtailment and redispatch, and financial compensation
where required, priority access should be limited to where it remains strictly necessary.
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R&D results47
: In relation to dispatching and curtailment, the Integral project showed that load-shedding
based on software tools and remote control can be a useful tool to manage grid constraints and prevent
network problems. It demonstrated that load-shedding can be done on a procurement basis by the grid
operator and is a viable alternative to RES E curtailment. Thus, the grid operator can find the most cost-
efficient solution on market based terms as opposed to taking recourse to simply curtailing certain sources
of generation.
Driver 3: Consumers do not actively engage in the market and demand response
potential remains largely untapped
The active participation of consumers in the market is currently not being promoted,
despite technical innovation such as smart grids, self-generation48
and storage equipment
that allow consumers – even smaller commercial and residential consumers – to generate
their own electricity, store it, and manage their consumption more easily than ever. While
more and more consumers have access to smart meters and distributed renewable energy
resources such as roof-top solar panels, heat pumps and batteries, a minor share manages
their consumption and these resources actively.
Large-scale industrial consumers already are active participants in electricity markets.
However, the vast majority of other consumers neither has the ability nor the incentive to
take consumption, production and investment decisions based on price signals that reflect
the actual value of electricity and grid infrastructure. The metering and billing of
consumers does not allow them to react to prices within the time frames in which wholesale
markets operate. And even where technically possible, many electricity suppliers appear
reluctant to offer consumer tariffs that enable this. This leads to the
overconsumption/underproduction of electricity at times when it is scarce and the
underutilisation/overproduction of electricity at times when it is abundant.
Indeed, current markets do not enable us to reap the full benefits of technological progress
in terms of reducing transaction costs, reducing information asymmetries, and (thereby)
reducing barriers to market participation for smaller commercial and residential
consumers.
Periods of abundance and scarcity will increasingly be driven by high levels of RES E
generation. To deal with an increased share of variable renewables generation in an
efficient way, flexibility is key. Traditionally, almost all flexibility was provided in the
electricity systems by controlling the supply side. However, it is now possible to provide
demand side flexibility cost effectively. New technological developments such as smart
metering systems, home automation, etc. but also new flexible loads such as heat pumps
and electric vehicles allow for the reduction of demand peaks and, hence, significantly
reduce system costs.
47
Technological developments are both part of the drivers that affect the present initiative and part of the
solutions of the identified problems they affect. Therefore reference is made to finding of various
research and development projects that provide insights where these are pertinent. A list of the research
and development projects mentioned in this box and their findings relevant to the present impact
assessment is provided in Annex 8.
48
The specific issue of self-generation and self-consumption is analysed in detail in the Impact Assessment
for the RED II.
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The current theoretical potential of demand response adds up to approximately 100,000
MW and is expected to increase to 160,000 MW in 2030. This potential lies mainly with
residential consumers, and its increase will greatly depend on the uptake of new flexible
loads such as electric vehicles and heat pumps.
Figure 1: Theoretical demand response potential 2016 (in MW)
Source: Impact Assessment support Study on downstream flexibility, demand response and
smart metering, COWI, 2016
For the industrial sector demand response is mainly related to flexible loads in electric steel
makings. In the commercial sector, a high theoretical potential exist for ventilation of
commercial buildings while in the residential sector mainly freezers and refrigerators, and
the electric heater with storage capacity show a high theoretical potential.
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
Industrial
Commercial
Residential
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Figure 2: Theoretical potential of demand response per appliance
Source: Impact Assessment support Study on downstream flexibility, demand response and
smart metering, COWI, 2016
Approximately 30-40% of this potential can be considered technically and economically
viable and, hence, can expected to be activated if the right technologies, incentivising
mechanisms and market arrangements are in place. Demand response service providers
(often referred to as aggregators) can play an important role in activating this potential by
enabling smaller consumers and distributed generation in general to interact with the
market and have their resources being managed based on price signals, or provide
balancing or grid congestion services. These aggregators effectively reduce transaction
0 4000 8000 12000 16000
Aluminum
Copper
Zinc
Chlorine
Mechanical Pulp
Paper Machines
Paper Recycling
Electric Steel
Cement
Calcium Carbide
Air Seperation
Industrial Cooling
Industrial Building Ventilation
Cooling Retail
Cold storage houses
Cooling Hotels/Restaurants
Ventilation Commercial Buildings
AC Commercial Buildings
Storage hot water commercial sector
Electric storage heater commercial sector
Pumps in water supply
Waste water treatment
Residential refrigerators/freezers
Washing machines
Laundry driers
Dish washers
Residential AC
Storage hot water residential sector
Electric storage heater residential sector
Residential heat circulation pumps
MW
Theorertical potential of demand response per
appliance
2030 2020 2010
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costs and information asymmetries in the market, enabling a large number of smaller
and/or distributed resources to praticipate.
Of this potential, currently only around 21,000 MW demand response is used in the market.
Approx. 15,000 MW are contracted from large industrial consumers through direct
participation in the market while approx. 6,000 MW come from residential consumers who
are on traditional time of use tariff (usually just differentiating between day and night).
Only in the Nordic markets a slow uptake of dynamic price contracts linked to the
wholesale market is taking place. This shows that especially in the residential and
commercial sector with a theoretical potential of more than 70,000 MW the uptake of
deman dresponse is slow.
The main reasons for residential and commercial consumers not taking part in the demand
response schemes are mostly technical but can also be explained by currently relative small
benefits for those consumer groups:
- The technological prerequisites are not yet installed and even where smart meters
are being rolled out they do not always have the functionalities necessary for
consumers to take active control of their consumption;
- Dynamic electricity price contracts are only available for commercial/residential
consumers in very few Member States and hence consumers do not have a
financial incentive to shift consumption;
- In many Member States, third-party service providers helping consumers to
manage their consumption can not freely engage with consumers and do not have
full access to the markets;
- In many European markets price spreads are reletively small and price peaks either
not incur often or only lead to peak prices that are slightly higher than the average
price which makes demand response currently not very interesting from a financial
point of view. However, with an increase in renewables generation this price
spreads are likely to increase and participating in demand response will become
more profitable for consumers in the future. Variable network tariffs can equally
contribute to increasing the price spread;
- Consumers are more likely to participate in demand response when they have
significant single loads such as electric heating or electric boilers that are easy to
shift. In that respect the uptake of electric vehicles and heat pumps will also open
new opportunities for consumers to engage in demand response;
- Finally, automatisation is key to untap the full potenial of demand response in the
residential and commercial sector. Considering the relatively small economic
benefit residential consumers are likley to realise by participating in demand
response it is essential that theparticipation does not require active efforts but
devices can react automatically to price signals. Hence, interoperability of smart
metering systems will be crucial for the uptake of demand response.
In addition, the current design of the electricity market has not evolved to fully accomodate
demand side flexibility. It was meant for a world where consumers are passive consumers
of electricity that do not actively participate in the market. Hence, current market
arrangements at both the wholesale and retail level often make it very difficult for demand-
side flexibility to compete on a level playing field with generation:
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- Similar to RES E, consumption is variable and subject to forecast errors. As a
consequence, it is often infeasible for most individual customers to offer demand-
response many days ahead of the moment when electricity is actually consumed
- The liquidity of intraday markets – where demand response at short notice can
fetch a high price – is currently limited, providing little incentive to offer demand-
side flexibility;
- Procurement timeframes for balancing reserves capacity have generally long lead
times (week-, month- or year-ahead) for which demand response cannot always
secure firm capacity.
- Balancing markets often require that units can offer both upward regulation (i.e.
increasing power output) and downward regulation (i.e. reducing power output;
offering demand reduction) at the same time, making it difficult for demand
response to participate in those markets;
- And finally, product definitions make it difficult for aggregated loads to compete
in many markets.
The table below summarizes in which Member States markets are open to demand
response and the volume of demand response contracted. While demand response is
allowed to participate in most Member States, volumes of more than 100MW can only be
found in 13 Member States.
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Table 3: Participation of explicit Demand Response in different markets
Member State
Demand Response
in energy markets
Demand Response
in balancing
markets
Demand
Response in
Capacity
mechanisms
Estimated
Demand
Response for
2016 (in MW)
Austria Yes Yes 104
Belgium Yes Yes Yes 689
Bulgaria No No 0
Croatia No No 0
Cyprus No market No market 0
Czech Republic Yes Yes 49
Denmark Yes Yes 566
Estonia Yes No 0
Finland Yes Yes Yes 810
France Yes Yes Yes 1689
Germany Yes Yes Yes 860
Greece No (2015) No 1527
Hungary Yes Yes 30
Ireland Yes Yes Yes 48
Italy Yes No Yes 4131
Latvia Yes No Yes 7
Lithuania unclear No 0
Luxembourg No information No information
Malta No market No market
Netherlands Yes Yes 170
Poland Yes Yes No 228
Portugal Yes No 40
Romania Yes Yes 79
Slovakia Yes Yes 40
Slovenia No Yes 21
Spain Yes No Yes 2083
Sweden Yes Yes Yes 666
UK Yes Yes Yes 1792
Total 15628
Source: Impact Assessment support Study on downstream flexibility, demand response and smart metering,
COWI, 2016
R&D results: VSync demonstrated that PV or wind generation, if equipped with a technology as
demonstrated in the VSync project, can replace the inertia that large power plants possess that is needed to
reduce frequency variations. Therefore, such technologies could in principle be used to provide balancing
services to the TSO.
EvolvDSO has identified and worked-out the details of future roles for actors active in the management of
power systems at the distribution level. The project identifies ways in which flexibility of resources
connected at distribution level could be revealed, valorised, contracted and exploited by various actors of the
power system. It identified roles that could be fulfilled by DSOs and by market parties and asks that these
are clarified
Several European demonstration projects such as ECOGRID-EU, Integral, EEPOS, V-Sync and S3C have
provided evidence that demand response is sufficiently mature from a technical point of view, while stressing
the need to removing market related barriers to its deployment.
In particular, Integral and ECOGRID-EU show that valuing flexibility through price signals is possible and
easy, that local assets can participate and earn money in the wholesale market, and that the economic viability
depends on the value of flexibility. Integral also demonstrated that flexibility of a household's energy
consumption (and hence the ability to provide demand response) was higher than initially expected, probably
due to the automated response that did not require active consumer participation. ECOGRID-EU showed
that a customer with manual control gave a 60 kW total peak load reduction while automated or semi-
automated customers gave an average peak reduction of 583 kW.
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RES E and flexible electricity systems
Demand response, like other measures that improve the degree of flexibility in the system,
have an connection to the ability of RES E to finance itself in the market, through what is
often referred to as the 'merit order effect'. 49
During windy and sunny days the additional
electricity supply reduces the prices. Because the drop is larger with more installed
capacity, the market value of variable renewable electricity falls with higher penetration
rate, translating into a gap to the average market value of all electricity generators over a
given period. Inflexible markets where demand and generation are non-responsive to price
signals (including through measures such as priority dispatch or 'must-run' obligations)
render this effect more pronounced. This effect is already visible today in certain Member
States, and in the absence of measures, can be expected to become even more relevant as
renewables penetration increases further.
At the one hand, this implies that as renewables are further gaining market shares in the
coming decade, the regulatory framework should not only incentivise the deployment of
renewables where costs are low (e.g. due to abundant wind or solar resources), but also
where and when the value of the produced electricity is the highest. On the other hand, by
improving the market framework in which RES E operates by rendering it more flexible,
unnecesarry erosion of the value of RES E assets can be prevented.
Reference is made to the box in Section 6.2.6.3 and Section 6.2.6.4 for further information.
Driver 4: Distribution networks are not actively managed and grid users are poorly
incentivised
Most of the time, the present regulatory framework does not provide appropiate tools to
distribution network operators to actively manage the electricity flows in their networks.
It also does not provide incentives to customers connected to distribution grids to use the
network more efficiently. Because smaller consumers have historically participated in the
broader electricity system only to a limited extent, currently no framework exists that puts
such incentives in place. This has led to fears over the impact that the deployment of
distributed resources could have at system-level (e.g. that the costs of upgrading the
network to integrate them would outweigh their combined benefits in other terms).
Moreover, the regulatory framework for DSOs, which most of the times is based on cost-
plus regulation, does not provide proper incentives for investing in innovative solutions
which promote energy efficiency or demand-response and fails to recognise the use of
flexibility as an alternative to grid expansion.
With RES E being a source of electricity generation that is often decentralised in nature,
DSOs are gradually being transformed from passive network operators primarily
concerned with passing-on electricity from the transmission grid to end-consumers, to
network operators that, not unlike TSOs, actively have to manage their grids. At the same
49
See Hirth, Lion, "The Market Value of Variable Renewables", Energy Policy, Volume 38, 2013, p.
218-236). The merit order effect is occasionally also referred to as the 'cannibalisation effect'.
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time, technological progress allows distribution system operators to reduce network
investments by managing locally the challenges that more decentralised generation brings
about. However, outdated national regulatory frameworks may not incentivise or even
permit DSOs to make these savings by operating more innovatively and efficiently because
they reflect the technological possibilities of yesteryear. The resulting inflexibility of
distribution networks significantly increases the cost of integrating more RES E
generation, particulary in terms of investment.
R&D results: Reduced network investment by managing locally decentralised generation is demonstrated
in European projects like: SuSTAINABLE, MetaPV, evolvDSO, PlanGridEV, BRIDGE and REServices50
.
According to EvolvDSO, flexibility procurement and activation by DSOs are not addressed in the regulatory
framework in most Member States: they are not excluded in principle but not incentivised either and, because
they are not explicitly addressed, this creates uncertainty for the DSO to apply them.
The REServices study has analysed the possible services that wind and solar PV energy can provide to the
grid in theory but concludes that they are not able to (in the Member States analysed) due to the way the
market rules are defined.
The project SuSTAINABLE demonstrated that intelligent management supported by more reliable load and
weather forecast can optimise the operation of the grid. The results show that using the distributed flexibility
provided by demand-side response can bring an increase of RES E penetration while, at the same time, avoid
investments in network reinforcement, and this leads to a decrease in the investment costs of distribution
lines and substations.
The BRIDGE project recommended that products for ancillary services should be consistent and
standardized from transmission and down to the local level in the distribution network. Such harmonization
will facilitate the participation of demand-side response and small-scale RES in the markets for these
services, and thereby increase the availability of the services, enable cross-border exchanges and lower
system costs.
Tests in the project PlanGridEV with controllable loads (demand response, electric vehicles) performed in a
large variety of grid constellations have shown that peak loads could be reduced (up to 50%) and more
renewable electricity could be transported over the grid compared to scenarios with traditional distribution
grid scenarios. As a result, critical power supply situations can be avoided, and grids, consequently, do not
call for reinforcement
Both MetaPV and EvolvDSO suggest that a DSO makes a multiannual investment plan that takes into
account flexibility it can purchase from connected demand-side response or self-producers and consumers
(MetaPV suggests to do this through a cost-based analysis)
MetaPV also demonstrated that remotely controllable inverters connecting PV-panels to the distribution grid
can offer congestion management services to the distribution grid (in the form of voltage control obtained
via reactive power modulation). This increases the capacity of the distribution grid to integrate intermittent
RES by 50%, at less than 10% of the costs of ‘traditional’ investments in hardware such as copper.
2.2. Problem Area II: Uncertainty about sufficient future generation investments
and uncoordinated capacity markets
In light of the 2030 objectives, considerable new investment in electricity generation
capacity will be required. The power sector is likely to play a central role in the energy
transition. First, it has been the main sector experiencing decarbonisation since the last
50
A list of the research and development projects mentioned in this box and their findings relevant to the
present impact assessment is provided in Annex 8.
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decade and its challenges still remain high. Second, in the near future, the power sector is
expected to support the economy in reducing its dependence on fossil fuels, notably in the
transport and heating and cooling sectors.
Generation capacity in the EU increased sharply from 2009 onwards due to the addition of
new renewables technologies to the already existing capacity. The composition of the
capacity mix progressively changed. Nuclear capacity started declining in recent years
(2010-2013) due to phasing out decisions in some Member States. Other conventional
capacity showed a decline in 2012-2013 as well51
.
The largest part of the required new capacity will be variable wind and solar based,
complemented by more firm, flexible and less carbon-intensive forms of power generation.
At the same time, in light of the ageing power generation fleet in Europe with more than
half of the current capacity expected to be decommissioned by 204052
, it is important to
maintain sufficient capacity online to guarantee security of supply. The modelling results
nevertheless indicate that investment needs in additional thermal capacity will be limited
especially in the period 2021-2030. According to PRIMES EUCO27, about 81% of net
power capacity investments will be in low-carbon technologies, of which 59% in RES E
and 22% in nuclear generation53
.
Table 4: Investment Expenditure (including new construction, life-time extension
end refurbishment) in generation capacity by technology (average over 5 year
period) in MEuro'13
Period 2000-2005 2005-2010 2010-2015 2015-2020 2020-2025 2025-2030
Nuclear 1,502 739 270 6,291 11,011 14,312
Renewable energy 16,789 28,672 43,393 38,957 25,217 21,911
Hydro (pumping
excl.)
5,995 2,557 3,289 2,239 354 633
Wind 9,238 17,095 19,614 28,553 14,059 14,219
Solar 1,556 9,019 20,487 7,870 10,581 6,728
Other renewables - 2 3 295 223 332
Biomass-waste fired 2,626 3,438 4,157 11,779 465 433
Geothermal heat 100 90 110 182 - -
Thermal 11,989 14,019 13,391 17,151 3,355 3,274
Solids fired 1,029 1,237 5,333 2,610 870 192
Oil fired 639 373 362 75 33 9
Gas fired 7,595 8,880 3,427 2,505 1,987 2,641
Hydrogen plants - - 1 - - -
Total (incl. CHP) 30,280 43,430 57,054 62,399 39,583 39,497
Source: PRIMES; based on EUCO27 scenario
51
See on this and for further information, European Commission, Investment perspectives in electricity
markets, Institutional Paper 003, July 2015, page 8.
http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf.
52
World Energy Outlook 2015, IEA
53
The challenge to attract sufficient investment in RES E is examined in detail in the RED II impact
assessment
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At the same time, short-term market prices at wholesale level have decreased substantially
over the past years. In parallel with high fossil fuel prices, European wholesale electricity
prices peaked in the third quarter of 2008; then fell back as the economic crisis broke out,
and slightly recovered between 2009 and 2012. However, since 2012 wholesale prices have
been decreasing again. Compared to the average of 2008, the pan-European benchmark for
wholesale electricity prices were down by 55% in the first quarter of 2016, reaching 33
EUR/MWh on average, which was the lowest in the last twelve years54
.
Figure 3 on pan-European wholesale market prices
Source: Platts and European power exchanges
Prices declined for a number of reasons55
including (i) a decrease in primary energy prices
(e.g. coal, and more recently also natural gas), (ii) an increasing imbalance between the
supply and demand for carbon allowances, leading to a surplus of over 2 billion allowances
by 2012 and a corresponding decrease in carbon allowance prices56
, and (iii) an
54
See the "main findings" of Section 1.1 on Wholesale electricity prices from the 2016 Commission Staff
Working Document accompanying the forthcoming 'Report on energy prices and costs in Europe'.
55
The influence of each market factor might strongly very across different regions. For example, the share
of renewables and carbon prices have strong impact on wholesale price evolution in North Western
Europe, while in Central and Eastern Europe the main price driver is the share of coal and gas in the
generation mix.
56
Between April 2011 and May 2013 carbon emission allowance contracts underwent a significant price
fall (decreasing from 17 EUR/tCO2e to 3.5 EUR/tCO2e) reflecting the fall in demand for allowances
due to the recession. Since April 2013 carbon prices have increased, reaching an average auction clearing
price of €7,62/tCO2e in 2015.
(See: http://ec.europa.eu/clima/policies/ets/auctioning/docs/cap_report_201512_en.pdf).
The extent to which the carbon price impacts the wholesale power price depends on the carbon intensity
of the marginal power producer.
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overcapacity of power generation facilities57
, putting a downward pressure on wholesale
prices.
Overcapacity was, in turn, caused by: (i) a drop in electricity demand as electricity
consumption decoupled from an already low economic growth58
, (ii) over-investments in
thermal plants59
, (iii) the increasing proportion of renewables with low marginal costs
driven by EU policies, (iv) barriers to decommission capacity60
, and (v) continuing
improvement in the field of coupling national electricity markets61
, leading to an increased
sharing of resources among Member States62
.
As a result, for most regions in Europe current electricity wholesale prices do not indicate
the need for new investments into generation capacity. There are, however, doubts whether
the market, as currently designed, would be able to produce investment signals in case
generation capacities were needed. Independently of current overcapacities of most regions
in Europe, a number of Member States anticipate inadequate generation capacity in future
years and introduce capacity mechanisms at national level.
57
In parallel with decreasing fossil fuel and carbon prices (resulting in decreasing marginal costs of
electricity generation(, and the generation overcapacity, the share of renewable energy sources (wind,
solar, biomass, also including hydro) has been gradually increasing over the last few years. In most of
the EU countries fossil fuel costs set the marginal cost of electricity generation, being decisive for the
wholesale electricity price. However, increasing share of renewables in the electricity mix, together with
significant baseload generation capacities, shifted the generation merit order curve to the right, resulting
in lower equilibrium price set by supply and demand. Consequently, we can say that increasing share of
renewable energy sources, in an already oversupplied market, have significantly contributed to low
wholesale electricity prices in the EU markets.
58
Consumption of electricity in the EU decoupled from economic growth during the last few years due to
energy efficiency gains.
59
Investment decisions in the electricity sector are typically taken long before returns on investment are
effectively earned, due to the time to construct new power plants. At the same time, the decentralised
nature of investment decision-making means that each generator has limited information about the
generation capacity that competitors will make available in the coming years. The result is what has
been referred to as boom-bust cycles: alternate periods of shortages and overcapacity resulting from lack
of coordination in the investment decisions of competing generators.
60
In some Member States, there is an overcapacity situation that is in fact artificially extended by clear
regulatory exit barriers, which in the short-term depress market prices and in the mid/long-term ruin the
investment incentives.
61
In parallel, progressing market integration decreased price divergence within the EU. Indeed in the first
quarter of 2008 the price difference between the most expensive and the cheapest European wholesale
electricity market was 44 EUR/MWh, eight years later this difference has shrunk to 24 EUR/MWh.
Based on "main findings" from 2016 costs and prices report and underlying studies, published in
conjunction with the present impact assessment
62
See also Box 9 behind section 6.4.6 for more on overcapacity, market exit and prices
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Driver 1: Lack of adequate investment signals due to regulatory failures and
imperfections in the electricity market
The internal energy market is built on competitive (short and long-term) wholesale power
markets where price signals are central to guide market participants production and
consumption decisions. Short-term prices signal prevailing supply and demand conditions
while long-term prices are formed according to expectations about future supply and
demand. Conditions, such as for example shortages or oversupply that are expected to
prevail in the future will not only determine short-term (spot) prices but also impact long-
term (forward, futures) prices.
In around half of Member States sales achieved at short and long term markets determine
the bulk of generators' income63
. This income is required to cover their full costs, mainly
fuel, maintenance and amortisation of assets (i.e. investments). These arrangements are
often referred to as energy-only markets. In the other half of Member States there are also
measures (either market based or non-market based) in place to pay generators for keeping
their capacity available (capacity mechanisms or 'CM's), regardless as to whether they are
producing electricity or not64
. For generators who operate on the market these payments
represent an additional income next to their earnings on the wholesale markets for energy.
Capacity payments, thus, represent additional support to maintain and/or develop capacity.
Irrespective whether generators are expected to earn their investments solely on the
'energy-only' market or whether they can also rely on additional payments for capacity,
wholesale power prices are central to provide the right signals for efficient market
63
See below, figure 1 and ACER Market Monitoring Report 2014; generators may also collect additional
income from offering their capabilities, including the availability of (short-term) electricity to TSO's
who rely on them to manage the system (i.e. short-term balancing and ancillary Services)
64
"Capacity mechanisms exist worldwide both in regulated and in non-regulated markets": CIGRE paper
C5-213, "Capacity Mechanisms: Results from a World Wide Survey", H. Höschle, G. Doorman (2016).
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operations. For the EU-target model65
to function properly, prices need to be able to
properly reflect market conditions66
.
Price signals and long-term confidence that costs can be recovered in reasonable payback
times are essential ingredients for well-functioning market. In a market which is not
distorted by external interventions, the variability of the spot price on the wholesale
market, plays a role in signalling the need of investment in new resources. In the absence
of the right short- and long-term price signals, it is more likely that inappropriate
investment or divestment decisions are taken, i.e. too-late decisions or technology choices
that turn out to be inefficient in the long run. Price differentials between different bidding
zones should determine where generation and demand should ideally be located,67
.
In 2013 the Commission published an assessment identifying reasons why the market may
fail to deliver sufficient new investment to ensure generation adequacy68
. These reasons
are a combination of market failures and regulatory failures. For example when consumers
cannot indicate the value they place on uninterrupted electricity supply, the market may
not be effective performing its coordination function. Equally however, regulatory
interventions, as well as the fear of such interventions, such as price caps and bidding
restrictions (regardless as to whether effectively restricting price formation at that moment
or only later) limit the price signal for new investments. Likewise the prices on balancing
markets operated by TSOs should not undermine the price signals from wholesale markets.
Power generators and investors have argued that regulatory uncertainty and the lack of a
stable regulatory framework undermine the investment climate in the Union compared to
other parts of the world and to other industries.
In fact, current market arrangements often do not allow prices to reflect the real value of
electricity, especially when supply conditions are tight and when prices should reflect its
scarcity, affecting the remuneration of electricity generation units that operate less often
but provide security and flexibility to the system.
These regulatory failures are amplified by the increasing penetration of RES E. RES E is
capacity that often has a cost structure typified by low operational costs69
, resulting in more
65
The "Electricity Target Model" aims at integrating wholesale power markets by harmonising the way
how transmission capacity is allocated between Member States. Central to it is market coupling which
is based on the, so-called, "flow based" capacity calculation, a method that takes into account that
electricity can flow via different paths and optimises the representation of available capacities in meshed
grids. The implementation of the target models in gas and electricity is equivalent to achieving the
completion of the internal energy market.
66
Evidently, efficient market outcome also presumes that all assets are treated equally in terms of the risks
and costs to which they are exposed and the opportunities for earning revenues from producing
electricity i.e. they operate on a level playing field as is esually fostered by the present intiative.
67
See on price signals, European Commission, Investment perspectives in electricity markets, Institutional
Paper 003, July 2015, pages 32 and following.
(http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf
68
See also SWD(2013) 438 "Generation Adequacy in the internal electricity market - guidance on public
interventions", Section 3 .
69
Cost structures vary according to the underlying technology deployed. In general, wind and solar
technologies have very low operational costs whereas the opposite is true for biomass fuelled generation.
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frequent periods with low wholesale prices. The variability of RES E production moreover
decreases the number and predictability of the periods when conventional electricity
generators are used, thereby increasing the risk profile and risk premiums of all
investments in electricity resources70
. Whereas market participants are used to hedging
risks, and market trading arrangements are adapting to allow more risks to be covered, the
risk profile of investments will become more pronounced. This increases the need to ensure
that prices reflect the real value of electricity to ensure plants can cover their full costs,
even if they are operating less frequently.
The current market arrangements are constructed around the notion of price zones
delimited by network constraints. The price differences between such zones should drive
investments to be located where they relieve congestion by rewarding investments in areas
typified by high prices. The congestion rents collected by network operators to transport
electricity from low to high price zones are meant to be used to relieve congestion by
maintaining and constructing interconnection capacity.
However, today the delineation of price zones in practice does not reflect actual
congestion, but national borders. This prevents the establishment of prices that reflect local
supply and demand, which leads to the phenomenom of loop flows, which can reduce the
interconection capacity made available for cross-border trading and leads to expensive out-
of-market redispatching and significant distortions to prices and investment signals in
neighbouring bidding zones. To illustrate this, ACER has estimated, in their Market
Monitoring Report71
, that reductions in cross-border capacity due to loop flows resulted in
a welfare loss of EUR 445 million in 2014. Further, the costs of re-dispatch and
countertrading to deal with inaccurate dispatch can be high. In 2015 the total cost for
redispatching within the German-Austria-Luxembourg bidding zone was approximately
EUR 930 million72
. There is also evidence that cross-border capacity is being limited in
order to deal with internal contraints, again limiting cross-border trading opportunities.
The impacts of this can be significant. For example, when looking at the capacity between
Germany and the Nordic power system, the Swedish regulatory authority noted significant
capacity limitations, concluding that these were mostly due to internal contraints, and
found that losses amounted to a total of EUR 20 million per annum in Norway and
Sweden73
.
A further issue that can potentially distort investment is that of network charges on
generators. This includes charges for use of the network, both at distribution-level and
transmission-level (tariffs), as well as the charges applied to generators for their connection
(connection charges). There is significant variation across the EU on the structure of these
charges, which are set at Member State-level. For instance, some Member States do not
70
Generators' expectations about future returns on their investments in generation capacity are affected
not only by the expected level of electricity prices, but also by several other sources of uncertainty, such
as increasing price volatility. The increasing weight of intermittent renewable technologies makes prices
more volatile and shortens the periods of operation during which conventional technologies are able to
recoup their fixed costs. In such circumstances, even slight variations in the level, frequency and duration
of scarcity prices have a significant impact on the expected returns on investments, increasing the risk
associated to investing in flexible conventional generation technologies.
71
"Market Monitoring report 2014" (2015) ACER, Section 4.3.2 on unscheduled flows and loop flows.
72
ENTSO-E Transparency Platform, at https://transparency.entsoe.eu/
73
"Capacity limitations between the Nordic countries and Germany" Swedish Energy Markets
Inspectorate (2015)
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apply any tariffs to generators, others apply them based on connected capacity and others
based on the amount of electricity produced. Some include locational signals within the
tariff, some do not. With regards to connection charges, some calculate them based only
on the direct costs of accessing the system (shallow) and others include wider costs, such
as those of any grid reinforecement required (deep). Such variations can serve to distort
both investment and dispatch signals.
Driver 2: Uncoordinated state interventions to deal with real or perceived capacity
problems
The uncertainty on whether the market will bring forward sufficient investment, or keep
existing assets in the market, has, in a number of Member States, fuelled concerns about
system adequacy, i.e. the ability of the electricity system to serve demand at all times.
Certain Member States have reacted by introducing CMs designed to support investment
in the capacity that they deem necessary to ensure a secure and acceptable level of system
adequacy.
These measures often take the form of either dedicated generation assets kept in reserve or
a system of market wide payments to generators for availability when needed.
Figure 4: Capacity Mechanisms in Europe – 2015
Source: "Market Monitoring Report 2014" (2015) ACER.
These initiatives by Member States are based on non-aligned perceptions and expectations
as to the degree the electricity system can serve electricity demand at all times and a
Strategic reserve
(since 2004 ) - gradual phase-
out 2020 and considering a
permanent market system
after 2020
New Capacity Mechanism
under assessment by COMP
(Capacity payments from 2006
to 2014)
Capacity payment (since 2008) –
Tendering for capacity
considered but no plans
No CM (energy only market)
CM operational
Reliability option
(first auction end 2016, first
delivery contracted capacity is
expected in 2021)
Strategic reserve
(from 2016 on, for 2 years,
with possible extension for 2
years)
CM proposed/under consideration
Capacity requirements
(certification started 1 April
2015)
Capacity auction
(since 2014 - first delivery in
2018/19)
Capacity payment
(since 2007)
considering reliably options
Capacity Payment (Since 2010
partially suspended between
May 2011 and December 2014)
Strategic reserve (since 2007)
Debate pending
Strategic reserves for DK2
region from 2016-2018 (and
potentially from 2019-2020)
Strategic reserve
(since 1 November 2014)
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reluctance to rely on the contribution the EU system as a whole can make to the adequacy
of the system of a given Member State.74
As reflected in the Interim Report of the Sector Enquiry75
led by DG Competition, many
existing CMs have been designed without a proper assessment of whether a security of
supply problem existed in the relevant market. Many Member States have not adequately
established what should be their appropriate level of supply security (as expressed by their
'reliability standard') before putting in place a CM.
Methods of assessing resource adequacy vary widely between Member States76
, which
make comparison and cooperation across borders difficult. Many resource adequacy
assessments take a purely national perspective and may substantially differ depending on
the underlying assumptions made and the extent to which foreign capacities77
as well as
demand side flexibility78
are taken into account. This, in turn, means some Member States
force consumers to over-pay for 'extra' capacities they do not really need.
74
Indeed, a majority of Member States expect reliability problems due to resource adequacy in the future
even though such problems have been extremely rare in the past five years. Such issues have only arisen
in Italy on the Islands of Sardinia and Sicily which are not connected to the grid on the mainland.
75
See also SWD(2016) 119 final "Interim report of the Sector Inquiry on Capacity Mechanisms",
http://ec.europa.eu/competition/sectors/energy/state_aid_to_secure_electricity_supply_en.html
76
For more details, see annex 5.1. See also "Generation adequacy methodologies review", (2016), JRC
Science for Policy Report and CEER (2014), "Assessment of electricity generation adequacy in
European countries".
77
According to the CEER report, "the extent to which current generation adequacy reports take the
benefits of interconnectors into account varies a lot: 4 reports still model an isolated system (Norway,
Estonia, Romania, and Sweden); 2 reports use both interconnected and isolated modelling (France and
Belgium); 3 report methodologies are being modified to include an interconnection modelling; 9 reports
simulate an interconnected system (UK, the Netherlands, Czech republic, Lithuania, Finland, Belgium
and Ireland, while France and Italy use both methods)."
78
According to the CEER report, "only 3 countries include demand response as a separate factor in their
load forecast methodology i.e. the UK, France and Spain. In Norway and Finland, the contribution from
demand response is not included as separate factor, but peak load estimation is based on actual load
curves which include the effect of demand response. Sweden does not consider demand response, and
do not assume that consumers respond to peak load in their analysis."
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Table 5: Deterministic vs probabilistic approaches to adequacy assessments
Source: European Commission based on replies to sector inquiry, see below for a description of capacity
margin, LOLP, LOLE, and EENS79
The introduction of CMs fundamentally change wholesale electricity markets because
generators and other capacity providers are no longer paid only for the electricity they
generated but also for their availability. Worse however is that CMs when introduced in
an uncoordinated manner can be inefficient and distort cross-border trade on wholesale
electricity markets.
In the short-term, CMs may lead to distortions if their design affects natural price formation
in the energy market (e.g. bidding behaviour of generators) and therefore alter production
decisions (operation of power generating plants) and cross-border competition. For
instance, a possible distortion is when generators in a market applying a CM, receive
(capacity) payments which are determined in a way that affects their electricity generation
bids into the market, while in a neighbouring "energy-only" market generators do not. This
may tilt the playing field for generators on either sides of the border. Another example
might be if strategic reserves (a particular form of CMs) are dispatched 'too-early' impeding
the market's ability to establish equilibrium between supply and demand. This can cause
or contribute to a 'missing money' problem as strategic reserves would outcompete existing
(or future) generators who, at least partly, rely on scarcity rents to cover their costs.
CMs may also influence investment decisions (investment in plants and their locations),
with potential impacts in the long term. If contributions from cross-border capacity are not
appropriately taken into account, they may lead to over-procurement of capacity in
countries implementing CMs, with a detrimental impact on consumers.
CMs may also cause a number of competition concerns. In this respect, the Sector Inquiry
identifies substantial issues in relation to the design of CMs in a number of Member States.
First, many CMs do not allow all potential capacity providers or technologies to
79
See annex 5.1 for the definition of the different methodologies.
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participate, which may unnecessarily limit competition among suppliers or raise the price
paid for the capacity80
.
Second, capacity mechanisms are also likely to lead to over-compensation of the capacity
providers – often to the benefit of the incumbents – if they are badly designed and non-
competitive. In many Member States the price paid for capacity is not determined through
a competitive process but set by the Member State or negotiated bilaterally between the
Member State and the capacity provider. This creates a serious risk of overpayment81
.
Third, the inquiry revealed that capacity providers from other Member States (foreign
capacity) are rarely allowed to directly or indirectly participate in national CMs82
. This
leads to market distortions as additional revenues from CMs remain reserved to national
companies. This is particularly problematic in case of dominant national incumbents
whose dominant position may even be strengthened by a national CM.
Lastly, although there is a challenge to design penalties that avoid undermining electricity
price signals which are important for demand response and imports, where obligations are
weak and penalties for non-compliance are low, there are insufficient incentives for plants
to be reliable.
All in all, the Sector Inquiry highlights that "a patchwork of mechanisms across the EU
risks affecting cross-border trade and distorting investment signals in favour of countries
with more ‘generous’ capacity mechanisms. Nationally determined generation adequacy
targets risk resulting in the over-procurement of capacities unless imports are fully taken
into account. Capacity mechanisms may strengthen market power if they for instance, do
not allow new or alternative providers to enter the market. Capacity mechanisms are also
likely to lead to over-compensation of the capacity providers – often to the benefit of
incumbents – if they are badly designed and non-competitive." All of these issues can
undermine the functioning of the internal energy market and increase energy costs for
consumers.
As reflected in the Sector Inquiry, the heterogeneous development of capacity mechansims
has led to fragmented markets across the EU. The Sector Inquiry highlights that "the
different types of capacity mechanisms are not equally well suited to address problems of
security of supply in the most cost effective and least distortive way".
80
In some cases, certain capacity providers are explicitly excluded from participating or the group of
potential participants is explicitly limited to certain providers. In other cases, Member States set
requirements that have the same effect, implicitly reducing the type or number of eligible capacity
providers. Examples are size requirements, environmental standards, technical performance
requirements, availability requirements, etc.
81
In Spain for example, the price for an interruptibility service almost halved after a competitive auction
was introduced.
82
For example, Portugal, Spain and Sweden appear to take no account of imports when setting the amount
of capacity to support domestically through their CMs. In Belgium, Denmark, France and Italy, expected
imports are reflected in reduced domestic demand in the CMs. The only Member States that have
allowed the direct participation of cross-border capacity in CMs are Belgium, Germany and Ireland. For
more details, see annex 5.2.
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The Sector Inquiry concludes that capacity payment schemes are generally problematic as
they risk over-compensating capacity providers because they rely on administrative price
setting rather than competitive allocation procedures. The risk for overcompensation is
lower for market-wide and volume-based schemes and strategic reserves. What matters is
the design of the support scheme, which can make it more or less distortive.
Several stakeholders have proposed to address investment uncertainty by dedicated
regulatory provisions encouraging and clarifying the use of long-term contracts ('LTC's)
between generators and suppliers or consumers83
. They argue that such rules could help
mitigating the investment risk for the capital-intensive investments required in the
electricity sector, facilitating access to capital in particular for low-carbon technologies at
reasonable costs.
While mandatory LTCs may involve a risk transfer to consumers unless they are certain
they will have enduring future electricity demand, such contracts may allow them to benefit
from less volatile retail prices as electricity would be purchased long time ahead of
delivery. In terms of market functioning, it has to be stressed that current EU electricity
legislation does not discourage the conclusion of long-term electricity purchase contracts.
Even absent dedicated legislation, LTCs between a buyer and seller to exchange electricity
on negotiated terms, can anyway be freely agreed on by interested parties without any need
for further intervention by governments or regulators. Tradable wholesale contracts are
already available to market parties (albeit with limited liquidity for contracts of more than
three years84
). A dedicated framework for hedging price risks over longer terms has just
been created with the EU Guideline on Forward Trading ("FCA Guidelines"). The only
regulatory restriction to the use of LTCs may result, in exceptional situations85
, from EU
Treaty rules on competition law (e.g. if they are used by by dominant companies to prevent
new market entry).
It may also be noted that experience has shown that regulatory encouragement of LTCs
under EU law may also entail the risk of "lock-in risk" in the fast developing electricity
markets86
.
Options suggested to facilitate long-term contracting include (i) socialising the costs of
guaranteeing delivery of bilateral contracts (to reduce the default risk) or (ii) introducing
long-term contracts with a regulated counterparty. Both models might, however, be
considered to be capacity mechanisms and would have to be scrutinised under the relevant
State aid rules.
83
See e.g. submissions to the Commission's market design consultation from a limited number of
generation companies and from energy-intensive industries.
84
See for further information, CEPS Special Report, The EU power sector needs long-term price signals,
No. 135/April 2016, page 9.
85
It should be noted that there is extensive guidance and case practice on the interpretation of Article 81
and 82 with respect to long-term energy contracts available.
86
The fast changing electricity markets may require different generation solutions than today (e.g. due to
new storage technology). See also the example of guaranteeing revenues for solar power producers for
timeframes ten years ago which proved to be higher than necessary in retrospective due to technological
developments.
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2.3. Problem Area III: Member States do not take sufficient account of what
happens across their borders when preparing for and managing electricity
crisis situations
In spite of best efforts to build an integrated and resilient power system, electricity crisis
situations may occur. Whilst most incidents are minor87
, the likelihood of larger-scale
incidents affecting the European electricity system might well be on the rise due to extreme
weather conditions88
, climate change (giving rise to extreme and unpredictable weather
conditions, which already today constitute a major challenge to electricity systems)89
, fuel
shortage90
and a growing exposure to cybercrime and terrorist attacks in Europe. Already
in 2014 a series of cyberattacks by the so-called "Energetic Bear" targeted several energy
companies in Europe and US, highlighting the increasing vulnerability of the energy
sector91
.
Where crisis situations occur, they often have a cross-border effect. Even where incidents
start locally, they may rapidly proliferate across borders. Thus, a black-out in Italy in 2003
due to a tree flashover affected the electricity systems of its neighbouring states as well,
and in 2006 the tripping of an electricity line by a cruise ship in Germany affected 15
million people and had an impact on the entire continental power system92
.
Crisis situations may also affect several Member States at the same time as it was the case
during the prolonged cold spell in February 201293
, which led to a series of uncoordinated
emergency measures across Europe. Given the increasing interconnectivity of the EU's
87
In 2014 ENTSO-E identified over 1000 security of supply incidents. Most of these were minor but there
were some more serious disturbances, for example storms on 12 February 2014 leaving 250,000 homes
in Ireland without power.
See: https://www.entsoe.eu/Documents/SOC%20documents/Incident_Classification_Scale/151221_ENTSO-
E_ICS_Annual_Report_2014.pdf
88
Extreme weather events are likely to affect the power supply in various ways: (i) thermal generation is
threatened by lack of cooling water (as shown e.g. in summer 2015 at the French nuclear power stations
Bugey, St. Alban and Golfech); (ii) heat waves cause high demand of air conditioning (which e.g.
resulted in price peaks in Spain in late July 2015 when occurring in parallel with low wind output); (iii)
heat waves affect grid performance in various ways, e.g. moisture accumulating in transformers (which
e.g. lead to blackouts in France on June 30th
2015) or line overheating (leading to declaration of
emergency state by the Czech grid operator CEPS on July 25th
in 2006) (source: European Power Daily,
Vol. 18, Issue 123 (2016), S&P Global, Platts).
89
"Delivering a secure electricity supply on a low carbon pathway", Energy Policy no 52. 55-59 (2013),
Boston, Andy.
90
One example proving that such risks should be taken into account is the shortage of anthracite coal in
Ukraine in June 2016 due to the political situation in Ukraine affected the rail transport of coal. As
several Ukrainian nuclear power units were offline for maintenance in parallel, the responsible ministry
called for limiting power consumption as preventive measure. (Source: European Power Daily, Vol. 18,
Issue 123 (2016), S&P Global, Platts).
91
On 23 December 2015, a cyberattack in Ukraine led to serious power cuts affecting more than 600.000
households.
92
The Italian blackout on 28/09/2003, due to a tree flashover, affected 55 million people in Italy,
Switzerland, Austria, Slovenia and Croatia. It led to a black-out situation to up to 24 hours and
interrupted energy of 17 GWh.
93
The first two weeks of February 2012 saw a prolonged colder-than-usual weather period consistently
with 12 degrees Celsius below winter average and reaching historically low temperatures exceeding 1
in 20 climatic conditions.
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electricity systems and linkage of electricity markets, the risk of electricity crisis situations
simultaneously affecting several Member States are set to further rise94
.
It should be noted that risks of cross-border electricity incidents do not stop at the European
Union's borders, given increasing links between the electricity systems of EU Member
States and those of some of its neighbours (e.g., synchronisation with Western Balkans,
common infrastructure projects between e.g., Italy-Montenegro, Romania-Moldova,
Poland-Ukraine).
Given the key role of electricity to society, electricity crisis situations entail serious costs
– both economically and for the society at large95
.
Both when preparing for and dealing with crisis situations, Member States take very
different approaches and tend to focus on their national territories and customers only,
ignoring the possible assistance of and the impact on neighbouring countries and
customers. This entails serious risks for security of supply and can also lead to undue
interferences with the internal energy market.
94
METIS simulation shows that the better integration of the markets would result in a propagation of the
stress hours across Member States. Additionally, the stress hours would be concentrated in periods
affecting simultaneously several Member States.
95
The economic impact of large scale blackouts could be estimated in billions. Thus, for instance, a
blackout in France on 26 December 1999 due to storms of unprecedented violence with devastating
effects, affected 3.5 million households (which corresponds to about 10 million people losing their
electricity supply) and entailed an economic cost of EUR 11.5 billion and interrupted energy estimated
in 400 GWh.
Recent simulations show that the damages as consequence of the power outages of 5 hours in a border
region between Belgium, France and Germany to all of the economic sectors would amount to 1 billion
Euro. www.blackout-simulator.com; simulation of a blackout in following NUTS regions: FR21
Champagne-Ardenne, FR41 Lorraine, FR42 Alsace, BE34 Prov. Luxembourg, BE35 Prov. Namur ,
DEC0 Saarland, DEB Rheinland-Pfalz, FR30 Nord - Pas-de-Calais, BE32 Prov. Hainaut, BE25 Prov.
West-Vlaanderen, FR22 Picardie, BE31 Prov. Brabant Wallon, BE23 Prov. Oost-Vlaanderen, DE1
Baden-Württemberg.
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Driver 1: Plans and actions for dealing with electricity crisis situations focus on the
national context only
First, whilst most Member States have plans to prevent and deal with electricity crisis
situations, the content and scope of these plans varies considerably and plans tend to focus
on the national situation only96
. Cross-border cooperation in the planning phase is scarce
and where it takes place at all, it is often limited to cooperation at the level of TSOs97
. This
is largely due to a regulatory failure: the existing EU legal framework does not prescribe a
common approach, and rules and structures for cross-border co-operation are almost
entirely absent98
. Cross-border cooperation is also hindered by divergent national rules.
Cooperation with Member States outside the EU is even more limited.
Further, where crisis situations do arise, Member States also tend to react on the basis of
their own national set of rules, and without taking much account of the cross-border
context. Evidence shows, for instance, that Member States have different concepts of what
an emergency situation is and entails99
, and who should do what and when in such
situations. In particular, there is considerable uncertainty and divergence as regards what
public authorities can do in emergency situations100
.
The fact that Member States tend to adopt national, 'going alone' approaches when
preparing for and managing crisis situations stands in strong contrast with the reality of
96
Source: Risk Preparedness Study - "Review of current national rules and practices relating to risk
preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal Network,
study prepared for DG Energy.
https://ec.europa.eu/energy/sites/ener/files/documents/DG%20ENER%20Risk%20preparedness%20fi
nal%20report%20May2016.pdf
97
There are examples of existing regional co-operation involving national authorities, e.g. among the
Nordic countries in the framework of Nord-BER (Nordic Contingency Planning and Crisis Management
Forum). However, this co-operation is mainly restricted to the exchange of best practices.
98
See the results of the evaluation, attached as Annex VI.
99
For instance the concept of 'emergency' is not defined in all Member States and where they exist,
definitions diverge.
100
This is for example the case of France, where the Government may "take temporary measures to
attribute or suspend exploitation authorizations of electricity infrastructures". In Portugal, the Minister
for Energy can adopt transitory and temporary safeguard measures which include the use of fuel reserves
and the imposition of demand restrictions.
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today's interconnected electricity market, where the likelihood of crisis situations affecting
several Member States at the same time, is on the rise.
Where crisis situations stretch across borders (or have the potential of doing so), joint
action is needed, as well as clear rules on who does what, and when, in a cross-border
context. Uncoordinated actions and decisions in one Member State (for instance on what
to do to prevent a further deterioration of a crisis situations or on where to shed load, when
and to whom), can have serious negative effects:
For instance, as to date, several Member States still legally foresee 'export bans' (curtailing
interconnectors) in times of crisis101
. This undermines the proper functioning of markets
and can seriously aggravate security of supply problems in neigbouring Member States,
who might no longer be able to ensure that electricity is delivered to those that need it
most. The reverse situation is also true: where in a crisis situation an interconnected state
does not restrict its own electricity consumption, it risks propagating the crisis situation
beyond its own borders.
The dangers related to a purely national, inward-looking management of electricity crisis
situations, are illustrated by an incident that occurred during a prolonged cold spell in
February 2012102
. Confronted with a situation of unexpected shortage, one Member State
decided to resort to an export ban in an effort to protect its national consumption. This
aggravated however problems in other, neighbouring Member States, who in turn also
resorted to export bans. The ensuring cascade of export bans seriously imperiled security
of supply in an entire region of Europe103
.
101
One Member State specifically includes a legal provision on export bans in its legislation; eleven more
Member States include forms of export restrictions in national law, TSO regulations or multilateral
agreements. (Source: Risk Preparedness Study - "Review of current national rules and practices relating
to risk preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal
Network, study prepared for DG Energy).
102
Another example where domestic consumption was prioritized over exports occurred in the Nordic region
over the winter 2009/2010, where the region experienced a scarcity situation (in fact a series of them
that lead to three price spikes: on December 17, January 8 and February 22) with prices reaching 1000
EUR/MWh. The initial cause was the loss of approximately 5000 MW of Swedish nuclear capacity.
Maintenance on these plants over the summer was not completed on time, and so the plants were
functioning at diminished capacity (61% of normal operating capacity, on average) into the winter
Production reached a minimum on December 18, driving prices to the technical limit. This coincided
with a winter that was already colder that average. The limited nuclear capacity continued for a period
of a few weeks, and on January 8th
was exacerbated by a reduction in transmission capacity between
Norway and Sweden to 0MW because of higher than anticipated demand in Oslo. The Norwegian TSO,
Statnett, decided to prioritise domestic consumption over exports by eliminating the interconnector.
Finally, on February 22, continued low nuclear production combined with low hydro reservoirs in
Norway led to a general state of limited generation capacity. Statnett again reduced transmission capacity
(not to 0 MW but to 150 MW) and prices were again pushed to 1000 EUR/MWh or higher. Source: IEA
(2016): Electricity Security Across Borders. Case Studies on Cross-Border Electricity Security in
Europe.
103
Export limitations were imposed by Bulgaria on 10 February, by FYROM on the 13 February, by Bosnia
Herzegovina on 14 February, by Greece on 15 February and by Romania on 16 February.
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Purely national approaches to crisis prevention and management can also lead to premature
(and therefore unnecessary) market interventions, such as for instance a premature recourse
to an emergency extra reserve capacity, or to a demand interruption scheme.
Finally, different approaches to crisis prevention and management might also lead to cases
of 'under-protection. For instance, where Member States do not take the measures needed
to prevent (e.g., cyber-incidents), the entire region or even synchronous area is likely to
suffer. A similar problem might arise if Member States do not take the measures necessary
to protect assets that are critical from a security of supply perspective against possible take-
overs by foreign entities, in circumstances in which such take-overs could lead to any
undue political influence. Experience with recent take-overs (or planned take-overs) of
certain strategic energy assets in Europe shows that such risks are serious, notably where
the buyer is controlled by a third country. At this stage however, Member States address
this issue from a purely national perspective, based on national rules,104
without taking
necessarily account of the wider European implications possible problems could have. This
could lead to situations wherein some Member States take foreign ownership risks too
lightly, whilst other Member States might overreact.105
Evidence shows that in an inter-connected market, stronger co-operation on how to prevent
and manage crisis situations brings clear benefits: it leads to a better security of supply
overall, at a lesser cost. The recent METIS results106
point in this direction, as well as
experiences with a few voluntary arrangements in place in parts of Europe107
.
Driver 2: Lack of information-sharing and transparency
Today, national plans to prepare for crisis situations are not always public, nor shared
across Member States108
. It is not clear who will act in crisis situations, and what the roles
are of the different actors (governments, TSOs, DSOs, NRAs). This makes any cross-
border co-operation in times of crisis very difficult109
.
104
An increasing number of Member States adopt so called 'foreign investment screening laws', covering
notably changes of control over strategic energy assets.
105
See also the Impact Assessment accompanying the proposal for a Regulation concerning measures to
safeguard security of gas supply and repealing Council Regulation 994/2010 (SWD (2016) 25 final.
106
See Section 6.3.3. (Impact of policy Option 2).
107
For example, a co-operation agreement worked out amongst Nordic countries contains detailed
arrangements on how to deal with situations of simultaneous crisis, e.g., on curtailment sharing.
108
Nine Member States keep Risk Preparedness Plans confidential, eight make them public and eleven
others have a mixed framework with some measures being released and others being kept confidential.
(Source: Risk Preparedness Study - "Review of current national rules and practices relating to risk
preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal Network,
study prepared for DG Energy).
109
A recent simulation of an electricity crisis situation across Europe, showed that Member States were
neither adequately equipped to deal with the crisis nor the consequences thereof, largely because it was
not clear who did what in which country on what moment (cf. results of VITEX 2016 exercise, organized
by the Dutch Ministry: https://english.nctv.nl/currenttopics/news/2016/successful-international-
exercise-vitex.aspx?cp=92&cs=38 ). VITEX 2016 is an international table top exercise on the
improvement of Critical Infrastructure Protection. The main goal of the exercise is to strengthen the ties
between EU Member States on this subject. VITEX 2016 aims to create a shared understanding of what
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In addition, Member States do not systematically inform each other or the Commission
when they see crisis situations emerge. In fact, whilst ENTSO-E's seasonal outlooks110
already point at the likelihood of upcoming crisis situations in Europe, Member States
affected by such crisis situations do not systematically communicate on actions they intend
to take, nor on the possible effect of such actions on the functioning of the internal market
or the electricity situation in neighbouring Member States. In fact, in spite of the fact that
Member States are legally obliged to notify the Commission in case they take 'safeguard
measures', such notifications have been very rare, and tend to take place ex post (e.g.,
Poland in 2015)111
.
Likewise, there is no systematic exchange of information on how past crisis situations have
been handled.
Such lack of information-sharing and transparency limits the capacity of reaction of
potential Member States affected, may lead to premature interventions in the market, and
reduces the possible benefits that cooperation can bring.
In addition, even though the Electricity Coordination Group could be used as a tool to
discuss how to prevent and mitigate crisis situations112
, this does not happen in practice, in
the absence of clear and proper roles given to the group, and clear obligations on Member
States to report on how they address electricity crisis situations, both ex ante (before
incidents occur) and ex post.
Driver 3: No common approach to identifying and assessing risks
Whilst all Member States identify and assess risks that can affect security of supply, there
are many different understandings of what constitutes a 'risk' and methods for assessing
and addressing such risks vary considerably.
the Critical Infrastructures within Member States are and how European cooperation can contribute to
improve the resilience of Critical Infrastructure.
110
ENTSO-E has the obligation to carry out seasonal outlooks as required by Article 8 of the Electricity
Regulation. The assessment explores the main risks identified within a seasonal period and highlights
the possibilities for neighbouring countries to contribute to the generation/demand balance in critical
situations.
111
Poland activated a crisis protocol mid-August 2015 allowing the TSO to restrict power supplies to large
industrial consumers (load restrictions did not apply however to households and some sensitive
institutions such as hospitals). Poland notified the adoption of these measures under Article 42 of the
Electricity Directive one month after.
112
According to Article 2 of Commission Decision of 15 November 2012 setting up the Electricity
Coordination Group, the Group shall in particular "promote the exchange of information, prevention and
coordinated action in case of an emergency within the Union and with third countries".
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Different risks are assessed in different ways113
, by different people114
, and in different
time horizons115
.
There is also no common agreement on what indicators to use to assess security of supply
overall116
.
In the absence of a common approach to risk identification and assessment, it is difficult
to get an exact picture of what risks are likely to occur, in a cross-border context. This, in
turn, seriously hampers the possibility for relevant actors – TSOs, NRAs, Member States
– to prevent and manage crisis situations in a cross-border context.
2.4. Problem Area IV: The slow deployment of new services, low levels of service
and questionable market performance on retail markets
Retail markets for energy in most parts of the EU suffer from persistently low levels of
competition and consumer engagement. In addition, whilst information technology now
offers the possibility of greatly improving the consumer experience and making the market
more contestable, realising these benefits could be hampered by the lack of a data-
management framework that unlocks the full benefits of smart energy management to all
market actors – incumbents and new entrants alike.
These closely inter-related issues result in the slow deployment of innovative products
that would help to make the electricity system function better in today's changing
context, as well as excessive prices for some end-consumers and/or poor levels of
service.
113
There exists a patchwork of types of risks covered under the assessments in the Member States. The
level of detail in which the types of risks are described varies and a high level of detail was found in
three Member States. In five Member States the types of risks to be assessed are not or very generally
described. (Source: Risk Preparedness Study - "Review of current national rules and practices relating
to risk preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal
Network, study prepared for DG Energy).
114
The combination of national entities (TSOs, the competent Ministries, the NRAs and the DSOs)
responsible for risk assessment and the division of their roles, which are often defined by law, vary
across the Member States. TSOs play a major role in the assessment of risks in a majority of the
countries. (Source: Risk Preparedness Study - "Review of current national rules and practices relating
to risk preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal
Network, study prepared for DG Energy).
115
Time horizons covered can vary from one year to fifteen years. Moreover, some Member States set no
limits of validity for their measures, others have a system of continuous updates whist at least eleven
countries do not specify time horizons. (Source: Risk Preparedness Study - "Review of current national
rules and practices relating to risk preparedness in the area of security of electricity supply" (2016),
VVA Europe, Spark Legal Network, study prepared for DG Energy).
116
A wide variety of metrics and methodologies to assess security of supply and system adequacy is used,
but there is no specific reference to an economic value of adequacy (in particular to VOLL). Several
Member States have established standards, generally in terms of LOLE targets. However, information
is lacking on the criteria (if any) used to establish those standards. Metrics and standards have been set
through subjective decision, despite the evident fact that setting a standard (and the generation or
transmission capacity necessary to achieve that standard) will have an economic impact on consumers.
(Source: "Identification of Appropriate Generation and System Adequacy Standards for the Internal
Electricity Market" (2016), AF Mercados, E-Bridge, REF-Em, study prepared for DG Energy).
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R&D results: Retail level innovative products and services such as dynamic pricing, self-consumption
incentives, and local flexibility and energy markets, have been tested in European projects, EEPOS,
ECOGRID-EU, Grid4EU, INTrEPID, INCREASE, DREAM, Integral117
.
For example, ECOGRID-EU showed that the highest cost is in the installation of the automation
technologies, control systems and sensors in the household. These costs could be virtually zero in the future
when appliances are connected anyway.
Integral states that large scale implementation of demand-side response services based on a market for
flexibility requires standardised solutions (for the communication of the devices (smart meters and devices
controllers…) and for the framework within which market players communicate to each other) to reduce the
cost per household and to lower the price of the smart energy services.
Driver 1: Low levels of competition on retail markets
Competition on retail markets is multifaceted, and recent trends in several indicators
suggest that it can be improved in many Member States.
The price of energy for end consumer can be broken down into three main components: i)
energy, ii) network and iii) taxes and levies. The energy component typically includes cost
elements such as the wholesale price of the commodity and various costs of the supply
companies, including their operating costs and profit margins. The network component
mainly consists of transmission and distribution tariffs. It might also include further cost
elements such as ancillary services. The taxes & levies component includes a wide range
of cost elements that significantly vary from country to country. Levies are typically
designated to specific technology, market or socially bound policies, while taxes are
general fiscal instruments feeding into the state budget. On average in the EU in 2015
energy made up 36% of the final household consumer price, the network component 26%,
and taxes and levies 38%.
In spite of falling prices on wholesale markets (analysed earlier), overall electricity prices
for household consumers rose steadily between 2008 and 2015 at an annual rate of around
3%. This trend was largely driven by increased network charges, taxes and levies118
, the
117
A list of the research and development projects mentioned in this box and their findings relevant to the
present impact assessment is provided in Annex 8.
118
The average network component in consumer bills has increased by 25% since 2008, and cost EU
households 5.45 euro cents per kWh in 2015. Taxes and levies increased by 70% in the same period,
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various causes of which have been touched upon in the preceeding sections: the over
reliance of RES E assets on government support due to barriers to fully participating in all
markets; inflexible distribution networks that increase the cost of integrating RES E; and
fragmented balancing markets that increase the costs of ancillary services, amongst others.
However, a proxy for mark-ups119
on the energy component of consumer bills in several
Member States also seem to be higher than could be expected, posing questions about the
extent of price competition. Indeed, whereas there has been a significant reduction in
wholesale prices between 2008 and 2015, the nominal level of the energy component of
household electricity bills actually increased in 13 Member States during this period120
. In
these countries, the fall in wholesale prices has not translated into a reduction in the energy
component of retail prices despite the fact that this is the part of the energy bill
(representing around 36% of average household prices) where energy suppliers should be
able to compete.
Figure 5: Relationship between the wholesale price and the energy component of the
retail price in household segments in countries with non-regulated retail prices from
2008 to 2014 for electricity and from 2012 to 2014 in gas (EUR/MWh)
Source: ACER Database, Eurostat, NRAs and European power exchanges data (2014) and ACER
calculations. Note: Gas data are available only for the period 2012-2014.
Abnormally low mark-ups are equally problematic as they make it difficult or impossible
for a new supplier to compete against an incumbent. A reasonable mark-up is necessary
and stood at 7.92 euro cents per kWh in 2015. Energy taxation is not fully harmonized at the EU-level.
Source: DG ENER data.
119
As defined in "Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015, pp. 288-295. This proxy essentially measures the relationship between the
wholesale price and the energy component of the retail price. However, other factors apart from the
mark-up may affect this relationship, notably including a higher proportion of fixed charges in wholesale
prices.
120
DG ENER Data.
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for a new entrant to cover consumer acquisition and retention costs which are higher than
those of the incumbent who usually retains the most loyal (‘sticky’) customers. Mark-ups
that are too low and low levels of competition can be observed in several markets with
regulated prices (developed further on the next page)121
.
As for non-price competition, whilst sampling data from European capitals suggest that
'choice' for consumers in European capitals widened in recent years, a closer inspection
reveals that this has largely been driven by just two products – 'green' and dual-fuel
(electricity + gas) tariffs122
. The offer and uptake of other, more innovative consumer
products, such as aggregation services or dynamic price tariffs linked to wholesale
markets123
, remains limited.
Facilitating competition can be seen as means of improving consumer satisfaction.
However, the data indicate that there is clearly scope for improvement in this dimension,
too. According to the 2016 edition of the Commission's Consumer Scoreboard – a
comprehensive study measuring consumer conditions – electricity services rank 26th
and
gas services 14th
among the 29 markets for services across the EU. Indeed, the total
detriment to EU electricity consumers124
has recently been quantified at over EUR 5 billion
annually125
. Both markets can therefore be considered low performing from the consumer
standpoint.
High levels of market concentration also suggest that competition could be improved: The
cumulative market share of the three largest household suppliers (CR3) is greater than 70%
in 21 out of 28 Member States for electricity and in 20 out of 28 Member States for gas.
CR3 values above 70% are indicative of possible competition problems.
Also significant is the fact that some form of non-targeted price regulation for electricity
and/or gas still exists in 17 out of 28 Member States126
. The regulation of electricity and
gas prices may result in an environment that strongly impairs healthy competition,
particularly in terms of the level of customer service, or the development and provision of
121
Based on Annex 5, "Market Monitoring Report 2014" (2015) ACER and VaasaETT 2015
122
Source: ACER database.
123
See also the evaluation as regards Demand Response.
124
Consumer detriment involves consumers suffering harm or damage. Research for the Commission has
suggested the following two definitions of consumer detriment, for use in different policy contexts:
1. Personal detriment — negative outcomes for individual consumers, relative to reasonable
expectations.
2. Structural detriment — the loss of consumer welfare (measured by consumer surplus) due to market
failure or regulatory failure.
"An analysis of the issue of consumer detriment and the most appropriate methodologies to estimate it;
Final report for DG SANCO by Europe Economics” (2006) Europe Economics.
125
Sum of total post-redress financial detriment & monetised time loss. "Study on measuring consumer
detriment in the European Union" (2016) Civic Consulting,
126
This figure is comprised of Member States which regulate both electricity and gas prices, as well as
Member States which regulate exclusively gas or electricity prices. In addition, Commission classifies
Italy as having regulated electricity prices whereas ACER does not in their "Market Monitoring report
2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015, pp 88-96,
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innovative new services that consumers would be willing to pay extra for. Reliance on the
government to set prices can result in consumer disengagement. In addition, regulatory
intervention in price setting can have a direct impact on suppliers' ability to offer products
that are differentiated in terms of pricing-related aspects – dynamic price tariffs that reflect
the minute-by-minute fluctuations on wholesale markets, for example.
When justifying price regulation Member States cite the need to protect the vulnerable and
energy poor along with the need to protect all customers against the risk of market abuse.
Around 10.2% of the EU population might be affected by the problem of energy poverty,
based on a proxy indicator measuring "the inability to keep home adequately warm"127
. If
energy prices continue to increase, it is likely that energy poverty across the EU will
increase and therefore more pressure to maintain energy price regulation.
Under the existing provisions in the Electricity and Gas Directive, Member States have to
address energy poverty where identified. The evaluation of the provisions found important
shortcomings stemming from the unclarity of the term energy poverty, particularly in
relation to consumer vulnerability, and the lack of transparency with regards to the number
of households suffering from energy poverty across Member States.
Addressing the issue of energy poverty through blanket price regulation can be
disproportionate as it affects all consumers big or small, rich or poor. It can also lead to a
chicken-and-egg problem whereby price regulation leads to distortions to the market and
low competition, which are in turn used to justify the continuation of price regulation.
Resolving this impasse would allow one of the most fundamental aspects of the market –
the price mechanism – to function properly.
ACER's Retail Competition Index – a composite indicator that draws upon many of the
abovementioned statistics, as well as others128
– was developed to achieve a full picture of
retail market competitiveness which is not dependent on a single indicator. It illustrates the
disparities in retail markets that still exist between Member States, and clearly suggests
that competition can be improved in a number of them (see Graph 3).
127
The indicator is measured as part of the Eurostat Survey on Income and Living Conditions (EU-SILC).
128
1) Concentration ratio, CR3; 2) Number of suppliers with market share > 5%; 3) ability to compare prices
easily; 4) average net entry (2012-2014); 5) switching rates (supplier + tariff switching) over 2010-2014;
6) non-switchers; 7) number of offers per supplier; 8) measure of whether the market meets consumer
expectations; 9) average mark-up (2012–2014) adjusted for proportion of consumers on non-regulated
prices.
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Figure 6: ACER Retail Competition Index (ARCI) for electricity household markets
in 2014
Source: ACER
Driver 2: Possible conflicts of interest between market actors that manage and
handle data
High levels of information asymmetry (between incumbents and potential entrants) and
high transaction costs impede competition and the provision of high levels of service on
retail markets for energy.
For example, studies from NRAs cite discriminatory access to information on potential
customers as a key barrier for new entrants to EU retail energy markets (Box 1 under). As
most DSOs are also energy suppliers, safeguards are necessary to prevent them using
privileged access to consumer data – especially smart metering data – to gain a competitive
advantage in their supply operations.
In addition, "unjustified" or "incorrect" invoices are one of the largest sources of electricity
and gas consumer complaints reported to the Commission129
– an issue that can be largely
resolved if accurate metering information were made quickly and readily available to
suppliers and consumers.
Information technology could directly address these issues, making the market more
contestable, facilitating the development of new services and improving the customer
experience around day-to-day operations such as billing and switching. Although 80% of
EU consumers should have smart meters by 2020, the experience from Member States that
129
These made up around 10% of all electricity and gas complaints. Source: European Consumer
Complaints Registration System.
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have already rolled them out indicates that robust rules are necessary to ensure the full
benefits of smart metering data are realised, and that data privacy is respected. Such rules,
however, are not fully developed in the existing EU legislation, and the diverse interests
of market actors who may be involved in data handling mean that they are unlikely to
emerge without regulatory intervention.
Box 1: Data management as a market entry barrier130
Data management comprises the processes by which data is sourced, validated, stored,
protected and processed and by which it can be accessed by suppliers or customers
The necessity to adapt to different data management models for each market can have an
impact on the resources of the potential market newcomers. Non-discriminatory and
smooth accessibility of data is naturally most important during the pre-contractual phase
as well as for running contractual situations. The fact that not all countries have rolled out
smart meters yet also creates significant differences in the availability and accessibility of
data.
A standardised approach to the provision and exchange of data creates a level playing field
among stakeholders and helps to encourage new challenging market actors to enter a new
market.
Driver 3: Low levels of consumer engagement
Consumer engagement is essential for the proper functioning of the market. As such, it is
closely inter related with competition (Driver 1). However, consumers are also put-off
from engaging in the market by behavioural biases and bounded rationality that make it
harder for them to take the decision to search for, and to switch to, the best offer.
In particular, three key barriers to consumer engagement have been identified. First, the
broad variety of fees that consumers may be charged when they switch diminishes the
(perceived) financial gains of moving to a cheaper tariff in what is already a marginal
decision for many consumers. The evidence suggests around 20% of electricity consumers
in the EU currently face a fee of between EUR 5 and EUR 90 associated with switching
suppliers. A portion of those fees – affecting around 4% of consumers – may be illegal
under existing EU legislation (see Section 2.6.2).
Secondly, whereas online comparison websites play an important role in helping
consumers to make an informed decision about switching suppliers, recent reports of
unscrupulous practices have damaged consumer trust in them. Identified issues include the
130
Adapted from: CEER Benchmarking report on removing barriers to entry for energy suppliers in EU
retail energy markets, (2016) p. 19,
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/tab6/C15-RMF-70-03_BR_barriers_to_entry_for_suppliers_1-Apr-2016.pdf. See also VaasaETT
(2014), ' Market Entrant Processes, Hurdles and Ideas for Change in the Nordic Energy Market', p.22,
http://www.nordicenergyregulators.org/wp-content/uploads/2014/12/VaasaETT-Report-
Market_Entry_Barriers.pdf.
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default presentation of deals by some websites, the use of misleading language, and a lack
of transparency about commission arrangements. Indeed, a third of respondents to a recent
EU survey somewhat or strongly agreed that they did not trust comparison websites
because they were not impartial and independenct.131
And thirdly, consumer groups report that consumers have difficulties understanding their
energy bills and comparing offers in spite of existing EU legislation aiming to facilitate
this. There is a broad divergence in national requirements around billing and consumer
satisfaction with their bills varies significantly between different Member States. Whereas
energy bills are the foremost means through which suppliers communicate with their
customers, consumers' inability to correctly answer simple questions about their own
electricity use reveals that bills are not effective in providing information that could
facilitate effective consumer choice.132
Addressing this will be increasingly important with
the shift to more varied consumer products.
R&D results: The project S3C has developed a toolkit for the active engagement of end users and identifies
improvements to the way and content of the communication of energy system actors with customers and
citizens.
2.5. What is the EU dimension of the problem?
The EU's electricity market is strongly integrated physically, economically and from a
regulatory point of view. The discretion of Member States to act individually has been
substantially reduced by the resulting interdependencies and, in fact, can create significant
externalities if not adequately framed within an EU-wide context.
RES E deployment is expected to increase in all Member States. The need to spur the
emergence of a more flexible electricity system thus exists EU-wide. Moreover, as the EU
electricity system is both physically and economically integrated, non-coordinated action
is likely to increase the costs of RES E integration.
The same applies to CMs where the externalities of non-coordinated action are one of the
underlying reasons for the proposed measures. It is true that not all Member States have
enacted CMs, however the benefits of a more coordinated approach will benefit all
Member States. Member States that have implemented a CM will be able to lower their
costs by increased cross-border competition whereas the avoidance of negative spill-over
effects will benefit all Member States regardless as to whether they enacted a CM or not.
In an integrated electricity market, considering the prevention and management of
electricity crisis a purely national issue leads to serious problems. Where crisis situations
occur, they often have a cross-border effect, and can entail serious adverse consequences
for the EU as a whole. Evidence shows that non-coordinated approaches to preventing and
managing electricity crisis may seriously distort the internal electricity market and put at
risk the security of supply of neighbouring Member States.
131
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, pp. xix, 191.
132
For example, less than one third of consumers recently surveyed strongly agreed that they knew what
kind of a contract they currently had (fixed price, variable price, green, etc.).
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Well designed and implemented consumer policies with a European dimension can enable
consumers to make informed choices that reward them through healthy competition, and
support the European goal of sustainable and resource-efficient growth, whilst taking
account of the needs of all consumers. Increasing confidence and ensuring that unfair
trading practices do not bring a competitive advantage will also have a positive impact in
terms of stimulating growth. The consumer-related measures undertaken as part of this
initiative therefore play an essential role in the establishment and functioning of the
internal market.
2.6. How would the problem evolve, all things being equal?
The projected development of the current regulatory framework
In the absence of additional measures, the electricity market would continue to be governed
by the Third Package and the Electricity Security of Supply Directive. Various network
codes may still be adopted and implemented133
, such as the draft Network Code on
Emergency and Restoration and the Balancing Guideline. Whilst these network codes will
help address some of the issues identified above, they will not offer a sufficient remedy on
their own.
Solving the above-identified problems requires measures that cannot be addressed in the
current legal framework. As the network codes constitute secondary implementing
legislation designed to amend non-essential elements of the Third Package by
supplementing it, their scope is confined to the same limits drawn by the Third Package
and hence, developing new network codes cannot be expected to provide for adequate
solutions either.
In view of the fact that the proposals in essence develop new areas for which currently no
clear legal basis exist in the Third Package or in the Electricity Security of Supply
Directive, stronger enforcement is not an option either (with some limited exceptions,
which are further developed below).
Member States have developed forms of voluntary collaboration that attempt to address
some of the problems identified. However, these initiatives cannot be expected to resolve
all problems and with the same effectiveness as EU action (See also EU value added).
Regarding security of supply in particular, both the evaluation and the results of the public
consultation clearly show that Directive 2009/89 is outdated. It does not take account of
the current, fast evolving situation of the electricity market. And it offers no framework
for coordinating national policies in the area of security of electricity supply.
With regards to consumer issues, the Commission may develop guidance to tackle
implementation issues caused by difficulties in interpreting the existing legislation. In
particular, it may issue an interpretative note on the existing provisions in the Electricity
and Gas Directives covering switching-related fees, as well as further guidance on how the
dozen or so consumer Directives relevant to comparison tools should be applied.
133
For a full overview of network codes, see Annex VII.
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On energy poverty, the Commission will already set up the EU Energy Poverty
Observatory using funds already secured from the European Parliament. However, the
extent to which the Observatory continues to share good practices and improve data
gathering is uncertain, as continued funding is not secured beyond the first year of
operation. Moreover, the impact of this measure may be limited as the current legislation
does not require Member States to measure energy poverty and hence to address it.
Expected evolution of the problems under the current regulatory framework
Both this and the impact assessment for the parallel RED II initiative come to the
conclusion that the electricity market, provided that it is improved, together with projected
CO2 prices, may deliver investments in most mature low-carbon technologies such as solar
PV and onshore wind by 2030. However, in the absence of a market optimised for
increasing levels of renewable penetration, achieving the 2030 objectives will only be
possible at significantly higher costs.
In the absence of a better defined framework for government interventions, the current
trend of non-coordinated implementation of national resource adequacy measures risks
proliferating, undermining the efficiency of the market to deliver efficient production and
investment decisions and defragmenting its regulatory framework.
In fact, in the absence of measures that will improve investment incentives and efficient
market functioning, it is likely that more Member States will have to take recourse to means
other than the market to secure sufficient investments for resource adequacy purposes,
setting in motion a negative spiral in which government interventions increase the need for
the subsequent one.
Failing to integrate all participants in the market means that their decisions will not be
guided by market signals, entailing the risks that their investment and production decisions
will be sub-optimal from a welfare perspective, if not distort markets.
In addition, in the absence of a clear framework for co-ordinated action between Member
States when it comes to preventing and managing crisis situations, the EU's electricity
system risks being increasingly exposed to risks of serious incidents, without the EU or its
Member States having any means to properly tackle them. There is a real risk that Member
States will continue to do as they see fit in crisis situations, thus undermining the proper
functioning of the internal electricity market.
Regarding active consumer engagement, Member States have committed to deploying
smart meters to around two thirds of the population while access to innovative services
such as demand response or in the area of self generation remains limited in many Member
States. Individual action by Member States would perpetuate current differences in the
Union regarding consumer awareness, choice and access to dynamic prices, demand
response and integrated smart services. Consumer-friendly functionalities would be taken
up partially and the flexibility consumers can provide to the electricty system would remain
largely untapped.
With regards to consumer protection and engagement, enforcement could help diminish
the illegal switching-related costs currently faced by an estimated 4% of all EU electricity
consumers. And some Member States may also voluntarily cease or reduce excessive
regulatory interventions in price-setting as their retail markets mature. However,
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shortcomings in the existing legislation will greatly limit the Commission's ability to tackle
these and other consumer-related problem drivers more effectively.
The issue of energy poverty is likely to remain relevant. Pressure on energy prices may
continue as a result of the efforts to decarbonise the energy system. If energy prices grow
faster than household income, more and more households will find it difficult to pay their
energy bills. This may have a knock-on effect on Member States willingness to lift price
regulation which will ultimately impact suppliers' ability to innovate, competition and
consumer welfare. Thus, the greater the importance of enhanced transparency to estimate
the number of energy poor households.
And whilst many Member States may seek to ensure the neutral, expedient, and secure
management of consumer data, it is highly likely that national requirements will vary
significantly, leading to an uneven playing field for new suppliers and energy service
companies in the EU. Here, the only credible approach to effectively tackling the potential
conflicts of interest among market actors is a legislative one.
2.7. Issues identified in the evaluation of the Third Package
A retrospective evaluation was carried out in parallel with the present impact assessment
and has been added as Annex VI. Its main conclusions are:
- That the initiative of the Third Package to further increase competition and to
remove obstacles to cross-border competition in electricity markets has generally
been effective and that active enforcement of the legislation has led to positive
results for electricity markets and consumers. Markets are in general less
concentrated and more integrated than in 2009. As regards retail markets, the set
of new consumer rights introduced by the Third Energy Package have clearly
improved the position of consumer in energy markets.
- However, the success of the rules of the Third Package in developing the internal
electricity market further to the benefit of customers remains limited in a number
of fields concerning wholesale and retail electricity markets.
- Moreover, while the principles of the Third Package achieved its main purposes
(e.g. more supplier competition), new developments in electricity markets such as
the increase of RES E, the increase of state interventions into the electricity markets
and the changes taking place on the technological side have led to significant
changes in the market functioning in the last five years and have dampened the
positive effect of the reforms for customers. There is a gap in the existing legislation
regarding how to deal with these developments.
The conclusions of the evalution are also reflected in section 3 of each of the Annexes
1.1 throught to 7.6 to the present impact assessment.
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3. SUBSIDIARITY
3.1. The EU's right to act
In order to create an internal energy market, the EU has adopted three consecutive
packages of measures between 1996 and 2009 aiming at the integration and liberalisation
of the national electricity and gas markets and addressing a wide range of elements such
as market access, the improvement of the level playing field, transparency, increased rights
for consumers, stronger independence of regulatory authorities, etc. In February 2011, the
European Council set the objective of completing the internal energy market by 2014 and
of developing interconnections to put an end to any isolation of Member States from the
European gas and electricity grids by 2015. In June 2016, the European Council called for
Single Market strategies, including on energy, and action plans to be proposed by the
Commission and to be completed and implemented by 2018.
Article 194 of the Treaty on the Functioning of the European Union ('TFEU') consolidated
and clarified the competences of the EU in the field of energy. According to Article 194
TFEU, the main aims of the EU’s energy policy are to: ensure the functioning of the energy
market; ensure security of energy supply in the Union; promote energy efficiency and
energy saving and the development of new and renewable forms of energy; and promote
the interconnection of energy networks.
The planned measures of the present intiative further progress towards the objective of
improving the conditions for competition by improving the level playing field, while at the
same time adjusting to the decarbonisation targets and enhancing the solidarity between
Member States in relation to security of supply.
Therefore, Article 194 TFEU is the legal basis of the current proposal.
3.2. Why could Member States not achieve the objectives of the proposed action
sufficiently by themselves?
The section below provides a high-level summary of the necessity of EU action, based on
the four problem areas identified in section 2.
The issue of subsidiarity is also discussed in section 6 of Annexes 1.1 to 7.6 to the present
impact assessment.
As regards the issue concerning a market design that is not fit for taking up large amounts
of variable, decentralised electricity generation and allowing for new technical
developments, it is important to note that EU action is necessary to ensure that national
markets are comparable in order to improve the functioning of the internal electricity
market and enable maximum cross-border trading to happen. EU-action is also necessary
in order to enhance the transparency in the functioning of the electricity markets and avoid
discrimination between market parties. Moreover, a number of the measures proposed to
address this issue (e.g., measures for the common sizing and procurement of balancing
reserves) require full cooperation of neighbouring TSOs and NRAs, and hence individual
Member States might not be able to deliver a workable system or might only provide
suboptimal solutions. Moreover, existing provisions under the Third Package are arguably
not sufficiently clear and robust and their implementation of such rules has highlighted
areas with room for improvement and hence EU action will be necessary to address the
identified shortcomings.
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With specific respect to DSOs, distribution grids will have to integrate even greater
amounts of RES E generation in the future, and so ensuring all DSOs can efficiently
manage their networks will help to reduce distribution costs and thereby support the
achievement of EU RES targets. In addition, widely divergent distribution tariff regimes
may affect the development of the internal energy market as they affect the conditions
under which RES E generation or other resources can access the grid and participate in the
national and cross-border energy markets. EU action in these areas would thereby facilitate
the deployment of RES E and create a level playing field for flexibility services such as
demand response by ensuring a coherent approach by Member States based on common
principles. Developing this through independent Member State action would not be
feasible given the heterogeneity of current national networks and regulations.
Concerning the uncertainty about future investments in generation capacity and
uncoordinated government interventions, the measures in the proposed initiative aim at
improving the functioning of the electricity markets and at improving the coordination
between Member States for capacity mechanisms. The necessity of EU action derives from
the fact that as regards the measures for improving the functioning of the electricity
markets, these are already covered by EU legislation, although not sufficiently clearly, and
therefore an amendment to such measures to address the distortions and deficiencies
identified would require EU action. For the measures concerning the improvement of the
coordination between Member States for capacity mechanisms, given that the aim is to
address the shortcomings identified from resource adequacy assessments carried out at
national level and to develop the cross-border participation in capacity mechanisms, the
EU is best placed to provide for a harmonised framework.
In relation to the problem that Member States do not take into account of what happens
across their borders when preparing for and managing electricity crisis situations, the
necessity of EU action is based on the evidence that uncoordinated national approaches
not only lead to the adoption of suboptimal measures but that they also make the impacts
of a crisis more accute. Given the interdependency between the electricity systems of
Member States, the risk of a blackout is not confined to national boundaries and could
directly or indirectly affect several Member States. Therefore, the actions concerning
preparedness and mitigation of crisis situations cannot be defined only nationally, given
the potential impact on the level of security of supply of a neighboring Member State
and/or on the availability of measures to tackle scarcity situations.
Regarding the slow deployment of new services, low quality of services and increasing
mark-ups on retail markets, there is a clear need for EU action to ensure convergence of
national rules, which is a precondition for the development of cross-border activity in the
retail markets. Moreover, national regulations have in some instances led to distortions,
weakening the internal energy market. Such distortions can be observed in relation to the
protection of vulnerable and energy poor consumers which is a policy area characterised
by a great variety in types of public internvention across Member States, both in terms of
the definitions used and in terms of the levels of protection established. In that case EU
action is justified not only to ensure customer protection and enhanced transparency but
also to improve the functioning of the internal market through a more cohesive approach
across all markets.
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3.3. Added-value of action at EU-level
The initiative aims at amending existing EU legislation and at creating new frameworks
for cross-border cooperation, which can legally and practically only be achieved at the
European level.
National policy interventions in the electricity sector have direct impact on neighbouring
Member States. This even more than in the past as the increasing cross-border trade, the
spread of decentralised generation and more enhanced consumer participation increases
spill-over effects. No state can effectively act alone and the externalities of unilateral action
have become more important.
To illustrate, uncoordinated national policies for distribution tariffs may distort the internal
market for distributed resources such as distributed generation or storage, as such resources
will increasingly participate in energy markets and provide ancillary services to the system,
including across borders. Furthermore, the lack of appropriate incentives for DSOs may
slow down the integration of RES E, and the uptake of innovative technologies and energy
services. EU action therefore has significant added value by ensuring a coherent approach
in all Member States.
It is true that certain Member States collaborate on a voluntarily basis in order to address
certain of the identified problems (e.g. Pentalateral Energy Forum –PLEF-, CEEE).
However, these fora are characterised by different levels of ambition and effectiveness and
are held-back by the fact that no means exist to enforce agreements on market design
related arrangements. Moreover, even if one would presume that they would be fully
effective in these regards, they geographically cover only part of the EU electricity market.
It should be added that clear synergies exist between the present initiative and other EU
policy objectives, notably the EU's climate policies and other policy objectives in the
energy field. Indeed, a well-functioning market is the base upon which the ETS can most
efficiently deliver its goals and will permit a cost effective integration of RES E in the EU's
electricity markets.
Consequently, the objectives of this initiative cannot be achieved only by Member States
themselves and this is where action at EU-level provides an added value.
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4. OBJECTIVES
4.1. Objectives and sub-objectives of the present initiative
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4.2. Consistency of objectives with other EU policies
The consistency of the present initiative with various parallel initiatives in the energy
policy area was already explored in section 1.2.
The ETS constitutes a cornerstone of the European Union's policy to combat climate
change and its key tool for reducing industrial and electricity sector greenhouse gas
emissions cost-effectively. To achieve the at least 40% greenhouse gas emission reduction
target, the sectors covered by the ETS, which includes electricity generation, have to
reduce their emissions by 43% compared to 2005. The ETS interacts with the electricity
markets as it places a price on emissions of CO2, which is proportional to the emissions'
intensity of electricity production. This can be taken into account for both operational
decisions as well as for investment decisions, in which price expectations for the future
will also play a larger role due to the long-term nature of investments in the electricity
sector. (By contrast, decommissioning decisions may be primarily driven by short-term
considerations relating primarily to operational costs and revenues). The ETS thus
functions by affecting production and investment decision of electricity market actors134
.
It follows that an ETS can only function if its is complemented by an efficient electricity
market is. The objectives of the ETS and the present proposals are hence complementary
to one another and mutually reinforcing.
The Effort Sharing Decision establishes binding annual greenhouse gas emissions for
Member States for the period 2013-2020 in sectors not covered by the ETS and forms part
of the climate and energy package. As part of the 2030 climate and energy framework, a
similar binding emission reduction framework is proposed for the period 2021-2030.
Reducing greenhouse gas emissions by 30% in effort sharing sectors below 2005 levels
can have an indirect impact on the projection for the demand of electricity in 2030 and this
has been taken into account in the Impact Assessment by using the EUCO27 scenario in
the baseline against which the impacts of the present initiative is being assessed.
The Communication on the decarbonisation of transport in 2030 aims at setting out a
strategy covering several legislative and non-regulatory initiatives covering the transport
sector which will be subsequently proposed to contribute to meeting the agreed 2030
greenhouse gas reduction targets. The decarbonisation of transport in 2030 has an impact
on the projection for the demand of electricity in 2030, primarily via the electrification of
transport, and this has been taken into account in the Impact Assessment by using the
EUCO27 scenario in the baseline against which the impacts of the present initiative is
being assessed. The efficient integration of electric vehicles into the electricity system
requires incentivising their charging to take place at times of low electricity demand and/or
134
The existing imbalance between the supply and demand for ETS allowances has limited the impact of
the carbon price in recent years. However, the agreement in 2014 to postpone the auctioning of 900
million allowances, and the decision in 2015 to introduce a Market Stability Reserve from 2019 onwards,
as well as the proposal to revise the EU ETS, including a higher annual reduction to the number of
allowances in the ETS from 2021 onwards, will gradually address the surplus of allowances. With the
introduction of the auctioning of allowances as the default method of allocation for installations in the
power sector from 2013 onwards and a single EU wide limit or cap on the overall number of allowances
in the system, the EU ETS already provides a largely harmonised incentive for decarbonisation at EU
level.
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high supply. The present initiative aims at enabling and rewarding consumers to manage
their consumption, including when charging their electric vehicles, actively via demand
response thus enabling smart charging. In essence, electric vehicles will thus become part
of the supply of flexibility to the electricity system.
EU's competition instruments and, in particular, the EU state aid rules are applicable to the
energy sector. They have been clarified in the Guidelines on State aid for environmental
protection and energy 2014-2020135
. These EEAG aim at supporting Member States in
reaching their 2020 targets while addressing the market distortions that may result from
subsidies granted to RES. To this end, the EEAG promote a gradual move to market-based
support for RES E. They also include provisions on aid to energy infrastructure and rules
on aid to secure adequate electricity capacity, allowing Member States to introduce CMs
when there is a real risk of insufficient electricity generation capacity. The objectives and
the rules of the EEAG are set to avoid undue competition distortions from national support
provided in the energy sector. The proposed initiative to strenghten efficient, integrated
and functioning electricity markets is complementary to this framework.
The existing EEAG already go a considerable way in guiding CMs. The present initiaitve
intends to complement this framework. For instance:
- The EEAG require that state intervention in support of resource adequacy must be
necessary. The MDI impact assessment136
thus explores options for creating a
robust framework for assessing the EU's adequacy situation which could give a
good sense how much intermittent renewables can contribute to security of supply
or to what extent Member States can rely on supplies from their neighbours. Today,
Member States introduce capacity mechanisms based on national reports which
assess these factors very differently and underestimate the contribution of RES E
or foreign supplies to a Member States' security of supply. Therefore a genuine and
high quality assessment which will help assessing real needs and question
unfounded national claims.
- The EEAG already require that national capacity markets are open to foreign
resources. However, organising effective foreign participation in national
mechanism requires active contributions of several parties. The MDI impact
assessment137
explores options for defining clear roles and responsibilities to
capacity providers, transmission system operators and regulators so that foreign
participation becomes effective and that investment incentives are not distorted
across the borders.
The proposed changes on the new performance based remuneration framework for DSOs
would also support the Digital Single Market Strategy in the sense that those would
provide further incentives to enable cross sector synergies in electronic communication
infrastructure deployment allowing win win solutions for the cost efficient and timely
smartening of grids and high speed connectivity for EU citizens, also decreasing the digital
divide and providing the backbone for digital products and services which have the
potential to support all aspects of the lives of EU citizens, and drive Europe's economic
135
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A52014XC0628(01)
136
See the preferred option in problem area II
137
See the preferred option in problem area II
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recovery. The proposed measures would complement from the energy regulatory side the
measures already introduced with Directive 2014/61/EU which aims at reducing the cost
of high speed broadband infrastructure deployment partly via cross sector synergies.
The proposed measures do in general have no interaction with the fundamental rights laid
down in the Charter of Fundamental Rights, with the exception of the processing of
personal data and improvement of consumer protection. These elements are discussed in
more detail in section 6.4.6, Annex 7.1 and Annex 7.3.
The New Skills Agenda for Europe focuses on skills as an elevator to people's
employability and prosperity, in line with the objective of a "social triple-A" for Europe.
It will promote life-long investment in people, from vocational training and higher
education through to digital and high-tech expertise and the life skills needed for citizens'
active engagement in changing workplaces and societies. The energy transition will bring
significant shifts in employment and skill sets required for employees active in the energy
sector as traditional means of generation will be replaced by RES E. This transition is
however primarily driven by EE and RED II related measures as well as national choices
as to the generation mix. More relevant for the present initiative are the measures aiming
at inducing the development of the retail markets from electricity supply markets towards
including more service oriented product offerings facilitating the participation of
consumers in the electricity market.
As regards consumer rights, the Unfair Commercial Practices Directive is the overarching
piece of EU legislation regulating unfair commercial practices in business-to-consumer
transactions. It applies to all commercial practices that occur before (i.e. during advertising
or marketing), during and after a business-to-consumer transaction has taken place. Where
sector-specific EU law is in place and its provisions overlap with the provisions of the
UCPD, the corresponding provisions of the sector-specific EU rules prevail, so no
contradictions exist.
Research, Innovation and Competitiveness being Energy Union's 5th
dimension, cuts
across all its elements. The Strategic Energy Technology Plan implements the energy
union's fifth dimension, promotes research and innovation for low carbon technologies,
contributing to the transformation of the EU's energy system and creating jobs, growth and
global export opportunities in the fast-growing clean-technology sector. Technological
developments create opportunities for citizens to turn from being passive consumers of
electricity into prosumers that actively manage their consumption, storage and production
of electricity and participate in the market and allow for the increasing penetration of
distributed resources. A new Research, Innovation and competitiveness strategy,
encompassing energy, transport and industrial competitiveness aspects is expected to be
presented in the months to come. This strategy builds on the achievements of the SET Plan
and further addresses the R&I challenges particularly towards industrialisation of
innovative low carbon technologies.
The present initiative is fully coherent as it seeks to remove barriers for the participation
of consumers, for bringing new resources to the market and seeks to improve price
formation with a view to create the conditions for new business models to emerge and for
innovative products to be absorbed by the market.
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5. POLICY OPTIONS
A fully functioning European wide electricity market is the best means to ensure that
electricity can be delivered to consumers in the most cost-efficient way at any time. To
continue fulfilling that purpose, the electricity market needs to be able to adapt to the
significant increase of variable renewable electricity production, integrate new enabling
technologies such as smart grids, smart metering, smart-home, self-generation and storage
equipment, empower citizens to take ownership of the energy transition and assure security
of electricity supply at least costs. Market mechanisms may need to be complemented by
initiatives which help preventing and managing electricity crisis situations.
Any EU action aimed at strengthening the market should build on the gradual liberalisation
of the EU energy markets resulting from the three Energy Packages described earlier in
this document.
The following policy options have been considered to address the problems of today's
electricity market and to meet the broad energy policy objective of ensuring low carbon
electricity supply to European customers at least costs. In assessing all possible options to
achieve this broad objective, the following approach was taken:
- Identification of the main areas where initiatives might be needed to achieve
the main objectives of a new electricity market design. These Problem Areas
are set out in Box 2 below: "Overview of Problem Areas".
- To address each Problem Area a set of high level options was identified (set-
out in the following paragraphs). Each of these high level options groups
options for specific measures.
- A bottom-up assessment was performed for each specific measure, comparing
a number of options in order to select the preferred approach. The assessments
of the specific measures can be found in the Annexes to the present impact
assessment.
To help the reader, a table matching the assumed measures for each high level option is
included at the end of each problem area with references to the Annexes.
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Box 2: Overview of Problem Areas
Problem Area I: Market design not fit for taking up large amounts of variable,
decentralised electricity generation and allowing for new
technological developments
Problem Area II: Uncertainty about sufficient future investments in generation
capacity and un-coordinated government interventions
Problem Area III: Member States do not take sufficient account of what happens
across their borders when preparing for and managing electricity
crisis situations
Problem Area IV: The slow deployment of new services, low levels of service and
poor retail market performance
5.1. Options to address Problem Area I (Market design not fit for an increasing
share of variable decentralized generation and technological developments)
Overview of the policy options
With a significant part of the produced electricity coming from variable renewable sources
and distributed resources, new challenges will be arising in terms of security of supply and
electricity price volatility. The options examined here aim to address these challenges in
the most cost-effective way for the whole European electricity system. These system cost
savings will be passed on to consumers by way of lower network charges. They will also
make it easier for RES E assets to earn a higher fraction of its revenues through the market.
Two possible paths were identified: the path of enhancing current market rules in order to
increase the flexibility of the system, retaining to a certain extent the national operation of
the systems (with more or less coordination assumed depending on the related sub-options)
and the path of moving to a fully integrated approach.
Box 3: Overview of the Policy Options for Problem Area I
Each policy option consists of a package of measures which address the drivers of the
problem. In the following sub-sections, the high level policy options and the packages of
measures they contain are described. Details on the individual measures are included in
the Annexes. It is then explained if any of those options are to be discarded at this stage,
prior to assessment, or whether other options were considered but were discarded from the
outset. The section is closed by a table summarising all specific measures included in each
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option and references to the Annexes where each measure is described and asessed in more
detail.
The relevant Annexes addressing the policy options below in more detail are: 1.1 to 3.4.
Option 0: Baseline Scenario – Current Market Arrangements
Under this option no new legislation is adopted, but there is some effort to implement
existing legislation including via the adoption of so-called network codes or guidelines.
The network codes, provided for in Article 6 and the guidelines provided for in Article 18
of the Electricity Regulation specify technical rules on the operation of European electricty
markets138
. They are, as such, only designed to amend non-essential elements of the
Electricity Regulation and can only be adopted in areas specifically mentioned in the above
mentioned Articles.139
Under these limitiations, network codes/guidelines are not the suitable instrument to
achieve all objectives of this initiative. For instance, whereas the implementation of the
Guideline on Capacity Allocation and Congestion Management ('CACM Guideline') will
bring a certain degree of harmonisation of cross-border intraday markets, gate closure
times and products for the intraday, as well as a market clearing, there is no guarantee that
the local market will adapt to reflect the cross-border approach and practices (auctions /
continuous trading) and local intraday markets across Europe will continue to remain non-
harmonised. This means that the EU-wide intraday market coupling envisaged by the
CACM Guideline will not be able to reach its full potential.
The Balancing Guideline is expected to bring certain improvements to the balancing
market, namely the common merit order list for activation of balancing energy, the
standardisation of balancing products and the harmonisation of the pricing methodology
for balancing. Nonetheless, other important areas like balancing capacity procurement
rules, frequency, geographical scope and sizing will not be affected by this regulation.
Priority dispatch rules, must-run priorities and other technology specific rules related to
the scheduling and operation of the system do not change at all with the adoption of
network codes. The same applies for the possibility for demand and distributed resources
to access the markets, and to compete on a level playing field with thermal generation. The
baseline assumes that demand response exists only in countries where it currently has
access to the market, with only industrial consumers being able to participate.
Overall, this option assumes that the future situation will remain more or less the same as
today, except from some specific measures included in the network codes (as above). The
138
More detail as regards network codes and guidelines is provided in Annex VII.
139
CIGRE paper C5-202 (2016): "Market coupling, facing a glorious past?" by R.Hirvonen, A.Marien,
B.Den Ouden, K.Purchala, M.Supponen, describes the past and future challenges of implementing
market coupling.
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baseline does not consider explicitly any type of existing support schemes for power
generation plants, neither in the form of RES E subsidies nor in the form of CMs140
.
Stakeholders' opinions141: None of the respondents to the public consultation expressed
the opinion that there is no need for further upgrade of the current market arrangements.142
Option 0+: Non-regulatory approach
Whilst systematically considered143
, no such option could be identified144
.
Stronger enforcement provides little scope for improving the level playing field among
resources. To the extent the lack of a level playing field is due to the variety of provisions
in national law, a clear and transparent EU framework is a prerequisite for any
improvement. If the lack of a level playing field is due to exemptions in the EU regulatory
framework, stronger enforcement of these would actually be counter productive. In this
regard, the Evaluation report indicates that the rules of the Third Energy Package appear
to be insufficient to cope with the challenges facing the European electricity system.145
Moreover, voluntary cooperation has resulted in significant developments in the market
and a lot of benefits. However, it it unlikely to provide for appropriate levels of
harmonisation or certainty to the market and legislation is needed in this area to address
the issues in a consistent way.
The current EU regulatory framework contains very limited rules on balancing and
intraday markets in a manner that allow to strengthening these short-term markets. In
particular, the Third Package does not address regional sizing and procurement of
balancing reserves nor contain rules allowing achieving a larger degree of harmonisation
of intraday trading arrangements.
Given that the existence of Regional Security Coordinators ('RSCs') depends on the
implementation of the System Operation Guideline, RSCs may only be fully operational
140
More details on the baseline and the reasons for not considering existing support schemes can be found
in Annex IV.
141
Stakeholders' opinions are reflected through-out Section 5 (and occasionally Section 6) of the main text
of this impact assessment to provide insides into their views as to the various options considered.
Stakeholder views are moreover reflected in detail in Section 7 of of each of the Annexes 1.1 throught
to 7.6 to the present impact assessment.
142
Some stakeholders propose to preserve only particular rules of the current market arrangements, while
being supportive to other Commission proposals for upgrading of the electricity market. E.g., one
stakeholder is supportive to more aligned framework for balancing markets and European measures to
incentivise demand side flexibility and in the same time supports the priority dispatch and priority access
for renewables. Similarly, one stakeholder strongly supports measures to incentivise the demand side
response and strengthening the powers of ACER, but considers that power exchanges should not be
subject to governance rules as well as that redesigning of the balancing markets is the task of Member
States and not the EU.
143
For each measure the opportunities for stronger enforcement have also been assessed in the annexes
with measures associated with each option. References to the relevant annexes are provided in Sections
5.1.7, 5.2.9, 5.3.8 and 5.4.6
144
The Commission has conducted – and is still conducting – a systematic ex-officio compliance check of
national legislation with the Third Energy Package. While EU-Pilot or formal infringement procedures
are still ongoing, they will however not be able to fulfil the policy objectives of the proposed measures.
145
See Section 7.3.1., 7.34 and 7.3.4 of the Evaluation.
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around mid-2019. Hence, stronger enforcement is currently not a possible option. Any
progress beyond the framework in the System Operation Guideline and the application of
other network codes would depend on the voluntary initiatives of TSOs. However, these
voluntary initiatives would be limited due to constraints deriving from differing national
legal frameworks.
As to demand response, stronger enforcement of existing provisions in the electricity and
energy efficiency directives are unlikely to untap the potential of flexibility. This is because
the existing provisions give Member States a high degree of freedom that has proven not
to be specific enough to ensure a full removal of existing market barriers.
Evidence suggests that voluntary cooperation will not result in progress in this area, as
there has been to date already significant opportunity to effect the necessary changes
voluntarily.
In the case of DSOs the current EU regulatory framework does not provide a clear set of
rules when it comes to additional tools that DSOs can employ to improve their efficiency
in terms of costs and quality of service provided to system users. Moreover, the current
framework does not address the role of DSOs in activities which are expected to have a
key impact in the development of the market (e.g. data management).
Option 1: EU Regulatory action to enhance market flexibility
Electricity production from wind and sun is more variable and less predictable than
electricity production from conventional sources of energy. Due to this, there will be times
when renewables cover a very large share of electricity demand and times when they only
cover a minor share of it. The large scale integration of such variable electricity production
thus requires a more flexible electricity system, one which matches the variable production.
Options to deliver the desired flexibility may comprise:
a. Abolishing (i) those measures that enhance the inflexibility of the current system,
namely priority dispatch for certain technologies (e.g. RES E, CHP, indigenous
fuels) and "must-runs" of conventional generation, (Creating a level playing field)
and (ii) barriers preventing demand response from participating in the energy and
reserve markets;
b. In addition to the measures under a), better integrating short-term markets,
harmonizing their gate closure times and bringing them closer to real-time, in order
to take advantage of the diversity of generation resources and demand across the
EU and to improve the estimation and signalling of actual flexibility needs
(Strengthening the short-term markets);
c. In addition to the measures under a) and b), pulling all flexible distributed
resources concerning generation, demand and storage, into the market via proper
incentives and a market framework better adapted to them, based on active
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aggregators, roll-out of smart-metering and time-of-use supply tariffs linked to the
wholesale prices.146
The sub-options described above reflect a different degree of ambition to change the
market, as well as the different views expressed among stakeholders on how strong the
proposed interventions should be. Sub-option 1(a) (level playing field) retains a more
national status of the markets, Sub-option 1(b) (strengthening short-term markets) moves
also to more regionally coordinated markets, while Sub-option 1(c) (demand
response/distributed resources) makes an additional step towards a more decentralised
electricity market and system.
European Parliament: "…[I]n order to achieve the climate and energy targets, the
energy system of the future will need more flexibility, which requires investment in all four
flexibility solutions – flexible production, network development, demand flexibility and
storage"[.]147
European Economic and Social Committee: "The goal of a low-carbon energy supply,
with a high proportion of adjustable renewable energy sources, can only be achieved in
the short to medium term if all market participants (including new ones) have at their
disposal enough options that afford flexibility, such as sufficient storage capacity, flexible,
consumer-friendly demand options and flexible power generation technologies (e.g.
cogeneration), as well as adequately upgraded and interconnected power distribution
infrastructure. Other conditions are that consumers must receive adequate, timely and
correct information, they must have the chance to develop their own marketing
opportunities and the necessary investments in technology and infrastructure should pay
off. None of this is currently the case"148
.
Stakeholders' opinions: In the public consultation on Market Design Initiative most
stakeholders supported full integration of renewable energy sources into the market e.g.
through full balancing obligation and phasing-out priority dispatch. Also, most
146
IEA "Re-powering markets" (2016) suggests: … “dispatching” demand response as a generator
requires complex market rules. Demand response can only be assessed according to a baseline
consumption levels, which are difficult to define and can lead to hidden subsidies. Setting the right level
of remuneration for aggregators has proven to be complex. Instead, dynamic pricing should be
encouraged, using new measurement and automation technologies such as smart meters.
147
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, Recital C.
148
Opinion of the European Economic and Social Committee on the ´Communication from the Commission
to the European Parliament, the Council, the European Economic and Social Committee and the
Committee of the Regions – Launching the public consultation process on a new energy market
design´(COM (2015) 340 final) (2016/C 082/03), OJ C 82, 3.3.2016, p. 13-21, § 1.4.
http://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=uriserv:OJ.C_.2016.082.01.0013.01.ENG&toc=OJ:C:2016:082:TOC
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stakeholders agree with the need to speed up the development of integrated short-term,
balancing and intraday, markets.
5.1.4.1.Sub-option 1(a): Level playing field amongst participants and resources
The first group of measures aims at removing market distortions resulting from manifold
different regulatory rules for generation from different sources. Creating a level playing
field among all generation modes and restoring the economic merit order curve is an
important prerequisite for a well-functioning electricity market with prices that reflect
properly actual demand and supply conditions. For this reason the measures described here
are an integral part of all sub-options under Option 1.
The measures considered under this option would mainly target the removal of existing
market distortions and create a level playing field among technologies and resources. This
could involve abolishing rules that artificially limit or favour the access of certain
technologies to the electricity market (such as so-called "must-run" provisions, rules on
priority dispatch and access and any other rules discriminating between resources149
).
Industrial consumers would become active in the wholesale markets, both for energy and
reserves, in all Member States. All market participants would become balance responsible,
bearing financial responsibility for the imbalances caused and thus being incentivized to
reduce the risk of such imbalances. Dispatch and redispatch decisions would be based on
using the most efficient resources available, curtailment should be a measure of last resort
which is limited to situations in which no market-based resources are available (including
storage and demand response), and only subject to transparent rules.
Therefore, all resources would be remunerated in the market on equal terms. This would
not mean that all resources earn the same revenues, but that different resources face the
same prices for equal services. In most cases the TSO should follow the merit order,
allowing the market to define the dispatch of available resources, using the inherent
flexibility of resources to the maximum potential (e.g. by significantly reducing must-run
generation, creating incentives for the use of heat storage combined with CHP and the use
of biomass generation in periods of peak demand rather than as baseload, and using
demand response or storage where it is more efficient than generation). Where resources
are used on the basis of merit order (thus on the basis of the marginal cost for using a
particular resource at a given point in time)150
, supply costs are reduced.
Imposing additional obligations increases the risk and hence the financing costs of some
technologies such as RES E. Part of this risk will be hedged through the more liquid
intraday and balancing markets resulting from the full implementation of the Network
Codes, in combination with the increased participation of resources due to the removal of
must-run and priority dispatch provisions. These obligations should be also accompanied
by measures that reduce their costs of compliance, such as the introduction of transparent
149
See in detail Annex 1(1) – 1.
150
Where marginal costs are based on the use of fuel, this can also result in lower CO2 emissions. However,
inflexible conventional plants will include the cost of starting or stopping power generation into their
market bids, thus possibly deciding to operate at a price below their fuel costs. In this case, the cost of
not operating the power plant exceeds the cost of operating it.
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curtailment rules. Additionally, exemptions from certain regulatory provisions may, in
some cases, be required. This can e.g. be the case for emerging technologies, which,
although they are not yet competitive, need to reach a minimum number of running hours
to gather experience. For certain generators, particularly small RES E (e.g. rooftop solar),
exemptions can be furthermore justified to avoid excessive administrative efforts related
to being active on the wholesale markets.
Stakeholders' opinions:151
Most stakeholders support the full integration of all
technologies into the market, e.g. through full balancing obligations for all technologies,
phasing-out priority dispatch and removing subsidies during negative price periods.
Also stakeholders from the renewable sector often recognize the need to review the priority
dispatch framework. However, in their view, a phase-out of priority dispatch for renewable
energy sources should only be considered if (i) this is done also for all other forms of power
generation, (ii) liquid intraday markets with gate closure near real-time exist, (iii) balancing
markets allow for a competitive participation of wind producers; (short gate closure time,
separate up/downwards products, etc.), and (iv) curtailment rules and congestion
management are transparent to all market parties.
Cogeneration sector stakeholder seek for a least parity between CHP and RES E.
European Parliament: "European Parliament […]stresses that a new market design for
electricity as part of an increasingly decentralised energy system must be based on market
principles, which would stimulate investment, ensure that SMEs have access to the energy
market and unlock a sustainable and efficient electricity supply through a stable,
integrated and smart energy system[...]"152
"European Parliament […] [i]nsists that, with the increasing technical maturity and
widespread use of renewable energy sources, subsidy rules must be geared to market
conditions, such as feed-in premiums, in order to keep costs for energy consumers within
reasonable bounds[.]"153
151
More detailed depictions of stakeholder's opinions are provided in Sections 7 of each annexe describing
the more detailed measures i.e. annexes 1.1 to 7.6 of the Annexes to the Impact Assessment.
152
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, §5.
153
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, §52.
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"European Parliament […] recalls the existing provisions of the Renewable Energy
Directive, which grant priority access and dispatch for renewables; suggests that these
provisions should be evaluated and revised once a redesigned electricity market has been
implemented which ensures a more level playing field and takes greater account of the
characteristics of renewable energy generation[.]"154
Council: "[…] Renewable energy sources should become an integrated part of the
electricity market by ensuring a level playing field for all market participants and enabling
renewable energy producers to be fully involved in the market, including in balancing their
portfolio and reacting to market price signals."155
European Electricity Regulatory Forum, Florence: "The Forum stresses that the
renewables framework for the post 2020 period should be based on an enhanced market
design, fit for the full integration of renewables, a strong carbon price signal through a
strengthened ETS, and specific support for renewables, that when and if needed, should
be market based and minimise market distortions. To this end, the Forum encourages the
Commission to develop common rules on support schemes as a part of the revision of the
Renewables Directive that facilitate a market based and more regionalised approach to
renewables."156
5.1.4.2.Sub-option 1(b): Strengthening short-term markets
Sub-option 1(b) (strengthening short-term markets) includes the measures described under
1(a) (level playing field ) and a set of additional measures, further enhancing the measures
foreseen in the CACM and EB Guidelines (and are assumed as part of the baseline). As
explained above, variable RES E have fundamentally different generation characteristics
compared to traditional fuel based generation (e.g. variability, only short-term
predictability). An important additional step would therefore be to have more liquid and
better integrated short-term markets, going beyond what the implementation of technical
implementing legislation ("Network Codes") will achieve, setting the ground for
renewable energy producers to better access energy wholesale markets and to compete on
an equal footing with conventional energy producers. Short-term markets will also allow
Member States to share their resources across all "time frames" (forward trading, day-
ahead, intraday and balancing), taking advantage of the fact that peaks and weather
conditions across Europe do not occur at the same time.
Also, the closer to real time electricity is traded (supply and demand matched), the less the
need for costly TSO interventions to maintain a stable electricity system. Although TSOs
would have less time to react to deviations and unexpected events and forecast errors, the
liquid, better interconnected balancing markets, together with the regional procurement of
154
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, §54.
155
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, Annex, paragraph 4.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
156
31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §6.
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
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balancing reserves, would be expected to provide them with adequate and more efficient
resources in order to manage the grid and facilitate RES E integration.
In order to support these actions and mainly in order to be able to optimally exploit
interconnections along all "time frames", a number of measures are assumed to be taken:
gate closure times could be brought closer to real-time to provide maximum opportunity
for the market to balance its positions before it becomes a TSO responsibility and some
harmonisation would be brought to trading products for intraday markets in order to further
incentivize cross-border participation of market parties. The sizing of balancing reserves
and their procurement would be harmonized in larger balancing zones, allowing to reap
benefits of cross-border exchange of reserves and use of the most efficient reserves
available.
At the same time, the integration of national electricity systems, from the market and
operational perspectives, requires the enhancement of cooperation between TSOs. The
creation of a number of regional operational centres ('ROCs'), with an enlarged scope of
functions, an optimised geographical coverage compared to the existing regional security
coordinators and with an enhanced advisory role for all functions, including the possibility
to entrust them decision-making responsibilities for a number of relevant issues, could
contribute to better TSO cooperation at regional level.157
Measures on enhanced
cooperation between TSOs could be accompanied by an increased level of cooperation
between regulators and governments.158
All these options would be expected to strongly incentivize participation in the intraday
and balancing markets, further increasing their liquidity, while at the same time minimizing
TSOs' interventions.
Stakeholders' opinions: Most stakeholders agree with the need to speed up the
development of integrated short-term (intraday and balancing) markets. A significant
number of stakeholders argue that there is a need for legal measures, in addition to the
technical network codes under development, to speed up the development of cross-border
balancing markets. Many stakeholders note that the regulatory framework should enable
RES E to participate in the market, e.g. by adapting gate closure times and aligning product
specifications.
European Parliament: "European Parliament […][c]alls for the completion of the
integration of internal market and balancing and reserve services by fostering liquidity
and cross-border trading in all market timeframes; urges that efforts to achieve the
ambitious goals of the Target Model regarding intraday and balancing markets be speeded
157
For more details concerning policy measures for the establishment of ROCs, refer to Option 1 in Annex
2.3.
158
For more details concerning policy measures for the enhanced cooperation between regulators and
governments, refer to Option 1 in Annex 3.4.
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up, starting with the harmonisation of gate closure times and the balancing of energy
products[.]"159
Council: "An integrated European electricity market requires well-functioning short term
markets and an increased level of cross-border cooperation with regard to day-ahead,
intraday and balancing markets, without hampering the proper functioning of the
networks, as this will enhance security of supply at lower costs for the system and
consumers"160
.
European Economic and Social Committee: "The EESC underlines the particular
importance of intraday trade as a way of ensuring meaningful trade involving
VREs[variable renewable energies]"161
.
European Electricity Regulatory Forum, Florence: "The Forum supports the view that
further steps are needed beyond agreement and implementation of the Balancing
Guideline. In particular, further efforts should be made on coordinated sizing and cross--
‐border sharing of reserve capacity. It invites the Commission to develop proposals as part
of the energy market design initiative, if the impact assessment demonstrates a positive
cost--‐benefit, which also ensures the effectiveness of intraday markets"162
.
"The Forum Acknowledges the significant progress being made on the integration of cross
- border markets in the intraday and day--‐ahead timeframes, and considers that market
coupling should be the foundation for such markets. Nevertheless, the Forum recognises
that barriers may continue to exist to the creation of prices that reflect scarcity and invites
the Commission, as part of the energy market design initiative, to identify measures needed
to overcome such barriers"163
.
"[T]he Forum invites the Commission to identify those aspects of national intraday
markets that would benefit from consistency across the EU, for example on within--‐zone
gate closure time and products that should be offered to the market. It also requests for
action to increase transparency in the calculation of cross--‐zonal capacity, with a view to
maximising use of existing capacity and avoiding undue limitation and curtailment of
cross--‐border capacity for the purposes of solving internal congestions"164
.
159
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 46.
160
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, Annex, paragraph 6.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
161
31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §3.5.
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
162
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §3,
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
163
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §
4,
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
164
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §
5,
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"The Forum stresses that, whilst scarcity pricing in short--‐term markets is critical to
creating the right signals, the importance of hedging opportunities and forward/future
markets in creating more certainty for investors and alleviating risks for consumers must
not be overlooked. Further, it considers that the Commission must recognise the risks of
State Interventions undermining scarcity pricing signals"165
.
5.1.4.3.Sub-option 1(c): Pulling demand response and distributed resources into the
market166
Sub-option 1(c) (demand response/distributed resources) includes the measures described
under 1(a) (level playing field) and 1(b) (strengthening short-term markets), as well as a
set of additional measures, aiming at using the full potential of demand response, storage
and distributed generation. The previous options would introduce a level playing field for
all resources and improve the short-term market framework. They would, however, not
include any measure intending to pull all the additional available potential from distributed
resources into the market. Such resources are most importantly demand response,
distributed RES E and storage.167
A significant part of the current costs for the electricity system stem from the new
challenges of variable generation for the system, notably the increased need to deal with
supply peaks and unexpected generation gaps. As the elecricity grid requires a constant
balance of demand and supply, grid operators need to take costly measures. Demand
response, distributed RES E and storage can play an important role to reduce these costs.
The measures considered under Option 1(c) bring demand response from all consumer
groups, including residential and commercial consumers168
, and storage as additional
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
165
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §
6,
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
166
This set of measures could have been introduced alternatively as Sub-Option 1(b), thus before the
improved short-term market functioning related measures, as a further enhancement to the rules creating
a level-playing field for all technologies. However, the benefits from the participation of these additional
resources in the market are enhanced via their participation in the balancing markets and the procurement
of reserves. Introducing this set of measures in the context of improved short-term market functioning
therefore allows the full benefits of them to be realised. See also footnote 294, Section 6.1.7.
167
RSCAS Research report (2015), "Conceptual framework for the evolution of the operation and regulation
of electricity transmission systems towards a decarbonised and increasingly integrated electricity
system in the EU" by J.-M.Glachant, J.Vasconcelos, V.Rious, states: "EU has a target model for the EU
internal market and for the transmission system operation. It has none for EU “RES pocket markets”
and for the distribution system operation".
168
As big industrial consumers are assumed to already participate directly in the market in Option 1(a)
(level playing field), this sub-option extends the participation of demand response to all consumer groups
(including residential and commercial consumers) who, because of their small individual loads, can enter
the market only through third party service providers, e.g. aggregators. At the same time though the
described measures are expected to significantly increase the DR potential for all categories, including
industrial consumers who do not wish to engage directly in the market and by allowing DSOs to procure
additional flexibility services.
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resources into the market, especially to the balancing market. This would even further
increase the flexibility of the electricity system and the resources for the TSOs to manage
it. At the same time it should lead to much more efficient operation of the whole energy
system.
This option would include more in particular:
Enabling consumers to directly react to price signals on electricity markets both in terms
of consumption and production, by giving consumers access to a fit-for-purpose smart
metering system, enabling suppliers to measure and settle electricity consumption close to
real time, as well as requiring suppliers to offer consumers electricity supply contracts with
prices linked dynamically to the wholesale spot market that will enable consumers to
directly react to price signals on electricity markets both in terms of consumption and
production.
Box 4: Benefits and risks of dynamic electricity pricing contracts
The preferred policy option is to provide all consumers the possibility to voluntarily choose
to sign up to a dynamic electricity price contract and to participate in demand response
schemes. All consumers will however have the right to keep their traditional electricity
price contract.
Dynamic electricity prices reflect – to varying degrees – marginal generation costs and
thus incentivise consumers to change their consumption in response to price signals. This
reduces peak demand and hence reduces the price of electricity at the wholesale market.
Those price reductions can be passed on to all consumers. At the same time, suppliers can
pass parts of their wholesale price risk on to those consumers who are on dynamic
contracts. Both aspects can explain why, according to the ACER/CEER monitoring report
2015, on average existing dynamic electricity price offers in Europe are 5% cheaper than
the average offer.
While consumers on dynamic price contracts can realise additional benefits from shifting
their consumption to times of low wholesale prices they also risk facing higher bills in case
they are consuming during peak hours. Such a risk is deemed to be acceptable if taking
this risk is the free choice of the consumer and if he is informed accurately about the
potential risks and benefits of dynamic prices before signing up to such a contract.
Aggregators are companies that act as intermediaries between the electricity system and
distinct agents in the electricity system, mainly small, individual resoures but that exist in
large numbers, and which are usually located in the distribution grid (consumers,
prosumers and producers).169
Developing a comprehensive framework for demand, supply
and storage aggregators would facilitate their participation in the market and thus increase
flexibility in the energy system and complement large generation connected to the
169
EPRG working paper 1616 (2016), "Which Smart Electricity Services Contracts Will Consumers
Accept?" by L-L.Richter and M.G.Pollit states: "By combining appropriate participation payments with
sharing of bill savings, service providers could attract the number of customers required to provide the
optimal level of demand response."
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transmission grid.170
Larger storage facilities can be connected at distribution or
transmission level, and provide services on a peer basis with other providers.
R&D results: The economic and technical viability of the concept of aggregation has already been
demonstrated in European projects like: Integral, IDE4L, Grid4eu, INTrEPID, INCREASE, DREAM. The
ability of small-scale RES to participate in the balancing market or contribute to solving grid congestion has
been demonstrated in European projects like: V-Sync and MetaPV.
In order to pull all available resources into the market, it is also important to enable and
incentivise DSOs, without compromising their neutrality as system operators, to manage
their networks in a flexible and cost-efficient way, This could be achieved by establishing
a performance-based remuneration framework for DSOs that would reward them for
innovating and improving overall efficiency of their networks through synergies with other
actors, making full use of energy storage, and/or investing in electronic communication
infrastructure. This would be enabled by the deployment of intelligent infrastructure and
by ensuring coherence with other Commission policies in the field of the Digital Single
Market and the General Data Protection Regulation171
.
Measures under this option would also include defining the conditions under which DSOs
may acquire flexibility services without distorting the markets for such services, and
putting in place distribution tariff structures that send accurate price signals to all grid
users. Such initiative would be aimed at facilitating the integration of the increasing
amounts of variable RES E generation that will be connected directly to distribution grids
in the future.
Stakeholders' opinions: Many stakeholders identified a lack of smart metering systems
offering the full functionalities to consumers and dynamic electricity pricing (more flexible
consumer prices, reflecting the actual supply and demand of electricity) as one of the main
obstacles to kick-starting demand side response, along with the distortion of retail prices
by taxes/levies and price regulation.
Other factors include market rules that discriminate against consumers or aggregators who
want to offer demand response, network tariff structures that are not adapted to demand
response and the slow roll-out of smart metering. Some stakeholders underline that demand
response should be purely market driven, where the potential is greater for industrial
customers than for residential customers. Many replies point at specific regulatory barriers
to demand response, primarily with regards to the lack of a standardised and harmonised
framework for demand reponse (e.g. operation and settlement). A number of respondents
also underline the need to support the development of aggregators by removing obstacles
for their activity to allow full market participation of renewables. Many submissions
170
CIGRE paper C5-304 (2016), B. Guédou and A. Rigard-Cerison, RTE France says: "One can learn,
from French experience, that building an appropriate market for DSR requires to benefit from a strong
political commitment (intense involvement from the administration, the regulatory authorities and the
TSO) and to solve some key issues, requiring innovative answers both on the regulatory side and the
technical side (e.g. role of aggregators / independent DR operators, adaptation of the regulatory
framework to enable competition, role of TSOs and DSOs, data collection and privacy…)".
171
This would entail also close cooperation with TSOs, as elaborated for example in CIGRE paper C2-111:
"Increased cooperation between TSO and DSOs as precondition for further developments in ancillary
services due to increased distributed (renewable) generation", M.Kranhold, 50Hertz Transmission
GmbH (2016)
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highlight the crucial role of scarcity pricing for kick-starting demand response at industrial
and household level.
Regarding the role of DSOs, the respondents consider active system operation, neutral
market facilitation and data hub management as possible functions for DSOs. Some
stakeholders point at a potential conflict of interests for DSOs who are able to actively
menage their networks where these DSOs are also active in the supply business,
emphasizing that the neutrality of DSOs should be ensured. A large number of the
stakeholders stressed the importance of data protection and privacy, and consumer's
ownership of data. Furthermore, a high number of respondents stressed the need of specific
rules regarding access to data. As concerns a European approach on distribution tariffs, the
views are mixed; the usefulness of some general principles is acknowledged by many
stakeholders, while others stress that the concrete design should generally considered to be
subject to national regulation.
European Parliament: "European Parliament […] considers that this framework should
promote and reward flexible storage solutions, demand-side response technologies,
flexible generation, increased interconnections and further market integration, which will
help to promote a growing share of renewable energy sources and integrate them into the
market[.]"172
"European Parliament[…] recalls that the transition to scarcity pricing implies improved
mobilisation of demand response and storage, along with effective market monitoring and
controls to address the risk of market power abuse, in particular to protect consumers;
believes that consumer engagement is one of the most important objectives in the pursuit
of energy efficiency, and that whether prices that reflect the actual scarcity of supply in
fact lead to adequate investment in electricity production capacity should be evaluated on
a regular basis[.]"173
"European parliament […][c]onsiders that energy storage has numerous benefits, not
least enabling demand-side response, assisting in balancing the grid and providing a
means to store excess renewable power generation; calls for the revision of the existing
regulatory framework to promote the deployment of energy storage systems and other
flexibility options, which allow a larger share of intermittent renewable energy sources
(RES), whether centralised or distributed, with lower marginal costs to be fed into the
energy system; stresses the need to establish a separate asset category for electricity or
energy storage systems in the existing regulatory framework, given the dual nature –
generation and demand – of energy storage systems[.]"174
Council: "The future electricity retail markets should ensure access to new market players
(such as aggregators and ESCO’s) on an equal footing and facilitate introduction of
innovative technologies, products and services in order to stimulate competition and
growth. It is important to promote further reduction of energy consumption in the EU and
172
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 5.
173
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 10.
174
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 28.
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inform and empower consumers, households as well as industries, as regards possibilities
to participate actively in the energy market and respond to price signals, control their
energy consumption and participate in cost-effective demand response solutions. In this
regard, cost efficient installation of smart meters and relevant data systems are essential.
Barriers that hamper the delivery of demand response services should be removed"175
.
European Electricity Regulatory Forum, Florence: "The Forum recognises that the
development of a holistic EU framework is key to unlocking the potential of demand
Response and to enabling it to provide flexibility to the system. It notes the large
convergence of views among stakeholders on how to approach the regulation of demand
response, including: the need to engage consumers; the need to remove existing barriers
to market access, including to third--‐party aggregators; the need to make available
dynamic market--‐based pricing; the importance of both implicit and explicit demand
response; and the cost--‐efficient installation of the required technology"176
.
Option 2: Fully Integrated EU market
This option considers measures that would aim to deliver a single truly pan-European
electricity market via relatively far-reaching changes to the current regulatory framework,
aiming at the full integration of electricity markets and system operation, and at mobilising
all available flexibility of the EU-wide system.
For a fully integrated EU market, one would need to significantly change the current
regulatory approach of the internal market. The current EU wholesale market design of the
Third Package provides for a coordination framework between grid operators and national
regulators and sets some rules for certain issues which are relevant for cross-border
exchange of electricity (e.g. coordinated electricity trading and grid operation measures).
However, under the Third Package, regulatory decisions are in principle left to Member
States, the 28 national regulators and the 42 European grid operators if not otherwise
provided in the Third Package.
Leaving scope for national decision-making on trading and system operation may lead to
inefficiencies due to unsufficiently coordinated and contradicting decisions. A more
centralised regulatory approach could therefore be considered to achieve more integrated
EU markets.
Under this option, procurement of balancing reserves would be performed directly at EU
level, instead of a regional level. For system operation, this could mean shifting from a
system of separate national TSOs to an integrated system managed by a single European
Independent System Operator ("EU ISO"). System operation (including real time
175
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, Annex, paragraph 8.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
176
31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §1.
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
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operation) and planning functions could be performed by this EU ISO, which would be
competent for the whole Union.177
In order to optimally deal with congestion between countries and to let the market transmit
the right price signals, this option would entail to move from zonal to nodal pricing178
. The
values of available transmission capacities would be calculated centrally and could be
closely coordinated across market regions, thereby taking advantage of all information
available among the TSOs in different grid arreas and also taking into account the
interrelationship between different interconnectors. As a result, it is assumed that more
interconnector capacity is made available to the market(s) and resources are expected to
be utilized more efficiently across regions.
In general, Option 2 would not only entail coordination, approximation and harmonisation
of selected topics relevant for national market and grid operation rules, but also to apply
the same rules and specifications for products and services across the EU, including
centrally fixed rules for electricity trading, for common EU-wide procurement of reserves
and central system planning and operation. Such centralised integrated market would also
provide for mandatory smart meter roll-out and a full EU framework for incentive-based
demand response to better exploited demand reponse. Under Option 2, also distribution
tariff structures would be harmonised, stronger unbundling rules for DSOs be created as
well as harmonised renumeration methodologies that ensure DSOs' incentives to invest in
innovative and efficient technologies.
ACER would need to gain significant competences and take over most NRAs'
responsibilities directly or indirectly related to cross-border and EU-level issues. ENTSO-
E would need to be formally separated from its members' interest and take up more
competences.179
Such measures, intended to optimise the cost-efficiency and flexibility of the European
electricity system, would involve going significantly beyond the measures described under
Option 1, requiring also particularly far-reaching institutional changes.
Stakeholders' opinions: No stakeholder expressed support for the possibility of designing
measures leading to the creation of a fully integrated EU electricity market. For example,
as regards the establishment of an EU Independent System Operator, a number of
stakeholders emphasized that while it is necessary to reinforce TSO coordination, this
should take place through a step-wise regional integration of system operation
177
For more details on policy option concerning the establishment of an EU ISO, please refer to Option 3
in annex 2.3.
178
Nodal Pricing is a method of determining prices in which market clearing prices are calculated for a
number of locations on the transmission grid called nodes. Each node represents the physical location
on the transmission system where energy is injected by generators or withdrawn by loads. The price at
each node represents the locational value of energy, which includes the cost of the energy and the cost
of delivering it, i.e. losses and congestion
179
For more details on ACER's and ENTSO-E's enhanced competences in a fully integrated EU market,
refer to Option 2 in Annex 3.4.
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For Option 1 and 2: Institutional framework as an enabler
Each set of proposed measures under Options 1(a) to 1(c), as well as (2), will necessitate
a different degree of reinforcement of the institutional framework of the EU's electricity
markets. Since the harmonisation of regulatory aspects (e.g. gate closure times, rules for
the curtailment of cross-border capacities, bidding zones etc.) often has different economic
impacts in different Member States, an institutional framework is needed to find the
necessary compromises. Experience has shown that it will generally be more difficult to
achieve ambitious harmonisation goals with an institutional framework that grants veto
rights to each national regulator or TSO (i.e. in cooperative institutions applying
unanimous decision-making). An alignment or harmonisation of aspects concerning the
electricity market design is therefore more likely to happen with an institutional framework
which applies (qualified) majority decision-making or which replaces the decision-making
by 28 different regulators/TSOs by a central body which takes the decision in the European
interest180
.
A robust institutional framework constitutes a pre-requisite for the integration and proper
functioning of the EU market. For this reason, it is necessary that the institutional
framework reflects the realities of the electricity system and the resulting need for regional
cooperation as well as that it addresses existing and anticipated regulatory gaps in the
energy market.
In order to effectively establish a level playing field between all potential market
participants and resources (Sub-option 1(a) (level playing field)), it is necessary to
reinforce ACER's competences at EU level in order to address regulatory gaps already
identified in the implementation of the Third Package and ensure the oversight over
entities and functions with relevance at EU level.
When markets and market regulation achieve a regional dimension (Sub-option
1(b)(strenghening short-term markets)), the institutional framework needs to be adapted
accordingly, if it is to remain efficient and effective. Currently, the EU institutional
framework is based on the complementarity of regulation at national and EU law. Hence,
the regulatory framework would then need to be reinforced to address the need for
additional regional cooperation. In this regard, ACER's competences and NRAs'
cooperation at regional level should be enhanced, corresponding to increased regional
TSO cooperation and to the implementation of network codes and guidelines at regional
level. The mandate of ENTSO-E could be clarified to strengthen its obligation to take a
European / internal market perspective and to emphasize its transparency and monitoring
obligations. The role of power exchanges in cross-border electricity issues should be
acknowledged and they should be involved in all regulatory procedures relevant for them.
Finally the use of congestion income should be altered, increasing the proportion spent on
investments that maintain or increase interconnection, thus creating the basis for the
regional co-operation through a strongly interconnected system181
.
180
The transfer of decisions on cross-border cost allocation to the Director of ACER is one example of
decision-making by an independent supranational body. See Article 12(6) of Regulation 347/2013
(TEN-E Regulation).
181
As is in fact discussed under Option 1 of Problem Area II
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In order to facilitate distributed resources to participate in the market (Sub-option 1(c)
demand response/distributed resources), DSOs must become more active at European level
and have increased responsibilities and tasks, similar to those of the TSOs. Their role
should be formalised into a European organisation with an efficient working structure to
render their participation effective and independent. In particular, whereas DSOs are
currently represented at EU level by four associations (Eurelectric, Geode, CEDEC and
EDSO), none of these has the necessary characteristics to represent the sector by engaging
in tasks that might include the codification of formal EU market rules: Either they or their
members are listed as lobbyists on the EU Transparency Register, none of their
memberships is representative of all EU DSOs, and none has the explicit mandate to
represent EU DSOs in such activities.
Finally, Option 2 requires significantly restructuring the institutional framework, going
beyond addressing the regulatory gaps and moving towards more centralised institutional
structures with additional power and responsibilities, particularly for ACER and ENTSO-
E.
Stakeholders' opinions: Opinions with regard to strengthening ACER’s powers are
divided. There is clear support for increasing ACER's legal powers by many stakeholders.
However, the option to keep the status quo is also visibly present, notably in the
submissions from Member States and national energy regulators. While some stakeholders
mentioned a need for making ACER'S decisions more independent from national interests,
others highlighted rather the need for appropriate financial and human resources for ACER
to fulfil its tasks.
With regard to ENTSO-E, stakeholders' positions are divided as to whether ENTSO-E
needs strengthening remain divided. Some stakeholders mention a possible conflict of
interest in ENTSO-E’s role – being at the same time an association called to represent the
public interest, involved e.g. in network code drafting, and a lobby organisation with own
commercial interests – and ask for measures to address this conflict. Some stakeholders
have suggested in this context that the process for developing network codes should be
revisited in order to provide a greater a balance of in interests.
Some submissions advocate for including DSOs and stakeholders in the network code
drafting process. While a majority of stakeholders support governance and regulatory
oversight of power exchanges, particularly as regards the market coupling operator
function, other stakeholders are sceptical whether additional rules are needed for power
exchanges given the existing rules in legislation on market coupling (in the CACM
Guideline).
European Parliament: "European Parliament […][n]otes the importance of effective,
impartial and ongoing market monitoring of European energy markets as a key tool to
ensure a true internal energy market characterised by free competition, proper price
signals and supply security; underlines the importance of ACER in this connection, and
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looks forward to the Commission’s position on new and strengthened powers for ACER on
cross-border issues[.]"182
"European Parliament […][s]tresses that in most cases renewables are fed in at
distribution system level, close to the level of consumption, and therefore calls for DSOs
to play a greater role as facilitators and to be more closely involved in the design of
European regulatory framework and in the relevant bodies when it comes to drawing up
guidelines on issues of concern to them, such as demand-side management, flexibility and
storage, and for closer cooperation between DSOs and TSOs at the European level[.]"183
Summary of specific measures comprising each Option
The following table summarizes the specific measures comprising each package of
measures, as well the corresponding specific measure option considered under each high
level option184
. The detailed presentation and assessment of each measure can be found in
the indicated Annex.
182
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 70.
183
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 63.
184
The preferred options for the specific measures set out in the annex are highlighted in the table in green.
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Table 6: Summary of Specific Measures investigated for Problem Area I
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Specific Measures Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Option (a) +
Strengthening
short-term
markets
Option 1(a), 1(b) +
Demand response/distributed
resources
Fully integrated markets
Priority Access and
Dispatch
(Annex 1.1)
Maintain priority dispatch
for RES, indigenous fuels
and CHP
(Annex 1.1.4 Option 0)
Abolish priority dispatch and introduce clear curtailment rules to replace
priority access, with the exception of emerging technologies and small
CHP and RES E plants
(Annex 1.1.4 Options 2 and 3)
Fully abolish priority dispatch and
access
(Annex 1.1.4 Option 1)
+ Balancing
Responsibility
(Annex 1.2)
Financial balancing
responsibility under EEAG
(Annex 1.2.4 Option 0)
Balancing responsibility for all parties, with the exception of emerging
technologies and small CHP and RES E plants
( Annex 1.2.4 Option 2)
Full balancing responsibilities for all
parties
(Annex 1.2.4 Option 1)
+ RES providing non-
frequency ancillary
services
(Annex 1.3)
Services continue to be
provided by large
conventional generation
(Annex 1.3.4 Option 0)
Principles for transparent, non-discriminatory market-based framework for
the provision of these services
(Annex 1.3.4 Option 2)
EU market framework for such services
(Annex 1.3.4 Option 1)
+ Reserves Sizing and
Procurement
(Annex 2.1)
National sizing of balancing reserves, frequency of
procurement as today (e.g. many products, not
necessarily separete upwards/downwards
products)
(Annex 2.1.4 Option 0)
Regional sizing and procurement of balancing
reserves, daily procurement of upward/downward
products
(Annex 2.1.4 Option 2)
European sizing and procurement of
balancing reserves, daily procurement of
upward/downward products
(Annex 2.1.4 Option 3)
+ Remove distortions
for liquid short-term
markets
(Annex 2.2)
National non-harmonised intraday markets
(Annex 2.2.4 Option 0)
Selected harmonisation of national intraday markets
of gate closure times and products, with gradual
implementation
(Annex 2.2.4 Option 2)
Full harmonisation and coupling of
intraday markets
(Annex 2.2.4 Option 1)
+ TSO Co-operation
(Annex 2.3)
Regional Security Coordinators (RSCs) to perform
five tasks at regional level for national TSOs
(Annex 2.3.4 Option 0)
Upgrade RSCs to Regional Operational Centres
(ROCs) centralising additional functions over
relevant geographical areas
(Annex 2.3.4 Option 0)
Creation of Regional or EU Independent
System Operators
(Annex 2.3.4 Options 2 and 3)
+ Demand Response
(Annex 3.1)
Smart meter rollout remains limited in geographical scope and
functionalities, market barriers to aggregators persist, and the full
potential of demand response and self-consumption remains untapped
(Annex 3.1.4 Option 0)
Give consumers access to
enabling technologies that will
expose them to market price
signals and a common European
framework defining roles and
responsibilities of aggregators
(Annex 3.1.4 Option 2)
Mandatory smart meter roll out and full
EU framework for incentive based
demand response
(Annex 3.1.4 Option 3)
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Specific Measures Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Option (a) +
Strengthening
short-term
markets
Option 1(a), 1(b) +
Demand response/distributed
resources
Fully integrated markets
+ Ensuring that DSOs
become active and
remain neutral towards
other market actors
(Annex 3.2)
Broad variety of national approaches to DSO roles and responsibilities
(Annex 3.2.4 Option 0)
Specific requirements and
conditions for 'active' DSOs;
Clarification of DSO's role in
specific tasks; Enhanced DSO-
TSO cooperation (Annex 3.2.4
Option 1)
EU framework for a specific set of DSO
tasks and stricter unbundling rules
(Annex 3.2.4 Option 2)
+ A performance-based
remuneration
framework for DSOs
(Annex 3.3)
Broad variety of national approaches to DSO compensation
(Annex 3.3.4 Option 0)
EU-wide principles on
remuneration schemes; NRAs
monitor the performance of
DSOs (Annex 3.3.4 Option 1)
Fully harmonize remuneration
methodologies (Annex 3.3.4 Option 2)
+ Distribution tariffs
that send accurate price
signals to grid users
(Annex 3.3)
Broad variety of national approaches to distribution tariffs
(Annex 3.3.4 Option 0)
EU wide principles to make
tariffs structures become more
transparent and more accurately
reflect the impact of each
system user on the grid,
especially during different times
of the day; NRAs to implement
more detailed requirements
(Annex 3.3.4 Option 1)
Fully harmonize distribution tariff
structures through concrete requirements
(Annex 3.3.4 Option 2)
+ Adapting Institutional
Framework to reality of
integrated markets
(Annex 3.4 institutional
framework)
Retain Status Quo (no
change)
(Annex 3.4.4 Option 0)
Adapt institutional framework to the new realities of the electricity system
and the resulting need for additional regional cooperation and to address
regulatory gaps (relevant to each respective policy sub-option)
(Annex 3.4.4 Option 1)
Restructure the EU Institutional
Framework providing for more
centralised institutional structures
(Annex 3.4.4 Option 2)
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5.2. Options to address Problem Area II (Uncertainty about sufficient future
generation investments and uncoordinated capacity markets)
Overview of the policy options
A number of Member States anticipate inadequate generation capacity in future years and
plan to introduce or have already introduced unilateraly, unaligned capacity mechanisms.
Capacity mechanisms remunerate the guaranteed availability of electricity resources (e.g.
generation or demand response) rather than paying for electricity actually delivered. The
current regulatory market design does provide for rules on capacity mechanisms185
. While
it does not prohibit nor encourage capacity mechanisms, the Third Package is, in principle,
built on the concept of an "energy-only" market, in which generators are remunerated
mainly based on the energy delivered186
. Undistorted cross-border markets should provide
for the necessary investment signals to ensure stable generation at all times. Price signals
should drive production and investment decisions, whereas price differentials between
different bidding zones should determine where facilities should ideally be located,
provided that all assets are treated equally in terms of the risks and costs to which they are
exposed and the opportunities for earning revenues from producing electricity i.e. they
operate within a level playing field.
Several Options will be considered to address the concerns regarding investment certainty
and fragmented approaches to CMs:
Box 5: Overview of the Policy Options for Problem Area II
Each policy option consists of a package of measures which act upon the drivers of the
problem. Some of the options differ according to whether generators can only rely on
energy market payments or whether they receive additional remuneration from CMs.
Option 1 (Improved energy-only markets) would be based on additional measures to
further strengthen the internal electricity market (complementing the measures described
above in options 1(a) (level playing field), 1(b) (strengthening short-term markets) and (c)
185
Capacity markets are only indirectly addressed, e.g. through the obligation for Member States under the
Third Package to maximise cross-border capacities (see e.g. Art. 16 (3) of Regulation 714/2009) and to
avoid unnecessary limitations of cross-border flows, e.g. through State Interventions.
186
It may be noted that generators can receive additional revenues from providing frequency reserves,
which could be described as a form of (short-term) capacity markets.
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(demand response/distributed resources) presented in Problem Area I). Under this option,
CMs would no longer be allowed. Option 2 and 3 would also include the proposed
measures to strengthen the internal energy market as presented in Option 1, but also
propose possible measures to better align national CMs. The possibility to set up a
mandatory EU-wide CM is described in Option 4.
The following sub-sections describe the policy options and the packages of measures they
comprise. It then explains which options can be discarded at this stage, prior to assessment,
as well as present other options that were considered but were discarded from the
beginning. A table summarising all specific measures for each option is provided at the
end of this section.
The relevant Annexes addressing the policy options below are: 4.1 to 5.2.
Option 0: Baseline Scenario – Current Market Arrangements
Under the baseline scenario, price formation on electricity wholesale markets is
constrained, e.g. through price caps. Prices may not be able to reach levels which truly
reflect the value of energy when the demand and supply balance is tight and, hence,
electricity is scarce. Therefore price signals from wholesale markets would, in times of
scarcity, be distorted and revenue streams of generators cannot properly reflect their value
to the system. This affects, in particular, the remuneration of assets that can provide
flexibility to the electricity system, regardless to whether this concerns flexible generation
capacity, electricity storage or demand response.
At this stage most electricity markets in Europe face generation overcapacities. In this
situation, price caps do in practice not matter – scarcity prices cannot be expected anyway.
However, once old capacities will have exited the market and the power mix has adjusted
(see in this regard the analyses presented in section 6.2.6.3), true price formation would be
essential to produce signals for new investments. This could not happen as long as price
caps exist.
Price signals are also not aligned with structural congestion in the transmission grid, thus
not revealing the locations where investments would relieve congestion and production
decisions. TSOs then can only operate sub-optimally the existing network and need to take
frequent congestion management measures. Although the CACM Guideline provides a
process for reviewing price or bidding zones, the current process lends itself to maintaining
the status quo (mostly price zones along Member State borders), making this the most
plausible assumption for the baseline. This is because there are likely to be competing
interests at stake. In particular, some Member States are unlikely to want to amend bidding
zones where it would create price differentials within their borders; it is sometimes
considered to be right for all consumers to pay the same price within a Member State, and
for all producers to receive the same price. The current legislation does not, therefore,
provide for the socially optimal solution to be agreed.187
Based on perceived or real resource adequacy concerns, several Member States take
actions concerning the introduction of national resource adequacy measures or the
187
For more details concerning the deficiencies of current legislation concerning bidding zone
configuration, see Sections 4.2.2 and 4.2.3 of Annex 4.2 to this Impact Assessment.
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imposition of regulatory barriers to decommissioning. These measures are usually based
on national resource adequacy assessments and projections, which may substantially differ
depending on the underlying assumptions made and the extent to which foreign capacities
as well as demand side flexibility are taken into account in calculations. Some of these
concerns and projections are a result of the current market arrangements.
The Commission's current tool to assess whether government interventions in support of
resource adequacy are legitimate is state aid scrutiny. The EEAG require among others a
proof that the measure is necessary, technological neutral and allows for explicit cross-
border participation. However, the EEAG do not clarify how an effective cross-border CM
regime could be deployed.
The baseline is common with the one presented in 5.1.2, with only two differences: (a)
presence of price caps based on current practices and (b) existence of structural congestion
in the transmission grid.
Stakeholders' opinions: None of the respondents to the public consultation took the view
that the current market arrangements were sufficient and no further measures are required.
Option 0+: Non-regulatory approach
Whilst systematically considered188
, no such policy option could be identified.
This option would entail relying on existing legislation to improve the current market
arrangements. The likelihood of seeing any meaningful change as a result of this process
is minimal. Existing provisions under EU legislation are arguably not sufficiently clear and
robust. In this regard, the Evaluation report indicates that the rules of the Third Energy
Package appear to be insufficient to cope with the challenges facing the European
electricity system.189
In addition, certain areas, like resource adequacy, are not addressed
in the Third Package. Consequently, the Evaluation report concludes that the Third
Package does not not ensure sufficient incentives for private investments in the new
generation capacities and network because of the minor attention in it to effective short-
term markets and prices which would reflect actual scarcity.190
Voluntary cooperation has resulted in significant developments and a lot of benefits (e.g.,
the PLEF, whereby some Member States have voluntarily decided to cooperate and deliver
a regional resource adequacy assessment). However it may not provide for appropriate
levels of harmonisation across all Member States and certainty to the market and
legislation is needed in this area to address the issues in a consistent way.
Option 1: Improved energy market - no CMs
Option 1 assumes that European electricity markets, if sufficiently interconnected and
undistorted, can provide for the necessary price signals to incentivise investments into new
generation. Wholesale markets would be strengthened by a set of specific measures aiming
at improving price signals so as to deliver the necessary investments based only on price
188
For each measure the opportunities for stronger enforcement has been assessed in the annexes.
189
See Section 7.3.1 and 7.3.3 of the Evaluation.
190
See Sections 7.3.2 of the Evaluation.
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signals. CMs, whether at national, regional or European level would not be justifiable to
secure electricity supplies under this option as the market should be incentivising
investments.
Even if such price signals concern the spot price on the wholesale market corresponding
to the day-ahead market, these prices are the reference for the forward market and would
thus have a long-term effect. Having as a starting point the reformed market design as
described in section 5.1.4.3191
, it is additionaly assumed that no administrative mechanisms
directly affecting investments and price signals are allowed to be in place, in the form of
CMs or (below Value of Lost Load192
or 'VoLL') price caps. In the case of the latter this
would be effected by ensuring that any technical limits imposed by power exchanges are
merely that, and are raised in the event they are reached, and, in order to provide maximum
investor confidence, an end-date, after which such limits must not be below VoLL.
The strengthened short and long-term markets and the participation of distributed
generation offer the necessary flexibility required to integrate variable RES E into the
market. Combined with the removal of (below VoLL) price caps,193
the market should be
able to drive investments towards the needed flexible assets, such as storage and demand
response, and sufficient generating capacity. Furthermore, proper incentives are introduced
aiming to unlock the flexibility that can be provided by existing assets, such as demand
response and storage.
At the same time price signals could drive the geographical location of new investments
and production decisions, via price zones aligned with structural congestion in the
transmission grid. The location of the price zone borders would be decided through a robust
regulatory decision-making process. Price differentials between these price zones should
help determine where investments are needed and make the best use of natural resources
(particularly important for RES E, but also for interconnectors) and, for those assets
already deployed, which one will be producing. Such locational prices would also provide
efficient signals for the location of demand – for example new energy intensive industries
would choose to locate in areas where there is excess generation and therefore low
prices.194
Measures would also be taken to further restrict the practice of limiting cross-
border capacity in order to deal with internal network contraints and, finally, measures
would be taken to minimise, in the long-term, the most significant investment and
operational distortions on generators arising as a result of network charges.195
Stakeholder's opinions: A majority of answering stakeholders is in favour an "energy-
only" market (possibly augmented however with a strategic reserve, which is a form of a
capacity market). Many stakeholders share the view that properly designed energy markets
would make capacity mechanisms gradually redundant. Many generators and some
191
Sub-option 1(c) (demand response/distributed resources) from problem area I was used as the basis here,
as it was identified as the preferred option when comparing the respective options in Section 7.1.
192
Value of Lost Load is a projected value reflecting the maximum price consumers are willing to pay to
be supplied with electricity
193
For more detail on policy measures related to the removal of price caps, refer to Annex 4.1.
194
For more detail on policy measures related to the improvement of locational signals, refer to Annex 4.2.
195
For more detail, refer to Annexes 4.3 and 4.4.
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governments disagree and are in favour of capacity remuneration mechanisms (assessed in
Options 2, 3 and 4).
A large majority of stakeholders agreed that scarcity pricing is an important element in the
future market design. While single answers point at risks of more volatile pricing and price
peaks (e.g. political acceptance, abuse of market power), others stress that those respective
risks can be avoided (e.g. by hedging against volatility).
A large number of stakeholders agreed that scarcity pricing should not only relate to time,
but also to locational differences in scarcity (e.g. by meaningful price zones or locational
transmission pricing). While some stakeholders criticised the current price zone practice
for not reflecting actual scarcity and congestions within bidding zones, leading to missing
investment signals for generation, new grid connections and to limitations of cross-border
flows, others recalled the complexity of prices zone changes and argued that large price
zones would increase liquidity.
Many submissions highlight the crucial role of scarcity pricing for kick-starting demand
response at industrial and household level.
European Parliament:"…[N]ational capacity markets make it harder to integrate
electricity markets and run contrary to the objectives of the common energy policy, and
should only be used as a last resort once all other options have been considered, including
increased interconnection with neighbouring countries, demand-side response measures
and other forms of regional market integration[.]"196
"European Parliament […] [i]s
sceptical of purely national and non-market-based capacity mechanisms and markets,
which are incompatible with the principles of an internal energy market and which lead to
market distortions, indirect subsidies for mature technologies and high costs for
end-consumers; stresses, therefore, that any capacity mechanism in the EU must be
designed from the perspective of cross-border cooperation following the completion of
thorough studies on its necessity, and must comply with EU rules on competition and State
aid; believes that better integration of national energy production into the EU energy
system and the reinforcement of interconnections could reduce the need for, and cost of,
capacity mechanisms[.]"197
Option 2: Improved energy market – CMs only when needed, based on a common
EU-wide adequacy assessment)198
This Option includes the measures to strenghten the internal energy market (as described
in Option 1 above), i.e. every Member State is assumed to have in place a well-functioning
energy market.
196
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, Recital H.
197
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 24.
198
Further elements of this option are presented in Annex 5.1.
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In addition to Option 1 however, Member States would be allowed to implement national
CMs, but only under certain conditions. Additional measures are proposed in order to avoid
negative consequences of uncoordinated CMs for the functioning of the internal market,
building on the EEAG' state aid Guidelines and the Sector Inquiry on CMs.
To address the problem of diverging and purely national assessments of the needs for CMs,
ENTSO-E would be required under this option to propose a methodology for an EU-wide
resource adequacy assessment. The upgraded methodology should be based on transparent
and common assumptions199
and ENTSO-E would carry out the assessment anually. The
prerequisite for a Member State to implement a CM or prohibit capacity from exiting the
market would be that ENTSO-E's assessment indicated a lack of generation capacity and
where markets cannot be expected to close the gap. This would avoid that back-up
capacities are developed based on a purely national perspective (i.e. national adequacy
assessments, using different methodologies and not taking into account the generation
potential across borders).
When proposing or applying CMs, Member States would need to introduce resource
adequacy targets, which can be diverging (as an expression of their diverging preference
for resource adequacy). The standards should be expressed in a unique format to become
comparable across the EU – as Expected Energy Non Served ('EENS'), and it should be
derived following a methodology provided by ENTSO-E which takes into account the
value that average customers in each bidding zone put on electricity supplies (Value of
Lost Load – 'VoLL').
Stakeholders' opinions: There is almost a consensus amongst stakeholders on the need
for a more aligned method for resource adequacy assessment. A majority of answering
stakeholders supports the idea that any legitimate claim to introduce CMs should be based
on a common methodology. When it comes to the geographical scope of the harmonized
assessment, a vast majority stakeholders call for regional or EU-wide resource adequacy
assessment, while only a minority favour a national approach. There is also support for the
idea to align adequacy standards across Member States.
European Parliament: "[…]stresses the importance of a common analysis of resource
adequacy at regional level, facilitated by the Agency for the Cooperation of Energy
Regulators (ACER) and the European Network of Transmission System Operators
(ENTSO-E), and calls for the transmission system operators (TSOs) of neighbouring
199
The ENTSO-E assessment should have the following characteristics:
i. It should cover all Member States
ii. It should have a granularity of Member State/ bidding zone level to enable the analysis of national/
local adequacy concerns;
iii. It should apply probabilistic calculations that consider dynamic characteristics of system elements
(e.g. start-up and shut-down times, ramp up and ramp-down rates…)
iv. It should calculate generation adequacy indicators for all countries (LOLE, EENS, etc.)
v. It should appropriately take into account foreign generation, interconnection capacity, RES , storage
and demand response
vii. Time span of 5-10 years
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markets to devise a common methodology, approved by the Commission, to that end;
highlights the enormous potential of strengthened regional cooperation[…]"200
Council: "Member States considering implementing capacity mechanism should take into
account synergies of cross-border regional cooperation and avoid any disincentive for
investment in interconnection, while minimising market distortion"201
.
Option 3: Improved energy market - CMs only when needed, based on a common
EU-wide adequacy assessment, plus cross-border participation202
Option 3 includes the measures to strenghten the internal energy market as described in
Option 1 above. It also includes the requirement for national CMs to be justified by a
European adequacy assessment (see Option 2). In addition, Option 3 would however
provide for design rules for better compatibility between national CMs, also building on
the EEAG state aid guidelines and the Sector Inquiry on CMs notably in order to facilitate
cross-border participation ('blue-print') .
To date, in order to comply with EEAG, Member States have to individually organise, for
each of their borders separately, the necessary cross-border arrangements involving a
multitude of parties (e.g. resource providers, regulators, TSOs).
This option would provide a harmonised cross-border participation scheme across the EU
by setting out procedures including roles and responsibilities for the involved parties (e.g.
resource providers, regulators, TSOs).
Stakeholders' opinions: Most of the stakeholders including Member States agree that a
regional/European framework for CMs are preferable. Indeed, 85% of market participant
respondents and 75% of public body respondents to the sector inquiry on Capacity
Mechanisms203
felt that rules should be developed at EU level to limit as much as possible
any distortive impact of CMs on cross national integration of energy markets. Member
States might instinctively want to rely more on national assets and favour them over cross-
border assets. It is often claimed that in times of simultaneous stress, governments might
choose to 'close borders' putting other Member States who might actually be in bigger need
in trouble.
European Parliament: "[…][c]alls for cross-border capacity mechanisms to be
authorised only when the following criteria, inter alia, are met: a. the need for them is
confirmed by a detailed regional adequacy analysis of the production and supply situation,
including interconnections, storage, demand-side response and cross-border generation
resources, on the basis of a homogeneous, standardised and transparent EU-wide
methodology which identifies a clear risk to uninterrupted supply; b. there is no possible
alternative measure that is less costly and less market-intrusive, such as full regional
200
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 14.
201
See "Messages from the Presidency on electricity market design and regional cooperation" (2016), Note
to the Permanent Representatives Committee/Council, Page 2.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
202
Further elements of this option are presented in Annex 5.
203
"Interim Report of the Sector Inquiry on Capacity Mechanisms" SWD(2016) 119 final.
http://ec.europa.eu/competition/sectors/energy/capacity_mechanisms_swd_en.pdf
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market integration without restriction of cross-border exchanges, combined with targeted
network/strategic reserves; c. their design is market-based and is such that they are
non-discriminatory in respect of the use of electricity storage technologies, aggregated
demand-side response, stable sources of renewable energy and participation by
undertakings in other Member States, so that there is no cross-border cross-subsidisation
or discrimination against industry or other customers, and it is ensured that they only
remunerate the capacity strictly necessary for security of supply; d. their design includes
rules to ensure that capacity is allocated sufficiently in advance to provide adequate
investment signals in respect of less polluting plants; e. sustainability and air quality rules
are incorporated in order to eliminate the most polluting technologies (consideration
could be given to an emissions performance standard in this connection) […]"204
Option 4: Mandatory EU-wide or regional CMs
Under this option based on regional or EU-wide resource adequacy assessments, entire
regions or ultimately all EU Member States would be required to roll-out CMs on a
mandatory basis. The design of the CMs would follow a EU 'blue print' (i.e. a set of design
requirements for CMs), with the required resource adequacy target to be set at regional or
EU level. This approach would assess and address adequacy concerns at a regional or EU
level. Decisions on whether to introduce CMs or not would no longer be left with
individual Member States, but an EU-wide CM would be created, as a mandatory
additional layer to the "energy-only" market. Differences between Member States (e.g.
whether all areas within larger regions actually face adequacy challenges, or network
congestions) would not justify exception from the obligation to introduce a CM.
Discarded Options
Option 0+ will not be further analysed as no means were identified to implement it.
Option 4 does not consider the significant regional differences when it comes to resource
adequacy. The EU-wide or region-wide roll-out would disregard existing congestions in
the European network and it would consequently over- or underestimate the resource
adequacy in single bidding zones/ Member States belonging to a wider region. As a result
CMs might need to be introduced in bidding zones/Member States that do not face any
adequacy concerns. Alternatively, emerging resource adequacy problems in certain
bidding zones/Member States might not be identified and addressed appropriately. In
addition, as a number of Member States rely on energy-only markets to provide for the
necessary investments in their power systems it would not be appropriate to force them to
adopt CMs.
Summary of specific measures comprising each Option
The following table summarizes the specific measures comprising each package of
measures, as well the corresponding specific measure option considered under each high
204
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 25.
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level option205
. The detailed presentation and assessment of each measure can be found in
the indicated Annex.
205
The preferred options for the specific measures set out in the annex are highlighted in the table in green.
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Table 7: Summary of Specific Measures Examined for Problem Area II
Specific Measures Option 0 Option 1 Option 2 Option 3 Option 4
Baseline (Current market
arrangements)
Improved
energy
market/ no
CM
Improved energy
market/ CMs only
when needed,
based on a common
EU-wide adequacy
assessment)
Improved energy market/ CMs
only when needed, plus cross-
border participation)
Mandatory EU-wide or
regional CMs
Specific Measures related to the
Energy Market
As in section 5.1.2 As in section 5.1.4.3
+ Price Caps
(Annex 4.1)
Lower than VoLL
(Annex 4.1.4 Option 0)
At VoLL
(Annex 4.1.4 Option 2)
+ Locational Price Signals
(Annex 4.2)
Price Zones defined based on
arrangements in CACM Guideline
(4.2.4 Option 0)
Strengthened process for deciding on price zones, leading to the definition
of zones based on systematic congestion in networks
(4.2.4 Option 3)
Nodal Pricing
(4.2.4 Option 1)
+ Transmission Tariff Structures
(Annex 4.3)
Limited harmonisation of the
methodologies setting
transmission tariffs
(Annex 4.3.4 Option 0)
More concrete principles on the setting of transmission tariffs and other
network charges.
(Annex 4.3.4 Option 2)
Full harmonisation of the
methodologies setting
transmission tariffs
(Annex 4.3.4 Option 3)
+ Congestion Income (Annex
4.4)
Limited restrictions on the use of
congestion income
(Annex 4.4.4 Option 0)
Further prescription on the use of congestion income, with the aim of an even more European approach
(Annex 4.4.4 Option 1)
+ Resource Adequacy Plans
(Annex 5.1)
National plans following different methodologies
(Annex 5.1.4 Option 0)
Common EU-wide assessment by ENTSO-E becomes the basis for MS to introduce CMs
(Annex 5.1.4 Option 3)
+ Cross-border Participation of
CMs
(Annex 5.2)
No EU framework with rules for
cross-border participation
(Annex 5.2.4 Option 0)
N/A
No EU framework
with rules for cross-
border participation
(Annex 5.2.4 Option
0)
Harmonized EU framework for cross-border participation
(Annex 5.2.4 Option 1)
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5.3. Options to address Problem Area III (When preparing or managing crisis
situations, Member States tend to disregard the situation across their borders)
Overview of the policy options
With the intention to meet the objectives set out in the previous section, the Commission
services have identified several policy options ranging from an enhanced implementation
of the existing legislation to the full harmonization and decision making at regional level.
Option 0 represents the baseline or the measures currently in place. Each policy option
consists of a package of measures combining existing tools, possible updated and improved
tools and new tools which act upon the drivers of the problem. This section finalizes with
a table summarising all specific measures comprising each option.
The relevant Annex addressing the policy options below is Annex 6.
Table 8: Overview of the Policy Options for Problem Area III
Option 0: Baseline scenario – Purely national approach to electricity crises
Under the baseline scenario, Member States would continue identifying and addressing
possible crisis situations based on a national approach, in accordance with their own
national rules and requirements.
There would be no rules or structures facilitating and guaranteeing a proper identification
of cross-border crisis situations206
and ensuring that Member States take the necessary
action to deal with them, in co-operation with one another. Whilst some co-operation
between Member states could take place (e.g., between the Nordic countries as well as
within the context of the PLEF207
), in practice such cooperation would remain entirely
206
In the framework of the SESAME project (which was financed under FP7) tools were developed for the
identification of grid and production plants vulnerabilities and for estimating the damage resulting from
network failures. However, this project had a more national focus (in particular on Romania and Austria)
and the identification and management of cross-border crisis was outside the scope of this project
(https://www.sesame-project.eu/).
207
Pentalateral Energy Forum, consisting of the Ministries, NRAs and TSOs of BENELUX, Germany,
France, Austria, Switzerland.
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voluntary, and might be hampered in practice by different national rules and procedures,
and a lack of appropriate structures at regional and EU level.
Innovative tools208
have been also developed for TSOs in the area of the system security
in the last years, improving monitoring, prediction and managing secure interconnected
power systems and preventing, in particular, cascading failures209
. In addition, the recently
adopted network codes and guidelines bring a certain degree of harmonisation on how to
deal with electricity systems in different states (normal state, alert state, emergency state,
black-out and restoration) and should bring more clarity as to how TSOs should act in
crisis situations, and as to how they should co-operate with one another. However, network
codes and guidelines focus on technical issues and co-operation between TSOs (in
implementation of the current legal framework). They do not offer a framework ensuring
a proper co-ordination and co-operation between Member States on how to prepare for and
handle electricity crisis situations, in particular in situations of simultaneous scarcity.210
For instance, political decisions such as where to curtail, to whom and when, would still
be taken nationally, by reference to very different national rules and regulations. In
addition, any cross-border assistance in times of crisis would be hampered by a lack of
common principles and rules governing co-operation, assistance and cost compensation.
Finally, risks would still assessed and adressed on the basis of very different methods, and
from a national perspective only.
Stakeholders' opinions: Stakeholders agree that the current framework does not offer
sufficient guarantees that electricity crisis situations are properly prepared for and handled
in Europe. They also take the view that, whilst network codes and guidelines will offer
some solutions at the technical level, there is a need for a better alignment of national rules
and cooperation at the political level211
.
Option 0+: Non-regulatory approach
As current legislative framework established by the SoS Directive set general principles
rather than requires Member States to take concrete measures, better implementation and
enforcement actions will be of no avail.
208
ITESLA project (which was financed under FP7) developed methods and tools for the coordinated
operational planning of power transmission systems, to cope with increased uncertainties and variability
of power flows, with fast fluctuations in the power system as a result of the increased share of resources
connected through power electronics, and with increasing cross-border flows. The project shows that
the reliance on risk-based approaches for corrective actions can avoid costly preventive measures such
as re-dispatching or reduced the overall risk of failure.
209
In addition the AFTER project (which was financed under FP7) also developed tools for TSOs to
increase their capabilities in creating, monitoring and managing secure interconnected electrical power
system infrastructures, being able to survive major failures and to efficiently restore service supply after
major disruptions (http://www.after-project.eu/).
210
In addition, whilst the guidelines and codes require TSOs to co-operate, they do not require them to
engage in joint action (e.g. through the ROCs).
211
See for examle the answers to the public consultation of the International Energy Agency, ENTSO-E.
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In fact, as the progress report of 2010 shows212
, the SoS Directive has been implemented
across Europe, but such implementation did not result in better co-ordinated or clearer
national policies regarding risk preparedness.
In addition, the evaluation of the SoS Directive has revealed the existence of numerous
deficiencies in the current legal framework213
. It highlights the ineffectiveness of the SoS
Directive in achieving the objectives pursued, notably contributing to a better security of
supply in Europe. Whilst some of its provisions have been overtaken by subsequent
legislation (notably the Third Package and the TEN-E Regulation), there are still regulatory
gaps notably when it comes to preventing and managing crisis situations.
The evaluation also reveals that the SoS Directive intervention is no longer relevant today
as it does not match the current needs on security of supply. As electricity systems are
increasingly interlinked, purely national approaches to preventing and managing crisis
situations can no longer be considered appropriate. It also concludes that its added value
has been very limited as it created a general framework but left it by and large to Member
States to define their own security of supply standard. Whilst electricity markets are
increasingly intertwined within Europe, there is still no common European framework
governing the prevention and mitigation of electricity crisis situations. National authorities
tend to decide, one-sidedly, on the degree of security they deem desirable, on how to assess
risks (including emerging ones, such as cyber-security) and on what measures to take to
prevent or mitigate them.
The recently adopted network codes and guidelines offer some improvements at the
technical level, but do not address the main problems identified.
In addition, today voluntary cooperation in prevention and crisis management is scarce
across Europe and where it takes place at all, it is often limited to cooperation at the level
of TSOs. It is true that certain Member States collaborate on a voluntary basis in order to
addresss certain of the problems identified (e.g. Nord-BER, PLEF). However, these
initiatives have different levels of ambition and effectiveness, and they geografically cover
only part of the EU electricity market. Therefore, voluntary cooperation will not be an
effective tool to solve the problems identified timely in the whole EU.
Option 1: Common minimum rules to be implemented by Member States
Under Option 1, Member States would have to respect a set of common rules and principles
regarding crisis prevention and management, agreed at the European level ('minimum
harmonisation'). In particular, Member States would be obliged to develop national Risk
Preparedness Plans ('Plan') with the aim to avoid or better tackle crisis situations. Plans
could be prepared by TSOs, but need to be endorsed at the political level. Plans should be
based on an assessment of the most relevant crisis scenarios originated by rare/extreme
risks. Such assesment would be carried out in a national context (as is the case today), but
would have to based on a common set of rules. In particular, Member States would be
required, for instance, to consider at least the following risks: a) rare/extreme natural
212
Report on the progress concerning measures to safeguard security of electricity supply and
infrastructure investment COM (2010) 330 final.
213
See Evaluation of the EU rules on measures to safeguard security of electricity supply and infrastructure
investment (Directive 2005/89/EC).
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hazards, b) accidental hazards which go beyond N-1, c) consequential hazards such as fuel
shortage, d) malicious attacks (terrorist attacks, cyberattacks).
Plans would have to respect a set of common minimum requirements. They would need to
set out who does what to prevent and to manage crisis situations, including in a situation
of a crisis affecting more than one countrry at the same time. More specifically on
cybersecurity, Member States would need to set out in the Plans how they will prevent
and manage cyberattack situations. This would be combined with soft guidance on
cybersecurity in the energy sector, based on the NIS Directive214
. Member States would
also be required to set out how they ensure that assets that are important from a security of
supply perspective, are protected against undue influences in case ownership control
changes.
Plans should be adopted by relevant governments / ministries, following an inclusive
process, and (at least some parts of the Plans) should be rendered public. Plans should be
updated on a regular basis.
In addition, under Option 1 there would be new common rules and principles governing
crisis management, in replacement of the current Article 42 of the Electricity Directive,
which allows Member States to take 'safeguard measures' in crisis situations. All crisis
management actions (whether taken at the level of the TSOs or at the level of governments)
would need to respect three principles:
- 'Market comes first': Non-market measures (such as obligatory demand reduction
schemes) should only be introduced as a means of last resort, when duly justified,
and should be temporary in nature. Use of such measures should not undermine
market and system functioning;
- 'Duty to offer assistance': Member States would be obliged to address electricity
crisis situations, in particular situations of a simultaneous crisis, in a spirit of co-
operation and solidarity. This means agreeing in advance on practical solutions on
e.g. where to shed load and how much in cross-border crisis situations, subject to
financial compension (which is also to be agreed upon in advance).
- 'Transparency and information exchange': Member States should inform each
other and the Commission without undue delay when they see a crisis situation
coming (e.g., as a result of a seasonal outlook pointing at upcoming problems) or
when being in a crisis situation. They should also be transparent about measures
taken and their effect, both when taking them and afterwards.
The main benefits this option would bring is better preparedness, due to the fact that a
common approach is followed across Europe, thus excluding the risk that some Member
States being 'under-prepare'. In addition, better preparedness is likely to reduce the chances
of premature market interventions, where Member States act in a transparent manner and
214
Directive (EU) 2016/1148 of the European Parliament and of the Council of 6 July 2016 concerning
measures for a high common level of security of network and information systems across the Union, OJ
L 194, 19.07.2016, p. 1-30.
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on the basis of a clear set of rules. By imposing obligations to cooperate and lend
assistance, Member States are also less likely to 'over-protect' themselves against possible
crisis situations, which in turn will contribute to more security of supply at a lesser cost.
Since a 'minimum' harmonisation approach would be followed, Member States would have
still room to take account of national specificities, where needed and appropriate.
Stakeholders' opinions: A large majority of stakeholders is in favour of risk preparedness
plans based on common rules and principles, as a tool to ensure a more common and more
transparent approach. Consulted stakeholders215
agree on the need for a common approach
what Member States can do in crisis situations and call for more transparency.
Option 2: Common minimum rules to be implemented by Member States, plus
regional co-operation
Option 2 would build on Option 1. It would include all common rules included in Option
1 (i.e., define a set of minimum obligations Member States would need to respect). In
addition, it would put in place rules and tools to ensure that effective cross-border co-
operation takes place, in a regional and EU context. Given the interlinked nature of EU's
electricity systems, enhanced regional co-operation brings clear benefits when it comes to
preventing and managing crisis situations.
First, under Option 2, there would be a systematic assessment of rare/ extreme risks at
the regional level. The identification of crisis scenarios would be carried out by ENTSO-
E, who would carry out such assessments in a regional context. To achieve this, ENTSO-
E would be able to delegate all or part of its tasks to the ROCs. This regional approach
would ensure that the risks originating across borders, including scenarios of a possible
simultaneous crisis, are taken into account. The crisis scenarios identified by ENTSO-E
would be also discussed in the Electricity Coordination Group, to ensure that a coherent
and transparent approach is followed across Europe. For cybersecurity, building on
Option 1, the Commission would propose the development of a network code/guidelines
which would ensure a minimum level of harmonization in the energy sector throughout the
EU216.
The Risk Preparedness Plans would contain two parts – a part reflecting national
measures and a part reflecting measures to be pre-agreed in a regional context. The
latter part includes in particular preparatory measures such as simulations of simultaneous
crisis situations in neighbouring Member States ("stress tests" in regional context
organised by ENTSO-E who can delegate all or part of its tasks to the ROCs); procedures
for cooperation with other Member States in different crisis scenarios, as well as
215
See for example the Public Consultation answers of the Dutch and Latvian Governments, GEODE,
CEDEC, EDF UK, TenneT, Eurelectric and Europex welcoming risk preparendess plans.
216
The network code/guidelines should take into account at least: a) methodology to identify operators of
essential services for the energy sector; b) risk classification scheme; c) minimum cyber-security
prerequisites to ensure that the identified operators of essential services for the energy sector follow
minimum rules to protect and respond to impacts on operational network security taking the identified
risks into account. A harmonized procedure for incident reporting for the energy sector shall be part of
the minimum prerequisites.
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agreements on how to deal with simultaneous electricity crisis situations. Through such
regional agreements, Member States would be required to define in advance, in a regional
context, how information will be shared, how they will ensure that markets can work as
long as possible, and what kind of assistance will be offered accross borders, For instance,
Member States would be required to agree in advance in which situations and according to
what priorities customers would be curtailed in simultaneous crisis situations. The regional
coordination of plans would build trust and confidence between Member States, which is
crucial in times of crisis. It would also allow optimising scarce resources in times of crisis,
whilst ensuring that markets can work as long as possible.
The regional parts of the Plans should be pre-agreed in a regional context. Such regionally
co-ordinated plans would help ensure that increased TSO cooperation is effectively
matched by a more structured cooperation between Member States.217
For this reason,
Member States would be called upon to co-operate and agree in the context of the same
regional settings as are used for the ROCs. Effective regional co-operation and agreements
would help ensure that electricity crisis situations are dealt with in the most effective
manner, whilst respecting the needs of electricity consumers and systems at large.
To facilitate cross-border cooperation, Member States should designate one 'competent
authority', belonging either to the national administration or to the NRA.
Additionally, ENTSO-E would be required to develop a common method for carrying
out short-term risk assessments, to be used in the context of seasonal outlooks and weekly
risk assessments by TSOs.
To allow for a precise monitoring, ex-ante and ex-post, of how well Member States'
systems perform in the area of security of supply, harmonised security of supply indicators
would be introduced, as well as obligation on Member States to inform the Electricity
Coordination Group and the Commission on crisis situations, their impact and the
measures taken. This would enhance transparency, comparability and mutual trust in
neighbours.
Further, in this option, the role of the Electricity Coordination Group218
would be
reinforced, so that it can act as an effective forum to monitor security of supply in Europe
and oversee the way (possible) electricity crisis situations are dealt with. For instance, the
Group would be asked to review the cross-border crisis scenario's developed by ENTSO-
E and to review ex ante risk preparedness plans put in place by Member States. The Group
could issue recommendations and develop best practice. Overall, the reinforcement of its
tasks and powers would contribute to enhance cooperation and to build trust and
confidence among Member States.
217
For cases of crisis, in particular simultaneous scarcity, also ENTSO-E sees a need for "not only on a
technical level but political cooperation" and plans which "should cover extreme crisis situations beyond
the measures provided by e.g. network codes and RSCs services" (Source: ENTSO-E (2016):
"Recommendations to the regulatory framework on risk preparedness (WS5)").
218
The members of the Electricity Coordination Group are Member States authorities (ministries competent
for Energy), National Regulatory Authorities, ACER and ENTSO-E.
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Figure 7: Overview of measures in Option 2
Stakeholders' opinions: The majority of consulted stakeholders are in favour of regional
coodination of risk preparedness plans219
and a stronger co-ordinating role of the
Electricity Coordination Group220
. Various stakeholders make the case for a common
methodology for assessing risks in various time horizons, to detect cross-border crisis
situations and guarantee comparability of results221
. Several stakeholders also see a need
for clear rules and ex-ante cross-border agreements to ensure that markets function as long
as possible in (simultaneous) crisis situations222
.
The European Electricity Regulatory Forum, Florence: The Florence Forum welcomes
a more co-ordinated approach to risk preparedness based on risk preparendess plans and a
common framework for how to deal with (simultaneous) crisis situations, including the
principle that the market should act first223
.
219
See for example the Public Consultation answers of the Finish, Dutch, Norwegian governments, TenneT
and the German Association of Local Utilities.
220
See for example the Public Consultation answers of the Dutch government and ENTSO-E.
221
See for example the Public Consultation answers of the Dutch government, EDF, ENTSO-E.
222
See for example ENTSO-E's presentation on Capacity Mechanisms (TOP 2.4) from the Florence Forum
in June 2016 (available here: https://ec.europa.eu/energy/en/events/meeting-european-electricity-
regulatory-forum-florence).
223
See conclusions from Florence Forum, March 2016, paragraph 10.
Source: DG ENER
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"The Forum recognises the need for more co-ordination across Member States and clearer
rules on coping with electricity crisis situations. It encourages the Commission to quickly
bring the draft Emergency and Restoration Network Code forward for discussion with the
Member States. It also welcomes the Commission's work on a new proposal on risk
preparedness in the electricity sector and considers that risk preparedness plans and
common framework for how to deal with critical situations should be its key builing blocks.
It stresses the need that all action on risk preparedness should respect the principle that
the market should act first."
The European Parliament224
calls for more regional co-operation, notably as regards
'action to be taken in the event of an electricity crisis, in particular when such a crisis has
cross-border effects,' and calls on the Commission 'to propose a revised framework to that
end".
Council: The Council recognizes the responsibility of Member States for ensuring security
of supply but sees a "benefit from a more coordinated and efficient approach", "a necessity
to work on a further harmonization of of methods for assessing norms and indicators for
security of supply" and "a need to develop a more common approach to preparing for and
managing crisis situations within the EU".225
Option 3: Full harmonisation and decision-making at regional level
Building on Option 2, under Option 3 the risk preparedness plans would be developed
on regional level. This would allow a harmonised response to potential crisis situations in
each region. On cybersecurity, Option 3 would go one step further and nominate a
dedicated body (agency) to deal with cybersecurity in the energy sector. The creation of
the agency would guarantee full harmonisation on risk preparedness, communication,
coordination and a coordinated cross-border reaction on cyberincidents.
Crisis would have to be managed according to the regional plans agreed among
Member States. The Commission would determine the key elements of the regional plans
such as: commonly agreed regional load-shedding plans, rules on customer categorisation,
a harmonised definition of protected customers at regional level or specific rules on crisis
information exchanges in the region.
Regarding crisis handling, under Option 3, a detailed 'emergency rulebook' would be
put in place, containing an exhaustive list of measures that can be taken by Member States
in crisis situations, with detailed indications as regards what measures can be taken, in
what circumstances and when.
224
See European Parliament: Towards a New Energy Market Design (2016), Werner Langen, paragraph
68.
225
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, paragraph 7.
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Stakeholders' opinions: The results of the public consultation showed that only few
stakeholders were in favour of regional or EU wide plans. Some stakeholders mentioned
the possibility to have plans on all three levels (national, regional and EU)226
.
Whilst stakeholders generally acknowledge the need for more commonality and more
regional co-operation on risk prevention and management, there is no support for a fully
harmonised approach based on rulebooks227
.
Discarded Options
Option 0+ was disregarded as no means for enhanced implementing of the existing acquis
were identified.
Summary of specific measures comprising each Option
The following table summarizes the specific measures to be taken under each option 228
. A
more detailed discussion can be found in annex.
226
See for example the Public Consultation answers of Latvian government, EDSO, GEODE, Europex.
227
See for example the Public Consultation answers of the Finish and German governments.
228
The preferred options for the specific measures set out in the annex are highlighted in the table in green.
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Table 8: Sumary of Specific Measures Examined for Problem Area III
Specific
Measures
Option 0 Option 0+ Option 1 Option 2 Option 3
Baseline Non-regulatory
approach
Common minimum EU rules for
prevention and crisis management
Common minimum EU rules plus regional
cooperation, building on Option 1
Full harmonisation and full
decision-making at regional
level, building on Option 2
Assessments
Rare/extreme risks
and short-term risks
related to security of
supply are assessed
from a national
perspective.
Risk identification &
assessment methods
differ across Member
States.
This option was
disregarded as no
means for
enhanced
implementing of
the existing acquis
nor for enhanced
voluntary
cooperation were
identified.
Member States to identify and assess
rare/extreme risks based on common risk
types.
ENTSO-E to identify cross-border electricity
crisis scenarios caused by rare/extreme risks,
in a regional context. Resulting crisis
scenarios to be discussed in the Electricity
Coordination Group.
Common methodology to be followed for
short-term risk assessments (ENTSO-E
Seasonal Outlooks and week-ahead
assessments of the RSCs).
All rare/extreme risks
undermining security of supply
assessed at the EU level, which
would be prevailing over
national assessment.
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Plans
Member States take
measures to prevent
and prepare for
electricity crisis
situations focusing on
national approach,
and without
sufficiently taking
into account cross-
border impacts.
No common approach
to risk prevention &
preparation (e.g., no
common rules on
how to tackle
cybersecurity risks).
- - Member States to develop mandatory
national Risk Preparedness Plans setting
out who does what to prevent and
manage electricity crisis situations.
- Plans to be submitted to the Commission
and other Member States for
consultation.
- Plans need to respect common minimum
requirements. As regards cybersecurity,
specific guidance would be developed.
Mandatory Risk Preparedness Plans including
a national and a regional part. The regional
part should address cross-border issues (such
as joint crisis simulations, and joint
arrangements for how to deal with situations
of simultaneous crisis) and needs to be agreed
by Member States within a region.
Plans to be consulted with other Member
States in the relevant region and submitted for
prior consultation and recommendations by
the Electricity Coordination Group.
Member States to designate a 'competent
authority' as responsible body for coordination
and cross-border cooperation in crisis
situations.
Development of a network code/guideline
addressing specific rules to be followed for the
cybersecurity.
Extension of planning & cooperation
obligations to Energy Community partners.
Mandatory Regional Risk
Preparedness Plans, subject to
binding opinions from the
European Commission.
Detailed templates for the plans
to be followed.
A dedicated body would be
created to deal with
cybersecurity in the energy
sector.
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Crisis
management
Each Member State
takes measures in
reaction to crisis
situations based on its
own national rules
and technical TSO
rules.
No co-ordination of
actions and measures
beyond the technical
(system operation)
level. In particular,
there are no rules on
how to coordinate
actions in
simultaneous crisis
situations between
adjacent markets.
No systematic
information-sharing
(beyond the technical
level).
Minimum common rules on crisis
prevention and management (including
the management of joint electricity crisis
situations) requiring Member States to:
(i) not to unduly interference with
markets;
(ii) to offer assistance to others where
needed, subject to financial
compensation, and to;
(iii) inform neighbouring Member States
and the Commission, as of the moment
that there are serious indications of an
upcoming crisis or during a crisis.
Minimum obligations as set out in Option 1.
Cooperation and assistance in crisis between
Member States, in particular simultaneous
crisis situations, should be agreed ex-ante; also
agreements needed regarding financial
compensation. This also includes agreements
on where to shed load, when and to whom.
Details of the cooperation and assistance
arrangements and resulting compensation
should be described in the Risk Preparedness
Plans.
Crisis is managed according to
the regional plans, including
regional load-shedding plans,
rules on customer
categorisation, a harmonized
definition of 'protected
customers' and a detailed
'emergency rulebook' set forth at
the EU level.
Monitoring
Monitoring of
security of supply
predominantly at the
national level.
ECG as a voluntary
information exchange
platform.
- - Systematic discussion of ENTSO-E
Seasonal Outlooks in ECG and follow
up of their results by Member States
concerned.
Systematic monitoring of security of supply in
Europe, on the basis of a fixed set of indicators
and regular outlooks and reports produced by
ENTSO-E, via the Electricity Coordination
Group.
Systematic reporting on electricity crisis
events and development of best practices via
the Electricity Coordination Group.
A European Standard (e.g. for
EENS and LOLE) on Security
of Supply could be developed to
allow performance monitoring
of Member States.
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5.4. Options to address Problem Area IV (Slow deployment and low levels of
services and poor market performance)
Overview of the policy options
To recap, the drivers in this Problem Area are:
- Low levels of competition on retail markets;
- Low levels of consumer engagement;
- Market failures that prevent effective data flow between market actors.
Each policy option consists of a package of measures that addresses the problem drivers in
a different way and to a different extent. They aim to tackle the existing competition and
technical barriers to the emergence of new services, better levels of service, and lower
consumer prices, whilst ensuring the protection of energy poor consumers.
Box 5: Overview of the Policy Options for Problem Area IV
In the following sub-sections the policy options and the packages of measures they
comprise are described. This section is closed by a table summarising all specific measures
comprising each option.
The relevant annexes addressing the policy options below are: 7.1 to 7.6.
Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer
engagement and poor data flows
Under this option no new legislation is adopted, there are no further efforts to clarify the
existing legislation through guidance, and no additional work through non-regulatory
means to address the problem drivers. It assumes that the future situation will remain more
or less the same as today.
Stakeholders' opinions: A significant number of stakeholders consider that the level of
competition in retail markets is too low and there is no record of significant support for
current market arrangements and their organic development. The sole exception is on
billing information, where energy suppliers and industry associations indicate that there
may be little scope for EU action to ensure bills facilitate consumer engagement in the
market due to subsidiarity considerations.
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Option 0+: Non-regulatory approach to address competition and consumer
engagement
Under this option, the problem drivers are addressed to the greatest extent possible without
resorting to new legislation. This means strengthening enforcement to tackle cases of the
non-transposition or incorrect application of existing legislation, new Commission
guidance to tackle implementation issues related to difficulties in interpreting the existing
legislation, and examining new soft law provisions to address gaps in the legislation itself.
To improve competition, bilateral consultations are held with Member States to
progressively phase out price regulation, starting with prices below costs. Should it be clear
that Member State interventions in price setting are not proportionate, justified by the
general economic interest or not compliant with any other condition specified in the current
EU acquis229
, then enforcement action is taken under the existing acquis and recent Court
judgements, which require these criteria. Section 7.1.1 of the Evaluation argues that the
regulation of electricity and gas prices limits consumer choice, restricts competition, and
discourages investment.
To improve consumer engagement, the Commission issues an interpretative note on the
existing provisions in the Electricity and Gas Directives covering switching-related fees.
Section 7.1.1 and Annex IV of the Evaluation show that the current framework remains
both complex and open to interpretation with regard to the nature and scope of certain key
obligations.
The Commission works to ensure the dissemination and uptake of the key cross-sectorial
principles for comparison tools. Enforcement action follows. Nevertheless, Section 7.3.5
and Annex V of the Evaluation show that the relevance of the existing legislation is
challenged by the fact that it is not adapted to reflect new ways of consumer-market
interaction, such as through comparison tools.
The Commission also develops a Recommendation on energy bills that builds upon the
recommendations prepared by the Citizen's Energy Forum's Working Group on e-Billing
and Personal Energy Data Management230
. Section 7.1.1 and Annex V of the Evaluation
show that there is poor consumer satisfaction with energy bills, and poor awareness of
information conveyed in bills. This suggests that there may still be scope to improve the
comparability and clarity of billing information.
Finally, to better protect energy poor and vulnerable consumers231
, the Commission
establishes the EU Energy Poverty Observatory which will contribute to the sharing of
good practices and strengthens enforcement around existing requirements for National
229
Article 3(2) of the Electricity Directive and of the Gas Directive
230
https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-billing_energy_data.pdf
231
As a result of the Third Energy Package, Member States have to defined and protect vulnerable
consumers in energy markets. The evaluation of the provisions related to consumer vulnerability found
the definitions of vulnerable consumers to vary widely across Member States. ACER grouped these
definitions in two groups (i) explicit definitions when characteristics of vulnerability are stated in the
definition such as age, income, or health; and (ii) implicit definitions when vulnerability is linked to be
beneficiary of a social support measure. A study commissioned by DG ENER concluded that energy
poverty is usually a narrower term than vulnerability as it mostly refers to lack of affordability of energy
services.
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Regulatory Authorities to monitor disconnection rates – an area identified as lacking in the
Evaluation (Section 7.1.1 and Annex III).
However, no action is taken to address the market failures that prevent effective data flow
between market actors. As this involves tackling possible conflicts of interest among
market actors, non-regulatory measures were not deemed appropriate to credibly
addressing this problem driver. Section 7.3.6 and Annex IX of the Evaluation show that
the current legislation was not designed to address currently known challenges in managing
large, commercially valuable consumption data flows.
By tackling regulatory interventions in price setting, this option would enable suppliers to
profitably develop value-added products, thus fostering innovation in energy retail
markets. It would also promote the consumer-driven uptake of such innovative products
by addressing switching fees, unreliable comparison tools and unclear bills – each a key
barrier to consumer engagement.
Stakeholders' opinions: There are no explicit opinions among the stakeholders on a non-
regulatory approach. However, some of the points raised by the stakeholders, like
increased transparency on switching suppliers, exit fees, comparison tools as well as
transparent bills, may be addressed by non-regulatory measures.
Option 1: Flexible legislation addressing all problem drivers
Under this option, all problem drivers are addressed through new legislation that provides
Member States leeway to adapt their laws to the conditions in national markets.
To improve competition, Member States progressively phase out blanket price regulation
by a deadline specified in new EU legislation, starting with prices below costs.
Transitional, targeted price regulation for vulnerable consumers is permitted (e.g. in the
form of social tariffs), allowing a case-by-case assessment of the proportionality of
exemptions to price regulation that takes into account the social and economic
particularities in Member States.
To both improve competition and reduce transaction costs in the market, consumer data
management rules that can be applied independently of the national data-management
model are put in place. These include criteria and measures to ensure the impartiality of
market actors involved in data handling, as well as the implementation of standardised,
national data formats to facilitate data access. These measures aim at eliminating barriers
to entry associated with data access, and helping all market actors provide a higher level
of service to consumers through the efficiencies that information technology offers.
To increase consumer engagement, the use of contract termination fees is restricted. Such
fees are only permissible for the early termination of fixed-term contracts, and they must
be cost-reflective. Consumer confidence in comparison websites is fostered through
national authorities implementing a certification tool for the most useful and reliable
websites in their markets. In addition, high-level principles ensure that energy bills are
clear, easy to understand, and free from unnecessary information, whilst leaving Member
States some scope to tailor billing format and content to national requirements. Certain
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information elements in bills would be mandatory and would need to be prominently
displayed to facilitate the comparison of offers and switching.232
Finally, to better protect energy poor and vulnerable consumers, an improved, principle-
based EU legal framework to support Member State action on vulnerable and energy poor
consumers is put in place. A generic adaptable, definition of energy poverty based on
household income and energy expenditure is included in the legislation for the first time.
Member States would measure and report energy poverty with reference to household
income and energy expenditure, and NRAs would publish the number of disconnections
due to non-payment – figures they should already be collecting under the current
legislation. These actions are taken cumulatively, on top of the non-regulatory measures
on energy poverty described in Section 5.4.3.
These measures build upon the existing provisions on energy poverty in the Electricity and
Gas Directives which state that Member States must adress energy poverty where it is
identified. They offer the necessary clarity about the meaning of energy poverty, as well
as, the transparency with regards to the number of household in energy poverty. Better
monitoring of energy poverty across the EU will, on one hand, help Member States to be
more alert about the number of households falling into energy poverty, and on the other
hand, peer pressure will also encourage Member States to put in place measures to reduce
energy poverty. Since currently available data can be used to measure energy poverty, the
administrative cost is limited233
. Likewise, the actions proposed do not condition Member
States on their primary competence of social policy, hence, respecting the principle of
subsidiarity.
Taken together, this option would strongly promote innovation on retail markets by
ensuring that new entrants and energy service companies receive non-discriminatory
access to consumer data – access that will allow these market actors to develop and offer
the value-added products that (integrated) incumbents have not. A firm commitment to
phase out blanket price regulation would enable suppliers in many Member States to
differentiate their offers to consumers through non-price competition. And by tackling
financial barriers to switching, improving the availability of comparison tools and helping
consumers understand important information in their bills; this option would increase
consumer engagement with the market and the selective pressure for new services.
Stakeholders' opinions: Feedback indicates that the general principles put forward as part
of Option 1 would likely enjoy broad support amongst stakeholders. The sole exception
would be the measures on billing information, where energy suppliers and industry
associations have stated that there may be little scope for EU action. However, even here,
the general principles proposed in this option would give broad leeway to Member States
to tailor national requirements to the conditions and consumer preferences in each market.
232
EPRG Working paper 1515 (2015), "Why Do More British Consumers Not Switch Energy Suppliers?"
by X. He D. Reiner: "We conclude that policies which emphasize simplification of energy tariffs,
increasing convenience of switching, improving consumers’ concerns about energy issues, improving
consumers’ confidence to exercise switch are likely to increase consumer activity."
233
See Annex 7.1, Table 16.
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Option 2: EU Harmonization and extensive safeguards for consumers addressing
all problem drivers
Under this option, all problem drivers are addressed through new legislation that aims to
provide maximum safeguards for consumers and the extensive harmonisation of Member
State action throughout the EU.
To improve competition, Member States progressively phase out all blanket price
regulation, starting with prices below costs, by a deadline specified in new EU legislation,
as per Option 1 (flexible legislation). However, exemptions to price regulation are defined
at the EU level in terms of either: a) a price threshold to be defined based on principles
ensuring coverage of the cost incurred by the energy undertakings above which Member
States may set retail prices; and/or b) a consumption threshold below which household
may benefit from a regulated tariff.
To both improve competition and reduce transaction costs in the market, a standard
consumer data handling model is enforced. This assigns the responsibility for data handling
to a neutral market actor, such as a TSO or independent third-party, eliminating all
possibility of conflicts of interest. Nationally standardised formats are devised to facilitate
data access to all market actors concerned, including cross-border access.
To increase consumer engagement, all switching-related fees are banned, including
contract termination fees. NRAs establish comparison websites to ensure consumers have
access to at least one neutral comparison resource, alongside private sector offerings. In
addition, the format and content of energy bills is partially harmonized through the
inclusion of a standard 'comparability box' that prescriptively presents key information in
exactly the same way in every EU bill.
Finally, to better protect energy poor and vulnerable consumers, a uniform EU framework
to monitor energy poverty and reduce disconnections is put in place. A specific,
harmonised definition of energy poverty is included in EU legislation referring to
households that fall below the poverty line after meeting their required energy needs. In
order to measure energy poverty, Member States survey the energy efficiency of their
national housing stock and calculate the amount of energy, and costs, required to make all
housing comfortable. These survey results are reported to the Commission.
In addition, a host of preventive measures on disconnections are put in place: (i) Member
States are to give all customers at least two months (approximately 40 working days) notice
before a disconnection from the first unpaid bill; (ii) before a disconnection, all customers
receive information on sources of support, and are offered the possibility to delay payments
or restructure their debts; and (iii) the disconnection of vulnerable consumers is prohibited
in winter.234
These actions are taken cumulatively, on top of the non-regulatory measures
on energy poverty described in Sections 5.4.3.
As with Option 1 (Flexible legislation), this option would strongly promote innovation on
retail markets through non-discriminatory access to consumer data, a firm commitment to
phase out blanket price regulation, and by tackling barriers to consumer engagement.
However, any negative impacts to competition resulting from the stronger, and more
234
Similar legislation is already in place in 14 Member States.
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costly, safeguards for the vulnerable and energy poor may also reduce the availability of
new services. In addition, Member States may be better suited to design disconnection
safeguard schemes to ensure that synergies between general national social service
provisions and disconnection safeguards are achieved.
Stakeholders' opinions: Whilst many stakeholders support the objectives Option 2 aims
to achieve, several have flagged reservations regarding the prescriptive approach to
achieving them. In particular, NRAs have voiced their unease over an over-prescriptive
EU billing format, and recommend that the decision on whether or not to allow contract
exit fees is best taken at the national level. NRAs also point out that it is their role to define
the appropriate methodologies for applicable price regulation. Most of the Member States
consider that the model for data handling should be best decided at national level. And
finally, whilst many stakeholders have supported comparison tool accreditation schemes
(Option 1 – flexible legislation), none have called for government authorities to provide
comparison tools exclusively.
Summary of specific measures comprising each Option
The following table summarizes the specific measures comprising each package of
measures, as well the corresponding specific measure option considered under each high
level option.235
The detailed presentation and assessment of each measure can be found in
the indicated Annex.
235
The preferred options for the specific measures set out in the annex are highlighted in the table in green.
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Table 9: Summary of Specific Measures Examined for Problem Area IV
Specific
Measures
Option 0 Option 0+ Option 1 Option 2
Baseline Non-regulatory approach Flexible legislation Harmonization and extensive consumer safeguards
Energy poverty
and
disconnection
protection
(Annex 7.1)
Sharing of good
practices(Annex 7.1.4
Option 0)
EU observatory for energy
poverty. Sharing of good
practices and increase efforts
to correctly implement
legislation (Annex 7.1.4
Option 0+)
Introducing a generic adaptable, definition
of energy poverty in EU legislation, and
setting an EU framework to monitor
energy poverty (Annex 7.1.4 Option 1)
Introducing a specific, harmonised definition of energy
poverty in EU legislation, a comprehensive EU
framework to monitor energy poverty based on an energy
efficiency survey of the housing stock, and a host of
preventive measures to avoid disconnections (Annex 7.1.4
Option 2)
Price regulation
(Annex 7.2)
Making use of existing acquis to continue bilateral
consultations and enforcement actions to restrict price
regulation to proportionate situations justified by manifest
public interest
(Annex 7.2.4 Option 0)
Requiring MS to progressively phase out
price regulation for households, starting
with prices below costs, by a deadline
specified in new EU legislation, while
allowing transitional, targeted price
regulation for vulnerable customers
(Annex 7.2.4 Option 1)
Requiring MS to progressively
phase out price regulation for
households below a certain
consumption threshold to be
defined in new EU legislation
or by MS, with support from
Commission services
(Annex 7.2.4 Option 2a)
Requiring MS to phase
out below cost price
regulation by a
deadline specified in
new EU legislation
(Annex 7.2.4Option
2b)
Data
management
(Annex 7.3)
Member States are primarily responsible on deciding roles
and responsibilities in data handling (Annex 7.3.4 Option 0)
EU data management rules that can be
applied independently of the national data-
management model (Annex 7.3.4 Option
1)
A standard EU data management model (data hub)
(Annex 7.3.4 Option 2)
Consumer
engagement
(Annexes 7.4, 7.5
and 7.6)
Lacklustre consumer
engagement persists,
diminishing the demand
for new services and
competitive pressure in the
market
Improved EU guidance and
Recommendations on
switching-related charges and
comparison tools (Annexes
7.4.4, and 7.5.4 Option 0+)
Flexible legislative measures to further
limit switching-related charges,
establishing a certification scheme to
improve consumer confidence in
comparison tools, and making information
in bills clearer through minimum content
requirements (not format) (Annexes 7.4.4,
7.5.4 and 7.6.4 Option 1)
Outlawing all switching-related charges, making all
national authorities offer (or fund) an independent
comparison tool, and full EU harmonization of the
presentation of certain information in bills (Annexes
7.4.4, 7.5.4 and 7.6.4 Option 2)
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6. ASSESSMENT OF THE IMPACTS OF THE VARIOUS POLICY OPTIONS
This section assesses the impacts of the options under each Problem Area. The analysis focuses
on the broad impacts of those options. The impacts of the specific measures included in each
option are assessed in more detail in separate annexes attached to this impact assessment.
Each option was assessed both quantitatively and qualitatively, in an effort to capture at the
highest possible detail the impacts of the underlying measures within each option. When
reliable quantitative analysis or information was not available, the assessment could only be
performed qualitatively, based on specific criteria.
6.1. Assessment of economic impacts for Problem Area I (Market design not fit for an
increasing share of variable decentralized generation and technological
developments
Methodological Approach
6.1.1.1.Impacts Assessed
The market design options are examined on the basis of their effectiveness in addressing the
identified problems and achieving the desired objectives, while at the same time facilitating the
delivery of the 2030 climate and energy targets236
in a cost-efficient and secure way for the
whole of Europe.
As the examined measures focus on the better functioning of the electricity markets237
,
economic impacts are in particular analysed with respect to competition, cost-efficiency, better
utilization of resources, as well as impacts on security of electricity supply.
The effect of the measures on the wholesale markets will induce indirect social impacts and
have limited effect on innovation and research. The effects of energy market related polices on
employment are primarily associated with the policy measures seeking to secure the
achievement of the 2030 decarbonisation objectives238
. They will therefore not be assessed in-
depth for all options.
Some indirect environmental impacts are also expected, due to the different types of fuel used
for power generation, as a well-functioning flexible electricity market would incentivize the
increase of low carbon generation.
236
See: http://ec.europa.eu/clima/policies/strategies/2030/index_en.htm .
237
Note that these options are not touching the issue of investment, which is examined under Problem Area II.
Therefore the same power generation mix is assumed for all options.
238
Reference is hence made to the impacts assessments for the EE and RED II initiatives and the one elaborated
in the context of Communication from the Commission to the European Parliament, the Council, the European
Economic and Social Committee and the Committee of the Regions, "A policy framework for climate and
energy in the period from 2020 up to 2030" (SWD(2014) 15 final)
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Other significant impacts, direct or indirect, are not expected for the examined options, unless
specifically noted.
The assessment is presented individually for each option, with qualitative analysis and
interpretation of quantitative results. Summary tables reporting the modelling results for all
options are included in section 6.1.6.
6.1.1.2.Modelling and use of studies
For most of the quantitative analysis, the METIS239
modelling software was used to underpin
the findings on the impact of the different options. METIS is a modular energy modelling
software covering with high granularity (geographical, time) the whole European power system
and markets. Simulations adopted a Member State-level spatial granularity and an hourly
temporal resolution for year 2030 (8760 consecutive time-steps per year), capturing also the
uncertainty related to demand and RES E power generation.
For consistency with all parallel European Commission work on the 2030 Energy and Climate
Framework, in the Red II, EE and Effort Sharing Regulation impact assessments, METIS was
set-up (calibrated) such as to reflect as close as possible240
the year 2030 projection of the power
sector in the PRIMES EUCO27 scenario. The PRIMES EUCO27 scenario241
, built on the EU
Reference Scenario 2016, ensures a cost-efficient achievement of at least 40% GHG reduction
(including agreed split of reductions between ETS and non-ETS), 27% RES and 27% EE target.
A stand-alone analysis of the impact of potential policies promoting downstream price and
incentive based demand response, at all customer segments (industrial, commercial,
residential), has also been undertaken (detailed information hereon can be found in Annex 3.1).
The options analysed looked at how to reach the full potential of demand response in order to
reduce overall system costs, considering (i) both price and incentive based demand response,
and their combination, as well as (ii) the level of access of demand service providers to the
market (access rules and incentives), and (iii) customers' ability to react (by means of access to
required technologies-smart metering, tariff structures and knowledge) for engaging in price
based demand response. The analysis focused on the assessment of the theoretical potential of
demand response, based on the nature of the electricity use/ability to shift demand by different
clusters of consumers, its current level, and how the different options are likely to increase the
share of the theoretical potential being realised, as well as in the estimation of associated cost
and benefits.
6.1.1.3.Summary of Main Impacts
Figure 8 below summarizes the annual quantified benefits of the assessed options for 2030242
,
as presented in detail in sections 6.1.2 to 6.1.5. It illustrates the significant benefits of the
239
A detailed description of the METIS model can be found in Annex IV, including details on the implemented
modelling methodology.
240
A detailed description of the METIS calibration to PRIMES EUCO27 can be found in Annex IV.
241
More details on the methodological approach followed concerning the baseline, on EUCO27, as well as on
the coherence with the scenarios of all parallel initiatives can be found in Annex IV.
242
All impacts were assessed for one full year (8760 hours) reflecting projected situation in 2030. Reported
figures are in annual real terms (€'13).
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measures under Options 1 to adapt the market design, with annual savings in 2030 of EUR 5.9
billion only for Sub-option 1(a) (level playing field), EUR 8.6 billion for 1(b) (strengthening
short-term markets) and EUR 9.5 billion for Sub-option 1(c) (demand response/distributed
resources). For Option 2 (fully integrated market) the calculated benefits would amount to EUR
10.6 billion.
Figure 8: Annual cost savings for Problem Area I in 2030 by option
Source: METIS
6.1.1.4.Overview of Baseline243
(Current Market Arrangements)244
Under the baseline, the power system in 2030 relies heavily for energy on RES E generators,
as well as conventional generation which is to a large degree inflexible. In particular, the share
of RES E in electricity generation has almost reached 50%, thus being equal to the share of all
other conventional generation together (i.e. gas, coal, lignite, nuclear, oil). The share of variable
generation (solar and wind) in total generation approaches 30% across Europe. Concerning
conventional generation, nuclear holds a 22% share, coal and lignite a 15% share, and natural
gas 13%. The respective shares tend to differentiate across EU regions, based on the
particularities of each region (Figure 9).
243
The assumptions concerning the baseline can be found in Section 5.1.2 and in Annex IV.
244
Although all modelling work was based on the PRIMES EUCO27, the PRIMES scenario has as a basic
assumption the existence of well-functioning competitive markets. As this is the ultimate goal of the assessed
measures, the baseline departs form EUCO27, reflecting the observed distortions or inefficiencies of current
market arrangements.
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Figure 9: Shares of Electricity Generation per Region245 in EU in the Baseline
Source: METIS
A number of rules affecting dispatch remain in place, most notably priority dispatch246
for RES
E and that certain technologies are considered as must-run247
, reflecting current practices and
nominations in the market. In fact special dispatch rules concern 60% of total installed capacity
(752 GW on a total of 1,247 GW).
245
For the modelling purposes, an indicative split of Europe into five regions was made as follows (Cyprus was
excluded as assumed not directly interconnected to the rest countries):
Region 1 (CE): Austria, Belgium, Czech Republic, Demark, France, Germany, Hungary, Luxembourg,
Netherlands, Poland, Slovakia, Slovenia
Region 2 (NEE): Estonia, Finland, Latvia, Lithuania, Sweden and Norway.
Region 3 (NWE): Ireland and UK
Region 4 (SWE): Portugal and Spain
Region 5 (SEE): Bulgaria, Croatia, Cyprus, Greece, Italy, Malta, and Romania
246
In "Evaluating the impacts of priority dispatch in the European electricity market", Oggioni et al (2014), show
using a stylized model that significant increase of wind penetration under priority dispatch can cause even the
collapse of the EU Target Mode. Test-runs performed using METIS came to a similar conclusion. Initial runs
lead to significant hours of loss of load for many MS. In order to resolve this issue a "softened" definition for
priority dispatch was assumed for the modelling, allowing the curtailment of units (which should not be
normally the case under priority dispatch) but at a cost.
247
In general, when scheduled in day ahead, must-run units cannot be decommitted during intraday and are
required to operate at least at their technical minimum level. For the scope of the modelling, coal and lignite
units were assumed as being must-run in the baseline. Day-ahead scheduling was assumed though always
optimal (so only units with priority dispatch were assumed to disrupt the economic merit order in day-ahead,
namely biomass) for each national market, which may not be true in practice due to nominations, scheduling
practices, etc. Modelling performed with PRIMES/IEM, results presented in Section 6.2.6.1, captured also the
effect of nominations and other practices in the baseline.
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Region 1
Region 2
Region 3
Region 4
Region 5
Region 1 Region 2 Region 3 Region 4 Region 5
Variable RES
Generation
27% 14% 34% 48% 29%
Hydro 10% 49% 4% 19% 19%
Biomass, Waste
& Other RES
5% 8% 15% 3% 7%
Gas 9% 7% 24% 12% 20%
Oil 0% 0% 0% 0% 0%
Solids 21% 4% 1% 4% 17%
Nuclear 27% 18% 22% 14% 7%
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Figure 10: Projected Generation Capacity in 2030 per Member State in GW248
Source: METIS
Another factor reducing the flexibility of the European power system is the limited allocation
of interconnection capacity during intraday and balancing time frames, as well as the varying
gate closures and products, which in practice reduce the opportunities for trading in the short-
term markets and thus their liquidity.
Reserves are procured on a national level and in many cases in infrequent intervals249
, with
corresponding services mainly provided by (large) thermal generators and only in some
Member States by industrial consumers.
Demand response, storage (excl. hydro) and distributed generation have very limited
participation in the market. In most cases available products are not customized for these
resources, minimum thresholds exist for participating in the market, etc. At the same time, a
large part of the generation, mainly RES E, are not balance responsible and do not have a strong
incentive to perform accurate forecasts and declare accurate schedules in the day-ahead market
(the share of variable generation is about 42% of total generation capacity). As a consequence,
the observed imbalances are large, leading to increased needs for frequency reserves.
The deficiencies of the current regulatory framework create significant inflexibility to the
system operation; the inflexibility in turn increases further the need for reserves (notably so-
called replacement reserves)250
. Close to real-time, the TSOs can mainly rely either on units
248
Please note that the assumed generation capacities in the baseline have certain differences compared to the
ones in EUCO27 PRIMES scenario, as a preliminary version of EUCO27 was used for the calibration. Further
details can be found in Annex IV.
249
For the scope of the modelling, a yearly procurement by (large) thermal generators and hydro has been
assumed for countries with no reserve market, while daily optimal procurement is modelled in countries with
such markets. More details can be found in Annex IV and in "Electricity Market Functioning: Current
Distortions, and How to Model Their Removal" COWI (2016).
250
It should be emphasized that METIS does not include a grid model. Thus the main use of replacement reserves
('RR'), to address grid (non-frequency related) issues, is not captured. The implemented methodology can only
-
50
100
150
200
250
AT
BE
BG
CH
CY
CZ
DE
DK
EE
ES
FI
FR
UK
GR
HR
HU
IE
IT
LT
LU
LV
MT
NL
NO
PL
PT
RO
SE
SI
SK
Nuclear
Solids
Oil
Gas
Biomass, Waste
& Other RES
Hydro
Variable RES
Generation
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providing replacement reserves or on very flexible (and expensive) units to avoid loss of load
(peakers). In this context, in METIS replacement reserves provide than 600 GWh of electricity
in the baseline, mainly in Poland and South East Europe. The same applies for RES E
curtailment, as curtailment is the only alternative to the encountered stress of the system and
the lack of available flexible resources: 13.0 TWh of RES E is found to be curtailed on an
annual basis, mainly in the Iberian Peninsula (8.3 TWh) and UK/Ireland (4.1 TWh).
Policy Sub-option 1(a) (Level playing field amongst participants and resources)
6.1.2.1.Economic impacts
The restoration of the economic merit order curve in the wholesale electricity market has a
direct and significant positive impact to the cost-efficient operation of the power system,
leading to tangible reductions of the costs consumers. It would also allow to feed in (and
remunerate from the market) more RES E (notably from wind and solar) to the system.
With special rules concerning unit dispatching eliminated (i.e. must-runs, priority dispatch), the
TSOs are able to schedule and re-dispatch units more efficiently. As a result (in conjunction
with the other measures under this option):
- total costs of the power system are reduced by 7%;
- the activation of replacement reserves is reduced by about 500 GWh;
- RES E curtailments (e.g. wind and solar) decline by 4.7 TWh251
; and,
- the occurrence of negative prices is completely eliminated252
.
Figure 11 - which presents the merit order253
at a given hour - illustrates how preferential
dispatch rules for certain technologies shift the merit order to the right, resulting in price
decreases but at the same time in an increase of the overall costs for the system. The example
shown for biomass priority dispatch is also applicable for must-runs and priority dispatch of
other (expensive) technologies. Restoring the economic merit order thus reduces the overall
costs for the power system at times where these technologies would be out-of-the-money, while
increasing the electricity price during these hours.
be considered as a proxy in an effort to capture a part of the impacts of RR. As some of the scenarios (Options
0 (baseline) and 1(a)( level playing field)) were characterised by important values of Loss of Load during the
intraday time frame, it was assumed that this was addressed by replacement reserves. To compute the costs
related to RR, first the intraday loss of load curve was identified at country level and then the amount of peaker
capacity needed to bring the Loss of Load duration down to 3 hours in each country was computed. A cost of
60k EUR/MW/y for peaker units and fuel costs of 180 EUR/MWh was assumed.
251
From a system perspective, it can sometimes be economical to reduce the generation of wind and solar in
order to maintain the system balance.
252
This result is directly linked with the modelling assumption that all electricity is traded in the market.
253
Each generation fleet is represented as a block, as large as its power capacity and as high as its generation
cost. Without distortions, the market dispatches the lowest (cheapest) blocks until demand is met. The
generation cost of the most expensive dispatched power plant sets the clearing price.
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Figure 11: Merit order effect of priority dispatch
Source: METIS
Focusing on priority dispatch, which was found to be the main distortion for the day-ahead
market scheduling for the modelling254
, the biggest impacts on generation would be observed
in Denmark, UK and Finland, where biomass holds a large share of generation capacity. The
removal of priority of dispatch would have a considerable effect on expensive biomass
production255
, which in most cases is dispatched out of the merit order. It can also be expected
that the share of CHP generation would be negatively affected, due to the relatively inflexible
character of CHP production256
. On the other hand, removing priority dispatch rules would
benefit variable RES E which could expand its production (due to the reduction in curtailments).
More importantly, variable RES E producers could significantly increase their revenues due to
the increase of the wholesale prices (partly due to the elimination of negative prices)257
. Overall,
the removal of priority dispatch and must-runs helps better integrating variable RES E
generation and leads to significant system costs reductions and thus cost savings for consumers.
254
Data availability on must-runs, nominations and other practices affecting the day-ahead schedule, leading to
an operation of the system deviating from the economic merit order, was very limited and thus were not
captured by the model. The impacts of must-runs were captured however for the intraday market and amounted
to around EUR 0.5 billion.
255
The Commission's study indicates that up to 85% of biomass generation could be affected by removing priority
dispatch. This result is also partly due to the assumption of having only one fuel for biofuel/biogas, this being
exclusively wood, rendering biomass very expensive. Note also that the analysis focuses on electricity
dispatch and does not examine why would a biomass (or any other) plant want to operate with losses in the
wholesale market (most likely an additional revenue stream like income from selling heat or some kind of
operational support would be required), as is often the case today. A more complete analysis of this result is
presented under environmental impacts, Section 6.1.6.
256
As part of the limitations of the modelling, one should note that the effects of removing priority dispatch from
CHP are not captured in the assessment. In particular CHP and small scale RES E are not modelled as separate
assets. It can be expected though that the results on biomass would be applicable also to a large part of the
CHP generation, unless they are able to recover their losses from the heat market or are industrial CHP, in
which case industrial opportunity costs need to be considered.
257
Because of biomass' assumed flexibility, a part of the lost revenues is recovered from its participation in
reserve procurement and balancing energy activation
Without biomass priority dispatch
With biomass priority dispatch
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Figure 12: Effect of removal of special dispatch rules to negative prices
Source: METIS
The above also leads to an increase of the share of Combined Cycle Gas Turbines ('CCGTs') in
power generation258
. RES E generation enters the market merit order, thus catering for more
efficient price formation in the day-ahead and intraday markets. The removal of priority
dispatch will offer access on equal terms to all resources. Moreover, it will more than double
the competitive segment of the market, which in the baseline was only 40% of the market.
As more resources participate under the same competitive rules in the markets, markets would
become more competitive259
. This implies an increase in wholesale prices as they will now
reflect the actual marginal cost of generation instead of one technically lowered via rules
affecting dispatch260
. As a result, this will lead to a much more cost-efficient operation of the
power system, and consequently to a 7% decrease of its total cost.
Finally, the extension of balance responsibility to all generating and consuming entities, offers
a strong incentive for variable RES E and other balance responsible parties to improve their
forecasting, bid more accurately in the day-ahead market and be more active in the intraday
markets. This leads to smaller imbalances and a lower requirement for reserve procurement by
the TSOs. In particular the needs for mFRR are reduced by around 30%. This, combined with
the capability of the demand response to also participate261
in the reserve procurement and
balancing markets, leads to a more cost-efficient reserve procurement process.
258
Share of CCGT in total net electricity generation increases from 12.3% to 15.1%.
259
See for a more detailed discussion of the arguments for and against maintaining priority dispatch in Annex 1.
260
The elimination of the significant hours with negative prices also contributes to the increase of the average
wholesale price.
261
Note though that as no measures are assumed to be implemented here for incentivizing the wider participation
of demand response, only industrial consumers are assumed to be participating in the respective markets.
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6.1.2.2.Who would be affected and how
Abolishing priority dispatch and priority access would mainly affect RES E producers using
biofuels and CHP262
and operators that benefit from priority dispatch when producing using
indigenous resources fuels (if their marginal costs are substantial). For low marginal cost,
variable generators, such as wind and solar power plants, the impact is actually positive, which
will be amplified by measures to enable RES E access to ancillary services markets.
In any event, all generators will benefit from increased transparency and legal certainty on
redispatch and curtailment rules. For TSOs, the removal of priority dispatch and priority access
would also facilitate grid operation.
Introducing balancing responsibilities (with exemption possibilities for emerging
technologies263
and or small installations264
) will mainly impact generators currently exempted
or partly shielded from balancing responsibility. Accordingly, this measure will mean they have
to increase their efforts to remain in balance (e.g. through better use of weather forecasts)
though at the costs of being exposed to financial risks.
6.1.2.3.Administrative impact on businesses and public authorities
The removal of priority dispatch, priority access and ensuring compliance with the balancing
rules would give rise to administrative impacts for RES E (and CHP) generators, in particular
for operators of very small installations. This administrative impact can however be
significantly reduced by facilitating aggregation, allowing the joint operation and management
of a large number of small plants (as discussed in more detail under Option 1(c)).
Impacts of Policy Sub-option 1(b) (Strengthening short-term markets)
6.1.3.1.Economic Impacts
Strengthening short-term electricity markets improves market coupling across time-frames,
leads to a more efficient utilization of interconnector capacity and reduces the amount of
required reserves, as well as their cost.
The efficiency of the intraday markets is improved due to the harmonization of their market
specifications, including the transition to continuous trade and harmonisation of gate closures,
as well as by an improved allocation of interconnector capacity across time-frames.
Harmonising intraday markets across Europe265
allows to further reduce RES E curtailment by
460 GWh and the utilisation of replacement reserves by 100 GWh. Note that curtailment is not
only reduced in countries where implicit auctions were not implemented in Option 1(a) (level
262
As part of the limitations of the modelling, one should note that the effects of removing priority dispatch from
CHP are not captured in the assessment. See also footnote 254.
263
In the PRIMES EUCO27 scenario, the emerging technologies of tidal and solar thermal generation (other
technologies having insignificant shares) are projected to have a total installed capacity of 7.26 GW (0.7% of
total generation capacity) and produce 10 TWh of electricity in 2030 (0.3% of total generation).These shares
only slightly increase by 2050.
264
In the PRIMES EUCO27 scenario, RES E small-scale capacity is projected in 2030 to reach 85 GW (7.8 %
share in generation capacity) and produce 96 TWh of energy (2.9% share of total generation).
265
Continuous trading was modelled as consecutive hourly implicit auctions.
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playing field), but in already implicitly coupled regions too. Thus, extending the coupled area
also benefits already coupled countries such as Germany, since it can export more of its variable
RES generation. The effects are illustrated in Figure 13.
Figure 13: Positive impacts of harmonising intraday markets across Europe266
Source: METIS
By improving the methodologies for reserve dimensioning and procurement of balancing
reserves, the need for balancing reserves is further reduced compared to Option 1(a). Certain
improvement comes from the separation of the bids and prices for up and down regulation in
order to reflect their true underlying marginal costs, which may be different both for generation
and load267
. The separate provision of downwards reserves greatly improves the efficiency of
the system, as now thermal plants are not forced to be online to provide such reserves. Another
means is via the procurement of reserves on a day-ahead basis, thus their sizing being able to
reflect the hourly needs for these services, while at the same time allowing the most efficient
resources at a given hour to be procured as reserves by the TSO.
The reduction in the reserve needs though is mainly achieved by the regional reserve
dimensioning and more efficient exchange and sharing of balancing capacity among TSOs, as
the generation and consumption patterns differs between Member States according to the
generation mix, renewable energy sources and differences in energy consumption. Thus, the
79.6 GW of reserve needs (FCR + FRR) in Option 0, is reduced to 65.8 GW in Option 1(a)
266
The figures presented in this paragraph show the impact of implicit intraday auctions only. Other measures of
Option 1(b) (strengthening short-term markets), in particular interconnection reservation at day-ahead for
reserve procurement, tend to increase intraday costs.
267
Although the separation of upward and downward balancing was initially foreseen for this initiative, and thus
assessed herein, it may be introduced earlier in the EB GL.
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(level playing field) and to only 42.3 GW in Option 1(b) (strengthening short-term markets) (a
reduction of 47% compared to the baseline).
It is important to note that the reduction in FRR268
is stronger in the well-interconnected regions
(about 50% reduction), namely Central Europe, the Nordics and South / South East Europe,
while the benefits for UK/Ireland and Spain/Portugal are smaller due to their limited
interconnection (about 20% reduction). In order to achieve these reductions from the sharing of
reserves, the Member States need to ensure that sufficient interconnection capacity is reserved
for this purpose, in order to ensure that despite the lower reserve requirements, the national
ability to balance the system remains the same269
. The amount of capacity that needs to be
reserved for this purpose is on average approximately 6%270
of the Net Transfer Capacities
('NTCs'), with actual values varying significantly per interconnector and per hour of the day.
Similarly, different market areas have different access to flexible resources and such flexible
resources are vital to the cost-efficient integration of renewable electricity generation. TSOs
may not only procure smaller volumes of reserves but providers of relatively cheap flexibility
resources may supply a larger volume thereof. Hence, overall balancing market payments are
reduced, while at the same time more interconnection capacity can be given to the market by
reducing transmission reliability margins ('TRMs').
An interesting observation coming from the assessment is the increased generation by baseload
thermal plants, compared to more flexible thermal plants. In particular, the electricity
generation of nuclear, CCGTs, coal and lignite plants increases by 10%, while the generation
of gas and oil peakers reduces by 50% compared to the baseline271
. The reason is that by sharing
resources between countries and decreasing reserve needs, the baseload plants do not need to
retain part of their capacity on stand-by for supplying reserves and thus can increase the
quantities of energy they generate. At the same time, though, flexible plants end up competing
for reduced amounts of reserve needs, thus their revenues are significantly reduced compared
to Option 0 (baseline) and Option 1(a) (level playing field)/ Therefore, better interconnecting
268
Both mFRR and aFRR
269
Adopting a regional approach to reserve dimensioning results in lower reserve requirements because of the
statistical cancellation that can occur between imbalances originating from different countries. As a result the
reserve needs are lower when adopting a regional dimensioning approach. The regional reserve need is then
translated into minimal reserve requirements at national level by using an allocation criteria (in METIS case
the national annual demand). However a national TSO still has to face the same level of risk - the imbalances
on its Control Area remain the same – and the minimal reserve requirements may not be sufficient to balance
its system. As a consequence, national TSOs have to reserve a share of the interconnection capacity for
reserves, so that the other countries can assist it to balance the system. METIS does not explicitly model
reserve exchanges, but risk pooling.
270
Considering that for Option 1(b) an assumption was made that the NTC capacities were increased by 5%,
reflecting e.g. the reduced TRM compared to Option 1(a) due to the increased co-operation between MS via
ROCs, it is interesting to notice that the average capacity that needs to be reserved for sharing balancing
reserves is around the same level. On the other hand this does not signify something, as the averaging hides
the huge variability among hours and interconnectors.
271
It should be noted that the analysis excludes the effect that increased generation by thermal plants would have
on the carbon market and how this in turn would indirectly impact electricity generation.
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markets and making them more flexible serves as a second option for bringing more flexibility
into the system, complementary to but also competing with flexible generation plants.
Enhancing TSO regional coordination through the establishment of regional operational centres
and by optimising market, operational, risk preparedness and network functions from the
national to the regional level will entail significant efficiency gains and increase social
welfare.272
For example, the regional sizing and procurement of reserves via ROCs could lead
to benefits of EUR 3.4 billion compared to benefits of EUR 1.8 billion from national sizing and
procurement of reserves based on daily probabilistic methodologies.273
Significant welfare
benefits would, inter alia, derive from the more efficient use of infrastructure and from a
decrease of financial losses that would otherwise result from the disconnection of demand in
case of generation shortages.
6.1.3.2.Who would be affected and how
Improving short-term markets will affect all generation operators to a certain extent but it will
in particular improve the ability of variable RES E operators to participate in the market.
Improving intraday and balancing markets would impact the work of the TSOs and Power
Exchanges, because of their involvement in the operation of these markets. On the one hand
this will require operating the system and organising trade within shorter timeframes. On the
other hand, the shorter timeframe will allow TSOs to benefit from significant efficiencies and
to reduce the risk of system problems. TSOs will also be affected through the need to
collaborate closer with neighbouring TSOs through ROCs and through the changes to the
balancing markets which they operate. This has the positive effect of requiring TSOs to consider
systematically the impact of their actions on their neighbouring TSOs.
6.1.3.3.Administrative impact on businesses and public authorities
The administrative impact on businesses is marginal as compared with the baseline.
Power exchanges and TSOs would have to review and adapt their business practises to
facilitate the changes to the market functioning as envisaged under this option. Notably,
changes will have to be made to trading arrangements for intraday and balancing products.
TSOs would collaborate through ROCs, which will have to be set up. The setting up of the
ROCs can be estimated to cost between 9.9 and 35.6 million Euros per entity, depending on the
functions and degree of responsibilities attributed to the ROCs.274
Whereas these costs are not insignificant, these costs of several million Euros (which would be
covered and compensated by grid fees) are minor when compared with the benefits this option
will bring.
272
For more information on the assessment of the economic impact of ROCs, please refer to Table 2 of Annex
2.3 of the Annexes to the Impact Assessment.
273
"Integration of electricity balancing markets and regional procurement of balancing reserves", COWI (2016).
274
"Integration of electricity balancing markets and regional procurement of balancing reserves", COWI (2016).
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Impacts of Policy Sub-option 1(c) (Pulling demand response and distributed resources
into the market)
6.1.4.1.Economic Impacts
The series of measures assumed in this Option include (i) the adaptation of balancing products
closer to what distributed resources like demand response, variable RES and small scale storage
can provide, (ii) the facilitation of the participation of distributed resources in the market mainly
via aggregators and (iii) stronger incentives for the roll-out of smart-meters. These measures
significantly improve the efficiency of the market and the reduce costs.
The market set-up under Option 1(c) provides the opportunity to variable RES E to better
manage their imbalances due to forecast errors at lower cost (due to more competitive prices),
but also to receive additional revenues for any flexibility they can provide to the market.
Similarly, demand is offered the incentives and capability to respond to market prices and thus
complete existing electricity markets. This can be achieved by either shifting load from hours
of peak demand to hours with low demand (e.g. via storage or changing consumption partterns)
or by simply adjusting consumption (when load cannot be shifted or is not really needed) 275
.
Available data coming from a standalone analysis276
performed on the impact of potential
policies promoting downstream price- and incentive-based demand response, at all customer
segments (industrial, commercial, residential), show that demand response can be of great
service, and deliver net benefits to the system as a whole while engaging all consumer segments.
More in particular, it has been demonstrated that demand response schemes can lead to a
reduction of the peak demand and thereby of the required backup capacity in both the
transmission and distribution networks. This also translates into lower investment needs.
The analysis has shown that in a business as usual scenario (reflected in Option 0) demand
response can account for approximately 34 GW, of which 19 GW will come from incentive and
15GW from price based demand response. With a supporting policy framework in place, as in
Option 1(c), demand response can account for approximately 57 GW in 2030, of which 39 GW
will come from incentive and 18 GW from price based demand response.
Allowing small-scale producers, storage and consumers to participate in the market, e.g.,
through aggregated bids, creates incentives for demand side response and flexible solutions,
pulls the above potential in the market and creates a more dynamic market. New flexible
resources are made available for reserve procurement and balancing market. These resources
bring significant short-term and mid-term flexibility277
to the system, contributing to the more
efficient handling of scarcity situations and integrating variable RES E. This abundance of
275
As part of the limitations of the modelling approach, these benefits were not fully assessed because of data
unavailability. Therefore the same load profile was used, based on the ENTSO-E’s TYNDP assumptions,
without being known at which extent it already included some DR (at least for EV charging)
276
See Annex 3.1 and "Impact Assessment support Study on downstream flexibility, demand response and smart
metering", COWI (2016).
277
For more details on the flexibility needs of the system and how storage, interconnections and demand response
can answer such needs please see "METIS Study S7: The role and need of flexibility in 2030. Focus on Energy
Storage", Artelys (2016).
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available resources significantly reduces the cost of the power system and, most importantly,
the load payments to EUR 253 billion, from EUR 278 billion in the baseline and EUR 293
billion in Option 1(a).
These reported savings278
are mainly a result of a significant shift in the provision of reserves
from thermal plants to demand side response (incl. storage) and wind. For example, while in
Option 1(b) (strengthening short-term markets), gas was providing about 20 GW of reserves,
hydro 19 GW and coal 3 GW, under Option 1(c) demand response partly replaces the above
plants by providing 5 GW of reserves. In particular demand response and small scale storage
(electric vehicles and heating storage) become the main providers of upward synchronized
reserves, providing 33% of corresponding needs279
. Wind provides an additional 90 MW of
upwards synchronized reserves and 330 MW of downward synchronized reserves.
6.1.4.2.Who would be affected and how
The new provisions opening up the markets to aggregated loads and demand response will bring
business opportunities for aggregators, new energy service providers, and suppliers who choose
to expand their portfolio of services, but will also affect generators who are likely to face
reduced turnover from lower peak prices and from providing reserves.
Furthermore, demand side flexibility, along with access to real time data coming from smart
metering, will help the network operators optimise their network investments and cost-
effectively manage their systems. In the case of TSOs, it also allows for the better calculation
of settlements and balancing penalties based on real consumption data. On the other hand,
suppliers may face higher imbalances and resulting penalties as their customers change
consumption patterns.
Finally, end consumers are expected to benefit from more competition, access to wider choice,
and the possibility to actively engage in price based and incentive based demand response, and
hence from reduced energy bills. Even those end users who choose not to participate in demand
response schemes could still profit from lower wholesale prices that result from demand
response, assuming that the respective price reductions are passed on to consumers.
Box 6: The possibility of large-scale grid disconnection
Looking forward, our modelling (the EUCO27 scenario) shows a continuation of the general
trend of rising retail electricity prices through to 2030, stabilising from 2035 onwards. Given
the decreasing costs of small-scale renewable generation and storage technologies, concerns
have been raised that this trend could result in a growing number of prosumers becoming self-
278
The proposed measures are expected to also have an impact on the day-ahead market, but as explained in Annex
IV this was not possible to assess due to the lack of sufficient detailed data. Benefits from load shifting or load
reductions were not assessed with METIS due to the lack of a dynamic profile for demand and storage, which
would better capture the reactions of demand to market prices. These impacts were captured though with
PRIMES/IEM, results presented in Section 6.2.6.1. The benefits of demand response and its full potential is
analysed in more detail in Annex 3.
279
The analysis shows the demand response does not provide any downwards balancing at all (by increasing
demand when needed), as this is provided at a much lower cost by RES and conventional generation (by
decreasing generation and saving fuel costs). This result is subject to the limitations of the modelling that does
not use dynamic load profiles for demand and storage. Therefore the relevant benefits are most likely
underestimated in the assessment.
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sustainable and disconnecting from the electricity network – a development that could have
several consequences.
On the one hand, this potential 'flight from the grid' could see the remaining connected
ratepayers bear an increasing share of the burden of contributing to public finances and
financing the electricity network. On the other, grid costs may actually fall as distributed
generation and storage assets enable network operators to more efficiently manage the grid and
connect remote customers.
Predicting the full extent and implications of this trend is difficult given the current
uncertainties, including regarding future cost reductions in small scale renewables and storage
technologies, and the lack of real-world case studies. Nevertheless, our analysis suggests that
this development will be progressive, and that the risks of large scale disconnections are limited
given the difficulties of achieving complete self-sufficiency throughout the year.
In particular, even if decentralised generation and storage becomes competitive, it is
questionable whether self-sufficient prosumers will fully disconnect from the grid.
Disconnecting would imply losing the grid as back-up for when their own generation is
inadequate (e.g. for sustained periods of low sunlight). It would also mean that prosumers
forego the opportunity to sell excess electricity to the market (e.g. during prolonged sunny
periods when their installed storage is at full capacity). This is one of the reasons why the MDI
aims at ensuring full access of prosumers to electricity markets.
It should be added that the discussion of disruptive large scale disconnections is not only
connected with distributed resources but to the perception that consumers are increasingly
confronted with perverse incentives and hidden subsidies. To address this, the initiative includes
measures that should lead to more cost-reflective distribution tariffs i.e. tariffs that allocate the
costs of the grid fairly amongst system users. Cost-reflective tariffs will send the right long-
term economic signals to system users and allow a market-driven move towards a more efficient
electricity system, which will contribute to limiting network tariffs and lead to investments that
are economically rational and efficient.
What is certain is that public authorities and network operators will have to adapt in order to
effectively manage the challenges of any transition towards a more decentralized electricity
system, and make the most of the opportunities this presents. Completely self-sufficient
consumers who do not wish to be connected to the grid should not contribute to the grid costs.
6.1.4.3.Impact on businesses and public authorities
The measures proposed to enable the uptake of demand response are designed to reduce market
barriers for new entrants and provide them with a stable operating framework. This is
particularly important for start-ups and small and medium-sized enterprises ('SMEs') who
typically offer innovative energy services and products. However, these measures may
introduce an additional administrative impact for Member States and their competent
authorities that will be required to clearly define in such a new setting: (i) roles and
responsibilities of aggregators, as well as (ii) arrangements for consumers' entitlement to
participate in price based demand response schemes, including their access to the enabling
smart metering infrastructure. At the same time, access to smart metering will support consumer
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engagement, with better informed and more selective consumers also making it easier for NRAs
to ensure proper functioning of the national (retail) energy markets280
.
Moreover, thanks to the wider deployment of smart metering, the distribution system operators
will be in a position to lighten, and improve, some of their administrative processes (linked to
meter reading, billing, dis/re-connection, switching, identification of system problems,
commercial losses), and offer increased customer services281
. Similarly, transmission system
operators will optimise their settlement and balancing penalty calculations, as they can make
use of real time data coming from smart metering282
.
Impacts of Policy Option 2 (Fully integrated EU market)
6.1.5.1.Economic Impacts
By creating a centralised, fully integrated European market with market design features and
procedures in place in order to deal with grid constraints and increase the available
interconnection capacity offered to the market (e.g. due to the further reduction of security
margins and the implementation of flow based market coupling across time-frames), the
European power system can be operated even more efficiently than in the options above.
Benefits coming from the further improvements in the dimensioning and procurement of
balancing reserves, now on a European level, as well as the better utilization of interconnectors
by the EU Independent System Operator, lead to further reductions of the total costs compared
to Option 1(c) by 1.5%. Reserve needs are further reduced by 30% compared to Option 1(c)
and 63% compared to the baseline, although downwards reserves, which have a low
procurement cost, are mainly procured on a national level, in order to use interconnectors
mainly for exchanging electricity instead of reserving it for potential assistance to/from the
neighbours.
The results indicate that although the economic benefits of moving from a national to a regional
approach (Option 1(b) (strengthening short-term markets)) are significant, the move towards a
more integrated European approach (Option 2) has a less significant economic value-added, as
most of the benefits have already been harvested by moving towards a regional approach. On
the other hand this result is also subject to the limitations of the modelling, not being able to
280
See Annex1(c).1, Stakeholders views; Reference CEER discussion paper "Scoping of flexible response", 3
May 2016
281
“Bringing intelligence to the grids – case studies” (2013) Geode Report;
http://www.geode-eu.org/uploads/REPORT%20CASE%20STUDIES.pdf; also
“Eurelectric policy statement on smart meters” (2010); http://www.eurelectric.org/media/44043/smart-
metering-final-2010-030-0335-01-e.pdf
282
“Towards smarter grids: developing TSO and DSO roles and interactions for the benefit of
consumers” (2015) ENTSO-E;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/150303_ENTSO-
E_Position_Paper_TSO-DSO_interaction.pdf;
“Market design for demand side response” (2015) ENTSO-E Position paper;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr_web.
pdf
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capture the positive impacts from the more efficient operation of the network (since METIS
does not include detailed network modelling).
6.1.5.2.Who would be affected and how
Under this option, TSOs, DSOs, power exchanges, electricity undertakings in general as well
as Member States and competent authorities would be subject to far-reaching organisational
changes (e.g. EU ISO and EU Regulator instead of national TSOs and regulators), and bound
by fully harmonised rules setting out the full integration of the EU electricity market. This
increases the likelihood that these rules may be difficult to implement in specific countries. This
could lead to high resource requirements amongst these stakeholders, public authorities and
Member States, that may be ultimately borne by consumers.
6.1.5.3.Impact on businesses and public authorities
The creation of a fully integrated European electricity market can be considered the most
efficient of all the options and could, in the long run, avoid frictions from coordination and
provide for a high quality electricity system with a high degree of security of supply. Under this
option, it could be argued that in the long run the impact on stakeholders (e.g., TSOs, DSOs,
power exchanges, electricity undertakings, etc.) may be reduced, since the integration of the
electricity market would ensure a high degree of consistency.
However, this option would entail significant changes compared to the current state of the art
of the electricity systems across the EU. It would be necessary to build new entities, processes
and methods without being able to draw upon established practice (e.g., for the establishment
of an EU ISO). Hence, there is a risk that this would lead to disruptions and would require a
significant amount of time to become operational.
This option would also reduce the scope to take into account regional specificities and to draw
upon established regional actors. This option would reduce the scope to develop rules at the
regional level between the parties involved in organising the cross-border trade and system
operation. This is because the key framework as well as the institutional structure would already
be set out at the pan-European level.
In light of the above, it should be noted that the political and administrative effort required
under this option would be considerable.
Environmental impacts of options related to Problem Area I
The measures proposed in this Problem Area aim to improve the cost-efficiency and the
flexibility of the power system. By doing so, climate-friendly variable RES E can be better
integrated in the market; resources are used more efficiently, and unnecessary fuel-based
generation (e.g. backup generation needed because of missing rules for cross-border short-term
markets) can be avoided by better using the aggregation potential of the internal market. Using
the full potential of demand response has also a positive effect on the environment. If
consumption can be shifted more easily to off-peak times, less backup generation from fuel-
based plants is needed.
On the other hand, the removal of privileged rules for certain production forms may lead to a
shift from some RES E production (i.e. biomass) to other generation types which will not only
be wind and solar, but also fossil fuel-based. Therefore, although direct CO2 emissions from
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the power sector decrease while moving from Option 1(a) to Option 1(c), from 615 Mt CO2 to
600 Mt C02, METIS results show an increase when moving from the baseline to Option 1(a) by
60 Mt CO2. The analysis of the impact on emissions is, however, complex283
.
The removal of priority dispatch from biomass (as well as from any other resource, including
must-run generation) is pivotal in restoring the economic merit order in the power markets and
significantly increasing their economic efficiency. Such a measure would discontinue the use
of expensive biomass as baseload generation, replacing it by the marginal technologies (mainly
coal and gas). Expensive biomass would then mainly be used in the power sector as a flexible
generation technology, as well as for providing reserves.
The replacement of biomass by gas and coal could lead in the short-term to increasing
emissions. The environmental impacts of the market design measures cannot though be
examined in isolation from all other complementary energy and climate policies. At the EU
level, the reduction in greenhouse gas emissions within the sectors covered by the EU ETS is
guaranteed by the declining cap which in turn ensures that the emissions reductions objective
is met cost-effectively. In the event of an increase in emissions from certain changes in the
power sector mix, the corresponding increase in demand for allowances would raise the carbon
price leading to an increase in abatement through other means, whether this is through a fuel
switch in power generation elsewhere or an emissions reduction in other ETS sectors. Due to
the binding limit on overall emissions a reduction in the use of biomass would therefore
eventually result in the same amount of GHG emissions over time, with a different fuel mix at
a lower total system cost.
The main effects of removing priority dispatch for biomass are therefore:
- only cheaper fractions of biomass are being used (such as waste streams), while the
more expensive one is being used as flexible dispatchable generation, rather than
subsidised baseload;
- overall higher CO2 prices and lower generation costs, and higher wholesale electricity
prices (but most likely lower retail prices, as no subsidies will need to be recuperated
outside the wholesale market).
- more favourable conditions for gas, with more operating hours;
The possible increase in emissions in the power sector is in reality the effect of current energy
policies for RES E (and specifically the incentives given by the subsidization of biomass) and
not of electricity market related policies. By removing the distortions currently present in the
electricity markets, the market is able to give clearer signals on the interactions between climate
and energy policies and help identify the right balance between cost and resource efficiency
and emissions reduction.
Summary of modelling results for Problem Area I
The analysis shows that although today electricity markets function much better than in the
past, there are still significant gains to be harvested. Restoring the merit order and creating a
283
It should be noted that the analysis excludes the effect that increased generation by thermal plants would have
on the carbon market and how this in turn would indirectly impact electricity generation.
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level-playing field for all technologies can reduce the operational cost284
from EUR 83.4 billion
in Option 0 to EUR 77.5 billion in Option 1(a). Another EUR 2.7 billion can be saved by further
strengthening and linking the short-term markets; EUR 0.9 billion by better integrating demand
response and RES E into the market; and EUR 1.1 billion from fully integrating EU markets.
Overall, the measures under Option 1(c) can lead to cost reductions up to 11.4% compared to
the baseline, while the additional measures under Option 2 would raise this to 12.7%.
When considering the above results, three important points need to be made. First of all the cost
saving estimates for each option are directly related to the volume of traded energy (and
reserves) they concern. Option 1(a) (level playing field) affects all market frames, but most
notably the day-ahead, where the largest volume of trades takes place. Options 1(b)
(strengthening short-term markets) and Option 2 (fully integrated markets) focus on
interconnections (for all market time frames), intraday and balancing; traded volumes there are
only a fraction of the ones of the day-ahead. Option 1(c) (demand response/distributed
resources) concerns mainly the balancing and reserve markets285
. Secondly, the effect of the
measures on the intraday and balancing traded volumes is much greater, but more difficult to
quantify, as it is bi-directional (upwards and downwards compared to the day-ahead scheduled
energy) and complementary to the day ahead market286
. Finally the proposed blocks of
measures were deemed as the most efficient ones, but also were found to have limited impact
on the reported results287
.
Apart from the cost savings, which relate only to the generation side costs, it is important to
also examine the final cost of the wholesale market for the consumers, referred to below as
'Load Payments' (see Glossary). With the removal of all special rules affecting dispatch, the
wholesale price begins reflecting the actual marginal value of electricity and thus increases; this
affects also the Load Payments which increase by 5%. Subsequent Options though bring more
resources into the market, better utilizing the interconnections and further improving the cost-
efficiency of the market, gradually reducing the Load payments by 6% in Option 1(b)
(strengthening short-term markets), 9% for Option 1(c) (demand response/distributed
resources) and 11.5% for Option 2 (fully integrated market) compared to the baseline. The
above are equivalent to a reduction of the wholesale market cost for the consumer288
from 78
EUR/MWh in the baseline to 71 EUR/MWh for Option 1(c) and 70 EUR/MWh for Option 2.
284
Cost reflects the operational cost of the electricity system (reflecting mainly fuel cost and CO2 cost). Lower
cost implies a more efficient operation of the system.
285
The proposed measures are expected to also have an impact on the day-ahead market, but this was not possible
to assess due to the lack of sufficient detailed data. See also footnote 278.
286
There are two important connections with the day-ahead market. The closer the day-ahead schedule matches
the optimal dispatch (based on realized demand and generation), the smaller the need to act in the shorter term
markets; and how interconnection is split between day-ahead and intraday. For this reason it is preferable to
look at the results as a whole and not separately for each market frame.
287
A sensitivity performed with METIS introducing the Option 1(c) measures (demand response/distributed
resources) before Option 1(b) (strengthening short-term markets) shows a marginal improvement of Option
1(c) benefits by EUR 0.3 billion, despite the much higher potential for improvement still available in the
market in the context of this Option.
288
If these costs were shared equally among consumers.
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Table 10: Monetary Impacts (in billion EUR) of the assessed Options (for EU28+NO+CH
in 2030)
Monetary Impacts (billion EUR)289
Option 0
Option
1(a)
Option
1(b)
Option
1(c)
Option 2
Baseline
Level
playing
field
Strengtheni
ng short-
term
markets
Demand
response/
distributed
resources
Fully integrated markets
Cost day-ahead 82.5 76.9 73.5 72.7 72.4
Cost intraday 1.4 0.9 1.2 1.1 0.3
Cost balancing -0.5 -0.3 0.1 0.1 0.1
upwards 0.7 0.5 0.7 0.7 0.7
downwards -1.2 -0.8 -0.6 -0.6 -0.6
Total cost 83.4 77.5 74.8 73.9 72.8
Cost savings - 5.9 8.6 9.5 10.6
Load Payments
day-ahead
278 293 262 253 246
Load Payment
Savings
- -15 16 25 32
Source: METIS
The monetary impacts described in Table 10 are very closely linked to the impacts of the
measures on the wholesale prices. In Option 1(a) (level playing field) the increase of the
competitive segment of the market from 40% (due to priority dispatch and must-runs) to 100%
is the main driver for a more cost-efficient operation of the system, with no negative prices
observed in the performed model runs, leading in the end to higher day-ahead prices. In parallel
the reserve prices are generally lowered, due to the reduction of the inflexibility in the system.
Only mFRR upwards prices increase, as these services are now primarily offered by peaking
units.
In Options 1(b) (strengthening short-term markets) the trends reverse, as more resources enter
the market, thus lowering day-ahead prices. The better utilized interconnection capacity and the
improved functioning of the reserve markets allows baseload plants to produce more electricity
in the day-ahead, while the more flexible (and expensive) plants become the main providers of
reserves. As a consequence, balancing prices tend to increase (together with intraday prices).
Subsequently, the introduction of demand response and the provision of reserves by RES E in
Option 1(c) (pulling demand response and distributed resourced into the market) further lower
wholesale prices (as more resources enter the market), with the exception of downwards reserve
prices which increase290
. Finally the impacts of Option 2 (fully integrated markets) are similar
to the ones of Option 1(b) (strengthening short-term markets).
289
Unless otherwise noted, figures in all tables represent annual numbers for 2030. The geographical context is
always noted in the title of each graph and in some cases it also covers NO and possibly CH because of the
market coupling of EU Member States with these countries.
290
Downwards balancing activation is a benefit (fuel savings) for the system, while there is no gain (in METIS)
to increase demand.
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Table 11: Impacts (EUR/MWh) to Average Annual Wholesale Prices (for EU28 in 2030)
Average Wholesale Prices (EUR/MWh)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/
distributed
resources
Fully
integrated
markets
Day-ahead Market
Price291 78.4 82.5 73.9 71.3 69.6
Balancing Price -
aFRR upwards
71.9 58.3 76.2 71.3 72.3
Balancing Price -
aFRR downwards
52.8 52.5 54.4 59.8 60.6
Balancing Price -
mFRR upwards
72.1 82.3 85.6 76.3 76.3
Balancing Price -
mFRR downwards
70.1 65.2 64.7 58.4 58.3
Source: METIS
An interesting aspect to examine is the distributional impact of the various options on the
generator surplus (i.e. revenues above cost) and consumer surplus (i.e. cost below VoLL). It is
important to note that this should not be interpreted as an investment or "missing money"
analysis, since the modelling used here is static (based on the same set of capacities across the
options). The issue of investments is analysed in Section 6.2.6.3, using a dynamic investment
model (PRIMES/OM).
With the day-ahead prices significantly affected by the measures, so does generator surplus (i.e.
revenues above cost). The distributional impacts on the market players though are concentrated
on thermal generators, with competitive RES E generators even increasing their day-ahead
revenues (not considering the additional revenues from the other markets).
Although in the baseline thermal generation seems to be making reasonable revenues, sufficient
in many cases to cover fixed costs – especially for gas units – the improvements in the market
design introduced in Options 1(b) (strengthening short-term markets), 1(c) (demand
response/distributed resources) and 2 (fully integrated markets) lead to a significant decrease
of their revenues, turning their operation to loss-making. Note, this result is a large extent due
to the static modelling approach followed here and the increased competition in the market, as
a result of bringing more resources into it and better utilising interconnections (thus better
sharing national resources across EU). With the power generation capacities remaining constant
across Options, this leads to a market with increasing resources participating (to the point of
oversupply) and more intense competition, thus shrinking revenues.
291
EU weighted average price on Member States' demand
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Table 12: Generator Surplus292 (in EUR/kW) for different plant categories (for EU28 in
2030)
Generator Surplus (EUR/kW)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/
distributed
resources
Fully
integrated
markets
Solids 394 393 146 124 108
OCGT 112 102 34 19 9
CCGT 191 178 39 29 22
Nuclear 451 490 435 418 413
Hydro 204 215 200 194 190
Solar 65 73 74 74 75
Wind onshore 117 133 137 137 137
Wind offshore 176 204 211 213 213
Source: METIS
Similarly, the introduced measures have certain consequences on the generation production,
although these tend to be relatively limited. Summarizing what has already been discussed in
the dedicated assessment of each option, and presented in Table 13:
- The main impact on the electricity generation patterns appears in Option 1(a), when
dispatch begins reflecting the economic merit order. Most notably, biomass generation
is replaced mainly by gas and coal generation.
- Otherwise, generation patterns remain relatively stable across Options, except for some
shifting of gas generation to nuclear in Option 1(b) (strengthening short-term markets).
This comes as a result of the more efficient interconnection allocation and procurement
of reserves, which leads to the utilisation of nuclear and lignite plants mainly for
producing energy, while the more expensive gas plants are used more for reserves and
balancing.
- RES E curtailment and activation of replacement reserves is steadily reduced across all
options, as all measures introduce more and more flexibility to the system. In fact
replacement reserves are no longer needed in Option 2.
- Procurement of Balancing Reserves also decreases substantially, from 79.6 GW in the
baseline to only 29.6 GW in Option 2. The gradual drop in the required reserves is an
outcome of the specific measures assumed in each case and explained in more detail in
the assessment of the respective options.
292
Reported surplus concerns day-ahead and reserve market revenues. Some additional revenues (but minor in
comparison) should be expected from the intraday and balancing markets (but were difficult to identify and
report).
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Table 13: System Operation Results (for EU28+NO+CH in 2030)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/
distributed
resources
Fully integrated
markets
Net Electricity Generation (TWh)
Total 3618 3606 3599 3588 3586
Biomass & Waste 236 78 73 72 71
Hydro293
632 623 618 609 607
Wind 722 726 728 729 729
Solar 303 303 303 303 303
Lignite 269 274 278 279 280
Nuclear 755 775 800 803 804
Coal 237 272 274 268 266
Gas 455 545 515 516 515
Others 10 10 10 10 10
RES Curtailment
(GWh)
13.0 8.3 6.0 5.0 4.6
Balancing Procurement (GW)
Reserve
Dimensioning
79.6 65.8 42.3 42.3 29.6
of which FCR 12.4 12.4 12.4 12.4 12.4
of which aFRR 20.5 20.4 10.1 10.1 6.0
of which mFRR 46.6 33.1 19.8 19.8 11.1
Reserves via
interconnections294 - - 12.2 11.7 18.7
Replacement
Reserves
Activation295
(GWh)
600 100 80 60 0
Source: METIS
In terms of distributional impacts across the EU regions, results are strongly related to the
respective generation mix of each region, as well as to how well interconnected each region is
to the others. For the regions with significant biomass generation (e.g. region 3), there are
significant cost savings when moving from the baseline to Option 1(a) (level playing field).
293
Hydro includes pumped hydro storage whose utilisation decreases from Option 0 to Option 2.
294
The reserves via interconnections are computed as the difference between the reserves needed to face the
national risks and the procured reserves.
295
Activated for avoidance of Loss of Load
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Similarly, the benefits of Option 1(b) (strengthening short-term markets) and Option 2 (fully
integrated markets) are more significant for the Member States that are better interconnected
(Regions 1 and 2). Option 1(c) (demand response and distributed resources) reduces costs for
all regions, except for Region 5, as the competition with additional reserve resource decreases
the cost for reserve procurement. Similar observations apply for the load payments and the
wholesale prices. It is also worth noting how wholesale prices tend to converge as markets
become more harmonised and better functioning, with the exception of Region 4 (Spain &
Portugal), which has a limited interconnection to the rest of EU only via France.
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Table 14: Distributional Impacts – regional perspective296(for EU28 in 2030)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/distributed
resources
Fully
integrated
markets
Total cost – Day Ahead Market (billion EUR)
Region 1 42.1 40.3 39.4 38.9 38.6
Region 2 6.9 5.5 4.8 4.5 4.4
Region 3 13.3 10.7 9.6 9.4 9.3
Region 4 5.5 5.3 5.0 4.9 5.0
Region 5 14.3 14.9 14.6 14.9 14.9
Total Load Payments – Day-Ahead Market (billion EUR)
Region 1 157 161 138 131 126
Region 2 36 40 34 32 30
Region 3 26 31 30 30 30
Region 4 17 18 19 19 19
Region 5 37 37 36 36 37
Average Day-Ahead Market Price (EUR/MWh)
Region 1 88.1 90.6 77.3 73.3 70.6
Region 2 87.6 97.2 81.6 78.0 73.6
Region 3 63.3 75.5 73.8 73.0 73.0
Region 4 49.6 53.2 55.2 54.6 55.5
Region 5 70.9 71.8 70.6 70.6 70.8
Source: METIS
296
Regions as indicated in footnote 244.
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6.2. Impact Assessment for Problem Area II (Uncertainty about future generation
investments and fragmented capacity mechanisms)
Methodological Approach
6.2.1.1.Impacts Assessed
Similarly to Problem Area I, the assessment focused on the economic impacts of the examined
options. The emphasis though is not on the operation of the power system and the integration
of RES E, but on whether the market revenues can incentivize the necessary investments and –
most importantly – on the relevant cost for the consumer. Inefficiencies resulting from
fragmented approaches to CMs are also considered.
The impacts of the options to the environment and the society, excluding their economic
aspects, are directly linked with the changes in the generation capacities of each option. Other
significant, direct or indirect, impacts for the examined options were not identified.
The assessment is presented individually for each option, with qualitative analysis and
references to quantitative results. The detailed modelling results for the various options, along
with their interpretation, are presented in section 6.2.6.
6.2.1.2.Modelling
The modelling for this part was performed using PRIMES/OM, a specific version of the
PRIMES model that can assume different types of competition in the electricity market, as well
as model how CMs affect the investment decisions of the market participants. PRIMES/OM
was selected over METIS for this part of the analysis, because it can model in detail the
investment decisions of the market participants over an extended time-period, namely until
2050, while at the same time being able to capture the effect of different bidding behaviours
from the side of the market participants (necessary to assess the impact of scarcity pricing).
In addition, PRIMES/IEM (a day-ahead and unit commitment simulator developed by NTUA)
was used to assess in more detail the benefits of the energy-only market. Contrary to METIS297
,
PRIMES/IEM places more emphasis on accurately simulating the market behaviour of
generators by assuming specific bidding strategies followed by the market participants and
departing from the usual marginal cost assumption298
. Moreover, PRIMES/IEM was able to
capture the effect of introducing locational price signals, as it includes a network model. Further
297
Due to the differences in the two modelling approaches and underpinning assumptions of METIS and
PRIMES/IEM, a direct comparison of the two sets of modelling results could be misleading.
298
The marginal cost assumption is perhaps the most usual assumption in the dispatch type of models, as it helps
focus more on the effect of market design measures and departs from competition or behavioural issues.
However, one cannot capture well the effect of measures like scarcity pricing under the marginal cost bidding
assumptions, as the prices would fluctuate between the marginal cost of the most expensive running plant and
VoLL (or price cap), which is not what is observed in practice in the market.
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details on both models and the methodological approach followed can be found in Annex IV,
as well as in the relevant NTUA report299
.
The above tools were complemented by a study performed using METIS, analysing the revenue
related (weather-driven) risks faced by conventional generation and how these could be
mitigated, while also identifying the value of co-ordinated solutions300
.
6.2.1.3.Overview of Baseline (Current Market Arrangements)
The baseline reflects the current market arrangements of Problem Area I, similar to what is
described in section 6.1.1.4. In addition it is assumed that Member States put in place price
caps, as well as that there may be systemic congestion in the transmission grid.
Comparing the baselines of Problem Areas I and II in modelling terms, certain differences exist
in terms of figures and assumptions, mainly reflecting the differences in the respective
modelling approaches301
intended to better capture the options assessed in each Problem Area,
as well as their calibration to a different version of EUCO27302
. Under this baseline:
- Price caps apply as today303
;
- Units bid according to bidding functions by plant category304
and not marginal costs;
- The unit commitment simulator applies a flow-based allocation of interconnections;
- Modelling includes more detailed information on generation capacities, including
vintages, technology types and technical characteristics of plants;
- The day-ahead market covers only part of the load, as is the case today. A large part
of the energy (especially produced by inflexible units) is nominated.
- The baseline of this Problem Area fully reflects EUCO27.
Nevertheless, both models identify similar trends concerning the operation and the revenues of
the various generation types, as already presented in Problem Area I.
299
"Methodology and results of modelling the EU electricity market using the PRIMES/IEM and PRIMES/OM
models", NTUA (2016)
300
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it", Artelys
(2016)
301
Further details can be found in Annex IV.
302
METIS had to be calibrated to PRIMES much earlier than PRIMES/IEM. Therefore, a preliminary version of
EUCO27 was used as the basis for the calibration. The main differences of the two versions concerning the
power sector can be found in Annex IV.
303
For more details please see: "Electricity Market Functioning: Current Distortions, and How to Model Their
Removal", COWI (2016).
304
The basis is the marginal fuel cost of the plant, increased by a mark-up defined hourly as a function of scarcity,
calculated for each market segment in which the respective plant category usually operates (e.g. peak, mid-
merit, baseload). Further details can be found in Annex IV.
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Impacts of Policy Option 1 (Improved energy markets - no CMs )
6.2.2.1.Economic Impacts
Option 1 assumes that Member States can no longer put in place CMs. The analysis is hence
solely based on a strengthened energy-only market.
With sufficient economic certainty, investments should in principle be able to take place based
on the electricity price signal alone, provided that the price signal is not significantly distorted.
Further, the electricity price, and its behaviour, should stimulate not only investment in
sufficient capacity when needed (be it production or demand), but also in the right type of
capacity. A steady electricity price, one that does not vary significant on an hour-to-hour basis,
should steer investment to the types of capacity that can operate steadily at lowest production
cost. A rapidly fluctuating electricity price should steer investment to capacity that can ramp-
up and ramp-down very quickly and can take advantage of high prices at short notice and avoid
operation when prices are too low. The shift to variable generation will increasingly require
fast-ramping and highly flexible generation and cause the market exit of less flexible types of
generation capacity. Investment uncertainty and varying prices are not a unique feature to the
electricity industry305
.
In this way, the effect of variable renewables, insofar as their deployment will increase the
variability of the electricity price, should stimulate investment in the flexible capacity needed
to keep the system in balance at all times. Ensuring that prices can reflect market fundamentals
is key to this and removing as many potential distortions on electricity prices is critical to
enabling it to play this function.
Indeed, the analysis performed with PRIMES/OM supports the arguments above, showing that
an energy-only market can in general deliver cost-efficiently the necessary investments in
thermal capacity (especially flexible one). The enhanced market design will also improve the
viability of RES E investments, but electricity market revenues alone might not prove sufficient
in attracting investments in RES E in a timely manner and at the required scale to meet EU's
2030 targets. (See in this regard also the box on RES E investments in Section 6.2.6.3).
Moreover, PRIMES/IEM results show that undistorted, energy-only markets can significantly
decrease load payments by around EUR 50 billion306
in 2030. The largest part of these savings
is attributable to the improvements in the short-term markets and the participation of demand
response in the market, representing EUR 20 billion and EUR 26 billion savings respectively
in 2030. The implementation of measures introducing a level playing for all technologies and
removing price caps brings EUR 5 billion savings in 2030 and at the same significant more
cost-efficiency to the system, as explained in Section 6.1.2.1.
305
See in this respect e.g. the report by Frontier Economic on "Scenarios for the Dutch electricity supply system",
p. 134. https://www.rijksoverheid.nl/documenten/rapporten/2016/01/18/frontier-economics-2015-scenarios-
for-the-dutch-electricity-supply-system
306
The benefits become almost double compared to Option 1(c) as assessed with METIS, due to the additional
distortions included in the baseline and measures to address them, on top of the expected differences due to
the different modelling approach. The two figures give a satisfactory range on the possible benefits for Europe
from an improved energy only market design.
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As resources are better utilised across the borders compared to the baseline, and demand can
better participate in markets, undistorted energy-only markets are able to improve the overall
cost-efficiency of the power sector significantly. Equally, it can ensure resource adequacy (See
in the regard also Section 6.2.6.3).
It thus follows that by improving the energy markets, the need of government intervention to
support investments in electricity resources is reduced
6.2.2.2.Who would be affected and how
As this option encompasses to the largest extent the options discussed under Problem Area 1,
the assessment made there as to who would be affected and how applies here as well.
With regard to more variable pricing, they will benefit owners of flexible resources, such as
flexible generation capacity, storage and demand response, and incentivise them to come to
or stay in the market. In this end, they will provide the motor for more innovative services and
assets to be deployed.
End consumers will be affected insofar as changes to the wholesale price are passed on to them
in their retail price. However, more variable prices will not necessarily be felt by end-consumers
as they can be hedged (particularly households) against this volatility in their retail contracts or
through wholesale market arrangements. In fact, more variable pricing will incentivise the
development of more sophisticated energy wholesale market products allowing price and
volume risks to be hedged more effectively. Power exchanges would be impacted by removal
of price caps as they will be required to introduce changes to systems and practices.
Minimising investments and dispatch distortions due to transmission tariff structures would
mostly affect generators. Positive impacts on their revenues would be expected due to lower
connection charges or tarrifs.
TSOs will be affected by improvements in locational price signals as it would likely mean that
they hold and operate networks over more than one price zone. To a lesser extent this applies
to power exchanges as these are often already operating in different price zones today.
Spending of the congestion income to increase cross-border capacity may have impact on end
consumers, where the congestion income is used for the reduction of tariffs. But this should be
outweighed by the positive effect of more cross-border capacity being available, and the benefit
this has on competition and energy prices.
6.2.2.3.Administrative impact on businesses and public authorities
As this option encompasses to the largest extent the options discussed under Problem Area I,
the assessment made there as regards administrative impacts made there also applies here307
.
Overall, the administrative impact on businesses and public authorities should be limited as,
even if the measures associated with Option 1 (in addition to those assessed under Problem
307
For the impact of the additional measures (removing price caps, introduction of locational price signals, etc.),
a detailed analysis is also presented in Annexes 4.1 to 4.4.
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Area I) require changes, they are not fundamentally different from the tasks performed already
under the baseline scenario.
More variable pricing will incite the development of more sophisticated energy wholesale
market products allowing price and volume risks to be hedged more effectively. This should
help reduce lower overall risks to businesses.
Impacts of Policy Option 2 (Improved energy markets – CMs only when needed, based
on a common EU-wide adequacy assessment)
6.2.3.1.Economic Impacts
This option builds on a strengthened energy market (Option 1). Indeed, as developed in Section
2.2.1, undistorted energy price signals are fundamental irrespective of whether generators are
solely relying on energy market income or also receive capacity payments. Therefore, the
measures aimed at removing distortions from energy-only markets are 'no-regrets' and assumed
as being integral parts of Options 2 and 3.
In addition, the option assumes the presence of CMs but only in those Member States for which
a resource adequacy assessment performed at European level has demonstrated a resource
adequacy problem. As no restrictions are placed on these CMs, it is assumed they foresee
implicit cross-border participation (i.e. only taking into account imports and exports in the
dimensioning of the CM, without any remuneration of foreign capacity).
In order to highlight the importance of considering the regional aspects in a generation adequacy
assessment, Artelys performed an independent study308
assessing the capacity savings that can
be obtained from a European approach in capacity dimensioning for resource adequacy in
comparison to a resource adequacy assessment conducted at Member State level.
The mode used jointly optimises peak capacities given security of supply criteria309
for two
reference cases – without cooperation (capacities are optimised for each country individually,
as if countries could not benefit from the capacities of their neighbours) vs. with cooperation
(capacities are optimised jointly for all countries, taking into account interconnection capacities
(i.e. NTCs). The difference in installed capacity between the two cases reveals the savings could
be made from cooperation in investments.
Results show that almost 80 GW of capacity savings across the EU can be achieved with
cooperation in investments. This represents a gain of EUR 4.8 billion per year of investments310
when comparing the two extremes. A reason for these savings is that Member States have
different needs in terms of capacity with peak demands that are not necessarily simultaneous.
Therefore, they can benefit from cooperation in the production dispatch and in investments. It
should be noted that this figure does not assess at which stage Member States are currently (i.e.
308
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it", Artelys
(2016). The results of this study are spelled-out in more detail in Annex 2.2.
309
A value of 15k€/MWh for loss of load is used and system adequacy is assessed on 50 years of hourly weather
data. For more details on the characteristics of capacity dimensioning, see Annex 2.2.
310
The 80 GW of capacity savings are a result of optimal investment decisions on EU level, based on an EU
approach vs a national approach. Efficient market functioning can also provide efficient investment signals
leading to more efficient investments. See section 6.2.6.3.
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whether some Member States already benefit from the capacities of their neighbours), as the
benefits have already been reaped by some. It should also be noted that this figure does not
include savings on production dispatch, which could lead to much higher monetary benefits.
PRIMES/OM was used to assess the impact of introducing CMs on a certain number of
countries, with the CMs foreseeing implicit cross-border participation. The runs assumed that
four countries were justified based on a EU-wide adequacy assessment, to have a CM: UK,
Italy, Ireland and France. This assumption was based on a selection of countries from the Sector
Inquiry on Capacity Mechanisms (as the model always ensures that the expected security of
supply levels are always met).
The analysis shows that the introduction of CMs lowers wholesale prices, but to a limited
degree, primarily in the MS introducing CMs, but also to all EU countries due to the assumed
well-functioning markets. On the other hand this does not translate to reduced Load Payments
for the consumers on a EU level, as the CM related costs slightly exceed the reductions in the
cost of the wholesale energy market in 2030. This difference though becomes quite significant
in the longer term, making Option 1 cheaper than Option 2 by an average of EUR 4
billion/annum when comparing over the period 2021-2050. Interestingly enough, the
consumers of the Member States introducing CMs face a EUR 7 billion increase in costs in
2030, while the cost for all other EU Member States drop by a similar amount.
6.2.3.2. Who would be affected and how
EU-wide resource adequacy assessments would benefit consumers through maintaining high
standards of security of supply while lowering costs through reduced risk of over procurement
of local assets as foreign contribution to national demand and demand side flexibility would be
sufficiently taken into account.
ENTSO-E would be required to carry out an EU-wide resource adequacy assessment based on
national raw data provided by TSOs (as opposed to a compilation of national assessments).
ENTSO-E would also have to provide an updated methodology with probabilistic calculations,
appropriate coverage of interdependencies, availability of RES E and demand side flexibility
and availability of cross-border infrastructure. NRAs/ ACER would be required to approve the
methodology used by ENTSO-E for the resource adequacy methodology and potentially
endorse the assessment. TSOs would be obliged to provide national raw data to ENTSO-E
which will be used in the EU-wide resource adequacy assessment.
Member States would be better informed about the likely development of security of supply
and would have to exclusively rely on the EU-wide resource adequacy assessment carried out
by ENTSO-E when arguing for CMs.
With the updated methodology provided by ENTSO-E, intermittent RES generators/ demand-
side flexibility would be less likely to be excluded from contributing to resource adequacy.
6.2.3.3.Impact on businesses and public authorities
The main burden would be for ENTSO-E having to provide for a single 'upgraded' methodology
and to carry out the assessment for all EU countries. Important to note is that ENTSO-E has
already been carrying out an EU-level resource adequacy assessment based on Union
legislation. However, the methodology used has to be upgraded which would require increased
manpower. Nonetheless, the administrative costs of this 'updated' assessment are expected to
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be marginal compared to the economic benefits that would be reaped. It is estimated that these
these costs311
would range from EUR 4-6 million per year (representing mainly personnel and
IT costs).
Impacts of Policy Option 3 (Improved energy market – CMs only when needed, plus
cross-border participation)
6.2.4.1.Economic Impacts
This option builds on Option 2, i.e. a strengthened energy market and CMs only in Member
States where justified by a European adequacy assessment. In addition, this option provides an
EU framework for explicit cross-border participation in CMs.
Explicit cross-border participation lowers overall system costs compared to implicit
participation, as it corrects investment signals and enables a choice between local generation
and alternatives. As more capacity will be participating in the CM, than in the implicit
participation case, competition will be more intense and thus CM payments lower. In addition,
the enhanced competition will extend also to the wholesale market, thus leading to lower market
clearing prices.
Based on the same setup as in Option 2 (Improved energy market – CMs only when needed,
based on EU resource adequacy assessment) only now with explicit cross-border participation
(i.e. remunerating foreign resources for their services) instead of only implicit (i.e. only taking
into account imports and exports in the dimensioning of the CM, without any remuneration of
foreign capacity), PRIMES/OM estimates that explicit cross-border participation would result
in significant savings. Results show that explicit participation brings savings of EUR 2 billion
(in 2030) compared to implicit participation, with savings significantly increasing in the long
run to more than EUR 100 billion over the whole projectin period of 2021-2050 (i.e. about EUR
3.5 billion per annum). The main reason is enhancement of competition in the CM auction and
the resulting lower auction prices.
By remunerating foreign resources for their services, this option is likely to better ensure that
the investment distortions of uncoordinated national mechanisms present in Option 2 are
corrected and that the internal market able to deliver the benefits to consumers.
6.2.4.2.Who would be affected and how
A positive impact of cross-border capacity mechanism would be expected on the foreign
capacity providers, generators, interconnectors and aggregators. They would receive the
possibility to participate directly in a national capacity auction, with availability obligations
imposed on the foreign capacity providers and the interconnecting cross-border infrastructure.
Foreign capacity providers/ interconnectors would be remunerated for the security of supply
benefits that they deliver to the CM zone and but would also receive penalties in case of non-
availability.
311
The economic costs linked to resource adequacy assessments are based on own estimations, resulting from
discussions with stakeholders and experts. For more details, see Annex 5.1.
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NRAs/ACER would be required to set the obligations and penalties for non-availability for
both participating generation/demand resources and cross-border transmission infrastructure.
ENTSO-E would be required to establish an appropriate methodology for calculating suitable
capacity values up to which cross-border participation would be possible. Based on the ENTSO-
E methodology, TSOs would be required to calculate the capacity values for each of their
borders. They might potentially be penalized for non-availability of transmission infrastructure.
TSOs would also be required to check effective availability of participating resources.
6.2.4.3.Impact on businesses and public authorities
Providing an EU framework with roles and responsibilities of the involved parties would enable
explicit cross-border participation (as already required by the EEAG). Although the cost of
designing cross-border participation in CM depends to some extent on the design of the CMs,
an expert study312
estimated that such cost corresponds roughly to 10% of the overall cost of
the design of a CM313
. In addition, they estimate costs associated with the operation of a cross-
border scheme i.e. additional costs if cross-border participation is facilitated to amount to 6-30
FTEs314
for TSOs and regulators combined. Providing for an EU framework would remove the
need for each Member State to design a separate solution and potentially reduce the need for
bilateral negotiations between TSOs and NRAs, reducing the overall impact on these
authorities. According to the same study, TSOs and NRAs bear the main costs related to cross-
border participation as they have to check eligibility and ensure compliance. The study
estimates cost savings of 30% on these eligibility and compliance costs compared to the
baseline. It would also reduce complexity and the administrative impact for businesses
operating in more than one zone.
Environmental impacts of options related to Problem Area II
The impacts of these measures to the environment are very limited, as they mainly influence
the generating capacity but not so much the operation of the units, which is the source of
emissions. The actual emissions depend on the merit order and the relation of the marginal cost
of coal in comparison to the marginal cost of gas. This in turn depends on the CO2 price and
the relation of coal versus gas price, and not on whether there is a CM in place or not.
Overview of modelling results for Problem Area II
6.2.6.1.Improved Energy Market as a no-regret option
Several facts speak in favour of market design which relies on an improved energy market as
the driver for investment and operation. As already described in the assessment of Problem
Area I, the improvements in the wholesale market described under Option 1 of Problem Area I
(level playing field, strengthening short-term markets, pulling demand response and distributed
resources into the market) are expected to bring significant benefits and reduce the need to
correct market failures with capacity markets. These benefits are further enhanced when
considering the additional measures considered in this Option (e.g. removal of price caps, a
312
Thema (2016), Framework for cross-border participation in capacity mechanisms (First interim report)
313
The same expert study also found that the overall cost of of the design are fairly small compared to the overall
cost of the CM (remuneration of the participation ressources).
314
FTEs in other phases refer to (annually) recurring costs.
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process which leads to the introduction of locational price signals reflecting systematic
congestion, limiting curtailments of interconnector capacity).
The benefits of further improving the market in this way, assessed this time using the
PRIMES/IEM model, are presented in Table 15 below. The level of the reported figures in
Table 15 are higher compared to Table 10 due to the inclusion of more distortions in the baseline
of PRIMES/IEM, as well as the use of scarcity bidding, instead of marginal cost bidding in
METIS315
.
Table 15: Cost of supply in the wholesale market in the year 2030316
Load Payments (billion EUR)
Day-
ahead
Market
Intra Day
Market
Reserves
and
balancing
Total
Current Market Arrangements
(in context of low price caps, systematic
congestion)
326.2 22.1 7.7 356.0
Level playing field + removal of low
price caps
327.5 17.1 6.8 351.4
Strengthening short-term markets +
removal of low price caps, locational
price signals
317.6 11.6 1.9 331.2
Demand response / distributed resources
into the market + removal of low price
caps, locational price signals, demand
response in day-ahead
300.4 4.0 1.0 305.4
Source: NTUA modelling (PRIMES/IEM)
Overall, despite differences in the modelling approaches, results of PRIMES/IEM are fairly
consistent with METIS results used to access the options from Problem Area I, especially
concerning the ranking of the respective options. The results indicate that the "improved energy
market" Option could significantly decrease wholesale supply costs by around EUR 50 billion
in the year 2030. As a consequence, the unit cost of generation paid by the consumers would
315
At the same time the assumption that CHP, small scale RES E and biomass retain (implicitly in some cases)
priority dispatch in PRIMES/IEM in the first three examined cases – but not for small scale RES in the last
one -, implies lower percentage changes when moving between the first three options, due to the smaller
generation affected by the measures, but at the same time a more significant one for the last option. More
details on the exact assumptions can be found in Annex IV.
316
The rows correspond to the respective options of problem area I (except Option 2). In addition though Option
1(a) (level playing field) is complemented by the removal of price caps; Option 1(b) (strengthening short-term
markets) is complemented by the introduction of locational price signals; and Option 1(c) with demand
response participating also in the day-ahead market (which could not be captured by METIS, as it captured
demand response in the intraday and balancing markets only). The last row reports the aggregate costs of
Option 1 of Problem Area II.
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drop from 102.9 EUR/MWh to 94.7 EUR/MWh, the largest part of which is attributable to the
participation of demand response in the market317
.
The above analysis highlights the importance of an improved market design, with all the
measures described under Option 1(c) of Problem Area I, together with scarcity pricing and the
proper locational signals (as added under Option 1 of Problem Area II), irrespective of whether
generators are solely relying on energy market income or also receive capacity payments.
Therefore the measures aimed at removing distortions from energy markets are considered as
'no-regrets'.
6.2.6.2.Comparison of Options 1 to 3
In order to better assess the dynamic behaviour of markets and how markets can also provide
investment signals, modelling analysis was performed using PRIMES/OM318, 319
. Option 1
assumes an improved energy-only market for all Member States. Options 2 and 3 assume that
the improved energy-only market is complemented in certain cases by a national CM320,321
as a
means for the Member States to address possible forecasted resource adequacy problems in
their markets, on the basis of a resource adequacy assessment performed at the European level.
The difference between the two options is that Option 3 assumes that the CM foresees rules for
effective, explicit cross-border participation, while Option 2 does not.
For the scope of this assessment, four countries were assumed to be in need of a CM: France,
Ireland, Italy and UK. This hypothesis was not based on a resource adequacy analysis, but on
the CMs examined under DG COMP's Sector Inquiry, focusing specifically on countries with
market-wide CMs. (Results could differ if different countries were selected, which is why a
sensitivity, presented below, was performed).
317
Contrary to METIS, in PRIMES/IEM demand response resources participate also in the day-ahead market,
thus bringing additional savings for the relevant Option. The impact is much more significant in this case
because the day-ahead market covers the vast majority of transactions.
318
PRIMES/OM delivers results complementary to the ones of market simulation models, like METIS and
PRIMES/IEM, as its focus is on investments. The main difference of PRIMES/OM with other energy system
investment models, like PRIMES, is that while PRIMES model analyses revenues/costs at the level of the
generation portfolio, the PRIMES/OM evaluates the probability of plant survival depending on the economic
performance calculated individually for each plant. A detailed description of PRIMES/OM can be found in
Annex IV.
319
The results will not be compared directly to the baseline as it was not technically possible to produce robustly
this scenario using PRIMES/OM. Nevertheless this does not affect the assessment, as all options build upon
the preferred option of Problem Area I.
320
The simulation of the CM auction by country, which is based on an estimation of a demand curve for capacity
procurement, takes into account imports and exports in the context of market integration using power flow
allocation of interconnection capacities. Therefore, the capacity procurement is configured so as to avoid
demanding for unnecessary capacities, as imports are considered to contribute to resource adequacy. Similarly,
exporting countries configure demand for capacity procurement taking into account capacity needed to
support exports.
321
When a country is assumed to have a CM in place, it is assumed that generators no longer follow scarcity
pricing bidding behaviour, but shift to marginal cost bidding. This is partly a result of competition, as more
generation remains in the market, as well as the expectation that when a plant gets a CM remuneration as a
result of an auction it foregoes revenues that would otherwise be needed to be covered from the day-ahead
market (e.g. because it signs a reliability option contract or a contract for differences with a strike price
effectively acting as a price cap to the generator's revenues from the energy market).
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The main conclusions when comparing Options 1-3 are presented in Table 16 and can be
summarized in the following:
- The load payments for the three Options are very comparable when assessed at the EU28
level. For the year 2030, Option 3 (Improved energy market – CMs only when needed,
plus cross-border participation) is slightly cheaper by EUR 1 billion compared to Option
1 (Improved energy markets - no CMs) and by EUR 2 billion compared to Option 2
(Improved energy markets – CMs only when needed, based on a common EU-wide
adequacy assessment);
- Results actually show that Option 3 is consistently cheaper than Option 2 throughout
the projection horizon until 2050 and on a EU28 level. This is mainly due to the lower
cost of the CMs, as through the cross-border participation more resources can compete
for the relevant payments;
- As a result of the above, the average annual cost of total demand is very close for Option
1 and Option 3, with the lowest cost option alternating along the years. Option 3 is
always less costly for the consumer than Option 2 though.
- When comparing the Options for the whole projection period, i.e. 2021-2050, Option 1
is found to be EUR 17 billion cheaper than Option 3 (on average about EUR 0.5
billion/annum) and EUR 120 billion cheaper than Option 2 (on average EUR 4
billion/annum). The main reason for this difference is that CMs provide incentives to
retain capacity on the system that otherwise would have exited the market. This cost is
somewhat balanced by the slightly lower energy prices observed in the market, although
the final cost to the consumer comprises of both the energy and the CM cost.
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Table 16: Main Impacts over the projection period 2020-2050 on EU28 level
2020 2025 2030 2035 2040 2045 2050
Load Payments (billion EUR)
Option 1 241 316 351 419 447 557 516
Option 2 241 312 352 428 454 560 530
Option 3 241 306 350 426 452 553 526
Load Payments for energy and reserves (billion EUR)
Option 1 241 316 351 419 447 557 516
Option 2 241 302 340 417 443 548 518
Option 3 241 297 340 417 443 543 516
Load Payments to capacity mechanisms (billion EUR)
Option 1 - - - - - - -
Option 2 - 11 11 11 11 11 12
Option 3 - 9 10 9 10 10 10
Average SMP (billion EUR)
Option 1 74 95 103 118 115 135 122
Option 2 74 91 100 117 114 133 123
Option 3 74 89 100 117 114 132 122
Average cost of total net demand (EUR/MWh)
Option 1 80 102 111 127 125 146 132
Option 2 80 101 111 129 127 147 135
Option 3 80 99 110 129 126 145 134
Source: NTUA Modelling (PRIMES/OM)
Note:Option 1: Improved energy markets - no CMs
Option 2: Improved energy markets – CMs only when needed, based on a common EU-wide adequacy assessment
Option 3: Improved energy market – CMs only when needed, plus cross-border participation
In order to better understand the impacts322
of the CMs and the effect of cross-border
participation, Table 17 presents the impacts in 2030 for the three following groups of countries:
(a) the countries implementing a CM, (b) their direct neighbours and (c) the rest of the EU
countries.
Results for Option 2 shows that by introducing a CM in the assumed four countries, the actual
distribution of cost varies among the different groups of countries. Countries implementing a
CM are significantly burdened, mainly due to the cost of the CM, while their neighbours benefit
from it.
322
The impacts of CMs on the energy mix were very limited, inducing only some limited switching in electricity
generation from coal to gas plants.
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In particular countries implementing the CM are burdended with an additional EUR 6.8 billion
of costs, while the cost of their neighbours drops by EUR 3.6 billion. Even the cost of the rest
of the EU countries drops by EUR 2.9 billion. The cost of energy and reserves is reduced for
all countries323
. In the countries implementing a CM the cost is reduced about two times more
than in the rest coutries, thus leading to lower payments for energy and reserves. However,
these reductions are outbalanced by the CM costs, borne solely by the countries introducing
CMs. The CMs induce an additional EUR 11 billion of payments, part of which are attributed
to the 5 GW of capacity which would otherwise have retired early in the absence of CMs.
Moving to Option 3, i.e. assuming explicit cross-border participation in the CMs, the results
compared to Option 2 improve in terms of cost-efficiency, not only for the whole EU as
presented above, but also for the countries implementing CMs. On the other hand the benefits
for the countries without a CM are slightly reduced.
In particular, the analysis for the year 2030 shows that explicit cross-border participation is still
worse-off for the countries with a CM compared to the energy-only market, costing EUR 3.6
billion more then the energy-only market, but better than implicit cross-border participation,
which costs an additional EUR 3.2 billion to the countries with CM.
In general, modelling results indicate that a CM, compared to an energy-only market, is likelier
to keep more capacity in the system, part of which would have otherwise exited due to making
losses in the energy market. As more capacity is kept in the Member States with a CM, less
capacity is needed in the other Member States, especially the neighbouring ones, which then
rely more on imports.
As it was discussed above, these results are influenced by the specific choice of countries
assumed to have a CM. To address this issue, an additional sensitivity was performed,
comparing the cases of all Member States introducing a CM, either with implicit or explicit
cross-border participation (same applying for all). Results show that the case of CMs with
explicit cross-border participation is less costly, with load payments being EUR 7 billion less
(about 2%) in the year 2030. Half of this benefit is coming from the reduced CM payments and
half from the reduced energy and reserve payments.
323
This result is related to some specific characteristics of these countries. France is heavily exporting electricity
based on nuclear and this is not affected by the establishment of a CM in France. This is also the reason why
energy costs drop across Europe. The UK and Italy heavily depend on CCGT plants in the context of the
scenario examined and, in addition, have limited free space in interconnections, because they are saturated by
import flows of nuclear energy coming from France.
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Table 17: Distributional Impacts of Options for Member States in 2030324
Option 1 Option 2 Option 3
Improved energy
markets - no CMs
Improved energy
markets – CMs only
when needed, based
on a common EU-
wide adequacy
assessment
Improved energy
market – CMs only
when needed, plus
cross-border
participation
Load Payments in 2030 (billion EUR)
MS with CMs 133 140 137
MS directly neighbouring MS with CM 135 131 132
Rest of the MS 82 79 80
Load Payments for energy and reserves (billion EUR)
MS with CMs 133 129 127
MS directly neighbouring MS with CM 135 132 132
Rest of the MS 82 80 80
Load Payments to capacity mechanisms (billion EUR)
MS with CMs 0 11 10
MS directly neighbouring MS with CM 0 0 0
Rest of the MS 0 0 0
Average SMP (EUR/MWh)
MS with CMs 104 100 98
MS directly neighbouring MS with CM 102 100 100
Rest of the MS 103 101 101
Cancelling of Investments or Early Retirements of Capacity in 2021-2030 (GW) 325
MS with CMs 18 9 9
MS directly neighbouring MS with CM 35 41 42
Rest of the MS 10 10 11
Source: NTUA modelling (PRIMES/OM)
The main reason for the overall improved performance and reduced costs of Option 3 compared
to Option 2 is the enhancement of competition in the CM auction and the resulting lower auction
prices when allowing for explicit cross-border participation. This reduction lowers the revenues
of generators from a CM, but the probability of capacity reduction does not significantly
increase, compared to the case with implicit cross-border participation. Explicit cross-border
324
Impacts comparing the effects to countries assumed to have CMs and countries without. The 4 countries
assumed to have CMs in 2030 (France, Italy, UK, Ireland) were chosen based on the finding of DG COMP
Sector Inquiry. No specific assumption was made for the design of the relevant CMs. Differences are due to
the peculiarities of each national energy system, mainly related to its power mix and its level of
interconnections. Results could be different if other MS had been chosen.
325
The values under "cancelling of investments or early retirements of capacity" represent excess capacity which
becomes redundant due to the improved market functioning. Early retirement in the model is market-based,
coming as a result of anticipating a negative present value of earnings above operation costs in the future, in
comparison to the remaining value of the plant.
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participation in the CM auctions implies that competition is stengthened not only in the CM,
but also in the electricity wholesale market.
6.2.6.3.Delivering the necessary investments
Despite the different modelling approaches followed, the analysis with both METIS and
PRIMES/IEM reach a similar conclusion: improving the electricity market design is a no regret
option for the society as a whole. It is expected to reduce both the cost of operating the power
system, as well as the final cost for the consumers.
At the same time though the two models showed that these savings come to the detriment of
the thermal generator revenues, which are expected to be reduced compared to the baseline.
This modelling conclusion is a consequence mainly of the following two reasons:
- on one hand, the improved market design increases competition in the market, by
bringing more resources into the market and better utilisation of interconnections;
- on the other hand, capacities are assumed to be constant due to the nature of the
modelling (static, focusing on 2030 based on the same capacities across all options).
The combination of the two points above leads to a market with overcapacity326
and thus low
prices, since there is no scarcity and there is sufficient capacity of flexible resources. In reality
though, the low prices in a well-functioning market would serve as a signal for lower
investments and exit of loss-making generators. Therefore this overcapacity should either never
appear or only be temporary.
The above dynamic interactions were better captured with PRIMES/OM, which simulated
investment behaviour till 2050327
. In an energy-only market context, PRIMES/OM projected
that 63 GW of capacity would either be retired early or the relevant investments would be
cancelled in the period 2021-2030. About half of it would come from (mainly old) coal plants
and another half from peaking units or steam turbines fuelled by oil and gas.
The reason for retiring capacity and cancelling investments is the unprofitable operation of the
units. From the results it is indicated that the market can be successful in maintaining CCGT in
operation and, partly, peak devices. On the other hand it does not provide sufficient incentives
to retain old coal and old oil/gas steam turbine power plants, which are loss-making.
Table 18: Power generation328 capacity in EU28
Power Generation
Capacity (GW)
Cancelling of Investments or Early
Retirements of Capacity (GW)
2030 2040 2050 2021-2030 2031-2040 2041-2050
Total 1,094 1,271 1,504 63 68 48
326
Moreover the capacity mix is not optimal any more.
327
All modelling runs assume certain reliability standards are met (i.e. security of supply concerns are always
met)
328
Reported generation capacities do not include capacities of CHP plants. Reported figures on cancelled
investments do not include 2 GW of cancelled nuclear investments in 2021-2030 and another 2 GW in 2041-
2050.
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Coal & Lignite 77 45 14 32 45 33
Peakers & Steam
turbines (oil/gas)
12 6 6 28 16 8
CCGT 158 165 175 0.3 7 4
Nuclear 110 124 122 2 0 2
Source: NTUA Modelling (PRIMES/OM)
In this context of adjusting capacities, the profitability329
of thermal generation changes
significantly for the better. Scarcity pricing and the reduction of overcapacity are the main
drivers for this. Table 19 below shows how the adjustment of capacities, together with scarcity
pricing, would affect wholesale prices and allow thermal plants to at least recover their total
costs from the market.
Table 19: Effect of adjusting capacities to wholesale market prices in 2030
Day-Ahead Market Price
Before Adjusting Capacities
Day-Ahead Market Price
After Adjusting Capacities
Average Price (EUR/MWh) 89 103
Baseload 80 93
Mid-merit 90 103
Peak load 94 137
Spread (EUR/MWh) 14 44
Source: NTUA Modelling (PRIMES/IEM, PRIMES/OM)330
In this context, the market seems able to deliver to a large extent the necessary investments for
all competitive technologies in the long term. A new CCGT plant, which is the marginal
technology, constructed post-2025 (when overcapacity is gradually resolving) will likely
remain profitable over the following 20 years of its operation. If this plant is part of a larger
portfolio, especially if it includes competitive RES E technologies, then it will be able to better
hedge its risks and further increase the likelihood that the whole portfolio will be profitable.
More specifically per technology:
CCGT Scarcity bidding succeeds in maintaining the vast majority of CCGT
capacity, a large part of it being new investments in the period 2021-
2030. These plants have a variety of revenue sources (day-ahead,
intraday, balancing, reserves) and the projected increase in ETS prices
makes them economically more attractive to operate. As a result CCGT
plants are dispatched more often at full capacity.
329
Profits are highly dependent on the assumed fuel costs, technology costs and CO2 price. Therefore the
discussion in this Section should be read in a probabilistic context, i.e. the "likelihood" of the investments
being profitable, similar to how the modelling of investment decisions was performed. Concerning the specific
assumptions used, PRIMES/OM was based on the relevant PRIMES EUCO27 projections, reported in Annex
IV.
330
PRIMES/IEM results are before capacity adjustment, PRIMES/OM after adjustment. Similar assumptions and
the same bidding strategies were used in both models, thus results are comparable, within the limitations of
each modelling approach.
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Nuclear Nuclear plants do not have any revenue issues, due to their low
marginal cost. Note that new investments in nuclear appear only in the
long-term.
Coal / Lignite These plants have the biggest revenue problems, as market revenues
prove insufficient even to cover their fuel and variable (non-fuel) costs.
There was very limited new investment in the projections even in the
baseline, so this issue mainly concerns decisions for the refurbishment
of coal plants.
Peak devices Peak units and steam turbines (many of them old) do not produce
comfortable revenues until 2035331. Around that period though and due
to the strong investments in variable RES E and the increasing needs
for flexible capacity, the situation turns around, rendering these units
very profitable.
RES E
(excl. biomass)
The situation for RES E is contrasted, depending on the level of
maturity of RES E technologies. Even if some less advanced RES E
technologies would need support to emerge as part of the power
generation mix towards 2030, this is not the case for many competitive
RES E technologies, such as hydro, onshore wind and solar PV (at least
in some parts of Europe)332
. For a more elaborate discussion on this
point see the text box below on RES E investments and market design.
CHP (incl.
biomass)
CHP333
remains unprofitable over the whole projection period when
considering only their electricity market related revenue streams. It
should be considered though that the main use of these plants is
assumed to be the production of industrial steam/heat, with electricity
being a side-product. Therefore, no conclusion should be made based
on these partial results. Similar for biomass (outside industrial CHP),
additional revenues are assumed to come from support schemes and
the value of heat when producing heat for district heating.
331
"METIS Study S16" shows that peakers’ revenues highly depend on the occurrence of scarcity hours that
happen mainly during very cold years, which constitutes an additional risk for peakers who rely on scarcity
prices to generate revenues. On the contrary, base-load producers have more stable revenues from one year to
the other.
332
A more detailed analysis can be found in the RED II impact assessment, specifically in Annex 5, where a
detailed analysis on the viability of RES E projects is presented for the period post-2020.
333
The category of CHP plants includes only those which serve industrial steam and district heating as their main
function. Other CHP plants have been appropriately distributed within the capacities of the respective
technologies.
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The following table summarizes the projected profitability for all generation technologies over
the period 2020-2050:
Table 20: Average profits or losses334 for different plant categories in the case of an energy
only market over the projected horizon 2020 – 2050 in EUR/kW for EU28
Source: NTUA modelling (PRIMES/OM)
It is important to highlight that the above analysis has been performed per individual plant basis.
Although this reflects project finance type of decisions, it does not reflect portfolio-based
decisions, which are closer to the usual power sector business model for utilities, due to
economies of scale. The portfolio approach (e.g. investing in both wind and peak generators)
allows the sharing of risks between different technologies, directly improving the performance
of the investments.
Similarly the above analysis does not consider the existence of any type of contracts between
supply and demand, be it long-term contracts, futures (e.g. EEX hedging products) or even
typical contracts between utilities and residential/commercial consumers. Such contracts,
concluded on a purely voluntary market basis, would again transfer part of the risk of the
generators to consumers, in exchange of higher security of supply, protection against price
spikes and more stable payments, allowing both sides to better manage their risks. This would
in turn increase the likelihood of the investments turning out to be profitable.
The above analyses also highlights that the market, of improved along the lines with the
measures assessed in the present impact assessment, can deliver to a large extent the necessary
334
The reported results concern financial evaluation at individual plant level. In the context of PRIMES/OM,
profits or losses are defined as follows: revenues from day-ahead market, revenues from reserve market,
revenues from CM (if applicable) minus sum of fuel costs, variable non-fuel costs, O&M fixed costs and
capital costs. For capital costs the model estimates the not-yet amortized value of initial investment
expenditure for old plants (including cost of refurbishment if applicable) and the investment expenditures for
new investments. As these are aggregate numbers, they approximate but are not equal to the missing money
(as when calculating aggregate profits, one unit's losses may cancel out with another unit's profits, while when
calculating missing money you only add the losses).
2020 2025 2030 2035 2040 2045 2050
Total -46.9 9.1 35.7 78.4 68.8 129.2 80.5
Solids 69.9 94.8 1.6 -111.5 -80.9 -89.7 -207.7
Steam turbines oil/gas -66.2 -116.7 -117.3 -93.8 -90.7 -68.5 -120.9
CCGT -75.1 -55.6 -23.2 27.6 -23.5 21.1 -59.6
Peak -53.7 -50.1 -51.9 -11.8 224.2 344.1 36.8
Nuclear -47.5 102.8 141.0 249.4 233.8 374.5 259.4
Lakes 144.0 162.3 185.6 205.9 211.9 270.5 263.4
Run of River 268.4 309.3 335.4 355.3 304.9 345.3 209.0
Geothermal 153.3 235.4 313.8 438.3 477.1 443.4 356.1
Wind onshore 1.9 30.7 82.2 117.2 118.5 173.1 142.1
Solar PV (large) -63.0 -1.2 25.6 58.6 49.0 86.1 62.5
RES (small) -115.0 -101.4 -48.5 34.7 19.1 24.9 5.0
Wind offshore -6.2 -83.8 -85.9 -18.2 2.6 127.7 55.9
Biomass -137.9 -171.2 -141.3 -59.0 -74.1 20.5 13.2
Solar thermal -678.7 -666.4 -466.2 -422.0 -385.3 -265.1 -415.0
Tidal -5,569.9 -4,105.4 -308.5 -252.8 -175.7 -116.0 -130.0
CHP solids -136.9 -203.5 -208.5 -227.6 -315.5 -364.8 -434.8
CHP gas -163.8 -185.8 -169.3 -128.4 -207.7 -235.5 -328.0
CHP biomass -338.5 -336.1 -324.0 -289.9 -292.3 -128.3 -90.1
CHP oil -333.2 -459.2 -487.9 -372.3 -367.8 -629.5 -413.8
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investments for a wide range of technologies in the long term, thereby reducing the need for
government intervention to support investment in electricity resources.
Box 7: RES E investments and market design
Amongst all sectors that make up our energy system, electricity is the most cost-effective to
decarbonize. Currently about one fourth of Europe's electricity is produced from renewable
energy sources. Modelling indicates that the share of RES E in electricity generation needs to
almost double by 2030 in order for the EU to meet its 2030 energy and climate targets.
A functioning market is the most efficient tool to implement the decarbonisation agenda at least
costs while securing electricity supplies at all times.
The Commission's ambition for the post-2020 context is that renewable electricity generators
can earn an increasingly larger fraction of their revenues from the energy markets.
This ambition requires adapting the market design for the cost-effective operation of variable,
decentralised generation, and improving the market as the catalyst for investments by removing
regulatory failures and market imperfections. In a nutshell, markets will need to:
(a) be more focused on short-term trading, including cross-border trading, to allow
electricity from wind and solar energy to effectively compete in the market;
(b) link wholesale and retail markets to increase the flexibility of the system, let consumers
benefit from times of cheap electricity, let them engage in demand response systems
and produce electricity themselves; and,
(c) become even better at generating investment signals – as a matter of principle, it should
be the market through its price signals triggering investments.
In this context, the present impact assessment investigates a number of options that improve
market functioning by removing market distortions between different types of generation, that
render the market's operation more flexible and adapted to the cost-effective operation of
variable generation and improving the conditions for the participation of decentralised, flexible
resources, such as demand and storage, into the market. Moreover, it investigates various means
to improve price signals inciting investment in the right resources and location and investments
in infrastructure.
The enhanced market design will improve the viability of RES E investments, but electricity
market revenues alone might not prove sufficient in attracting renewable investments in a
timely manner and at the required scale to meet EU's 2030 targets.
The enhanced market design and the strengthened ETS will improve the viability of RES E
investments, in particular through the following channels:
- Where the marginal producer is a fossil fired power plant, a higher carbon price translates
into higher average wholesale prices. The existing surplus of allowances is expected to
decrease due to the implementation of the Market Stability Reserve and the higher Linear
Reduction Factor, reducing the current imbalance between supply and demand for
allowances;
- Greater system flexibility will be critical for a better integration of RES E in the system,
reducing their hours of curtailment and the related forgone revenues; improving overall
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system flexibility is equally essential to limit the merit-order effect335
and thus in avoiding
the erosion of the market value of RES E produced electricity336
- The revision of priority dispatch rules and the better functioning of the short-term markets
will strongly reduce (even eliminate according to the analysis) the occurrence of negative
prices – leading again to higher average wholesale prices (especially during the hours with
significant variable RES E generation);
- Improved market rules for intraday and balancing markets will increase their liquidity and
allow access to those markets for all resources, thus helping RES E generators reduce their
balancing costs;
- Removing existing (explicit or implicit) restrictions for the participation of all resources to
the reserve and ancillary services markets will allow RES E to generate additional revenues
from these markets.
- Price signals reflecting the actual value of electricity at each point of time, as well as the
value of flexibility, will help ensure that flexible capacity is properly rewarded, channelling
investment into such capacities or prevent its decommissioning.
With technology costs gradually reducing, ETS price increasing and the electricity market
prices better reflecting the value of electricity, RES E investments in the electricity market will
gradually become more and more market-based, reflecting the balance of supply and demand
for the coming years and the associated costs to each technology.
The present impact assessment and the one on the RED II thus jointly come to the conclusion
that the improved electricity market, in conjunction with a revised ETS could, under these
conditions, deliver investments in the most mature renewable technologies (such as solar PV
and onshore wind).
However, despite best efforts in market integration, electricity market revenues alone might not
prove sufficient in attracting renewable investments in a timely manner and at the required scale
to meet EU's 2030 targets. This investment gap is analysed in more details in the RES II impact
assessment. The analysis shows that the picture is dynamic, with the enhanced market design
and the strengthened ETS gradually and increasingly improving RES E profitability over the
2021-2030 period. At the beginning of the period, over-capacity, low ETS and wholesale
market prices and still high RES E technology costs, make the case for investments in RES E
technologies more difficult. However, an increasing ETS price, a more flexible and dynamic
electricity market, technology costs reductions and adjustments in capacity increasingly
facilitate investments over this period337
.
335
Also referred occasionally as the 'cannibalisation effect'.
336
The inherent variability of wind exposure and solar radiation affects the price that variable renewable
electricity generators receive on the market (market value). During windy and sunny days the additional
electricity supply reduces the prices. Because the drop is larger with more installed capacity, the market value
of variable renewable electricity falls with higher penetration rate, translating into a gap to the average market
value of all electricity generators over a given period (See Hirth, Lion, "The Market Value of Variable
Renewables", Energy Policy, Volume 38, 2013, p. 218-236)
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The impact assessment for RED II concludes that over the period 2021-2030 around half of the
additional RES E capacity will still need some kind of support, but with significant decrease in
the number of investments needing support towards 2030.
In particular, less mature RES E technologies, such as off-shore wind, will likely need some
form of support throughout the 2021-2030 period. These technologies are required if RES E
technologies are to be deployed to the extent required for meeting the 2030 and 2050 energy
and climate objectives, and provide an important basis for the long-term competitiveness of an
energy system based on RES E.
The picture also depends on regions. RES E technologies are more easily financed from the
market in the regions with the highest potential (e.g. onshore wind in the Nordic region or solar
in Southern Europe), while RES E continue to largely require support in the British Isles and in
Central Europe.
Additionally, it should be noted that the speed at which RES E parity338
is reached, in addition
to the successful implementation of the MDI and ETS, also depends on factors that lay outside
of the scope of these initiatives, including: (i) continued decrease in technology costs for RES
E as well as complementary technologies (e.g. storage); (ii) the availability of (reasonably
cheap) capital, which is a function of many variables, including project-specific and RES E
framework-specific risks, but also general country risk; (iii) continued social acceptance; (iv)
sufficiently high and stable fossil fuel prices.
The need for a framework for RES E support schemes
In order to address the risks associated with investments in RES E and the chance of failing to
meet EU's 2030 target for RES, the MDI and the RED II impact assessments jointly consider
that electricity market and ETS policies need to be complemented by an improved policy
framework on RES E support schemes.
Against this background, the RED II impact assessment investigates options to ensure that, if
and where support is needed, support is only applied where needed in a manner that is: (i) cost-
effective and kept to a minimum, and (ii) creates as little distortions as possible to the
functioning of electricity markets, and to competition between technologies and between
Member States. Indeed, the market can only deliver the full benefits sketched above, if policies
fostering RES E are compatible with the market environment in which they operate.
In particular, the RED II impact assessment suggests creating a common European framework
for support schemes. The framework would be effective as it would define design principles (i)
that ensure sufficient investor certainty over the 2021-2030 and (ii) require the use (where
needed) of market-based and cost-effective schemes based on emerging best practice design
(including principles that are not covered by the current State Aid guidelines).
At the same time, the framework would be proportionate by leaving actual implementation to
the State Aid guidelines (e.g. for the definition of thresholds applicable for any foreseen
exemptions) and, most importantly, to the case by case, evidence-based, in-depth assessment
338
i.e. the moment when LCOE decreases to the level of the actual market value of the asset to be financed.
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of individual schemes by the services of DG Competition .Importantly, the framework would
enshrine in legislation and expand the requirement to tender support; it would define tender
design principles, based on emerging best practice, to ensure the highest cost-efficiency gains
and to ensure market incentives are least distorted by the support mechanism.
The framework would thus strengthen the use of tenders as a natural phase-out mechanism for
support, by which a competitive bidding process determines the remaining level of support
required to bridge any financing gap – such level of support being expected to disappear for the
most mature technologies over the course of the 2021-2030 period.
The importance of a framework for RES E support schemes for the present initiative.
It is also important to note that the progressive reform of RES E support schemes as proposed
by the RED II initiative, building on the EEAG, is a prerequisite for the results of the present
initiative to come about. In order to ensure that a market can function, it is necessary that market
participants are progressively exposed to the same price signals and risks. Support schemes
based on feed-in-tariffs prevent this and would need to be phased-out, with limited exemptions,
and replaced by schemes that expose RES E to price signals, as for instance premium based
schemes. This would be further supported by setting aid-levels through auctioning as RES E
investment projects will then be incentivised to develop business models that optimise market-
based returns339
.
How different types of CMs might affect RES E remuneration in the market
In market-wide, volume-based CMs, assets are remunerated if they can respond to specific
technical performance criteria (i.e. in practice if they are dispatchable). Hence, it is likely that
variable RES E producers (wind and solar) cannot participate in such schemes to the same
extent as dispatchable generators. As the introduction of a market-wide volume-based scheme
might render scarcity-based pricing less effective, RES E producers might receive less income
then they would otherwise be able to earn on energy-only markets. A well-designed strategic
reserve (provided it is activated (only at value of lost load and activated as a measure of last
resort (see above)), is less likely to have a negative impact on market revenues for intermittent
RES E, as such a scheme relies on commodity price signals only and does not interact with
scarcity-based pricing.
6.2.6.4.Level and volatility of wholesale prices
The analysis performed using all three models (METIS, PRIMES/IEM, PRIMES/OM)
confirms that the projected investments in low carbon technologies, combined with increased
demand response participation, are not expected to lead to the collapse of the wholesale market
prices in the short and medium term. Although there will be hours with low (or even negative)
prices, the wholesale prices will most probably be set by the marginal thermal generation
technology during most hours of the year. Table 21 presents the distribution of wholesale prices
339
See also Annex IV for more information for information on the robustness on
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in 2030, assessed for the various options of Problem Area I with PRIMES/IEM. Results indicate
that the wholesale prices will fluctuate, but within reasonable limits on an EU level340
.
Table 21: Distribution of load weighted day-ahead market prices341
in 2030
Day-ahead price
in 2030 (EUR/MWh)
Number of Hours
Option 0 Option 1(a) Option 1(b) Option 1(c)
Baseline
Level playing
field
Strengthening
short-term
markets
Fully
integrated
markets
Below 60 0 0 84 0
Between 60-80 0 0 1155 1572
Between 80-90 2482 2642 2394 3169
Between 90-100 3254 3290 2870 3121
Between 100-110 2197 2013 1288 484
Between 110-120 372 555 528 0
Between 120-140 455 260 88 150
Above 140 0 0 353 264
Source: NTUA Modelling (PRIMES/IEM)
The above results do indicate that the improved market design will lead to more volatile average
hourly prices, partly due to the introduction of locational signals which reveal the different
value of electricity in the various nodes. This volatility though will be fairly restricted and will
not be the result of extreme price fluctuations between zero and VoLL. The observed price
ranges will be fairly constrained, as long as the share of variable RES E remains within certain
limits342
. When the share of RES E, and specifically of variable RES E technologies, exceeds
these rough limits though, price volatility may increase significantly if other resources like
storage are not in place yet to absorb a large part of it.
As can be seen in the table below, in 2050 the share of RES E is projected to approach 60%. In
this case the spread between the baseload and peak load prices increases significantly, mainly
due to the lower baseload prices compared to the previous periods. The average day-ahead
340
Certain Member States though with very high RES E shares, like Spain and Portugal, and limited
interconnections are expected to have significantly more volatile wholesale prices than other Member States.
341
Reported results reflected assumed bidding behaviour of generators. The behaviour was relatively
conservative, reflecting though a stable condition in the market and the effects of competition (though market
power was considered). The most important assumption driving these results is that plants bid above marginal
costs and the hydro plants bid at opportunity costs. Minimum price observed (on EU28 level) was not lower
than 60 EUR/MWh, highest price did not exceed 200 EUR/MWh. There were higher and lower prices on
Member State level.
342
A study by METIS finds that as long as the share of solar generation is lower than 10-12% of total electricity
generation, solar production coincides with periods of high power demand and tends to smooth-out residual
demand over the day, which is expected to lead to less variable prices. This changes though considerably for
higher shares of solar. On the other hand, wind energy is directly related to variability and is a significant
driver for flexibility needs. "METIS Study S7: The role and need of flexibility in 2030. Focus on Energy
Storage", Artelys (2016).
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market prices though remain high throughout the projection horizon, as thermal generation is
still expected to be marginal (thus setting the day-ahead market price) during most hours of the
year.
Table 22: Average wholesale prices and RES E Shares
2020 2025 2030 2035 2040 2045 2050
Average wholesale market prices343 (EUR 13/MWh)
Average day-ahead market prices 74 95 103 118 115 135 122
baseload 74 83 93 98 89 108 71
mid-merit 74 95 103 118 116 137 122
peak load 93 98 137 135 134 149 138
Spread between average
baseload and peak load SMP
19 15 44 38 45 41 67
Share of RES E in net electricity generation (%)
Share of variable RES E 30.8 36.0 40.4 43.0 49.6 53.2 57.5
Solar 4.8 7.7 8.9 9.4 9.9 11.1 13.6
Wind 14.4 17.0 20.4 22.7 29.3 32.1 34.1
Source: NTUA modelling (PRIMES/OM)
6.3. Impact Assessment for problem Area III (reinforce coordination between Member
States for preventing and managing crisis situations)
Methodological Approach
In this section the impacts of the different policy options are identified and assessed. The
options proposed should first and foremost be effective in improving trust of Member States to
rely on neighbours' electricity markets in times of system stress. They should also lead to a
more effective functioning of markets, with less undue market distortions. Additionally,
reinforced coordination and cooperation between Member States in the identification and
mitigation of risks and the management of crisis have also been identified as specific objectives.
The methodological approach followed for this analysis is mostly qualitative; however some
quantitative analysis is provided as well, notably via the METIS simulations.
As regards the impacts, given the administrative nature of the measures and the objectives
pursued, the most relevant impacts in terms of magnitude are the economic impacts.
343
Based on the modelling methodology followed, described in Annex IV, reported wholesale prices reflect the
level of electricity prices which would lead to the recovery of the full costs of generators only via the wholesale
market, on a plant by plant basis and over the lifetime of each asset in the case of an Energy only Market (i.e.
Option 1). This modelling context differs significantly from the current one, characterised by different
underlying market conditions (overcapacity, low fuel prices, distorted markets etc). See also Box 9 in Section
6.2.6.4 for a further discussion on this topic.
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The measures proposed (e.g. enhanced regional coordination and information exchange)
anticipates a very limited impact, if any, on the environment. Therefore, the assessment does
not examine the impact of the proposed measures on the environment.
Impacts of Policy Option 1 (Common minimum rules to be implemented by Member
States)
6.3.2.1.Economic impacts
Overall, the policy tools proposed under this option should have positive effects. Putting in
place a more common approach to crisis prevention and management would not entail
additional costs for businesses and consumers. It would, by contrast, bring clear benefits to
them.
First, a more common approach would help better prevent blackout situations, which are
extremely costly. The immense costs of large-scale blackouts provide an indication of potential
benefits of improved preparation and prevention344
.
Table 23: Overview over most severe blackouts in Europe
Country & year
Number of end-
consumers
interrupted
Duration,
energy not
served
Estimated costs to
whole society
Sweden/Denmark,
2003
0.86 million
(Sweden); 2.4
million (Denmark)
2.1 hours, 18
GWh
EUR 145 – 180
million
France, 1999 1.4 - 3.5 million
2 days–2 weeks,
400 GWh
EUR 11.5 billion
Italy/Switzerland,
2003
55 million 18 hours
Sweden, 2005 0.7 million
1 day – 5 weeks,
11 GWh
EUR 400 million
Central Europe, 2006 45 million
Less than 2
hours
Source: SESAME: Securing the European Electricity Supply Against Malicious and Accidental Threats
A more common approach to emergency handling, with an obligation for Member States to
help each other, would help to avoid or limit the effects of potential blackouts. A more common
approach, with clear obligations to e.g., follow up on the results of seasonal outlooks, would
also reduce the costs of remedial actions TSOs have to face today. This, in turn, should have a
positive effect with a reduction of costs overall.
344
Previous blackouts in Europe had severe consequences. For example, the blackout in Italy in September 2003
resulted in a power disruption for several hours affecting about 55 million people in Italy and neighbouring
countries and causing around 1.2 billion euros worth of damage. (source: The costs of blackouts in Europe
(2016), EC CORDIS: http://cordis.europa.eu/news/rcn/132674_en.html).
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In addition, improving transparency and information exchange would facilitate coordination,
leading to a more efficient and less costly measures.
By ensuring that electricity markets operate as long as possible also in stress situations, cost-
efficient measures to prevent and resolve crisis are prioritized.
6.3.2.2.Who would be affected and how
Option 1 is expected to have a positive effect on society at large and electricity consumers in
particular, since it helps prevent crisis situations and avoid unnecessary cut-offs. Given the
nature of the measures proposed, no major other impact on market participants and consumers
is expected.
On cybersecurity, given the voluntary approach of this option, several stakeholders (TSOs,
DSOs, generators, suppliers and aggregators) could be affected, as long as they implement the
guidance proposed. However, the impact is estimated limited as the costs of cybersecurity for
regulated entities merely need to get considered and taken into account by the regulatory
authority. Thus, the TSOs and DSOs affected could recover their costs via grid tariffs. In that
case, the pass through of costs would have an impact on consumers that could see a slightly
increased in the final prices of electricity.
6.3.2.3.Impact on businesses and public authorities
The preparation of risk preparedness plans as well as the increased transparency and
information exchange in crisis management imply a certain administrative effort345
. However,
the impact in terms of administrative impact would remain low, as currently Member States
already assess risks relating to security of supply, and all have plans in place for dealing with
electricity crisis situations346
.
In addition, it is foreseen to withdraw the current legal obligation for Member States to draw
up reports monitoring security of supply347
, as such reporting obligation will no longer be
necessary where national plans reflect a common approach and are made transparent. This
would reduce administrative impacts.
345
Administrative costs are defined as the costs incurred by enterprises, the voluntary sector, public authorities
and citizens in meeting legal obligations to provide information on their action or production, either to public
authorities or to private parties.
346
See Risk Preparedness Study.
347
Article 4 of the Electricity Directive; Article 7 of the Electricity SoS Directive.
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Impacts of Policy Option 2 (Common minimum rules to be implemented by Member
States plus regional co-operation)
6.3.3.1.Economic impacts
This option would lead to better preparedness for crisis situations at a lesser cost through
enhanced regional coordination. The results of METIS simulations348
show that well integrated
markets and regional coordination during periods of extreme weather conditions (i.e. very low
temperature349
) are crucial in addressing the hours of system stress (i.e. hours of extreme
electricity demand), and minimizing the probability of loss of load (interruption of electricity
supply).
Most importantly, while a national level approach to security of supply disregards the
contribution of neighboring countries in resolving a crisis situation, a regional approach to
security of supply results in a better utilization of power plants and more likely avoidance of
loss of load. This is due to the combined effect of the following three factors: (i) the variability
of renewable production is partly smoothed out when one considers large geographical scales,
(ii) the demands of different countries tend to peak at different times, and (iii) the power supply
mix of different countries can be quite different, leading to synergies in their utilization.
The following table compares the security of supply indicator, EENS, assessed by METIS for
the three levels of coordination (national, regional, European)350
. It highlights the highest value
of the loss of load (electricity non-served expressed as percentage of annual load) when it is
measured in a scenario of non-coordinated approach, which does not take into account the
potential mutual assistance between countries. When cooperation takes place among Member
States, the percentage of electricity non-served significantly decreases.
Table 24 - Global expected energy non-served as part of global demand within the three
approaches for scenario ENTSO-E 2030 v1 with CCGT/OCGT current generation
capacities
Level EENS (% of annual load) – ENTSO-E V1 scenario
National level 0,36 %
Regional level 0,02 %
European level 0,01 %
ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario where no common
European decision regarding how to reach the CO2-emission reductions has been reached. Each country has its
own policy and methodology for CO2, RES and resource adequacy.
Source: METIS
348
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it", Artelys
(2016).
349
Even though periods with very low temperature occur rarely (9C difference between the 50 year worst case
and the 1% centile) countries can face high demand peaks (e.g. Nordic countries and France) mainly due to
the high consumption for the electric heating. As example, the additional demand for the 50 years peak
compared to the annual peak demand is 23% for France, 18% for Sweden and 17.3% for Finland.
350
"METIS Study S04: Stakes of a common approach for generation and system adequacy", Artelys (2016).
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The EENS for the three levels of coordination are represented on the figure below. When the
security of supply is assessed at the national level, many countries of central Europe seem to
present substantial levels of loss of load. However, since these countries are interconnected, a
regional assessment of security of supply (taking into account power exchanges within this
region) significantly decreases the loss of load levels.
Figure 14 - EENS (%) estimation by country for scenario ENTSO-E 2030 v1 with
CCGT/OCGT current generation capacities. From left to right: EENS estimated at
European, regional and national levels
CCGT: Combined Cycle Gas Turbine OCGT: Open Cycle Gas Turbine
ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario where no common
European decision regarding how to reach the CO2-emission reductions has been reached. Each country has its
own policy and methodology for CO2, RES and resource adequacy.
Source: METIS
METIS simulations also show that thanks to regional cooperation the stress situations would
decrease and concentrate in a limited number of hours that may occur simultaneously351
.
Therefore, it highlights the need for specific rules on how Member States should proceed in
these particular circumstances, as proposed in this Option 2.
As the overall cost of the system would decrease thanks to enhanced coordination this could
have a positive impact on prices for consumers.
On the contrary, a lack of coordination on how to prevent and manage crisis situations would
imply significant opportunity costs. A recent study also evidenced that the integration of the
European electricity market could deliver significant benefits of EUR 12.5 to 40 billion until
2030. However, this amount would be reduced by EUR 3 to 7.5 billion when Member States
pursue security of electricity supply objectives following going alone approaches352
.
351
Please also see in Annexes to the Impact Assessment: Assessment of the Measures Associated with the Main
Option: Graphs 1 and 2 in "6. Detailed measures assessed under problem area 3: a new legal framework for
preventing and managing crises situations".
352
Benefits of an Integrated European Energy Market (2013), BOOZ&CO.
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6.3.3.2.Who would be affected and how
As in the case for Option 1, Option 2 is expected to have a positive effect on society at large
and electricity consumers in particular, since it helps prevent crisis situations and avoid
unnecessary cut-offs. Given that, under Option 2, Member States would be required to
effectively cooperate, and tools would be in place to monitor security of supply via the
Electricity Coordination Group, such crisis prevention and management would be even more
effective.
The measures would also have a positive effect on the business community, as there would be
much more transparency and comparability as regards how Member States prepare for and
intend to manage crisis situations. This will increase legal certainty for investors, power
generators, power exchanges but also for TSOs when managing short-term crisis situations.
Among the stakeholders the most affected would be the competent authorities (e.g. Ministry,
NRA) as actors responsible for the preparation of the risk preparedness plans (see below,
assessment of impacts on public authorities).
6.3.3.3.Impact on businesses and public authorities
The assessment of this option shows a limited increase in administrative impact, although it
would be to some extent higher than Option 1, given that national authorities would be required
to pre-agree part of their risk preparedness plans in a regional context.
However, existing experiences show that a more regional approach to risk assessment and risk
preparedness is technically and legally feasible. Further, since the regional parts of the plans
would in practice be prepared by regional co-ordination centres between TSOs, the overall
impact on Member States' administrations in terms of 'extra burdens' would be limited, and be
clearly offset by the advantages such co-operation would bring in practice.353
In addition, more regional cooperation would also allow Member States to create synergies, to
learn from each other, and jointly develop best practices. This should, overtime, lead to a
reduction in administrative impacts.
Finally, European actors such as the Commission and ENTSO-E would provide guidance and
facilitate the process of risk preparation and management. This would also help reduce impacts
on Member States.
It should be noted, that under Option 2 (as is the case for Option 1) no new body or new
reporting obligation is being created, and that existing obligations are being streamlined. Thus,
the Electricity Coordination Group is an existing body meeting regularly, for the future it is
foreseen to make this group more effective by giving it concrete tasks. Further, national
reporting obligations would be reduced (e.g. repealing the obligation of Article 4 of Electricity
Directive) and EU-level reporting would take place within the context of existing reports and
353
The Nordic TSOs, regulators and energy authorities cooperate through NordBER, the Nordic Contingency
and Crisis Management Forum. This includes information exchange and joint working groups and
contingency planning for the overall Nordic power sector as a supplement to the national emergency work
and TSO cooperation (www.nordber.org).
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existing reporting obligations (e.g. ACER annual report Monitoring the Internal Electricity and
Natural Gas Markets).
Impacts of Policy Option 3 (Full harmonisation and full decision-making at regional
level)
6.3.4.1.Economic impacts
The regional coordination through the regional plans would have a positive impact in term of
cost as the number of plans would be necessary less than twenty-eight plans and limited to the
number of regions. In addition, the coordination at European level would decrease slightly the
loss of load level compared to the regional coordination (EENS 0.01% compared to 0.02%).
On the contrary, on cybersecurity, the creation of a dedicated agency at EU level would have
important economic implications as this agency would be a new body that does not exist yet
and which is also not foreseen in the NIS Directive. The costs of creating this new agency are
not only limited to the creation of a new agency itself, but the costs would also have to include
the roll-out of a whole security infrastructure. For example, the estimated costs of putting in
place the necessary security infrastructure and related services to establish a comparable
national body - cross-sectorial governmental Computer Emergency Response Team ("CERT")
with the similar duties and responsibilities at national level as the planned pan-European sector-
specific agency - would be approximately EUR 2.5 million354
per national body. This means
that the costs for the security infrastructure would be manifold for a pan-European body. In
terms of human resources, for the proper functioning of the new agency with minimum scope
and tasks at EU level, it is estimated a staff of 168 full time equivalents (considering 6 full time
equivalents per Member State sent to the EU agency). The representation from all Member
States in the agency is essential in order to ensure trust and confidence on the institution.
However, the availability of network and information security experts who are also well-versed
in the energy sector is limited.
6.3.4.2.Who would be affected and how
The obligation of regional plans would have important implications for the competent
authorities as the coordination and agreement of common issues (e.g. load shedding plan,
harmonised definition of protected customers) would be a lengthy and complex process.
On cybersecurity, the creation of the new agency at EU level would mobilize highly qualified
human resources with skills in both energy and information and communication technologies.
This could have a potential impact on national administrations and energy companies as long
as some of the experts in the field could be recruited by the new institution. However, the impact
would be limited as the representation for all Member States should be guaranteed. Therefore,
a small number of experts (around 6) per country could be recruited.
354
"Impact Assessment accompanying the document Proposal for a Directive of the European Parliament and
of the Council Concerning measures to ensure a high level of network and information security across the
Union". SWD(2013) 32 final.
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6.3.4.3.Impact on businesses and public authorities
Overall Option 3 would imply significantly administrative impact in the preparation of the
regional plans. It would require important efforts to gather information related to national and
regional circumstances and contribute to the joint task of assessing the risks and identifying the
measures to be included in the plans. In any case, it would seem difficult to coordinate within
a region the national specificities and risks originate mostly in one Member State.
The creation of a new agency on cybersecurity would imply significant administrative impacts
in the preparation and set-up of the agency, as well as in the communication structure with
already existing cross-sectorial bodies of Member States (CERTs/ Computer Security Incident
Response Teams "CSIRTs").
6.4. Impact Assessment for Problem Area IV (Increase competition in the retail
market)
Methodological Approach
This section compares the costs and benefits of each of the policy options to address this
Problem Area in a semi-quantitative manner.
No data or methodology exists that would allow us to accurately quantify all the benefits of the
measures examined.
However, this section draws on behavioural experiments from a controlled environment to
evaluate the impact of some policy options on consumer decision-making. Where economic
impacts cannot be quantified, quantitative desktop research and case studies are used to inform
estimates of the extent of possible impacts, as well as possible winners and losers. Where
appropriate, this section aims to illustrate the possible direct benefit to consumers assuming
certain conditions. Implementation costs in terms of the impact on businesses and public
authorities were estimated using the standard cost model for estimating administrative costs.
And finally, this section also highlights important qualitative evidence that policymakers should
also incorporate into their analysis of costs and benefits.
Impacts of Policy Option 0+ (Non-regulatory approach to improving competition and
consumer engagement)
6.4.2.1.Economic Impacts
Option 0+ would lead to an estimated EUR 415 million in benefits to consumers for the period
2020-2030, which come as a result of an enforcement drive to tackle the switching costs
currently faced by an estimated 4% of all EU electricity consumers that do not comply with EU
law355
.
355
See Annex 7.4, Section 7.4.5.
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Other unquantifiable economic benefits include improved retail level competition resulting
from the phase-out of regulated prices in some Member States356
, and more comparison tools
that comply with the Unfair Commercial Practices Directive357
.
In addition, one may expect modest, indirect improvements to the health and well-being of
energy poor consumers from the exchange of good practices stemming from the activities of
the EU Observatory for energy poverty358
.
In spite of these considerations, it is unlikely that Option 0+ (Non-regulatory approach) would
most effectively address the problems identified.
First, this option does not address the poor data flow between retail market actors that
constitutes both a barrier to entry and a barrier to higher levels of service to consumers. Whereas
Option 0+ is non-regulatory, a credible policy to tackle conflicts of interest among market actors
around data handling would require a legislative intervention.
Secondly, as a non-regulatory option, the effectiveness of Option 0+ is significantly limited by
shortcomings in the existing legislation. This significantly reduces the ability to address
contract termination fees (which are currently legal under EU law), the partial availability of
comparison websites in Member States, as well as energy poverty, which the current legislation
does not require Member States to measure, and hence address it.
And finally, a non-regulatory approach to tackling price-regulation may lead to a fragmented
regulatory framework across the EU given: (i) the uncertainty that surrounds the Commission's
ability to convince hold-out Member States to voluntarily cease excessive regulatory
interventions in price-setting; and (ii) the uncertainty that surrounds the success of any
subsequent legal measures to infringe Member States on the issue.
6.4.2.2.Who would be affected and how
Consumers will benefit from more easily being able to compare offers in the market, as well
as lower financial barriers to switching. Whilst consumer prices may rise in Member States
phasing out price regulation, this would be offset by higher levels of service and the greater
availability of value added products on the market.
Member States will benefit from a clearer understanding and measurement of energy poverty
will have indirect positive impacts on energy poor consumers.
Suppliers would benefit from increased access to the market of any Member State phasing out
price regulation. However, certain suppliers would also face tougher competition and increased
pressure on margins as the result of the modestly greater consumer engagement expected.
Any increase in consumer switching would increase the administrative impacts to DSOs.
However, these costs would be passed through to end consumers.
356
See Annex 7.2, Section 7.2.5.
357
See Annex 7.5, Section 7.5.5.
358
See Annex 7.1, Section 7.1.5.
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NRAs in any Member States phasing out price regulation will need to significantly step up
efforts to monitor the market, ensure efficient competition, and guarantee consumer protection.
They will need to more closely monitor and report the number of disconnections. However, this
may be offset by a reduction in price setting interventions, and increased competition resulting
from greater consumer engagement.
6.4.2.3.Impact on businesses and public authorities
Option 0+ (Non-regulatory approach) would lead to quantifiable implementation costs of
around EUR 0.9 million for the period 2020-2030, all resulting from setting up and running an
EU Observatory for energy poverty359
. It is anticipated that the soft law and enforcement
measures associated with making better use of the existing legislation on regulated prices,
switching fees and comparison tools would not result in significant additional costs compared
with a business as usual scenario.
Impacts of Policy Option 1 (Flexible legislation addressing all problem drivers)
6.4.3.1.Economic Impacts
Option 1 would lead to an estimated EUR 2.2 billion in direct benefits to consumers for the
period 2020-2030, which come as a result of: (i) reducing the switching-related charges faced
by 21% of household electricity consumers, and so helping them realize the potentially
significant gains of moving to a cheaper tariff360
; (ii) further improvements to the switching rate
for both electricity and gas household consumers as a result of the improved availability of price
comparison tools361
; (iii) an improved ability for consumers to identify the best offer in the
market through improved access to information on the bill (although the gains of this latter
intervention are not easy to quantify compared for instance with interventions aimed at making
switching less costly for consumers)362
.
Other unquantifiable economic benefits include significantly improved retail competition
resulting from the definitive phase-out of blanket price regulation in the 17 Member States still
practicing it363
. The impact of phasing out price regulation on retail price levels is impossible
to quantify. However, the evidence strongly suggests it will lead to higher levels of consumer
satisfaction. Indeed, even the energy component of retail bills does increase slightly in the short-
term, consumer surplus (the difference between the price of the service and the price a consumer
would be willing to pay for that service) may actually increase too as a result of the better
service levels consumers receive in the non-regulated market. In addition, retail price
competition is an important prerequisite for new services that would increase system flexibility
359
The Commission secured funding to set up the Observatory for the period 2016-2019. The costs included in
the Impact Assessment refer to the running annual cost to continue operating the Observatory. See Annex 7.4,
Table 11 and Section 7.1.5.
360
See Annex 7.4, Section 7.4.5.
361
See Annex 7.6, Section 7.6.5.
362
See Annex 7.4, Section 7.4.5.
363
See Annex 7.2, Section 7.2.5.
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(benefits examined in Section 6.1.4), and should lead to lower system costs that are passed
through to consumers in both the energy and network components of bills in the longer term.
Non-discriminatory access to consumer data and nationally harmonized data formats will also
help new suppliers and service providers to enter the market and develop innovative new
products, resulting in further competition benefits and facilitating the transition to a more
flexible electricity system364
.
Greater consumer engagement will also drive retail competition improvements, as competitive
suppliers and service providers find it easier to take market share from less competitive
alternatives. Other benefits come in terms of the higher levels of service electricity consumers
can expect from more efficient data handling, and greater consumer awareness of the market
and their own energy situation.
In addition, one may expect improvements in the targeting of measures to tackle energy poverty.
Better measurement of the number of households on energy poverty will allow Member States
and the EU to design better policies and exchange good practices. A generic definition of energy
poverty in the legislation will clarify the concept of energy poverty, improving the functioning
of the current provision and further helping knowledge dissemination and synergies across EU
policies in energy efficiency and consumer protection.
6.4.3.2.Who would be affected and how
Consumers will benefit significantly from more easily being able to compare offers in the
market, as well as lower financial barriers to switching. Whilst consumer prices may rise in the
Member States phasing out price regulation, this would be offset by higher levels of service and
the greater availability of value added products on the market. Consumers would also benefit
from increased competition and higher levels of service resulting from rules that ensure quick
and non-discriminatory access to data.
Box 8: Impacts on different groups of consumers
The benefits of the vast majority of the measures contained in the preferred options in Problem
Areas I, II and III would manifest through lower system costs and greater system reliability,
and therefore accrue to all consumers in an even manner. However, most of the measures
contained in the preferred option of Problem Area IV, above, would benefit certain kinds of
consumers more than others.
For example, whereas energy poor households would be the chief beneficiaries of new
obligations to measure energy poverty levels, the marginally increased burdens of these
obligations would be socialized amongst other ratepayers/taxpayers. In addition, whereas
phasing out price regulation would free public finances to better protect households who qualify
for targeted social support measures (i.e. vulnerable and/or energy poor consumers), the biggest
losers from this policy would be high-volume, often higher-income consumers who have
hitherto benefitted from retail prices that have been set at artificially low levels. Both these
measures can therefore be considered progressive in nature i.e. they tend to redistribute surplus
364
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” (2016) Copenhagen
Economics, and VVA.
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from relatively high-income ratepayers/taxpayers in order to increase the welfare of lower-
income ratepayers.
The measures on switching-related fees and comparison tools would predominantly benefit
consumers who are engaged in the market i.e. those who compare offers and/or switch
regularly. Whilst the measures would also increase consumer engagement levels, and whilst the
increased competition engendered by the measures would lead to more competitive offers on
the market, disengaged consumers, including consumers who may be vulnerable, will not reap
as many direct benefits.
And finally, the benefits of the billing measures would accrue predominantly to consumers who
do not engage in the market or better control their energy consumption because of insufficient
billing information or confusing bills. This may include a varied range of consumers, including
certain vulnerable consumers, or those who are time poor.
Many Member States will benefit from a clearer understanding of energy poverty, which will
have indirect positive impacts on energy poor consumers. However, Member States will also
need to collect and report more information on energy poverty as a result of requirements in
this option.
Suppliers would benefit from increased access to the market of the Member States phasing out
price regulation. New entrants and energy service companies offering innovative products
would also benefit from quick and non-discriminatory access to data. However, suppliers would
also likely face increased pressure on margins as the result of the modestly greater consumer
engagement expected. Certain suppliers may need to adjust contractual conditions and reformat
their consumer bills in order to comply with new requirements on contract termination fees and
billing information. And they would likely also bear the brunt of the significant costs to protect
energy poor consumers.
As TSOs and DSOs are normally the market actors charged with data management, they would
be the most affected by the new data management requirements – particularly the DSOs who
currently fall below the unbundling threshold as they would need to implement further measures
to ensure non-discriminatory data handling. Any increase in consumer switching would also
increase the administrative impacts to DSOs. However, all these costs would be passed through
to end consumers. In addition, network operators would benefit from the anticipated entrance
of aggregators and other energy service companies who facilitate network flexibility, as a result
of non-discriminatory data flows.
NRAs in the 17 Member States phasing out price regulation will need to significantly step up
efforts to monitor the market, ensure efficient competition, and guarantee consumer protection.
However, these impacts may be offset by increased consumer engagement, which would
naturally foster competition in the market.
6.4.3.3.Impact on businesses and public authorities
It is estimated that implementing the consumer-related elements of Option 1 (Flexible
legislation) would lead to quantifiable costs of between EUR 21 million and EUR 24 million
for the period 2020-2030. These would mainly stem from national authorities having to set up
and run certification schemes for energy comparison tools or an independently run energy
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comparison tool themselves365
. However, many suppliers would also bear costs associated with
modifying their consumer bills to comply with the modest requirements in this option366
.
Unquantifiable impacts come in the form of the reduced contractual freedom that suppliers
have, which is associated with the restriction on contract termination fees for certain kinds of
contracts only367
.
Implementing the energy poverty provisions in Option 1 (Flexible legislation) would result in
quantifiable costs of EUR 2.3 million for the period 2020-2030. These primarily result from
measuring energy poverty making reference to household income and household energy
expenditure using data already collected by Member States368
.
Significant, albeit unquantifiable costs are associated with creating a level playing field for
access to data in Option 1 (Flexible legislation). In particular, ensuring that Member States
implement a standardised data format at the national level will significantly impact many
market actors (suppliers, DSOs, third parties such as energy service companies, data
administrators), who would have to redesign their IT systems to accommodate this format.
However, these costs will be mitigated by the fact that measures can be applied independently
of the data management model that each Member State has chosen. This reduces the potentially
very significant scope for sunk costs if Member States were to all conform to a common data
management model369
.
Impacts of Policy Option 2 (Harmonization and extensive safeguards for consumers
addressing all problem drivers)
6.4.4.1.Economic Impacts
Option 2 (Harmonization and extensive safeguards) could lead up to up to EUR 3.5 billion in
direct benefits to consumers for the period 2020-2030, which come as a result of: (i) an outright
ban on all switching-related charges370
; (ii) further improvements to the switching rate as a
result of every Member State establishing a government (funded) price comparison tool
guaranteed to work in the consumer's interest371
; (iii) an improved ability for consumers to
identify the best offer in the market through fully standardised billing information372
.
However, there is greater uncertainty surrounding the benefits that stem from these
interventions. Whilst an outright ban on all switching-related charges would increase the
financial incentive to switch, it could also make it more difficult to finance certain energy
service investments (i.e. solar panels or energy efficiency upgrades packaged with energy
supply contracts) if implemented poorly. It might also result in a smaller range of tariffs
365
See Annex 7.5, Section 7.5.5.
366
See Annex 7.6, Section 7.6.5.
367
See Annex 7.4, Section 7.4.5.
368
See Annex 7.1, Section 7.1.5 and Table 16.
369
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” Copenhagen Economics,
and VVA (2016).
370
See Annex 7.4, Section 7.4.5.
371
See Annex 7.5, Section 7.5.5.
372
See Annex 7.6, Section 7.6.5.
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available to consumers. Not all government (funded) price comparison tools may work better
for consumers than the comparison tools already available on the market. And it may be
difficult, if not impossible, to devise a standard EU bill design that accommodates differences
in consumer preferences and market conditions in all Member States.
Whilst phasing-out blanket price regulation in the 17 Member States still practicing it would
lead to improved retail competition, defining the conditions under which price regulation could
continue at the EU level would be problematic. In particular, permitting price regulation for
households who consume below a certain price threshold would not accurately target those
most in need of assistance. In addition, permitting regulators to only set price caps above cost
would be difficult to enforce due to opaque cost structures. It also risks holding back
investments in product innovation and service quality, which require higher margins373
. As with
Option 1 (Flexible legislation), the impact of phasing out price regulation on retail price levels
is impossible to quantify, whereas the evidence strongly suggests it will lead to higher levels of
consumer satisfaction.
Defining a specific EU data management model for all Member States, such as an independent
central data hub, would bring similar benefits to Option 1 in terms of helping new suppliers and
service providers to enter the market. In addition, it would be easier to enforce at the EU level374
.
6.4.4.2.Who would be affected and how
Consumers will benefit from more easily being able to compare offers in the market, as well
as lower financial barriers to switching. However, these gains may be tempered by a reduction
in the availability of beneficial products on the market. Whilst consumer prices may rise in the
Member States phasing out price regulation, this would be offset by higher levels of service and
the greater availability of value added products on the market. Consumers would also benefit
from increased competition and higher levels of service resulting from rules that ensure quick
and non-discriminatory access to data.
Energy poor consumers in many Member States would enjoy significant benefits from the
comprehensive set of disconnection safeguards outlined as they are more likely to be on risk of
disconnection. Whilst many Member States will benefit from a prescriptive EU definition of
energy poverty and from better information on the energy efficiency of the housing stock, the
benefits of better measurement may not composite for the significant resources required to
survey the housing stock at national level. Energy poor and vulnerable consumers may also be
impacted by more poorly targeted support as the result of permissible instances of price setting
being defined at the EU-level, rather than being assessed on a case by case basis.
Suppliers would benefit from increased access to the market of the Member States phasing out
price regulation. However, all suppliers would need to significantly reformat their bills in order
to comply with a standard EU bill design. They would likely also bear the brunt of the very
significant costs to protect energy poor consumers introduced under Option 2 (Harmonization
and extensive safeguards) – in particular the complete ban on winter disconnections. However,
373
See Annex 7.2, Section 7.2.5.
374
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” Copenhagen Economics,
and VVA (2016)
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new entrants and energy service companies offering innovative products would benefit from
quick and non-discriminatory access to data.
As TSOs and DSOs are normally the market actors charged with data management, they would
be the most affected by the requirement to establish a standard EU data management model that
all Member States. Indeed, since many would incur significant sunk costs in adopting a model
different from their own, the impacts could be significant. However, all these costs would be
passed through to end consumers. In addition, network operators would benefit from the
anticipated entrance of aggregators and other energy service companies who facilitate network
flexibility, as a result of non-discriminatory data flows.
NRAs in the 17 Member States phasing out price regulation will need to significantly step up
efforts to monitor the market, ensure efficient competition, and guarantee consumer protection.
However, these impacts may be offset by increased consumer engagement, which would
naturally foster competition in the market.
6.4.4.3. Impact on businesses and public authorities
It is estimated that implementing the consumer-related elements of Option 2 ((Harmonization
and extensive safeguards) would lead to quantifiable costs of between EUR 42 million and EUR
51 million for the period 2020-2030. These would mainly stem from national authorities having
to set up and run energy comparison tools375
, and energy suppliers having to heavily modify
their consumer bills to comply with the requirements in this option376
. Unquantifiable impacts
come in the form of the greatly reduced contractual freedom that suppliers have, which is
associated with the ban on contract termination fees377
.
Implementing the energy poverty provisions in Option 2 (Harmonization and extensive
safeguards) would result in quantifiable costs of between EUR 1.2 billion and EUR 3.8 billion
for the period 2020-2030. Unless public authorities step in, these costs would most likely fall
on suppliers and result from: (i) the additional costs of unpaid bills resulting from the
requirement for suppliers to give all customers a disconnection notice of at least two months;
(ii) the additional costs of unpaid bills resulting from the cessation of winter disconnections;
and (iii) refinancing costs resulting from the obligation to offer all consumers the possibility to
delay payments or restructure their debt prior to disconnection378
.
As these costs associated with disconnection safeguards are large, it is likely that this option
would result in distortions to competition in Member States where the public does not cover
these costs. Whilst suppliers active in such markets could raise margins to socialize losses from
unpaid bills, certain suppliers – especially smaller ones who are less well equipped to deal with
the additional pressure on their operations – may seek to avoid entering markets where there
are likely to be significant risks of disconnections.
Member States may be better suited to design these schemes to ensure that synergies between
national social services and disconnection safeguards are achieved. These synergies may also
375
See Annex 7.5, Section 7.5.5.
376
See Annex 7.6, Section 7.6.5.
377
See Annex 7.4, Section 7.4.5.
378
See Annex 7.1, Section 7.1.5 and Table 24.
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result in public sector savings which may be significant given the substantial costs of these
measures and the overlap between social policy and disconnections for non-payment.
Very significant costs are associated with creating a level playing field for access to data in
Option 2 (Harmonization and extensive safeguards). A mandatory data handling model will
imply the administrative costs of defining and designing such a model, and more importantly
high sunk costs for existing data models and additional costs for rebuilding a new one, both in
terms of personnel costs and IT infrastructure. Designing and building a new data handling
model is a complex procedure and may well take several years of planning and implementation.
For example, in Denmark alone, the central data hub took more than 4 years to design and
develop in its simple form, and 7 years in its enhanced form, and is estimated to a cost of
approximately EUR 165 million, where approximately EUR 65 million accrued to the data hub
administrator (the TSO), and around EUR 100 million accrued to DSOs and energy suppliers379
.
Environmental impacts
The legislative options examined above – Option 1 (Flexible legislation) and Option 2
(Harmonization and extensive safeguards) – can each be expected to have significant, albeit
indirect, environmental benefits because they enable the uptake of technologies that help the
electricity system become more flexible, thus enabling higher levels of variable and
decentralized RES E penetration. Non-discriminatory access to consumer data and a phase-out
of regulated prices will allow new entrants and energy service companies to develop and offer
value-added products such as dynamic price supply contracts, incentive-based demand response
services, green tariffs, and supply contracts with bundled energy efficiency or rooftop solar
investments. In addition, tackling the barriers to consumer engagement will increase the
selective pressure for such new services. The measures will benefit smaller consumers in
particular, the group of market actors which the analysis has shown represents the greatest
remaining source of low hanging fruit in terms of system flexibility potential.
In addition, phasing out blanket price regulation – particularly in Member States with very low
margins – will help address the high levels of electricity and gas consumption caused by
artificially low prices. This will make it easier to achieve climate objectives and provide a
proper price signal for energy efficiency investments.
Impacts on fundamental rights regarding data protection
A key building block for the completion of the Digital Single Market and the Energy Union
includes strong and efficient protection of fundamental rights in a developing digital
environment. The proposed policy measures on data management were developed in this
context, to ensure widespread access and use of digital technologies while at the same time
guaranteeing a high level of the right to private life and to the protection of personal data as
enshrined in Articles 7 and 8 of the Charter of Fundamental Rights of the EU.
As data on individual consumers' consumption and billing become central to the deployment of
distributed energy resources and the development of new flexibility services, the measures on
data management in the various policy options proposed (from compliance with data protection
379
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” Copenhagen Economics,
and VVA (2016).
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legislation and the Third Energy Package - Option 0 (Baseline); to further introduction of
specific requirements on data handling responsibilities based on principles of transparency and
non-discrimination – Option 1 (Flexible legislation); and implementation of a specific data
management model to be described in EU legislation – Option 2 (Harmonization and extensive
consumer safeguards)) seek to ensure the impartiality of the entity which handles data and to
ensure uniform rules under which data can be shared. Indeed, consumers must be reassured that
their consumption and metering data remain under their control. Access to a consumer's
metering or billing details can only happen when authorised by that consumer and under the
condition that the personal data protection and privacy are guaranteed.
In this light, the data management policy options are therefore fully aligned and further
substantiate the fundamental rights to privacy and protection of personal data of Articles 7 and
8 of the Charter of Fundamental Rights of the EU, as well as with the General Data Protection
Regulation and with the Commission Recommendation on the Data Protection Impact
Assessment Template for Smart Grid and Smart Metering Environments.
Box 9: External factors and the assessment of the impacts
Price signals and long-term confidence that costs can be recovered in reasonable payback times
are essential ingredients for a well-functioning market. In a market which is not distorted by
external costs and interventions, the level and variability of the spot price on the wholesale
market, plays a role in signalling the need for investments in new resources. With external costs
and in the absence of the right short- and long-term price signals, it is more likely that
inappropriate investment or divestment decisions are taken, i.e. too-late decisions or technology
choices that turn out to be inefficient in the long run. It also renders it more likely that capacity
exits that is valuable for the system as a whole.
The impact assessment demonstrates that an improved market design can lead to a much more
efficient utilisation of resources and establish the market as a main driver of investments in
generation assets (even if only progressively and not fully for all RES E technologies (See Box
7)). This will be mainly driven by the restoration of the economic merit order curve (see Section
6.1.2, Figure 11) and the improved reflection of scarcity in short term electricity prices (see
Section 6.2.6.4, Table 21), both resulting from the measures proposed by the current initiative,
combined with the exit of non-economical units as a result of the transition towards a market
equilibrium (See section 6.2.6.3, Table 18) from the current overcapacity.
Market exit should be brought about by market forces and the initiative generally aims at
removing existing obstacles to this in regulation. Market exit is framed to some degree by the
measures proposed under Problem Area II. The extent to which a system with capacity
remuneration exacerbate or not existing excess capacity depends on how the capacity
requirement is set within the mechanism. If the system is correctly calibrated by means of a
genuine resource adequacy assessment (See Problem Area II, Option 2) there will be no
overcapacities. This is both important to ensure that CMs do not incite lower than economically
optimal wholesale prices, which would inhibit investments, and prevent delays upon the
transition path by preventing exit of non-essential resources. Moreover, the measures under
Problem Area I and Problem Area II, option I, will ensure that prices better reflect the real value
of electricity, affecting specifically the remuneration of electricity generation units that operate
less often but provide security and flexibility to the system. For the same reason, it is important
that TSOs (as responsible entities for overall operation of the system) define and remunerate
ancillary services appropriately, remunerating generators for the full range of services they
provide. These market improvements affect exit in the sense that they ensure that only those
resources will exit that genuinely have no value for the system as a whole.
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It is true that overall price developments in the electricity sector will also depend on cost factors
beyond the present initiative, such as the carbon prices, prices for primary fuels or technological
costs.
These external factors would mainly impact the level of wholesale prices380
, possibly affecting
to a certain extent the overall level of benefits to be expected from the present initiative or their
distribution among individual options (in manners which are not easily predictable in view of
the many interactions that take place). However, such changes are not expected to affect the
order of preferred options. Indeed, the proposed measures in essence derive their benefits from
the removal of current market distortions and imperfections, while at the same time having
comparably small implementation costs. These are benefits that are inherent to the measures
themselves and do not depend on the precise context in which they are implemented. Moreover,
strong synergies exist between the sets of options within the package (See Section 7.5.1),
meaning that the overall benefits of a given option are more affected by the coherence of the
package as a whole, than by its interactions with factors outside the present initiative.
Low wholesale prices though would affect investments in electricity resources such as demand
response, RES E and peaking plant investments. Concerning demand response, the aim of the
initiative is to offer to the consumers the opportunity to participate in the market if they wish
to, either directly (e.g. industrial consumers) or indirectly (e.g. via aggregators). The initiative
is not aiming to affect the level and variability of wholesale prices, but to make the functioning
of the markets more efficient so that it can deliver price signals reflecting the value of electricity
at each moment of time and the need for future investments (and in what type). Although
persistent low electricity wholesale prices could lead to low investments, this is a normal
outcome if it is a result of market dynamics and not distortions. For example a system
characterized by overcapacity should have low prices to signal that investments are not needed.
It is equally noteworthy that the modelling work (as presented in section 6.2.6.4) indicates that
in the mid-long term, even in the presence of larger shares of variable RES E, conventional
generators will set the marginal price in a sufficient number of hours to produce meaningful
price signals to guide overall market operations. Increasing RES E penetration therefore does
not necessarily give rise to low(er) average wholesale market prices.
The assessment of the benefits also depends to a certain degree on the progress made in the
implementation of measures proposed by parallel initiatives, considered as part of the baseline
for the present initiative, most notably the REDII. In this context, it is important to note that the
assessment of the present initiative assumes the full phase-out of non-market based support
mechanisms by 2030 for RES E, i.e. feed-in-tariffs would be phased-out and replaced by
schemes that expose RES E to price signals, as for instance premium based schemes. Such
investments would be further triggered by setting support-levels through auctioning as RES E
investments projects would then be incentivised to develop business models that optimise
380
For example the prices projected by PRIMES/OM tend to be quite higher even in 2020 compared to the
currently observed market prices. Several reasons contribute to this: (a) fuel costs are projected to increase by
25% for gas and coal, (b) demand increases, (c) few new investments take place (mainly RES to reach the
2020 target); this point combined with demand increase described above , make it the first step in reducing
the currently observed overcapacity, (d) a well-functioning EoM without distortions is assumed, (e) scarcity
bidding is assumed, in the sense that there is a mark-up on the bids so that generators can recover their full
costs only from the market in the long-run.
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market based returns. These are reasonable assumptions in view of the rules that are expected
to be in place well before 2030 (see in particular Annex IV).
The success or failure to implement such measures for RES E in time would have a direct
impact on the effectiveness of the present initiative. A partial or delayed implementation of the
closely associated policies, as proposed in the revised Renewable Energy Directive, especially
if combined with the prolongation of existing distortions, would reduce the efficiency of the
market design initiative in the medium term and postpone its expected benefits further into the
future. On the contrary, an expedient implementation would achieve the establishment of
efficient markets and the delivery of the associated benefits sooner.
6.5. Social impacts
European social partner's joint position381
:
"Citizens and especially low-income households should be able to pay their bills"
The new market design should be: "ensuring that the provision of electricity is secure, safe,
reliable and reasonably priced"
It was also underlines that: "workers in and outside of the electricity sector are relying on a
stable electricity market for their jobs. There is currently a precarious situation for many
workers in the electricity sector, especially among power plant workers. Many plants are not
adequately remunerated for the services they provide (e.g. flexibility, security of supply) and
therefore several companies foresee closure. Workers could lose their jobs".
A shown above, more efficiently organised cross-border electricity markets can avoid
significant costs for energy customers. Given the importance of energy costs for many
companies and for individual households, realising the possible cost savings can be expected to
improve competitiveness of commercial players (with positive impact on jobs and growth) and
on private customers (especially relevant for low-income households).
The electricity industry (i.e. production, transmission, distribution and trade of electricity) is a
key economic sector with a turnover amounting to not less than EUR 1.182 billion in 2014382
.
EU households spent EUR 148.2 billion on electricity bills (EUR 97.4 billion on gas), which
means that every household had to pay EUR 686,- per year for electricity (EUR 451,- for gas)
on average, with important variations between single Member States383
. Especially for low-
income households, costs for electricity can eat up large parts of the available income384
. Also
382
Eurostat Data for 2014.
383
Eurostat Data for 2014.
384
In 2014, EU households in the lowest income quintile spent an average of 9% of their household income on
electricity and gas, whereas middle income households spent 6% on electricity and gas. Source: DG ENER
Data.
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for many industries, especially those in competition at a world-wide scale, energy costs are an
important factor for competitiveness. EU wholesale electricity prices are still higher than in
other regions in the world (e.g. around 30% compared to the U.S.385
). Avoiding unnecessary
prices increases by an intelligent organisation of electricity markets (e.g. market-based
solutions and using advantages of aggregation across borders) can therefore save jobs and create
growth in the EU.
The possible measures analysed to better adapt the current market rules to decarbonised
electricity markets through revised legislation (See options in 'Problem Area I' e.g. re-
establishing the level playing field, improving short-term markets and removing barriers for
demand response and distributed resources) would allow to integrate electricity generated from
RES E at lower costs. They would also increase the potential for cross-border trade, leading to
more competition and better possibilities to level out production and demand differences across
larger areas.
Grid fees and other system costs have increased in recent years due to the suboptimal
organisation of markets, but also through the need to adapt the infrastructure to decentralised
generation. Better organised electricity markets would therefore not only save costs for
electricity, but also keep grid costs in check (e.g. by limiting the necessary costs for TSO-
interventions to keep the grid stable, so-called 're-dispatching'386
). Measures to keep the further
expansion of grid fees in check can therefore bring tangible benefits to industry and private
(low-income) customers387
.
The analysed measures to improve investors' certainty and limit state interventions ('Problem
Area II', e.g. better co-ordinating capacity mechanisms between countries) can also be
expected to have a positive impact on competitiveness and on energy bills to of households. As
shown above, fragmented adequacy planning and capacity mechanisms leads to higher energy
costs and network charges. If each Member State builds its backup generation in its own country
without taking into account generation from neighbours, this will necessarily lead to
inefficiencies through unnecessary duplication of investments388
. Notably Options 2 (regional
adequacy assessment) and Option 3 (cross-border openness of capacity mechanisms) would
help to keep the prices for state interventions concerning capacity mechanism in check. 389
385
See e.g. Communication on "A Framework Strategy for a Resilient Energy Union with a Forward-Looking
Climate Change Policy" of 25.2.2015 COM (2015), p.3.
386
See e.g. the estimations for Germany, where grid tariff component already exceeds the energy costs and where
re-dispatching costs are estimated to grow to EUR 4 billion/year in the next years, see e.g.
http://www.zfk.de/artikel/bis-zu-vier-milliarden-fuer-engpassmanagement-2023.html .
387
According to the Commission's modelling, the assessed options under Problem Area I reduce the average cost
of total demand, i.e. the cost of each MWh generated, apart from Option 1(a) (level playing field). More
specifically and compared to the baseline, Option 1(a) (level playing field) increases it by 6%, while Options
1(b) (strengthening short-term markets), 1(c) (demand response/distributed resources) and Option 2 decrease
it by 6%, 9% and 11%, respectively.
388
See for further evidence on the disadvantages of fragmented CMs above, Problem Area II (investment
uncertainty/fragmented CMs), discussion of Option 3.
389
Option 4 (EU wide capacity market) is not considered here as it was already discarded above. However, it is
useful to note that it would also be more costly (about 5% pursuant to the Commission's model) than the other
options.
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In a similar manner, the analysed measures to improve risk preparedness ('Problem Area III',
e.g. better co-ordinated planning and rules to better coordinate possible load shedding in case
of crises) options are likely to have a positive impact for EU citizens and businesses. Previous
blackouts have shown that even in the "traditional" electricity market with low shares of RES
E so-called "cascade blackouts" resulting from problems in other Member States can seriously
harm businesses and customers, in particular those depending on electrical heating (see on the
system blackouts in 2003 and 2006 above, section 6.3.2.1). Amounts of variable RES E have
increased ever since, and so has the importance of a reliable electricity grid for citizens and
customers (e.g. increased risks of blackouts for internet-driven businesses and private
communication). Minimising blackout risks through better regional coordination will therefore
contribute to avoid negative impacts on businesses and households.
Finally, the analysed measures to enhance performance of retail markets (Problem Area IV,
e.g. measures facilitating to change suppliers, more targeted support for "energy-poor")
customers in the transition to market-based prices, etc.) will also have a positive impact on
businesses and households. In addition, the proposals relative to the phasing out of regulated
prices, should incentivise Member States which currently use blanket price regulation to
provide targeted support for vulnerable and energy poor consumers instead of providing an
indirect support to all consumers regardless of their circumstances as is currently often the case.
Improvements to the health390
and well-being of energy poor consumers, savings to the health
sector391
, and economy-wide productivity gains392
can be expected from the packages of energy
poverty measures evaluated above. Due to the indirect nature of the way these measures would
address energy poverty, and a lack of specific data on their impact, these benefits are impossible
to quantify.
Health impacts most commonly associated with energy poverty and under-heated dwellings can
be fatal, resulting in higher mortality during winter period. Benefits of effective action to reduce
excess winter mortality could be substantial given the scale of the issue. In fact independent
research shows that over 200,000 excess winter deaths have occurred across 11 Western
European countries alone393
during the winter of 2014/2015. In addition to the physical impacts,
cold homes are directly related to mental health problems.
The energy transition and decarbonisation policies play a key role in developing Europe’s
competitive edge internationally as growth and jobs increasingly will have to come from
innovative products and services which are closely linked to sustainable and smart solutions.
390
"Fuel Poor & Health. Evidence work and evidence gaps. DECC. Presented at Health, cold homes and fuel
poverty Seminar at the University of Ulster". 2015. Cole, E. Available at:
http://nhfshare.heartforum.org.uk/HealthyPlaces/ESRCFuelPoverty/Cole.pdf; "Towards an identification of
European indoor environments’ impact on health and performance - homes and schools. 2014. Grün &
Urlaub, Excess winter mortality: a cross-country analysis identifying key risk factors. Journal of
Epidemiology & Community Health" 2003. Healy.
391
"2009 Annual Report of the Chief Medical Officer (London: Department of Health", 2010. Donaldson, L.
392
"Indoor cold and mortality. In Environmental Burden of Disease Associated with Inadequate Housing",
(Bonn: World Health Organisation (Regional office for Europe)). 2011. Rudge, J.
393
Excess mortality in Europe in the winter season 2014/15, EuroMOMO, source:
http://www.euromomo.eu/methods/pdf/winter_season_summary_2015.pdf
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Recent studies on the impact of EU’s energy and climate targets suggest a net increase in job
demand in the power generation market as a result of the transition of the energy system. One
factor behind this is the higher labour intensity in power generation from renewable sources
compared to gas or nuclear. There will also be a change in the employment structure as many
of the jobs associated with the energy transition require higher skills and increased supply of
workers that outweigh job losses in somewhat less qualified jobs in conventional energy
generation. The total number of jobs in the power sector (operation, maintenance, construction,
installation, and manufacturing) is forecast to increase by around a half by 2030394
. Further
positive impacts are expected in the indirect and substitution effects. 395
Whereas these effects
are related to the energy transition as such and cannot be attributed solely to the measures
assessed here, by ensuring a cost effective transition in more smoothly functioning markets,
these beneficial social effects stand a much increased chance of being realised and retained.
7. COMPARISON OF THE OPTIONS
Taking into account the impacts of the options and the assessment presented in Section 6, the
following section compares the different options against each other using, the baseline scenario
as the reference and applying the following criteria:
- Effectiveness: the options proposed should first and foremost be effective and thus
be suitable to addressing the specified problem;
- Efficiency: this criterion assesses the extent to which objectives can be achieved at
the least cost (benefits versus the costs).
The tables provide a summary of the assessment of the policy options against these criteria. The
options are measures against the criteria applied for the assessment of the impacts specified for
options developed to address each Problem Area (See Sections 6.1, 6.2, 6.3 and 6.4
respectively) and the comparison of the options below. Each policy option is rated between "--
-" (very negative), 0 (neutral) and "+++" (very positive).
The options are not compared here on the basis of their coherence with parallel initiatives. The
design of the baseline already assures that all option are compatible with parallel initiatives. In
particular, the baseline in the present impact assessment ensures that under all investigated
options, the RES E targets (as well as other policy targets) are met. Consequently, comparing
options on the basis of their compatibility with the RED II initiative is meaningless.
7.1. Comparison of options for adapting market design for the cost-effective operation
of variable and often decentralised generation, taking into account technological
developments
All options, except for Option 0 (baseline scenario) can contribute to achieving to a degree the
objective of adapting the market design to make it suitable for the cost-effective operation of
variable, often decentralised generation of electricity and capture some of the potential social
welfare and environmental opportunities (e.g. lower wholesale electricity prices; incentivise the
394
Between 2 and 2.5 million in 2030, depending on the decarbonisation scenario (source Neujobs/CEPS)
395
Neujobs/CEPS report “Impact on Decarbonisation of the Energy System on Employment in Europe” 2015 ,
The methodology is based on applying “employment factors” (i.e. labour intensities) of different energy
technologies to changing energy mixes as projected by the EU decarbonisation scenarios.
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increase of low carbon electricity generation). However, the effectiveness and efficiency of the
different options, as well as their impact, vary significantly.
Table 25: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Impact on business
and public
authorities
Policy Option 0
(Baseline)
0 0 0 0 0
Policy Option
1(a) (level
playing field)
+ + + - -
Policy Option
1(b)
(strengthening
short-term
markets)
++ ++ ++ -- --
Policy Option
1(c) (demand
response/
distributed
resources )
+++ ++ +++ -- --
Policy Option 2
(fully integrated
markets)
+++ +++ ++ --- ---
Source: DG ENER
In summary:
Option 0 (baseline scenario): will fall short in providing for the adaptation of the market design
to the new realities of the interconnected electricity system and will not allow the internal
electricity market to reach its full potential.
Options 1(a) (level playing field), 1(b) (strengthening short-term markets) and 1(c) (demand
response/distributed resources) reflect an increasing degree of ambition regarding the
integration of the national electricity markets, with Option 1(c) building on the packages of
measures covered under Options 1(a) and 1(b) and including additional measures. All these
options present a compromise between bottom-up initiatives and top-down steering of the
market development, without substituting the role of national governments, regulators and
TSOs by a centralised and fully harmonised system. Option 1(a) and Option 1(b) are
significantly more efficient than Option 0 but cannot be expected to fully meet the specific
objectives, given that these options do not cover measures for including additional resources
(i.e., demand response, distributed RES E and storage) in the electricity markets to further
increase the flexibility of the electricity system and the resources for the TSOs to manage it.
The value of these additional resources for the efficient operation of decarbonised electricity
markets and hence for the energy transition should not be underestimated. Option 1(c) provides
a more holistic, effective and efficient package of solutions and has the added value that it will
not lead to significant additional impacts on stakeholders or on businesses and public
authorities. Indeed, while Option 1(c) may lead to additional administrative impacts for
Member States and competent authorities regarding the implementation and monitoring of the
measures, these impacts will be offset by lower barriers to entry to start-ups and SMEs, by the
benefits to market parties from more stable regulatory frameworks and new business
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opportunities as well as by the benefits to consumers from more competition and access to
wider choice.
As regards Option 2 (fully integrated market), while having advantages in terms of lower
coordination requirements (i.e., a fully integrated EU-market can be operated more efficiently),
the results of the assessment indicate that the move towards a more integrated European
approach has less significant economic added value since most of the benefits will have already
been reaped under the regional, more decentralised approach under Option 1(c) (demand
response/distributed resources). Moreover, Option 2 (fully integrated market) has the
disadvantage of requiring significant changes to established practices, systems and processes
and hence a significant impact on stakeholders, businesses, Member States and competent
authorities. Such profound changes of national competences in favour of centralised powers
"across the board" would also raise serious questions concerning the subsidiarity of the
measure. Therefore, in view that for Option 2 (fully integrated market) the efficiency gains are
not significantly higher compared to Option 1(c) (demand response/distributed resources) but
the impacts and required changes to national competences much greater, it appears
disproportionate and not the most appropriate option at the current stage of development of the
internal electricity market.
In the light of the previous assessment, the preferred option would be Option 1(c) (pulling
demand response and distributed resources in the market) (which encompasses Options
1(a) (level playing field) and 1(b) (strengthening short-term markets). This option is the
best in terms of effectiveness and, given its impacts, has been demonstrated to be the most
efficient as well as consistent with other policy areas.
This preferred Option has large support among stakeholders. No support exists for retaining the
status quo (i.e. Option 0 or 0+) whereas Option 2 (fully integrated market) was generally
deemed a step too far. It is noted that hesitations by stakeholders on aspects of the preferred
option, such as the removal of priority dispatch provisions under Option 1(a) (level playing
field), are based on the notion that this should go hand in hand with a reform rendering the
market more adapted to RES E resources, which is what is foreseen under Option 1(b)
(strengthening short-term markets) and Option 1(c) (demand response/distributed resources)396
.
7.2. Comparison of Options for facilitating investments in the right amount and in the
right type of resources for the EU
All options, except for Option 0 (baseline scenario), can improve the overall cost-efficiency of
the electricity sector and contribute towards achieving the objective of facilitating investments
in the right amount and in the right type of resources for the EU. However, the effectiveness
and efficiency of the different options, as well as their viability and impact, vary significantly.
396
Reference is made to Section 5.1.1 through to 5.1.5 and Sections 7 of Annexes 1.1 through 3.4 for more
detailed representations of stakeholders' opinions.
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Table 26: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Impact on business
and public
authorities
Policy Option 0
(Baseline
scenario)
0 0 0 0
0
Policy Option 1
(Reinforced
energy-only
market without
CMs)
+ + + +/- -
Policy Option 2
(reinforced
energy-only
market + EU
adequacy
assessment for
CMs)
+ + + + +
Policy Option 3
(reinforced
energy-only
market + EU
adequacy
assessment for
CMs + EU
framework on
cross-border
participation
CMs)
++ ++ ++ ++ ++
Source: DG ENER
In summary:
Option 0 (baseline scenario), which would assume the existence of national capacity
mechanisms without coordination at EU-level will fall short of achieving the specific objectives
of improving market functioning to reduce the need to have recourse to state intervention and
of ensuring that state-interventions, where needed, are more coordinated, efficient and
compatible with the EU's internal energy market.
Option 1 (reinforced energy-only market without CMs) can improve the overall cost-efficiency
of the electricity sector significantly. The analysis shows that undistorted energy-only markets
increase overall system efficiency as make sure that resources are better utilized across the
borders, demand can better participate in markets, and renewables can be better integrated into
the system without additional need for subsidies. This will in turn decrease the need for capacity
mechanisms (which are often introduced as a reaction to markets which do not produce correct
price signals due to state interventions).
The analysis also shows that reinforced energy-only markets can in principle provide the right
signals for market operation and ensure resource adequacy. Option 1 also has slightly more
positive environmental impacts than any of the other options.
However, markets are still characterised by manifold regulatory distortions today, and
removing the distortive effects will not be possible with immediate effects in many Member
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States. The observation that undistorted markets can provide the necessary investment signals
has therefore to be weighed against the observation that a significant transition time to phase
out the existing distortions will be necessary. Furthermore, some national distortions (e.g.
resulting from differences in taxation) cannot be addressed by a reform of energy law and are
therefore likely to continue.
Investors also do not have perfect foresight of market conditions, and confidence that they will
not be distorted for the economic lifetime of their investments. Such certainty is increasingly
difficult to find, often due to uncertainty as to the regulatory measures that could be taken in
the future that may supress prices and reduce the load factors of plants compared to the
assumptions made when the investment decision is taken. In a market that requires more and
more varied sources of funding that in many cases are competing with other, non-electricity,
projects for capital, relying solely on the energy price as a basis for investment is not always
easy. Uncertainty about future policy developments or the perception thereof can create
'missing money' that may require addressing397
.
The legislator should also take into account that the level of interconnection is markedly
different among Member States. This militates for a more nuanced approach than a
straightforward EU-wide prohibition of CMs.
In this perspective, not allowing Member States to introduce any type of CMs would mean that
Member States would be prevented from addressing adequacy concerns with CMs. As those
concerns might be legitimate, this option is not considered to be appropriate.
But, as developed in Chapter 2.2.1 undistorted energy price signals are fundamental irrespective
of whether generators are solely relying on energy market incomes or also receive capacity
payments. Therefore the measures aimed at removing distortions from energy-only markets
discussed under Option 1 (e.g. scarcity pricing or reinforced locational signals) are 'no-regrets'
and assumed as being integral parts of Options 2 (CMs + EU adequacy assessment) and 3 (CMs
+ EU framework on cross-border participation)..
When compared with the baseline, Option 2 (CMs + EU adequacy assessment) can improve
the overall cost-efficiency of the electricity sector as significant savings can be achieved
through establishing an EU-wide approach to resource adequacy assessments as opposed to
national-based adequacy assessments. At the same time Option 2 does not allow reaping the
full benefits of cross-border participation in CMs.
Option 3 (CMs + EU framework on cross-border participation) (which includes the market
reforms under Option 1 and the regional assessment under Option 2) goes beyond Option 2 as
it proposes additional measures to avoid fragmentation of CMs. This would achieve significant
additional net benefits when compared with Option 2. This is because it makes sure that foreign
resource providers can effectively participate in national capacity mechanisms and avoids
competition and market distortions resulting from capacity payments which are reserved to
domestic participants. By remunerating foreign resources for their services this option reduces
397
It must however also be recognised that CMs by themselves are not a panacea as they can equally be a source
of regulatory uncertainty. Indeed, in practise CM designs are regularly found imperfect and consequently
adjusted on a regular basis.
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investment distortions that might be present in Option 2 as a result from uncoordinated
approaches to cross-border participation.
In view of the assessment above, Option 3 (CMs + EU framework on cross-border
participation) (encompassing options 1 and 2) is the preferred option.
This preferred Option has large support among stakeholders. There is almost a consensus
amongst stakeholders on the need for a more aligned method for generation adequacy
assessment. A majority of stakeholders support the idea that any legitimate claim to introduce
CMs should be based on a common methodology. When it comes to the geographical scope of
the harmonised assessment, a vast majority of stakeholders call for regional or EU-wide
adequacy assessments, while only a minority favour a national approach. There is also support
for the idea to align adequacy standards across Member States. Stakeholders clearly support a
common EU framework for cross-border participation in CMs398
.
Most stakeholders including Member States agree that a regional/ European framework for
CMs is preferable. Member States, however, might want to keep a large degree of freedom
when proposing a CM. They might claim that beyond a revamped regional/ EU generation
adequacy assessment, there is legitimacy for a national assessment based on which they can
claim the necessity of their CM. Similarly Member States might instinctively want to rely more
on national assets and favour them over cross-border assets.
7.3. Comparison of options for improving Member States' reliance on each other in
times of system stress and reinforcing coordination between Member States for
preventing and managing crisis situations
All options, except for Option 0 (baseline scenario), can contribute to achieve the objective of
improving Member State's reliance on each other in times of system stress and reinforcing their
coordination and cooperation at times of crisis situation. However, the effectiveness and
efficiency of the different options, as well as their viability and impact, vary significantly.
398
Reference is made to Section 5.2.1 through to 5.2.9 and Sections 7 of Annexes 4.1 through 5.2 for more
detailed representations of stakeholders' opinions.
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Table 27: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Impact on
business and
public authorities
Policy Option 0
(Baseline
scenario)
0 0 0 0 0
Policy Option 1
(Common
minimum EU
rules)
++ ++ + + 0/-
Policy Option 2
(EU rules +
regional
cooperation)
+++ +++ ++ ++ 0/-
Policy Option 3
(Full
harmonisation)
+++ -- + + 0/--
From the point of view of impacts, particularly costs and administrative impact, Option 1
(Common minimum EU rules) could in principle appear as preferred option. However, the
performance in terms of effectiveness and efficiency is limited compared to Option 2 (EU rules
+ regional cooperation) and Option 3 (Full harmonisation). Additionally, impacts associated
with Option 3 (Full harmonisation) are neither proportionate nor fully justified by the
effectiveness of the solutions, which makes Option 3 (Full harmonisation) perform poorly in
terms of efficiency compared to Option 2 (EU rules + regional cooperation).
Overall, the more harmonized approach to security of supply through minimum rules pursued
by Option 1 (Common minimum EU rules) would not solve all the problems identified, in
particular, the uncoordinated planning and preparation ahead of a crisis. As regards Option 1
(Common minimum EU rules), the main drawback of this approach is that each Member State
would be drafting and adoption the national risk preparedness plans under its own
responsibility. While the regionally coordinated plans with crisis scenarios identified at regional
level and the agreement of some aspects of the plan (e.g. load shedding plan) in a regional
context, aim at ensuring that all regional specificities are fully considered. Given the urgency
to enhance the level of protection against cyber threats and vulnerabilities, it must be concluded
that Option 1 (Common minimum EU rules) regarding cybersecurity is not recommended,
because it is not viable for reaching the policy objectives, given that the effectiveness would
depend on whether the voluntary approach would actually deliver a sufficient level of security.
Option 2 (EU rules + regional cooperation) addresses many of the shortcomings of Option 1
(Common minimum EU rules) providing a more effective package of solutions. In particular,
the regionally coordinated plans ensure the regional identification of risks and the consistency
of the measures for prevention and managing crisis situations. For cybersecurity this option
creates a harmonised level of preparedness in the energy sector and ensures that all players have
the same understanding of risks and that all operators of essential services follow the same
selection criteria for the energy sector throughout Europe.
Overall, Option 3 (Full harmonisation) represents a highly intrusive approach that tries to
address possible risks by resorting to a full harmonisation of principles and the prescription of
concrete solutions. For example, the preparation of risk preparedness plans at regional level
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ensures full coherence of actions ahead and during a crisis. However, the major limitation is
that national specificities could not be addressed through regional plans. The detailed
"emergency rulebook" with an exhaustive list of measures would also reduce the room of
manoeuvre of Member States to tackle local problems. The creation of a dedicated agency on
cybersecurity at EU level would be also a costly solution. The assessment of impacts in Option
3 (Full harmonisation) shows that the estimated impact on cost is likely to be high and looking
at the performance in terms of effectiveness, it makes Option 3 (Full harmonisation) a
disproportionate and not very efficient option.
In the light of the previous assessment, the preferred option would be Option 2 (EU rules
+ regional cooperation). This option is the best in terms of effectiveness and, given its
economic impacts, has been demonstrated to be the most efficient as well as consistent
with other policy areas.
This preferred Option has large support among stakeholders. The majority of stakeholders are
in favour of regional coordination of risk preparedness plans and ex-ante cross-border
agreements to ensure that markets function as long as possible in crisis situations. No support
exists for retaining the status quo (i.e. Option 0 or 0+), as stakeholders agree that the current
framework does not offer sufficient guarantees that electricity crisis situations are properly
prepared for and handled in Europe. Option 3 (Full harmonisation) was deemed a step too far;
stakeholders did not support a fully harmonised approached based on rulebooks399
.
7.4. Comparison of options for addressing the causes and symptoms of weak
competition in the energy retail market
Although there is a significant level of uncertainty in quantifying the benefits of the options in
this Problem Area, all options, except for Option 0 (baseline scenario), are expected to improve
retail competition. However, the anticipated effectiveness and efficiency of the different options
vary markedly.
399
Reference is made to Section 5.3.1 through to 5.3.6 and Section 6 of Annexes (6.1.4 presentation of options
and 6.1.8 for more detailed representations of stakeholders' opinions).
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Table 28: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Implementation
costs
Policy Option 0
(Baseline
scenario)
0 0 0 0 0
Policy Option
0+ (Non-
regulatory
approach)
+ +++ + +/0 -
Policy Option 1
(Flexible
legislation)
+++ ++ +++ +++/-- --
Policy Option 2
(Harmonization
and extensive
consumer
safeguards)
+++ / ++ - +++ / ++ ++/--- ---
Option 0+ (Non-regulatory approach) can be expected to lead to modest, albeit tangible,
economic benefits primarily as a result of the voluntary phase-out of regulated prices in some
Member States and the drive to tackle illegal switching costs. Given its low implementation
costs, it is a highly efficient option. And the few stakeholders that will be affected will be
affected positively. However, the effectiveness of Option 0+ is significantly limited by the
fact that non-regulatory measures are not suitable for tackling the poor data flow between retail
market actors that constitutes both a barrier to entry and a barrier to higher levels of service to
consumers. In addition, shortcomings in the existing legislation make it impossible to
significantly improve consumer engagement and energy poverty. They also introduce great
uncertainty around the drive to phase out price regulation.
Option 1 (Flexible legislation) would probably lead to substantial economic benefits. Retail
competition would be improved as a result of the definitive phase-out of blanket price
regulation, non-discriminatory access to consumer data, and increased consumer engagement.
In addition, consumers would see direct benefits through improved switching. And the energy
poor would be better protected, leading to knock-on benefits to the broader economy. Given
that Option 1 would entail moderate implementation costs (these stem primarily from
ensuring a standardised format for consumer data, and the various burdens associated with
improving consumer engagement) it is an efficient option as these costs are considerably
outweighed by the benefits. Many stakeholder groupings are likely to be positively and
negatively affected by the collection of policy measures in Option 1. But none would bear a
disproportionate burden that would not be offset by commensurate benefits. Likewise, the
proposed measures in Option 1 respect the principle and limits of subsidiarity.
Option 2 (Harmonization and extensive consumer safeguards) would also lead to substantial
economic benefits, albeit with a greater degree of uncertainty over the size of these benefits.
This uncertainty stems from the tension some of the measures in Option 2 may have with
competition (stronger disconnection safeguards, an outright ban on all switching-related
charges), and from the difficulty of prescribing EU-level solutions in certain areas (defining
exceptions to price deregulation, implementing a standard EU bill design). Whilst a single EU
data management model would be just as effective and easier to enforce, and whilst the energy
poor would be even better protected by the stronger safeguards proposed, the high
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implementation cost of these measures would reduce the efficiency of Option 2 compared
with Option 1. Disconnection safeguards may be better designed by Member States to ensure
synergies between national social services. As social policy is a primary competence of Member
States, Option 2 may go beyond the boundaries of subsidiarity. Finally, many stakeholders will
be affected by the collection of policy measures in Option 1, both positively and negatively.
Suppliers and DSOs in particular would face significant burdens that they would at least
partially pass on to consumers i.e. socialise.
In the light of the analysis, the preferred option is Option 1 (Flexible legislation). This
option is most likely to be the most effective, is efficient, and is consistent with other policy
areas.
Most stakeholders would support (or at least be indifferent to) the measures in preferred Option
1 (Flexible legislation). This is due to the fact that a flexible legislative approach allows the
problems identified to be largely addressed while accommodating: 1) the broad range of
national differences that still exist in retail markets for energy; and 2) the specific concerns
aired in the stakeholder outreach. Nevertheless, some Member States practising blanket price
regulation will likely oppose a phase out of this, and industry associations representing energy
suppliers have stated that they would not welcome any EU legislation addressing the content of
bills.
Almost no support exists for retaining the status quo (i.e. Option 0) or for tackling the issues in
the Problem Area through soft law (Option 0+), except for isolated instances already mentioned.
Several measures in Option 2 (Harmonization and extensive consumer safeguards) were
generally deemed a step too far by a number of stakeholders, including stakeholders such as
ACER, or NRAs who represent the interest of the public.400
7.5. Synergies, trade-offs between Problem Areas and sequencing
The measures considered in this impact assessment are highly complementary. Most of the
different Options considered in each Problem Area would reinforce the effect of options in other
Problem Areas, with little trade-offs between the different areas.
Synergies
The measures to make intraday and balancing markets more flexible such as pursued under
Problem Area I, in particular Option 1(b) (strenghening short-term markets) and Problem Area
II , Option 1 (reinforced energy-only market) will foster a price signal that better reflects the
value of electricity, notably when it is scarce. It will hence provide a price signal benefical for
flexible resources, in particular demand response and storage and improve the business case for
innovative assets and service models to enter the market as assessed under Problem Area I
Option 1(c) (demand response/distributed resources). It will also reinforce liquidity and
competition in the electricity wholesale electricity markets. As choice on the wholesale market
is a pre-condition for more competition on retail markets, more liquid wholesale markets will
also contribute to improving competition in retail markets (Problem Area VI).
400
See Section 5.4.2 through to 5.4.5, and Sections 7 of Annexes 7.1 through 7.6 for more detailed representations
of stakeholders' opinions.
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Helping RES E resources to be remunerated through the market as fostered with the measures
under Problem Area I will ultimately reduce the high level of taxes and levies currently
necessary to drive RES E deployment, decreasing overall system costs and making energy more
affordable compared with a scenario where markets remain poorly adapted to RES E.
The measures proposed to improve the functioning of the electricity markets as discussed under
Problem Areas I and II, in particular Option 1 (reinforced energy market/No CMs), will also
lead to a more robust formation of price signals. Robust price signals will reduce the need for
assets to be remunerated by alternative revenue streams to be a credible investment opportunity
or avoid its decommissioning and hence reduce the need for government intervention in the
form of CMs or otherwise to ensure resource adequacy such as discussed under Problem Area
II, Option 3. Moreover, the measures assessed Problem area II, in particular the preferred
Option 3 will reduce market distorition caused by genuinly justifed CMs and improve the ability
of the market to operate optimally. In other words, improving the energy markets will reduce
the need for governement intervention to ensure investments in electricity resources.
Measures to improve retail competition, consumer engagement and data handling as fostered
with the measures under Problem Area IV (Retail markets) will increase system flexibility as
targeted by the measures under Problem Area I, in particuler Option 1(c) (pulling demand
response and distributed resources into the market). This is because the majority of untapped
demand response potential originates from smaller consumers and because retail price
regulation can have a detrimental effect on the deployment of innovative consumer products
such as dynamic price supply contracts.
Improving the market in its ability to renumerate (in particular, flexible) resources and
removing the distortions that prevent resources to reacte to proper price signals (such as those
aimed at in Problem I area I and Option 1 of Problem Area II) will overall improve the
robustness of the system to satisfy demand at all times and, hence, the freqeuncy and overall
number of hours that recourse has to be taken to out-of-market measures to operate the system,
such as the demand curtailment, as discussed under Problem Area III (Crisis situations).
Phasing out price regulation as fostered with the measures under Problem Area IV (particularly
in Member States with very low retail margins) will help address the high levels of electricity
and gas consumption caused by artificially low prices and provide an accurate price signal for
energy efficiency investments that would ultimately mitigate the effects of security of supply
events as targeted by the measures under Problem Area III (Crisis situations). Removing price
regulation will also allow for a more flexible organisation of the market and increase the
incentives to participate in the market through demand response as fostered by the measures
assessed un Problem Area I. Option 1(c) (pulling demand response and distributed resources
into the market)
Measures to improve retail competition as discussed under Problems Area IV, will ensure that
all benefits, including those expected under Problem Areas I, II and III are transferred to end-
consumers, ultimately increasing the beneficial effects on social welfare and competiveness.
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Overall, market improvement measures will address increasing energy poverty as discussed in
Problem Area IV. Indeed, one of the three main drivers401
of energy poverty has been the
gradual increase in retail prices.
Measures to ensure a common approach to crisis prevention and management as is the objective
under Problem Area III avoid unduly interventions in market functioning. Better preparedness,
transparency and clear rules on crisis management will build trust between Member States to
rely on the internal electicity market for resource adequacy, helping the achievement of the
objectives under Problem Area II. By imposing obligations to cooperate and lend assistance,
Member States are also less likely to "over-protect" themselves againt possible crisis situations.
Trade-offs
The mesures selected as the preferred option under Problem Area I and II are mutually
reinforcing in that they collectively aim at improving market functioning, thereby reducing the
need for market gouvernment intervention through CMs, and reducing their distortive effects if
nonetheless required. However, scarcity pricing and CMs to a certain degree can be seen as
alternative measures to foster investments. Even if CM deployment rules and design principles
are ringfenced, the mere fact that resources are also renumerated by CMs means that the
effectiveness of scarcity prices to drive investment may be reduced as the number of hours that
scarcity occurs and thus the profits that more flexible resources can earn from selling energy in
the market is reduced. It needs also to be noted that scarcity prices and CMs (at least in its
market-wide version) act differently on investment decision in a crucial manner. Whereas such
CMs rewards any capacity, removing barriers for scarcity pricing will improve remuneration of
flexible capacity in particular.
The measures assessed under various options in the impact assessment seek to improve the
overall flexibilty of the electricity system. However, they do this by employing different means.
It can therefore be expected that some trade-offs exist between these options. Improvements in
the usage of interconnection capacity (as assessed under Problem Area I, Option 1(b)
(strenghening short-term markets)) allow a given plant to exploit variations in production and
demand over a larger geographcial area allowing for a more stable intertemporal production
pattern of the plant. Improving the usage of interconnection capacity will hence favour the
usage of less flexible resources over flexible ones. Similarly, pulling demand response into the
market will reduce the profits of generation capacity and, in particular, flexible generation
capacity which may amplify the amount of capacity that needs to exit the market into the
transition towards 2030. Ultimately, efficient markets should select the most cost-efficient
solutions.
Energy poverty safeguards whose costs directly accrue to suppliers – particularly, the costly
disconnection safeguards considered in Option 2 (Harmonization and extensive consumer
safeguards) of Problem Area IV (Retail markets) – may act as a barrier to retail-level
competition, and diminish the associated benefits to consumers, including lower prices, new
and innovative products, and higher levels of service. Although the implementation costs of
these safeguards will be passed on to consumers, and therefore socialized, different energy
suppliers may have different abilities to do this, and to deal with the additional consumer
401
The other two drivers being wage growth and the energy efficiency of housing stock
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engagement costs. Some may therefore choose not to enter markets with such safeguards in
place. A uniform level of such safeguards throughout the market would help create a level
playing field and address such competition impacts.
Sequencing of measures
Over all, the synergies between the measures are large and the temporal dependency low, the
overall beneficial effects will be achieved only if all measures are implemented as a package.
A sequencing of measures is not necessarily appropriate to establish at EU level. The judgement
of moving to a next stage of market development much depends on the development stage of
the electricity market at hand. The reality is that Member States are at different, sometimes even
very different stages, in the development of their market arrangements. As an example only, as
a result of the individual characteristics of national markets, the timing of the phase out of price
regulation may differ on a case-by-case basis. This is to enable national authorities to ensure
that the necessary prerequisites of a smooth transition are in place before all regulatory
interventions in price setting are discontinued. Such prerequisites may include, for example, the
number of suppliers in the market, the market share of the largest suppliers, or retail price levels.
The same is true for other measures proposed.
The EU legislation ultimately adopted should therefore need to find the appropriate balance
between setting out a well-defined endpoint whilst allowing sufficient space for Member States
to manage their transition thereon.
8. MONITORING AND EVALUATION
8.1. Future monitoring and evaluation plan
The Commission will systematically monitor the transposition and compliance of the Member
States and other actors with the finally adopted measures and take enforcement measures if and
when required and report on the progress made in this regard on a regular basis. For this
purpose, the Commission will be supported by ACER as described below.
In addition, as it has already done in the context of the implementation of the Third Package,
the Commission will provide guidance documents providing assistance on the implementation
of the adopted measures.
Parallel to the proposed initiatives, the Commission will bring forward an initiative concerning
the governance of the Energy Union that will streamline the monitoring and reporting
requirements. Based on the initiative of the governance of the Energy Union, the current
monitoring and reporting requirements of Commission and Member States' reporting
obligations in the Third Energy Package will be integrated in a horizontal monitoring report.
More information on the streamlining of the monitoring and reporting requirements can be
found in the impact assessment for the governance of the European Union.
The annual reporting by ACER and the evaluation by the Commission, together with the
reporting from the Electricity Coordination Group are part of the proposed initiatives and
described in the sections below.
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8.2. Annual reporting by ACER and evaluation by the Commission
The monitoring of the proposed initiatives will be carried out following a two tier approach:
annual reporting by ACER and an evaluation by the Commission.
Annual reporting by ACER
ACER's duties402
under the Third Package include the monitoring of and reporting on the
internal electricity market. ACER prepares and publishes an annual market monitoring report
that tracks the progress of the integration process and the performance of electricity markets
and identifies any barriers to the completion of the internal electricity retail and wholesale
markets.
The sources of data on which ACER relies to compile its annual market monitoring report are:
the Commission, NRAs, ENTSO-E, the Bureau Européen des Unions de Consommateurs
(BEUC) and other relevant organisations. ACER's annual report is based on publicly available
information and the information provided by these entities.
Based on the present proposals, ACER will continue to monitor and report on the internal
electricity market on an annual basis after the adoption of the proposals. ACER's annual
reporting will replace the Commission's reporting obligations that are currently still existing
under the Electricity Directive. The present proposals also foresee extending ACER's
monitoring mandate to include matters related to security of supply.
Evaluation by the Commission
The Commission will carry out a fully-fleged evaluation of the impact of the proposed
initiatives, including the effectiveness, efficiency, continuing coherence and relevance of the
proposals, within a given timeline after the entry into force of the adopted measures
(indicatively, 5 years).
In the context of this evaluation, the Commission will pay particular attention as to whether the
assumptions underlying its analyses in the present impact assessment were valid.
The evaluation report will be developed by the Commission with the assistance of external
experts, on the basis of terms of reference developed by the Commission services. Stakeholders
will be informed of and consulted on the evaluation report, and they will also be regularly
informed of the progress of the evaluation and its findings. The evaluation report will be made
public.
8.3. Monitoring by the Electricity Coordination Group
The Electricity Coordination Group will be also a tool to monitor developments in the internal
electricity market and in particular as regards security of supply more closely. To this end a
402
The legal basis for the Agency’s market monitoring duties is in Article 11 of Regulation (EC) No. 713/2009.
ACER equally monitors and reports on many more detailed aspects of the regulatory framework.
(http://www.acer.europa.eu/Official_documents/Publications/Pages/Publication.aspx)
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concrete mandate will be given to the Electricity Coordination Group, in particular to monitor
the security of supply in the EU on the basis of a set of indicators (e.g. EENS, LoLE) and regular
outlooks and reports produced by ENTSO-E403
.
8.4. Operational objectives
The key objective of the present initiative is to make electricity markets more secure, efficient
and competitive whilst ensuring that electricity is generated in a sustainable way and remains
affordable to all. The operational objectives for the preferred options are listed as follows:
Problem Area I (market design not fit for an increasing share of variable decentralised
generation and technological developments):
- Adoption of measures directed at removing market distortions deriving from the
different treatment to generation from different sources;
- Adoption of measures aiming at providing for liquid and better integrated short-term
markets;
- Adoption of measures directed at removing barriers preventing demand response from
participating in energy and reserve markets;
- Adoption of measures aiming at strengthening the role of ACER, clarifying the role of
NRAs at regional level, criteria for enhancing ENTSO-E's transparency and monitoring
obligations, rules for formalising the role of DSOs at European level.
Problem Area II (uncertainty about sufficient future generation investments and uncoordinated
capacity markets):
- Adoption of measures aiming at improving the price signals of the electricity markets;
- Specific requirements to align national CMs by requiring ENTSO-E to propose a
methodology for an EU-wide resource adequacy assessment and requiring Member
States to rely on the assessment.
- Adoption of rules aiming at enhancing the compatibility between CMs.
Problem Area III (reinforce coordination between Member States for preventing and managing
crisis situations):
- Adoption of measures aiming at improving risk assessment and preparedness;
- Adoption of rules aiming at improving coordination in emergency;
- Adoption of measures aiming at improving transparency and information sharing.
Problem Area IV (retail markets):
- Adoption of measures aiming at reducing regulatory intervention in retail price setting;
- Adoption of measures aiming at protecting energy poor and vulnerable consumers;
- Adoption of measures directed at removing barriers to market entry for new supply and
service companies;
403
See Preferred Option (Option 2 (EU rules + regional cooperation)) to address problem Area III (When
preparing or managing crisis situations, Member States tend to disregard the situation across their borders).
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- Adoption of measures aimed at increasing consumer engagement and choice.
8.5. Monitoring indicators and benchmarks
As of 2021, ACER will be invited to review its current monitoring indicators with a view to
ensure their continuing relevance for monitoring progress towards the objectives underlying the
present proposals. ACER will continue relying on the same sources of data used for the
preparation of the market monitoring report. It will be tasked to cover in that report the security
of supply dimension as well. Monitoring indicators could include:
Problem Area I (market design not fit for an increasing share of variable decentralised
generation and technological developments):
- Indicators relating to market and regulatory barriers that affect the level playing field
between market participant and types of resources, such as the degree of capacity
dispatched - fully, partially or not at all - on the basis of price signals only, and the
usage of market and non-market based curtailment;
- Indicators related to the degree of flexibility available within the electricity system and
the development of intraday and balancing markets, such the level of market liquidity
in intraday and balancing markets and the allocation and use of cross-border capacity
for these time-frames, and related efficiency gains;
- Indicators related to the participation of distributed resources and demand in the market
(including use from system operators), energy service operators such as aggregators and
barriers to market participation. Such for example, the capacity and production by
distributed RES E and storage, the capacity of demand response available and its
activation, the number of facilities and their capacity operated by aggregators;
- Indicators related to consumer access to smart metring systems, their functionalities and
availability/uptake of dynamic electricity pricing contracts;
- Indicators related to the evaluation of the performance by ACER, ENTSO-E and NRAs
of their duties.
Problem Area II (uncertainty about sufficient future generation investments and
uncoordinated capacity markets):
- Indicators pointing to the effectiveness of market arrangements in providing locational
signals and reflecting the value of electricity, also in times of scarcity, such as the extent
to which market prices have been contrained by any implicit or explict limits on prices,
levels of investment and correlation with price in different bidding zones.
- State interventions to support resource adequacy and their interaction with the EU's
electricity markets, such as their incidence, design features and degree of participation
of cross-border capacity;
Problem Area III (reinforce coordination between Member States for preventing and
managing crisis situations):
- Indicators for monitoring security of supply, such as expected energy non-served
(EENS) and loss of load expectation (LoLE);
- In the case that electricity crisis situations occur, the lessons learnt from these stress
situations should also feed in the analysis of security of supply.
Problem Area IV (retail markets):
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- The incidence of regulated prices and the progress towards their phase-out;
- Market developments regarding consumer switching, switching facilitation such as
switching rates, costs and incidence of price and non-price barriers to switching.
- Key performance indicators measuring the economic and technical effectiveness of
DSOs and impact on system users (level of distribution charges).
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9. GLOSSARY AND ACRONYMS
ACER The Agency for the Cooperation of Energy Regulators, a European
Union Agency that was created by the Third Energy Package to
further progress the completion of the internal energy market both
for electricity and natural gas.
ACER Regulation: Regulation (EC) No 713/2009 of the European Parliament and of the
Council of 13 July 2009 establishing an Agency for the Cooperation
of Energy Regulators, OJ L 211, 14.8.2009, p. 1–14.
Adequacy (Resource) adequacy can be defined as the ability of the system to
meet the aggregate power and energy requirements of all consumers
at virtually all times. In this impact assessment the term resource
adequacy is favoured over other terms often used in this context,
such as generation or system adequacy
aFFR See FFR
Aggregator A service provider that combines multiple consumer loads
(flexibility or energy) and/or supplied energy units for sale or auction
in organised energy markets.
Ancillary Services: Services necessary to support the transmission of capacity and
energy from resources to loads while maintaining reliable operation
of the transmission service provider. They refer to a range of
functions which TSOs contract so that they can guarantee system
security. These include services like the provision of mFFR and
aFFR or reactive power.
Balancing The situation after markets have closed (gate closure) in which a
TSO acts to ensure that demand is equal to supply, in and near real
time.
Balancing Guideline Commission Regulation establishing a Guideline on Electricity
Balancing, one of the legal acts to be adopted under Article 18 of the
Electricity Regulation.
Balancing reserves All resources, if procured ex ante or in real time, or according to
legal obligations, which are available to the TSO for balancing
purposes.
BAU Business As Usual, i.e. the state of the world if no additional action
is taken.
Bidding zone A bidding Zone means a geographical area within which electricity
market wholesale prices are uniform and market participants not
have to take into account grid constraints. Market participants who
wish to buy or sell electricity in another bidding zone have to take
into account grid constraints and related congestion rent payments.
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BRPs Balance responsible parties, such as producers and suppliers, keep
their individual supply and demand in balance in commerical terms.
BSPs Balancing Service Providers, such as generators or demand facilities,
balance-out unforeseen fluctuations on the electricity grid by rapidly
increasing or reducing their power output.
CACM Guideline Guideline on Capacity Allocation and Congestion Management, one
of the legal acts adopted under Article 6 of the Electricity
Regulation.
CCGT Combined Cycle Gas Turbine, a common type of gas-fired
generation plant
CEEE Central Eastern European Electricity Forum, a platform for
cooperation between certain EU Member States.
CERT Computer Emergency Response Team.
CHP Combined Heat and Power units produce heat and electricity
simultaneously. Their production of electricity is not necesarrily
deterined only by prices for electricity.
CM Capacity Mechanism, a regulatory intervention that remunerates the
availability of electricity resources instead of the production of
electricity (or the avoidance of electricity consumption).
Congestion Means a situation in which an interconnection linking national
transmission networks cannot accommodate all physical flows
resulting from international trade requested by market participants,
because of a lack of capacity of the interconnectors and / or the
national transmission systems concerned.
Conventional generation The non-low carbon technologies, based on fossil fuels (lignite, hard
coal, natural gas, oil). They usually constitute the mid-range and
peaking plants.
Cross-zonal transmission capacity: The capability of the interconnected system to
accommodate energy transfers between bidding zones.
CSIRT Computer Security Incident Response Team.
CT Comparison Tools, websites that help consumers to compare
different offers in the market.
Curtailment Curtailment means a reduction in the scheduled capacity or energy
delivery.
Day-ahead market The market timeframe where commercial electricity transactions are
executed the day prior to the day of delivery of traded products.
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DER Distributed Energy Resources, a generic term referring electricity
assets such as small-scale RES E, storage connected to distribution
grids or by end-consumers on their premises.
Digital Single Market EU policy strategy aimed at: (i) helping to make the EU's digital
world a seamless and level marketplace to buy and sell; (ii) designing
rules which match the pace of technology and support infrastructure
development; and (iii) ensuring that Europe's economy, industry and
employment take full advantage of what digitalisation offers.
DR Demand (side) response, the ability of consumers of electricity to
actively adapt their consumption to market conditions.
DSO Distribution System Operator, the entity that operates, maintains and
develops the low voltage networks in a given area to which most
consumers are connected.
ECG The Electricity Coordination Group was created in 2012 by
Commission Decision of 15 November 2012. The Group is a
platform for the exchange of information and coordination of
electricity policy measures having a cross-border impact. It also aims
to facilitate the exchange of information and cooperation on security
of electricity supply, including the coordination of action in case of
an emergency within the Union.
EE Energy Efficiency Directive. Directive 2012/27/EU of the European
Parliament and of the Council of 25 October 2012 on energy
efficiency, amending Directives 2009/125/EC and 2010/30/EU and
repealing Directives 2004/8/EC and 2006/32/EC. This directive
establishes a set of binding measures to help the EU reach its 20%
energy efficiency target by 2020.
EEAG Communication from the Commission - Guidelines on State aid for
environmental protection and energy 2014-2020, OJ C 200,
28.6.2014, p. 1–55. The Guidelines aim to help Member States
design state aid measures that contribute to reaching their 2020
climate targets. The guidelines will be in force until the end of 2020.
EENS Expected Energy Non Served, a metric to measure security of supply
and to set a reliability standard.
EESC The European Economic and Social Committee.
Electricity Directive Directive 2009/72 of the European Parliament and of the Council of
13 July 2009 concerning common rules for the internal market in
electricity and repealing Directive 2003/54/EC, OJ L 211,
14.8.2009, p. 55–93. Together with the Electricity Regulation, the
Electricity Directive sets the main parts of the legal framework for
the EU's electricity markets.
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Electricity Regulation Regulation (EC) No 714/2009 of the European Parliament and of the
Council of 13 July 2009 on conditions for access to the network for
cross-border exchanges in electricity repealing Regulation (EC) No
1228/2003, OJ L 211, 14.8.2009, p. 15–35. Together with the
Electricity Directive, the Electricity Regulation sets the main parts
of the legal framework for the EU's electricity markets.
End-customer End-customers procure electricity for their own use.
ENTSO-E European Network of Transmission System Operators for
Electricity. ENTSO-E was established and given legal mandates by
Third Package.
ENTSO-G European Network of Transmission System Operators for Gas.
ENTSOG was established and given legal mandates by Third
Package.
EPBD Energy Performance of Buildings Directive or Directive
2010/31/EU of the European Parliament and of the Council of 19
May 2010 on the energy performance of buildings. OJ L 153,
18.6.2010, p. 13–35, concerning energy efficiency of building.
Modifications are being proposed to the EPBD.
ETS Emmission Trading System, works on the 'cap and trade' principle.
A 'cap', or limit, is set on the total amount of certain greenhouse
gases that can be emitted by the factories, power plants and other
installations in the system. The cap is reduced over time so that total
emissions fall. This policy instrument equally fosters penetration of
RES E as it renders production of electricity from non- or less-
emitting generation capacity more economical.
EU Target Model: Term refering to the current design of the EU's electricity markets.
The EU target model is based on two broad principles: (i) the
development of integrated regional wholesale markets, preferably
established on a zonal basis, in which prices provide important
signals for generators' operational and investment decisions; and (ii)
market coupling based on the so-called "flow-based" capacity
calculation, a method that takes into account that electricity can flow
via different paths and optimises the representation of available
capacities in meshed electricity grids.
EUCO27 The central policy scenario modelled by PRIMES, reflecting the
agreed 2030 climate and energy targets (and the 2050 EU's
decarbonisation objectives).
FCR Frequency Containment Reserve are reserves from reserve providers
(generators, storage, demand response) used by TSOs to maintain
frequency stable in the whole synchronous area (e.g. continental
Europe). This category typically includes automatically activated
reserves with the activation time up to 30 seconds.
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Florence Forum The Florence Forum was set up to discuss the creation of a true
internal electricity market in Europe. The participants are national
regulatory authorities, Member States, the European Commission,
international organisations in the area of energy and European-wide
associations representing transmission and distribution system
operators, electricity traders, consumers, network users and power
exchanges.
FRR Frequency Restoration Reserve are reserves from reserve providers
(generators, storage, demand response) used by TSOs to restore
system frequency and power balance after sudden system imbalance
occurrence (e.g. the outage of a power plant). Those reserves replace
FCR if the frequency deviation lasts longer than 30 seconds. This
category includes operating reserves with an activation time
typically between 30 seconds up to 15 minutes. FRR can be
distinguished between reserves with automatic activation (aFRR)
and reserves with manual activation (mFRR).
Gas Directive: Directive 2009/73 of the European Parliament and of the Council of
13 July 2009 concerning common rules for the internal market in gas
and repealing Directive 2003/55/EC, OJ L 211, 14.8.2009, p. 94–
136. Together with the Gas Regulation, the Gas Directive sets the
main parts of the legal framework for the EU's gas markets.
Gas Regulation: Regulation (EC) No 715/2009 of the European Parliament and of the
Council of 13 July 2009 on conditions for access to the natural gas
transmission networks and repealing Regulation (EC) No
1775/2005, OJ L 211, 14.8.2009, p. 36-54. Together with the Gas
Directive, the Gas Regulation sets the main parts of the legal
framework for the EU's gas markets.
Gate closure The moment when contracts are frozen. After gate closure, no
trading is allowed anymore. At this point, parties are expected to
adhere to the physical data submitted to the System Operator and to
the contracted volumes submitted before Gate Closure.
G-charges Charges for network usage imposed on generators
Generator A generator produces electricity and sells this to suppliers or end-
customers
Independent aggregator Aggregator that is not affiliated to a supplier or any other market
participant.
ITC Regulation Commission Regulation (EU) No 838/2010 of 23 September 2010
on laying down guidelines relating to the inter-transmission system
operator compensation mechanism and a common regulatory
approach to transmission charging
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LFC block Load-Frequency Control block or balancing zone, defines the size of
the network area for which the balancing reserves are being
procured.
Load The total electricity demand
Load Payments Load Payments correspond to the amount of money retail
companies/consumers need to pay to generators for the electricity
bought from the wholesale market. For each hour, it corresponds to
the product of served demand with the electricity price.
LoLE Loss of load expectation, a metric to measure security of supply and
to set a reliability standard
LTC Long-term contract.
METIS A modelling tool used by the Commission, described in more detail
in Annex IV.
mFFR See FFR
NC ER Network Code on Emergency and Restoration
NEMO Nominated Electricity Market Operator; an entity designated by
competent authroities to perform tasks related to single day-ahead
and intraday coupling as defined in the Guideline on Capacity
Allocation and Congestion Management, one of the legal acts
adopted under Article 6 of the Electricity Regulation.
Electricity network codes and guidelines: a legal act adopted under Articles 6, 8 and 18 of the
Electricity Regulation. Examples of such codes and guidelines are
the NC ER, the CACM guideline, the RfG, the System Operation
Guideline or the Balancing guideline. For a full overview of these
network codes and guidelines, reference is made to Annex VII.
NIS Directive Directive (EU) 2016/1148 of the European Parliament and of the
Council of 6 July 2016 concerning measures for a high common
level of security of network and information systems across the
Union, OJ L 194, 19.07.2016, p. 1-30.
NRAs National Regulatory Authorities, are national authorties set up and
empowered by the Third Package to over see national electricity (and
gas) markets.
NTC Net Transfer Capacity, a metric to measure the capacity available on
interconnectors to transfer electricity.
Plan Risk Preparedness Plans, a measure proposed under Problem Area
III
PLEF Pentalateral Energy Forum, a platform for collaboration consisting
of the Ministries, NRAs and TSOs of the BENELUX, DE, FR, AT,
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CH as well as a market parties platform and the European
Commission.
Power exchange Power exchanges facilitate the trading of electricity at wholesale
level, often for delivery the next day or at even shorter intervals
(intraday). They cooperate with TSOs in optimising interconnection
capacity in the contex of market coupling.
PRIMES A modelling tool used by the Commission, described in more detail
in Annex IV.
PV Photovoltaic
RED II The Renewable Energy Package comprising the new Renewable
Energy Directive and bioenergy sustainability policy for 2030
Redispatching A measure activated by one or several system operators by altering
the generation and/or load pattern in order to change physical flows
in the transmission system and relieve a physical network
congestion.
Regional platform A platform or regionally coordinated platforms for the attribution of
Long Term Cross Zonal Capacity for a single border or set of
borders.
RES E Renewable sources of electricity
RfG Network code on Requirements for Grid Connection of Generators
ROC Regional Operational Centre
RR Replacement Reserve are reserves from reserve providers
(generators, storage, demand response) used by TSOs to restore the
required level of FCR and FRR due to their earlier usage. Contrary
to FCR and FRR, not all TSOs in the EU maintain RR. This category
includes operating reserves with activation time from several
minutes up to hours.
RSC Regional Security Coordinators, an entity foreseen under the System
Operation Guidelines to assist TSOs in maintaining the operational
security of the electricity system.
Sector Inquiry The sector inquiry into capacity mechanisms as conducted by DG
Competition of the European Commission
Smart meter An electronic device that records consumption of electric energy in
intervals of an hour or less and communicates that information at
least daily back to the utility for monitoring and billing. Smart meters
enable two-way communication between the meter and the central
system.
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SME Small and Medium-sized Enterprises as defined in the Commission
Recommendation of 6 May 2003 concerning the definition of micro,
small and medium-sized enterprises (notified under document
number C(2003) 1422), OJ L 124, 20.05.2003, p. 36-41.
SoS Directive Security of Electricity Supply Directive or Directive 2005/89/EC of
the European Parliament and of the Council of 18 January 2006
concerning measures to safeguard security of electricity supply and
infrastructure investment, OJ L 33, 4.2.2006, p. 22–27
Supplier Suppliers are active in the retail segment of the market and supply
electricity to end-consumers
Switching rate The percentage of consumers changing suppliers in any given year.
System Operation Guideline: Draft Commission Regulation which will set down rules relating
to the maintenance of the secure operation of the interconnected
transmission system in real time.
TFEU Treaty of the Functioning of the European Union
Third Package: A package of legislation adopted in 2009 comprising the Electricity
Directive, the Electricity Regulation, the ACER Regulation as well
as similar legislation concerning the gas markets.
ToU tariffs Time-of-Use tariffs: Time-based pricing is a pricing strategy where
the provider of a service or supplier of a commodity, may vary the
price depending on the time-of-day when the service is provided or
the commodity is delivered.
Transmission capacity The transmission capacity, also called TTC (Total Transfer
Capacity), is the maximum transmission of active power in
accordance with the system security criteria which is permitted in
transmission cross-sections between the subsystems/areas or
individual installations.
TRM Transmission Reliability Margin, a metric to capture the amount of
transmission transfer capability necessary to provide reasonable
assurance that the interconnected transmission system will be secure
during changing system conditions
TSO Transmission System Operator, the entity that operates, maintains
and develops the high voltage networks in a given area.
TYNDP Ten-Year Network Development Plan
VCWG The Vulnerable Consumer Working Group provides advice to the
European Commission on the topics of consumer vulnerability and
energy poverty, its membership comprising industry, consumer
associations, regulators and Member States representatives.
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VoLL Value of Lost Load is a projected value reflecting the maximum
price consumers are willing to pay to be supplied with electricity.
VoLL is typically quite high (e.g. several thousands of EUR/MWh)
and not necessarily the same for each (group of) consumer, thus
enabling DR activation by consumers before the VoLL is reached.


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 5/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
303
TABLE OF CONTENTS
6. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA III: A NEW LEGAL
FRAMEWORK FOR PREVENTING AND MANAGING CRISES SITUATIONS......... 305
Summary table.............................................................................................................................305
Description of the baseline ..........................................................................................................308
Deficiencies of the current legislation .........................................................................................309
Presentation of the options .........................................................................................................313
Comparison of the options ..........................................................................................................325
Subsidiarity...................................................................................................................................334
Stakeholders' Opinions ................................................................................................................334
7. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA 4: THE SLOW
DEPLOYMENT OF NEW SERVICES, LOW LEVELS OF SERVICE AND POOR RETAIL
MARKET PERFORMANCE ................................................................................................. 338
7.1. Addressing energy poverty............................................................................................................340
Summary table.............................................................................................................................341
Description of the baseline ..........................................................................................................343
Deficiencies of the current legislation .........................................................................................355
Presentation of the options. ........................................................................................................357
Comparison of the options ..........................................................................................................369
Subsidiarity...................................................................................................................................394
Stakeholders' Opinions ................................................................................................................395
7.2. Phasing out regulated prices .........................................................................................................400
Summary table.............................................................................................................................401
Description of the baseline ..........................................................................................................402
Deficiencies of the current legislation .........................................................................................403
Presentation of the options .........................................................................................................407
Comparison of the options ..........................................................................................................409
Subsidiarity...................................................................................................................................445
Stakeholders' opinions.................................................................................................................446
7.3. Creating a level playing field for access to data.............................................................................450
Summary table.............................................................................................................................451
Description of the baseline ..........................................................................................................452
Deficiencies of the current legislation .........................................................................................454
Presentation of the options .........................................................................................................454
Comparison of the options ..........................................................................................................455
Subsidiarity...................................................................................................................................458
Stakeholders' opinions.................................................................................................................458
7.4. Facilitating supplier switching .......................................................................................................464
Summary table.............................................................................................................................465
Description of the baseline ..........................................................................................................466
Deficiencies of the current legislation .........................................................................................475
Presentation of the options .........................................................................................................475
Comparison of the options ..........................................................................................................476
Subsidiarity...................................................................................................................................481
Stakeholders' opinions.................................................................................................................482
7.5. Comparison tools ..........................................................................................................................485
Summary table.............................................................................................................................486
304
Description of the baseline ..........................................................................................................487
Deficiencies of the current legislation .........................................................................................492
Presentation of the options .........................................................................................................493
Comparison of the options ..........................................................................................................496
Subsidiarity...................................................................................................................................505
Stakeholders' opinions.................................................................................................................506
7.6. Improving billing information........................................................................................................511
Summary table.............................................................................................................................512
Description of the baseline ..........................................................................................................513
Deficiencies of the current legislation .........................................................................................526
Presentation of the options .........................................................................................................530
Comparison of the options ..........................................................................................................531
Subsidiarity...................................................................................................................................541
Stakeholder's opinions.................................................................................................................543
8. DESCRIPTION OF RELEVANT EUROPEAN R&D PROJECTS ............................... 549
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6. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA III: A NEW LEGAL FRAMEWORK FOR PREVENTING AND MANAGING CRISES SITUATIONS
Summary table
Objective: Ensure a common and coordinated approach to electricity crisis prevention and management across Member States, whilst avoiding undue government intervention
Option 0: Do nothing Option 0+: Non-
regulatory
approach
Option 1: Common minimum
EU rules for prevention and
crisis management
Option 2: Common minimum EU rules plus regional
cooperation, building on Option 1
Option 3: Full harmonisation
and full decision-making at
regional level, building on
Option 2
Assessments
Rare/extreme risks and
short-term risks related to
security of supply are
assessed from a national
perspective.
Risk identification &
assessment methods differ
across Member States.
- This option was
disregarded as no
means for
enhanced
implementing of
existing acquis
nor for enhanced
voluntary
cooperation were
identified
- Member States to identify and
assess rare/extreme risks based on
common risk types.
-
ENTSO-E to identify cross-border electricity crisis scenarios
caused by rare/extreme risks, in a regional context. Resulting
crisis scenarios to be discussed in the Electricity Coordination
Group.
Common methodology to be followed for short-term risk
assessments (ENTSO-E Seasonal Outlooks and week-ahead
assessments of the RSCs).
All rare/extreme risks
undermining security of supply
assessed at the EU level, which
would be prevailing over
national assessment.
Plans
Member States take
measures to prevent and
prepare for electricity crisis
situations focusing on
national approach, and
without sufficiently taking
into account cross-border
impacts.
No common approach to
risk prevention &
preparation (e.g., no
common rules on how to
tackle cybersecurity risks).
a)
- - Member States to develop
mandatory national Risk
Preparedness Plans setting out
who does what to prevent and
manage electricity crisis
situations.
-
- Plans to be submitted to the
Commission and other Member
States for consultation.
-
- Plans need to respect common
minimum requirements. As
regards cybersecurity, specific
guidance would be developed.
Mandatory Risk Preparedness Plans including a national and
a regional part. The regional part should address cross-border
issues (such as joint crisis simulations, and joint arrangements
for how to deal with situations of simultaneous crisis) and
needs to be agreed by Member States within a region.
Plans to be consulted with other Member States in the relevant
region and submitted for prior consultation and
recommendations by the Electricity Coordination Group.
Member States to designate a 'competent authority' as
responsible body for coordination and cross-border
cooperation in crisis situations.
Development of a network code/guideline addressing specific
rules to be followed for the cybersecurity.
Extension of planning & cooperation obligations to Energy
Community partners
Mandatory Regional Risk
Preparedness Plans, subject to
binding opinions from the
European Commission.
Detailed templates for the plans
to be followed.
A dedicated body would be
created to deal with
cybersecurity in the energy
sector.
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Crisis
management
Each Member State takes
measures in reaction to
crisis situations based on its
own national rules and
technical TSO rules.
No co-ordination of actions
and measures beyond the
technical (system operation)
level. In particular, there are
no rules on how to
coordinate actions in
simultaneous crisis
situations between adjacent
markets.
No systematic information-
sharing (beyond the
technical level).
Minimum common rules on crisis
prevention and management
(including the management of
simultaneous electricity crisis)
requiring Member States to:
(i) not to unduly interference with
markets;
(ii) to offer assistance to others
where needed, subject to financial
compensation, and to;
(iii) inform neighbouring Member
States and the Commission, as of
the moment that there are serious
indications of an upcoming crisis
and during a crisis.
Minimum obligation as set out in Option 1.
Cooperation and assistance in crisis between Member States,
in particular simultaneous crisis situations, should be agreed
ex-ante; also agreements needed regarding financial
compensation. This also inclues agreements on where to shed
load, when an to whom. Details of the cooperation and
assistance agreements and resulting compensation should be
described in the Risk Preparedness Plans.
Crisis is managed according to
the regional plans, including
regional load-shedding plans,
rules on customer
categorisation, a harmonized
definition of 'protected
customers' and a detailed
'emergency rulebook' set forth
at the EU level.
Montoring
Monitoring of security of
supply predominatly at the
national level.
ECG as a voluntary
information exchange
platform.
- - Systematic discussion of ENTSO-
E Seasonal Outlooks in ECG and
follow up of their results by
Member States concerned.
Systematic monitoring of security of supply in Europe, on the
basis of a fixed set of indicators and regular outlooks and
reports produced by ENTSO-E, via the Electricity
Coordination Group.
Systematic reporting on electricity crisis events and
development of best practices via the Electricity Coordination
Group.
A European Standard (e.g. for
EENS and LOLE) on Security
of Supply could be developed
to allow performance
monitoring of Member States.
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Pros
Minimum requirements for plans
would ensure a minimum level of
preparedness across EU taking
into account cyber security.
EU wide minimum common
principles would ensure
predictability in the triggers and
actions taken by Member States.
Common methodology for assessments would allow
comparability and ensure compatibility of SoS measures
across Member States. Role of ENTSO-E and RSCs in
assessment can take into account cross-border risks.
Risk Preparedness Plans consisting of a national and regional
part would ensure sufficient coordination while respecting
national differences and competences. Minimum level of
harmonization for cybersecurity throughout the EU.
Designation of competent authority would lead to clear
responsibilities and coordination in crsis.
Common principles for crisis management and agreements
regarding assistance and remuneration in simultaneous
scarcity situations would provide a base for mutual trust and
cooperation and prevent unjustified intervention into market
operation.
Enhanced role of ECG would provide adequate platform for
discussion and exchange between Member States and regions.
Regional plans would ensure
full coherence of actions taken
in a crisis.
Cons
Lack of cooperation in risk
preparedness and managing
crisis may distort internal
market and put at risk the
security of supply of
neighbouring countries.
Risk assessment and preparedness
plans on national level do not take
into account cross-border risks
and crisis which make the plans
less efficient and effective.
Minimum principles of crisis
management might not
sufficiently adress simultaneous
scarcity situations.
The coordination in the regional context requires
administrative resources.
Cybersecurity here only covers electricity, whereas the
provisions should cover all energy sub-sectors including oil,
gas and nuclear.
Regional risk preparedness
plans and a detailed templates
would have difficulties to fit in
all national specificities.
Detailed emergency rulebook
might create overlaps with
existing Network Codes and
Guidelines.
Most suitable option(s): Option 2, as it provides for sufficient regional coordination in preparation and managing crsis while respecting national differences and competences.
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Description of the baseline
In the area of risk prevention and management of crisis situations the current legislation is
scattered over different legal acts.
Regarding risk assessment and preparedness, currently Article 4 of the Electricity
Directive obliges Member States to ensure the monitoring of security of supply issues.
Such monitoring should, in particular, cover the balance of supply and demand, the quality
and level of maintenance of the networks, as well as the measures to cover peak demand
and to deal with shortfalls of one or more suppliers. This also includes the obligation to
publish every two years, by 31 July, a report outlining the findings resulting from the
monitoring, as well as any measures taken or envisaged to address them. Member States
should submit the report to the Commission.
Additionally, ENTSO-E has the obligation to carry out seasonal outlooks (6 month –
summer & winter outlooks) as required by Article 8 of the Electricity Regulation. The
assessments, which follow a probabilistic generation adequacy methodology, explore the
main risks identified within a seasonal period and highlighting the possibilities for
neighbouring countries to contribute to the generation/demand balance in critical
situations.
In terms of coordination and exchange of information among Member States, the
Commission created in 2012 the Electricity Coordination Group1
in the aftermath of
Fukushima crisis. The Group is a platform for the exchange of information and
coordination of electricity policy measures having a cross-border impact. It also should
facilitate the exchange of information and cooperation on security of electricity supply
including the coordination of action in case of an emergency within the Union.
The legislation on crisis management is set by Directive 2005/89/EC (SoS Directive),
Article 42 of the Electricity Directive and, as regards technical issues, the network codes,
in particular by the Network Code on Emergency and Restoration ('NC ER') which is
currently in comitology for approval. In addition, also the CACM Guideline and the
Guideline on System Operation (SO Guideline) set out operational procedures during crisis
situations, in particular on system operation to be implemented by TSOs.
The Electricity Directive contemplates in its Article 42 the possibility for Member States
to take temporary safeguard measures in the event of a sudden crisis and where the physical
safety or security of persons, apparatus or installation or system integrity is threatened.
Member States are obligated to notify those measures without delay to the other Member
States and the Commission. Any safeguard measures taken by Member States must "cause
the least possible disturbance in the functioning of the internal market and must not be
wider in scope than is strictly necessary [...]." In taking safeguard measures “Member
States shall not discriminate between cross-border contracts and national contracts"
according to Article 4(3) of the SoS Directive.
1
Commission Decision of 15 November 2012 setting up the Electricity Coordination Group. OJ C353,
17.11.2012, p.2.
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Table 2: Specific provisions in network codes and guidelines governing crisis
prevention and management at the technical level
The Network Code on Emergency and Restoration ('NC ER') requires in preparation for emergency
situations that the relevant Regional Security Coordinators (RSCs) ensure consistency of individual TSO
System Defence Plans2
. This includes inter-TSO information exchange, identification of threats within
the capacity calculation region and identification of incompatibilities of planned measures. During
emergency "each TSO shall provide through interconnectors any possible assistance" to its neighbours
and to prepare automatic load-shedding plans to ensure stable system frequency3
. Concerning suspension
of (cross-border) market activities, TSOs can suspend the provision of cross-zonal capacity and the
submission of balancing bids under the following circumstances4
: (a) blackout state or imminent risk of a
blackout state after market mechanisms are exhausted; (b) continuing market activities decreases
effectiveness of restoration towards normal/alert state; (c) communication tools of TSO to facilitate
market are not available. It also addresses recovery and settlement of costs related to emergency measures
between TSOs and market participants, subject to assessment through NRAs5
.
The Regulation on Capacity Allocation and Congestion Management (CACM) addresses the firmness
of cross-zonal allocated capacity in case of 'force majeure' or emergency situations. It defines 'force
majeure' as unusual event which has happened, is objectively verifiable, is beyond the control of a TSO
and makes it impossible for the TSOs to fulfil its obligations as set out by the CACM Guideline. According
to Article 72, the event of 'force majeure' allows TSOs to curtail allocated cross-zonal capacity in
coordination with other concerned TSOs. TSOs are further obliged to notify market participants which
are concerned by curtailment, provide compensation and limit both consequences and duration of force
majeure.
The Guideline on System Operation (SO Guideline) defines the operational system states of 'normal',
'alert', 'emergency' and 'restoration' in its Article 18. This provides a framework for 'remedial actions'
which are used by the TSOs to manage operational security violations (Art. 20 – 23) and as an example
include manually controlled load-shedding (Art. 22, paragraph 1(j)). TSOs shall prepare and coordinate
their remedial actions among each other and their RSCs (Art. 21, paragraph 1(b)) and prefer remedial
actions which make available the largest cross-zonal capacity (Art 21, paragraph 2(d)). Moreover, they
are obliged to jointly develop a procedure for sharing costs of remedial actions (Article 76, paragraph
1(b)(v)).
Source: EU legislation
Finally, on cybersecurity, NIS Directive provides the horizontal framework to boost the
overall level of network and information security across the EU. It imposes a set of
obligations on Member States as well as on essential service providers - including the
electricity, oil and gas subsectors.
Deficiencies of the current legislation
The evaluation of Directive 2005/89/EC (SoS Directive) has revealed the existence of
numerous deficiencies in the current legal framework6
. In first place, the evaluation
concludes in the ineffectiveness of the SoS Directive in achieving the objectives pursued,
notably contributing to a better security of supply in Europe. Whilst some of its provisions
have been overtaken by subsequent legislation (notably the Third Package and the TEN-E
2
See Article 6 of NC ER.
3
See Articles 14 & 15 of NC ER.
4
See Article 35 of NC ER.
5
See Article 8 and 39 of NC ER.
6
See Evaluation of the EU rules on measures to safeguard security of electricity supply and infrastructure
investment (Directive 2005/89/EC).
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Regulation), there are still regulatory gaps notably when it comes to preventing and
managing crisis situations.
The evaluation also reveals that the SoS Directive intervention is no longer relevant today
as it does not match the current needs on security of supply. As electricity systems are
increasingly interlinked, purely national approaches to preventing and managing crisis
situations can no longer be considered appropriate. It also concludes that its added value
has been very limited as it created a general framework but left it by and large to Member
States to define their own security of supply standard. Whilst electricity markets are
increasingly intertwined within Europe, there is still no common European framework
governing the prevention and mitigation of electricity crisis situations. National
authorities tend to decide, one-sidedly, on the degree of security they deem desirable, on
how to assess risks (including emerging ones, such as cyber-security) and on what
measures to take to prevent or mitigate them.
The existing regulatory gap on preventing and managing crisis situations is described in
detail below.
The existing obligations for the Member States on monitoring security of supply (Article
4 of the Electricity Directive and Article 7 of the SoS Directive) focus mainly on generation
adequacy and do not address the preparation for or dealing with crisis situations. In
practice, the reports submitted under Article 4 of the Electricity Directive are a mere
compilation of information on supply and demand figures showing the evolution in a
certain time horizon, while the lists of measures described cover mainly infrastructure
projects on generation and cross-border interconnections.
There is no legal obligation for Member States to carry out a risk assessment or to draw
up a risk preparedness plan7
. All Member States set an explicit or implicit obligation to
carry out an assessment of electricity security of supply risks; however, not all Member
States describe the types of risks covered under the assessment8
. The analysis shows that
the risks to be assessed vary considerably9
. Furthermore each Member State has designed
its own "risk preparedness" or "emergency plan" to deal with stress situations, which has
resulted in different national practices across Europe which tend to differ in nature, scope
7
Only ten Member States set clear obligations to draw up risk preparedness plans, whilst eighteen other
Member States do not have such an obligation, but take risk preparedness considerations into account in
reports, plans or measures (source: Risk Preparedness Study).
In addition, Directive 2008/114/EC on the identification and designation of European critical
infrastructures defines the obligation that each identified European Critical Infrastructure needs an
operator security plan (Art. 5) which will be also reflected in the coming System Operation Guideline
(Art. 26). However, these plans focus only on each identified asset and not the electricity system as
whole.
8
Only nine Member States have direct obligations to carry out a risk assessment; other Member States
are implicitly looking at risks when monitoring the security of electricity supply (source: Risk
Preparedness Study).
9
23 Member States define risks to be addressed which vary considerably (source: Risk Preparedness
Study).
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and content and rarely take into account cross-border effects. Diverging perception of risks
could lead to different levels of preparedness.
The evidence shows that national plans do not look at the impacts beyond the national
borders or simultaneous crisis situations. There is close cooperation on the level of
TSOs which is not matched by a cooperation of national authorities10
.
Uncoordinated national measures to ensure the supply in emergency situations may not be
efficient or could have negative effects on neighbouring countries. The lack of cooperation
on the level of national authorities could also lead to diverging actions on TSO and
governmental level (e.g. decision on governmental level on export bans) which could have
detrimental effect on security of electricity supply.
Regarding transparency and information exchange, implementation of Article 42 of the
Electricity Directive shows that up to now the Commission was only notified of such
measures in few cases (e.g. Poland in 201511
), and only ex-post, where there was no
possibility ex-ante to assess their suitability. The current wording of Article 42 is of rather
general nature and does not lead to sufficient cross-border coordination beforehand.
The Electricity Coordination Group has limited powers beyond the exchange of
information. There is no explicit obligation to convoke the group in case of a crisis or when
at least two Member States are in emergency. It is purely a consultative body without
powers to issue recommendations for example on the measures that Member States could
put in place during an emergency.
On managing crisis situations, currently Member States predominantly resort to national
measures without sufficient account being taken of their impact on their neighbours or
synergies stemming from a coordinated approach. There are hardly any cross-border
procedures on how Member States should act in crisis situations. However, with
increasingly integrated markets, measures taken by one Member State are highly probable
to affect its neighbours. The cross-border impact is particularly serious and immediate in
case of an actual physical shortage in real time12
.
10
There are examples of existing regional co-operation is some regions involving national authorities, e.g.
among the Nordic countries in the framework of NordBER (Nordic Contingency Planning and Crisis
Management Forum) or Pentalateral Energy Forum, however, currently this co-operation is mainly
restricted to the exchange of best practice.
11
Poland activated a crisis protocol mid-August 2015 allowing TSO to restrict power supplies to large
industrial consumers (load restrictions did not apply however to households and some sensitive
institutions such as hospitals). However, Poland notified the adoption of these measures under Article
42 one month after (mid-September).
12
Physical shortage arises when it has not been possible to fulfil the given demand, neither by market
transactions in day-ahead and intraday markets nor by balancing activities of the TSO. In this case, load
shedding will be carried out by each TSO to remedy its deficit. After market closure there is no ambiguity
regarding the deficit’s allocation across affected countries – each TSO knows exactly the magnitude of
its control area’s deficit and consequently its 'scheduled curtailment'. For exporting Member States who
strive to protect their customers from disconnection, two scenarios may arise: (i) closing down
interconnectors to stop exports altogether or (ii) carry out less-than-scheduled load shedding in order to
reduce export flows. In both cases the national action can have an impact on cross-border power flows,
affecting the neighbours' supply.
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In case of a simultaneous scarcity situation in two or more Member States, stopping or
limiting exports to overcome national physical shortage before domestic demand has been
curtailed would directly translate into aggravating supplies to customers in the
neighbouring Member State. The management of interconnectors and the possible spill
over effects of Member States' national actions become particularly relevant when a
concurrent physical energy shortage remains over several days (e.g. due to a heat
wave/cold spell causing a sustained demand spike or when a large number of generation
units is put out of operation). This case of energy shortage is especially exposed to the risk
of intervention with system operation or premature non-market measures by Member
States.
The network codes, i.e. the draft NC ER, the CACM Guideline and the SO Guideline
are an important step in the harmonisation of technical procedures and interoperatibility of
rules in the EU. However, a general legislative framework setting out how Member
States should act and co-operate with each other to prevent and manage electricity crisis
situations is still missing. There is still no framework clarifying roles and responsibilities,
aligning national rules, and prescribing co-operation between Member States to resolve
political issues relating to crisis management. As a result, large-scale electricity crisis
situations, as well as situations of a simultaneous crisis, cannot effectively be resolved (for
instance, there is no framework for how to deal with crisis situations caused by extreme
weather conditions, or a fuel shortage; there are no rules on which consumers should be
protected most, how to communicate and intervene at a political level etc).
Article 4(3) of the SoS Directive does not define clear Dos and Don'ts at the Member State
level even though electricity crisis situations, especially in situations of simultaneous
scarcity, which require political decision and clear rules, roles and responsibilities. In such
situations, the market should be allowed to function as long as possible and deliver power
flows to countries with higher scarcity. Exporting Member States should not introduce
exports bans without restricting national consumers in a proportionate manner as this
would 'export' the scarcity across the borders. The treatment of interconnection capacity
and consequently the way possible load-shedding measures could be shared across
countries is not sufficiently defined. A few Member States explicitly foresee (potentially
unproportioned) export bans in their national legislation13
and a recent case of export bans
in South-Eastern Europe has proven this risk in reality.
On cybersecurity, the fragmented approach of the NIS directive could be problematic for
the energy sector, as energy infrastructure is arguably one of the most critical
infrastructures that other sectors - like banking, health and mobility, depend upon to deliver
essential services. Currently, the energy sector consists of both legacy and next generation
technologies. New grid technologies are introducing millions of novel, intelligent
components to the energy sector that communicate in much more advanced ways (two-
way communications, dynamic optimization, and wired and wireless communications)
than in the past. These new components will operate in conjunction with legacy equipment
that may be several decades old, and provide little to no cybersecurity controls. In addition,
with alternative energy sources such as solar power and wind, there is increased
13
One Member State specifically includes a legal provision on export bans in its legislation; eleven more
Member States include forms of export restrictions in national law, TSO regulations or multilateral
agreements (Source: Risk Preparedness Study).
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interconnection across organizations and systems. With the increase in the use of digital
devices and more advanced communications, the overall risk has increased. For example,
as substations are modernized, the new equipment is digital, rather than analogue. These
new devices include commercially available operating systems, protocols, and applications
rather than proprietary solutions. This increased digital functionality provides a larger
incident surface for any potential adversary, such as nation-states, terrorists, malicious
contractors, and disgruntled employees. This new technology increases the complexity of
addressing cyber risks. Many of the commercially available solutions have known
vulnerabilities that could be exploited when the solutions are installed in control system
components. Potential impacts from a cyber-event include: billing errors,
brownouts/blackouts, personal injury or loss of life, operational strain during a disaster
recovery situation, or physical damage to power equipment. The current legislative
framework does not prepare for these impacts.
Presentation of the options
Options to reinforce coordination between Member States for preventing and
managing crisis situations (Problem Area III)
Table 3: Overview of the Options for Problem Area III
Option 0: Baseline scenario
Option 0+: Improved implementation of current legislation without regulatory action at EU level
Option 1: Common minimum rules to be implemented by Member States
Option 2: Common minimum rules to be implemented by Member States plus regional cooperation
Option 3: Full harmonisation and full decision-making at regional level
Option 0: Baseline scenario
Under the baseline scenario, Member States would continue identifying and addressing
rare/extreme risks and possible crisis situations based on a national approach, in
accordance with their own national rules and requirements. As a consequence, neither risks
originating across borders, nor possible synergies in preparation for crisis are sufficiently
taken into account.
The recently adopted network codes and guidelines (i.e. The Network Code on Emergency
and Restoration, the Regulation on Capacity Calculation and Congestion Management and
the Guideline on System Operation) bring a certain degree of harmonisation on how to
deal with electricity systems in different states (normal state, alert state, emergency state,
black-out and restoration). This ensures more clarity as regards how TSOs should act in
crisis siuations, and as to how they should co-operate with one another.
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The innovative tools14
developed for TSOs in the area of the system security in the last
years, will also contribute to improve monitoring, prediction and managing secure
interconnected power systems preventing, in particular, cascading failures15
.
However, the TSOs cooperation would be limited to technical-level decisions, and would
be hampered in practice by the absence of a proper framework for national rules and
decisions on how to prepare for and handle electricity crisis situations, in particular in
situations of siumultaneous scarcity. Such political decisions continue to be taken at a
purely national level, in an intransparent manner, without taking account of other Member
States' interests, both in a preparatory phase, and when crisis situations kick in.
Monitoring results would be published bi-annualy without any requirement to coordinate
among each other or develop any risk preparedness plan. Furthermore Member States
would not be obliged to exchange information when a possible crisis approaches. A
current mandate of the Electricity Coordination Group would also not be sufficient to
act as information exchange platform in crisis situations. This could lead to inefficiencies
when preventing and managing a crisis situation or have negative effects on neighbouring
countries.
On cybersecurity, the NIS Directive, aiming at a high common level of network and
information security across the Union, provides the horizontal framework to boost the
overall level of network and information security across the EU on a cross-sectoral and
generic level. However, as the NIS Directive is defining only very generic and high-level
obligations, there is room for a more sectoral approach defining concrete modalities to
ensure a minimum of coordination among Member States and resilience of the
interconnected European electricity grid. Energy infrastructure is arguably one of the most
critical infrastructures that other sectors - like banking, health and mobility- which depend
upon to deliver essential electricity services. Thus it is essential to tackle the potential risks
of a major blackout taking into account coordinated attacks to more than one Member State
and the interconnectivity and the system complexity of the energy sector.
14
ITESLA project (which was financed under FP7) developed methods and tools for the coordinated
operational planning of power transmission systems, to cope with increased uncertainties and variability
of power flows, with fast fluctuations in the power system as a result of the increased share of resources
connected through power electronics, and with increasing cross-border flows. The project shows that
the reliance on risk-based approaches for corrective actions can avoid costly preventive measures such
as re-dispatching or reduced the overall risk of failure.
15
In addition the AFTER project (which was financed under FP7) also developed tools for TSOs to
increase their capabilities in creating, monitoring and managing secure interconnected electrical power
system infrastructures, being able to survive major failures and to efficiently restore service supply after
major disruptions (http://www.after-project.eu/).
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Table 4: R&D Results
The technical base to produce accurate prediction of rapid fluctuations and prevent cascading failures has
been developed in ITESLA through a framework for the exchange dynamic models of power system
elements. It showed that the reliance on risk-based approaches for corrective actions can avoid costly
preventive measures such as re-dispatching or reduced while the overall risk of failure is decreased. This
requires more and more formalised data exchange among TSO's to support the new methods and tools.
AFTER has developed a framework for electrical power systems vulnerability identification, defence
and restoration. It uses a large set of data (big data) coming from on-line monitoring systems available at
TSOs’ control centres. A fundamental outcome of the tool consists in risk-based ranking list of
contingencies, which can help operators decide where to deploy possible control actions.
SESAME, developed a comprehensive decision support system to help the main public actors in the
power system, TSOs and Regulators, on their decision making in relation to network planning and
investment, policies and legislation, to address and minimize the impacts (physical, security of supply,
and economic) of power outages in the power system itself, and on all affected energy users, based on the
identification, analysis and resolution of power system vulnerabilities.
Source: European Commission (DG ENER)
Table 5: Innovative Tools for Electrical System Security within Large Areas
(ITESLA)
Project FP7-ITESLA
Innovative Tools for Electrical System Security within Large Areas
Addressing mainly: Co-optimisation of interconnection capacity, Regional operational centres
The project developed methods and tools for the coordinated operational planning of power transmission
systems, to cope with increased uncertainties and variability of power flows, with fast fluctuations in the
power system as a result of the increased share of resources connected through power electronics, and
with increasing cross-border flows. The project aims at enhancing cross-border capacity and flexibility
while ensuring a high level of operational security.
Fact Sheet: http://cordis.europa.eu/project/rcn/101320_en.html
Web Site: http://www.itesla-project.eu/
Important project outcomes include
- A platform of tools and methods to assist the cooperation of transmission system operators in dealing
with operational planning from two days ahead to real time, particularly to ensure security of the
system. These tools support the optimisation of security measures, in particular to consider corrective
actions, which only need to be implemented in rare cases that a fault occurs, in addition to preventive
actions which are implemented ahead of time to guarantee security in case of faults. The tools provide
risk-based support for the coordination and optimisation of measures that transmission operators need
to take to ensure system security. The platform also supports "defence and restoration plans" to deal
with exceptional situation where the service is degraded, e.g. after storms, or to restore the service
after a black-out. The platform has been made publicly available as open-source software.
- A clarification of the data and data exchanges that are necessary to enable the implementation of
these coordination aspects.
- A framework to exchange dynamic models of power system elements including grids, generators and
loads, and a library of such models covering a wide range of resources. These models are essential to
produce accurate prediction of the rapid fluctuations that take place in the power grid after faults, and
to prevent cascading failures.
- The tools and models allow reducing the amount of necessary preventive measures. The reliance on
risk-based approaches can avoid or minimise costly preventive measures such as re-dispatching while
the overall risk of failure is decreased.
- A set of recommendations to policymakers, regulators, transmission operators and their associations
(jointly with the UMBRELLA project). These foster the harmonisation of legal, regulatory and
operational framework to allow the exploitation of the newly developed methods and tools. They also
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identify the need for increased formalised data exchange among TSO's to support the new methods
and tools.
Source: European Commission (DG ENER)
Option 0+: Non-regulatory approach
As current legislative framework established by the SoS Directive set general principles
rather than requires Member States to take concrete measures, better implementation and
enforcement actions will be of no avail.
In fact, as the progress report of 2010 shows16
, the SoS Directive has been implemented
across Europe, but such implementation did not result in better co-ordinated or clearer
national policies regarding risk preparedness.
The recently adopted network codes and guidelines offer some improvements at the
technical level, but do not address the main problems identified.
In addition, today voluntary cooperation in prevention and crisis management is scarce
across Europe and where it takes place at all, it is often limited to cooperation at the level
of TSOs. It is true that certain Member States collaborate on a voluntary basis in order to
addresss certain of the problems identified (e.g. Nord-BER, PLEF). However, these
initiatives have different levels of ambition and effectiveness, and they geografically cover
only part of the EU electricity market. Therefore, voluntary cooperation will not be an
effective tool to solve the problems identified timely and in the whole EU.
Option 1: Common minimum rules to be implemented by Member States
Assessments and plans
Under Option 1 Member States would be obliged to develop national Risk Preparedness
Plans ('Plan') with the aim to prevent or better manage the electricity crisis. The Plan should
respect minimum common requirements and include a risk assessment of the most
relevant crisis scenarios originated by rare/extreme risks. For that purpose, at least the
following types of risks could be considered: a) rare/extreme natural hazards17
, b)
16
Report on the progress concerning measures to safeguard security of electricity supply and
infrastructure investment COM (2010) 330 final.
17
Extreme weather events are likely to affect the power supply in various ways: (i) thermal generation is
threatened by lack of cooling water (as shown e.g. in summer 2015 at the French nuclear power stations
Bugey, St. Alban and Golfech); (ii) heat waves cause high demand of air conditioning (which e.g.
resulted in price peaks in Spain in late July 2015 when occurring in parallel with low wind output); (iii)
heat waves affect grid performance in various ways, e.g. moisture accumulating in transformers (which
e.g. lead to blackouts in France on June 30th
2015) or line overheating (leading to declaration of
emergency state by the Czech grid operator CEPS on July 25th
in 2006) (source: S&P Global, Platts:
European Power Daily, Vol. 18, Issue 123).
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accidental hazards which go beyond N-1, c) consequential hazards such as fuel shortage18
,
d) malicious attacks (terrorist attacks, cyberattacks).
The Plans would need to respect a set of minimum requirements, namely how Member
States would prepare for crisis situations and how they should deal with the identified
crisis scenarios. Preparatory measures could include, e.g. training for all staff involved in
crisis management and regular simulations of crisis. Risk preparedness plans should
further include how to prevent and manage cyber-attack situations which would be one of
the risks to be covered by the plans. This will be combined with a soft guidance on
cybersecurity in the energy sector based on NIS Directive.
Plans should be adopted by relevant governments / ministries, following an inclusive
process, and (at least some parts of the Plans) should be rendered public. Plans should be
updated on a regular basis (e.g., every three years, unless major incidents or market
developments require an earlier update). For the purpose of consultation, Plans should be
submitted to other Member States and the Commission.
The main benefit this option would bring is better preparedness, due to the fact that a
common approach is followed across Europe, thus excluding the risk that some Member
States 'under-prepare'. In addition, better preparedness, transparency and clear rules on
crisis management are likely to reduce the chances of premature market intervention.
Crisis management
To ensure transparency and information exchange, Member States would be obliged to
inform immediately in situations of "early warning" or "crisis" their neighbours and
the European Commission to provide them with all the necessary information, in particular
on the actions they intend to take.
"Early warning" could be defined as the state where there is concrete, serious and reliable
information that an event may occur which is likely to result in significant deterioration of
the supply situation and is likely to lead to a crisis level. While "crisis" could be defined
as the event of significant deterioration of electricity supply over a time span lasting long
enough to give room for political action and when all relevant market measures have been
implemented but the supply is insufficient to meet the remaining demand19
.
18
One example proving that such risks should be taken into account is the shortage of anthracite coal in
Ukraine in June 2016. Due to the political situation in Ukraine affected the rail transport of coal. As
several Ukrainian nuclear power units are offline for maintenance in parallel, the responsible ministry
called for limiting power consumption. (Source: S&P Global, Platts: European Power Daily, Vol. 18,
Issue 123).
19
In most of the cases the declaration of "crisis" by the national authorities will coincide with the "emergency
state" of the transmission system as severe technical problems could lead to the "exceptional situation".
But in very extreme or rare cases where situations demand political decisions and are not solely limited
to system operation in real time (e.g. fuel supply scarcity, energy shortage for longer time periods) the
government could decide to declare emergency - without necessary being in "emergency state"- with the
aim to take safeguard measures (non-market based measures).
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Under this option, the Commission could also set out legal principles governing crisis
management. This will replace the current Article 42 of the Electricity Directive, which
allows Member States to take 'safeguard measures' in situations of a sudden crisis and when
security of persons or equipment is threatened. When dealing with emergency Member
States should respect three basic rules:
- 'Market comes first': Non-market measures should be introduced only once market
measures cannot tackle the situation. Measures should not unduly distort functioning of
the market. They should be introduced only temporary and on the basis of an objective
trigger described in the Plans. In particular, market rules on cross-border trade need to be
respected20
.
- 'Duty to offer assistance': In case crisis arises, Member States should react in a spirit of
good cooperation and solidarity21
. Practical arrangements regarding cooperation and
solidarity measures shall be established in advance by Member States and be reflected in
the risk preparedness plans.
- 'Transparency and information exchange': Member States should ensure transparency of
the actions taken from the moment that there are serious indications of a crisis and during
a crisis. This should be ensured through the regional part of the risk preparedness plans
and through informing neighbours and the Commission in case of declaration of 'early
warning' or 'crisis'.
By imposing obligations to co-operate and lend assistance, Member States are also less
likely to 'over-protect' themselves against possible crisis situations, which in turn will
contribute to more security of supply at a lesser cost.
Monitoring
In order to anticipate and mitigate potential upcoming crisis, under Option 1 Member
States would be obliged to take into account the results of the ENTSO-E seasonal
assessments (winter & summer outlooks). Member States should take measures
accordingly, if there are serious indications that they could be in a predefined crisis
situation (i.e. in an 'early warning' situation), as well as in a situation of crisis.
Option 2: Common minimum rules to be implemented by Member States plus
regional co-operation
Assessments and plans
Option 2 would be built on Option 1 adding rules and tools facilitating cross-border
cooperation in a regional and Union wide context.
Under Option 2 Member States should also develop their Risk Preparedness Plans.
However, the identification of the crisis scenarios and the risk assessment would be
20
Rules on cross-border capacity allocation are set out in the CACM Guideline. Its Article 72 allows TSOs
to curtail allocated cross-zonal capacity in the event of 'force majeure'.
21
At TSO level, providing cross-border assistance through the available interconnectors is provided for in
Article 12 of the draft Network Code on Emergency and Restoration.
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carried out by ENTSO-E. This approach would ensure that the risks originating across the
borders, including scenarios of a possible simultaneous crisis, are taken into account.
ENTSO-E would be required to develop a methodology for the identification of risk
scenarios. Such methodology would need to include at least following elements:
- consider all relevant national and regional circumstances;
- the interaction and correlation of risks across the borders;
- running simulations of simultaneous crisis scenarios;
- ranking of risks according to their impact and probability.
To take account of all regional specificities ENTSO-E could delegate all or part of its tasks
to the ROCs. The crisis scenarios identified by ENTSO-E would be discussed in the
Electricity Coordination Group. The regional approach in the identification of the crisis
scenarios ensures a common strategy to minimise impacts of possible crisis, focus in
particular on correlated risks and on risks that could affect simultaneously several Member
States. This would significantly improve level of preparedness at national, regional and
EU level, as the cross-border considerations are duly taken into account since the
beginning.
Table 6: Best practice examples of Member State cooperation
Nordic Contingency and Crisis Management Forum (NordBER)
The Nordic (including Iceland) TSOs, regulators and energy authorities founded a Nordic cooperation
body (NordBER) in order to improve crises management and preparedness. The cooperation focuses on
the exchange of information and experiences on contingency planning and emergency exercises.
Moreover, it requires a common contingency planning for the overall Nordic power sector as a supplement
to the national emergency work and as an extension of operation and planning cooperation between the
TSOs.
Pentalateral Energy Forum
The Pentalateral Energy Forum is the framework for regional cooperation of relevant ministries, NRAs,
TSOs and market parties in Central-Western Europe (BENELUX-DE-FR-AT-CH). Its Support Group 2
gives guidance on regional cooperation in the field of security of supply and acts as "development center
for new ideas" with the goal to reach specific recommendations.
Source: https://nordber.org/ and http://www.benelux.int/nl/kernthemas/energie/pentalateral-energy-forum/
The Risk Preparedness Plans under this option would contain two parts – a part
reflecting national measures and a part reflecting measures to be pre-agreed in a regional
context. The latter part includes particular preparatory measures such as simulations of
simultaneous crisis situations in neighbouring Member States ("stress tests" organised by
ENTSO-E in a regional context); procedures for cooperation with other Member States in
different crisis scenarios, and rules for how to deal with simultanous crisis situations. In
this context the Member States should, among others, agree in advance in which situations,
what load and to whom will be curtailed in simultaneous crisis situations. In order to
facilitate the extent of offered assistance, in particular in cases where no other agreement
has been made for assistance in simultaneous crisis, it might be necessary to allign
principles for priorization and the share of customers which is prioritized highly in order
to avoid overprotection at the cost of neighbouring Member States.
The draft Plans should be consulted with other Member States in each region and submitted
for prior consultation to the Electricity Coordination Group. Through regionally co-
ordinated plans, Member States would be able to ensure that increased TSO cooperation is
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matched by a more structured co-operation between Member States22
. The regions for such
cooperation should therefore be the same as the TSO regions developed for the RSCs. To
ensure cooperation further, the obligation on coordinated planning should be extended to
Energy Community Partners.
To facilitate the cross-border cooperation and to overcome the current situation of unclear
roles and responsibilities, Member States should designate one 'competent authority',
which would be the responsible body for coordination and cross-border cooperation in a
crisis situation. The Competent Authority should belong either to the national
administration or to the NRA.
In order to also adress specific rules to be followed to ensure cybersecurity a network
code or guideline should be developed.The network code/guidelines should take into
account at least the following elements: a) methodology to identify operators of essential
services for the energy sector; b) risk classification scheme; c) minimum cyber-security
prerequisites to ensure that the identified operators of essential services for the energy
sector follow minimum rules to protect and respond to impacts on operational network
security taking the identified risks into account. A harmonized procedure for incident
reporting for the energy sector shall be part of the minimum prerequisites.
Crisis management
As described in Option 1, all measures taken by Member States to prepare to or deal with
'crisis' should be based on a common framework and the principles of 'market comes
first', 'duty to offer assistance' and 'transparency and information exchange'.
The 'duty to offer assistance' should especially address simultaneous scarcity situations
which would be set to further rise in the near future given the increasing interconnectivity
of the European electricity systems and markets (see Graphs 1 and 2). In situations of
concurrent energy shortage over several days23
, Member States should agree in advance,
when and what loads would be curtailed in crisis situations with a cross-border impact24
.
Solidarity measures in simultaneous scarcity, including coordinated demand restrictions in
various markets, could be subject to financial compensation ex-post, following agreements
between Member States according to the principles set out in Article 39 of NC ER
(avoiding market distortion, incentivizing balanced positions). In order to avoid 'exporting'
22
For cases of crisis, in particular simultaneous scarcity, also ENTSO-E sees a need for "not only on a
technical level but political cooperation" and plans which "should cover extreme crisis situations beyond
the measures provided by e.g. network codes and RSCs services" (s. ENTSO-E recommendations to the
regulatory framework on risk preparedness (WS5) (2016), ENTSO-E, document in the process of
publication).
23
Unlike sudden power outages, an energy shortage could be (i) anticipated e.g. several days in advance
and (ii) last over a period of several days. Therefore, decision making on customer disconnection, rota
plans etc. is likely to not only affect TSOs, but also involve Member States. A good example of a rota
plan is the "Electricity Supply Emergency Code" of the UK:
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/396424/revised_esec_ja
nuary_2015.pdf
24
One example of a load shedding plan prioritizing regions is the Belgian "Plan de délestage en cas de
pénurie d'électricité" http://economie.fgov.be/fr/penurie_electricite/plan-delestage/#.VpTd2v7luUk
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energy scarcity to neighbouring markets Member States should also allow for domestic
load shedding to be carried out by their TSOs according to schedules. Any rules on
protected customers should not lead to unjustified over-protection of a too high share of
national customers25
.
25
As already existing in many Member States today, Member States can introduce rules on customer
categorization to prioritize customers in case of load shedding. Such rules on protected customers should
take into account national and local specifics, but respect harmonized principles.
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Graph 1: Distribution of system stress hours by Member States over fifty years of
historical demand data
Stress hours are defined as hours of extremely high demand. The graph shows the 150 hours per Member
State of the highest demand in the historical period of fifty years (1960-2010). The intensity of the colour
indicates the intensity of demand (red means super peaks of demand). Rows indicate Member States.
Columns indicate the respective historical years.
Source: METIS
Graph 2: Distribution of prices at VoLL in the context of a well-integrated market
by Member States over fifty years of historical demand data
As result of better integration of the markets the stress hours would decrease and be concentrated in periods
affecting simultaneously several Member States.
During these stress hours the price becomes equal to VoLL.
Source: METIS
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Table 7: Best practice example of TSO agreements of Nordel
The Nordic TSOs pre-agreed on certain procedures to be taken in crisis situations (s. Apendix 9 of Nordel
System Operation Agreement 3 (5)). In Power Shortages, it demands information of the other TSOs as
quickly as possible and forbids that prearranged trading between players can be changed. In Critical
Power Shortages and after all manual balancing reserve (i.e. available generation capacity) has been
exhausted, it sets out a procedure for load shedding without a commercial agreement. After the subsystem
with the greatest physical deficit has started load shedding and two or more subsistems have an equally
large deficit, load shedding is distributed thereafter between those subsystems26
.
Source: Nordel System Operation Agreement 1 (5), Appendix 9
Monitoring
Building on Option 1, ENTSO-E would carry out seasonal assessments, which would need
to be further improved via the introduction of a common methodology, to be developed
by ENTSO-E on the basis of criteria set out in EU legislation. This could be a probabilistic
methodology that should take into account uncertainties of input variables (e.g. probability
of transmission capacity outage, of severe weather conditions, of unplanned outage of
power plants, variability of demand, etc.). The methodology would also indicate the
probability of a critical situation actually occuring and of low level of cross-border
capacity. This methodology should be used not only for seasonal outlooks but also for
weekly risk assessments by RSCs.
This option also contemplates the reinforcement of tasks and powers of the Electricity
Coordination Group with a view to ensure transparency and wide discussion between
Member States in the preventive phase and after declaration of early warning/crisis. In
particular, the Group would be the forum for the discussion of the draft plans and the
measures that Members States foresee to implement based on the results of the seasonal
outlooks. The Group could also play a role in the assessment of measures adopted by
Member States in early warning/crisis. More generally, the Group could be given concrete
tasks to discuss policies in the area of security of supply, for instance, through regular
discussions on the basis of ENTSO-E adequacy outlooks. It could issue recommendations
and develop best practice. The reinforced role would enhance the coordination of measures
and ensure more uniformity and coherent plans. Overall, the reinforcement of tasks and
powers of the Electricity Coordination Group would contribute to enhance cooperation and
to build trust and confidence among Member States.
In addition to the obligation to notify immediately the declaration of early warning or crisis
and provide Member States concerned and the Commisison with all relevant information,
under Option 2 Member States would be obligated to carry out an ex-post evaluation. The
evaluation should be submitted to the Commission at the latest six weeks after the lifting
of early warning or crisis. The assessments should be presented by the Member States
concerned at the Electricity Coordination Group.
To allow for a precise monitoring of how well Member States' systems perform in the area
of security of supply, security of supply indicators would be introduced. ENTSO-E
would calculate for all Member States the following security of supply indicators: expected
26
That agreements similar to the Nordic TSOs could be a best practice also for the system of continental
Europe as it mentioned by the Dutch TSO TenneT to the public consultation. It recommends to have
common rules and definitions and defining allowed measures on different levels of criticality, as security
of electricity supply is becoming an issue of reginal rather than national importance.
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energy non served (EENS) expressed in GWh/year and loss of load expectation (LOLE)
expressed in hours/year. ENTSO-E would conduct the security of supply performance
measurements based on the indicators on annual basis, at the occasion of the adequacy
assessment outlook. The introduction of security of supply indicators to assess how well
Member States perform in the area of security of supply would enhance comparability and
mutual trust in neighbours.
Option 3: Full harmonisation and full decision-making at regional level
Assessments and plans
Built on Option 2, under Option 3 the assessment of rare and extreme risks would be carried
out at EU level, which would prevail over national assessments.
The risk preparedness plans would be developed on regional level27
. In each region the
Member States would need to agree on one risk preparedness plan which would address
the most relevant risks in each region. The list of measures to mitigate the risks should be
developed on and co-ordinated at the regional level by the ROCs. This would allow a
harmonised response to potential crisis situation in each region.
Even though the regional plans would ensure full coherence of actions ahead and in
particular in a crisis, it would be difficult that all national specificities could be addressed
through regional plans.
On cybersecurity Option 3 would go one step further and nominate a dedicated body
(agency) to deal with cybersecurity in the energy sector. This would guarantee full
harmonisation on risk preparedness, communication, coordination and a coordinated cross-
border reaction on cyber-incidents.
Crisis management
Regarding crisis management, under Option 3 crisis would have to be managed according
to the regional plans agreed among Member States. The Commission would determine the
key elements of the regional plans such as: commonly agreed regional load-shedding plans,
rules on customer categorisation, a harmonised definition of 'protected customers' (high
priority grid users) at regional level or specific rules on crisis information exchanges in the
region. Under Option 3, the Commission would also create a detailed 'emergency
rulebook' with an exhaustive list of measures that can be taken by Member States and
TSOs in crisis situations.
27
The results of the public consultation showed that only few stakeholders were in favour of regional or
EU wide plans. Some stakeholders mentioned the possibility to have plans on all three levels (national,
regional and EU), e.g. see the answers of Latvian government, EDSO, GEODE, Europex.
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Monitoring
The seasonal outlooks carried out by the ENTSO-E and ROCs would include a proposal
of ROCs for each reagion of measures to mitigate the risks identified. Member States
would be obligated to implement them.
In order to also harmonize monitoring practices on a European level and ensure full
consistency, a European standard (e.g. for EENS and LOLE) on Security of Supply could
be developed and fixed (e.g. determined value to be fulfilled by all Member States) which
could be used to monitor the Member State performance.
Comparison of the options
Option 1 (Common minimum rules to be implemented by Member States)
Contribution to the policy objectives
Under this option, Member States would be required to draw up risk preparedness plans,
built on common elements, and to respect certain common minimum rules when managing
crisis situations.
The main benefit this option would bring is better preparedness, due to the fact that a
common approach is followed across Europe, thus excluding the risk that some Member
States 'under-prepare'. In addition, better preparedness, transparency and clear rules on
crisis management are likely to reduce the chances of premature market intervention.
By imposing obligations to co-operate and lend assistance, Member States are also less
likely to 'over-protect' themselves against possible crisis situations, which in turn will
contribute to more security of supply at a lesser cost.
Economic Impacts
Overall, the policy tools proposed under this option should have positive effects. Putting
in place a more common approach to crisis prevention and management would not entail
additional costs for businesses and consumers. It would, by contrast, bring clear benefits
to them.
First, a more common approach would help better prevent blackout situations, which are
extremely costly. The immense costs of large-scale blackouts provide an indication of
potential benefits of improved preparation and prevention28
.
28
Previous blackouts in Europe had severe consequences. For example, the blackout in Italy in September
2003 resulted in a power disruption for several hours affecting about 55 million people in Italy and
neighbouring countries and causing around 1.2 billion euros worth of damage. (source: The costs of
blackouts in Europe (2016), EC CORDIS: http://cordis.europa.eu/news/rcn/132674_en.html).
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Table 8: Overview over most severe blackouts in Europe
Country & year
Number of end-
consumers
interrupted
Duration,
energy not
served
Estimated costs to
whole society
Sweden/Denmark,
2003
0.86 million
(Sweden);
2.4 million
(Denmark)
2.1 hours,
18 GWh
EUR 145 –
180 million
France, 1999 1.4 - 3.5 million
2 days–2 weeks,
400 GWh
EUR 11.5 billion
Italy/Switzerland,
2003
55 million 18 hours
Sweden, 2005 0.7 million
1 day –
5 weeks,
11 GWh
EUR 400 million
Central Europe, 2006 45 million
Less than
2 hours
Source: SESAME: Securing the European Electricity Supply Against Malicious and Accidental Threats
A more common approach to emergency handling, with an obligation for Member States
to help each other, would help to avoid or limit the effects of potential blackouts. A more
common approach, with clear obligations to e.g., follow up on the results of seasonal
outlooks, would also reduce the costs of remedial actions TSOs have to face today29
. This,
in turn, should have a positive effect on costs overall.
In addition, improving transparency and information exchange would facilitate
coordination, leading to a more efficient and less costly measures.
By ensuring that electricity markets operate as long as possible also in stress situations,
cost-efficient measures to prevent and resolve crisis are prioritized.
The overall impact of the Commission Recommendations on cybersecurity for the energy
sector can be very broad, given the voluntary nature of this approach. If fully followed by
all Member States, the same impacts as in Option 2 should be considered. If only partially
considered by Member States, the average administrative cost would be rather low.
Who should be affected and how
Option 1 is expected to have a positive effect on society at large and electricity consumers
in particular, since it helps prevent crisis situations and avoid unnecessary cut-offs. Given
the nature of the measures proposed, no major other impact on market participants and
consumers is expected.
29
The example of the Summer Outlook 2016 for Poland involves the following remedial actions to prevent
emergency situations: (i) switching measures of the respective TSOs PSE and 50Hertz, as well as (ii)
rescheduling of DC loop flows involving DE, DK, SE, PL, (iii) bilateral re-dispatch between DE and PL
and (iv) multilateral re-dispatch additionally involving e.g. AT, CH. Out of those, (i) and (ii) are non-
costly measures whereas re-dispatch induces significant costs.
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On cybersecurity, given the voluntary approach of this option, several stakeholders (TSOs,
DSOs, generators, suppliers and aggregators) could be affected. However, the impact is
estimated limited as the costs of cybersecurity for regulated entities merely need to get
considered and taken into account by the regulatory authority. Thus, the TSOs and DSOs
affected could recover their costs via grid tariffs. In that case, the pass through of costs
would have an impact on consumers that could see a slightly increased in the final prices
of electricity.
Impact on business and public administration
The preparation of risk preparedness plans as well as the increased transparency and
information exchange in crisis management imply a certain administrative effort30
.
However, the impact in terms of administrative impact would remain low, as currently
Member States already assess risks relating to security of supply, and all have plans in
place for dealing with electricity crisis situations31
.
In addition, it is foreseen to withdraw the current legal obligation for Member States to
draw up reports monitoring security of supply32
, as such reporting obligation will no longer
be necessary where national plans reflect a common approach and are made transparent.
This would reduce administrative impacts.
Option 2 (Common minimum rules to be implemented by Member States plus
regional co-operation)
Contribution to the policy objectives
Option 2 build on Option 1, but adds the dimension of regional (and some) EU-level co-
operation. In particular, it requires Member States to pre-agree on certain aspects of the
Risk Preparedness Plans (notably on how to deal with situations of a simultaneous
electricity crisis). It also calls for a more systematic assessment of rare/ extreme risks at
the regional level. Given the interlinked nature of EU's electricity systems, enhanced
regional co-operation brings clear benefits when it comes to preventing and managing
crisis situations.
The regional approach in the identification of the crisis scenarios ensures a common
strategy to minimise impacts of possible crisis, focus in particular on correlated risks and
on risks that could affect simultaneously several Member States. This would significantly
improve level of preparedness at national, regional and EU level, as the cross-border
considerations are duly taken into account since the beginning. The regional coordination
of plans would build trust between Member States which is crucial in times of crisis. The
harmonised approach via Network Codes/Guidelines would also ensure a minimum level
of harmonization for cybersecurity in the energy sector throughout the EU.
30
Administrative costs are defined as the costs incurred by enterprises, the voluntary sector, public
authorities and citizens in meeting legal obligations to provide information on their action or production,
either to public authorities or to private parties.
31
All twenty-eight Member States have a general obligation to monitor the security of electricity supply
from which implicitly follows the obligation to assess electricity supply risks, while nine countries have
a direct legal obligation to carry out an assessment of these risks. (Source: Risk Preparedness Study).
32
Article 4 of the Electricity Directive; Article 7 of the Electricity SoS Directive.
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The agreement at regional level of some aspects of the risk preparedness plan would
ensure that coordination and cooperation is agreed in advance. This is particularly relevant
as regards situations of simultaneous crisis.
The regional approach for the ENTSO-E's seasonal outlooks would ensure a more
granular and in-depth assessment of possible cross-border situations. This could give a
better indication of the impacts of possible crisis situations and the possible solutions that
cooperation could bring.
The introduction of security of supply indicators to assess how well Member States
perform in the area of security of supply would enhance comparability and mutual trust in
neighbours.
The reinforced role of the Electricity Coordination Group would ensure transparency
and wide discussion in prevention and managing crisis. It would also facilitate the
exchange of information in situations of early warning and crisis and the ex-post
evaluation. In addition, it would enhance the coordination of measures and ensure more
uniformity and coherent plans. Overall, the reinforcement of tasks and powers of ECG
would contribute to enhance cooperation and to build trust and confidence among Member
States.
Economic Impacts
This option would lead to better preparedness for crisis situations at a lesser cost through
enhanced regional coordination. The results of METIS simulations33
show that well
integrated markets and regional coordination during periods of extreme weather conditions
(i.e. very low temperature34
) are crucial in addressing the hours of system stress hours (i.e.
hours of extreme electricity demand), and minimizing the probability of loss of load
(interruption of electricity supply).
Most importantly, while a national level approach to security of supply disregards the
contribution of neighboring countries in resolving a crisis situation, a regional approach to
security of supply results in a better utilization of power plants and more likely avoidance
of loss of load. This is due to the combined effect of the following three factors: (i) the
variability of renewable production is partly smoothed out when one considers large
geographical scales, (ii) the demands of different countries tend to peak at different times,
and (iii) the power supply mix of different countries can be quite different, leading to
synergies in their utilization.
The following table compares the security of supply indicator "expected energy non-
served" (EENS) assessed by METIS for the three levels of coordination (national, regional,
33
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016).
34
Even though periods with very low temperature occur rarely (9C difference between the 50 year worst
case and the 1% centile) countries can face high demand peaks (e.g. Nordic countries and France) mainly
due to the high consumption for the electric heating. As example, the additional demand for the 50 years
peak compared to the annual peak demand is 23% for France, 18% for Sweden and 17.3% for Finland.
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European)35
. It highlights an overestimation of the loss of load, when it is measured in a
scenario of non-coordinated approach, which does not take into account the potential
mutual assistance between countries.
Table 9 - Global expected energy non-served as part of global demand within the
three approaches
Level EENS (% of annual load) – ENTSO-E V136 scenario
National level 0,36 %
Regional level 0,02 %
European level 0,01 %
Source: METIS
The EENS for the three levels of coordination are represented on the figure below. When
the security of supply is assessed at the national level, many countries of central Europe
seem to present substantial levels of loss of load. However, since these countries are
interconnected, a regional assessment of security of supply (taking into account power
exchanges within this region) significantly decreases the loss of load levels.
Figure 1 - EENS (%) estimation by country for scenario ENTSO-E 2030 v1 with
CCGT/OCGT current generation capacities. From left to right: EENS estimated at
European, regional and national levels
Source: METIS
METIS simulations also show that thanks to regional cooperation the stress situations
would decrease and concentrate in a limited number of hours that may occur
simultaneously. Therefore, it highlights the need for specific rules on how Member States
should proceed in these particular circumstances, as proposed in this Option 2.
35
"METIS Study S04: Stakes of a common approach for generation and system adequacy", Artelys (2016).
36
ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario where
no common European decision regarding how to reach the CO2-emission reductions has been reached.
Each country has its own policy and methodology for CO2, RES and system adequacy.
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As the overall cost of the system would decrease thanks to enhanced coordination this
could have a positive impact on prices for consumers.
On the contrary, a lack of coordination on how to prevent and manage crisis situations
would imply significant opportunity costs. A recent study also evidenced that the
integration of the European electricity market could deliver significant benefits of 12.5 to
40 billion euro until 2030. However, this amount would be reduced by 3 to 7.5 billion euro
when Member States pursue security of electricity supply objectives following going alone
approaches37
.
Overall, the costs to develop and to follow a Network Code or Guidelines on cyber-security
would be limited. Additionally, given the administrative nature of the Option, the impact
could be estimated limited as it mostly requires harmonising existing practices available in
most of Member States. In addition, some obligations specific for the energy sector would
reinforce existing provisions on the NIS Directive such as the identification of operations
of essential services and the reporting obligation of cyber-incidents. Security does in
general not present a separate budget line; that is why it is very hard to estimate how much
is already spent on cybersecurity expenditures. Some of the costs might also be hidden in
other budget lines, like in human resources, securing buildings, etc. Thus there is very few
evidence on cybersecurity expenses in the energy sector. As example, according to a US
survey in a small sample of 21 utilities and energy companies, they spent an average of
$45.8 million a year on computer security to prevent 69% of known cyber strikes against
their systems in 201138.
On the contrary, the damages of cybersecurity breaches could be
huge. Even though the range of costs varies on the incident, a recent study reveals a wide
spectrum of costs ranging from $156,000 (very low end estimate) to $5.5 million per single
event39
. Additional costs may arise through losses in stock value. Overall, the costs of a
blackout following a cyber-incident are the same as for a physical incident. Therefore, the
overall impact of rules on cybersecurity would be limited while the benefits of preventing
cyber-incidents could be high.
Who should be affected and how
As in the case for Option 1, Option 2 is expected to have a positive effect on society at
large and electricity consumers in particular, since it helps prevent crisis situations and
avoid unnecessary cut-offs. Given that, under Option 2, Member States would be required
to effectively cooperate, and tools would be in place to monitor security of supply via the
Electricity Coordination Group, such crisis prevention and management would be even
more effective.
The measures would also have a positive effect on the business community, as there would
be much more transparency and comparability as regards how Member States prepare for
and intend to manage crisis situations. This will increase legal certainty for investors,
37
"Benefits of an Integrated European Energy Market (2013)", BOOZ&CO.
38
Insurance as a risk management instrument for energy infrastructure security and resilience (2013), U.S.
Department of Energy: http://www.bloomberg.com/news/articles/2012-02-01/cyber-attack-on-u-s-
power-grid-seen-leaving-millions-in-dark-for-months.
39
Insurance as a risk management instrument for energy infrastructure security and resilience" (2013),
U.S. Department of Energy: http://www.bloomberg.com/news/articles/2012-02-01/cyber-attack-on-u-s-
power-grid-seen-leaving-millions-in-dark-for-months.
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power generators, power exchanges but also for TSOs when managing short-term crisis
situations.
Among the stakeholders the most affected would be the competent authorities (e.g.
Ministry, NRA) as actors responsible for the preparation of the risk preparedness plans
(see below, assessment of impacts on public authorities).
Other actors, such as TSOs, could be also affected, given in particular the possibility for
the Competent Authorities to delegate certain tasks (e.g. carry out the risk assessment).
However, as the tasks delegated would be closely linked to the tasks attributed by law to
the TSOs (e.g. ensuring the ability of the system to meet demand), the impact of the specific
tasks delegated would be limited.
ENTSO-E could be affected as well as it has to identify the cross-border scenarios and
improved the seasonal outlooks with more robust regional analysis. Given the possibility
for ENTSO-E to delegate certain tasks to the ROCs, the national TSOs as members of the
ROCs could be also affected. However, the impact would remain limited given the current
experience of TSOs on risk analysis and the existing cooperation among the TSOs.
Impact on business and public authorities
The assessment of this option shows a limited increase in administrative impact, although
it would be to some extent higher than Option 1, given that national authorities would be
required to pre-agree part of their risk preparedness plans in a regional context.
However, existing experiences show that a more regional approach to risk assessment and
risk preparedness is technically and legally feasible. Further, since the regional parts of the
plans would in practice be prepared by regional co-ordination centres between TSOs, the
overall impact on Member States' administrations in terms of 'extra burdens' would be
limited, and be clearly offset by the advantages such co-operation would bring in
practice.40
In addition, more regional cooperation would also allow Member States to create
synergies, to learn from each other, and jointly develop best practices. This should,
overtime, lead to a reduction in administrative impacts.
Finally, European actors such as the Commission and ENTSO-E would provide guidance
and facilitate the process of risk preparation and management. This would also help reduce
impacts on Member States.
It should be noted, that under Option 2 (as is the case for Option 1) no new body or new
reporting obligation is being created, and that existing obligations are being streamlined.
Thus, the Electricity Coordination Group is an existing body meeting regularly, for the
future it is foreseen to make this group more effective by giving it concrete tasks. Further,
national reporting obligations would be reduced (e.g. repealing the obligation of Article 4
40
The Nordic TSOs, regulators and energy authorities cooperate through NordBER, the Nordic
Contingency and Crisis Management Forum. This includes information exchange and joint working
groups and contingency planning for the overall Nordic power sector as a supplement to the national
emergency work and TSO cooperation (www.nordber.org).
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of Electricity Directive) and EU-level reporting would take place within the context of
existing reports and existing reporting obligations (e.g. ACER annual report Monitoring
the Internal Electricity and Natural Gas Markets).
Option 3 (Full harmonisation and full decision-making at regional level)
Contribution to the policy objectives
The measures of this Option pursue the maximum level of harmonisation at EU level with
the clear aim to increase the level of preparedness ahead of a crisis and the mitigation of
the impact in the case of an unexpected event occurs.
The starting point for this option is the preparation of risk preparedness plans at regional
level. Even though the regional plans would ensure full coherence of actions ahead and in
particular in a crisis, it would be difficult that all national specificities could be addressed
through regional plans.
The creation of a new EU agency dedicated to cybersecurity in the energy sector would
ensure full harmonisation on risk preparedness, communication and coordination across
Europe. Additionally, the agency would facility a quick and coordinated cross-border
reaction on cyber-incidents.
Economic Impacts
The regional coordination through the regional plans would have a positive impact in term
of cost as the number of plans would be necessary less than twenty-eight plans and limited
to the number of regions. In addition, the coordination at European level would decrease
slightly the loss of load level compared to the regional coordination (EENS 0,01%
compared to 0,02%).
On the contrary, on cybersecurity, the creation of a dedicated agency at EU level would
have important economic implications as this agency would be a new body that does not
exist yet and which is also not foreseen in the NIS Directive. The costs of creating this new
agency are not only limited to the creation of a new agency itself, but the costs would also
have to include the roll-out of a whole security infrastructure. For example, the estimated
costs of putting in place the necessary security infrastructure and related services to
establish a comparable national body - cross-sectorial governmental Computer Emergency
Response Team (CERT) with the similar duties and responsibilities at national level as the
planned pan-European sector-specific agency - would be approximately 2.5 million EUR41
per national body. This means that the costs for the security infrastructure would be
manifold for a pan-European body. In terms of human resources, for the proper functioning
of the new agency with minimum scope and tasks at EU level, it is estimated a staff of 168
full time equivalents (considering 6 full time equivalents per Member State sent to the EU
agency). The representation from all Member States in the agency is essential in order to
41
SWD(2013) 32 final.
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ensure trust and confidence on the institution. However, the availability of network and
information security experts who are also well-versed in the energy sector is limited.
Who should be affected and how
The obligation of regional plans would have important implications for the competent
authorities as the coordination and agreement of common issues (e.g. load shedding plan,
harmonised definition of protected customers) would be a lengthy and complex process.
On cybersecurity, the creation of the new agency at EU level would mobilize highly
qualified human resources with skills in both energy and information and communication
technologies (ICT). This could have a potential impact on national administrations and
energy companies as long as some of the experts in the field could be recruited by the new
institution. However, the impact would be limited as the representation for all Member
States should be guaranteed. Therefore, a small number of experts (around 6) per country
could be recruited.
Impact on business and public authorities
Overall Option 3 would imply significantly administrative impact in the preparation of the
regional plans. It would require important efforts to gather information related to national
and regional circumstances and contribute to the joint task of assessing the risks and
identifying the measures to be included in the plans. In any case, it would seem difficult to
coordinate within a region the national specificities and risks originate mostly in one
Member State.
The creation of a new agency on cybersecurity would imply significant administrative
impacts in the preparation and set-up of the agency, as well as in the communication
structure with already existing cross-sectorial bodies of Member States (CERTs/CSIRTs).
Conclusion
From the point of view of impacts, particularly costs and administrative impact, Option 1
could in principle appear as preferred option. However, the performance in terms of
effectiveness and efficiency is limited compared to Option 2 and 3. Additionally, impacts
associated with Option 3 are neither proportionate nor fully justified by the effectiveness
of the solutions, which makes Option 3 perform poorly in terms of efficiency compared to
Option 2.
Overall, the more harmonized approach to security of supply through minimum rules
pursued by Option 1 would not solve all the problems identified, in particular, the
uncoordinated planning and preparation ahead of a crisis. As regards Option 1, the main
drawback of this approach is that each Member State would be drafting and adoption the
national risk preparedness plans under its own responsibility. Given the urgency to enhance
the level of protection against cyber threats and vulnerabilities, it must be concluded that
Option 1 regarding cybersecurity is not recommended, because it is not viable for reaching
the policy objectives, given that the effectiveness would depend on whether the voluntary
approach would actually deliver a sufficient level of security.
Option 2 addresses many of the shortcomings of Option 1 providing a more effective
package of solutions. In particular, the regionally coordinated plans ensure the regional
identification of risks and the consistency of the measures for prevention and managing
crisis situations. For cybersecurity this option creates a harmonised level of preparedness
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in the energy sector and ensures that all players have the same understanding of risks and
that all operators of essential services follow the same selection criteria for the energy
sector throughout Europe.
Overall, Option 3 represents a highly intrusive approach that tries to address possible risks
by resorting to a full harmonisation of principles and the prescription of concrete solutions.
The assessment of impacts in Option 3 shows that the estimated impact on cost is likely to
be high and looking at the performance in terms of effectiveness, it makes Option 3 a
disproportionate and not very efficient option.
In the light of the previous assessment, the preferred option would be Option 2. This
option is the best in terms of effectiveness and, given its economic impacts, has been
demonstrated to be the most efficient as well as consistent with other policy areas.
Subsidiarity
The necessity of EU action is based on the evidence that national approaches not only lead
to sub-optimal measures, they also make the impacts of a crisis more acute. Additionally,
the risk of a blackout is not confined to national boundaries and could directly or indirectly
affect several Member States. Therefore, national actions in terms of preparedness and
mitigation cannot only be defined nationally, given the potential impact on the level of
security of supply of a neighbouring Member State and/or on the availability of measures
to tackle scarcity situation.
The increasing interconnection of the EU electricity markets requires a coordination of
measures. In the absence of such coordination, security of supply measures (including
measures on cybersecurity) implemented at national level only are likely to jeopardize
other Member States' or the security of supply at EU level. Situations like the cold spell of
2012 showed that coordination of action and solidarity are of vital importance. An action
in one country can provoke risks of blackouts in neighbouring countries (e.g. electricity
export limitations imposed by Bulgaria in February 2012 had an impact in the electricity
and gas sectors in Greece). By contrary, coordination may offer a wider range of solutions.
So far, the potential for more efficient and less costly measures thanks to the regional
coordination has not being fully exploited, which is detrimental to EU consumers.
However, the regional approach to security of supply also requires paying special attention
to the divergences that between regions could appear. Therefore such coordinated approach
requires action at the EU level. Action at EU level could be also needed under certain
situations where the security of supply in the EU, cannot be sufficiently achieved by the
Member States alone and can therefore, by reason of the scale or efforts of the action, be
better achieved at Union level.
The EU action is framed under Article 194 of Treaty of the Functioning of the Energy
Union (TFEU) which recognizes that certain level of coordination, transparency and
cooperation of the EU Member states' policies on security of supply is necessary in order
to ensure the functioning of the energy market and the security of supply in the Union.
Stakeholders' Opinions
The results of the Public Consultation on Risk Preparedness in the area of Security of
Electricity Supply showed that the majority of respondents (companies, associations and
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Governments) take the view that the current legal framework (the SoS Directive) is not
sufficient to address the interdependencies of an integrated European electricity market.
Assessments and Plans
A majority of stakeholders is in favour of requiring Member States to draw up risk
preparedness plans (see as example the answers from the Dutch and Latvian Governments,
GEODE, CEDEC, EDF UK, TenneT, Eurelectric and Europex).
Stakeholders also see a need for regional coordination of the assessment and preparation
for rare/extreme risks (see for example the anwers of the Estonian, Finish, French, Dutch,
Swedish Governments as well as ENTSO-E and Eurelectric). However, there is no
agreement on how to 'define' regions for planning and cooperation. Most stakeholders
suggest to use existing (voluntary) systems for regional cooperation as a staring point (e.g.
the Finish Government) and emphasize the role of the existing RSCs (e.g. the Czech
Government). Also the European Parliament42
takes the view that it makes sense to step
up cooperation within and between regions under the coordination of ACER and with
cooperation of ENTSO-E, particularly as regards evaluating cross-border impacts.
Stakeholders further make the case for a common methodology for assessing risks to
ensure comparability of results (e.g. EDF). This could be achieved through common high-
level templates (e.g. answers from the Finish, Dutch, Norwegian Governments and the
German Association of Local Utilities). There is general acknowledgement of the
importance of preventing risks related to cyber-attacks.
Many stakeholders stress the need for a definition/clarification on roles and responsibilities
as well as operational procedures to be followed (e.g. who to contact in times of crisis).
Stakeholders see the added value of designating one 'competent authority' per Member
States, however there is no agreement on who this should be. Some argue that the choice
should be left with the Member States (see for example the answers from the Norwegian
Government or the German Association of Local Utilities) while others prefer a strong
mandate of the TSOs (e.g. TenneT).
Crisis management
Stakeholders, in particular from the industry also request more transparency to reduce the
scope for measures that unnecessarily distort markets. A majority of stakeholders sees a
need for clear provisions on the suspension of market activities, "protected customers" and
cost compensation (e.g. EDF).
Even though stakeholders point out that the draft Network Codes and current practice
should be taken into account, they see a need for political discussion on regional level and
the definition of clear principles for crisis management as e.g. curtailment in simultaneous
42
See: Towards a New Energy Market Design (June 2016), Werner Langen, European Parliament,
paragraph 68.
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scarcity situations requires political decision (e.g. ENTSO-E43
). The need to develop a
more common approach to managing crisis situations within the EU while taking into
account the existing regional solutions is also seen by the Dutch Presidency of the
European Council44
and the Florence Forum45
.
Monitoring
In order to ensure adequate oversight, most stakeholders are in favour of a system of peer
reviews to be conducted in a regional context or in the frame of the Electricity Coordination
Group which could provide the interlinkage between technical and political/economical
aspects. Monitoring could be further enhanced through more common and transparent
approach to standards. Some stakeholders wish a stronger role for ACER/ENTSO-E and a
rather facilitating role for the Commission (e.g. CEER, ENTSO-E)
43
See for example ENTSO-E's presentation on Capacity Mechanisms (TOP 2.4) from the Florence Forum
in June 2016, ENTSO-E (available: https://ec.europa.eu/energy/en/events/meeting-european-electricity-
regulatory-forum-florence).
44
See Note to the Permanent Representatives Committee/Council: Messages from the Presidency on
electricity market design and regional cooperation, paragraph 7.
45
See Conclusions from Florence Forum, March 2016, paragraph 10.
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7. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA 4: THE SLOW DEPLOYMENT
OF NEW SERVICES, LOW LEVELS OF SERVICE AND POOR RETAIL MARKET PERFORMANCE
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7.1. Addressing energy poverty
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Summary table
Objective: Better understanding of energy poverty and disconnection protection to all consumers
Option: 0 Option: 0+ Option 1 Option 2
BAU: sharing of good practices. BAU: sharing of good practices
and increasing the efforts to
correctly implement the
legislation.
Voluntary collaboration across
Member States to agree on scope
and measurement of energy
poverty.
Setting an EU framework to monitor energy
poverty.
Setting a uniform EU framework to
monitor energy poverty, preventative
measures to avoid disconnections and
disconnection winter moratorium for
vulnerable consumers.
Energy poverty - EU Observatory of Energy
poverty (funded until 2030).
- Option 0+: EU Observatory of Energy
Poverty (funded until 2030).
- Generic description of the term energy
poverty in the legislation. Transparency in
relation to the meaning of energy poverty
and the number of households in a situation
of energy poverty
- Member States to measure energy poverty.
Better implementation of the current
provisions.
- Option 0+: EU Observatory of Energy
Poverty (funded until 2030).
- Specific definition of energy poverty
based on a share of income spent on
energy.
- Member States to measure energy
poverty using required energy.
Better implementation and transparency
as in Option 1.
Disconnection
safeguards
- NRAs to monitor and report
figures on disconnections.
- NRAs to monitor and report figures on
disconnections.
- NRAs to monitor and report figures on
disconnections.
- A minimum notification period before a
disconnection.
- All customers to receive information on
the sources of support and be offered the
possibility to delay payments or
restructure their debts, prior to
disconnection.
- Winter moratorium46
of disconnections
for vulnerable consumers.
46
An all season moratorium may be suitable to some MS but not necessarily to all. In addition, evidence on Excess Summer Death is less developed than for Excess Winter Deaths which
makes it difficult to quantify the cost/benefits. Finally, stakeholders have noted that while in winter, heating is necessary, particularly if affected by bad health. Other cost effective solutions
can be found for heatwave (drink water; staying indoors). We are aware that in some MS the housing stock is not prepared for heatwaves and houses are overheated. However, this may be
better assessed at Member State level.
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Pros - Continuous knowledge exchange. - Stronger enforcement of current
legislation and continuous
knowledge exchange.
- Clarity on the concept and measuring of
energy poverty across the EU.
- Standardised energy poverty concept
and metric which enables monitoring of
energy poverty at EU level.
- Equip Member States with the tools to
reduce disconnections.
Cons - Existing shortcomings of the legislation
are not addressed: lack of clarity of the
concept of energy poverty and the
number of energy poor households
persist.
- Energy poverty remains a vague concept
leaving space for Member States to
continue inefficient practices such as
regulated prices.
- Indirect measure that could be viewed as
positive but insufficient by key
stakeholders.
- Insufficient to address the
shortcomings of the current
legislation with regard to energy
poverty and targeted protection.
- New legislative proposal necessary.
- Administrative costs.
-
- New legislative proposal necessary.
- Higher administrative costs.
- Potential conflict with principle of
subsidiarity.
- Specific definition of energy poverty
may not be suitable for all Member
States.
- Safeguards against disconnection may
result in higher costs for companies
which may be passed to consumers.
- Safeguards against disconnection may
also result in market distortions where
new suppliers avoid entering markets
where risks of disconnections are
significant and the suppliers active in
such markets raise margins for all
consumers in order to recoup losses
from unpaid bills.
- Moratorium of disconnection may
conflict with freedom of contract.
Most suitable option(s): Option 1 is recommended as the most balanced package of measures in terms of the cost of measures and the associated benefits. Option 1 will result in a clear
framework that will allow the EU and Member States to measure and monitor the level of energy poverty across the EU. The impact assessment found that the propose disconnection
safeguards in Option 2 come at a cost. There is potential to develop these measures at the EU level. However, Member States may be better suited to design these schemes to ensure that
synergies between national social services and disconnection safeguards can be achieved. Please note that Option 1 and Option 2 also include the measures described in Option 0+.
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Description of the baseline
Energy has a fundamental role to ensure adequate households' standards of living. Energy
services are crucial to ensure warm homes, water and meals, lighting, refrigeration and the
operation of other appliances. European households are, however, increasingly unable to
meet their basic energy needs due to energy prices increasing faster than household income
and inefficient housing and household appliances leading to higher energy bills47
.
An affordable connection to energy supply facilitates modern daily life by providing
essential services and enabling social interactions. Lack of access to an energy supply
impinges on the rights of energy consumers and negatively affects living conditions and
health48
. This is well recognised in legislation49
and reflected in the overall objectives of
the European Internal Energy Market (IEM).
Under the existing provisions in the Electricity and Gas Directive, Member States have to
address energy poverty where identified. The evaluation of the provisions found important
shortcomings stemming from the opaqueness of the term energy poverty, particularly in
relation to consumer vulnerability, and the lack of transparency with regards to the number
of households suffering from energy poverty across Member States.
The aim of this Section is to describe the two policy areas impacted by the proposed
options: energy poverty and disconnection safeguards.
Energy poverty: drivers of energy poverty and number of households in energy poverty
Energy poverty is often defined as the situation in which individuals or households are not
able to adequately heat their homes or meet other required energy services at an affordable
cost50
.
Energy poverty is usually discussed in the context of general poverty. Yet, households face
widely varying costs to achieve the same level of warmth for reasons other than income,
such as, energy efficiency of the dwelling or household's ability to interact with the market.
In addition, an adequate level of energy is essential for citizens to function and actively
participate in society51
.
47
Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies and
measures. (2015). Insight_E.
48
COM (2015) "A framework Strategy for a Resilient Energy Union with a Forward-looking Climate
Change Policy"
49
Directive 2009/72/EC Point 45 states that “Member States should ensure that household
customers...enjoy the right to be supplied with electricity of a specified quality at clearly comparable,
transparent and reasonable prices.”
50
Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies and
measures. (2015). Insight_E.
51
Fuel Poverty: The problem and its measurement. 2001. John Hills. Available at:
http://sticerd.lse.ac.uk/dps/case/cr/CASEreport69.pdf. Working Paper on Energy Poverty. 2016.
Vulnerable Consumer Working Group. The Vulnerable Consumer Working Group (VCWG) provides
advice to the European Commission on the topics of consumer vulnerability and energy poverty.
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Insight_E identifies high energy bills, low income and poor energy efficiency as the main
drivers of energy poverty52
.
Figure 1: Drivers of energy poverty
Source: Insight_E (2015)
Looking at the drivers, it is likely that energy poverty impacts low-income households with
higher energy needs. Eurostat publishes the number of households who felt unable to keep
warm during winter. This indicator is widely used in the literature as a proxy indicator of
energy poverty. In 2014, around 10% of the EU population was not able to keep their home
adequately warm53
(see Figure below).
Industry, consumer associations, regulators and Member States representatives are members of the
group.
52
Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies and
measures. (2015). Insight_E.
53
The indicator is measured as part of the Eurostat Survey on Income and Living Conditions (EU-SILC).
ENERGY
POVERTY
ENERGY
AFFORDABILITY
ENERGY
USE
PATTERNS
HOUSING
PATTERNS
HIGH
ENERGY
BILLS
POOR
ENERGY
EFFICIENCY
LOW
INCOME
Indicators:
- Energy consumption
(type)*
- Type of heating
system & share of
central heating*
Indicators:
- Tenure system*
- Housing
characteristics*
Indicators:
- Income
- Energy prices*
- Energy
consumption
(level)
* : exogenous
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Figure 2: Percentage of all households and households in poverty that consider they
are unable to keep warm
Source: Eurostat – SILC indicators (Inability to keep home adequately warm - Code: ilc_mdes01)
Evidence suggests that energy poverty is increasing in Europe. In recent years, energy
prices have risen faster than household disposable income54
, which has been particularly
problematic for low-income households, who depending on their individual circumstances,
may have had to under-heat their homes, reduce consumption on other essential goods and
services or get into debt to meet their energy needs55
.
Data from Member States on household energy consumption shows that the poorest
households have seen their share of disposable income spent on gas, electricity and other
fuels used for domestic use56
increased more than middle-income households. The Figure
below presents the EU share of household expenditure on domestic energy between 2000
and 2014.
54
Source: Eurostat (Electricity prices for domestic consumers; Gas prices for domestic consumers;
disposable income of households per capita; period 2010 – 2014).
55
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
56
Domestic use refers to heating, lighting and powering appliances.
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Figure 3: EU average - share of households' budget spent on domestic energy services
Source: National Statistical Authorities of EU Member States; VCWG (2016)
In 2014, expenditure on energy services for the poorest households in the EU increased by
50%, reaching almost 9% of their total budget.
Preliminary analysis for the upcoming Energy Price and Cost Report indicates that in most
of the EU Member States the share of energy in total expenditure grew faster in the lowest
income quintile than in the third quintile, implying that increasing energy costs impacted
poorer households more significantly than those on middle income. For instance, the EU
average spending for households in the lowest income quintile on electricity and gas
increased by 24% in real terms. As a comparison, middle income households saw their
domestic energy expenditure increase by 18% in real terms.
The lack of affordability of domestic energy services, which can be understood as a proxy
for energy poverty, can have serious consequences on households' well-being.
The Marmot Review highlighted the strong relationship between colder homes, Excess
Winter Deaths (EWDs) and increased incidence of other health problems. The review
found that 22% of EWDs in the UK could be attributed to cold housing. Healy57
found that
countries with the poorest housing (Portugal, Greece, Ireland, the UK) show the highest
excess winter mortality.
The Figure below presents EWD58
for the EU Member States in 2014. The Figure shows
that deaths in winter are significantly higher than during the rest of the year, particular for
some Member States.
57
Excess winter mortality in Europe: a cross country analysis identifying key risk factors. (2003). Healy.
58
Excess Winter Deaths = winter death (December – March)- 0.5Non-winter deaths (August –
November, April – July / (average of non-winter deaths)
6%
9%
5%
6%
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Poorest households Middle income households
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Figure 4: Excess Winter Deaths – 2014
Source: EU Buildings Database (BPIE)
In addition to the negative impacts on health, energy poverty can result in high level of
indebtedness or even disconnection. At the EU level, energy poverty risks excluding some
consumers from the energy transition, preventing them from enjoying the benefits of the
IEM.
The issue of energy poverty or lack of affordability of domestic energy services is likely
to remain relevant. In a scenario where energy prices follow GDP growth while wages,
especially for low-income workers remain flat, the gap between household income and
energy prices will widen and energy poverty is likely to increase. There are two main
channels through which wages for low-skilled workers may be supressed:
- Automation: routine tasks which are usually carried out by low-skilled workers can
be automated as technology allows. As the cost of technology falls, low-skilled
wages may be supressed to compete with capital59
.
- Skill-bias innovation: modern economics rely on a more educated workforce. As
demand for skilled individuals increases, it decreases the demand for unskilled
workers and their wages60
These effects combined are likely to supress wages, making affordability of energy
services more difficult for low-income households and, as a result, increase the number of
households in energy poverty.
Disconnection safeguards: protecting energy poor and vulnerable consumers
59
Unemployment and Innovation, No 20670, NBER Working Papers. 2014. Stiglitz.
60
"Skills, Tasks and Technologies: Implications for employment and earnings", No 16082, NBER
Working Papers. 2010. Acemoglu and Autor.
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The evaluation identified that given the rising levels of energy poverty. Member States
may have been discouraged to phase out regulated prices. Regulated prices, however, have
negative implications on consumers, hindering competition and innovation61
.
The evaluation recommended that any future legislative change could look into reinforcing
EU assistance on energy poverty proposing appropriate tools for addressing energy poverty
which support Member States' efforts to phase-out regulated prices62
. Article 3 of the
Electricity Directive63
and Gas Directive 64
markets reinforces the role of consumer
protection and the additional need for protection of vulnerable consumers through
particular measures, referring to the prohibition of electricity (and gas) in critical times as
one option.
Disconnections in electricity or gas supply to residential households typically arise out of
non-payment and can become especially problematic for households struggling to keep up
with their bills. In addition, there may be a disproportionately negative impact on
households with children or elderly residents in terms of health, education, etc.
In what follows, we provide an overview of the number of households being disconnected
and the main disconnection safeguards applied by Member States.
Overview of electricity and gas disconnections in the EU
Disconnection rates vary significantly across Member States. Figure 5 indicates that the
higher the disconnection level, as can be expected, the higher the arrears on utility bills65
,
which increases when the income falls below 60% of the median income. Similar
disconnection levels (Malta, Denmark, France, and Austria) exhibit similar levels of
arrears on utility bills. However, there are some exceptions: UK, Lithuania, Belgium and
Luxembourg have relatively high arrears and low disconnection rates.
61
A detail description of the negative impacts of regulated prices and the Member States currently applying
some kind of price regulation mechanism is included in Annex on Price Regulation
62
All energy consumers explicitly have a number of rights including a right to an electricity connection,
choice of and ability to switch supplier, clear contract information and right of withdrawal, and accurate
information and billing on energy consumption, vulnerable customers should receive specific protection
measures to ensure adequate protection.
63
“Member States shall take appropriate measures to protect final customers, and shall, in particular,
ensure that there are adequate safeguards to protect vulnerable customers. In this context, each Member
State shall define the concept of vulnerable customers which may refer to energy poverty and, inter alia,
to the prohibition of disconnection of electricity to such customers in critical times. Member States shall
ensure that rights and obligations linked to vulnerable customers are applied. In particular, they shall
take measures to protect final customers in remote areas.”
64
Directive 2009/73/EC of the European Parliament and the Council of 13 July 2009 concerning common
rules for the internal market in natural gas and repealing Directive 2003/55/EC (OJ L 211, 14.8.2009, p.
94).
65
Eurostat EU-SILC 2014
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Figure 5: Share of customers with electricity disconnections, gas disconnection, and
share of population in arrears on utility bills
Source: Insight_E (Forthcoming); Data: Eurostat; CEER National Indicators Database 2015
The rate of electricity disconnections, where the data is available, is highest across the
southern European Member States that have arguably been hardest hit by recessionary
effects of the recent economic downturn66
. In fact, in those Member States, households
exhibit the highest shares of debt on utility bills.
In terms of gas disconnections, where the data was reported, Portugal, Italy, Greece and
Hungary exhibit the highest levels of gas disconnections followed by France, Spain,
Poland, Austria, Germany and Slovakia.
Disconnection safeguards: a classification of measures
Disconnection safeguards represent one of the measures that Member States implement to
protect energy consumers. These measures ensure consumers have a continuous supply of
energy. Such safeguards can be applied to the entire customer base or to specific groups,
such as vulnerable consumers.
Disconnection safeguards can be grouped into four key measures, which can take the form
of direct protection measures, such as disconnection prohibitions, and / or other
complementary associated measures such as debt management, and customer engagement.
See Table below67
.
66
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
67
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
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Table 1: Summary of disconnection safeguards
Measure Description
Disconnection
prohibition
Moratorium on disconnecting the energy supply (either electricity, gas or both) for all
customers, a specific target group or time period (e.g., Winter)
Debt management Debt management can include a negotiated a payment plan, delayed payment
responsibility or a financial grant to assist with costs.
Customer
engagement
Customer engagement typically involves communication between the energy supplier
and the customer, where either the customer contacts the energy supplier for assistance
or the energy supplier is required to engage with the customer before commencing the
actual disconnection.
Source: Insight_E (Forthcoming)
Member States use a combination of these measures to prevent consumers from
disconnection. A summary of those is reported in Table 2.
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Table 2: Disconnection protection safeguards by Member States
E electricity G gas L legislated V voluntary
Source: CEER National Indicators Database 2015, INSIGHT_E Country Reports 2015
Focus AT BE BG CY CZ DE DK EE ES FI FR GR HR HU IE IT LT LV LU MT NL PL PT RO SE SK SI UK
All consumers EG
Vulnerable consumers/low
income/socio-demographic
E E EG EG EG EG EG EG E
Consumers with (or at risk
of) medical conditions
E EG E EG EG EG EG E E
Services (such as public
lighting, hospitals and
transport)
EG E
Unemployed consumers
EG EG EG
Under bill dispute
settlement
E E EG EG EG E
All consumers
EG EG E EG
Vulnerable consumers/low
income/socio-demographic
EG EG EG EG EG EG EG E EG
Consumers with (or at risk
of) medical conditions
EG EG EG
Debt management
LV LV L L LV LV L V L L L L L L L L L L
Prepaid meters
LV L LV L L L L L
Customer engagement
LV LV LV L LV L L LV LV L L L LV L V
Elec Discon per 1000
customers
9.1 1.5 55.1 7.5 10.0 23.0 10.0 32.6 6.3 3.6 40.0 1.8 3.0 10.0 20.0 56.1 14.0 0.0
Prepaid meters per 1000
customers
1.4 46.0 0.0 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 15.1 0.0 0.0 12.0
Disconnection
prohibition
Complementary
measures
Measures
year-round
measures
Seasonal
measures
(Winter
or
certain
days
of
the
week)
Statistics
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Disconnection safeguards - disconnection prohibition
Disconnection prohibitions are non-financial measures where moratoriums on
disconnections are declared, often for specific customer groups or for specific time periods.
These include measures that forbid disconnection to all customers or a target group, or
measures that allow disconnection only after certain stringent steps have been taken.
Prohibition can apply at particular times of the year (e.g., Winter), target particular socio-
demographic characteristics (e.g., either defined through the official definition for
“vulnerable consumer” or target households with elderly or children), where this would
have a negative impact on health, to customers in a legitimate complaint process, or to a
situation where a country is going through a national economic crisis68
.
Nineteen states have either year-round or seasonal disconnection prohibition.
Disconnection prohibition is legislated exclusively all year-round for specific customer
groups in seven Member States (Cyprus, Denmark, Spain, Luxembourg, Poland, Portugal,
Sweden), two Member States offer seasonal disconnection prohibition only (Belgium, UK)
and eleven Member States offer both year-round and seasonal disconnection prohibition
to varying customer groups (Estonia, Finland, France, Greece, Hungary, Ireland, Italy,
Lithuania, Netherlands, Romania and Slovenia).
Only four Member States provide blanket coverage for consumers in relation to
disconnection protection, but only on a seasonal basis (Belgium, Estonia, Italy, and the
Netherlands). Other widely protected consumers are those with (or at risk of) medical
conditions (in ten Member States - Cyprus, Estonia, Spain, Finland, Greece, Hungary,
Ireland, the Netherlands, Sweden, Slovenia), and customers currently under dispute
settlements (in six Member States - Italy, Luxembourg, the Netherlands, Poland, Portugal,
Sweden).
Disconnection safeguards - debt management
Debt management can include non-financial arrangements such as counselling or
assistance with budgeting as well as financial arrangements including a negotiated
payment plan, delayed payment responsibility or a financial grant to assist with costs. In
some instances, this is a measure that regulators or energy suppliers are required to offer,
whereas in other Member States, this can be offered either voluntarily through a
government agency, an energy supplier, or other consultation bodies.
The use of debt management measures is legislated in 17 Member States (Austria,
Belgium, Cyprus, Czech Republic, Germany, Spain, France, Hungary, Ireland, Italy,
Luxembourg, Malta, the Netherlands, Poland, Sweden Slovenia, and UK), while four
Member States (Austria, Belgium, Germany, Spain) also implement additional voluntary
measures, whereas Greece implements only voluntary measures for debt management.
Disconnection safeguards - customer engagement
Customer engagement typically involves communication between the energy supplier and
the customer, where either the customer contacts the energy supplier for assistance or the
68
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
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energy supplier is required to engage with the customer before commencing the actual
disconnection.
Energy consumers have a right to clear and transparent billing information and a single
point of contact, whose role is to ensure that consumers receive all the information that
they need regarding their rights.
Some form of customer engagement is implemented in 15 Member States (Austria,
Belgium, Germany, Denmark, Spain, France, Ireland, Italy, Luxembourg, Poland,
Portugal, Romania, Sweden, Slovakia, and UK). Limited information is available on how
the various energy companies choose to engage with customers, but a review of the
regulators showed that the legislation usually ensures that consumers are notified about
their bills or an impending disconnection usually in the form of a letter69
.
Finally, 22 Member States combine the use of debt management and some form of
customer engagement including: Austria, Belgium, Cyprus, Czech Republic, Germany,
Denmark, Spain, France, Greece, Hungary, Ireland, Italy, Luxembourg, Malta, the
Netherlands, Poland, Portugal, Romania, Sweden, Slovakia, Slovenia and UK.
On the other hand six Member States do not have debt management or customer
engagement safeguards either in their legislation or voluntarily and include Bulgaria,
Estonia, Finland, Croatia, Lithuania and Latvia.
Disconnection notification periods and procedures for disconnection and reconnection
across Member States
Even if the time frames differ among Member States, the practice for disconnecting and
reconnecting customers to electricity and gas provision is similar. The general practice in
most Member States consists of at least one (or more) written notices of unpaid bills,
followed by disconnection. Both the days between the unpaid bill and the final notice of
disconnection, and between the latter and the disconnection are usually legislated70
.
The number of days before disconnection varies among Member States (Figure 6). The
disconnection period is the highest in Belgium with a lengthy disconnection process71
,
followed by the UK. Both Belgium and the UK have the lowest share of customers
disconnected from electricity. The explanation for such low disconnection levels might be
in the fact that those two states have the highest requirements in terms of days before
disconnection is legally possible, but could also be linked to the fairly high share of prepaid
meters and strong use of complementary measures. Denmark does not have a specific
69
CEER National Indicators Database 2015
70
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
71
Upon defaulting on payments, a customer is given at least 30 day notice of cancellation of the contract,
followed by a 60 day grace period to find another supplier. If the customer defaults on payments with
the second supplier, this process is repeated. Thereafter, the supplier can apply to the local council for
permission to disconnect the customer, especially if they refuse the installation of a prepaid meter.
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number of days legislated, but rather specifies that at least two notifications must be sent
out72
.
Certain Member States (e.g., Sweden and Luxembourg) contact the social services in
between the final notice period and the disconnection of a consumer. Other Member States
have longer disconnection times where a smart meter is in place (e.g., in Italy before the
disconnection takes place, the maximum power supply is reduced to 15% for 15 days73
).
Figure 6: Working days before electricity disconnection, in ascending order for
notification period (2014)
Source: Insight_E (Forthcoming)
Reconnection happens in most Member States only upon receipt of payment of the entire
outstanding debt to the service provider or when an alternative repayment plan has been
negotiated. In some Member States, the customer is reconnected if the unpaid bill is
disputed. In those cases, the service provider cannot disconnect the customer again until
the dispute is settled.
72
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
73
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
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Deficiencies of the current legislation
This Section summarises Section 7.1.1 and Annex III of the Commission evaluation of the
provisions on consumer vulnerability and energy poverty in the 2009 Electricity and Gas
Directives. The full evaluation is included in a separate document.
The legislators' original objectives of these provisions were:
1. To ensure protection of vulnerable consumers by having Member States define the
concept of vulnerable consumers and implement measures to protect them.
2. To mitigate the problem of energy poverty by having Member States address
energy poverty, where identified, as an issue.
These provisions were put in place to facilitate the decision by Member States to proceed
with electricity and gas market liberalisation, as it was recognised by the legislators that
actions to protect vulnerable consumers were needed in the context of liberalising the
European energy market.
The evaluation assesses the legislation against five criteria. The Table below provides a
summary of this assessment.
Table 3: Evaluation of the provisions on consumer vulnerability and energy poverty
Criterion
Legislation
meets
criterion
Assessment
Achievements Shortcomings
Effectiveness Partially Member States define
vulnerable consumer and
adopt measures to protect
them.
Uneven protection of vulnerable
consumers.
Lack of data on the scale and drivers of
energy poverty
Growing energy poverty levels across
the EU
Lack of assistance by Member States
to address energy poverty.
NRA lack data to fulfil monitoring
role.
Some Member States still quote energy
poverty as a reason for maintaining
price regulation and not going ahead
with full energy market liberalisation
Efficiency Completely Low costs compared with
potential benefits.
Relevance Completely Consumer vulnerability will
remain relevant as some
drivers of vulnerability are
permanent.
Energy poverty likely to grow in the
future if no policy adopted.
Coherence Partially No inconsistencies with or
elements working against
objectives of the provisions.
Lack of an agreed description of the
term energy poverty and caveats in the
obligations stand in contrast to the call
for action in the Directive.
EU-added
value
Completely Member States have taken
action as a result of EU
intervention.
Source: Evaluation of the provisions on consumer vulnerability and energy poverty
The evaluation concluded that the provisions in the Electricity and Gas Directive related
to consumer vulnerability and energy poverty were mostly effective.
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EU action successfully encouraged Member States to define the concept of vulnerable
consumers in their legislation and to adopt measures to protect vulnerable consumers. The
provisions have also brought the issue of energy poverty to the attention of Member States.
However, the evaluation also identified certain shortcomings. With respect to energy
poverty, the evaluation shows that even though most Member States have correctly
implemented the provisions on consumer vulnerability, the incidence of energy poverty
has continued to rise across the EU. In addition, even though Member States have to
address energy poverty where identified, the Electricity and Gas Directives do not include
any reference to the meaning of energy poverty nor do they explain in which circumstances
energy poverty can be identified as an issue.
At the same time current legislation does not enable comparable data on energy poverty to
be sourced from Member States to deliver a full picture of energy poverty in the EU, in
terms of scale, drivers and potential future evolution. In addition, while the provisions on
vulnerable consumers and energy poverty were put in place to facilitate the decision by
Member States to proceed with electricity and gas market liberalisation, 17 Member States
still maintain electricity and/or gas price regulation, often quoting increase in energy
poverty as a risk associated with deregulating energy prices.
While research indicates that energy poverty and consumer vulnerability are two distinct
issues74
, the provisions in the Electricity and Gas Directives refer to energy poverty as a
type of consumer vulnerability. The evaluation argues that this may have led to an incorrect
expectation that a single set of policy tools could address both problems simultaneously.
The evaluation also identifies shortcomings in the effectiveness of the provisions referring
to the role of National Regulatory Authorities (NRAs) in monitoring electricity and gas
disconnections.
The evaluation found that the provisions were efficient and relevant. While efficiency was
difficult to quantify due to lack of data, it is likely that the benefits derived from defining
consumer vulnerability at the Member State level and implementing measures to protect
them outweighed the costs of setting up such policies. In terms of relevance, evidence
suggests that the problem of energy poverty is growing and it is likely to continue without
policy intervention. European Commission75
research suggests that consumer vulnerability
in the energy market will continue to be a relevant policy issue in the future as a substantial
share of those characterised as vulnerable consumers have permanent characteristics that
make them vulnerable.
Regarding coherence, there were no inconsistencies or elements in the legislation working
against the objectives of the provisions on vulnerable and energy poor consumers.
Nevertheless the misidentification of consumer vulnerability and energy poverty as the
same issue in the Electricity and Gas Directives means that the expected combined impacts
74
"Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies and
measures". (2015). Insight_E.
75
European Commission (2016). Available at:
http://ec.europa.eu/consumers/consumer_evidence/market_studies/vulnerability/index_en.htm-
summit/2015/files/ener_le_vulnerability_study_european_consumer_summit_2015_en.pdf.
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are not occurring and energy poverty grows while Member States take action to protect
vulnerable consumers.
In relation to EU-added value, while it is true that some Member States had been already
protecting their vulnerable energy consumers prior to EU intervention, others have been
obliged to take action as a result of EU intervention.
Overall, the evaluation concluded that the provisions have mostly met their objectives.
However, the legislation did not give sufficient attention to the issue of energy poverty. As
the Electricity and Gas Directives define energy poverty as a type of consumer
vulnerability, the effectiveness of the provisions was reduced. This categorisation leads to
a simplistic expectation that a single set of policy measures from Member States would
automatically address both problems simultaneously. However, evidence suggests that
energy poverty has been rising over the years, despite the protection available for
vulnerable consumers. In parallel, Member States have maintained regulated prices, which
had a negative effect on the internal energy market.
The Options presented in this impact assessment attempt to address this situation.
Presentation of the options.
This Section presents the policy options in detail. Each Option includes a table with the
description of the specific measures. An assessment of the costs and benefits for each of
the measures is presented in the following Section.
Business as Usual (BaU): sharing of good practices.
The BaU includes measures that are currently implemented or in the pipeline. These
measures will be undertaken without legislative change and aim at improving knowledge-
exchange.
Table 4: BaU
Measures Pros Cons
Energy
poverty
Promoting
good practices
Continuous
Knowledge
exchange.
Existing shortcomings of the legislation are not
addressed: lack of clarity of the concept of energy
poverty and the number of energy poor households
persist.
Energy poverty remains a vague concept leaving
space for Member States to continue inefficient
practices such as regulated prices.
Indirect measure that could be viewed as positive but
insufficient by key stakeholders.
The Commission has already secured funding to set up an Observatory of Energy Poverty.
However, the BaU scenario assumes the funding for the Observatory will not be extended
beyond 2019 and therefore no additional cost will be incurred in the appraised period.
The Commission will continue promoting the exchange of good practices which are likely
to contribute to enhance transparency and knowledge dissemination. However, this option
may be insufficient to address the partial effectiveness of the current provisions as
identified in the evaluation as the current legislation does not require Member States to
measure energy poverty and hence to address it.
Option 0+: sharing of good practices and monitoring the correct implementation of the
legislation.
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There is scope to address some of the problems identified in the evaluation without new
legislation. This option seeks non-legislative measures such as voluntary collaboration
across Member States as a tool to address these problems. With the help of the EU
Observatory of Energy poverty, this option includes voluntary collaboration across
Member States to agree on the scope of energy poverty as well as the way of measuring.
Measures to ensure the monitoring of disconnections across Member States are also
included.
The evaluation identified that National Regulatory Authorities (NRAs) have not reported
to ACER data on the number of disconnections. As described in the evaluation, ACER
reported that only 16 NRAs were able to report data on disconnections. This is despite the
legal obligation stated in the Electricity Directive Article 37 Duties and powers of the
regulatory authority under paragraphs (j)76
and (e)77
.
In addition, the Observatory delivers the exchange of good practices and better statistical
understanding of the drivers of energy poverty. Option 0+ assumes the Observatory
continues its operation at least until 2030 (the end of the assessment period for the Impact
Assessment).
Table 5: Option 0+
Measures Pros Cons
Energy
poverty
EU Observatory of Energy
Poverty.
NRAs to monitor and report
data on disconnections.
Voluntary collaboration across
Member States to agree on
scope and measurement of
energy poverty.
Stronger enforcement of
current legislation and
continuous knowledge
exchange.
Insufficient to address the
shortcomings of the current
legislation with regard to energy
poverty and targeted protection.
This option does not address all the shortcomings identified in the evaluation, such as the
need to measure energy poverty and the lack of adequate tools to protect vulnerable and
energy poor consumers. Furthermore, voluntary collaboration may not be a suitable
measure. The Commission already undertakes actions involving Member States, such as
the publication of guidelines and working paper in the context of the Vulnerable Consumer
Working Group, with have had a limited impact on Member States. Thus, legislative
action, beyond Option0+, is required.
Option 1: Setting an EU framework to monitor energy poverty.
76
Monitoring the level and effectiveness of market opening and competition at wholesale and retail levels,
including on electricity exchanges, prices for household customers including prepayment systems,
switching rates, disconnection rates, charges for and the execution of maintenance services, and
complaints by household customers, as well as any distortion or restriction of competition, including
providing any relevant information, and bringing any relevant cases to the relevant competition
authorities;
77
Reporting annually on its activity and the fulfilment of its duties to the relevant authorities of the Member
States, the Agency and the Commission. Such reports shall cover the steps taken and the results obtained
as regards each of the tasks listed in this Article;
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This option includes obligations on Member States that will need to be implemented
through new EU legislation. The measures included in this option are designed to address
the shortcomings identified in the evaluation:
- clarifying the concept of energy poverty,
- improving transparency with regard to the number of households in energy poverty.
Table 6: Option 1
Measures Pros Cons
Energy
poverty
- Generic, adaptable
description of the term
energy poverty in the
legislation.
- Member States to measure
energy poverty.
- Shared understanding of what energy
poverty entails while flexible enough
to cater for Member States'
differences.
- Transparency when measuring and
monitoring energy poverty.
- Synergies with the Observatory.
- New legislation will
be necessary.
- Administrative
impact on Member
States.
Option 1 includes a number of legislative changes that represent new obligations for
Member States. In what follows, we provide a detailed description of these new
obligations.
Energy poverty - a description of the term energy poverty
Option 1 adds a description of the term energy poverty in the EU legislation. The objective
of this measure is to clarify the term energy poverty.
A number of European institutions have called on the European Commission to propose
an EU-wide definition of energy poverty, calling for a common description of the term
energy poverty.
- EESC (2011; 1)78
: "… energy poverty should be tackled at all tiers of government,
and that the EU should adopt a common general definition of energy poverty, which
could then be adapted by Member States".
- Committee of the Regions (2014;15)79
"…recognition of the problem at the
political level on the one hand, and to ensure legal certainty for measures to
combat energy poverty on the other; such a definition should be flexible in view of
the diverse circumstances of the Member States and their regions…”.
- European Parliament (2016)80
" Calls on the Commission to develop with
stakeholders a common definition of energy poverty which should aim at assessing
at least the following elements: material scope, difficulty for a household to gain
access to essential energy, affordability and share of total household cost, impact
78
European Economic and Social Committee (EESC) (2011) Opinion of the European Economic and
Social Committee on ‘Energy poverty in the context of liberalisation and the economic crisis’
(exploratory opinion). Official Journal of the European Union, C 44/53.
79
Committee of the Regions (CoR) (2014) Opinion of the Committee of the Regions - Affordable Energy
for All. Official Journal of the European Union, C 174/15.
80
European Parliament. Committee on Employment and Social Affairs. Draft report on meeting the
antipoverty target in the light of increasing household costs. (2015/2223(INI)). Rapporteur: Tamás
Meszerics.
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on basic household needs such as heating, cooling, cooking, lighting and
transport".
- European Parliament (2016)81
"Calls for the development of a strong EU
framework to fight energy poverty, including a broad, common but non-
quantitative definition of energy poverty, focusing on the idea that access to
affordable energy is a basic social right"
Thomson et al82
summarise the arguments in favour and against of an EU-wide definition
of energy poverty.
Table 7: Arguments in favour and against an EU-wide definition of energy poverty
In favour Against
Policy synergy. Not all Member States are
addressing this problem and those that are, act on
their own, without seeking synergies with others,
which makes it harder to identify, assess and deal
with energy poverty at the European level.
Limited evidence. Need to compile comparable
household data on energy consumption and income
to produce reliable statistics.
Recognition. A common EU-level definition of
energy poverty may give the problem better
visibility at the Member State level.
Comparability. A shared pan-EU definition would
need to be relatively broad in order to accommodate
the diversity of contexts found at the Member State-
level, in terms of climate conditions, socioeconomic
factors, energy markets and more.
Clarification. Adopting even a general description
of fuel or energy poverty at the EU-level would
help to resolve the considerable terminological
confusion that presently exists, and may pave the
way for more detailed national definitions.
Path dependency. An incorrect definition may lead
Member States to a wrong path from which it may
be difficult to depart as a result of path dependency.
Source: Thomson et al (2016)
The Vulnerable Consumers Working Group (VCWG)83
looked into several definitions
used to describe energy poverty which have been put forward by Member States, European
institutions and research projects. Most of the definitions shared common themes:
- domestic energy services refer to services such as heating, lighting, cooking and
powering electrical appliances;
- the term affordable is used to refer to households receiving adequate energy
services without getting into debt; and
- the term adequate usually means the amount of energy needed to ensure basic
comfort and health.
VCWG concluded that a prescriptive definition of energy poverty for the EU28 would be
too restrictive, given the diverse realities across Member States. Yet, the group agreed that
a generic definition represents a positive step forwards to tackle the problem of energy
poverty. The VCWG argues that, if such as EU-wide definition were to be identified, it
should be simple, focus on the problem of affordability and allow sufficient flexibility to
be relevant across Member States84
. Such a definition can refer to elements such as
81
European Parliament. Committee on Industry, Research and Energy. Draft report on Delivering a New
Deal for Energy Consumers. (2015/2323(INI)). Rapporteur: Theresa Griffin.
82
Fuel poverty in the European Union: a concept in need of definition? 2016. Thomson et al.
83
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
84
A few Member States already have a definition of energy poverty. These definitions are presented in
Sub-Annex 1.
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households with a low-income; inability to afford; and adequate domestic energy services.
Within the generic definition Member States can adapt it to suit national circumstances
(e.g. by adopting their own numerical threshold for low income).
Energy poverty - Measuring energy poverty
Option 1 requires Member States to measure energy poverty. To measure energy poverty,
Member States will need to construct a metric which should make reference to household
income and household domestic energy expenditure.
Measuring energy poverty allows Member States to understand the depth of the problem
and assess the impact of the policies to tackle it85
.
Most researchers used Eurostat Survey on Income and Living Conditions (EU-SILC) to
produce proxy indicators of energy poverty at Member State level such as the perceived
inability to keep homes adequately warm86
. However, this indicator has some well-known
limitations87 88
:
- subjectivity due to self-reporting;
- limited understanding of the intensity of the issue due to the binary character of the
metric;
- assumption that participants in a survey view such judgments like 'adequacy of
warmth' in a similar way; and
- difficult to compare across Member States.
In Member States that have or are considering energy poverty metrics, most experiences
concern expenditure-based metrics rather than consensual-based metrics. The advantage
of an expenditure based metric is that it is quantifiable and objective. These indicators
measure energy poverty as a result of two of the main drivers of energy poverty: domestic
energy expenditure and household income. Nonetheless, these indicators also suffer from
some limitations89
:
- cannot assess whether consumers reduce expenditure because of budget constraints
or due to other factors. Thus, it does not take account of the issue of self-
disconnection i.e. households who do not consume adequate amount of energy to
avoid falling into arrears or debt;
- it does not reflect consumers’ motivation for expenditure levels; and
- sensitive to methodological decisions such as definition of income or the definition
of the threshold.
Member States will have the freedom to define the metric according to their circumstances.
A European Commission study reviewed 178 indicators of energy poverty and proposed a
final set of four indicators, three of them expenditure based metrics. The study confirmed
85
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
86
This kind of indicators is referred in the academic literature as consensual-based indicators.
87
Selecting Indicators to Measure Energy Poverty. 2016. Trinomics.
88
"Quantifying the prevalence of fuel poverty across the European Union". 2013. Thomson and Snell.
89
"Selecting Indicators to Measure Energy Poverty". 2016. Trinomics.
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that all the final recommended indicators can be produced using data already collected by
Member States90
.
These measures build upon the existing provisions on energy poverty in the Electricity and
Gas Directive. They offer the necessary clarity to the term energy poverty, as well as, the
transparency with regards to the number of household in energy poverty. Since currently
available data can be used to measure energy poverty, the administrative costs are limited.
Likewise, the actions proposed do not condition Member States primary competence on
social policy, hence, respecting the principle of subsidiary.
90
Trinomics 2016. Available at:
https://ec.europa.eu/energy/sites/ener/files/documents/Selecting%20Indicators%20to%20Measure%20
Energy%20Poverty.pdf
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Option 2: Setting a uniform EU framework to monitor energy poverty, preventative
measures to avoid disconnections and disconnection winter moratorium for vulnerable
consumers.
Table 8: Option 2
Measures Pros Cons
Energy poverty - Specific, harmonised
definition of energy poverty.
- Require Member States to
measure energy poverty using
required energy.
- Improve comparability
of energy poverty as a
result of a harmonised
concept of energy
poverty.
- Measuring energy
poverty using required
energy.
- New legislation will
be necessary.
- A prescriptive
definition of energy
poverty may not be
adequate for all
Member States.
- High administrative
cost to measure energy
poverty using required
energy.
Safeguards
against
disconnection
- A minimum notification period
before a disconnection.
All customers to receive
information on the sources of
support and be offered the
possibility to delay payments or
restructure their debts, prior to
disconnection.
- Winter moratorium of
disconnections for vulnerable
consumers.
- Equips Member States
with the tools to prevent
and reduce the number
of disconnections.
- - Gives customers more
time to make
arrangements to pay
their bills, i.e. avoids
unnecessary
disconnections and costs
of disconnecting and
reconnecting.
- - Customers are given
information. about
outreach points.
- Customers are given an
opportunity to better
handle their energy debts
- The most vulnerable
customers will benefit
from a guaranteed
energy supply through
the coldest months of the
year.
- New legislation will
be necessary.
- Administrative impact
on Member States.
- Administrative impact
on energy companies
- Safeguards against
disconnection may
result in higher costs for
companies which may
be passed to consumers.
- Safeguards against
disconnection may also
result in market
distortions as suppliers
seek to avoid entering
markets where there are
likely to be significant
risks of disconnections
and the suppliers active
in such markets raise
margins for all
consumers in order to
recoup losses from
unpaid bills.
- Moratorium of
disconnection may
conflict with freedom of
contract.
Option 2 represents additional obligations for Member States. In what follows, we describe
these new obligations.
Energy poverty - EU definition of energy poverty
Option 2 adds a specific definition of energy poverty in the EU legislation. Energy poverty
will refer to those households which after meeting their required energy needs fall below
the poverty line or other income related threshold. This measure will clarify the term
energy poverty (as in Option 1) and improve the comparability and monitoring of energy
poverty within the EU.
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A definition using a relative income threshold, such as the Low Income High Cost91
, is
suited to measure energy poverty in the EU. Since the poverty threshold is a relative metric
(e.g. below 40% of the median income) this type of metric takes account of the distribution
of income in each Member State. However, it might well be that in some Member States a
significant number of households live below the poverty line. In those cases, a different
metric of energy poverty using a lower income threshold may be more suitable.
Some stakeholders will be in favour of such as measure since it addresses the need for a
common definition. However, as it was described in Option 1, the EESC (2011: 1) and
Committee or the Regions (2014;15) request the Commission a 'common general
definition' ; 'flexible in view of the diverse circumstances of the Member States and
regions'. The VCWG92
also stated that 'a prescriptive definition of energy poverty for the
EU28 would be too restrictive, given the diverse realities across Member States'.
Similar arguments were put forward in Thomson et al93
with regard to comparability. The
authors argue that a shared pan-EU definition would need to be relatively broad in order
to accommodate the diversity of contexts found at the Member State level in terms of
climate conditions, socioeconomic factors or energy markets. This is in contradiction with
a more prescriptive definition of energy poverty at the EU level.
Energy poverty - measuring energy poverty
Option 2 requires Member States to measure energy poverty using 'required energy'.
Metrics using 'required' rather than 'actual' expenditure calculate the amount of energy
necessary to meet certain standards such as a specific indoor temperature during a number
of hours per day.
The main advantage of this type of measurement94
is that it refers to an adequate level of
energy service. As such, it computes the amount of energy for a specific heating regime
rather than measuring actual expenditure, which may not be adequate for low-income
households that may under-consume due to budget constraints.
In order to be able to compute required energy, the following information is needed95
:
- heating system and fuels used;
- dwelling characteristics;
- regional and daily climate variations; and
- number of days per year a household stays in their home.
91 "
Low income High Costs (LIHC) indicator" (Hills, 2011): A household i) income is below the poverty
line (taking into account energy costs); and ii) their energy costs are higher than is typical for their
household type.
92
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
93
"Fuel poverty in the European Union: a concept in need of definition?" 2016. Thomson et al.
94
The UK, which has considerable experience in this field, measures energy poverty or fuel poverty using
required energy.
95
Selecting Indicators to Measure Energy Poverty. 2016. Trinomics.
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This data, especially the variables related to dwelling characteristics, are rarely available.
To collect it, Member States are likely to need to run a Housing Condition Survey96
which
ideally should be linked to the Household Budget Survey.
Safeguards against disconnection - minimum notification period of 40 working days
Evidence suggests that stronger guidelines dictating adequate disconnection times and
procedures could be an effective way to prevent disconnections. For instance, in Belgium
and UK, the two countries with the highest disconnection time requirements, disconnection
levels are at the lowest97
.
This measure requires Member States to give all customers at least two months
(approximately 40 working days) notice before a disconnection from the first unpaid bill.
In Member States, legislated working days before disconnecting a customer vary between
a week and 200 days, with an average of approximately 40 days (See Table below).
Table 9: Statistics on disconnection notices (legal requirements) in Member States
MIN MAX Average Standard
deviation
Working days to final disconnection notice98
3 45 18.15 12.87
Working days to actually disconnect a final household
customer from the grid because of non-payment
7 200 36.81 36.79
Source: Insight_E (Forthcoming); Data: Eurostat; CEER National Indicators Database 2015
Longer disconnection period may stop some disconnections as customers have more time
to engage or to seek help. The direct monetary benefit comes in the form of avoided
disconnection and reconnection costs to society. Other non-direct monetary benefits to the
utility are those of retaining the customer, and avoiding lost income, due to allowing the
consumer time to pay back arrears.
It is possible to calculate the amount of time before which it is not cost effective to
disconnect a household from electricity and gas provision. This is done by comparing the
cost of disconnection and reconnection with the average monthly household expenditure
for gas and electricity.
Figure 7 shows the number of days it is cost-effective not to disconnect a household for
those Member States with available data to perform the necessary calculations.
96
The Housing Condition Survey measures the physical characteristics of the dwelling such as height of
the ceilings, materials of the wall, or the size of the windows to calculate the energy performance of the
building.
97
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
98
Denmark does not stipulate a number of days but rather that a minimum of two notices be sent
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Figure 7: Number of days from which it is cost-effective to disconnect a household
Source: Insight_E (Forthcoming)
Interestingly for both electricity and gas it is not cost effective to disconnect within a
certain time starting from the unpaid bill for any of the considered countries. For electricity,
in Germany and Italy, it is cost-effective to disconnect only after approximately 2 months
from the unpaid bill, while in Ireland and the UK at least one month is needed to justify
disconnection. That value is approximately 15 working days for France and Spain, having
less costly connection and reconnection procedures. For gas, as the cost of connection and
reconnection is higher, those values are larger. In Germany and Spain three or more months
of unpaid bills would justify a disconnection, for Italy and France more than one month99
.
It is to be noted that these numbers merely compare the cost of connecting and
disconnecting a household with household energy bills. Including other social and health
benefits would increase the amount of days before a disconnection is cost effective. Those
costs are difficult to quantify. Nonetheless, a number of articles and research projects
99
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E
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provide evidence of a link between warmer homes and improvements in health100101102103
104 105
. More information on the benefits of a longer notification period is provided in the
next Section.
Setting a minimum notification period of 40 working days will lead to 18 Member States
having to increase their disconnection notice requirements (See Table below). Five of those
would have to increase the notice by 10 working days or less. Hungary, Latvia, Spain,
Finland, Romania, Greece, Croatia, the Netherlands, UK and Belgium would not be
impacted by this regulation. In addition, Member States with robust social security
schemes disconnection safeguards would not have any substantial impact as early
intervention typically assists vulnerable consumers and the energy poor with avoiding
disconnections, nota bene via direct financial support.
The extension of the disconnection notice period is associated with additional costs for the
suppliers in the form of bills which can be left unpaid by some of the customers. The
measure also has potential market distortion effects as suppliers seek to avoid entering
markets where there are likely to be significant risks of disconnections and the suppliers
active in such markets raise margins for all consumers in order to recoup losses from
unpaid bills.
100
Chilled to Death: The human cost of cold homes. (2015). Association for the Conservation of Energy,
Available at: http://www.ukace.org/wp-content/uploads/2015/03/ACE-and-EBR-fact-file-2015-03-
Chilled-to-death.pdf
101
"Fuel Poor & Health. Evidence work and evidence gaps". DECC. Presented at Health, cold homes and
fuel poverty Seminar at the University of Ulster. (2015). Cole, E. Available at:
http://nhfshare.heartforum.org.uk/HealthyPlaces/ESRCFuelPoverty/Cole.pdf
102
Towards an identification of European indoor environments’ impact on health and performance - homes
and schools. (2014). Grün & Urlaub.
103
Excess winter mortality: a cross-country analysis identifying key risk factors. Journal of Epidemiology &
Community Health 2003. Healy.
104
Estimating the health impacts of Northern Ireland’s Warm Homes Scheme 2000-2008. (2008). Liddell.
105
The Health Impacts of Cold Homes and Fuel Poverty (London: Friends of the Earth). (2011). Marmot
Review Team.
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Table 10: Additional working days with a two month disconnection notice106
Member State Additional number of days
Cyprus 33
Czech Republic 33
Bulgaria 30
Ireland 30
Malta 26
Estonia 25
Lithuania 25
Portugal 25
Slovakia 25
Austria 20
Slovenia 20
Sweden 15
Germany 10
Italy 10
Luxembourg 10
Poland 10
France 5
Source Insight_E (Forthcoming); Data: Eurostat; CEER National Indicators Database 2015
Safeguards against disconnection – prior to disconnection notice, consumers should
receive: (i) information on the sources of support and (ii) be offered the possibility to delay
payments or restructure their debt.
Customer engagement
Customer engagement typically involves communication between the energy supplier and
the customer, where either the customer contacts the energy supplier for assistance or the
energy supplier is required to engage with the customer before commencing the actual
disconnection. This communication can take the form of a letter, registered letter, e-mail,
phone call, text message or house call. The use of these measures varies across Member
States and while a comprehensive review of how this is undertaken is not available, it is
clear that some variation of consumer engagement occurs nonetheless.
Debt management
Debt management can include non-financial arrangements such as counselling or
assistance with budgeting as well as financial arrangements including a negotiated
payment plan, delayed payment responsibility or a financial grant to assist with costs.
Safeguards against disconnection - winter moratorium of disconnections for vulnerable
consumers.
This measure stops disconnection from energy provision (electricity and gas), for
vulnerable consumers, during the winter months. Already, 10 Member States provide
seasonal disconnection prohibitions at particular times.
Of those Member States, eight define clearly the winter period during which
disconnections are banned (See Figure 8).
106
Denmark does not stipulate a number of days but rather that a minimum of two notices be sent
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Figure 8: Winter period with ban on disconnection in Member States
Sep Oct Nov Dec Jan Feb Mar Apr May
BELGIUM
ESTONIA
FINLAND
FRANCE
HUNGARY
IRELAND
NETHERLANDS
UK
Source: Insight_E (Forthcoming)
On the other hand, other countries define the winter as ‘cold season’ or depending on
temperatures (e.g. Lithuania prohibit disconnections when the highest daily air temperature
is lower than minus 15 °C or higher than plus 30 °C).
This measure, unlike the others, will specifically target vulnerable consumers. Hence, the
coverage of the measure depends on the definition of consumer vulnerability in energy
markets in each of the Member States.
With regard to the disconnection safeguards discussed in this Section, it needs to be noted
that Member States may be better suited to design these schemes to ensure that synergies
between national social services and disconnection safeguards can be achieved. These
synergies may also result in public sector savings which may be significant given the
substantial costs of some of these measures, see Table 22 and Table 23.
Comparison of the options
This Section quantifies the costs and benefits for the BaU and each of the policy options.
The tables below summarise the main results of the Cost Benefit Analysis (CBA). The
methodology, assumptions and calculations are subsequently explained.
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Table 11: BaU: costs and benefits
Costs Benefits
Description Quantification Description Quantification
Promoting good
practices.
Exchange of good
practices and
collaboration
across Member
States
EUR 0. Continuous
Knowledge
exchange.
N.A. only
qualitative.
Table 12: Option 0+: costs and benefits
Costs Benefits
Description Quantification Description Quantification
EU Observatory of
Energy Poverty.
Running the EU
Observatory of
energy poverty.
EUR100,000 per
year .
Knowledge
exchange.
N.A. only
qualitative.
NRAs to monitor
and report figures
on disconnections.
Better
implementation of
current legislation
Electricity
Directive Article
37 (j) and (e).
No additional cost. Improved
information on
number of
disconnections.
N.A. only
qualitative.
Table 13: Policy Option 1: costs and benefits
Costs Benefits
Description Quantification Description Quantification
Energy poverty
Generic
adaptable
description of
the term energy
poverty in the
legislation.
Enumerate the
main
characteristics
that define
energy poverty.
No additional
cost.
Transparency,
clarification and policy
synergies.
N.A. only
qualitative.
Member States
to measure
energy poverty.
Produce a metric
to measure
energy poverty.
Administrative
cost.
Understanding the extent
of the problem. Improved
transparency.
N.A. only
qualitative.
Note: Policy Option 1 includes the measures described in option 0+.
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Table 14: Policy Option 2: costs and benefits
Costs Benefits
Description Quantification Description Quantification
Energy poverty
Specific
definition of
energy poverty
Produce a
specific
harmonised
definition of
energy poverty.
No additional
cost.
Transparency,
clarification and policy
synergies.
N.A. only
qualitative.
Member States to
measure energy
poverty using
required energy
Collecting
detailed
housing stock
data.
Administrative
cost.
Understanding the extent
of the problem. Improved
transparency.
N.A. only
qualitative.
Disconnection safeguards
A minimum
notification
period before a
disconnection.
All customers
will receive a
disconnection
notice at a
minimum of at
least two
months (or 40
working days)
before
disconnection
from the first
bill unpaid.
Cost of unpaid
bills.
General benefits from
avoiding disconnection in
the form of improvements
in households' health and
well-being; cross-
departmental savings; and
avoiding cost of
disconnection and
reconnection. Gives
customers more time to
make arrangements to pay
their bills.
N.A. only
qualitative.
All customers to
receive
information on
the sources of
support and be
offered the
possibility to
delay payments
or restructure
their debts, prior
to disconnection.
Prior to issuing
a disconnection
notice, all
consumers
should: receive:
(i) information
on the sources
of support, and;
(ii) be offered
the possibility
to delay
payments or
restructure their
debt.
Consumer
information cost
varies depending
on the type of
intervention
which may
include
registered letters;
phone calls; text
message; or
emails.
Debt
management
cost depends on
the type of
intervention.
General benefits from
avoiding disconnection.
Gives customers more
time to make
arrangements to pay their
bills, i.e. avoids
unnecessary
disconnections and costs
of disconnecting and
reconnecting.
Customers are given
information about
outreach points.
Customers are given an
opportunity to better
handle their energy debts
N.A. only
qualitative.
Winter
moratorium of
disconnections
for vulnerable
consumers.
In case of non-
payment
vulnerable
consumers will
not be
disconnected
from the
electricity and
gas grid during
Winter.
The cost of
unpaid bills.
General benefits from
avoiding disconnection.
The most vulnerable
customers will benefit
from a guaranteed energy
supply through the coldest
months of the year.
N.A. only
qualitative.
Note: Policy Option 2 includes the measures described in option 0+.
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Methodology
The methodology follows the Better Regulation Guidelines. In this Section, we present the
steps taken for the calculation of the costs and benefits.
Introduction - Costs and Benefits Analysis (CBA)
This impact assessment takes account of societal costs and benefits when assessing the
impact of the policies. In addition, the net impact on total welfare and the net impacts on
specific groups (i.e. winners and losers) are relevant as these provisions are likely to benefit
more those in lower income or vulnerable economic conditions.
The cost of the measures occurs immediately following the adoption of the policies into
national legislation and are borne by public authorities (i.e. measuring energy poverty) and
energy providers (e.g. disconnection safeguards). Benefits, on the other hand, tend to
emerge over a longer time frame and are more difficult to quantify.
As far it has been possible, costs and benefits are based on market prices. However, this
has not always been possible, particularly when quantifying the benefits.
In the case of disconnection safeguards, the costs of this measure represent the mirror
image of the benefits for those households who are not disconnected as a result of the
safeguards. Even though this is a symmetrical change in private welfare and therefore it
cancels out at the aggregate level, there is an impact in terms of transfer of welfare between
those who are not in risk of disconnection (wealthier households) and those in risk of
disconnection (poorest households). It can be argued that this transfer has a positive impact
on efficiency if we assume poorest household have a higher marginal utility for each
additional euro received than wealthier households. This approach has been followed in
some Impact Assessments107
using empirical evidence from the academic literature108
. Due
to lack of data, however, these effects have not been quantified.
The discount rate used equals 4%. The time period starts when the measures are
implemented at Member State level and ends in 2030. We assume measures are
implemented in 2020109
. In reality, the starting period may be subject to change depending
on which year the measures are approved in each Member State. This will advance or delay
the costs and benefits impacting the overall net benefit of the policies.
As stated in the Better Regulation guidelines, CBA has important limitations. The main
limitations refer to:
- the assumption that income can be a proxy for happiness or satisfaction,
- the fact that it willingly ignores distributional effects; and
107
UK Treasury 'Green Book Appraisal and Evaluation in Central Government (2003). Annex 5
Distributional Impacts. Available at:
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/220541/green_book_co
mplete.pdf
108
Cowell and Gardiner (1999); Pearce and Ulph (1995)
109
We assume the legislation proposed in the Winter Package will be approved by the co-legislator in 2017
and Member States will require three years for implementing the new measures.
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- its lack of objectivity when it comes to the selection of certain parameters (e.g. the
inter-temporal discount rate), which can tilt the balance in favour of certain
regulatory options over others.
The overall goal of the intervention is to achieve the benefits at the overall lowest cost.
The policy options will contribute to advancement in social welfare in terms of economic
efficiency, consumer protection and life satisfaction.
Quantifying the costs
Producing a description of energy poverty (policy Option 1); and a specific definition of
energy poverty (policy Option 2) will be undertaken by the European Commission at no
additional cost.
Business as Usual – calculating the costs
Exchange of good practices
The European Commission continues fostering the exchange of good practices across
Member States through its network of stakeholders such as the Vulnerable Consumers
Workings Group. No additional cost is estimated.
Option 0+ – calculating the costs
The cost of the EU Observatory of Energy Poverty
The European Commission has published a contract service to build and maintain the EU
Observatory of Energy Poverty. The current budget equals EUR 800,000 for a 40 month
contract. The continuation of the work after the contract is estimated at EUR 100,000 per
year110
.
The cost of NRAs monitoring and reporting figures on disconnections
The current energy legislation requires national regulators to monitor disconnections.
However, not all Member States report figures on disconnections111
. Full implementation
of the current legislation represents no extra cost as there is no additional obligation.
Policy Option 1 – calculating the costs
The cost of Member States to measuring energy poverty making reference to household
income and household energy expenditure
Measuring energy poverty will result on a new information obligation for Member States.
This is a direct cost related to compliance i.e. the need to divert resources to address the
110
"Selecting Indicators to Measure Energy Poverty". (2016). Trinomics.
111
ACER Market Monitoring Report (2014)
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direct consequences of the policy options which creates an administrative cost112
to comply
with the new information obligation.
The administrative costs consist of two different cost components: the business-as-usual
costs and administrative impacts. The administrative impacts stem from the part of the
process which is done solely because of a new legal obligation.
To compute these costs we follow the Better Regulation Guidelines which state that the
effort of assessment should remain proportionate to the scale of the administrative costs
imposed by the legislation and must be determined according to the principle of
proportionate analysis.
To calculate the administrative cost we use the Standard Cost Model. The main objective
of the model is to assess the cost of information obligations imposed by EU legislation.
The following Table presents the steps that will need to be followed to measure energy
poverty.
112
Administrative costs are defined as the costs incurred by enterprises, the voluntary sector, public
authorities and citizens in meeting legal obligations to provide information on their action or production,
either to public authorities or to private parties.
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Table 15: Steps to measuring energy poverty
Activity
Identification of
information
obligations
Measuring energy poverty making reference to household income and household
energy expenditure.
Data requirements: household income and household energy expenditure. Source:
Household Budget Survey and/or Survey of Income and Living Conditions.
Identification of
required actions
Familiarising with the information obligation: senior managers will need to assess
the information needed and allocate tasks within the Civil Service to measure energy
poverty.
Training employees about the information obligation: civil servants will need
training on the necessary data to measure energy poverty. The amount of training
necessary is likely to be limited since the information needed (i.e. household income
and household energy expenditure) is already collected by Member States.
Retrieving relevant information from existing data: civil servants will need to retrieve
household income and household energy expenditure data either from the Household
Budget Survey and/or Survey on Income and Living Condition.
Producing new data: civil servants will need to use household income and household
energy expenditure to produce an indicator of energy poverty. For those Member
States with no official metric to measure energy poverty, it is likely that the Civil
Service will produce different metrics and recommend one for adoption. The work
required to produce the most common indicators of energy poverty is not particularly
burdensome113
.
Holding meetings: senior civil servants will hold several meetings to decide which
metric should be used to measure energy poverty. Ultimately a decision will need to
be made at the Government level before the metric is reported to the European
Commission.
Inspecting and checking: civil servants will need to perform quality control activities
on the data to ensure the robustness of the results.
Submitting the information: civil servants will need to submit the information to the
European Commission. It is likely that in some cases civil servants may need to
allocate additional time for discussion with European Commission officials for
clarification.
Identification of
target group
Public Authorities
Identification of
frequency of
required actions
Once a year
Identification of
relevant cost
parameters
No particular relevant cost such as external costs (e.g. using consultancies or
gathering new data) has been identified.
Assessment of the
number of entities
concerned
28 Member States
The administrative impact will decrease after the first year since Member States will be
familiar with the new obligation and have agreed on the internal procedures to measure
113
"Selecting Indicators to Measure Energy Poverty". (2016). Trinomics.
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energy poverty. Hence, we have computed the administrative impact for year 1 and the
administrative impact for the subsequent years separately.
An estimation of the time and frequency of the tasks was gathered from information
provided by Member States.
France, the UK and Ireland already measure energy poverty. Hence, this obligation will
not constitute an additional cost for these Member States.
To quantify the administrative impact we used the Standard Cost Model. The model does
not include information for Croatia. The cost of measuring energy poverty in Croatia was
calculated using information on labour cost from Slovenia. Even though this is not ideal,
we prefer this approach to avoid any under-estimation of the cost of the obligation. At the
EU level, the relative small size of Croatia means that the EU wide cost will not be
significantly affected by this assumption. The final cost is shown in the Table below.
Table 16: Cost of measuring energy poverty making reference to household income
and household energy expenditure (EUR)
First year Following years
Standard Cost Model EUR 454,129 EUR 255,277
Estimated cost in France, UK,
Ireland
(-EUR57,137) (-EUR32,444)
Estimated cost in Croatia EUR 10383 EUR 5788
Final cost EUR 407,375 EUR 228,621
Source: European Commission's calculation
For completeness, we include the results of the Standard Cost Model in the tables below.
These results include the cost of measuring energy poverty in all Member States but
Croatia.
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Table 17: Administrative costs of measuring energy poverty in year 1
Obligation Action Target
Group
Staff type Hourly
rate
Man
hours
Activity cost
(EUR)
Measuring energy
poverty
Familiarizing with the information obligation 28 MS Legislators, senior officials and
managers
41.5 65 75,530
Training employees about the information
obligations
28 MS Professionals 32.1 33 29,660
Retrieving relevant information from existing data 28 MS Professionals 32.1 50 44,491
Adjusting existing data 28 MS Professionals 32.1 25 22,470
Producing new data 28 MS Professionals 32.1 143 128,079
Holding meetings 28 MS Legislators, senior officials and
managers
41.5 52 60,424
Inspecting and checking 28 MS Professionals 32.1 31 27,638
Copying 28 MS Professionals 32.1 50 44,940
Submitting the information 28 MS Professionals 32.1 23 20,897
Total 454,129
Source: European Commission's calculation
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Table 18: Administrative costs of measuring energy poverty in following years
Obligation Action Target
Group
Staff type Hourly
rate
Man
hours
Activity cost
(EUR)
Measuring energy
poverty
Familiarizing with the information obligation 28 MS Legislators, senior officials and
managers
41.5 27 31,374
Training employees about the information
obligations
28 MS Professionals 32.1 29 26,065
Retrieving relevant information from existing data 28 MS Professionals 32.1 33 29,660
Adjusting existing data 28 MS Professionals 32.1 12.5 11,235
Producing new data 28 MS Professionals 32.1 45 40,446
Holding meetings 28 MS Legislators, senior officials and
managers
41.5 26 30,212
Inspecting and checking 28 MS Professionals 32.1 33 29,660
Copying 28 MS Professionals 32.1 45 40,446
Submitting the information 28 MS Professionals 32.1 18 16,178
Total 255,277
Source: European Commission's calculation
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Option 2 – calculating the costs
The cost of Member States measuring energy poverty using required energy
The UK measures energy poverty using required energy rather than actual expenditure.
Social and physical surveys are carried out in each constituent country to gather all the
necessary information to estimate and monitor energy poverty.
The European Commission requested the assistance of the Scottish Government to gather
the necessary information to understand the activities and estimate the costs of measuring
energy poverty using required energy. The estimated cost for using this approach at the EU
level is based on the cost of an analogous exercise to measure energy poverty in Scotland.
The main tool to gather all the data to estimate the level of energy poverty in Scotland is
the Scottish House Condition Survey114
(SHCS). The objective of the survey is much
broader than measuring energy poverty. The survey includes a range of additional topics,
as well as information on several characteristics of the household. Each year a Technical
Report115
is published to summarise the survey methodology and delivery of the survey
work.
The SHCS includes a sample of more than 3,000 paired households and dwellings. The
Table below breaks down the different components of the SHCS. Member States already
undertake social surveys116
, making the physical survey the main additional cost of this
measure.
Table 19: SHCS – cost structure
SHCS – Activities Description of activities SHCS – Share
of total cost
Survey management Project management, recruitment, briefing and training, etc. 15%
Fieldwork costs
- Social
surveys
- Physical
survey
45 minutes social interview and 60 minutes physical survey,
and work to secure interviews. 24%
33%
Processes and final
output
Data processing, sampling, selection, questionnaire
development, validation, clean datasets, and survey reports.
24%
Estimating energy
poverty
Energy poverty modelling using information collected in the
surveys
4%
Source: European Commission's calculation
The methodology to calculate cost of gathering data to measure energy poverty using
required energy at EU level is as follows:
1. Calculate the cost per interview.
114
The Scottish House Condition Survey run as a standalone survey every 5 years, in 1991, 1996, and 2002.
In 2004 it became an annual survey, running separately until 2011. From 2012, the SHCS was merged
with the Scottish Household Survey.
115
"Scottish Household Survey Technical Report". Available at:
http://www.gov.scot/Topics/Statistics/SHCS/2009techrep
116
For instance, physical surveys can be run as a sub-sample of larger surveys such as the Household
Budget Survey which will significantly reduce the costs.
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2. Adjust cost per interview by Member States labour costs.
3. Multiply cost per interview in each Member States by the number of effective
interviews necessary to get a representative sample in each Member States.
Based on the information provided by the Scottish Government, we estimate the cost of
the SHCS per interview to be around EUR 268. This cost includes the activities described
in the Table above: survey management; fieldwork cost (physical survey); processes and
final output; and estimating energy poverty.
A significant component of that cost relates to labour costs. Thus, we adjust the cost per
interview by the different labour costs across the EU using information on wages provided
in the Standard Cost Model. As previously mentioned, the model does not contain labour
costs for Croatia. As before, we approximate Croatian labour costs using the labour cost
in Slovenia.
The total number of households that would need to be interviewed depends on several
statistical considerations. We use the effective sample size of the Household Budget
Surveys117
provided by Eurostat.
117
Eurostat Household Budget Surveys 2010 Achieve Sample Sizes. Quality Report. Source:
http://ec.europa.eu/eurostat/documents/54431/1966394/LC142-
15EN_HBS_2010_Quality_Report_ver2+July+2015.pdf/fc3c8aca-c456-49ed-85e4-757d4342015f
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Table 20: Cost per dwelling adjusted by Member States labour costs
Member State Adjustment factor
(MS' labour cost /
UK labour cost –
category:
professional)
Cost per
interview (EUR)
Sample size
required
Total cost (EUR)
BE 1.3 346 3,459 1,195,000
BG 0.1 27 1,343 36,000
CZ 0.3 82 3,182 262,000
DK 1.2 320 1,697 544,000
DE 1.1 298 37,606 11,209,000
ET 0.2 62 1,619 100,000
IE 1.1 291 2,562 746,000
EL 0.7 184 1,512 278,000
ES 0.7 193 8,743 1,688,000
FR 1.0 274 5,114 1,404,000
IT 1.0 272 8,884 2,420,000
CY 0.8 219 1,910 419,000
LV 0.2 44 1,653 73,000
LT 0.2 44 1,242 55,000
LU 1.3 356 3,068 1,092,000
HU 0.2 60 4,175 250,000
MT 0.4 116 3,157 366,000
NL 0.9 249 1,461 364,000
AT 1.0 269 2,962 796,000
PL 0.3 91 4,022 367,000
PO 0.6 156 30,228 4,708,000
RO 0.2 45 6,328 288,000
SL 0.5 138 2,658 366,000
SK 0.3 69 2,076 143,000
FI 0.9 253 2,532 640,000
SE 1.0 258 2,157 556,000
HR 0.5 138 2,464 340,000
Total Cost 30,704,000
Source: European Commission's calculation
As the housing stock changes slowly, a physical survey of the housing stock does not need
to be carried out annually. The survey can be run every two years and produce accurate
results118
. Hence, we estimate that the total annual cost of measuring energy poverty using
required energy to be approximately EUR 15.35 million.
The annual cost may increase for those Member States that have to start procurement
processes to gather this data. It is likely, however, that the cost of measuring energy poverty
using required energy is over-estimated. This is because the SHCS gathers more
information than what is explicitly required to measure energy poverty.
The cost of disconnection safeguards – 40 working days minimum notification period
The cost of a minimum notification period can be assessed as the amount of the unpaid
energy bills during the period in which disconnection is not possible. This could be either
a cost, in case the consumer never pays back the bills, or a delayed income, in case the
118
Based on interview with Scottish Survey manager.
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measure is successfully implemented and the non-paying consumer only delays in paying
the bill.
The direct monetary benefit comes in the form of avoided disconnection and reconnection
costs to society. To calculate the average amount of time spent on disconnection and
reconnection, the cost of disconnection and reconnection was divided by the hourly wage
of a technical staff using data from the Standard Cost Model. The average time was equal
to 2.4 hours. To calculate the potential savings to society, we assume that the notification
reduces the number of disconnections by 10%. We consider 10% to be a conservative
assumption. The examples of UK and Belgium show that long pre-disconnection periods
contribute, among other factors, to low disconnection numbers. In addition, in many cases
disconnections are solved within few days. Notifications are sent to all consumers, many
of them, are not necessarily vulnerable or in low-income but have simply forgotten to pay
their energy bills.
After the notification, households will be disconnected and acquire a debt with their energy
supplier. In many cases, those households will be reconnected again and the debt will be
repaid either by the households or the Government. In other cases, a household can be
declared in bankruptcy and never repay the debt. For those cases, the unpaid bill during
the notification period will be a cost for the supplier. To calculate this cost, we assume119
a high cost scenario where 30% of households will never repay their debts and a central
cost scenario for which 10% households will never repay their debt.
There are no statistics available with the number of households permanently without
electricity or gas as a result of non-payment. Anecdotal evidence, gathered through
discussions with national regulators, indicate that this number may be small. Given that
the majority of European households connected to the electricity or gas grid do receive
energy services, it is possible that before or after a household is being disconnected, some
kind of process starts by which the affected household or the public sector repay the debt
or it is condoned by the supplier.
This is highly likely in Member States with strong social security systems such those who
may have to extend their notification like Austria, Germany, Denmark, France, or Sweden
and Member States such as Ireland and Poland where pre-payment meters are offered to
households as a last resort measures to provide energy and slowly repay the debt. For these
Member States, extending the notification period may not result in any added cost.
However, to avoid any under-estimation of the cost we have added all the Member States
with notification periods lower than 40 days.
The steps taken to calculate the total net costs are the following:
- Calculate the cost of connection and disconnection in each Member State impacted
by this measure.
- Estimate the savings of a longer notification period which equals to the avoided
cost of connection and reconnection.
- Calculate the average household energy expenditure for 40 working days in each
Member State impacted by this measure.
119
The assumed number of households unable to repay the debt was checked against regulators'
experiences.
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- Estimate the cost of the measure assuming that 10% (central cost scenario) and
30% (high cost scenario) of households will never repay their debt.
- Calculate the net cost of the policy.
The net cost of unpaid bills for these two scenarios for those Member States with a
notification period lower than 40 working days is presented in Table 21.
Table 21: Estimated cost of extending notification period
Member State Central Cost (10%) in EUR High Cost (30%) in EUR
AT 148,160 1,027,465
BG* 184,081 624,502
CY 236,164 942,264
CZ* 405,482 1,587,838
DE 627,268 9,340,006
DK 219,079 1,216,659
EE* -5,018 96,725
FR 1,617,788 6,439,202
IE 35,596 222,339
IT -570,068 18,342,145
LT 6,046 24,428
LU* 3,194 24,311
MT 11,103 47,098
PL 945,689 4,131,371
PT 2,328,274 9,210,831
SE* 156,570 778,667
SI* 204,133 708,164
SK 109,395 484,050
Total Annual Cost 6,662,934 55,248,063
Note: * indicates Member States without available data on disconnections. For these Member States
disconnections was proxy by the average number of disconnections.
Source: European Commission's calculation
Estonia and Italy enjoy a net benefit from extending the notification period i.e. expressed
as a negative cost. In these Member States, the savings from avoiding the cost of
connection and reconnection during the notification period is higher than the total debt in
the central cost scenario where 10% of households do not repay their debt.
The results in Table 21 are nonetheless sensitive to the assumptions used with regard to
the number of disconnections avoided and the number of households who will never repay
their debt. For instance, if we assume that just 5% of households do not repay their debt,
extending the notification period results in an EU net benefit of more than EUR 5 million.
It is also important to note that publically available data on disconnection rates across all
Member States is incomplete, despite Member States’ obligation to report such data to
National Regulatory Authorities. For the purpose of the present analysis, the average
number of disconnection was applied to proxy for potential disconnection in those Member
States without available data. This assumption may not be adequate for Member States
such as Luxembourg or Sweden which may have a significantly lower number of
disconnections than the average.
Overall, it is likely that the conservative assumption used in the calculation of the costs led
to conservative estimates of the cost which may over-estimate the impact of the measures.
In addition to the above it is important to note that Member States with robust social
security schemes are unlikely to face any additional costs as a result of the extension of the
disconnection notice period as rapid intervention of social security services typically helps
households in those Member States to avoid disconnections.
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The cost of disconnection safeguards - prior to disconnection notice, consumers should
receive: (i) information on the sources of support and (ii) be offered the possibility to delay
payments or restructure their debt.
To calculate the cost of these measures, we collected information on the cost of similar
schemes currently operating in Member States and estimate the cost of replicating these
schemes in the Member States where debt management or customer engagement activities
do not exist.
The steps taken to calculate the total costs are the following:
- Gather information on case studies and calculate the cost per household for debt
management and customer engagement.
- Calculate the cost per household in each Member States taking account of different
labour costs using information from the Standard Cost Model.
- Multiply the cost per household by the number of households in arrears (high cost
scenario) and the number of disconnections (central cost scenario)
Similarly to the cost of extending notification period, it is likely that in some Member
States, particularly those with strong social security system, households may never need
debt management advice or information on the sources of support.
It might well be that even though Member States such as Denmark, Finland, or the
Netherlands do not have official debt management advice or customer engagement
activities120
, households in these Member States do receive support prior to disconnection
or when facing difficulties to pay their energy bills. That will make these measures
superfluous. In those cases, Member States will not face any additional cost. However, to
avoid any under-estimation of the costs, the impact assessment includes all the Member
States without these services121
.
Using the number of households in arrears as a proxy for the number of disconnections
may also over-estimate the costs. First of all, not all households in arrears may be in a
position to require support. Arrears may well be for other reasons than financial constraints
or difficulties to make ends meet. Secondly, in some Member States, households in arrears
may receive support from local authorities or social services which will erase the need for
these measures and thus the cost.
As a result of these assumptions, we believe the costs presented here are conservative.
The cost of debt management
Step Change is a UK based charity which helps people overcome their debt difficulties122
.
In 2014, the charity served more than 300,000 people at an operating cost of around GBP
120
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E
121
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E
122
Step Change: http://www.stepchange.org/
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140 per beneficiary which equates to around EUR 172123
. A similar scheme operates in
Germany at the local level124
. The cost of the Germany scheme was on average EUR 167
per households. The estimations are based on the cost from the UK based programme since
it is run nationally. Nonetheless, the UK and German program have similar cost per
households.
Assuming the same efficiency in other Member States but different labour costs, the cost
of replicating Step Change activities in other Member States is shown in Table 22. The
same Table also shows the cost of extending the services to all households in arrears with
utility bills (as potential households in need of assistance with managing utility bills – high
cost scenario) and the cost of providing the service to those households who are actually
disconnected125
– central cost scenario.
When estimating the costs of debt management it is important to note that debt
management assistance have positive long-term impacts on households. This means that a
substantial share of households benefiting from debt management assistance can be
expected to manage their payments more effectively after the initial intervention. Thus, the
annual cost of this intervention can be expected to decrease annually reflecting the success
rate of the measure.
For instance, from the more of 1,200 households receiving support in Germany, 90% of
the beneficiaries felt their future energy needs would be secured and therefore were not in
need to reapply to receive assistance. In addition 80% of the disconnection threats were
averted which generates savings in the form of avoided disconnection and reconnection
costs.
The 90% success rate in the German example may not be easy to replicate in other Member
States. As a conservative assumption we assume a success rate of 25%. Hence, the annual
cost of the measure will decrease by 25% year-on-year.
It is also important to note that this type of services, despite being of a considerable cost
per customer provide an added-value to the energy suppliers. For example, Step Change is
partly funded by the energy suppliers as they enjoy the benefits of having an intermediary
that provides support to customer on arrears or in risk of disconnection for non-payment.
The cost of customer engagement
Irish suppliers have established an Energy Engage Code which provides guidelines on the
approach suppliers should take with customers in arrears and those with possible
disconnection. According to the Code, suppliers should communicate with customers
having difficulties in paying their bills and advise them on possible debt management
plans. The cost of this option involves communication costs including letter, phone calls
123
2014 average exchange rate of GBP 0.806 for one euro.
124
Information on the scheme can be found at:
https://www.verbraucherzentrale.nrw/mediabig/238730A.pd and
https://www.verbraucherzentrale.nrw/mediabig/237456A.pdf
125
Information on the total number of disconnections was not available for all Member States. For those
Member States for which this information was not available, we applied the average disconnection rate.
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and SMS messages. Information on the estimated cost of customer engagement provided
by one of the main Irish suppliers is presented below:
- Written communication: EUR 1.5
- Phone calls: EUR 5
- Mobile Text: 8 euro cents
It is likely that this measure may have positive long-term impacts reducing the number of
beneficiaries and the cost of the scheme. However, we did not find any evidence of the
possible success rate. To avoid any under-estimation of the cost we assume the number of
beneficiaries remains constant over time.
This amounts to an estimated cost of customer engagement of around EUR 6.6 per
customer. The same approach as per debt management was used to calculate the cost of
extending similar schemes to other Member States. We first adjust the cost of customer
engagement per customer for each Member State using Eurostat Purchasing Power Parity
Index. The cost per customer was multiplied by the total number of households in arrears
– high cost scenario and total number of disconnections – central cost scenario.
Table 22: Cost of debt management and customer engagement
Member State
Estimated cost of debt
management (EUR) Member State
Estimated cost of customer
engagement (EUR)
Central Cost High cost Central Cost High Cost
BG 114,408 6,770,270 BG 21,056 1,245,997
DK 7,665,949 73,559,897 CY 121,107 97,921
EE 65,607 3,882,393 CZ 9,217 545,417
FI 708,564 41,930,412 EE 7,045 416,885
HR 1,016,791 22,934,923 FI 25,786 1,525,929
LT 95,899 5,634,449 GR 900,327 4,138,621
LV 22,088 1,266,903 HR 52,140 1,176,085
PT 33,574,204 91,806,810 HU 410,753 1,139,442
RO 293,008 17,339,207 LT 11,309 664,469
SK 121,024 7,161,768 LV 3,129 179,479
MT 12,187 100,663
NL 9,876,748
SI 116,888 164,857
Total Annual Cost 43,677,542 272,287,031 Total Annual Cost 1,690,944 21,272,514
Note: the number of reported disconnections in the Netherlands was nil. CEER database
Source: European Commission's calculation
The cost of disconnection safeguards - winter moratorium of disconnections for vulnerable
consumers.
A winter disconnection moratorium for vulnerable consumers may result in a cost for the
energy supplier, consumers or the government, depending on how the measure is financed.
The cost of this measure can be estimated as the cost of the unpaid energy bill from non-
paying vulnerable consumers during winter. However, the debt per each non-paying
household might be recovered at a certain point, therefore not resulting in a cost.
The cost per non-paying household of a possible winter disconnection is reported in Table
23. This was calculated assuming that a household does not pay the energy costs for the
full winter, assumed to be four months long which is equal to the average legislated winter
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length in countries that have disconnection safeguards for the winter. This was calculated
using the average energy expenditures for the lowest income quintile.
We also assume that a percentage of vulnerable consumers will not repay their energy bill
due to the moratorium. A high and a central cost scenario are presented in the table below.
The scenarios assume that 30% (high cost) and 10% (central cost) of the vulnerable
households will not repay their energy bills during winter. It can be argued, as it was done
previously for the other disconnection safeguards, that these assumptions are likely to over-
estimate the cost.
It might be that some Member States such as Austria, Germany or Luxembourg have
sufficient tools in place to protect vulnerable households from being disconnected making
a moratorium unnecessary. For those Member States, the costs of the moratorium will not
be realised. However, as in the other Sections of the impact assessment, we have included
all Member States without a winter moratorium for vulnerable consumers.
As previously discussed, anecdotal evidence suggests that the number of households
permanently cut-off from electricity and gas services because of non-payment may be
significantly lower.
The number of vulnerable consumers was not available for some of the impacted Member
States. In these cases, referred in the table below with an asterisk, the number of vulnerable
consumers the number of households unable to keep their homes adequately warm was
used as a proxy. This is likely to over-estimate the number of vulnerable households,
particularly in those Member States with an explicit definition of consumer vulnerability
in energy markets. Further information on the definition of consumer vulnerability in
energy markets can be found in the evaluation.
It needs to be added that the inability of a vulnerable household to pay its energy bill may
also be linked to the type of tariff. It might well be that vulnerable households are not in
the most advantageous tariff. In those cases, switching to a more competitive offer reduces
energy costs and may avoid disconnection. These interactions were not taken into account
in this impact assessment. However, it can be assumed that the preventative measures
undertaken prior to disconnection such as customer engagement and debt management
may assist vulnerable consumers to reduce their energy cost by switching to a more
economic tariff.
Finally, there might be scope for reducing the costs of winter moratorium of disconnections
if it is designed taking into account Member States national social services. However, as
social policy is a primary competence of Member States, an EU winter moratorium on
disconnections may go beyond the limits of subsidiarity (see Section 7.1.6 Subsidiarity).
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Table 23: Cost of winter moratorium for vulnerable consumers
Mem
ber
state
Vulnerabl
e
consumers
Electricity Gas
Central cost case
(10% disconnect
and never pays
back) in EUR
High cost case
(30% disconnect
and never pays
back) in EUR
Central cost case
(10% disconnect
and never pays
back) in EUR
High cost case
(30% disconnect
and never pays
back) in EUR
AT* 118,357 2,092,547 6,277,640 733,812 2,201,435
BG* 1,048,035 9,643,610 28,930,829 229,965 689,895
CZ* 267,191 4,559,591 13,678,772 2,807,494 8,422,483
DE* 1,978,803 33,507,728 100,523,184 15,962,343 47,887,029
LU* 1,374 26,642 79,926 20,210 60,630
LV* 215,001 1,743,136 5,229,408 607,682 1,823,046
MT 24,416 242,927 728,782 36,852 110,557
PT 61,129 941,387 2,824,160 707,059 2,121,176
SK* 117,990 1,172,983 3,518,950 1,333,957 4,001,872
Total Annual Cost 53,930,551 161,791,651 22,439,374 67,318,123
Note: Vulnerable consumers for AT, BG, CZ, DE, LU, LV and SK set as the number of households feeling
unable to keep warm during winter. It was not possible to calculate the cost for Croatia due to lack of data
on household energy expenditure
Source: European Commission's calculation
Summary Table
The annual cost and the total net present cost for the period 2020 and 2030 of the policy
options presented in the impact assessment are summarised in the Table below.
Table 24: Total Cost
Annual cost in EUR Net present cost for the period
2020 – 2030 in EUR
BAU: sharing of good practices. 0 0
Option 0+: sharing of good
practices and increasing the
efforts to correctly implement the
legislation.
100,000 911,090
Policy Option 1: Setting an EU framework to monitor energy poverty
Central cost scenario 407,375 (first year)
228,621 (following years)
2,261,696
Policy Option 2: Setting a uniform EU framework to monitor energy poverty, preventative
measures to avoid disconnections and disconnection winter moratorium for vulnerable
consumers.
Central cost scenario 159,105,345 1,194,481,728
High cost scenario 587,348,869 3,820,183,393
Source: European Commission's calculation
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Quantifying the Benefits
In this Section we describe the benefits derived from implementing the policies.
Overall benefits
Tackling energy poverty can have positive effects on individual's health and well-being,
savings for the health sector, as well as provide economy-wide gains on productivity levels.
Although it is difficult to quantify the specific impact of the policies presented in this
impact assessment towards these overall benefits, it is likely that applying these policies
will contribute to reap these benefits.
For instance, it is likely that on individual's health, there have been various studies linking
cold homes with respiratory illnesses and excessive winter mortality. The World Health
Organisation estimated that 30% of Excess Winter Deaths (EWD) can be directly related
to cold homes126
. The 2009 Annual Report of the Chief Medical Officers127
estimated that
for every £1 spent on ensuring homes are kept warm, the public health sector saves £0.42.
A recent study concluded that home environment is key to ensure citizens are healthy and
productive128
. Remaining connected to an energy supply better enables households to
maintain healthy homes in terms of indoor temperature and humidity levels. Lack of energy
supply has been linked to an increase of respiratory illnesses, circulatory diseases, mental
health and allergies, which, left unchecked, lead to absence from work and loss of
productivity estimated to total 9.8 billion EURO annually in Europe129130131
. Policies
proposes in the revision of the EED and the EPBD which contribute to better energy
efficiency in the domestic sector will also contribute to realise benefits of better health and
productivity.
The UK Healthy Homes Barometer 2016 estimates that minor illnesses, such as coughs,
colds, flus and illnesses can be attributed to 27 million lost working days, which affect
morale and productivity. The direct cost to the economy in the UK due to these absences
is estimated at £1.8 billion in 2013.
Ensuring energy provision can also have a positive impact on educational attainment,
lower missed school days and life chances for children132
.
Identifying energy poverty will also assist Member States in assessing the level of energy
poverty. Such identification will support Member States to better target public policies to
those households in need of assistance. In addition, disconnection safeguards will further
help Member States to reduce the number of disconnections, benefiting in particular low-
126
"Indoor cold and mortality. In Environmental Burden of Disease Associated with Inadequate Housing",
(Bonn: World Health Organisation (Regional office for Europe)). (2011). Rudge, J.
127
2009 Annual Report of the Chief Medical Officer (London: Department of Health). 2010. Donaldson,
L.
128
"Healthy Homes Barometer". (2016). Wegener and Fedkenheuer,
129
"Towards an identification of European indoor environments’ impact on health and performance -
homes and schools". (2014). Grün & Urlaub,
130
"The Health Impacts of Cold Homes and Fuel Poverty" (London: Friends of the Earth). (2011). Marmot
Review Team.
131
"Estimating the health impacts of Northern Ireland’s Warm Homes Scheme" 2000-2008. (2008). Liddell.
132
Evaluating the co-benefits of low-income energy-efficiency programmes. 2013. Heffner & Campbell.
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income households who are more likely to face energy poverty. With such measures in
place, Member States may feel more confident to phase out regulated prices.
The removal of regulated prices which will bring efficiency improvements, resulting on:
- more competition in the energy markets with positive impacts on consumer and
innovation;
- the removal of market distortions which alter the allocation of resources.
- additional citizen's satisfaction due to the positive impacts of competition on
innovation in the form of enhanced service provision and quality;
- a positive impact on the internal energy market. Companies wishing to engage in
cross-border trade will not be discouraged by regulated prices, which prevent
competition when set below cost,; and
- improved public finances since regulated prices are an ineffective measure of
protection as they are applied to all households, including those who can afford to
pay a higher price. Phasing out regulated prices will unlock resources which can be
used for targeted protection.
Better information on the level of energy poverty and measures to reduce the number of
disconnections will have a positive impact on consumer protection and the health and well-
being of European citizens. Art. 38 of the Charter of Fundamental Rights of the EU
requires EU policies to ensure a high level of consumer protection. The Treaty establishes
that 'consumer protection requirements shall be taken into account in defining and
implementing other Union policies and activities' (TFEU, art. 12), and that '… the Union
shall contribute to protecting the health, safety and economic interests of consumers, as
well as to promoting their right to information, education and to organise themselves in
order to safeguard their interests.' (TFEU, Art. 169)
Policy Option 1 – assessing the benefits
The benefits of a generic description of the term energy poverty in the legislation
Three main benefits have been identified as a result of a shared understanding of energy
poverty across the EU: recognition, clarification and policy synergy133
.
In terms of recognition, an EU description of energy poverty may help Member States to
identify the problem. This is relevant as the majority of Member States have not defined
the phenomenon of energy poverty despite the evidence which suggest that household
across Europe are struggling to access adequate energy services134
,
As for clarification, a major regulatory impediment to addressing energy poverty is the
unclear understanding of the term. This is particularly relevant as in many cases the term
energy poverty is mixed or used interchangeably with the broader term of consumer
vulnerability or general poverty135
. Adopting a generic description of energy poverty
would help to resolve the terminological confusion that presently exists, and may pave the
way for more detailed national definitions. Above all a generic common understanding of
energy poverty in the EU, which focuses on the drivers of energy poverty, is a necessary
133
"Fuel poverty in the European Union: a concept in need of definition?" 2016. Thomson et al.
134
"Quantifying the prevalence of fuel poverty across the European Union". (2013). Thomson and Snell.
135
"Working Paper on Energy Poverty".(2016). Vulnerable Consumer Working Group.
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prerequisite towards achieving reliable and comparable data on the current and future
evolution of the nature and scale of the issue.
In terms of policy synergy, there is potential for achieving synergies at the EU and Member
State level. Having a shared concept could also assist Member State cooperation and
knowledge exchange in this area.
The benefits of measuring energy poverty by referring to household income and household
energy expenditure
Measuring energy poverty will assist Member States to assess whether energy poverty is
getting better or worse over time. It will also help Member States to identify the people
affected so that they can be targeted by appropriate interventions. Hence, measuring energy
poverty will help policy makers to assess the impact of their policies136
.
In summary, measuring energy poverty will enable Member States to:
- measure the level of energy poverty at a particular moment of time
- identify trends and changes on the levels of energy poverty,
- understand the extent, depth and persistence of the problem,
- identify the kinds of people affected; and
- support policy design and delivery to tackle the problem
These offer the necessary clarity to the term energy poverty, as well as, the transparency
with regards to the number of household in energy poverty while respecting the principles
of subsidiarity.
Option 2– assessing the benefits
The benefits of a specific EU definition of energy poverty
A specific, harmonised EU definition of energy poverty such as the one explained
previously will bring benefits similar to those associated with a general definition of energy
poverty. In addition, being a more specific definition, we expect the benefits in relation to
clarification to be higher.
However, here it is important to remember the risks that a specific definition of energy
poverty at the EU level may bring in terms of currently limited comparable evidence,
comparability and relevance, and path dependency137
.
As discussed before, a specific EU definition of energy poverty may be in conflict with the
diversity of contexts at the Member States in terms of climate conditions, socioeconomic
factors or energy markets. If the definition were to be inadequate for a Member State, it
would take considerable amount of time to change the EU legislation and amend this
situation.
136
Fuel Poverty: The problem and its measurement. (2001). John Hills. Available at:
http://sticerd.lse.ac.uk/dps/case/cr/CASEreport69.pdf
137
"Fuel poverty in the European Union: a concept in need of definition? " (2016). Thomson et al.
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The benefits of Member to measure energy poverty using required energy
Measuring an adequate level of energy services is the main advantage of using required
rather than actual expenditure. This is the approach taken in the UK and it is regarded as
most appropriate by several experts138
. It requires, nonetheless, agreeing on what is
adequate. In some cases, the term adequate refers to a specific heating regime139
.
Having defined what is adequate, the required energy approach calculates the amount of
energy needed to meet that heating regime. Energy poverty is later computed comparing
the required energy expenditure against household income. Hence, required energy
expenditure solves the main weakness of the actual expenditure approach. When using
actual expenditure, we are not able to distinguish between those households that do not
consume sufficient energy because of financial constraints from those that do not need
much energy to meet their energy needs because they live in a high energy efficient
dwelling.
The benefits of disconnection safeguards - minimum notification period
Longer disconnection periods will provide customers with additional time to engage with
suppliers and/or seek help. There is a direct monetary benefit in the form of avoided
disconnections and reconnection costs. In addition to these benefits, any avoided
disconnection stemming from this measure will bring benefits such as health
improvements and cross-department savings in social and health budgets, and
improvements in equality.
Suppliers will also benefit from lower disconnection rates as they will retain such
customers, thereby avoiding lost income, allowing the customer to pay back arrears, and
avoiding some of the costs related to new customer acquisition.
The benefits of disconnection safeguards - prior to disconnection notice, consumers should
receive: (i) information on the sources of support and (ii) be offered the possibility to delay
payments or restructure their debt.
Providing additional information to consumers and the possibility to delay payments or
restructure their debt may result in a number of disconnections being averted. Hence, the
benefits are similar as in the case of extended notification period In addition, households
will be better informed, and can improve their energy management and potentially avoid
future debt. As described in the case of minimum notification period, suppliers will also
benefit from lower disconnections. Investment in consumer engagement and debt
management services will support a number of jobs in services such as debt counselling.
The benefits of winter moratorium of disconnections for vulnerable consumers.
138
"Selecting Indicators to Measure Energy Poverty". (2016). Trinomics.
139
For instance in the case of Scotland, the current definition of fuel poverty makes reference to a heating
regime for standard occupants between 21°C and 18°C for 9 hours during weekdays and 16 hours else
and for any occupant aged 60 or more or long-term sick and disabled between 23°C and 18°C 16 hours
per day. Source: http://www.gov.scot/resource/0039/00398798.pdf
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Similar to the other measures which reduce disconnections, a winter moratorium will bring
benefits in the form of health benefits to vulnerable consumers, cross-departmental savings
in social and health budgets, and avoided disconnection and reconnection costs.
Sensitivity analysis
This impact assessment suffers from important shortcomings to quantify the benefits. The
policy options bring multiple benefits in terms of better public policy with regard to energy
poverty, improvements in individuals' well-being and public sector saving from fewer
disconnections. However, we were not able to quantify the value of these benefits from
market prices.
Sensitivity analysis allows us to calculate the amount of benefits that would be necessary
to justify the costs from these policies.
One of the key benefits of the options presented stem from improvements in individual
health which can be particularly effective at addressing Excess Winter Deaths (EWD).
EWD refers to deaths which would not have occurred if dwellings had been properly
heated. The cost to society of EWD can be estimated as forgone GDP i.e. each excess
winter death translates in forgone monetary value approximated by GDP per capita. This
is a rather crude measure with some disadvantages (e.g. different values for different
countries) but it can be interpreted as an estimation of the loss to society.
To perform the sensitivity analysis, the following steps are taken:
- Aggregate the cost of policy Option 1 and 2 for the high and central cost scenario.
- Multiply the number of EWD140
by the GDP per capital141
- Calculate the reduction in EWD that equals the cost of the policies.
The results of the calculation are presented below.
Table 25: Sensitivity analysis
Benefits from reduction in Excess
Winter Deaths equal to the cost of the
policies
Policy Option 1: Setting an EU framework to monitor energy
poverty
Policy Option 1 – first year 0.004%
Policy Option 1 – following years 0.002%
Policy Option 2: Setting an EU uniform framework to monitor
energy poverty and reduce disconnections for vulnerable
consumers.
Policy Option 2 – central cost scenario 1.5%
Policy Option 2 – high cost scenario 5.6%
Source: European Commission's calculation. Note: Policy Option 1 and 2 include the measures described
in option 0+.
140
The number of EWD is calculated following an approach similar to Johnson and Griffinths (2003). The
number of deaths is equal to the deaths between the months of December and March minus the average
number of deaths for other months. Data source: Eurostat. Mortality Statistics.
141
Eurostat. GDP per capital in euros at current prices.
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The Table shows that a minimal reduction in EWD is sufficient to justify the cost arising
from policy Option 1. On the other hand, a reduction of 1.5% and 5.6% is necessary for
the cost of policy Option 2 to be equal to possible benefits. The differences between the
low and high cost scenario are explained by the assumptions used to calculate the cost,
and in particular, to the number of households that after being disconnected or because of
the moratorium will never repay their debt.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the preceding
pages, accrue overwhelmingly to energy poor households. Depending on how individual Member States
choose to finance their new obligations to measure energy poverty levels (costs outlined in detail in Tables
15 to 17), the marginally increased burdens resulting from the implementation of these measures are
socialized amongst other ratepayers or taxpayers. The measures can therefore be considered progressive in
nature i.e. they tend to redistribute surplus from relatively high-income ratepayers/taxpayers to increase the
welfare of lower-income ratepayers
Subsidiarity
In this Section we assess the options presented in the impact assessment against the
subsidiarity principle as stated in Article 5 of the Treaty of the EU.
The subsidiarity principle is upheld because the objectives of the policy options, which
have been defined to address the shortcoming of the current legislation as identified in the
evaluation, cannot be achieved sufficiently by Member States.
The evaluation of the current provision of the Electricity and Gas Directive defined energy
poverty as a subset of consumer vulnerability. This categorisation leads to a simplistic
expectation that a single set of policy measures from Member States would automatically
address both problems simultaneously. However, evidence suggests that energy poverty
has been rising over the years, despite the protection available for vulnerable consumers.
In this context, Member States have been reluctant to phase out regulated prices, pointing
towards the protection of vulnerable and energy poor households as one of the main
reasons. As a consequence, national regulation has had negative spill-over effects,
weakening the internal energy market.
The measures proposed in Option 1 build upon the existing provisions on energy poverty
in the Electricity and Gas Directive. They offer the necessary clarity to the term energy
poverty, as well as, the transparency with regards to the number of household in energy
poverty. Since currently available data can be used to measure energy poverty, the
administrative costs are limited. Likewise, the actions proposed do not condition Member
States primary competence on social policy, hence, respecting the principle of subsidiary.
In addition, the protection of vulnerable and energy poor consumers has been quoted as
one of the reasons for maintaining regulated prices. This type of intervention, particularly
when prices are regulated below costs, has negative implications on the functioning of the
internal energy market. Article 114 and 194 pf the Treaty pf the Functioning of the
European Union states that in order to achieve the objectives in Article 26, the EU
legislators shall adopt the measures for the approximation of the provisions laid down by
law, regulation or administrative action in Member States which have as their object the
establishment and functioning of the internal market. Article 194 states that the Union
policy shall aim to ensure the functioning of the energy market.
It can be argued that Article 169 on Consumer Protection provides further justification for
action at the EU level. The options described in this IA include disconnection safeguards
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either as preventative measures prior to disconnection or as a prohibition of disconnection
for vulnerable consumers.
The options presented in this Annex bring a double dividend: on the one hand they
contribute to the protection of consumers – as explained in the introduction there is a link
between energy poverty and excess winter deaths – and on the other hand, these measures
support the completion of the internal energy market.
It needs to be noted that, as we explained in Option 2, Member States may be better suited
to design schemes to protect households from disconnection in order to ensure that
synergies between national social services and disconnection safeguards are achieved.
In addition, a prohibition on disconnections for vulnerable consumers may restrict the
principle of freedom of contract, in particular for the ten Member States that do not have
such a measure in place. However, action at EU level may be the most effective way to
ensure a common level of protection for vulnerable consumers. Furthermore, in terms of
proportionality, Member States should carefully specify the group of vulnerable consumers
who cannot be disconnected to avoid going beyond what is necessary to achieve the
consumer protection objective.
Stakeholders' Opinions
The options described in this impact assessment have benefited from the continued
dialogue between the European Commission services and civil society through the
Vulnerable Consumer Working Group (VCWG).
The VCWG was reconvened after the 2015 Citizens' Energy Forum. The group has met
five times since then:
- 3 June 2015
- 21 October 2015
- 9 December 2015
- 26 January 2016
- 24 May 2016
The VCWG meetings are attended by key stakeholders from industry, consumer
associations, academics, regulators and representatives of Member States. A full list of the
members of the group who have attended at least one of the last five meetings is provided
below:
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Table 26: Members of the Vulnerable Consumer Working Group
Organisation Member State
Ministry of Economics Latvia
Ministry of Economy Poland
Ministry of Employment and the Economy, Energy
Department
Finland
Ministry of National Development Hungary
Bulgarian Permanent Representation to the EU Bulgaria
Hungarian Permanent Representation to the EU Hungary
Czech Permanent Representation to the EU Czech Republic
FPS Economy - DG Energy Belgium
ERO - Energy Regulatory Office of the Czech
Republic
Czech Republic
E-control Austrian Energy Regulator Austria
OFGEM United Kingdom
NEON European Organisation
Citizens advice United Kingdom
Danish Consumer Council Denmark
DECO Portugal
The Swedish Consumer Energy Markets Bureau Sweden
RWADE Belgium
University of Leicester United Kingdom
University of Stuttgart Germany
European Disability Forum European Organisation
Fondazione Consumo Sostenibile Italy
GEODE European Organisation
HISPACOOP Spain
Housing Europe Belgium
International Union of Tenants European Organisation
EURELECTRIC European Organisation
EUROGAS European Organisation
ADEME France
AEEGSI Italy
AISFOR Italy
CEDEC European Organisation
DGEC France
EAPN European organisation
EFIEES European Organisation
ENGIE France
FdSS France
In the meetings of the VCWG142
, the group discussed the topic of energy poverty. These
discussions were captured in the Working Paper on Energy Poverty143
. The group
conclusions were as follows (emphasis added):
- Measuring energy poverty is important to understand the depth of the problem and
also assess the impact of the policies which have been put in place to tackle it.
Metrics which account for the relationship between household income and
household energy needs or expenditure capture well the problem of affordability.
142
The minutes, agenda and presentations of the meetings can be found online at:
https://ec.europa.eu/energy/en/events/citizens-energy-forum-london
143
VCWG (2016) Working Paper on Energy Poverty. Available at:
https://ec.europa.eu/energy/sites/ener/files/documents/Working%20Paper%20on%20Energy%20Pover
ty.pdf
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- Better information on housing stock, which can be efficiently gathered as part of
the regular Household Budget Survey, will help Member States to measure energy
poverty and design energy efficiency policies which benefit the energy poor.
- Tackling energy poverty requires a combination of policies, dealing with the causes
and the symptoms of energy poverty. Good examples include targeted short-term
(financial support) and long-term measures (energy efficiency) in addition to
consumer protection and reasonable safeguards against disconnections.
- A common understanding of the concept of energy poverty will help Member
States, civil society and industry to start a dialogue about the depth of energy
poverty and how to tackle it. The VCWG considers that a common understanding
of energy poverty in the form of a generic definition represents a positive step
forwards to tackle the problem of energy poverty. Such a definition should be
simple, focus on the problem of affordability, and allow sufficient flexibility to be
relevant across Member States. The VCWG proposes that such a definition can
refer to elements such as low-income; inability to afford; and adequate domestic
energy services
The options described in this impact assessment draws from the conclusions of this
paper. In particular, key elements of Option 1 are supported by the VCWG Working
Paper on Energy Poverty.
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Sub-Annex 1
Table 27: Energy poverty definitions
Member
State
Definition
France
Energy Poverty: A person who encounters in his/her accommodation particular difficulties
to have enough energy supply to satisfy his/her elementary needs, this being due to the
inadequacy of resources or housing conditions.
Ireland
Energy poverty is a situation whereby a household is unable to attain an acceptable level of
energy services (including heating, lighting, etc.) in the home due to an inability to meet
these requirements at an affordable cost.
Cyprus
Energy poverty may relate to the situation of customers who may be in a difficult position
because of their low income as indicated by their tax statements in conjunction with their
professional status, marital status and specific health conditions and therefore, are unable
to respond to the costs for the reasonable needs of the supply of electricity, as these costs
represent a significant proportion of their disposable income.
Slovakia
Energy poverty under the law No. 250/2012 Coll. Of Laws is a status when average monthly
expenditures of household on consumption of electricity, gas, heating and hot water
production represent a substantial share of average monthly income of the household”
England
Energy poverty: A household i) income is below the poverty line (taking into account
energy costs); and ii) their energy costs are higher than is typical for their household type.
Scotland
Fuel poverty: A household, in order to maintain a satisfactory heating regime, it would be
required to spend more than 10% of its income (including Housing Benefit or Income
Support for Mortgage Interest) on all household fuel use.
Wales
Fuel poverty is defined as having to spend more than 10% of income (including housing
benefit) on all household fuel use to maintain a satisfactory heating regime. Where
expenditure on all household fuel exceeds 20% of income, households are defined as being
in severe fuel poverty.
Northern
Ireland
A household is in fuel poverty if, in order to maintain an acceptable level of temperature
throughout the home, the occupants would have to spend more than 10% of their income
on all household fuel use.
Source: Insight_E 2015
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7.2. Phasing out regulated prices
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Summary table
Objective: Removing market distortions by achieving the phase-out of supply price regulation for all customers144
.
Option: 0 Option 1 Option 2a Option 2b
Making use of existing acquis to continue
bilateral consultations and enforcement
actions to restrict price regulation to
proportionate situations justified by general
economic interest, accompanied by EU
guidance on the interpretation of the current
acquis.
Requiring Member States to progressively
phase out price regulation for households by a
deadline specified in new EU legislation,
starting with prices below costs, while allowing
transitional, targeted price regulation for
vulnerable customers (e. g. in the form of social
tariffs).
Requiring Member States to
progressively phase out price
regulation, starting with prices below
costs, for households above a certain
consumption threshold to be defined in
new EU legislation or by Member
States.
Requiring Member States to progressively phase
out below cost price regulation for households by
a deadline specified in new EU legislation.
Pros:
- Allows a case-by-case assessment of the
proportionality of price regulation, taking into
account social and economic particularities in
Member States
Pros:
- Removes the distortive effect of price
regulation after the target date.
- Ensures regulatory predictability and
transparency for supply activities across the
EU.
Pros:
- Limits the distortive effect of price
regulation.
- Would reduce the scope of price
regulation therefore limiting its
distortive impact on the market.
Pros:
- Limits the distortive effect of price regulation
and tackles tariff deficits where existent.
Cons:
- Leads to different national regimes
following case-by-case assessments. This
would maintain a fragmented regulatory
framework across the EU which translates
into administrative costs for entering new
markets.
Cons:
- Difficult to take into account social and
economic particularities in Member States in
setting up a common deadline for price
deregulation.
Cons:
- Difficult to take into account social
and economic particularities in
Member States in defining a common
consumption threshold above which
prices should be deregulated..
Cons:
- Defining cost coverage at EU level is
economically and legally challenging.
- Implementation implies considerable regulatory
and administrative impact.
- Price regulation even if above cost risks holding
back investments in product innovation and
service quality.
Most suitable option(s): Option 1 - Setting an end date for all price intervention would ensure the complete removal of market distortions related to end-user price regulation and help create
a level playing field for supply activities across the EU while allowing targeted protection for vulnerable customers and/or energy poor.
144
For the purpose of this annex of the impact assessment, households or household customers shall include customers in a comparable situation (e. g. SMEs, hospitals etc.)
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Description of the baseline
A regulated supply price is considered as a price subject to regulation or control by public
authorities (e.g. governments, NRAs), as opposed to being determined exclusively by
supply and demand. This definition includes many different forms of price regulation, such
as setting or approving prices, standardisation of prices or combinations thereof.
The existing acquis only allows price regulation if strict conditions are met.
Regulated prices are unlawful under current Gas and Electricity Directives as interpreted
by the Court of Justice, unless they meet specific conditions. Accordingly, the Court of
Justice has ruled145
that supply prices must be determined solely by supply and demand as
opposed to State intervention as from 1 July 2007. The Court based its interpretation on
the provision146
stating that Member States must ensure that all customers are free to buy
electricity/natural gas from the supplier of their choice as from 1 July 2007 (Article 33 of
the Electricity Directive and Article 37 of the Gas Directive interpreted in light of the very
purpose and the general scheme of the directive, which is designed progressively to achieve
a total liberalisation of the market in the context of which, in particular, all suppliers may
freely deliver their products to all consumers).
Article 3(1) of Gas and Electricity Directives requires Member States to ensure, on the
basis of their institutional organisation and with due regard to the principle of subsidiarity,
that natural electricity/gas undertakings are operated in accordance with the principles of
that directive with a view to achieving, inter alia, a competitive market.
However, Gas and Electricity Directives are also designed to ensure that, in the context of
that liberalisation, high standards of public service are maintained and the final consumer
is protected.
In order to meet those latter objectives, Article 3(1) of Gas and Electricity Directives states
that it applies without prejudice to Article 3(2), which expressly permits Member States to
impose public service obligations on undertakings operating in the electricity and gas
sectors, which may in particular concern the price of supply.
In this context the conditions allowing price regulation in the form of public service
obligation imposed on undertakings are to i) be adopted in the general economic interest,
ii) be clearly defined, transparent, non-discriminatory and verifiable, guarantee equality of
access for EU companies to national customers and iii) meet a requirement for
proportionality (which refers in particular to limitation in time and as regards the scope of
beneficiaries).
145
Case C-265/08, Federutility and others v Autorità per l’energia elettrica e il gas
146
The Court judgement was based on Article 23(1)(c) of Directive 2003/55 of the Second Energy Package
which provides that Member States must ensure that all customers are free to buy natural gas from the
supplier of their choice as from 1 July 2007; however a similar provision is contained in the Second
Package Electricity Directive and the relevant provisions has remained unchanged in the Third Package
Directives.
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Price regulation for non-households has been systematically challenged via infringements
while price regulation for households has not been yet subject to infringement procedures.
Deregulating household prices may be politically unpopular in Member States where
regulation is justified by social policy objectives and/or lack of competition.
This policy choice has meant addressing through infringements the more important market
distortion created by the regulation of prices for larger and potentially most active
consumers who use most of the energy sold on the European market (more than 70% of
total electricity consumption and close to 60% of the total gas consumption)147
. In addition,
the Commission has opted initially for an informal approach via bilateral consultations
with Member States to discuss reasonable and sustainable alternatives to price regulation
and accompanying support for vulnerable consumers. However, infringement actions
against price regulation for households are not excluded in the follow-up to informal
consultations.
Electricity and gas price regulation refers to the ‘energy’ component of the end-user price,
excluding costs of transport/distribution, taxes, other levies and VAT. This component is
the element which should be determined by market demand and supply in a fully liberalised
energy market. By contrast, the other elements that influence the end-use electricity price
are subject to other regulation and legislation including network regulation, taxes and
levies/support schemes for energy efficiency and renewable energy sources.
Deficiencies of the current legislation
Despite the current acquis, some form of price regulation exists in 17 Member States, as
shown in the table below.
This is problematic because evidence presented in Section 5 of the present Annex
demonstrates that regulation of electricity and gas prices limits customer choice, reduces
customer satisfaction and restricts competition. This is particularly true for markets where
supply prices are set below costs (i.e. without taking into consideration wholesale market
prices and other supply costs).
Artificially low regulated prices (even without pushing them below costs) limit market
entry and innovation, prompt customers to disengage from the switching process and
consequently hinder competition in retail markets. In addition, they may increase investor
uncertainty and impact the long-term security of supply.
Furthermore, regulated prices (even when set above costs) can act as a pricing focal point
which competing suppliers are able to cluster around and – at least in markets featuring
strong customer inertia – can also considerably dilute competition.
As shown in the Evaluation of the EU's regulatory framework for electricity market design
and consumer protection in the fields of electricity and gas, market-based energy prices
that are able to take into account the rapid changes of demand and response and cross-
147
In 2014, non-residential customers consumed 1.921.153 out of the total 2.706.310 Gigawatt-hour
electricity consumption and 1.506.185 Gigawatt-hour out of the total 2.578.779 Gigawatt-hour of gas
consumption – Eurostat data, 2014.
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border trade are even more crucial than in 2009. The evaluation concludes that progress
towards lifting regulated prices blocking competition and consumers' choice should
continue (Evaluation Section 7.1.1).
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Table 1: Energy price regulation in EU Member States – February 2016148
148
Based on current state of play of the conformity checks.
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Member State Electricity Gas
Austria
Belgium
Bulgaria X X
Croatia X X
Cyprusi
X
Czech Republic
Denmarkii
X X
Estonia
Finland
France X X
Germany
UK (Great Britain)
UK (Northern Ireland) X X
Greeceiii
X
Hungary X X
Ireland
Italyiv
X X
Latviav
X
Lithuaniavi
X X
Luxembourg
Maltavii
X
Netherlands
Polandviii
X X
Portugalix
X X
Romaniax
X X
Slovakia X X
Slovenia
Spainxi
X X
Sweden
Source: European Commission Data.
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i
Price regulation economically justified due to natural monopoly.
ii
Denmark is implementing measures aimed at progressively removing regulated prices. This follows
from changes in the energy law introduced in January 2013.
iii
Discussions with Greece on the phase-out of regulated prices are conducted as part of the Economic
Adjustment Programme and lead to the phase-out of electricity regulated prices for households and small
enterprises as of 30 June 2013. The only exceptions are end-user prices for vulnerable customers. As
regards gas, a major reform of the Greek gas retail market is envisaged that seeks to abolish the regional
monopolies of the EPAs for gas supply and to progressively extend eligibility to all retail customers.
iv
Italy has introduced since 2013 market based reference prices for small customers including SMEs that
according to the Italian NRA should be considered de facto non-regulated.
v
Latvia has removed regulated prices for electricity for households other than vulnerable in January 2015.
As a first step towards price deregulation, a revised Energy Law, adopted on 18 September 2014,
introduced a category of vulnerable customers (underprivileged social groups and families with 3 or more
children) and set a fixed price for electricity for these customers. Regarding gas, the liberalization is
expected to be completed by 2017, subject to interconnections projects being realized in order to make
the transition from isolated market to an interconnected one.
vi
Lithuania has removed electricity regulated prices in the beginning of 2015.
vii
Malta regulates electricity prices for all customer segments. However, it has extensive exemptions
notably from market opening and customer eligibility provisions of the Third package.
viii
Discussions with Poland are ongoing regarding draft measures communicated to Commission's
services implementing the judgement delivered on 10 September 2015 concerning gas price regulation
(36/14 Commission v. Poland). The draft measures foresee deregulation of gas prices for households by
2023.
ix
Portugal has agreed a roadmap for phasing out regulated prices as a result of the infringement
proceedings initiated by the Commission. In August 2012, the government announced the complete
elimination of regulated tariffs with a transitory tariff in place for three years.
x
Romania has agreed an electricity and gas price deregulation calendar as part of the Economic
Adjustment Programme.
ix
In Spain, on 27 December 2013, the new Electricity Act modified the last resort tariff for electricity and
introduced the PVCP (Precio Voluntario Pequeño Consumidor or Voluntary price for small customers)
for electricity households. The energy component of this price reflects the spot market during the period,
only the profit margin of the suppliers being regulated.
Presentation of the options
Option 0: Making use of existing acquis to continue bilateral consultations and
enforcement actions to restrict price regulation to proportionate situations justified by
manifest public interest
This option consists in a new round of bilateral meetings with the Member States as regards
households, relying on the existing acquis. Due to the political sensitivity attached to price
regulation for households, but also taking into account that national price regulation
regimes are characterised by a variety of rules and justifications thereof, voluntary
collaboration between Member States based on assistance by the Commission services has
not been considered as an adequate tool for achieving price deregulation, a bilateral
approach being preferred. Bilateral meetings can be followed by EU Pilots and
infringement procedures to restrict price regulation to time-limited situations justified by
the public interest.
In this context, the Commission services will:
- offer Member States assistance on practical implementation of deregulation
including on accompanying good practice in protecting the energy poor through
social policy;
- monitor Member States' adherence to adopted phase-out roadmaps and the
implementation of the principle of cost-reflectiveness of their regulated prices; and
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- initiate enforcement where Member States refuse to phase-out regulated prices on
a voluntary basis.
While enforcement action under this option may be effective, as repeatedly backed by
favourable judgements of the European Court of Justice, infringement actions by the
Commission against price regulation for households remain politically sensitive.
Option 1: Requiring Member States to progressively phase out price regulation for
households by a deadline specified in new EU legislation, starting with prices below costs,
while allowing transitional, targeted price regulation for vulnerable customers (e. g. in the
form of social tariffs).
The legislative measures would include:
- introducing binding deadlines (e. g. 3-4 years from the entry into force of the
legislation) in the Electricity and Gas Directives for price-setting for households to
be free of regulatory intervention and instead subject only to supply and demand.
- allowing regulated prices (e. g. in the form of social tariffs) targeted at specific
groups of vulnerable customers, notably the energy poor. This would also
contribute to ensuring universal access to affordable energy services as required
under UN-backed Sustainability Development goals.
These measures would be accompanied by:
- bilateral consultations, as appropriate, to support Member States in defining and
implementing the roadmaps and in identifying vulnerable groups for special
protection.
- technical advice, guidance and sharing of good practices on energy efficiency,
alternative financial support measures (e. g. energy cheques) or income support
through the welfare system to complement or progressively substitute the need for
social tariffs.
This option might accelerate liberalization processes in Member States by establishing a
clear target date for price deregulation while allowing regulated prices as targeted,
transitional support to vulnerable customers. However, it would not fully take into account
social and economic particularities in Member States in setting up a common deadline for
price deregulation.
Option 2a: Requiring Member States to progressively phase out price regulation, starting
with prices below costs, for households below a certain consumption threshold to be
defined in new EU legislation or by Member States, with support from Commission
services.
If the consumption threshold is defined below current levels used by Member States to
apply price regulation, this option would reduce the scope of price regulation therefore
limiting its impact on the market.
The main challenge of this option concerns the calculation of the right thresholds. Allowing
regulated prices up to certain rather low energy consumption thresholds may miss out some
poorer customers who may consume rather more energy per household, as they may spend
more time in their homes (due to unemployment, invalidity, home work), live in poorly
insulated dwellings or require to be connected to medical equipment. As a consequence
they may exceed the defined thresholds. On the other hand and contrary to the desired
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effect, ordinary customers of sufficient wealth but low consumption e.g. due to a lifestyle
with a relatively limited use of appliances may profit from such thresholds. The same might
apply to secondary homes inhabited only temporarily by wealthier customers.
Maintaining regulated prices for large parts of consumption through high thresholds
prevents the development of market-based demand response and other flexibility options,
as price-based incentives cannot be created through price regulation schemes as effectively
as by the market. This option could thus limit the achievement of the full effects of the
Market Design initiative, particularly its elements aimed at end-customers.
Option 2b: Requiring Member States to phase out below cost price regulation by a deadline
specified in new EU legislation.
While this option would limit the distortive effect of price regulation and tackle tariff
deficits, maintaining regulated prices, even if above cost, would prevent the development
of market-based demand response and other flexibility options, as price-based incentives
cannot be created through price regulation schemes as effectively as by the market.
Moreover, price regulation that does not allow charging more than current costs risks
holding back investments in product innovation and service quality.
The main challenge of this option would be to define cost coverage methodologies for
price regulation at EU level. It is legally challenging as the current EU acquis establishes
as a general rule that prices should be set by market forces; moreover, this option could
produce weaker effects than current EU acquis as it would limit the requirement of
proportionality to be met by price regulation only to the cost coverage aspect (not taking
into account the limitation in time, in the scope of beneficiaries or the necessity test). It is
also economically challenging due to opaque cost structures of the companies. Moreover,
ensuring cost-reflectiveness by regulation would imply considerable regulatory and
administrative impact.
Comparison of the options
Comparison of performance of energy markets with and without price regulation
The objective of this Section is to assess the performance of energy markets where prices
are established by a governmental authority (they are regulated) with that of markets where
prices are set in market conditions, by supply and demand. The assessment is made based
on the level of competition within each group of markets, according to the conventional
structure-conduct-performance framework, which explores a range of retail market
indicators such as market structure and concentration, consumer switching activity and
consumer experience.
In order to assess the performance of markets with and without energy price regulation the
present Section carries out a comparative analysis of energy markets across all EU Member
States, grouped in two categories: markets where energy prices are set in market conditions
and markets characterised by intervention in the price setting mechanism. These two
groups are appraised using average values for each of the elements considered, weighted
by population.
Background: Energy market liberalisation and price regulation
The EU-level liberalisation of the electricity market was initiated with the First Energy
Market Directive, which was adopted in 1996. At that time, both the United Kingdom and
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the Nordic countries had already started to liberalise their markets. Two additional
legislative packages have followed since then, i.e. the Second Energy Market Directive in
2003 and the Third Package, including the Third Electricity Directive, in 2009. The process
has aimed to separate the network activities, i.e. transmission and distribution, from
generation and supply activities. The rules regarding unbundling of these activities into
separate entities have become increasingly stringent over this period to properly ensure
this separation of activities. This has mainly reflected concerns about the competition, in
particular regarding an appropriate pricing of these services as well as fair access to the
networks for new entrants.
Following the separation of the different activities in the supply chain of electricity, the
price formation of the final end-user price has also changed. The electricity price now
consists of different components relating to the different parts of the supply chain, as
shown on Figure 1.
While regulated prices are unlawful under current Gas and Electricity Directives, unless
they meet specific conditions, many Member States still apply price regulation.
At the same time it is important to note, as already explained in Section 2 of the present
Annex, that electricity and gas price regulation refers only to the ‘energy’ component of
the end-user price, excluding network charges, taxes, other levies and VAT. This
component is the element which should be determined by market demand and supply in a
fully liberalised energy market.
Figure 1: Different components of the final electricity price
Source: ECFIN
Background: Academic discussion on the merits of energy market liberalisation
A number of academic papers have presented arguments in favour of price regulation in
retail energy markets. The assumption presented is that deregulation will not lead to any
significant efficiency improvement or added value. The argument presented is that the
potential retail savings on activities such as metering, billing or customer services are
uncertain and their expected economic impact is too low to be significant for most
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customers.149
In addition, it is also argued that customers are reluctant to change150
and in
some cases inability to make appropriate choices.151
However, the above mentioned arguments have been refuted by a number of authors.
Littlechild argues that domestic customers are not indifferent to choice, and retailing is
precisely the activity that can lead to products that best suit customers' preferences.152
Based on the US experience with energy market liberalisation Zarnikau and Whitworth153
,
Rose154
and Joskow155
demonstrate cost-saving benefits from competition.
Moreover, introducing competition is equivalent to opening the door to innovation. The
market can create alternatives to a regulated framework. Those in favour of a regulated
retail market assume regulators will set up a pass-through tariff in which the final price of
energy will be composed of the cost of wholesale energy plus a margin to cover for the
cost of selling the energy to the final customers. However, Littlechild argues that if
customers want this option, the market will be able to deliver it. Indeed, as it is already the
case in the Nordic Member States, with the roll-out of smart meters, dynamic tariffs, which
are similar to the pass-through tariffs, will be available to customers. From this perspective,
the advantages of competition are clear.
Other arguments in favour of open retail markets refer the possibility that suppliers
introduce new billing options, improve operations of the wholesale market by raising the
number of agents involved or provide energy efficiency related services. On the other hand,
regulated prices may reduce customer engagement and, in these markets, there is a
possibility for Governments to alter electricity tariffs for political gains. More generally, it
has been argued that end-user price regulation in electricity and gas markets distorts the
functioning of the market and jeopardises both security of supply and the efforts to fight
climate change156
.
Assessment of market structure and concentration
Measures of market structure and concentration, such as the number of main suppliers and
the market share of largest suppliers, provide an indication of the degree of competition in
a market, which is a useful first step to draw a comparison between markets with energy
price regulations and those where prices are set by supply and demand. Markets with lower
market concentration where a high number of service providers compete to gain and retain
customers are under competitive pressure to deliver better deals for consumers. This makes
market structure indicators relevant for assessing the performance of energy markets.
149
"Why do we need electricity retailers? Or can you get it cheaper wholesale" (2000) Paul L. Joskow; "The
future of retail energy markets" (2008) Catherine Waddams; "The big retail ‘bust’: what will it take to
get true competition?" (2000) Theresa Flaim
150
"Consumer preference not to choose: methodological and policy implications" (2007) Timothy J Brennan
151
"Retail competition in electricity markets" (2009) Christophe Defeuilley
152
"Retail competition in electricity markets—expectations, outcomes and Economics" (2009) Stephen
Littlechild
153
"Has Electric Utility Restructuring Led to Lower Electricity Prices for Residential Consumers in Texas?"
(2006) Jay Zarnikau, Whitworth
154
"The State of Retail Electricity Markets in the US" (2004) Kenneth Rose
155
"Markets for power in the United States: an interim assessment" (2005) Paul L Joskow
156
"Position paper on end-user price regulation" (2007) European Regulators’ Group for Electricity and
Gas
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Evidence shows that energy markets without price regulation show a higher number of
suppliers and less market concentration. In fact, while markets without electricity price
regulation have on average 34 nationwide suppliers, markets with regulated prices have
19, as shown on Figure 2. A similar trend can be observed within the gas market, as shown
on Figure 4. While markets without gas price regulation have on average 30 suppliers,
markets with regulated prices have 17.
Among the top ten electricity markets in terms of the number of suppliers, seven do not
use any form of price regulation, including Sweden (97 nationwide suppliers), the
Netherlands (75) and Finland (45). In contrast, among the ten electricity markets with the
lowest number of suppliers, eight are characterised by regulated prices, including Cyprus
(1 nationwide supplier), Malta (1), Lithuania (3), Bulgaria (4) and Latvia (5).
Figure 2: Overall number of suppliers and number of nationwide suppliers active in
the retail electricity market for households
Source: ACER
19
34
174
390
0 100 200 300 400 500 600
WA (reg)
LV
EL
SK
RO
PT
PL
MT
LT
IT
HU
HR
FR
ES
DK
CY
BG
WA (non-reg)
UK
SI
SE
NL
LU
IE
FI
EE
DE
CZ
BE
AT
Overall number of suppliers
Nationwide suppliers
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Figure 3: Overall number of suppliers and number of nationwide suppliers active in
the retail gas market for households
Source: ACER
Market concentration, measured by the share of the main suppliers in that market, is
another key indicator of competitiveness. Main suppliers (i.e. suppliers who have a market
share above 5% of the total) in markets without price regulation have a 63% market share
in the electricity market and 56% market share in the gas market. Markets with regulated
prices see main suppliers covering 74% of the market on average in electricity and gas
markets. This data further confirms the advantage of markets without price regulation in
terms of their competitive performance.
17
35
80
300
0 100 200 300 400 500 600
WA (reg)
LV
EL
SK
RO
PT
PL
MT
LT
IT
HU
HR
FR
ES
DK
CY
BG
WA (non-reg)
UK
SI
SE
NL
LU
IE
FI
EE
DE
CZ
BE
AT
Overall number of suppliers
Nationwide suppliers
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Figure 4: Cumulative market share of main suppliers
Source: ACER
Assessment of market conduct
Effective retail competition is characterised by competition between suppliers over price
and non-price elements whereby suppliers undercut each other's' prices to the efficient cost
level, improve the quality of their services and develop innovative products which meet
the requirements of customers with a view to increasing market share and profits. In
competitive retail markets customers should have the freedom of choice by moving to an
alternative supplier, to change contracts or to choose new products. The freedom to choose
the energy supplier is key because customer switching activity puts competitive pressure
on market actors.
In the present Section all of the above described elements of retail market conduct are
analysed for both regulated and non-regulated energy price markets in order to complete
the relative performance assessment of these markets.
Price competition
Price competition is typically used as the basic indicator of market competitiveness. Price
competition among suppliers is limited to the energy component of the supply price which
remains the largest of the three price components despite the fact that this component has
generally diminished since 2008 mainly due to increases in the taxes/levies.157
Data from the Agency for the Cooperation of Energy Regulators (ACER)158
shows that
Member States without regulated prices have on average slightly higher energy prices than
those with price regulation. This is not surprising as Member States with regulated prices
can set de facto the final price on energy services. Price regulation by State authorities can
157
"Energy prices and costs in Europe" (2014) European Commission
https://ec.europa.eu/energy/sites/ener/files/publication/Energy%20Prices%20and%20costs%20in%20E
urope%20_en.pdf
158
"Market Monitoring Report 2014" (2015) ACER, available at
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015.pdf
63
74
56
74
0
10
20
30
40
50
60
70
80
Non-regulated Regulated
Electricity
Gas
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and in some instances does result in prices set below costs, i.e. the end consumer price does
not cover the full costs of producing and delivering energy to consumers.
Figure 5: Retail price level across EU Member States, 2014
Source: ACER
Note: Information for Latvia; Bulgaria; Bulgaria, Croatia, Cyprus; Lithuania; Malta; and Romania not available.
While lower retail prices seem to present an immediate advantage to all customers, it is
important to analyse the economic sustainability of energy prices regulated below the
actual cost and changes to consumer surplus resulting from price regulation.
Cost reflectiveness of regulated prices
Regulated prices can have negative impacts on the energy market especially if they are set
too low. First, energy prices which are set too low fail to provide the right signal to energy
customers about costs and scarcity, which risk resulting in over-consumption of a cheap
service. Second, the low level might hamper the process of market opening by
discouraging new companies from entering the market. Third, they will determine the
ability of different suppliers to make competitive offers on the wholesale market. For this
reason, if end-user prices are set too low, suppliers might not be able to recover their costs
and could face potential losses.
By contrast, if set too high, they might not reflect the production costs of the incumbent
and increase their rents, while at the same time reducing the surplus of final customers.
The result is inefficiencies in the overall energy system.
Determining the proper level of regulated prices requires full information on the cost
structure of the industry, which is becoming increasingly difficult as the electricity markets
evolve.
In fact, while ensuring cost-reflectiveness of regulated prices could be an option to address
negative effects of price regulation, the regulators' ability to set the right margin between
wholesale and retail prices is limited by imperfect information and rapidly changing market
conditions including a wholesale market which is affected by commodity prices, cost of
capital and the price of CO2 allowances, to quote just a few. These barriers constitute a
significant disadvantage characterising any kind of price regulation, even that which is set
"above costs", as there is a high risk that the margins set by the regulators will not be
23
18
0
5
10
15
20
25
30
35
AT
BE
CZ
EE
FI
DE
GB
IE
LU
NL
SI
SE
WA
(non-reg)
DK
FR
HU
IT
PL
PT
SK
ES
EL
WA
(reg)
Retail
price
level
€/kWh
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sufficient for new service providers to enter the market. The effect of such miscalculation
of the most optimum price level would be less market players and less competition and
therefore less innovation and a lower general level of services.
Issue of tariff deficits
Electricity tariff deficits have emerged as an issue for public finances. A tariff deficit
implies that a deficit or debt is built up in the electricity sector, often in the regulated
segments of transmission or distribution system operators, but in some cases also in the
competitive segments, e.g. in incumbent utilities.
A deficit is accumulated due to the fact that the regulated tariffs which should cover the
system's operating costs are either set too low or not allowed to increase at a pace that
cover rising production or service costs. As these deficits accumulate due to government
regulation of tariff or price levels, they have been recognised as contingent liabilities of
the State in a few Member States. In these cases, the debt stemming from low energy prices
need to be repaid through general taxation from present or future taxpayers.
The results of a study carried out by the Directorate General for Economic and Financial
Affairs on the issue of electricity tariff deficits indicates that 11 Member States had
accumulated electricity tariff deficits as of 2012159
. Within that group, 10 Member States
continue to regulate their electricity prices, as shown in Figure 7.
Figure 6: Electricity tariff deficit – comparison between Member States
Source: DG ECFIN, European Commission
Cumulated tariff debts are substantial in some Member States. In Spain and Portugal,
where electricity prices are regulated, the tariff debt represented 3% and 2.2-2.6% of the
GDP respectively.
Link between wholesale and retail prices
159
"Electricity Tariff Deficits. Temporary or permanent problem in the EU?" (2014) European Commission
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While regulated price markets show an advantage over unregulated price markets in terms
of the final price for the consumer, research carried out by the European Parliament shows
that the relationship between wholesale and retail prices for households is weaker in
countries with price regulation.160
Whilst retail household prices appear to be positively
related to wholesale prices for both groups of countries, the link for countries with price
regulation is less pronounced based on the estimated coefficients. This indicates that
regulated prices may weaken the link between wholesale prices and retail prices, or at least
tend to delay it. While this could delay or prevent the increase of household prices when
wholesale prices are high, it may also imply that households cannot fully benefit from a
decrease in wholesale prices.
Ensuring an effective link between wholesale and retail energy prices is key for delivering
the benefits of the wholesale energy market competition to energy consumers. To give a
sense of perspective, the European Commission 2014 report on the "Progress towards
completing the Internal Energy Market" found that wholesale electricity prices in the EU
declined by one-third and wholesale gas prices remained stable between 2008 and 2012.161
Protection of vulnerable consumers and the energy poor
Continuous price regulation in some Member States is justified on the grounds of
protection of vulnerable consumers and the energy poor. In this context, it is argued that
energy price regulation is necessary to protect customers from the market power of energy
monopolies. This is because an unregulated monopoly could charge customers a price
much higher than its production cost. Similar arguments have been put forward with
respect to vulnerable customers.
However, evidence shows that blanket energy price regulation is not an optimal protection
measure for vulnerable consumers from the point of view of efficient allocation of public
resources. The above is based on the assumption that deficits associated with energy prices
regulated below-costs are financed from the State budget. In fact, under regulated energy
price environments public resources are often used to support all households, regardless of
their income or vulnerability. The efficiency of such approach is questionable as even the
distribution of benefits associated with low regulated energy prices results in higher
income groups receiving higher public support than lower income groups, as evidenced in
Figure 7 below, which shows that top earners in most Member States consume more
electricity than the lowest income groups. Higher energy consumption among top income
groups occurs despite the assumed higher efficiency of dwellings inhabited by these
income groups and higher energy efficiency of appliances typically used.
160
"The impact of oil price on EU energy prices" (2014) European Parliament
161
"Communication on progress towards completing the Internal Energy Market" European Commission
COM(2014) 634 final
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Figure 7: Electricity consumption per income group
Source: DG ENER
It can be argued that if resources previously allocated to finance below-cost price
regulation are used for targeted support of vulnerable consumers, a higher impact can be
achieved in terms of the protection of vulnerable consumers. This conclusion is supported
by evidence presented in Figure 8 which shows that consumers in unregulated price
markets feel more able to maintain an adequate level of heat during winter. This data also
shows that energy price regulation is not an effective means of addressing energy poverty.
Figure 8: Percentage of population unable to keep their homes warm during winter,
2014
Source: DG ENER
Non-price competition/innovation
Although low prices are the most commonly thought of way for firms to attract consumers,
suppliers may also seek to distinguish their products by other means. These may include
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quality of service, convenience, an environmentally sustainable product, or any other non-
price aspect that adds value for consumer and brings innovation to the retail energy market.
The diversity of products available in a market is therefore also a good indication of the
health of competition.
Conversely, when prices are kept artificially low customer surplus may be reduced as some
customers are able and willing to pay higher prices for better and more innovative energy
services. In that context regulated prices might deprive those customers from accessing
more offers and more innovative and complex services such as certified green energy
offers, loyalty programmes, access to new technologies such as smart metering and mobile
apps, or non-financial benefits such as free maintenance of water boilers or home insurance
which are delivered by some retailers within the energy market.
In fact, data displayed in Figure 9 shows that customers in markets where prices are not
regulated have access to more diverse services and a wider choice of offers. Dual fuel
offers are available in 75% of the markets without price regulation and only in 44% in
those with regulated prices. Certified green energy offers are available in 92% of the
markets without price regulation and in 67% of the markets with regulated prices. Only
50% of markets with regulated prices offer energy pricing alternatives, while this option is
available in 92% of markets without price regulation.
Figure 9: Share of Member States with dual-fuel, certified green and variety of
energy pricing tariffs
Source: ACER
Markets without price regulation are also characterised by retail energy markets delivering
more financial and non-financial benefits and a greater availability of information and
communication technologies in association with energy contracts, as showed in Figure 10.
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Figure 10: Retail market innovation
number of
electricity
only
offers
dual-fuel
available
certified
green
energy
offers
available
availability
of non-
price
financial
benefits
availability
of non-
financial
benefits
ICT
offer
Variety of
energy
pricing
alternatives
available to
consumers
Austria 53 Yes Yes Yes Yes Yes Yes
Belgium 20 Yes Yes Yes No Yes Yes
Bulgaria 1 N/A N/A No
Croatia 4 N/A N/A Yes
Czech
Republic
69 Yes Yes Yes
Cyprus 1 N/A N/A No
Denmark 83 No Yes Yes No Yes Yes
Estonia 40 Yes No Yes
Finland 401 No Yes Yes Yes Yes Yes
France 22 Yes Yes Yes
Germany 404 No Yes Yes No Yes Yes
Great Britain 69 Yes Yes Yes Yes Yes Yes
Greece 7 No No Yes
Hungary 4 No No No
Ireland 9 Yes Yes Yes Yes Yes Yes
Italy 23 Yes Yes Yes Yes Yes Yes
Luxembourg 18 Yes Yes Yes
Latvia 1 N/A N/A No
Lithuania 1 N/A N/A No
Malta 1 N/A N/A No
Netherlands 86 Yes Yes Yes No Yes Yes
Poland 133 No Yes Yes
Portugal 34 Yes Yes Yes
Romania 1 N/A N/A No
Slovakia 23 No No No
Slovenia 5 Yes Yes No
Spain 54 Yes Yes Yes Yes Yes
Sweden 378 No Yes Yes Yes Yes Yes
Source: ACER/CEER, VaasaETT
Data presented above further confirms that markets where prices are set according to
supply and demand perform better in terms of bringing innovation to the retail energy
market– deliver greater choice and more innovative services and offers, than markets
where energy prices are regulated.
Customer switching activity
Customer switching activity puts competitive pressure on suppliers and therefore is an
important indicator of competition within the market.
ACER data presented in Figure 11 and 12 shows that markets with no price regulation
show higher customer activity both in terms of external switching (movement between
suppliers) and internal switching (movement between alternative products from the same
supplier) than markets with regulated prices.
On the other hand, electricity switching rates in markets with price regulation are
significantly lower. In Malta, Cyprus, Bulgaria, Latvia, Lithuania and Romania switching
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rates remained at zero, mainly due to the lack of retail competition or very weak
competition and limited choice available to customers.
Figure 11: Customer external switching rates
Source: ACER
Customers in regulated price markets also display lower internal switching rates – a
phenomenon which can be explained by more restricted choice of offers in those markets.
In fact, Figure 12 shows that 75% of customers in markets with price regulation have never
switched contracts, in comparison to 32,5% in markets with no price regulation.
Figure 12: Proportion of customers who have never switched contract (internal
switching)
Source: ACER
Low switching rates in markets with price regulation represent a lost opportunity for
savings for many customers. In fact in most markets customers can derive
substantial benefits from switching, as illustrated in Figure 13. In markets without
price regulation customers can save on average 23% of their energy bill by switching
from the incumbent. Potential savings in markets with price regulation amount to
12% on average.
8%
6%
0%
2%
4%
6%
8%
10%
12%
14%
16%
AT
BE
CZ
EE
FI
DE
GB
IE
LU
NL
SI
SE
WA
(non-reg)
DK
FR
HU
IT
PL
PT
SK
ES
EL
WA
(reg)
Rate
of
switching
(%)
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Figure 13: Savings on incumbent
Source: ACER
Assessment of customer experience
Customer experience is key to appraising the comparative performance of different types
of markets. Variables which compose customer experience and are analysed in this Section
include comparability of offers, trust in retails to respect the rules and regulations
protecting customers, the degree to which customer expectations are met and customer
satisfaction with the choice.
The above variables are measured by the Consumers, Health, Agriculture and Food
Executive Agency (CHAFEA) as part of the Market Monitoring Survey. The report
surveys 42 markets in the 28 Member States of the EU, as well as Norway and Iceland,
with the general aim to assess customer experiences and the perceived conditions of the
customer markets in all EU Member States. The assessment is measured through a "Market
Performance Indicator" (MPI) which is a composite index indicating how well a given
market performs, according to customers.
The overall MPI score for the market for “electricity services” across the EU is 75.3 points,
based on a maximum possible score of 100 points. Electricity services market scored 3.3
points lower than the services markets average. This makes it a low performing services
market, ranking 26th of the 29 services markets. The overall MPI score for the market for
“gas services” at EU28 level is 78.1, which is lower than the services markets average
score by 0.5 points. This makes it a middle to high performing services market, ranking
14th of the 29 services markets.
In comparison to the services markets average, the “electricity services” market has a
higher proportion of complaints and higher detriment score, measuring customers
experiencing problems with the products or services they purchased. The electricity
services market also performs worse than average in terms of the comparability of offers,
customers' trust in suppliers, the capacity to meet customers' expectations, and the ability
of the market to deliver sufficient choice. It is also characterised by a lower than average
switching activity.
At the same time, there is a 34.1 point difference in MPI between the top ranked country
and the lowest ranked country, indicating that there are considerable country differences
23%
12%
-10%
-5%
0%
5%
10%
15%
20%
25%
30%
35%
40%
AT
BE
CZ
DE
EE
FI
IE
LU
NL
SE
SI
UK
WA
(non-reg)
BG
CY
DK
ES
FR
HR
HU
IT
LT
MT
PL
PT
RO
SK
EL
LV
WA
(reg)
Savings on incumbent (%)
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to be taken into account when evaluating the electricity services market. The market scores
higher in the EU15 and lower in the EU13 compared to the EU28, while performing
especially well in the Western and Northern regions.
In comparison to the services markets average, the “gas services” market scores above the
average for the problems, detriment and expectations components. However, the
comparability and choice components are lower. The “gas services” market also has a
lower than average switching proportion.
Figure 14: Market Performance Indicator for electricity markets with and without
price regulation
Source: EC, DG JUST162
The MPI scores for 2015 indicate a clear advantage of markets without price regulation
over those with regulated prices in terms of customer satisfaction. As shown in Figure 14,
markets without price regulation scored on average 80 points, while those with price
regulation scored 72. The advantage of markets without price regulation over those with
regulated prices was equally spread across all five components analysed, as shown in
Figure 15.
162
"Monitoring Customer Markets in the European Union 2013 – Part III (Electricity)"(2013) European
Commission
80
72
68
70
72
74
76
78
80
82
WA (non-reg) WA (reg)
WA (non-reg)
WA (reg)
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Figure 15: Market Performance Indicator for electricity markets per component for
electricity markets with and without price regulation
Source: EC, DG JUST
The 2013 edition of EU market surveys provides an insight into general customer
satisfaction with the electricity market, as shown in Figure 15. Markets without price
regulation scored 7.6 and 7.8 on average for customer satisfaction with the offers on the
market and with the variety of suppliers, while markets with price regulation scored 6.8
and 5.8 points respectively. This data confirms a clear advantage of markets without price
regulation from the customer point of view.
Figure 16: Customer satisfaction with the electricity market
Source: European Commission (2013)
Conclusion of the assessment
In this Section we have methodically screened the performance of markets with and
without price regulation based on a number of competitiveness indicators and market
surveys which measure market competitiveness and customer satisfaction with the
electricity and gas markets. The analysis indicates that electricity and gas markets where
1,4
1,5
2,0
1,7
1,4
1,2
1,3
1,9
1,6
1,2
0,0
0,5
1,0
1,5
2,0
2,5
compare trust prob_det expect choice
WA (non-reg)
WA (reg)
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prices are set by supply and demand are able to deliver better and more diverse services to
the customers. In fact, despite slightly higher prices in markets without price regulation,
customers in these markets show a higher level of satisfaction as they have a wider choice
and access to better quality services which are more reflective of their preferences.
The analysis nonetheless suffers from clear limitations such as selection bias. It might well
be that the Member States in the category of non-regulated prices have lower market
concentration, higher switching rates or better customer experience for reasons different
than price regulation. However, despite the methodological weaknesses of the analysis, the
results are comparable with the results of research carried out by ACER in its Market
Monitoring Report.
In fact, in order to achieve a full picture of energy market competitiveness which is not
dependent on a single indicator ACER produced a single composite index (‘ACER Retail
Competition Index – ARCI’) which provides a comprehensive picture of the relative
competition performance of the retail electricity and gas household markets in each
Member State. The indicator combines several elements, including market concentration,
entry/exit activity, switching, consumer satisfaction and mark-ups (see Table 2 below). As
such the indicator covers all of the individual components used to analyse the performance
of markets with and without electricity and gas price regulation.
Table 2: Competition indicators included and the assessment framework for the
composite index
Indicator Scope Low score = 0 High score =10 Weight
Concentration ratio, CR3 National Market share of
three largest
suppliers 100%
Market share of three
largest suppliers 30%
or less
10
Number of suppliers with market
share > 5%
National Low number of
suppliers
High number of
suppliers
10
Ability to compare prices easily National Difficult to compare
prices
Easy to compare
prices
10
Average net entry (2012-2014) National Net entry zero Net entry of five or
more nationwide
suppliers
10
Switching rates (supplier + tariff
switching) over 2010-2014
National Annual switching
rate zero
Annual switching rate
20% or more
10
Non-switchers National None have switched All have <1/3 not
switched
10
Number of offers per supplier Capital
city
One offer per
supplier
Five or more offers
per supplier
10
Does the market meet
expectations
National Market does not
meet expectations
Market fully meets
expectations
10
Average mark-up (2012–2014)
adjusted for proportion of
consumers on non-regulated
prices
National High mark-up Low mark-up 10
Source: ACER
According to the index, the most competitive markets for households are electricity
markets in Sweden, Finland, the Netherlands, Norway and Great Britain and gas markets
in Great Britain, the Netherlands, Slovenia, the Czech Republic and Spain. The index
shows weak retail market competition in electricity household markets in Latvia, Bulgaria
and Cyprus and gas household markets in Lithuania, Greece and Latvia.
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The results of the ACER analysis, presented also in Figure 14, indicate that the level of
competition in markets with regulated prices for households is much lower than in
countries that do not regulate electricity and gas prices, with the exceptions of the gas
markets in Spain and Denmark. Therefore the ACER indicator confirms the overall
findings of the analysis of the performance of markets with and without price regulation
carried out in the present Section.
Figure 17: ACER Retail Competition Index (ARCI) for electricity and gas
household markets – 2014
Source: ACER
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Comparison of options for price deregulation
Table 3: General comparison of the options
0. Non legislative:
Making use of
existing acquis to
continue bilateral
consultations and
enforcement
actions,
accompanied by EU
guidance
1. Legislative
obligation:
No price
regulation but
social tariffs
allowed
2a Legislative
obligation:
Price regulation
allowed below
certain
consumption
threshold
2b. Legislative
obligation:
Cost covering
price regulation
allowed without
limitation as to
the amount of
energy consumed
Time
limitation
End date to be set by
each Member State in
compliance with EU
acquis to be assessed
on case-by-case
basis.
End date set in
EU legislation
for all price
regulation
(except social
tariffs)
End date set in EU
legislation for
price regulation
above a certain
consumption
threshold.
No end date for
price regulation
below the defined
threshold.
End date set in EU
legislation for price
regulation below
costs
No end date for
price regulation
below the defined
threshold.
Limitation as
to the scope of
beneficiaries
Scope of
beneficiaries to be
defined by each
Member State in
compliance with EU
acquis to be assessed
on case-by-case
basis.
No beneficiaries
of price
regulation.
Social tariffs
allowed as
transitional
measure
Beneficiaries of
price regulation
limited to
households below
a certain
consumption
threshold
No limitation as
regards the scope
of beneficiaries (all
households).
Methodology
for setting the
price
Methodology to be
defined by each
Member State in
compliance with EU
acquis to be assessed
on case-by-case
basis.
No provisions
as regards
methodology
(cost coverage
etc.) necessary
as all price
regulation is to
be phased out.
Methodology to
be defined by
each Member
State in
compliance with
EU acquis to be
assessed on case-
by-case basis.
Principles ensuring
cost coverage (e. g.
at least positive
mark-ups or costs
of an efficient
supplier plus a
reasonable profit
margin) to be
defined in EU
legislation while
concrete
methodologies
would be
developed at
national level.
Level of
harmonisation
Allows a case-by-
case assessment of
the price regulation
regimes as well as of
the eventual
exemptions.
Harmonised end
date for blanket
price regulation.
Allows a case-
by-case
assessment of
the exemptions
to price
deregulation
(targeted price
regulation for
vulnerable
consumers).
Harmonised end
date for blanket
price regulation.
Harmonised
exemptions to
price deregulation
(based on a
consumption
threshold).
Harmonised end
date for blanket
price regulation.
Harmonised
exemptions to
price deregulation
(based on a price
threshold).
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Option 0
Option 0 consists of making use of the existing acquis to continue bilateral consultations
and enforcement actions to restrict price regulation to proportionate situations justified by
general economic interest.
Costs
The main costs of this option are those of adapting price regulation regimes in Member
States following a case by case assessment by the Commission services via bilateral
consultations followed by infringement actions where appropriate based on the current EU
acquis. This option would result in different national regimes of price intervention (in terms
of applicability in time, to the scope of beneficiaries and definition of price regulation) or
a complete removal thereof, assessed on a case-by-case basis in terms of compliance with
the EU acquis including as regards proportionality of the measure for achieving the
pursued general interest objectives. It is therefore difficult to estimate the costs associated
with the implementation of each regime.
The resulting diversity of regimes would create/maintain uncertain prospects for
businesses which discourages cross-border supply activities.
The lack of a level playing field across the EU in terms of price setting procedures
translates into administrative costs for entering and conducting business in new markets.
Member States with no price regulation will not be affected by the implementation of this
option. Therefore no economic impacts are to be expected.
Benefits
While overall the competition on retail markets would improve compared to the existing
situation due to the limitation or complete removal of price regulation in Member States,
market distortions would continue to exist impacting national markets as well as cross-
border competition.
Consumers' benefits linked to price deregulation (more consumer choice for suppliers and
energy service providers, better services and resulting increased consumer satisfaction)
would vary according to the national price intervention regime/the lack thereof.
Option 1
Option 1 consists of requiring Member States to progressively phase out price regulation
for households by a deadline specified in new EU legislation, while having the right to
allow transitional, targeted price regulation for vulnerable customers (e. g. in the form of
social tariffs).
Social tariffs are a form of regulated prices, usually below market level, available to
specific groups of vulnerable customers, notably the energy poor, to ensure that these
customers have access to energy at affordable prices.
A social tariff can apply to electricity and/or gas (or any other fuel). The illustrative
analysis of costs and benefits for this option will focus on electricity.
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Costs
The main cost components of this option are associated with the potential introduction of
a targeted price regulation for vulnerable consumers, such as through the social tariff.
Member States already applying social tariffs (BE, BG, CY, FR, DE, GR, PT, RO, ES,
UK) would not be affected by the implementation of this option.
The estimation of cost and benefits of Option 1 is made in comparison to the free market
option (with no regulated prices of any kind or social tariff) for Member States which
currently do not use "social tariffs" as a form of protection of vulnerable consumers.
The estimations provided are for illustrative purposes only. The final amount of targeted
electricity and/or gas, number of households and level of subsidies can be varied depending
on the preferences of the Member State implementing the measure.
Table 4 below shows the average annual electricity consumption and average annual
expenditure on electricity which are the two variables used to estimate the cost of
introducing social tariffs.
Table 4: Average annual household electricity consumption and expenditure, 2014
Member State
Average annual electricity
consumption
Average annual expenditure
on electricity
kWh/HH EURO/HH
BG 3836 275
CY 4935 920
DK 4288 439
ES 3855 687
FR 5204 499
GR 3953 471
HR 3712 374
HU 2522 233
IT 2494 375
LT 2025 180
LV 2099 180
MT 4266 553
PL 2010 221
PT 2935 377
RO 1590 144
SK 2682 330
Source: INSIGHT_E
The cost of implementing a social tariff depends on the scope of beneficiaries, the
difference between the market-based price of energy and the advantageous price set for the
beneficiaries of social tariffs as well as on the amount of energy consumption to be covered
by the social tariff.
For the purpose of this analysis, the beneficiaries of the social tariff are defined as the share
of the population unable to keep warm (according to EU-SILC 2014). The level of the
social tariff is defined as 20% less than the regular electricity price (which is shown as the
average 2014 nominal price without taxes and levies). There would be no cap on the
amount of energy consumption covered by the social tariffs for the defined beneficiaries.
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However, in reality Member States would be able to decide on all of the above elements
according to their national circumstances. This means that Member States would be able
to decide on a more restraint or larger group of beneficiaries, a specific discount level
defining the price level under social tariffs and/or set a cap on energy consumption beyond
which market prices apply.
Within Option 1 various sub-options can be explored with respect to financing the
implementation of the social tariffs, such as:
A- financing only by non-vulnerable households,
B- financing by all households and
C- financing by all electricity customers (including industry, commercial sectors,
and all households including vulnerable households).
However, it is important to bear in mind that a levy only on industrial customers would not
be desirable as this would make industry less competitive. The final tariff would still vary
for vulnerable (eligible households) and other household customers as the base price for
the regular tariff and the social tariff remains the same in each instance. Of course, the
social tariffs can also be financed in part or in whole through the government budgets and
this option could be explored in addition (i.e. financial transfers).
The table and figures below show the costs or savings (net benefits) of the introduction of
a tariff, with savings arising for households receiving the social tariff and costs for those
paying for the tariff measure. Costs and benefits are calculated for each of the above
defined sub-options for financing: A, B and C.
As shown in the summary table below, the costs to finance the social tariff will see an
increase in the electricity bills from 1-14% depending on electricity prices, share of
vulnerable consumers and average electricity consumption in each Member State. The
increase in the electricity bills as result of the implementation of the measure is expected
to be highest in BG, GR, CY and PT if the financing is done via all non-vulnerable
households or all households. Financing the measure across all electricity consumers
allows alleviating the increase in energy bills thus limiting the impact on individual
customers.
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Table 6: Comparison of differences in tariffs to vulnerable and non-vulnerable
households for Option 1 according to different financing models
A - Financing across all non-
vulnerable households
B - Financing across all
households
C - Financing across all
electricity consumers
Non-vulnerable
Households
(regular tariff)
Vulnerable
Households
(social
tariff)
Non-vulnerable
Households
(regular tariff)
Vulnerable
Households
(social
tariff)
Non-vulnerable
Households
(regular tariff)
Vulnerable
Households
(social
tariff)
BG 14% -20% 8% -10% 3% -16%
CY 8% -20% 6% -13% 2% -18%
DK 1% -20% 1% -19% 0% -20%
ES 2% -20% 2% -17% 1% -19%
FR 1% -20% 1% -19% 0% -19%
GR 10% -20% 7% -12% 2% -17%
HR 2% -20% 2% -18% 1% -19%
HU 3% -20% 2% -17% 1% -19%
IT 4% -20% 4% -16% 1% -19%
LT 7% -20% 5% -13% 2% -18%
LV 4% -20% 3% -16% 1% -19%
MT 6% -20% 4% -14% 1% -18%
PL 2% -20% 2% -18% 0% -19%
PT 8% -20% 6% -13% 1% -18%
RO 3% -20% 2% -17% 1% -19%
Source: INSIGHT_E
Figure 17 and 18 further explore the nominal costs and benefits per vulnerable and non-
vulnerable household.
Figure 17: Comparison of annual costs per non-vulnerable household to finance
social tariffs implemented under Option 1(EUR per household per annum)
Source: INSIGHT_E
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Figure 18: Comparison of annual savings per vulnerable household benefiting from
social tariffs implemented under Option 1(EUR per household per annum)
Source: INSIGHT_E
Other costs related to the implementation of this option would be those associated with the
adoption and implementation of deregulation roadmaps in Member States applying price
regulation.
Benefits
This option delivers benefits linked to price deregulation in the form of a more competitive
retail energy market and the associated wider consumer choice of suppliers and energy
service providers and access to a larger variety of products, services and offers, thus
increasing consumer satisfaction, as demonstrated earlier in the present Section, under
subheading 5a.
At the same time the option to provide transitional and targeted price regulation to clearly
defined vulnerable consumer groups would provide the means for achieving the objective
of consumer protection during the period of market adjustment. After the period of
adjustment, transitional price regulation for targeted groups could be replaced by social
policy measures.
Moreover, suppliers would benefit from a level playing field across the EU in terms of a
regulatory environment which would encourage cross-border competition. For suppliers in
Member States applying price regulation, implementation of this option would lead to a
decrease in total costs due to the removal of compliance costs related to setting and
submitting for approval/applying regulated prices as set by the national authorities.
Allowing regulated prices (e. g. in the form of social tariffs) targeted at specific groups of
vulnerable consumers, notably the energy poor, would also contribute to ensuring universal
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access to affordable energy services as required under UN-backed Sustainability
Development goals.
Summary of costs and benefits for Option 1
The table below summarises the costs and benefits associated with the implementation of
Option 1. It reveals that costs of the measure would vary depending on the chosen financing
model, leading to an increase in the electricity tariff of non-eligible customers by 1-15%.
Vulnerable households eligible for social tariff save on average 20% on their annual
electricity bills.
Table 7: Option 1 - Cost and Benefits
Costs Benefits
Measure Description Quantification Description Quantification
Targeted price
regulation for
vulnerable
customers in the
form of social
tariffs.
Social tariffs in place
for a targeted
customer group
(usually less than
20% of the
population)
accompanying the
transition towards
market base prices.
Depending on
the financing
model (the
current
examples are
cost-neutral to
government),
those on the
regular tariff
will see an
increase in
their electricity
tariff by 1-
15%.
Allowing price
regulation exclusively
for clearly defined
vulnerable customer
groups would ensure
that it is a targeted and
transitional measure.
Benefits linked to
price deregulation:
wider consumer
choice, innovation in
the retail energy
market linked to
increased competition,
better quality of
services, increased
consumer satisfaction.
Vulnerable
households save
20% on their
annual electricity
bills.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the
preceding pages, accrue overwhelmingly to households who would qualify for targeted social tariffs and/or
other targeted social support measures i.e. vulnerable and/or energy poor consumers. The biggest losers
from the measures in the preferred option are high-volume, often higher-income consumers who have in
the past benefitted from retail prices that have been set at artificially low levels (see Table 6 and Figures 17
and 18, above). The measures can therefore be considered progressive in nature i.e. they tend to
redistribute surplus from relatively high-income ratepayers to increase the welfare of lower-income
ratepayers.
Nevertheless, it is also important to remember that in Member States where costs of social tariffs are covered
through a tax or a levy on the electricity bill, the social tariff regime places a disproportionately high burden
on low-income consumers who are just above the threshold for qualifying for a social tariff. In contrast,
direct financial support that is financed through income taxation would avoid this and place a higher burden
on those with broader shoulders. For this reason, when it comes to the most effective means of fighting
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energy poverty, well-targeted social policy measures and investments in energy efficiency, rather than social
tariffs, are essential
Option 2a
Option 2a consists of requiring Member States to progressively phase out price regulation
for households above a certain consumption threshold to be defined in new EU legislation
or by Member States, with support from Commission services.
Costs
The main costs associated with the implementation of this option are linked to the financing
of the subsidised energy amount for all beneficiaries of the measure (all households).
For the purpose of this analysis we assumed that all Member States applying price
regulation in the energy markets would deliver 30% of consumption of electricity for all
households at a reduced rate of 20% less than the average regular price163
. This level was
selected based on the current implementation of various social tariff schemes across
Member States, which point towards a reduction in the overall annual bill of 10-30%.
However this scheme applies to all households rather than vulnerable households only.
These values are for illustrative purposes only and the final amount can be varied
depending on the preferences of the Member States implementing the measure.
Under Option 2a the electricity consumption is subsidised for all households for the first
30% and the costs are evenly spread across all consumers.
The impacts on the final consumer bill are presented per Member State in the graphs below
– there is very little impact on the final bill of the households due to the fact that the
discount is available to all households and is also financed by all households.
However, the average final bill would be lower for households consuming less electricity
than the average and higher for households consuming more than the average. Therefore,
this option might incentivise households to lower their energy consumption but it could
also penalise lower income households which use more electricity than the average due to
poor building insulation, lower energy efficient appliances or higher than average people
per household.
163
Eurostat, 2014, Average prices excluding all taxes and levies - based on average consumption
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Figure 19: Option 2a cross-country comparison of average annual electricity costs
per household before and after the introduction of a subsidised amount of electricity
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Bulgaria
before policy
measure
after policy
measure
0
200
400
600
800
1000
1200
1400
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Cyprus
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Denmark
before policy
measure
after policy
measure
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0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Spain
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
France
before policy
measure
after policy
measure
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0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Greece
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Croatia
before policy
measure
after policy
measure
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0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Hungary
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Italy
before policy
measure
after policy
measure
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0
100
200
300
400
500
600
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Lithuania
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Latvia
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Malta
before policy
measure
after policy
measure
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0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Poland
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Portugal
before policy
measure
after policy
measure
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Benefits
In comparison to Option 1 the benefits linked to price deregulation under Option 2a can be
expected to be fewer as a greater share of the retail market is covered by regulated prices
under Option 2a.
However, in comparison to the current situation, if the consumption threshold beyond
which prices are de-regulated was lowered across Member States currently applying price
regulation, the net effect of the measure would be beneficial in terms of introducing more
competition in the retail energy markets.
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Romania
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Slovakia
before policy
measure
after policy
measure
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Comparison between Option 1 and Option 2a
Option 1 specifically targets the support measures for vulnerable consumers, such that the
discounted rate for purchasing electricity is only available to vulnerable consumers. Option
1 also allows greater benefits from the energy market opening in terms of more
competition, more consumer choice, better quality of services and more innovation. On the
contrary, under Option 2a a lower amount of energy will be subsidised but the
subsidy/support will be delivered to all households, regardless of their situation. This
means lower support for vulnerable consumers under Option 2a, as shown in Table 8 which
indicates the total amounts of electricity subsidised for vulnerable consumers under Option
1 and 2a. At the same time Option 2a delivers lower degree of market opening and therefore
lower competition within the market and fewer benefits associated with market
competition.
Table 8: Comparison of residential TWh subsidised in comparison to total
residential TWh consumed
Option 1 Option 2a
Share of
vulnerable
households
Total HH
consumption
Total
electricity
subsidised
for
vulnerable
consumers
Total
electricity
subsidised
-
vulnerable
households
Total
electricity
subsidised non-
vulnerable
households
Total
electricity
subsidised for
all households
TWh TWh TWh TWh TWh
BG 41% 10.6 4.3 1,3 1,9 3.2
CY 28% 1.4 0.4 0,1 0,3 0.4
DK 3% 10.1 0.3 0,1 2,9 3.0
ES 11% 70.7 7.8 2,4 18,8 21.2
FR 6% 149.4 8.8 2,6 42,2 44.8
GR 33% 17.2 5.6 1,7 3,5 5.2
HR 10% 5.6 0.5 0,2 1,5 1.7
HU 12% 10.4 1.2 0,4 2,8 3.1
IT 18% 64.3 11.6 3,5 15,8 19.3
LT 27% 2.7 0.7 0,2 0,6 0.8
LV 17% 1.7 0.3 0,1 0,4 0.5
MT 22% 0.6 0.1 0,0 0,1 0.2
PL 9% 28.0 2.5 0,8 7,6 8.4
PT 28% 11.9 3.4 1,0 2,6 3.6
RO 12% 11.9 1.5 0,4 3,1 3.6
SK 6% 4.9 0.3 0,1 1,4 1.5
EU-16 Totals 13% 401,5 49,4 14,8 120,4 135,2
Source: INSIGHT_E
While the total subsidised energy is much higher in the case of Option 2a, the amount of
energy subsidised for vulnerable customers is lower which indicated a lack of targeting
of the measure.
As regards administrative costs for implementing the measures, the blanket approach (lack
of identification of a targeted group of beneficiaries) used in Option 2a does not require
resources for the identification of vulnerable households. However, these administrative
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costs linked to the identification of vulnerable consumers can be expected to be minimal
as authorities responsible for identifying socially vulnerable groups are already operating
in all Member States.
Finally, a comparison of costs between these two options needs to take into account that,
in the case of Option 1, costs associated with the implementation of social tariffs would be
limited in time due to the temporary nature of the measure, while in the case of Option 2a
there is no foreseen end-date for subsidising a specific amount of energy consumption.
Option 2b
Option 2b consists of requiring Member States to progressively phase out below-cost price
regulation for households by a deadline specified in new EU legislation
Costs
This option allows price regulation defined at levels that cover the costs incurred by the
energy undertakings, therefore no subsidisation is necessary. This option does not involve
financing of any new measure therefore a quantitative estimation of costs cannot be
performed.
Main costs would be linked to the adoption and implementation of roadmaps foreseeing
gradual achievement of cost-reflectiveness of price regulation in the Member States
concerned. The main and key challenge for the implementation of this option would be to
define methodologies for defining cost coverage of energy prices at EU level in a context
where cost structures of market actors are opaque. Moreover, ensuring cost-reflectiveness
by regulation would imply considerable regulatory and administrative impact.
Benefits
The main benefits of this option would be to limit the distortive effect of price regulation
and tackle tariff deficits.
However it is necessary to point to the potential risks associated with energy prices being
regulated below costs, such as the accumulation of tariff deficits.
In a study164
carried out at the request of the European Parliament, a hypothetical case
study shows that in a country where the retail market price for electricity is 0.20 euro per
kWh for domestic customers and the regulated tariff is set at 0.18 euro per kWh, the tariff
deficit would be 0.02 euro per kWh. If there are 15 million domestic customers with an
average annual electricity consumption of 3 000 kWh, of whom 80 per cent are supplied
at the regulated tariff, the result would be a total tariff deficit of 720 million euro per year.
One may compare the size of the country in this hypothetical illustrative case (15 million
domestic customers) with a country of the size of Spain or Poland.
164
"Cost of Non-Europe in the Single Market for Energy" (2013) Institute for European Environmental
Policy at the request of the European Parliament, available at:
http://www.europarl.europa.eu/RegData/etudes/etudes/join/2013/504466/IPOL-
JOIN_ET(2013)504466(SUM01)_EN.pdf
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Figure 20: Tariff deficit
Source: European Parliament165
Regulated end-user prices reflecting actual costs would ensure remuneration for the
suppliers/generators providing them some economic incentives for investment in new and
existing generation capacities and in demand reduction measures.
This option could be implemented by progressively increasing the level of regulated prices
in countries where they are not cost covering with the objective of achieving cost covering
and contestable end user prices. Provided that the level of regulated prices will ensure cost
coverage incurred by the suppliers subject to price regulation plus a reasonable profit
margin, such measure would stimulate the competition on the retail market by encouraging
new entries and allowing existing non-regulated suppliers to gain more market share by
proposing better offers to customers. Such incentives would however be limited, directly
dependent on the profit margin allowed through the chosen methodology.
It can be expected that benefits linked to enhanced competition on the retail market
resulting from the implementation of this option would be more limited compared to
Option 1 or 2a mainly due to the lack of limitation of allowed price regulation (as regards
the scope of beneficiaries or the regulated amount of energy) which would result in a more
important market distortion.
One example of above costs price regulation is through a cost-of-service regulation166
,
under which a company is allowed to charge end customers its total incurred costs
(investment costs plus operation costs), where the investments costs include a fair return
on investment.
This example was studied by Pérez-Arriaga167
who identified that the main advantage of
this type of regulation is that it ensures that customers do not overpay and investors are not
165
"The Cost of Non-Europe in the Single Market for Energy" (2013) European Parliament
166
"Regulation of the Power Sector" (2013) Ignacio J. Pérez-Arriaga
167
"Regulation of the Power Sector" (2013) Ignacio J. Pérez-Arriaga
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undercompensated at any given time. However there are also important risks and
disadvantages linked to such approach, as shown in the table below.
Cost-of-service regulation
Pros Cons/risks
Ensures a fair price at any given time (customers do
not overpay and investors are not
undercompensated)
Ensures regulatory stability
Guarantees cost recovery (via suitable
remuneration), providing a favourable investment
climate, reducing capital costs
Guarantees high levels of security of supply for
electricity customers.
Possible cost inflation due to :
- Information asymmetries: utilities have much
more precise cost and demand data than the
regulator, who needs them in the tariff review
process. Information may therefore be manipulated
by regulated companies to bring in higher revenues
that cannot subsequently be recorded as earnings,
but which can be earmarked for certain cost items
(such as higher salaries or a larger headcount).
- Lack of incentives for efficient management:
keeping costs as low as possible (for a given
amount and quality of service) calls for some effort
from company managers. Under the traditional
system of regulation, managers have no incentive
to make this effort since, if costs grow, revenues are
in principle automatically adjusted to absorb the
difference.
- Regulator capture: utilities usually have a wealth
of resources that can be deployed to influence
regulator decisions in their favour. This undue
influence on regulatory decisions, called
‘‘regulator capture’’, may be exerted in a variety of
ways, including all forms of lobbying,
communication campaigns, regulator hire by the
regulated utilities and vice versa (so-called
revolving doors).
Source: "Regulation of the Power Sector" (2013) Ignacio J. Pérez-Arriaga
It becomes clear that, while this type of price regulation might appear as keeping end
customer prices under control while allowing a fair remuneration for energy utilities, it is
not exempted from risks of abuse by utilities. Therefore, the objective of protecting
customers from possible abuse by utilities in setting the price which is sometimes invoked
as justification for maintaining some form of price regulation does not seem to be fully
ensured by implementing this option.
Subsidiarity
Different national approaches to opening of the market for electricity and gas supply to
households prevent the emergence of a genuine internal energy market for household
customers. More specifically, we observe a wide range of criteria for defining the
beneficiaries of price regulation (consumption threshold, in some cases combined with
vulnerability criteria).
Under the EU acquis (Art. 14 TFEU, Protocol on SGEI), the Commission has assumed the
role of the guardian of both free competition and general interest. The interpretation of the
Treaty by the Court of Justice has in some cases allowed a restriction on competition if
necessary for the accomplishment of special tasks. Moreover, the adopted and proposed
legislation in the field of regulated public services shows how both free competition and
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restrictions on competition can have a place if required for the accomplishment of special
tasks.
The balance between both aspects is subject to the principle of proportionality, implying
that the restriction on competition should be no greater than is required to accomplish the
special tasks. In defining the proportionality principle, EU legislation can specify the scope
of beneficiaries for price regulation (consumption threshold) or the cost coverage
condition.
EU action obliging Member States to progressively adopt less restrictive measures to
achieve the objectives of general interest justifying price regulation is necessary in order
to minimize the negative effect of regulated prices which represent an important barrier to
retail competition, including cross-border. The added value of EU action with respect to
the deregulation of end-user electricity and gas prices has been highlighted by the
European Parliamentary Research Service in a study on "The Cost of Non-Europe in the
Single Market for Energy"168
which considers the possibilities for gains and/or the
realisation of a 'public good' through common action at EU level in specific policy areas
and sectors. This study identifies regulated end-user prices among the areas that are
expected to benefit most from deeper EU integration, where the EU added value is
potentially significant.
Stakeholders' opinions
Public consultation
The outcome of a public consultation carried out by the European Commission from 22
January 2014 to 17 April 2014 has confirmed that market-based customer prices are an
important factor in helping residential customers and SMEs better control their energy
consumption and costs (129 out of 237 respondents considered that it was a very important
factor while other 66 qualified it as important for the achievement of the said objective).
Moreover, out of 121 respondents who considered that the level of competition in retail
energy markets is too little, 45 recognised regulation of customer prices as one of the
underlying drivers.
National Regulatory Authorities
ACER identifies price regulation as one of the barriers to entering retail energy markets,
in particular in Member States where regulated prices are set below cost levels, which
hampers the development of a competitive retail market. It shows that even in other
Member States where end-user prices are set with reference to wholesale prices, which is
the preferred approach, they may negatively impact the customers’ propensity to switch.
Therefore, ACER recommends that, where justified, regulated prices should be set at levels
which avoid stifling the development of a competitive retail market. They must be
consistent with the provisions of the Third Package, and should be removed as soon as a
sufficient level of retail competition is achieved.
168
http://www.europarl.europa.eu/RegData/etudes/etudes/join/2013/504466/IPOL-
JOIN_ET(2013)504466(SUM01)_EN.pdf
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The body representing the EU's national regulatory authorities in Brussels, CEER (
The
Council of European Energy Regulators), identifies as well regulated end-user prices
among the barriers to entry for energy suppliers into retail gas and electricity markets
across the EU. It shows that in the situation where regulated prices are set below cost, or
with a too limited margin to cover the risk of activity, they discourage investments and the
emergence of newcomers.
In their reply to the question “Do you consider regulated end-user prices as a significant
barrier to entry for energy suppliers in your MS and have you taken initiatives to remove
it?” included in a questionnaire169
addressed by CEER to NRAs in 2016, NRAs from
countries with price regulation considered them as a significant barrier to entry for
alternative suppliers. All Member States, where NRAs consider regulated prices as a
significant barrier, are planning to remove them, at least for non-household customers.
In general, NRAs emphasised the need to “facilitate the phasing out of regulated end user
prices, as soon as practicable, whilst ensuring that customers are properly protected
where competition is not yet effective”, as expressed in the conclusions of the ACER /
CEER Bridge to 2025.
As part of a roadmap for phasing-out regulated prices, most of the concerned NRAs state
that regulated prices should first be aligned with supply costs. They also point out the role
of the NRA to define the appropriate methodology and to control end-user prices evolution.
Some NRAs suggest that the final decision for end-user prices withdrawal should depend
on the level of competition in the market, which could be assessed by the NRA, like the
number of market participants and their market share, the transparency of structure and
rules of market functioning, a non-discriminatory treatment on the market.
Eventually, some NRAs note the need to protect vulnerable and low income household
customers.
Suppliers
EUROGAS170
supports the distinction between regulated end-user prices and social
tariffs. It states that specific, time-limited and appropriate regulated end-user prices may
be necessary in circumstances where market forces are not yet in place (in pre-competitive
markets notably to ensure headroom for new entrants and to protect customers from market
abuse). They should then be generally widely available for customers in those Member
States, irrespective of their economic position and should not be set below market price or
below cost, to minimise distortions and barriers to entry. Social tariffs where they exist can
and should also be organized without market distortions. Member States should not be able
to use energy poverty definitions in such a way as to block market development.
169
"Benchmarking report on removing barriers to entry for energy suppliers in EU retail energy markets"
(2016) CEER, available at
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab6/C15-RMF-70-03_BR_barriers_to_entry_for_suppliers_1-Apr-2016.pdf
170
Eurogas press release available at: http://www.eurogas.org/uploads/media/2015-June_-
_15PP282__Eurogas_Position_Paper_on_Vulnerable_Customers.pdf
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In their contribution to the discussions within the workshop on the issue of electricity and
gas price (de)regulation organised by the European Commission in the context of the on-
going work on the future Electricity Market Design on 3 June 2016, EURELECTRIC
agreed that regulated prices represent a barrier to entry to new suppliers and that they
discourage competition on services.
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Customers, the Parliament's Committee on Industry, Research and Energy
(ITRE): " Considers that phasing out regulated energy prices for customers should take
into account the real level of market competition in the Energy Union Strategy context,
which should ensure that customers have access to safe energy prices"
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Customers, the Parliament's Committee on the Internal Market and
Customer Protection (IMCO) " Urges the Commission to take concrete action to better
link wholesale and retail energy markets, so as to better reflect falling wholesale costs in
retail prices and to achieve a gradual phasing-out of regulated prices, and to promote
responsible customer behaviour, by encouraging Member States to seek other means to
prevent energy poverty; recalls that prices set by the market benefit customers; ".
Consumer Groups
In their contribution to the discussions within the workshop on the issue of electricity and
gas price (de)regulation organised by the European Commission in the context of the on-
going work on the future Electricity Market Design, BEUC has argued that price regulation
should be a transitional tool before a certain level of competition is achieved on the retail
market. In any case, it stated that prices should be fixed at contestable levels to allow
alternative suppliers to compete. Moreover, an adequate market design should be the
prerequisite for price deregulation.
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7.3. Creating a level playing field for access to data
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Summary table
Objective: Creating a level playing field for access to data.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding roles and
responsibilities in data handling.
- Define responsibilities in data handling based on appropriate definitions in the
EU legislation.
- Define criteria and set principles in order to ensure the impartiality and non-
discriminatory behaviour of entities involved in data handling, as well as timely
and transparent access to data.
- Ensure that Member States implement a standardised data format at national
level...
- Impose a specific EU data management model (e.g. an
independent central data hub)
- Define specific procedures and roles for the operation of
such model.
Pro
Existing framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
The above measures can be applied independently of the data management model
that each Member State has chosen.
The measures will increase transparency, guarantee non-discriminatory access and
improve competition, while ensuring data protection.
Pro
Possible simplification of models across EU and easier
enforcement of standardized rules.
Con
The current EU framework is too
general when it comes to
responsibilities and principles. It is not
fit for developments which result from
the deployment of smart metering
systems.
Con Con
High adaptation costs for Member States who have already
decided and implementing specific data management models.
Such a measure would disproportionally affect those Member
States that have chosen a different model without necessarily
improving performance.
A specific model would not necessarily fit to all Member
States, where solutions which take into account local
conditions may prove to be more cost-efficient and effective.
Most suitable option(s): Option 1 is the preferred option as it will improve current framework and set principles for transparent and non-discriminatory data access from eligible market
parties. This option is expected to have a high net benefit for service providers and consumers and increase competition in the retail market.
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Description of the baseline
Legal Framework
Annex I (paragraph 1(h)) of the Electricity Directive set some basic requirements regarding
data access from consumers and suppliers, and for the party responsible for data
management. It also provides that data should be shared by explicit agreement and free of
charge.
Article 41 of the Electricity Directive provides that Member States shall be responsible for
setting responsibilities of TSOs, DSOs, suppliers, customers and other market participants
with respect to contractual arrangements, commitments to customers, data exchange and
settlement rules, data ownership and metering responsibility.
Assessment of current situation
Access to consumption data will support the deployment of distributed energy resources
and the development of new flexibility services. This is true not only in relation to
flexibility that system operators may use when planning and operating their networks, but
also to flexibility that will be used in the wholesale markets for achieving wider system
benefits.
Currently different models for the management of data have been developed or are under
development across the EU (e.g. data handled by DSO, TSO, or an Independent Data Hub).
The activity of handling metering data is closely linked to the traditional metering activity.
In the majority of Member States DSOs are responsible for installing and operating the
smart metering infrastructure and they are also responsible for collecting consumption data
and consequently being involved in the handling process of these data. From a European
policy perspective it is important to ensure the impartiality of the entity which handles data
and to ensure uniform rules under which data can be shared.
Table 2 presents the responsible entity in each Member State for the metering activity
(market regulated/non-regulated), and the responsible entity for the roll-out of smart
metering infrastructure, as well as for access to data171
.
171
"Benchmarking smart metering deployment in the EU-27 with a focus on electricity". COM(2014) 356
final
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Table 2: Data handling model in Member States with smart metering systems
(implemented or planned)
Source: COM(2014) 356 final
According to the above data in the majority of Member States the DSO is the responsible
party for metering activity and smart meters, as well as for data access. However, regarding
data access more recent information indicates that some Member States such as Finland
and Sweden are planning a central data hub under the responsibility of the TSO.
In general it is observed, that in countries with a high number of DSOs (e.g. SE, FI) it
seems to be more effective to introduce a central hub which will collect information from
several DSOs and provide access to these data to third parties. In such cases it is expected
that transparency and efficiency in the market will increase, while data will be easily
available to retailers and consumers.
However, different data handling models do not exclude responsibility and involvement of
DSOs, in most of the cases they are responsible for smart meters and participate in the data
handling process. This means that even if they are not assuming a central role in data
handling (e.g. the case of France or Italy), they will collect consumption data and
communicate these data to a central hub.
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Requirements of Article 1(h) of Annex I have been subject to formal actions against several
Member States.
Deficiencies of the current legislation
The Evaluation illustrates how one of the main objectives of the Electricity Directive was
to improve competition through better regulation, unbundling and reducing asymmetric
information. In general, unbundling measures contribute to the contestability of the retail
market and thus facilitate market entry by third party suppliers.
The implementation of smart metering systems in 17 Member States will generate more
granular consumption data and new business opportunities in the retail market. Data
management models for handling those data are accompanied by procedures which
facilitate the retail market and improve processes such as switching, billing, settlements
etc.
The existing provisions of the Electricity Directive provide a general framework under
which each Member State can decide its data management model and procedures of data
handling. This framework however needs to be enhanced and updated in terms for instance
of eligible market parties who should be allowed to access consumers' data, authorization
of parties which handle data, simple procedures and interoperable data format. Indeed,
Section 7.3.6 and Annex IX of the Evaluation show that the current legislation was not
designed to address currently known challenges in managing large, commercially valuable
consumption data flows.
Presentation of the options
Under Option 0 (BAU) Member States are responsible to develop their own data handling
model in line with rules of the Third Package and the related data protection legislation.
Member States are responsible for developing their own data handling models in line with
rules of the Third Package and the related data protection legislation.
A stronger enforcement and/or voluntary cooperation (Option 0+) has not been considered
as the existing EU framework provide only minimum requirements which need to be
updated in line with the developments in the retail market and the introduction of smart
metering systems, while voluntary cooperation would only deliver a set of best practices
that Member States could share, but it would not be adequate for setting the necessary
principle for a transparent and non-discriminatory exchange of data.
Under Option 1 Member States will continue to be responsible for the development of the
data management model; however, more explicit requirements will be introduced
regarding responsibilities in data handling based on appropriate definitions and principles.
Also, criteria and measures will be introduced to ensure the impartiality and non-
discriminatory behaviour of entities involved in data handling, as well as timely and
transparent access to data. Member States will also have to implement a standardised data
format in order to simplify retail market procedures and enhance competition. Measures
under this option will also ensure data protection in line with the requirements of
Regulation (EU) 2016/679 on the protection of personal data and Recommendation
2014/724/EU on the Data Protection Impact Assessment Template for smart grids and
smart metering systems.
Under Option 2 each Member State will have to implement a specific data management
model and procedures described in EU legislation.
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Comparison of the options
a. The extent to which they would achieve the objectives (effectiveness);
The main objective is to ensure that data handling models support equal data access and
facilitate retail market competition.
Option 0 would mean no further measures from the existing framework set in the
Electricity Directive. Member States would be practically completely responsible for
setting the general framework and the detailed regulation on data management models,
access rules and principles, roles and responsibilities of market actors etc.
Data access is highly important for supporting new services and for facilitating
competition, especially where smart metering systems exist. Option 0 would not guarantee
that national frameworks will accommodate all necessary elements in order for instance to
allow data access to a minimum of service providers besides suppliers.
Moreover, the current framework does not include any measures in order to avoid
privileged access to information from service providers which are affiliated to operators
which collect and store data (e.g. DSOs).
Option 1 seeks to address deficiencies of Option 0 by enhancing the existing framework
and set minimum requirements in terms of eligible market parties which should have
access to data, specific principles, and ensuring consumers' privacy. Moreover, this option
will set some minimum safeguards in order to avoid privileged access to data of
commercial value. The level of effectiveness of this option will depend on the specific
implementation in each Member State and the detailed national rules, as measures under
this option will set the basic EU framework.
Option 2 is considered to be less effective compared with the other two options as it will
entail full harmonisation of data management models and rules across EU Member States.
As in many Member States (e.g. UK, IT, FR, FI, NL, AT etc.) the data management models
have been already implemented or planned, the imposition of a different model (e.g.
independent data hub), would entail a restructuring of the existing models.
The above policy options were developed in the context of the Digital Single Market172
and the Energy Union which include the strong and efficient protection of fundamental
rights in a developing digital environment. One of the objectives should be to ensure
widespread access and use of digital technologies while at the same time guaranteeing a
high level of the right to private life and to the protection of personal data as enshrined in
Articles 7 and 8 of the Charter of Fundamental Rights of the EU.
The policy options proposed (from compliance with data protection legislation and the
Third Package - Option 0; to further introduction of specific requirements on data handling
172
In the context of the Digital Single Market the Commission will propose a European free flow of data
initiative with the aim to promote free movement of data in the European Union. The initiative will
tackle restrictions to data location and access to encourage innovation. The Commission will also launch
a European Cloud initiative, covering certification, switching of cloud service providers and a research
cloud (https://ec.europa.eu/digital-single-market/en/economy-society-digital-single-market).
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responsibilities based on principles of transparency and non-discrimination - Option 1; and
implementation of a specific data management model to be described in EU legislation -
Option 2) seek to ensure the impartiality of the entity which handles data and to ensure
uniform rules under which data can be shared. Access to a consumer's metering or billing
details can only happen when authorised by that consumer and under the condition that the
personal data protection and privacy are guaranteed.
The policy options are fully aligned and further substantiate the fundamental rights to
privacy and protection of personal data of Articles 7 and 8 of the Charter of Fundamental
Rights of the EU, as well as with the General Data Protection Regulation (EU Regulation
2016/679 modifying Directive 95/46/EC) and with Commission Recommendation
2014/724/EC on the Data Protection Impact Assessment Template for Smart Grid and
Smart Metering Environments.
b. Key economic impacts and benefit/cost ratio, cost-effectiveness (efficiency) &
Economic impacts
Option 1 is expected to yield higher net benefits in comparison with option 0, as it will set
principles for an open and more competitive retail market. Moreover, specific procedures
of the market such as switching are expected to improve with stricter requirements on the
data format.
An overall positive effect on the energy market can be expected. Active and well-aware
consumers are more likely to make informed decisions, from choosing their energy
supplier to consumption decisions. More consumers might switch their supplier, which
will foster competition in the retail market. Active consumers might also consider third
party services such as applications to reduce or optimise their energy consumption, which
would amplify the market for third party activities. Different initiatives and business
models could simplify the interaction between consumers and third parties, and therewith
further increase the market potential of third party services173
.
Moreover, direct feedback for example on real time consumption data and energy prices,
could have a substantial impact on energy savings. Evidence from Ireland and the UK
show that energy savings can reach up to 2.5% and 8.8% in peak hours174
.
A main benefit of ensuring interoperability between different data systems is the easy
access to new markets for commercial actors such as energy suppliers or aggregators.
Ensuring for instance uniform formats for consumption data reduces entry barriers for
commercial actors seeking to establish in other Member States. This could enhance
competition in the supplier and aggregator market. Ensuring interoperability would imply
173
Like for instance the Green Button initiative in US where consumers can easily give access to their
consumption data to third parties who automatically receive a standardized data-package for that
consumer; the initiative positively affected the overall business case of third parties ("Green Button:
One Year Later" (2012) IEE Edison Foundation). Another example of such initiative is the Midata
initiative in UK (http://www.gocompare.com/money/midata/) which concerns energy and other sectors;
as energy firms are increasingly taking on board the need to provide customers with downloadable data
to better understand their gas and electricity usage, Midata initiative aims to further encourage this
practice across all energy suppliers and to make it easier to upload this data to comparison sites.
174
Intelligent Energy Europe (2012): "European Smart Metering Landscape Report 2012"; Ofgem (2011):
"Energy Demand Research Project: Final Analysis" (study conducted by AECOM for Ofgem).
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agreeing to a common standard at national level, which would induce some costs such as
administrative costs for defining and concurring on the new format, especially to data
administrators (DSOs or data hubs) who will have to adapt their system to a new common
format. Depending on the case such costs might be significant, as a number of existing data
handling systems and the involved entities would have to adjust to the new standards
(suppliers, DSOs, third parties, data administrators). However, it is expected that on an
aggregated level these costs will not exceed benefits.
The implementation of Option 2 would entail high administrative costs. Determining a
mandatory data handling model will imply administrative costs of defining and designing
such a model, and more importantly high sunk costs for existing data handling models and
additional costs for establishing a new one, both in terms of personnel costs and IT
infrastructure. Designing and building a new data handling model is a complex procedure
and may well take several years of planning and implementation. In Denmark, the central
data hub took more than 4 years to design and develop in its simple form, and 7 years in
its enhanced form, and is estimated to a cost of approximately 165 million euros, where
approximately 65 million euros accrued to the data hub administrator (the TSO), and
around 100 million euros accrued to DSOs and energy suppliers. Therefore, the costs of
redesigning already implemented data handling models across the EU are therefore likely
to be substantial.
c. Simplification and/or administrative impact for companies and consumers
Option 2 for data management would result in high administrative costs affecting existing
structures as well as possibly energy companies and consumers.
d. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
e. Trade-offs and synergies associated with each option with other foreseen measures
Options 1 and 2 for data management are clearly also associated with demand response
and smart metering. Smart meters will provide granular data which should be accessible
from service providers for settlement or support of services. A well-functioning data
management model is therefore crucial for the provision of demand response services.
f. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
g. Which Option is preferred and why
Option 1 is the preferred option as it will improve current framework and set principles
for transparent and non-discriminatory data access from eligible market parties. This
option is expected to have a high net benefit for service providers and consumers and
increase competition in the retail market.
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Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the preceding
pages, accrue evenly to all consumers. The measures can therefore be considered neutral in nature i.e. they
do not redistribute surplus between higher- and lower-income ratepayers.
Subsidiarity
The EU has a shared competence with Member States in the field of energy pursuant to
Article 4(1) of the Treaty on the Functioning of the European Union (TFEU). In line with
Article 194 of the TFEU, the EU is competent to establish measures to ensure the
functioning of the energy market, ensure security of supply and promote energy efficiency.
Uncoordinated, fragmented national policies in the electricity sector may have direct
negative effects on neighbouring Member States, and distort the internal market. EU action
therefore has significant added value by ensuring a coherent approach in all Member
States.
An effective EU framework for data management which puts in place rules and principles
will give to electricity consumers more choices, better access to information and will
facilitate competition in the electricity market. Moreover, through effective data
management models and efficient procedures consumers will have access to more energy
service providers and actively participate in the electricity market. Active participation of
consumers and facilitation of demand response and energy efficiency service will
contribute to the completion of the internal energy market and support security of supply.
Envisaged measures do not aim to alter the structure of existing or planned national data
management models, but to set requirements which will enhance fundamental consumer
rights and support a competitive internal energy market.
Stakeholders' opinions
3.2.7.1. Results of the consultation on the new Energy Market Design
According to the results of the public consultation on a new Energy Market Design175
the
respondents view active distribution system operation, neutral market facilitation and data
hub management as possible functions for DSOs. Some stakeholders pointed at a potential
conflict of interests for DSOs in their new role in case they are also active in the supply
business and emphasized that the neutrality of DSOs should be ensured. A large number
of the stakeholders stressed the importance of data protection and privacy, and consumer's
ownership of data. Furthermore, a high number of respondents stressed the need of specific
rules regarding access to data.
Governance rules for DSOs and Models of data handling
Question: "How should governance rules for distribution system operators and access to
metering data be adapted (data handling and ensuring data privacy etc.) in light of market
and technological developments? Are additional provisions on management of and access
by the relevant parties (end-customers, distribution system operators, transmission system
175
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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operators, suppliers, third party service providers and regulators) to the metering data
required?"
Summary of findings:
The majority of stakeholders consider access to data by consumers and relevant third
parties under specific rules as an important element for the development of an open and
competitive retail market. Moreover, it is crucial to ensure data privacy and ownership of
data by consumers.
Regarding the data handling models, regulators and the majority of stakeholders from the
electricity industry believe that DSOs should act as neutral market facilitator. Some
stakeholders from the electricity industry suggest that the DSOs should undertake the role
of the data hub, providing an effective way to govern the data generated by smart meters.
On the other hand, IFIEC and few other stakeholders do not see favourably the role of
DSOs as market facilitator, the involvement of a third party is perceived to better support
neutrality and a level playing field.
National governments are divided on the best suitable model for data access and data
handling, around half of them advocate as the most favourable solution central data hubs.
Most of the Member States consider that the role of DSO and the model for data handling
should be best decided at national level.
Member States:
Given the central role of DSOs in metering and handling of data, Member States point out
the necessity for neutrality and independence of the DSO vis-à-vis other energy
stakeholders, while they consider that coordination between DSOs and TSOs should be
enhanced. Data need to be accessible in real-time or close to real-time for consumers and
relevant third parties, while data security and privacy is one of the most important aspects
for the acceptance of smart meters and the successful roll-out.
Some Member States promote central data hubs to collect and handle data (e.g. Denmark,
Estonia, Finland, Germany, Slovakia, and Sweden).
Some Member States (Czech Republic, France, Netherlands, and Slovakia) believe that
due to different local conditions in terms of available technologies and national regulatory
frameworks, detailed arrangements regarding data handling should be defined at member
State level through national legislation, and no further legislation is required at EU level
regarding the role of DSOs and the responsibilities for data handling.
On the other hand the Danish government considers that EU regulation should more
specifically define a minimum level of privacy and issues such as consumers' control over
their own data and non-discriminatory access to data by market players, while harmonising
the roles of market players and the kind of data they have access to. The Finnish
government also calls for a clarification of the role of DSOs in the operation of storage
facilities and questions whether there is a need to revise unbundling rules.
Regulators:
Regulators stress the importance of neutrality in the role of the DSOs as market facilitators.
To achieve this will require to:
- Set out exactly what a neutral market facilitator entails;
- When a DSO should be involved in an activity and when it should not;
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- NRAs to provide careful governance, with a focus on driving a convergent
approach across Europe.
Regulators consider that consumers must be guaranteed the ownership and control of their
data. The DSOs, or other data handlers, must ensure the protection of consumers’ data.
Electricity consumers:
The majority of stakeholders (BEUC, CEFIC, CEPI) agree that consumers should have
access to real time information, historical information, accurate billing and easy switch of
provider. Some of them (CEFIC, EURACOAL) believe that the DSOs should play a
central role in providing end-users with the necessary information. All electricity consumer
stakeholders agree that data protection must be assured.
IFIEC considers that DSOs should not play the role of market facilitator, the involvement
of a third party is perceived to better support neutrality and a level playing field. Moreover,
coordination of TSOs and DSOs and potentially extended role of DSOs with respect to
congestion management, forecasting, balancing, etc. would require a separate regulatory
framework. However, IFIEC express concerns that some smaller DSOs might be
overstrained by this. Extended roles for DSO should be in the interest of consumers and
only be implemented when it is economically efficient.
EUROCHAMBERS believes that due to different regional and local conditions a one size
fits all approach for governance rules for distribution system operators is not appropriate.
The EU could support Member States by developing guidelines (e.g. on grid infrastructures
and incentive systems).
Energy industry:
Most stakeholders (CEDEC, EDSO, ESMIG, ETP, EUROBAT, EWEA, GEODE) believe
that the role of DSOs should focus on active grid management and neutral market
facilitation. Some respondents state that the current regulatory framework prevents DSOs
from taking on some roles, such as procurer of system flexibility services and to procure
balancing services from third parties, and such barriers should be eliminated.
All stakeholders agree that the provision of data management services should be carried
out in a neutral and non-discriminatory manner with all appropriate protections for data
security, data privacy and the right of the consumers to control third party access to their
data. On this regard, GEODE highlights the need to have a clear distinction between
personal data (which belongs to the customer) and non-personal data which should be
provided to any relevant party who requests it, on a non-discriminatory basis.
According to Eurelectric, EWEA, ETP and GEODE, DSOs operating as data hub could
provide an effective way to govern the data generated by smart meters.
Eureletric believes that the need for guaranteeing security of information and preventing
cyber-attacks could also be better ensured when there is only one entity in charge of
managing information flow. Mindful of the different unbundling situations in place in the
EU, DSOs should be responsible for data handling up to the metering point in a fully
unbundled context. Moreover, regulatory authorities should make sure that data
management beyond the meter takes place in a condition that ensures customer privacy
and it should be up to the consumers whether to receive their data through an intermediary
(a market party) or retrieve it from a web platform linked to the data hub. Costs connected
with data management should be recovered via network tariffs.
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According to RGI, for privacy reasons most data should remain in the meter itself. Data
should be stored in and regulated by a public server in an aggregated and formatted way
only dealing with the strictly necessary information. TSOs should have access to relevant
data, reflecting the actual energy portfolio and installed capacity per source at any given
time.
Also SEDC envisages that DSOs should be neutral market facilitators where unbundling
is fully implemented. However, in this scenario DSOs should not be active in markets such
as for demand response, as this would undermine their neutrality.
In relation to a possible EU intervention on the topic, GEODE suggests that Commission
should lay down generic principles rather than specific provisions, taking into account that
different Member States implement different models on the treatment of smart metering
data.
3.2.7.2. Public consultation on the Retail Energy Market
According to the results of the 2014 public consultation on the Retail Energy Market176
the
majority of the respondents consider that DSOs should carry out tasks such as data
management, balancing of the local grid, including distributed generation and demand
response, and connection of new generation/capacity (e.g. solar panels).
81% of the respondents agreed that allowing other parties to have access to consumption
data in an appropriate and secure manner, subject to the consumer's explicit agreement, is
a key enabler for the development of new energy services for consumers.
3.2.7.3. Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31st
EU Electricity Regulatory Forum:
- "The Forum supports the cooperation of TSOs and DSOs on data management,
considering it an important step in finding common solutions to system operation
and system planning. It acknowledges the need to identify at EU-level a set of
common principles, roles, responsibilities and tasks concerning data management,
which will enable the development of new services and the active participation of
consumers in the future energy system while ensuring data protection and leaving
room for implementation at national level."
European Parliament resolution of 26 May 2016 on delivering a new deal for energy
consumers (2015/2323(INI)):
"29. Believes that consumers should have easy and timely access to their consumption
data and related costs, to help them make informed decisions; notes that only 16 Member
States have committed to a large-scale roll-out of smart meters by 2020; believes that
where smart meters are rolled out Member States should ensure a solid legal framework
to guarantee an end to unjustified back-billing and a rollout that is efficient and
affordable for all consumers, particularly for energy-poor consumers; insists that the
176
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
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benefits from smart meters should be shared on a fair basis between grid operators and
users;"
"33. Underlines that the collection, processing and storage of citizens’ energy-related
data should be managed by entities managing data access in a non-discriminatory
manner and should comply with the existing EU privacy and data protection framework
which lays down that consumers should always remain in control of their personal data
and that these should only be provided to third parties with the consumers’ explicit
consent; considers, in addition, that citizens should be able to exercise their rights to
correct and erase personal data;"
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7.4. Facilitating supplier switching
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Summary table
Objective: Facilitating supplier switching by limiting the scope of switching and exit fees, and making them more visible and easier to understand in the event that they are used.
Option 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Stronger enforcement, following the
clarification of certain concrete requirements
in the current legislation through an
interpretative note.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers, apart from: 1) exit fees
for fixed-term supply contracts; 2) fees
associated with energy efficiency or other
bundled energy services or investments. For
both exceptions, exit fees must be cost-
reflective.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers.
Pros:
- Evidence may suggest a degree of non-
enforcement of existing legislation by
national authorities.
- No new legislative intervention necessary.
Pros:
- Non-enforcement may be due to complex
existing legislation.
- No new legislative intervention necessary.
Pros:
- Considerably reduces the prevalence of
fees associated with switching suppliers, and
hence financial/psychological barriers to
switching.
Pros:
- Completely eliminates one
financial/psychological barrier to switching.
- Simple measure removes doubt amongst
consumers.
- The clearest, most enforceable requirement
without exceptions.
Cons:
- Continued ambiguity in existing legislation
may impede enforcement.
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
Cons:
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
- Certain Member States might ignore the
interpretative note.
Cons:
- Marginally reduces the range of contracts
available to consumers, thereby limiting
innovation.
- An element of interpretation remains
around exceptions to the ban on fees
associated with switching suppliers.
Cons:
- Would further restrict innovation and
consumer choice, notably regarding
financing options for beneficial investments
in energy equipment as part of innovative
supply products e.g. self-generation, energy
efficiency, etc.
- Impedes the EU's decarbonisation
objectives, albeit marginally.
Most suitable option(s): Option 1 is the preferred option, as it represents the most favourable balance between probable benefits and costs.
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Description of the baseline
The evidence presented in this annex draws extensively on survey data, as well as data
from a mystery shopping exercise. The aim of the mystery shopping exercise was to
replicate, as closely as possible, real consumers’ experiences across 10 Member States177
selected to cover North, West, South and East Europe countries. A total of 4,000
evaluations were completed between 11 December 2014 and 18 March 2015178
. Whilst
data from the mystery shopping exercise is non-exhaustive, the methodology enables the
controlled sampling of a very large topic area179
, as well as providing insights that would
not be apparent in a desktop evaluation of legislation and contractual terms. Using a
behavioural research approach rather than a traditional survey allowed us to identify what
people actually do, rather than what they say they do.
Switching rates180
for energy – a proxy for consumer engagement in the market – vary
considerably between Member States (0-15%), with electricity and gas comparing
unfavourably with many other consumer sectors such as vehicle insurance and mobile
telephony.
Figure 1: Switching provider by market - EU28
Source: Market Monitoring Survey, 2015
177
The Czech Republic, France, Germany, Italy, Lithuania, Poland, Slovenia, Spain, Sweden and the UK.
178
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
179
For example, there were over 400 electricity and gas supply offers in Berlin alone in 2014 (source:
ACER Database), making a comprehensive examination of all supply offers in the EU28 impracticable.
180
The percentage of consumers changing suppliers in any given year.
7%
8%
9%
9%
9%
9%
10%
10%
10%
13%
14%
15%
16%
16%
11%
+2.2*
+0.6
+1.0*
+2.3*
-0.6
+1.3*
+1.3*
+1.6*
+2.4*
+1.6*
+2.2*
+3.1*
+3.8*
+2.6*
+1.8*
-0.3
+0.2
+1.2*
-0.8*
-0.3
-0.4
-0.2
-0.7*
-0.4
+0.1
-0.7
+0.1
-0.4
-1.4*
-0.3*
-1.2*
+0.4
-0.9*
-2.2*
-0.6
-0.3
+0.1
-0.5
-0.2
-0.1
-0.2
0.0
-0.5
+1.0*
-0.4*
-0.6
+0.3
+0.2
+0.2
+1.8*
+0.2
-3.6*
+0.6
+1.3*
+0.5
-0.5*
Mortgages
Home insurance
Gas services
TV-subscriptions
Bank accounts
Private life insurance
Loans, credit and credit cards
Fixed telephone services
Electricity services
Internet provision
Investment products, private pensions and securities
Mobile telephone services
Commercial sport services
Vehicle insurance
Switching markets
Yes
Switching provider by market - EU28
Have you switched your <provider>? Diff
2015-
2013
Diff
2013-
2012
Diff
2012-
2011
Diff
2011-
2010
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Figure 2: Factors preventing electricity and gas consumers from switching – 2014 (1
– not at all important)
Source: ACER Questionnaire, February–April 2015
Consumer associations and NRAs report that insufficient monetary gain is the prime
obstacle to switching (Figure 2 above). An ACER questionnaire suggests that the perceived
minimum annual savings required by electricity consumers to switch in Belgium,
Germany, Italy, Latvia, Poland and Slovenia lie in the range of 0–100 euros, whilst in the
United Kingdom, the Netherlands, Portugal and Sweden, this was estimated be 100–200
euros. The switching trigger ranges were the same for gas consumers, with the exception
of Italy, where switching trigger is estimated to be in the range of 100–200 euros.
Given that the difference in price between most offers in the market lie within comparable
ranges to switching triggers (Figure 3 below), switching suppliers is a marginal decision
for many household consumers. This highlights the importance of the broad variety of fees
that consumers may be charged when they switch, as these diminish the (perceived)
financial gains of moving to a cheaper tariff in what is already a marginal decision for
many consumers.
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Figure 3: Dispersion in the energy component of retail prices for households in
capitals – December 2014
Source: ACER Retail Database (November–December 2014) and ACER calculations
Whilst the data indicates that switching is free for most EU consumers, a minority still face
switching-related charges. First of all, exit (termination) fees may apply when leaving a
fixed-term or fixed-price contract early181
. The legitimacy of such fees are acknowledged
in EU legislation (see Section 7.4.3 below), and they are often put in place to recoup the
costs of equipment, discounts and/or other incentives provided at the beginning of the
contract. A mystery shopping exercise in ten Member States revealed that whilst 77% of
electricity suppliers stated that consumers would face no charges for switching, 17% were
warned that they may be charged an exit fee (Table 1), a figure corroborated by ACER
data suggesting that exit fees are still common in at least 11 Member States for electricity
and 3 Member States for gas (Figure 4).
181
As sometimes occurs in Member States including NL and UK.
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Table 1: Electricity providers’ response when asked if there are any charges when
switching electricity provider
CZ DE ES FR UK IT LT PL SE SI Total
You will not be
charged for the change
60% 94% 83% 89% 59% 86% 80% 67% 66% 80% 77%
A fee for cancelling
your current energy
deal (e.g. exit fee for
fixed rates)
40% 5% 11% 5% 38% 1% 0% 28% 32% 14% 17%
Another extra charge 0% 0% 7% 4% 3% 11% 8% 4% 2% 2% 4%
No response 0% 1% 0% 1% 0% 1% 12% 1% 0% 4% 2%
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
Figure 4: Existence of exit fees imposed by suppliers when switching offers - 2014
Aside from exit fees, however, the same mystery shopping exercise revealed that 4% of
mystery shoppers were told they may be charged other fees related to switching, including
administrative costs, start-up costs for a new or short-term service, or security deposits
(Box 1 below). This finding is notable because EU legislation ensures that consumers "are
not charged for changing supplier"182
. As checks by the Commission indicate that this
legislation has been correctly transposed into Member State law, the finding suggests either
legal failures in the EU legislative text that prevent it from fulfilling its intention and/or
non-enforcement by national authorities.
182
This reading was recently supported by the body representing the EU's national regulatory authorities –
the Council of European Energy Regulators – who write: "The 3rd Energy Package Directives clearly
state that switching should be completely free for the customer." "Position on early termination fees"
(2016) CEER, Ref: C16-CEM-90-06.
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Box 1: Examples of “extra charges” when switching mentioned by electricity
providers (when being contacted by phone)
- Administration cost (EUR 35) – France
- A service fee (EUR 27.90) – France
- A fee for starting up the service (EUR 27.16) – France
- An administration cost added on the first electricity bill (EUR 27.59) – Italy
- An activation fee – Italy, Poland
- An extra charge of EUR 20.54 on the first bill; no explanation was provided for this charge – Italy
- A security deposit (EUR 70) – Italy
- A deposit (EUR 77) – Italy
- A fee for contracts of less than one year – Spain
- A yearly charge of 300 SEK/year (or 25 SEK/month) for each new contract – Sweden
Source: "Second Consumer Market Study on the functioning of retail electricity markets
for consumers in the EU" (2016) European Commission
In total, therefore, the results from these ten representative Member States suggest that
around one fifth of electricity consumers in the EU would face some sort of fee associated
with switching suppliers. As for the magnitude of switching-related charges, Figure 5
under indicates that average exit fees fall between 5 and 90 euros, depending on the capital
city sampled. Electricity and gas consumers on fixed-price and fixed-term contracts in
Amsterdam were the most affected by exit fees, and these could significantly reduce their
saving potential from 16% (without exit fees) to 6% (with first-year exit fees included)
with respect to the average incumbent standard offer for electricity consumers, and from
13% to 6% with respect to the average gas standard incumbent price. Exit fees could also
considerably reduce potential savings for electricity consumers in Ljubljana, Dublin,
Copenhagen, London and Warsaw.
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Figure 5: Potential effect of exit fees on annual savings to be made from switching
away from the incumbent in Europe - 2014 (% and euros)183
Source: ACER.
While the possibility of charging exit fees may provide suppliers with more flexibility in
the tariffs they are able to offer, they make comparisons more difficult for consumers and
reduce the incentive for switching. Furthermore, behavioural economic theory suggests
that all fees associated with switching can disproportionately discourage consumer action
because of a decision making bias called 'loss aversion' – a tendency to strongly prefer
avoiding losses (one-time switching fees) to acquiring gains (the long-term savings of
moving to a cheaper tariff)184
. This means the reduced incentives presented in Figure 5 will
appear much more significant in the eyes of most household consumers – twice as large if
findings from benchmark behavioural studies carry over into this real-world context185
. As
a result, three Member States (Belgium, France and Italy) have outlawed altogether
contract exit fees for household consumers in the energy sector.
183
Calculated on the basis of offer data for capital cities from the ACER Retail Database and the
information from the consumer organisations. For those countries where standard offers are variable and
where consumers typically incur exit fees while on fixed-term, fixed-price contracts, the above figure
should be considered illustrative. ‘Net’ savings equal the difference between the incumbent price and
the lowest offer, minus average exit fees typically imposed on fixed-term offers (i.e. savings for
consumers after exit fees have been paid for). ‘Gross’ savings equal the difference between the
incumbent price and the lowest offer. The data presented include information from the questionnaire
(i.e. an assessment of the existence and the level of exit fees in Member States and the information
collected on the basis of offer data in the ACER database to show the potential effect of exit fees in those
MSs where these exist. The exit fees shown in the above figure are the averages of all exit fees incurred
by consumers breaking away from contracts in the first year, and might be higher than those incurred
when breaking away in the 2nd or 3rd year. In the case of electricity offers in Oslo and Warsaw, exit
fees are estimated at 5% of the final standard offer.
184
"Choices, Values and Frames" (1984) Kahneman, D., and A. Tversky, American Psychologist, 39, 341-
350.
185
“Loss Aversion in Riskless Choice: A Reference-Dependent Model” (1991) Tversky, A., and D.
Kahneman, Quarterly Journal of Economics, 106 (4), 1039–1061.
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Box 2: Switching energy suppliers in Belgium
As from 13 September 2012, the Belgian Electricity Act was amended (see Article 18, Section 2 and 3 of the
Electricity Act) and suppliers were no longer permitted to charge households and SMEs (non-residential
users with a maximum annual usage of 100,000 kWh in natural gas and 50,000 kWh in electricity) a fee for
the early termination of a contract, provided that a one-month notice period is observed.
The abolition of early termination, or exit fees seems to have had a positive impact on the market with regard
to the number of users switching to a different electricity and gas provider. Switching jumped markedly in
all Belgian regions for bot electricity and gas around the time of the legislative change. This has led NEON
– the Europe-wide network of energy ombudsmen and mediation services – to suggest that the ban on
switching fees may have been to credit for this.
The Belgian Ombudsman also found that the number of complaints with regard to switching providers has
significantly fallen since the amendment of the act on 25 August 2012, from 14% (1,854 complaints) in 2014
to 8% in 2012 (1,250 complaints), 3% in 2013 (347 complaints) and 3.5% in 2014 (318 complaints).
Source: NEON, The National energy Ombudsman Network
One final factor to take into account is a high level of uncertainty amongst consumers over
whether they could be charged for switching – a fact that may be discouraging many from
looking into the possibility of switching because of the perceived complexity of it. Whereas
the evidence suggests only around 20% of consumers in the EU would actually face some
sort of fee associated with switching suppliers, 39% of consumers surveyed186
did not
know whether or not they would be charged. This does not include 17% that responded
with certainty that they could be charged a fee for switching.
186
29,119 interviews were conducted across 30 countries (EU28, Iceland and Norway). "Second Consumer
Market Study on the functioning of retail electricity markets for consumers in the EU" (2016) European
Commission.
2011 2012 2013 2014
Brussel - elektriciteit 4,1% 8,3% 14,3% 9,6%
Vlaanderen - elektriciteit 8,2% 16,5% 15,4% 11,9%
Wallonië - elektriciteit 8,6% 11,6% 13,6% 12,7%
Brussel - aardgas 4,7% 9,3% 18,3% 10,5%
Vlaanderen - aardgas 9,2% 18,9% 18,7% 13,9%
Wallonië - aardgas 11,0% 15,0% 21,2% 15,9%
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Figure 6: Knowledge of switching rules – no charge when changing electricity
company, by country187
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
A lack of information relevant to switching in bills is one explanation for this. Whereas
customers in the majority of Member States are currently provided with information on the
consumption period, actual and/or estimated consumption, and a breakdown of the price,
there is a greater diversity of national practices with regards to other information, including
switching information, and the duration of the contract188
.
Another explanation is incomplete information from suppliers themselves. Table 2 below
shows that mystery shoppers in ten representative Member States were often unable to find
any information on switching rules whatsoever on electricity companies’ websites.
187
Question: "The following are statements regarding consumer rights in the energy sector. Please indicate
whether each statement is true or false: "If you decide to change your electricity company, you will not
be charged for the change“".
188
For more details, see the Thematic Evaluation on Metering and Billing.
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Table 2: Switching rules found on electricity companies’ websites189
SI DE UK FR PL CZ IT LT SE ES Total
50 100 75 75 100 50 75 50 50 75 700
You will not be charged for the change 82% 57% 21% 52% 50% 36% 45% 30% 10% 24% 42%
The new provider must make the change within
three weeks (or less), provided you respect the
terms and conditions of the original contract
10% 13% 26% 13% 6% 8% 1% 10% 12% 3% 10%
Within six weeks (or less) after you switch, you
should receive the final closure account from
your previous provider
10% 11% 24% 4% 7% 2% 0% 2% 2% 4% 7%
It might be that you'll incur a fee for cancelling
your current energy deal
10% 5% 17% 0% 6% 8% 1% 0% 16% 5% 7%
None of the above 14% 38% 42% 43% 47% 52% 54% 66% 66% 69% 49%
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
High uncertainty levels indicate that the current prevalence of switching-related charges
may be having a much broader impact on switching rates than would be expected if only
consumers directly affected by such charges were considered. Whereas only 3% of survey
respondents stated that one of the main reasons they had not tried to switch was that they
would incur an exit fee from their electricity company, 16% stated that the savings would
not justify the trouble linked to changing electricity companies, 14% that it is difficult to
compare offers, and 12% that they perceive switching as being too complicated – each a
response that could have been influenced by the uncertain prospect of switching-related
charges.
Figure 7: Main reasons for not trying to switch electricity company190
Q32. What are the main reasons for not trying to switch your electricity company? (up to three responses)
%, EU28, Base: Those who have not switched electricity company in the last three years (Q27 code 2)
Question not a ed in Cyprus, Latvia and Cypru
42%
24%
23%
16%
14%
12%
12%
7%
5%
5%
4%
3%
2%
1%
6%
You are satisfied with your current electricity company
No difference between providers to make switching worthwhile
You never thought about the issue
Savings don't justify the trouble of changing provider
It is difficult to compare offers of different electricity companies
Switching is complicated
You dislike/distrust alternative electricity companies
There is no alternative local electricity company
You cannot find information on how to switch
You did not know that you can switch
Due to the length of the switching process
You will incur exit fees from your current electricity company
Other electricity companies are not as environmentally-friendly
In debt with current electricity company, so you you can't switch
Other reason specified
Main reasons for not trying to switch electricity company
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
Given the persistently low levels of switching and consumer engagement in the energy
sector (Figure 1), there may therefore be scope to further restrict the use of fees charged to
consumers for changing suppliers. This would remove a key monetary barrier to greater
consumer engagement. It would make it easier for consumers to control their bills and
harder for suppliers to lock consumers into disadvantageous contracts. Such action would
therefore be consistent with other provisions in the Electricity and Gas Directives which
189
Question: "Which of the following statements about the switching process were found on the website?
(multiple answers allowed)".
190
Question: "What are the main reasons for not trying to switch your electricity company? (up to three
responses)".
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state: “Member States shall ensure that the eligible customer is in fact easily able to switch
to a new supplier”.
Without intervention, switching-related fees in the range of 5 to 90 euros would likely
continue to affect an estimated 20% of electricity consumers in the EU, with uncertainty
over their applicability influencing the decision-making of well over half of all EU
electricity consumers. A lack of action to limit these fees would amount to ignoring a key
barrier to consumer engagement.
Although there is less evidence on switching-related fees in the gas sector, Figures 4 and
5 suggest they are prevalent in fewer Member States, and that their magnitude is similar.
Deficiencies of the current legislation
The consumer protection provisions in the Electricity and Gas Directives regulate
switching fees. Largely unchanged since their 2001/2003 introduction, these provisions
state that “customers are not to be charged for changing supplier”.
The following text regarding contract exit fees was added in 2007: contracts must specify
“whether withdrawal from the contract without charge is permitted”. It weakened the initial
provision by affirming the permissibility of certain switching-related charges without
explicitly addressing whether the legislation addressed all switching-related charges in
categorically exhaustive manner.
As addressed in Section 7.1.1 and Annex IV of the Evaluation, the current framework
therefore remains both complex and open to interpretation with regard to the nature and
scope of certain key obligations.
Presentation of the options
Option 0: Stronger enforcement
Stronger enforcement to tackle the switching fees currently imposed contrary to EU legal
requirements.
Option 0+: Clarifying certain concrete requirements in the current legislation through an
interpretative note, coupled with stronger enforcement
This option involves making it explicit that the existing Third Package provision stating
that consumers "are not charged for changing supplier" applies to contract switching fees.
This would seek to remove any legal uncertainty and improve Member State compliance.
Option 1: Legislation to outlaw the use of switching fees and to limit the use of exit fees
in electricity and gas supply contracts in the EU
In concrete terms, the preferred measures will include the following:
i. Define switching fees and contract exit fees in the legislation.
ii. Ban all switching fees, and ban exit fees in open-ended supply contracts and
fixed term contracts that have come to the end of the agreed term.
iii. For fixed-term contracts, permit exit fees if the contract has not ended, but
ensure the cost-reflectiveness and proportionality of these fees to avoid undue
consumer detriment. Clarify that consumers should always have the possibility to
exit the contract, if they are prepared to pay the exit fee.
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iv. Define exceptions to accommodate certain on-bill repayment of upfront
investments in, inter alia, energy efficiency financed by suppliers or energy service
providers.
v. Introduce transparency provisions so that fees are presented in an easily
understandable manner (e.g. amortisation schedule) in contracts and pre-
contractual information.
vi. Clarify that commercial and industrial supply contracts would not be affected.
Option 2: Legislation to categorically outlaw the use of all switching and exit fees in
electricity and gas supply contracts to EU household consumers
In concrete terms, the preferred measures will include the following:
i. Define switching fees and contract exit fees in the legislation.
ii. Ban all fees defined in i).
Comparison of the options
This section compares the costs and benefits of each of the Options presented above in a
semi-quantitative manner.
In general, the costs of implementing each of the above measures can be estimated to a
reasonably certain degree using tools such as the standard cost model for estimating
administrative costs. However, no data or methodology exists to accurately quantify all
the benefits of the measures in terms of direct benefits to consumer (consumer surplus) or
general competition. As such, this Section aims to illustrate the possible direct benefit to
consumers assuming certain conditions. It also highlights important qualitative evidence
from stakeholders that policymakers should also incorporate into their analysis of costs
and benefits.
Option 0: Stronger enforcement
An estimated 4% of EU consumers face switching-related charges that may be illegal under
EU law. Stronger enforcement would see these increasingly phased out. Whilst we cannot
measure the economic benefits of this option, we can estimate its benefit to consumers
given some simple assumptions.
If we assume that:
- One in fifty of the households currently affected by illegal electricity
switching fees make a switch as a direct result of an enforcement drive191
;
- Gas household consumers see no benefits192
;
191
This is a highly uncertain figure, affected by several variables that have not been studied in depth,
including the speed and effectiveness of EU enforcement action, and public awareness of consumer
rights.
192
This is a conservative estimate. Whilst the evidence suggests they may be less prevalent, and Figure
Figures X and Y indicate they are certainly present.
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- The annual financial benefit of switching for these households amounts to 82
euros, which is the average difference in price between the incumbent's
standard offer and the cheapest offer in the capital city in the EU193
;
- The financial advantage of switching as a result of these measures persists for
four years194
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms195
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 0 would result in an increase in consumer surplus of between 13.7 million
euros and 48.4 million euros annually (depending on the year of implementation), and
415 million euros in total for the period 2020-2030.
In spite of these considerations, it is unlikely that Option 0 would most effectively address
the problem of poor consumer engagement. First, a great degree of uncertainty surrounds
the estimation above associated with the speed and effectiveness of EU enforcement
action.
In addition, the effectiveness of Option 0 is significantly limited by the fact that the
provisions of the Electricity and Gas Directives state that consumer supply contracts must
specify "whether withdrawal from the contract without charge is permitted". A further 17%
of consumers will therefore continue to be directly affected by contract exit fees that are
legal under current legislation.
There are no implementation costs associated with Option 0.
Option 0+: Clarifying certain concrete requirements in the current legislation through an
interpretative note, coupled with stronger enforcement
This option would make it easier for suppliers and national authorities to interpret current
switching rules and to determine whether certain fees are compatible or incompatible with
the Third Package. Consumers would also have access to more and clearer information
regarding the legal situation surrounding such fees and could become better aware of the
types of fees used in their contracts. This option would make it easier for suppliers and
national authorities to interpret current switching rules and to determine whether certain
fees are compatible or incompatible with the Third Package. Consumers would also have
access to more and clearer information regarding the legal situation surrounding such fees
and could become more aware of the types of fees used in their contracts.
Whilst the economic benefits of this measure cannot be estimated, we can expect its
benefits to consumers to be similar to Option 0 (415 million euros in total for the period
193
The weighted average was not used because the large potential savings available to DE consumers
skewed this figure to over EUR 150. "Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documentsreality,
/Acts_of_the_Agency/Publication/ACER_Market_Monitoring_Report_2015, p.59.
194
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
195
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we have
no reliable data to quantify these differences in this specific context.
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2020-2030) or higher, reflecting the greater legal certainty engendered by the EU guidance
issued compared with Option 0.
However, as with Option 0, a further 17% of consumers are directly affected by contract
exit fees that are legal under current legislation.
It is unlikely that voluntary cooperation between Member States would address this
problem, as it is domestic in nature with no common gains to be had through supra-national
coordination.
There are no implementation costs associated with Option 0+.
Several stakeholders support the principle of better implementation of the existing
switching fee provisions in the Electricity and Gas Directives, including the European
Parliament's ITRE Committee and NRAs. Others, such as consumer groups and
ombudsmen, argue that there should be no fees associated with switching.
Option 1: Legislation to outlaw the use of switching fees and to limit the use of exit fees
in electricity and gas supply contracts in the EU
This option may considerably reduce the prevalence of both switching and exit fees for the
category of consumers most likely to be confused by such fees – household consumers.
If we assume that:
- One in one-hundred of the 17% of households currently affected by exit fees
in their electricity supply contracts make a switch as a direct result of this
intervention196
;
- The annual financial benefit of switching for these households amounts to 82
euros, which is the average difference in price between the incumbent's
standard offer and the cheapest offer in the capital city in the EU197
;
- Gas household consumers see no benefits198
;
- The financial advantage of switching as a result of these measures persists for
four years199
;
196
This is a highly uncertain figure as we have no clear and comprehensive picture as to: i) the proportion
of consumers who may be charged exit fees even though they are on indefinite contracts; ii) the
proportion of consumers whose exit fees would be considered disproportionate, and therefore not
permitted under this option; iii) the extent to which consumers benefitting from this measure would be
aware of it; iv) how those aware of the legislative change would respond to the increased financial
incentive to switch.
197
The weighted average was not used because the large potential savings available to DE consumers
skewed this figure to over EUR 150. "Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documentsreality,
/Acts_of_the_Agency/Publication/ACER_Market_Monitoring_Report_2015, p.59.
198
This is a conservative estimate. Whilst the evidence suggests they may be less prevalent, Figures 4 and
5 indicate they are certainly present.
199
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
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- All EU households within each Member State are able to benefit from these
changes equally in relative terms200
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in an increase in consumer surplus of between 29 million euros
and 102.8 million euros annually (depending on the year of implementation), and 881
million euros in total for the period 2020-2030 on top of any gains brought by improved
enforcement (estimated at 415 million euros for options 1 and 2).
Whilst these consumer benefits are subject to great uncertainty due to the unknown extent
to which they would increase consumer switching, Belgium's experience (See Box) would
seem to indicate that restricting contract exit fees has a significant potential to increase
consumer engagement – in the short-term at least.
In terms of implementation costs, Option 1 would most notably limit innovation and
consumer choice around certain elements of consumer supply contracts, most notably by
preventing exit fees from being charged in indefinite contracts. Whilst unquantifiable,
these implementation costs would likely be limited. Consumers wishing to benefit from
lower prices in exchange for greater consumer loyalty could still opt for fixed-term
contracts.
In addition, Option 1 would permit the on-bill repayment of upfront investments in energy
efficiency. Such financing through, for instance, energy performance contracting201
will
play an important part in meeting the EU's ambitious energy efficiency targets, and is a
priority under Commission plans.
Apart from consumer groups and ombudsmen, most stakeholders would seem to support
this option, including suppliers and NRAs. This is because it incrementally builds upon
the existing provisions of the Electricity and Gas Directives, helping to achieve the
legislators' intention more effectively.
This option would best clarify the legal situation and be the most enforceable measure.
Given the very significant effect on switching rates similar measures have had in Belgium
(See Box 2), this measure would also lead to a sizeable increase in consumer engagement
in many Member States in which contract exit fees are common.
200
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we have
no reliable data to quantify these differences in this specific context.
201
"Energy performance contracting" means a contractual arrangement between the beneficiary and the
provider of an energy efficiency improvement measure, verified and monitored during the whole term
of the contract, where investments (work, supply or service) in that measure are paid for in relation to a
contractually agreed level of energy efficiency improvement or other agreed energy performance
criterion, such as financial savings.
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If we assume that:
- One in four of the estimated 3% of household consumers who report that they
have not tried to switch because they would be charged a fee actually make a
switch as a result of a complete ban on such fees202
;
- The annual financial benefit of switching for these households amounts to 41
euros, which is half of the average difference in price between the
incumbent's standard offer and the cheapest offer in the capital city in the
EU203
;
- Gas household consumers see no benefits204
;
- The financial advantage of switching as a result of these measures persists for
four years205
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms206
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 2 would result in an increase in consumer surplus of between 64 million euros
and 227 million euros annually (depending on the year of implementation), and 1.9
billion euros in total for the period 2020-2030 on top of any gains brought by improved
enforcement (estimated at 415 million euros for options 1 and 2).
Whereas the implementation costs of Option 2 are unquantifiable, they may be
significant. This is because Option 2 would strongly restrict the range of contracts
available to consumers, which may impede competition, as well as the provision of a
legitimate class of products.
If implemented poorly, Option 2 could also impede the development of innovative
financing options for beneficial investments in energy assets for households. Such products
may require certain forms of termination fees in order to allow companies to recoup upfront
investment costs provided as part of an integrated energy service product e.g. solar panels
or energy efficiency upgrades. This option could therefore be in significant tension with
other EU policy priorities, including its energy efficiency, renewable deployment, and self-
consumption policies. For example, one of the objectives of the EED was to identify and
remove regulatory and non-regulatory barriers to the use of energy performance
contracting and other third-party financing arrangements for energy savings.
Whereas several stakeholders support an outright ban on switching fees – notably
consumer groups and energy ombudsmen – NRAs believe the decision on whether or not
202
See Figure 7. This estimate is based on survey responses, and has been discounted to conservatively
reflect possible unreliability in what consumers report.
203
We conservatively assume that the savings to consumers available in this option are significantly
reduced because the cheapest option available in the market – the benchmark price used in the other
options – is usually a fixed term contract, which may require the consumer to accept a contract exit or
termination fee in return for consumer loyalty. As this option entails banning all exit fees, it is unlikely
that suppliers would be able to offer consumers the same level of financial savings in such contracts.
204
This is a conservative estimate. Whilst the evidence suggests they may be less prevalent,
Figure 4 and Figure indicate they are certainly present.
205
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
206
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we have
no reliable data to quantify these differences in this specific context.
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to completely ban them should be taken at the national level. ACER and electricity
suppliers support the legitimacy of termination fees for fixed term contracts.
Conclusion
The analysis indicated that each of the Options above is likely to result in a net benefit.
However, Option 1 is the preferred option, as it represents the most favourable balance
between probable benefits and costs. Whereas the potential benefits of Option 2 are greater,
so are the potential implementation costs in terms of both reduced competition and tension
with the EU's sustainable energy policies.
Subsidiarity
Consumers are not taking full advantage of competition on energy markets due, in part, to
obstacles to switching. Well designed and implemented consumer policies with a European
dimension can enable consumers to make informed choices that reward competition, and
support the goal of sustainable and resource-efficient growth, whilst taking account of the
needs of all consumers. Increasing confidence and ensuring that unfair trading practices
do not bring a competitive advantage will also have a positive impact in terms of
stimulating growth.
As a result of current EU provisions, national legal regimes remain fragmented as regards
switching-related fees. Further restricting such fees would diminish an important barrier to
customer mobility. The possibility of easy and free-of-charge switching would exert more
competitive pressure on energy suppliers to improve quality and reduce prices.
The options here envisage clarifying the legislation and further limiting the use of exit fees
across different kinds of consumer contracts (fixed-term, indefinite, supply contracts
bundled with energy services) and to different degrees.
The legal basis for the legislative options proposed (Options 1 and 2) is therefore likely to
be Article 114 TFEU. This allows for the adoption of "measures for the approximation of
the provisions laid down by law, regulation or administrative action in Member States
which have as their object the establishment and functioning of the internal market". In
doing this, in accordance with Article 169 TFEU, the Commission will aim at ensuring a
high level of consumer protection.
Without EU action, the identified problems related to the lack of an EU-wide market will
continue to lead to consumer detriment.
Option 0+
The guidance option does not significantly change the legal status quo. Member State
authorities would continue, to have a significant degree of discretion in deciding if a
termination/switching fee is allowed or not.
From a subsidiarity perspective, this option allows member States to decide on the extent
to which they wish creating an environment where customers are encouraged to switch
more freely, as this – in theory, at least – may not always result in lower overall prices
depending on the national situation.
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From the perspective of proportionality, however, this option would not achieve the
objective of the Article of the Treaty taken as their legal basis – the establishment and
functioning of the internal market.
Option 1
The principles of subsidiarity and proportionality are best met through this Option, as it is
not overly prescriptive and will concretely reduce levels of consumer detriment that are, at
present, not addressed at a national level by Member State authorities.
This option aims primarily at clarifying and not strengthening existing legislation. As
switching and exit fees are already addressed in EU provisions, the subsidiarity and
proportionality principles have clearly been assessed previously and deemed as met.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the preceding
pages, accrue predominantly to consumers who are engaged in the market – those who compare offers and
are likely to change suppliers if they find a better deal. Whilst facilitating switch will also increase consumer
engagement levels, and whilst the increased competition engendered by easier switching will lead to more
competitive offers on the market, disengaged consumers, including consumers who may be vulnerable, will
not reap as many direct benefits from this policy intervention
Option 2
Banning exit fees in EU legislation would help to create a level playing field for consumers
within Member States and between Member States. At this point, however, it would be
disproportionate to impose a complete ban on exit fees as it would have a limiting effect
on innovation and choice. It would limit the range and number of offers available to
consumers, for example, fixed-term, fixed-price contracts that offer a lower cost per kWh.
Stakeholders' opinions
Public Consultation
222 out of 237 respondents to the Commission's Consultation on the Retail Energy
Market207
believed that transparent contracts and bills were either important or very
important for helping residential consumers and SMEs to better control their energy
consumption and costs.
When asked to identify key factors influencing switching rates, 89 respondents out of 237
stated that consumers were not aware of their switching rights, 110 stated that prices and
tariffs were too difficult to compare due to a lack of tools and/or due to contractual
conditions, and 128 cited insufficient benefits from switching.
Only 32 out of 237 respondents agreed with the statement: "There is no need to encourage
switching". 98 disagreed and 90 were neutral.
National Regulatory Authorities
ACER identifies exit fees as a potential barrier to switching, since they tend to increase
the threshold for consumers to switch due to the perceived diminished potential savings
207
Held from 22 to 17 April 2014. https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-
market
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available. However, ACER highlights that exit fees in fully competitive retail markets are
applied to cover the costs incurred by suppliers due to early contract termination. ACER
argues that offers which include exit fees should be made fully transparent (including on
price comparison tools) and that exit fees need to be objectively justified.
The body representing the EU's national regulatory authorities in Brussels, CEER208
,
supports the distinction between exit fees, which it deems to be a contractual matter, and
all other switching-related fees. CEER has stated that it should not be possible for energy
suppliers to charge an exit fee to customers who respect the end date of their fixed term
energy contract. It also deems that other switching-related fees are not permissible under
EU law. However, it argues that any decision on whether to abolish exit fees needs to be
taken at the national level, as creating an environment where customers are encouraged to
switch more freely may not always result in lower overall prices.
Ombudsmen
According to NEON, the National Energy Ombudsmen Network, EU regulations and
directives already provide that supplier switching should be easy and quick, without extra
charges. However, mistrust in the market, indecision and the perceived lack of benefits
remain the main obstacles to more switching. As it is the case in France and Belgium,
NEON believes that consumers should be allowed the right to change supplier whenever
they want, without paying termination or exit fees.
Consumer Groups
BEUC has argued for greater transparency on exit fees, stating that a summary of the key
contractual conditions, including conditions for switching, should be provided to
consumers in concise and simple language alongside with the contract209
. BEUC has also
stated that it is: "concerned about the application of termination fees representing a lock in
situation of the consumer and an anti-competitive measure as these fees often prevent
consumers from changing the supplier. Switching should not be subject to any termination
fee or penalty"210
.
BEUC, EURELECTRIC and Eurogas recently released joint statement on improved
comparability of energy offers211
. In it, they call for the following key information is
provided to customers by suppliers in one place in a short, easily understandable,
prominent and accessible manner:
- Product name and main features including, where relevant, information on
environmental impact, clear description of promotions (e.g. temporary discounts) and
additional services (e.g. maintenance, insurance, etc.)
- Total Price (fixed/variable) - which includes all cost components - and conditions for
price changes
- Contract duration, notice period (renewal/withdrawal - where relevant) and conditions
for termination, including, where relevant, fees and penalties
208
The Council of European Energy Regulators.
209
http://www.beuc.eu/publications/beuc-x-2015-
102_mst_beuc_response_to_public_consultation_on_a_new_energy_market_design.pdf
210
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
211
http://www.eurelectric.org/media/263669/joint_statement_-
_improved_comparability_of_energy_offers_-2016-030-0116-01-e.pdf
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- Payment frequency and method options (e.g. cash/ cheque/ direct debit/ standing order/
prepayment)
- Supplier’s contact details (e.g. customer service’s address, telephone number and/or
email, including, where relevant, identification of any intermediary)
Suppliers
In their contribution to the discussions within the Citizens' Energy Forum in 2016,
EURELECTRIC and its members welcomed the intention of the Commission and NRAs
to work towards removing barriers to switching supplier. EURELECTRIC believes that all
barriers should be considered, including non-commercial barriers, i.e. technical and
regulatory. In terms of commercial barriers, a distinction should be drawn between fixed
term contracts and variable contracts. Many customers are on variable tariffs with no end
date and these do not have exit fees. In contrast, according to EURELECTRIC, exit fees
need to be allowed to for fixed term deals – provided they’re proportionate to the costs
incurred by the supplier – as they help cover the costs suppliers face when customers leave
early, much like for broadband or mobile phone contracts. Such contracts can be cheaper
because suppliers have more certainty about how many customers they have and how much
energy to buy in advance. If exit fees were banned for such contracts, the prices of fixed
term deals would be likely to go up to the detriment of customers. EURELECTRIC
believes that in any case where exit fees do apply to fixed term contracts, they must be
clearly communicated to customers up-front.
BEUC, EURELECTRIC and Eurogas also recently released joint statement on improved
comparability of energy offers, which can be read above. It notably includes the
recommendation that termination fees be provided along with other key information on the
offer "in one place in a short, easily understandable, prominent and accessible manner".
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Parliament's Committee on Industry, Research and Energy
(ITRE): "Insists that the provisions on switching, as set out in the Third Package, should
be fully implemented by Member States, and that national legislation must guarantee
consumers the right to change suppliers in a quick, easy and free-of-charge way, and that
their ability to switch should not be hindered by termination fees or penalties".
Furthermore, ITRE calls for better information to consumers about their rights, and for
further measures to make switching between providers easier.
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Parliament's Committee on the Internal Market and
Consumer Protection (IMCO) called for: "the full implementation of the third energy
package, including the right to change suppliers free of charge and better information to
consumers about their rights, and for further measures to make switching between
providers easier and faster, including a shortened switching period and effective and secure
data portability in order to prevent the lock-in of consumers".
The Committee of the Regions
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Committee of the Regions suggests that information
campaigns for switching suppliers should be launched by energy regulators, local
authorities and consumer organisations. The Committee also encourages the EU to adopt
an ambitious regulation on reducing the transfer time for customers switching from one
provider to another, and making the transfer procedure automatic.
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7.5. Comparison tools
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Summary table
Objective: Facilitating supplier switching by improving consumer access to reliable comparison tools.
Option 0+ Option 1 Option 2
Cross-sectorial Commission guidance addressing the applicability of the
Unfair Commercial Practices Directive to comparison tools
Legislation to ensure every Member State has at
least one 'certified' comparison tool that complies
with pre-specified criteria on reliability and
impartiality
Legislation to ensure every Member State appoints
an independent body to provide a comparison tool
that serves the consumer interest
Pros:
- Facilitates coherent enforcement of existing legislation.
- Light intervention and administrative impact.
- Cross-sectorial consumer legislation already requires comparison tools to be
transparent towards consumers in their functioning so as not to mislead
consumers (e.g. ensure that advertising and sponsored results are properly
identifiable etc.).
- Cross-sectorial approach addresses shortcomings in commercial comparison
tools of all varieties.
- Cross-sectorial approach minimizes proliferation of sector-specific
legislation.
Pros:
- Fills gaps in existing legislation vis-à-vis energy
comparison tools.
- Limited intervention in the market, in most cases.
- Allows certifying all existing energy comparison
tools regardless of ownership.
- Proactively increases levels of consumer trust.
- Ensures EU wide access.
- The certified comparison websites can become
market benchmarks, foster best practices among
competitors
Pros:
- NRAs able to censure suppliers by removing their
offers from the comparison tool.
- No obligation on private sector.
- Reduces risks of favouritism in certification
process.
- Proactively increases levels of consumer trust.
Cons:
- Does not apply to non-profit comparison tools.
- Does not proactively increase levels of consumer trust.
- The existing legislation does not oblige comparison tools to be fully
impartial, comprehensive, effective or useful to the consumer.
Cons:
- Existing legislation already requires commercial
comparison tools to abide by certain of the criteria
addressed by certification.
- Requires resources for verification and/or
certification.
- Significant public intervention necessary if no
comparison tools in a given Member State meet
standards.
Cons:
- To be effective, Member States must provide
sufficient resources for the development of such
tools to match the quality of offerings from the
private sector.
- Well-performing for-profit tools could be side-
lined by less effective ones run by national
authorities.
Most suitable option(s): Option 1 is the preferred option because it strikes the best balance between consumer welfare and administrative impact. It also gives Member States control over
whether they feel a certification scheme or a publicly-run comparison tool best ensures consumer engagement in their markets.
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Description of the baseline
Online comparison tools – websites that compare different energy offers – play an
important role in helping consumers to make an informed decision about switching
suppliers. Comparison tools (CTs) have become increasingly widespread, and can now be
found in almost every MEMBER STATE (Table 1).
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Table 1: Estimated number of energy comparison tools in Member States212
212
Excluding CY and MT. Source: CEER, "Study on the coverage, functioning and consumer use of
comparison tools and third-party verification schemes for such tools", (2014) European Commission,
http://ec.europa.eu/consumers/consumer_evidence/market_studies/comparison_tools/index_en.htm.
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Member
State
Number
of energy
CTs
Of which
Govt.
Operated
Comment
* denotes estimate based on weighted average of figures from NRAs who reported data, or desktop
research
AT 2* 1
BE 11 3 Accreditation under review.
BG 0 0
CZ 2* 0*
DE 10 0 German consumer organisations under the umbrella of a market
watchdog have conducted a survey about CT's in February 2016
and provided a test report and ranking, which can be found here.
DK 2 2
EE 0 0
EL 3* 0*
ES 7 1 The NRA is legally entitled to run a CT. All suppliers are obliged
to send the commercial offers to the CT. The NRA CT would meet
accreditation standards.
The consumer organization also has a CT, but only for its affiliates.
The NRA has no powers to monitor the functioning of private CTs.
It can be estimated than very few of them would meet accreditation
standards, perhaps between 0 and 3, depending on the requirements
for the accreditation.
FI 4 1 No specific accreditation standards are applied. The CT
(www.sahkonhinta.fi) operated by the NRA, however, is free of
charge, neutral, easy to access and comprehensive (all suppliers are
obliged to report their public offers there). One of the commercial
CTs uses the price data that is published by the NRA.
FR 8 2
HU 3 0 There are several running service provider businesses
concentrating exclusively on businesses. In addition Hungary is
considering implementing a comparison tool - taking into account
the level of price competition - would primarily focus on businesses
and would be run by the Hungarian NRA.
HR 1* 0*
IE 2* 0 Accreditation scheme in place
IT 9 2
LV 0 0
LT 0 0 ACER reports no price comparison tools in this Member State.
LU 1 1
NL 14 0 No accreditation scheme. ACM developed a ‘guidance’ document
for all companies offering electricity and/or gas contracts,
including price comparison websites. The guideline is based on
general consumer law and sector specific energy legislation. The
goal of the guideline is to ensure that consumers are offered energy
products that are tailored made to their situation, contains
information they can easily understand, and compare with other
offers. ACM can intervene whenever a price comparison website
does not comply with the aforementioned legislation.
PL 1 1 Offers available on CT, are updated by NRA on the basis of
information from suppliers. Suppliers are obliged to send NRA new
offers immediately after deciding on the introducing their offer into
the market (but not later than 2 days before the offer starts).
However data concerning distribution is entered by particular DSO
on the basis of distribution tariffs and their changes.
PT 2 1
RO 0 0
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Member
State
Number
of energy
CTs
Of which
Govt.
Operated
Comment
* denotes estimate based on weighted average of figures from NRAs who reported data, or desktop
research
SE 4 1 The regulated CT is under supervision and checked regularly. The
other CTs are not regulated, supervised nor does the regulator
control the prices or how the prices are published. There is no
specific legislation for these CTs.
SI 1* 1
SK 1* 0*
UK 34 1 33 comparison tools make up over 90% of the market in GB, with
the remaining proportion of the market made up of 100’s of smaller
switching services.
Total 122* 18*
Source: CEER and DG ENER research
A recent study found that 64% of consumers who had compared the tariffs of different
electricity companies said they had used a comparison tool to do so, compared to 38% who
had visited company websites, and 8% who had contacted companies by phone213
. It also
showed that comparison tools significantly increased the number of cheaper offers
consumers were able to identify compared with contacting individual providers directly214
.
Overall, 23% of consumers surveyed in the EU have used a comparison tool to compare
energy offers in the last 12 months215
.
Comparison tools are likely to become even more important as the retail market for energy
matures. Between 2012 and 2014, ‘choice’ for consumers in European capitals widened,
with a greater variety of offers being available. However, the ability of consumers to
compare prices can be hampered by the complexity of pricing and the range of energy
products, as well as by an increasing number of offers and their bundling with additional
charge free or payable services216
.
In a retail market characterized by persistently low levels of consumer engagement,
comparison tools are an effective means of reducing search costs for consumers, and
presenting them with accurate market information in a manner that is clear and
comprehensive.
However, the majority of comparison tools are operated for profit, leading to situations
where their impartiality and the consumer interest may not be ensured. Most comparison
tools do not charge consumers for access to their sites and therefore the bulk of their
products are obtained via commercial relationships with the vendors they list. They get
paid via subscription fees, click-through fees, or commission fees. Some comparison sites
213
Non-exclusive figures i.e. respondents could choose more than one means of comparison.
214
From twice to twenty times, depending on the Member State. "Second Consumer Market Study on the
functioning of retail electricity markets for consumers in the EU" (2016) European Commission.
215
However, this figure varies widely across the EU with up to 45% of UK consumers using comparison
tools to compare energy offers compared to only 2% of consumers from Luxembourg. "Study on the
coverage, functioning and consumer use of comparison tools and third-party verification schemes for
such tools" (2013) European Commission,,
http://ec.europa.eu/consumers/consumer_evidence/market_studies/comparison_tools/index_en.htm
216
"Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015 p.40, 100.
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list sellers at no cost and get their revenue from sponsored links or sponsored ads. A lesser
used model is where some Comparison Tools charge consumers to obtain access to its
information, while firms do not pay any fees (Figure 1).
Figure 1: Business models of EU comparison tools (including non-energy)
Source: "Study on the coverage, functioning and consumer use of comparison tools and third-party
verification schemes for such tools" (2013) European Commission, pp. 99, 102
Recent reports of unscrupulous practices have damaged consumer trust in both comparison
tools and the switching process more generally (Box 1). Indeed, a third of respondents to
a recent EU survey somewhat or strongly agreed that they did not trust price comparison
websites because they were not independent and impartial and thus questioned the
independence of such tools. Perhaps for this reason, the same study found: "Comparison
tools did not appear keen to divulge details on how they generated income"217
.
Identified issues include:
i) the default presentation of deals by some websites;
ii) the misleading language used to provide consumers with a choice of which
presentation to pick;
iii) the lack of transparency about commission arrangements; and
iv) inadequate arrangements for regulatory oversight.
217
Less than half of Comparison Tools were willing to disclose details on their supplier relationship,
description of business model or the sourcing of their price and product data. "Study on the coverage,
functioning and consumer use of comparison tools and third-party verification schemes for such tools"
(2013) European Commission, pp. xix, 191.
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Box 1: UK House of Commons report into energy comparison tools218
The UK has the largest number of energy comparison websites of any Member State, with 34 such tools
controlling a 90% share of the market. In 2015, the House of Commons Energy and Climate Change
Committee published a report criticising energy comparison tools for "hiding the best deals from consumers
by concealing tariffs from suppliers that do not pay the website a commission." The report concluded that
"all deals should be made available by default to the consumer" and strongly objected to "any attempt to lure
consumers into choosing particular deals by the use of misleading language." In addition it highlighted "the
lack of transparency about commission arrangements between the websites and suppliers" as a shortcoming
in the UK energy comparison tool market.
Source: UK House of Commons, Energy and Climate Change Committee
The existing consumer acquis could be made to work better (see Section below), and is an
ex-post safety net that is enforced on a case-by-case basis by relevant national courts and
authorities. There may therefore be benefit in putting in place a specific ex-ante quality
assurance mechanism to guarantee a high level of quality information and transparency to
consumers, to spread the uptake of best practices, and to boost consumer confidence in
these tools. In addition, while comparison tools are indeed widespread, there is the need to
ensure a more universal coverage of reliable comparison tools throughout the internal
market.
Deficiencies of the current legislation
Section 7.3.5 and Annex V of the Evaluation show that the relevance of the existing
legislation is challenged by the fact that it is not adapted to reflect new ways of consumer-
market interaction, such as through comparison tools.
The 2005 Unfair Commercial Practices Directive219
(UCPD) addresses comparison tools
in so far as it requires them to provide enough information to ensure that consumers are
not misled. As such, comparison tools qualifying as traders under the UCPD must ensure
that they carry out comparisons in a transparent way. They must not provide false or
deceiving statements, nor must they omit information about products if this causes the
average consumer to take a decision they might not have taken otherwise. The UCPD
particularly requires all traders to clearly distinguish a natural search result from
advertising.
Indeed, the full implementation of the UCPD would help address two of the issues with
energy comparison tools identified in the Section above, namely: The misleading language
used to provide consumers with a choice of which presentation to pick; and the lack of
transparency about commission arrangements.
In spite of this legislation, however, there may be scope for further EU action to address
this area.
Firstly, because the UCPD is a cross-sectorial and principle-based piece of legislation, its
provisions may not address all of the problems we observe in comparison tools. For
example, whilst the UCPD states that comparison tools should not mislead consumers, it
218
In one such case, some comparison websites were found to be hiding the best deals from consumers by
concealing tariffs from suppliers that did not pay these websites a commission. “Protecting consumers:
Making energy price comparison websites transparent” (2015) UK House of Commons, Energy and
Climate Change Committee,
http://www.publications.parliament.uk/pa/cm201415/cmselect/cmenergy/899/899.pdf.
219
Articles 6 and 7, in particular.
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does not oblige them to be effective, impartial or useful to the consumer, nor does it require
comparison tools to cover an entire market. A comparison tool that only displayed biased
rankings would be in compliance with the UCPD as long as it clearly stated that this was
the case.
Secondly, Member States may have difficulties in interpreting the provisions of the UCPD
– as well as the 13 other pieces of legislation and official guidance that may apply (Box 2)
– and relating this body of legislation to energy comparison tools in particular. Clearer
provisions could therefore improve implementation.
Box 2: List of applicable legislation and official guidance documents
- Directive 2005/29/EC (Unfair Commercial Practices Directive)
- SEC(2009) 1666 (Guidance on Unfair Commercial Practices Directive)
- Directive 2011/83/EU (Consumer Rights Directive)
- Guidance Document concerning Directive 2011/83/EU (Guidance on Consumer Rights Directive)
- Directive 2006/114/EC (Misleading and Comparative Advertising Directive)
- Directive 2000/31/EC (E-Commerce Directive)
- Directive 98/6/EC (Price Indication Directive)
- Council Directive 93/13/EEC (Unfair Contract Terms Directive)
- Directive 2002/22/EC (Citizens' Rights Directive)
- Directive 2014/92/EU (Payment Accounts Directive)
- Regulation (EC) No 1008/2008 (Air Services Regulation)
- Directive 2009/72/EC (Electricity Directive)
- Directive 2009/73/EC (Gas Directive)
- Directive 2008/48/EC (Consumer Credit Directive)
- Directive 2007/64/EC (Payment Services Directive)
- Directive 2002/65/EC (Distance Marketing of Consumer Financial Services Directive)
Finally, whereas the UCPD and most other applicable consumer protection legislation only
applies to commercial comparison tools, there is also a need to ensure the quality of
comparison tools operated by national authorities and non-profit organizations.
As for the Third Package, consumer bills and pre-contractual information formed the basis
of consumer comparability at the time of its drafting, as consumers would manually
measure up individual offers against their current supply contract. The legislation therefore
addressed these points in order to promote consumer interests. Since then, the use of online
websites for comparison as well as marketing purposes has risen significantly across the
EU, challenging the relevance of the sector-specific energy acquis, which does not address
comparison tools at all.
Presentation of the options
Option 0+ (Non-regulatory approach): Cross-sectorial Commission guidance addressing
the applicability of the Unfair Commercial Practices Directive to commercially operated
comparison tools
The Unfair Commercial Practices Directive expressly prohibits activities that materially
distort the consumer’s economic behaviour to the point where their ability to make an
informed decision is impaired. This has implications for the following issues relevant to
energy comparison tools, inter alia:
- Identification of advertising and sponsored results;
- Criteria for ranking;
- The disclosure of relationship with suppliers (assessed on a case-by-case basis);
- Displaying the same information for all products.
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Building on the principles of reliability and impartiality endorsed by the Multi-Stakeholder
Dialogue on Comparison Tools, the Commission has therefore very recently published
updated guidance on how to apply the Directive to comparison tools in all sectors220
.
In addition, various other cross-sectorial consumer protection Directives require the
disclosure of price and product data sourcing221
. Stronger enforcement of the existing
acquis therefore has significant potential to address the shortcomings addressed above.
Accordingly, a 2013 Commission study on comparison tools found that the "[e]nforcement
of existing legal instruments appears to be first a priority"222
.
14 different EU legal instruments and guidance documents may currently apply to
comparison tools, depending on their ownership characteristics and which consumer sector
they operate in. This means that both consumers and comparison tool operators are unlikely
to be fully familiar with their respective rights and obligations. Further consolidated
guidance can be considered here, too.
Option 1: Legislation to ensure every Member State has at least one 'certified' comparison
tool that complies with pre-specified criteria on reliability and impartiality
Under this option, a designated national authority would certify energy comparison tool
websites that meet certain criteria for reliability with some form of 'trustmark' as part of a
voluntary scheme.
These criteria would include: impartiality; quality and accuracy of information; type of
information/characteristics to be compared; transparency on the criteria used for
comparisons; transparency on ranking methodologies; transparency on funding; and (near)
complete coverage of the market. As these criteria would be based on recommendations
contained in the Council of European Energy Regulator’s ‘Guidelines of Good Practice on
Price Comparison Tools’, they would be a product of the expert opinion of EU NRAs, as
well as an extensive public consultation process223
.This sector-specific approach would
plug gaps in the existing legislation, and was recently also taken to improve comparison
tools in the banking sector with the 2014 Payment Account Directive.
Box 3: Fourteen CEER recommendations for comparison tools
Independence: Comparison Tools in the energy sector should be independent from energy supply companies
(1), National Regulatory Authorities (NRAs) should maintain a role by assisting self-regulation, establishing
accreditation/regulation or by creating Comparison Tools (2).
Transparency: Comparison Tools should disclose the way they operate, their funding and their
owners/shareholders (3).
220
See updated Guidance on the UCPD, http://ec.europa.eu/consumers/consumer_rights/unfair-
trade/comparison-tools/index_en.htm.
221
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, pp. 289.
222
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, pp. 287.
223
"Guidelines of Good Practice on Price Comparison Tools",(2012) CEER, Ref: C12-CEM-54-03,
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf.
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Exhaustiveness: All prices and products available for the totality of customers should be shown as a first
step. If not possible, the Comparison Tool should clearly state this before showing results. After the initial
search, the option to filter results should be offered to the customer (4)
Clarity and Comprehensibility: Costs should always be presented in a way that is clearly understood by the
majority of customers, such as total cost on a yearly basis or unit kWh-price including amount and duration
of discounts and whether prices are an estimation based on historic or estimated consumption (5).
Fundamental characteristics of all products, for example fixed price products, floating price products or
regulated end user prices, should be presented on the first page of the result screen. This differentiation
should be easily visible to the customer. Explanations of the different types of offers should be available to
help the customer understand their options (6). The price Comparison Tool should offer information on
additional products and services, if the customer wishes to use that information to help choose the best offer
for them (7).
Correctness and Accuracy: Price information used in the comparison should be updated as often as necessary
to correctly reflect prices available on the market (8).
User Friendliness: The user should be offered help through default consumption patterns or, preferably, a
tool that calculates the approximate consumption, based on the amount of the last bill or on the basis of other
information available to the user (9).
Accessibility: To ensure an inclusive service at least one additional communication channel (other than the
Internet) for getting a price comparison should be provided free of charge or at minimal cost (10). Online
Comparison Tools should be implemented in line with the Web Accessibility Guidelines (WCAG) and
should ensure that there are no barriers to overcome to access the comparison (11).
Customer Empowerment: Where the Comparison Tool is run by an NRA/public body they should promote
the service to customers. Where the NRA/public body is regulating/accrediting/actively monitoring privately
run Comparison Tools they should consider establishing a marker or logo (12). Comparison Tool providers
should provide background information on market functioning and market issues if the customer wants this
information or provide links to useful independent sources of information (13). Information provided to
customers should be clearly written and presented using consistent or standardised terms and language (14).
The main administrative costs would fall upon national competent authorities who would
be charged with developing accreditation systems, monitoring compliance, and imposing
sanctions. However, the legislation would allow costs to be charged to website operators
seeking accreditation under this scheme. Such costs may be covered by, for example,
increased sales at the level of an accredited (and thus trustworthy) comparison tool.
In Member States where comparison tools are not widely used, it may be difficult to find
one that meets the criteria for certification. The legislation would therefore allow a public
authority such as the NRA to establish a comparison tool conforming to the certification
criteria.
However in more mature markets, existing providers are likely to be willing and able to
fulfil accreditation requirements in order to gain further recognition in the market and
strengthen their reputation with consumers.
Option 2: Legislation to ensure every Member State appoints an independent body to
provide a comparison tool that serves the consumer interest
Examples of such independent bodies could include NRAs, consumer authorities, or
independent consumer groups. The establishment and funding of such comparison tools
would be left to the discretion of the Member State, however the comparison tool must
conform to the same certification criteria put forward in Option 1 to ensure its reliability.
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Comparison of the options
This Section compares the costs and benefits of each of the Options presented above in a
semi-quantitative manner.
In general, the costs of implementing each of the above measures can be estimated to a
reasonably certain degree using tools such as the standard cost model for estimating
administrative costs224
. However, no data or methodology exists to accurately quantify all
the benefits of the measures in terms of direct benefits to consumer (consumer surplus) or
general competition. As such, this Section draws on behavioural experiments from a
controlled environment to evaluate the impact of some policy options on consumer
decision-making. Where appropriate, it aims to illustrate the possible direct benefit to
consumers assuming certain conditions. It also highlights important qualitative evidence
from stakeholders that policymakers should also incorporate into their analysis of costs
and benefits.
Option 0+: Cross-sectorial Commission guidance addressing the applicability of the Unfair
Commercial Practices Directive to commercially operated comparison tools
The cross-sectorial approach addresses shortcomings in commercial comparison tools of
all varieties, and minimizes the proliferation of sector-specific legislation. It helps national
authorities and comparison tool operators understand the relevant EU legislation,
addressing any possible cases of non-compliance. It also leads to a lighter administrative
impact in the Member States.
In spite of these considerations, it is unlikely that Option 0+ would most effectively
address the problem of poor consumer engagement.
Whereas stronger enforcement of the existing acquis has significant potential to address
the shortcomings identified above, the existing acquis does not oblige comparison tools to
be fully impartial, nor does it oblige existing comparison tools to cover (almost) the whole
market in a given Member State. It does not apply to non-profit comparison tools, and
better enforcement alone would not be as effective in boosting consumer confidence as a
proactive accreditation scheme. Moreover, this option would not ensure that all EU
consumers have access to a certified comparison tool – an aspect that is highly desirable
given the important role comparison tools play in engaging energy consumers and the
current disparity in the coverage of energy by comparison tools in various Member States
(Table 1).
It is unlikely that voluntary cooperation between Member States would address this
problem, as it is domestic in nature with no common gains to be had through supra-national
coordination.
Accordingly, NRAs, ombudsmen, consumer groups, and even industry associations
representing electricity and gas suppliers all support firmer action than Option 0+ proposes.
Indeed, the only major stakeholder that partially supports the soft-law approach embodied
in Option 0+ appears to be the European Parliament's Committee on the Internal Market
224
http://ec.europa.eu/smart-regulation/guidelines/tool_53_en.htm
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and Consumer Protection. But even here, the Committee also calls for EU-wide access to
an energy comparison tool – something that cannot be ensure without legislative changes.
There are no implementation costs associated with Option 0+.
Option 1: Legislation to ensure every Member State has at least one 'certified' comparison
tool that complies with pre-specified criteria on reliability and impartiality
The economic benefits of Option 1 will primarily be indirect, and come in terms of greater
competition (lower prices, higher standards of service and a broader variety of products on
the market). Comparison tools reduce the cost of comparing the market for consumers and
help to lower information asymmetries225
. Indeed, a behavioural experiment showed that
comparison tools increased the number of cheaper offers consumers were able to identify
by between two and twenty times (depending on the Member State) compared with
contacting individual providers directly. Given that insufficient financial gain is the main
consideration for not switching, this option should therefore help to reduce consumer
'stickiness' and create a more level playing field for suppliers.
Figure 2: Number of cheaper offers found (mean) – Contacting providers vs. using
comparison tools
12.7
9.2
7.0 6.8 6.1 4.5 4.2 3.9 3.6 3.2
32.5
20.7
49.7
46.3
27.6
36.6
12.3
29.9
12.7
7.7
SE
SI
DE
PL
Total
CZ
IT
UK
ES
FR
Online and phone enquiries
Comparison tools
Mean number of chepaeroffers found
Q17a-d & Q18a-b.Total number of offers found; Total number of cheaper offers
Base: all mystery shoppers (except Lithuania)
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
In addition, Option 1 will directly result in greater consumer surplus. Consumer
protection will be strengthened as suppliers and companies managing comparison tools
will be required to improve levels of transparency. For example, tools will not be restricted
to displaying the offers that are of greatest financial interest to either party. Customer
mobility through transparent publication of all offers will be improved, as will customer
trust through certification.
For this reason, the vast majority of consumers prefer comparison tools with third party
verification. In a behavioural test carried out within the recent study on price comparison
225
Comparison tool users surveyed for a recent EU study reported that they used these tools because they
offered them a quick way to compare prices (mentioned by 69%) and allowed them to find the cheapest
price (68%). Vast majorities of consumers agreed that price comparison websites are the quickest way
to compare prices (in total, 90% agreed), are easy to use (87%), and are useful to find out information
about specific products/prices (84%). "Study on the coverage, functioning and consumer use of
comparison tools and third-party verification schemes for such tools" (2013) European Commission,
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tools 78% of respondents chose an energy comparison tool that included third party
verification over 22% that chose tools with no verification226
.
226
12,000 respondents from 15 Member States: CZ, DE, DK, FR, GR, HR, HU, IT, LV, NL, PL, UK, RO,
SE, SI. The experiment tested (a) consumer choice of a comparison tool at the initial online search stage
using a mock search engine; (b) consumer choice of a comparison tool from a short list; and, (c)
consumer choice of a product or service on an individual comparison tool. The experiment was framed
for the electricity sector and travel sector (hotels). "Study on the coverage, functioning and consumer
use of comparison tools and third-party verification schemes for such tools" (2013) European
Commission, p. 205.
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Figure 3: POTP price spread and annual savings available from switching from the
incumbent standard offer
Source: ACER Retail Database (November–December 2014) and ACER calculations
Whilst the economic benefits of Option 1 in terms of increased competition cannot be
quantified227
, one dimension of consumer surplus – the direct financial benefits to
227
EU retail markets differ on too many dimensions to make a comparative approach reliable. And too
many factors affect key retail indicators to make the results of a longitudinal study into comparison tools
reliable.
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consumers of easier and more effective switching as a result of this measure – can be
estimated using the following assumptions.
If we assume that:
- The 14 Member States that already have accreditation schemes or at least one
government-operated comparison tool (AT, BE, DK, ES, FI, FR, IE, IT, LU,
PL, PT, SE, SI, UK) would see no additional benefits from this intervention
because they already fulfil its requirements228
;
- The average switching rates for electricity and gas in each of the other
Member States (BG, CZ, DE, EE, EL, HR, HU, LT, LV, NL, RO, SK)229
increased by 0.1% as a result of the intervention230
;
- The annual financial benefit of switching in these Member States amounts to the
difference in price between the incumbent's standard offer and the cheapest offer
in the capital city (Figure 3 above).231
;
- The financial advantage of switching as a result of these measures persists for
four years232
;
- Apart from increasing the switching rate, there were no other benefits of this
intervention in term of improving the ability of switching customers to
identify a better offer233
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms234
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in an increase in consumer surplus of between 27.8 million
euros and 98.3 million euros annually (depending on the year of implementation), and
843 million euros in total for the period 2020-2030. The main implementation costs
would fall upon national competent authorities who would be charged with developing
228
This is a conservative assumption, as it may be that the certification criteria put in place by Option 1
could improve the functioning of some existing certification schemes and government-run comparison
tools.
229
CY and MT were not included in this analysis.
230
Reflecting the increased consumer confidence in comparison tools, which greatly reduce the costs of
comparing the market. 27% of consumers surveyed strongly agreed, and 48% somewhat agreed, that
they trusted comparison tools more when they were affiliated with a third-party verification scheme.
And when respondents in a behavioural experiment were offered the choice between energy comparison
tools that carried no verification and ones that did, the sites that carried verification schemes were
selected 3.5 times more often than the ones that did not. "Study on the coverage, functioning and
consumer use of comparison tools and third-party verification schemes for such tools" (2013) European
Commission, pp. 191, 205.
231
This proxy correlates well with the results of a mystery shopping exercise in which respondents were
asked to report the actual annual savings they would benefit from if they moved to the cheapest
electricity tariff they were able to find. "Second Consumer Market Study on the functioning of retail
electricity markets for consumers in the EU" (2016) European Commission.
232
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
233
A conservative assumption in light of Figure 2.
234
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we have
no reliable data to quantify these differences in this specific context.
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accreditation systems or comparison websites, monitoring compliance, and imposing
sanctions.
Box 4: The costs of Elpriskollen.se - the Swedish NRA's comparison tool235
Initial investment (2008): 1,000,000 SEK (EUR 107,000)
IT system upgrade (2014): 280,000 SEK (EUR 29,400)
Website upgrade (2015): 600,000 SEK (EUR 63,600)
Annual running costs:
License: 28,000 SEK (EUR 2,996)
Servers and storage: 72,000 SEK (EUR 7704)
Application support and CGI: 150,000 SEK (EUR 16,050)
1 to 1.7 fulltime positions, depending on the year: EUR 66,768 - EUR 113,506
This equates to c. EUR 110,000 in start-up costs and EUR 105,143 - EUR 151,881 in running costs, factoring
in the annualized costs of periodic website and IT system upgrades.
Box 5: The costs of operating Ofgem's confidence code for comparison tools236
The UK currently has 12 websites that are accredited by a full-time, 3-person team at Ofgem. This small
team deals with ad hoc stakeholder engagements associated with the day-to-day operation of the confidence
code, as well as performing continuous internal audits of accredited websites throughout the year.
In addition, each accredited website undergoes an external audit every year by an external consultant (19
hours per site), and every new site registered undergoes a substantial external audit (70 hours per site).
This equates to around EUR 214,335 in annual running costs, assuming one new site is accredited each year
Assuming:
- All Member States currently without any comparison tools (EE, BG, LV, LT, and
RO) set up a state-run comparison tool to fulfil their obligations under Option 1;
- The costs of each of these comparison websites for electricity and gas is 50% higher
than the cost of the Swedish NRA's electricity price comparison website, which
deals with electricity alone (Box 4)237
;
235
Labour costs assume 2,080 work hours per man-year at EUR 32.10 for professionals, as per the standard
cost model.
236
Labour costs assume 2,080 work hours per man-year at EUR 41.50 for managers, EUR 32.10 for
professionals and EUR 23.50 for technicians or associate professionals, as per the standard cost model.
Calculations assume that Ofgem's confidence code team consists of one of each of the aforementioned
categories, and that external consultants charge at the rate of managers.
237
This is a conservative estimate given the significant labour cost differences between SE and these Member
States that would make setting up and operating a comparison website cheaper in other Member States.
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- All other Member States that would have to make changes under this option (CZ,
DE, EL, HR, HU, NL, SK) set up an accreditation scheme to fulfil their
obligations;
- The costs of the UK's accreditation scheme for energy comparison tools (Box 5)
can help us estimate the cost of accreditation schemes in these Member States;
- The costs of administering accreditation schemes is directly proportional to the
size of the market in terms of households238
;
- The cost of voluntary accreditation schemes to comparison tools is zero239
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in start-up costs of 802,500 euros running costs of between
1 million euros and 1.63 million euros annually (depending on the year of
implementation), and a total cost of between 13.3 euros and 16.5 million euros for the
period 2020-2030.
As regards stakeholder views, Option 1 would likely enjoy broad support amongst all
stakeholder groups. Whilst many stakeholders support the principle that comparison tools
should be independent and accurate without explicitly addressing the means of achieving
this, some – notably including industry groups and the European Parliament's ITRE
Committee, and the Committee of the Regions – explicitly call for certification.
Option 2: Legislation to ensure every Member State appoints an independent body to
provide a comparison tool that serves the consumer interest
As with Option 1, Option 2 would likely result in indirect and unquantifiable economic
benefits in terms of greater competition. It would also result in greater consumer surplus.
It would ensure EU-wide access to comparison tools free from any commercial interest
that could affect their impartiality. It would also have the additional benefits that national
authorities would be able to censure suppliers by removing their offers from the
comparison tool, there would be no obligation on the private sector, and no risk of claims
of favouritism in a certification process.
When asked which organizations would be the most appropriate to run comparison tools,
51% of comparison tool users thought that they should be run by consumer organisations.
13% selected a national authority or regulator as the most suitable organisation, and 8%
preferred to entrust this task to a private organisation240
. Given these results, one might
expect Option 2 to lead to greater levels of consumer trust than Option 1.
238
A conservative estimate, given that the UK appears to have a disproportionately large number of
comparison tools for the size of its market (Table 1).
239
As the scheme is voluntary, comparison tools can be expected to only to make the changes necessary to
qualify for accreditation if they judged this would be in their long-term financial interest anyway.
240
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, p. 203.
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Figure 4: Most appropriate organisation to run comparison tools (by country)241
"Study on the coverage, functioning and consumer use of comparison tools and third-party
verification schemes for such tools" (2013) European Commission
If we assume that:
- The average switching rates for electricity and gas in each of the 13 Member
States at least one government-operated comparison tool (BG, CZ, DE, EE,
EL, HR, HU, IE LT, LV, NL, RO, SK)242
increased by 0.13% as a result of
the intervention – 30% more than option one243
;
- The annual financial benefit of switching in these Member States amounts to
the difference in price between the incumbent's standard offer and the
cheapest offer in the capital city (Figure 3 above)244
;
- The financial advantage of switching as a result of these measures persists for
four years245
;
- Apart from increasing the switching rate, there were no other benefits of this
intervention in term of improving the ability of switching customers to
identify a better offer246
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms247
;
- A discount rate of 4% for the consumer benefits year on year;
241
Question: "Comparison tools can be run by different types of organisations. Among the following
organisations, which one do you think is the most appropriate?" '.
242
CY and MT were not included in this analysis.
243
Reflecting Figure 4. However, this estimate is highly uncertain in light of the fact that it assumes that
Member States would provide sufficient resources for the development of publicly run comparison tools
to match the quality of offerings from the private sector.
244
This proxy correlates well with the results of a mystery shopping exercise in which respondents were
asked to report the actual annual savings they would benefit from if they moved to the cheapest
electricity tariff they were able to find. "Second Consumer Market Study on the functioning of retail
electricity markets for consumers in the EU" (2016) European Commission.
245
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
246
A conservative assumption in light of Figure 2.
247
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we have
no reliable data to quantify these differences in this specific context.
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then Option 2 would result in an increase in consumer surplus of between 56 million euros
and 128 million euros annually (depending on the year of implementation), and 1.1
billion euro in total for the period 2020-2030. However, there is a greater degree of
uncertainty in these figures when compared with the workings for Options 1, in light of
possible variance in the effectiveness of such publicly-run comparison tools.
The main implementation costs would fall upon national authorities who would be
charged with developing and managing energy comparison websites248
. Privately-run
comparison sites may also lose market share to comparison tools run by a government-
funded body, although these impacts are impossible to estimate.
Assuming:
- All 13 Member States without a state-run comparison tool (BG, CZ, DE, EE,
EL, HR, HU, IE LT, LV, NL, RO, SK) set one up to fulfil their obligations
under Option 2;
- The costs of each of these comparison websites for electricity and gas is 50%
higher than the cost of the Swedish NRA's electricity price comparison website,
which deals with electricity alone (Box 5)249
;
- A discount rate of 4% year on year;
then Option 2 would result in start-up costs of 2.09 million euros, running costs of
between EUR 1.36 million and EUR 2.96 million euros annually (depending on the
year of implementation), and a total cost of between 20.6 million euros and 28.9
million euros for the period 2020-2030.
As regards stakeholder views, Option 2 may not enjoy broad support amongst all
stakeholder groups and Member States. Whilst all stakeholders emphasize the
independence of comparison tools, and some explicitly support certification (Option 1),
none have voiced their exclusive support for a publicly run and funded energy comparison
tools.
Conclusion
Option 1 is the preferred option. By proportionately updating the existing acquis,
establishing a mechanism to proactively build consumer trust, and ensuring all EU
consumers have access to a comparison tool, it strikes the best balance between consumer
welfare and administrative impact. It also gives Member States control over whether they
feel a certification scheme or a publicly-run comparison tool best ensures consumer
engagement in their markets.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the preceding
pages, accrue predominantly to consumers who are engaged in the market, and in particular those who
compare offers using the Internet. Whilst reliable comparison tools will also increase consumer engagement
levels, and whilst the increased competition engendered by comparison tools will lead to more competitive
offers on the market, disengaged consumers and consumers who do not use the Internet, including consumers
who may be vulnerable, will not reap as many direct benefits from this policy intervention.
248
The costs to suppliers in terms of notifying such sites of their is not considered significant.
249
This is a conservative estimate given the significant labour cost differences between SE and these
Member States that would make setting up and operating a comparison website cheaper in other Member
States.
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Subsidiarity
Consumers are not taking full advantage of competition on energy markets due, in part, to
obstacles to switching. Well designed and implemented consumer policies with a European
dimension can enable consumers to make informed choices that reward competition, and
support the goal of sustainable and resource-efficient growth, whilst taking account of the
needs of all consumers. Increasing confidence and ensuring that unfair trading practices
do not bring a competitive advantage will also have a positive impact in terms of
stimulating growth.
Comparison websites are an effective means of reducing search costs for consumers and
presenting them with accurate price and market information. Although they have become
increasingly important in recent years, the majority of comparison websites are operated
for profit, leading to situations where their impartiality and the consumer interest may not
be ensured. Recent reports of unscrupulous practices have damaged consumer trust in
comparison websites, suggesting the need to boost consumer confidence in such tools.
The options here revolve around improving the accessibility and reliability of comparison
websites, both commercial and not-for-profit, through improved legislative guidance,
certification schemes and/or differing obligations on Member States to ensure the
availability of such websites. Similar legislative provisions on comparison tools already
exist in other sectorial legislation (i.e. financial sector with the 2014 Payment Accounts
Directive250
).
The legal basis for the legislative options proposed (Options 1 and 2) is therefore likely to
be Article 114 TFEU. This allows for the adoption of "measures for the approximation of
the provisions laid down by law, regulation or administrative action in Member States
which have as their object the establishment and functioning of the internal market". In
doing this, in accordance with Article 169 TFEU, the Commission will aim at ensuring a
high level of consumer protection.
Without EU action, the identified problems related to the lack of an EU-wide market will
continue to lead to consumer detriment.
Option 0+
These options would fulfil the subsidiarity principle as they do not involve legislative
change and the subsidiarity of the existing legislation has been assessed previously.
However, consumer protection will continue to be compromised as consumers will not
have the assurance of comparison tool independence or of full transparency of all offers
available on the market. This is because of shortcomings inherent in the existing
legislation.
250
Directive 2014/92/EU of the European Parliament and of the Council of 23 July 2014 on the
comparability of fees related to payment accounts, payment account switching and access to payment
accounts with basic features. Text with EEA relevance.
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Option 0+ would therefore not meet the proportionality principle as it would not achieve
the objective of the Article of the Treaty taken as their legal basis – the establishment and
functioning of the internal market.
Option 1
The principles of subsidiarity and proportionality would be best met through this Option
as it would concretely improve the functioning of the internal market and reduce levels of
consumer detriment, whilst leaving national authorities broad flexibility to tailor measures
to the characteristics of their markets and their available resources.
Option 2
The principles of subsidiarity and proportionality may not be respected in this Option as it
may be excessive in terms of the implied impact on certain Member State authorities who
would need to establish an independent body to provide a comparison tool service.
Moreover, it is not clear that customer mobility or consumer protection would improve
with the introduction of such a body in all Member States as the reliability and user-
friendliness of at least some private sector comparison tools may already be of a high
standard.
Stakeholders' opinions
Public Consultation
When asked to identify key factors influencing switching rates, 110 out of 237 respondents
to the Commission's Consultation on the Retail Energy Market251
stated that prices and
tariffs were too difficult to compare due to a lack of tools and/or due to contractual
conditions.
178 out of 237 agreed that ensuring the availability of web-based price comparison tools
would increase consumers' interest in comparing offers and switching to a different energy
supplier. 40 were neutral and 4 disagreed.
Only 32 out of 237 respondents agreed with the statement: "There is no need to encourage
switching". 98 disagreed and 90 were neutral.
National Regulatory Authorities
ACER has argued that having reliable web comparison tools in place (allowing
comprehensive and easy ways to compare suppliers) can facilitate consumer choice and
consumer engagement by addressing the perceived complexity of the switching process. It
has therefore recommended that: "To improve consumer switching behaviour and
awareness further, National Regulatory Authorities (NRAs) could become more actively
involved in ensuring that the prerequisites for switching, such as transparent and reliable
online price comparison tools and transparent energy invoices, are properly
implemented."
CEER252
sees price comparison tools as a crucial instrument to provide information to
251
Held from 22 to 17 April 2014. https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-
market
252
The Council of European Energy Regulators.
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electricity and gas customers. There are a range of routes to setting standards for
comparison tools. NRAs or another public body may establish their own comparison tools
or they may regulate private comparison tools. Alternatively, self-regulation by
comparison tools providers may be appropriate. Whatever the route, CEER's position is
that it is important that comparison tools are independent from energy supply companies,
that they are accurate and that they ideally present the full range of offers available.
In 2012, following an extensive consultation process, CEER published 14
recommendations covering the following aspects of comparison tools in the energy sector:
Independence; transparency; exhaustiveness; clarity and comprehensibility; correctness
and accuracy; user-friendliness; accessibility; and empowering customers253
.
Ombudsmen
According to NEON, the National Energy Ombudsmen Network, regulators are best
placed to define the criteria of transparency and reliability of price comparisons tools and
to assess them. NEON insisted on referring to the 2012 CEER Guidelines of Good Practice
on Price Comparison Tools and the 15 recommendations they contain254
.
Bodies in charge of providing information to consumers (single point of contact) and
organisations in charge of alternative dispute resolution (or an independent ombudsman),
as well as consumer associations (i.e. impartial bodies with no advertising or consumer
champion role, thanks to their independence from suppliers) are according to NEON best
placed to develop neutral and reliable tools. This may also be the case of private
companies, as long as they do not favour certain suppliers that would fund them or with
which they have special agreements. For all tools implemented, an annual auditing of the
regulator would be necessary: the list of approved comparison tools and a summary of the
auditing may be published and accessible online.
If the regulator sets up a price comparison tool, another authority should be responsible for
carrying out auditing, even from another Member State (peer review).
Consumer Groups
BEUC believes it is essential that the consumer gets clear and independent information on
different offers. Regardless of who is running the comparison website, it must be ensured
that the information consumers get is impartial, up to date, accurate and provided in a user
friendly way and free of charge. The comparison tool should also enable consumers to
compare their current contract with new offers in an easy way.
At the same time, BEUC strongly believes there should be at least one independent
comparison tool for electricity and gas services in every Member State. In order to secure
the success of such a comparison tool, it is paramount to secure also a legal basis for
collection of price data. In addition, whilst comparison tools are increasingly used by
253
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf
254
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf
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consumers, the proliferation of comparison tools and the influence they can have on
consumers’ decisions have given rise to concerns about their trustworthiness.
According to BEUC, if the transparency and reliability of comparison tools is not
guaranteed, if the full scale and high quality of the information they provide is not ensured
or if they do not comply with existing legislation, comparison tools can become a source
of consumer detriment and risk misleading and thereby undermining consumers’ trust in
the market255
.
According to Citizens' Advice (UK) comparison tools can be operated by a regulator, a
consumer body or a private business that is appropriately regulated. The focus should
rather be on the establishment of key principles to the effect that the sites display
information in a way that is accurate, consistent, transparent, comprehensive and unbiased.
The tool must have all tariff data available from all suppliers in the market and include
information about termination fees, etc. The comparison should be based on the customer's
actual usage.
Suppliers
In their contribution to the discussions within the Citizens' Energy Forum in 2016,
EURELECTRIC considered that it is the task of regulators to make sure that comparison
tools are neutral, do not limit innovation and do not favour any specific supplier, either
directly (for example, if they collect different fees from different suppliers) or indirectly
(for example, if their IT systems are not able to process all offers). EURELECTRIC and
its members have repeatedly argued in favour of certifying comparison tool with e.g. a
trust mark from the regulator, and stressed their full support for the Commission’s
initiatives to work with NRAs to develop transparency and reliability criteria for
comparison tools where these do not exist yet.
Eurogas also welcomed the role that price comparison websites can play in national
energy markets, and argued that consumers should have access to such price comparison
services. For Eurogas, both price comparison websites operated by commercial entities as
well as non-commercial bodies operated by the NRA can provide "independent" services
to consumers. In order to ensure that this is the case, Eurogas supports an accreditation
system for such websites. According to Eurogas, experience in Member-States such as the
UK and the Netherlands suggests that price comparison websites develop over time, with
private companies establishing comparison services.
Whatever approach is adopted, Eurogas states that the funding of these sites should be
transparent. Regulation should be proportionate and would benefit from referring to the
2012 CEER Guidelines of Good Practice on Price Comparison Tools256
. Moreover, for
recommendations and best practices on price comparison tools, reference should be made
255
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
256
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf
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to the 2012 Report of the CEF Working Group on Transparency in EU Retail Energy
Markets257
.
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Parliament's Committee on Industry, Research and Energy
(ITRE): "Recommends developing guidelines for price comparison tools to ensure that
consumers can access independent, up-to-date and understandable comparison tools;
believes Member States should consider developing accreditation schemes covering all
price comparison tools, in line with CEER guidelines."
In addition, ITRE: "Recommends the creation of new platforms to serve as independent
[comparison tools] to provide greater clarity to consumers on billing; recommends that
such independent platforms provide consumers with information on the percentage share
of energy sources used and the different taxes, levies and add-ons contained in energy
tariffs in a comparable way to empower the consumer to easily seek more suitable offers
in terms of price, quality and sustainability; suggests that this role could be assumed by
existing bodies such as national energy departments, regulators or consumer
organisations; recommends the development of at least one such independent price
comparison tool per Member State."
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Parliament's Committee on the Internal Market and
Consumer Protection (IMCO) called on the Commission: "to ensure the implementation
of the Unfair Commercial Practices Directive and for better cooperation between national
authorities of Member States investigating such practices". It also welcomed "the
Commission’s intention to consider incorporating laws specifically concerning energy into
the Annex to the Regulation on Consumer Protection Cooperation", although this measure
was not eventually pursued by the Commission.
IMCO also called for: "European Union guidelines on independent, up-to-date and easy-
to-use price comparison tools, in particular to improve transparency, reliability, and
competition between all market players and to make it accessible and easier for consumers
to compare offers including types of contracts, prices and types of energy sources." It
finally supported: "access for all consumers to at least one price comparison tool for
energy services."
The Committee of the Regions
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Committee of the Regions supports the idea of ensuring that
each consumer has access to at least one independent and verified comparison tool.
According to the Committee, these comparators must be clear, comprehensive, trustworthy
and independent, easy to use and free of charge. They should allow existing contracts to
be compared with offers available on the market. Whereas suppliers tend to diversify their
offers by including services in energy supply contracts, comparison tools must make it
257
https://ec.europa.eu/energy/sites/ener/files/documents/2012111314_citizen_forum_meeting_working_gr
oup_report.pdf
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possible to compare the different "packages" on offer, while at the same time enabling the
"supply" element of the various packages to be compared on its own.
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7.6. Improving billing information
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Summary table
Objective: Ensuring that all consumer bills prominently display a minimum set of information that is essential to actively participating in the market.
Option: 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Commission recommendation on billing
information
More detailed legal requirements on the key
information to be included in bills
A fully standardized 'comparability box' in
bills
Pros:
- 77% of energy consumers agree or strongly
agree that bills are "easy and clear to
understand".
- Allows 'natural experiments' and other
innovation on the design of billing information
to be developed by Member State.
- Recent (2014) transposition of the EED means
premature to address information on energy
consumption and costs.
Pros:
- Low administrative impact
- Gives Member State significant
flexibility to adapt their requirements to
national conditions.
- Allows best practices to further
develop.
Pros:
- Ensures that the minimum baseline of
existing practices is clarified and raised.
- Allows best practices to further develop,
albeit less than Option 0.
- Improves comparability and portability of
information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
- Bill design left free to innovation.
Pros:
- Highest legal clarity and comparability of
offers and bills.
- A level playing field for all consumers and
suppliers across the EU.
- Very little leeway for suppliers to differently
interpret the legislation with regards to the
presentation of information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
Cons:
- Poor consumer awareness of market-relevant
information can be expected to continue.
- Does not respond to stakeholder feedback on
need to ensure minimum standards.
Cons:
- A recommendation is unenforceable
and may be ignored by Member
State/utilities.
- Poor consumer awareness of market-
relevant information can be expected to
continue.
- Does not respond to stakeholder
feedback on need to ensure minimum
standards.
Cons:
- Limits innovation around certain bill
elements.
- Remaining leeway in interpreting legal
articles may lead to implementation and
enforcement difficulties.
Cons:
- Challenging to devise standard presentation
which can accommodate differences between
national markets.
- Highest administrative impact.
- Prescriptive approach prevents beneficial
innovation.
- Difficult to adapt bills to evolving
technologies and consumer preferences.
Most suitable option(s): Option 1 is the preferred option as it likely to leads to significant economic benefits and increased consumer surplus without significant administrative costs or the
risk of overly-prescriptive legislation at the EU level.
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Description of the baseline
The evidence presented in this Annex draws extensively on survey data, as well as data
from a mystery shopping exercise. The aim of the mystery shopping exercise was to
replicate, as closely as possible, real consumers’ experiences across 10 Member States258
selected to cover North, West, South and East Europe countries. A total of 4,000
evaluations were completed between 11 December 2014 and 18 March 2015259
. Whilst
data from the mystery shopping exercise is non-exhaustive, the methodology enables the
controlled sampling of a very large topic area260
, as well as providing insights that would
not be apparent in a desktop evaluation of legislation and bills. Using a behavioural
research approach rather than a traditional survey allowed us to identify what people
actually do, rather than what they say they do.
Energy bills and annual statements be they paper or digital, are the most likely regular
communications from suppliers to be noticed and read by consumers. They are therefore
an important means through which consumers get information on their interaction with the
market. As well as data on consumption and costs, they can also convey a host of other
material which helps consumers to compare their current deal with other offers – the name
and duration of their contract, for example.
The Electricity and Gas Directives contain the following key provisions related to metering
and billing:
- Article 3 Billing and promotional material
- 3(3) Access to comparable and transparent supply options (Electricity only)
- 3(5)/3(6) Access to consumption data
- 3(9) Disclosure of the overall fuel mix and environmental impact of the
supplier (Electricity only)
- Annex I Consumer protection
- 1.c) The transparency of applicable prices and tariffs
- 1.d) Consumer payment methods
- 1.i) Frequency of information on consumption and costs
- 2. Intelligent metering systems (smart meter roll-out)
In addition, The Energy Efficiency Directive contains the following key provisions:
- Article10 Billing information (in conjunction with Annex VII)
- 10(1) Consumption based billing (information) requirement in general
(incl. as regards minimum frequency)
- 10(2) Requirements on consumption information from smart meters
- 10(3) General information and billing requirements pertinent to costs,
consumption and payment
- Article 11 Cost of metering and billing information
- 11(1) Metering and billing generally free of charges
258
The Czech Republic, France, Germany, Italy, Lithuania, Poland, Slovenia, Spain, Sweden and the UK.
259
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
260
For example, there were over 400 electricity and gas supply offers in Berlin alone in 2014 (source:
ACER Database), making a comprehensive examination of all supply offers in the EU28 impracticable.
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Whereas the EU acquis contains a relatively small number of general measures on energy
billing, all Member States have legislation with further billing requirements. For example,
UK electricity and gas suppliers must follow over 70 pages of rules on the information in
bills as part of their current licensing requirements. In recognition of the likelihood of being
overly prescriptive at present, the UK NRA is undertaking a pilot project to improve billing
in the interest of consumers.
Box 1: Select requirements for UK domestic energy bills261
The following information must be grouped together, in a box, distinct from other information and included
on page one of the Bill:
- The standardised title “Could you pay less?”
- Information on cheaper tariffs offered by the supplier and the savings available if the consumer were to
switch.
- A Personal Projection* for the consumer's current tariff.
- A signpost to further tariff information.
- A standardised switching reminder “Remember – it might be worth thinking about switching your tariff
or supplier”.
The following information must be grouped together and included on page two of the Bill, in a box, distinct
from other information, in the following order:
- The standardised title “About Your Tariff”.
- The name of the customer's fuel, current tariff, payment method, any applicable tariff end date, exit fees
and the customer's personalised usage in the last 12 months.
The following information must be provided anywhere on a bill:
- The standardised title “About Your TCR”**.
- The TCR for the customer's current tariff.
- A signpost to where to find independent advice on switching supplier.
* The Personal Projection is a standardised methodology that uses a consumer's actual or estimated
consumption to estimate their projected cost for a particular tariff for the next year.
** The TCR or 'Tariff Comparison Rate' is used to assist consumers to make an initial comparison of
alternative tariffs. It is similar in nature to the Annual Percentage Rate used to describe savings, loan and
credit agreements.
Table 1 under presents an overview of billing practices and regulation per country. There
is a large variation in how countries choose to approach the subject, in particular with
regards to the extent to which the content of bills is specifically defined in national
legislation. Three broad approaches can be identified:
261
"The Retail Market Review – Final domestic proposals Consultation on policy effect and draft licence
conditions", (2013) Ofgem, pp. 71-108, 130-163
https://www.ofgem.gov.uk/sites/default/files/docs/2013/03/the-retail-market-review---final-domestic-
proposals.pdf. See also Gas and Electricity Markets Authority, 'Standard conditions of electricity supply
licence'
https://epr.ofgem.gov.uk//Content/Documents/Electricity%20Supply%20Standard%20Licence%20Co
nditions%20Consolidated%20-%20Current%20Version.pdf
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- Highly prescriptive (HP) approaches relying on legal instruments or resolutions,
which request a large amount of detail and/or give very specific instructions on
what information to provide in electricity bills.
- Legislation which specifies the main information (MI) that must be included in
bills, which is subsequently reinforced by guidance from the regulator (in terms of
mandatory information and format, or best practice guidance).
- Legislation that specifies the main information, but leaves electricity providers
broad freedom (BF) to communicate this within their own format.
In the following table, billing practices in each country are described, noting what are
considered to be a highly prescriptive approach (HP), an approach enforcing
communication of main information (MI) and, finally, an approach that allows broad
freedom (BF).
Table 1: Billing practices and regulation per country262
Austria (MI) Article 81 of EIWOG specifies which information should be presented on the electricity
bill. This provision is further detailed by ordinances from the regulator, in which
suggestions are given as to how to present the mandatory information, including the energy
sources breakdown and the price components. The contents of the documents (e.g.
electricity bill, contract, etc.) are detailed not only in the Electricity Act, but also in the
Renewable Energy Act, the System Charges Order, the Electricity Duty Act, as well as in
individual Federal states legislation. The ‘DAVID-VO’ Ordinance (Articles 1-5) specifies
the information that electricity suppliers must give to customers.
Belgium (HP) Law April, 29th 1999 ‘Loi relative à l'organisation du marché de l'électricite’ details the
mandatory information to be present in a consumer’s bill. The information to be presented
in the bill is highly regulated, with 10 mandatory headings and many mandatory sub-
headings which detail the information to be provided.
Bulgaria (BF) The Bulgarian Consumer Protection Act (Art. 4, Par. 1) outlines a minimum set of
requirements for information to be provided to the customer such as: (1) information on the
composition, (2) the supplier’s contact details, (3) the trader’s complaint handling process,
and 4) arrangements for payment.
Croatia (MI) Articles 49 and 63 of the Act on Electricity Market (Official Gazette, no. 22/13, 95/15 and
102/15) regulate billing. In Croatia, regulations specify that the supplier needs to deliver an
electricity bill that contains the following elements: the share of the price that is freely
negotiated, the share that is regulated and fees and other charges prescribed by special
regulations.
Cyprus (MI) Article 91 (1)(d)(iv) and Article 93 (1)(j) of the Electricity Law 206(Ι)/2015 regulate how
the consumption of electricity should be communicated to consumers. The tariffs of the
main energy provider are regulated by the Cyprus Energy Regulatory Authority (CERA)
and they can be found on the website of the Electricity Authority of Cyprus (EAC).
Czech
Republic
(DF)
Bills for electricity, gas, heat supply and related services are governed by Act nr. 458/2000
Coll. in articles 11(a) and 98a. Electricity suppliers are to publish the conditions and price
of electricity supply for households and residential customers in a way that can be accessed
remotely. If increasing the prices for the supply of electricity, the supplier is obliged to
notify the consumer in advance. In the case of electricity and gas, outstanding charges are
billed at least once a year.
Denmark
(MI)
Regulation of billing information is implemented in Executive Order no.486 of 2007 on
electricity billing. However, the Danish Energy Regulatory Authority has presented an
executive order which gives consumers the possibility to receive a simplified bill. The
purpose of this order is to give consumers a better understanding of the price elements and
262
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
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an incentive to be active on the energy market. This order was implemented in Danish law
in October 2015.
Estonia (MI) Electricity Market Act §75 stipulates the following: “the seller shall submit an invoice for
the electricity consumed to the customer once a month, unless agreed otherwise with the
customer”. It is mandatory for suppliers to include information not just on consumption but
also on emissions and waste (nuclear and oil shale) as well as dispute resolution options.
Finland (MI) Part III, Ch. 9, 69 § of the Electricity Market Act (588/2013) outlines the legal requirements
with regards to billing imposed by the electricity provider. In the bill, the provider is to
include details on how the price is broken down, information on the contract’s duration and
which dispute-solving tools consumers have at their disposal.
France (HP) Article 4 of the Regulation 18 April 2012 covers electricity or natural gas bills, their
payment modalities and reimbursement of overpayment (i.e. bill based on an estimation of
the consumption). The bill must include information on over 16 different headings. The
website ‘Energie info’, made available by the National Energy Ombudsman, illustrates and
explains this mandatory content to consumers.
Germany
(MI)
The right to receive clear information on one’s energy contract before signing, and to be
informed in advance if any changes are made to the contract, are provided for within
German law (article 41 EnWG). The EnWG (Section IV art. 40) specifies the content that
should be provided to consumers on their electricity bills. The German Institute for
Transparency on Energy (DIFET) produces certificates for those suppliers that provide
consumer-friendly bills.
Greece (BF) The new Code of Electricity Supply regulates the tariffs of electricity suppliers.
Specifically, this code describes what must be included in the bill and how the bill must be
broken down into three different elements: (1) regulated charges; (2) competitive charges
or supply charges; and (2) other charges.
Hungary (HP) Law 2013. évi CLXXXVIII. törvény az egységes közszolgáltatói számlaképről regulates the
content of bills. The law gives actual examples of the minimal information necessary on
each bill and also gives examples as to which elements may be changed or added without
infraction. The law also imposes such details as fonts and font sizes and provides in its
annexes a detailed example of the respective bill in its actual detail. Additionally to the law,
the electricity suppliers also regularly provide a dedicated Section on how to read the
electricity bill.
Ireland (MI) Statutory instruments S.I. No. 426/2014 Part 4, Art. 6, Art. 7 and S.I. No. 463/2011, Art. 9,
regulate the communication of charges and consumption information to electricity
consumers in Ireland. Under Irish law, suppliers must also inform customers of upcoming
price changes at least one month before a price change comes into effect.
Italy (MI) D.Lgs 93/11 Art. 43(2); L 125/07 Art. 1(6) and Art. 1(5) legislate the communication of
charges and consumption information. Consumers should be informed of the components
relating to supply cost (servizi di vendita), network cost (servizi di rete), general system
charges (oneri generali di sistema), and taxes (VAT and other consumption taxes). The
regulator has set up several tools in order to help the consumer understand his bill, most
notably a dedicated webpage ”Your Bill Explained” (la bolletta spiegata) and a consumer
help-desk (lo Sportello per il Consumatore).
Latvia (MI) According to Art. 31 3° of Electricity Market Law, the Public Utilities Commission (PUC)
shall determine what kind of information and to what extent electricity supplier shall
include in their bills and informative materials that are issued to the consumer. The
regulations of the PUC determines that a bill shall include at least the electricity amount in
kWh supplied in billing period, the amount charged for consumed electricity in euros and
the average electricity price in euro per kWh during the billing period and fees for
electricity distribution system services, other additional services and the mandatory
procurements components and total fees for the billing period for consumers and other end-
users to whom shall be issued invoices regarding electricity service supply.
Lithuania
(BF)
Law on Energy of the Republic of Lithuania No. IX-884 and Law on Electricity of the
Republic of Lithuania No VIII-1881. Article 31 regulate the communication of charges and
consumption information to electricity consumers in Lithuania, as well as contractual
conditions and changes to contracts. The consumer is entitled to receive information on
conditions of service and electricity prices and tariffs, reports on prices, contract terms,
conclusion and termination conditions.
Luxembourg
(BF)
Article 2(5) of the Law of 1 August 2007 regulates the communication of charges and
consumption information to electricity consumers in Luxembourg, as well as contractual
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terms. With respect to billing, the law states that electricity providers must transmit to
residential customers transparent information on tariffs and prices.
Malta (MI) Electricity Market Regulations (S.L. 545.16), Art. 8(3) regulates billing. Bills issued by
Enemalta Corporation, Malta’s electricity supplier, must include contact details of its
subcontractor, ARMS Ltd, which is the company responsible for meter reading, billing,
debt collections and customer care services. Households should receive bills calculated on
actual consumption at least every six months. For households with a smart meter, these
bills based on actual readings are more frequent. All bills show a breakdown of the price
calculation, the total electricity consumption for that period as well as the average daily
energy consumption, relevant tariffs and CO2 emissions.
Netherlands
(MI)
The Electricity Act, article 95, details the mandatory information to be provided on an
energy bill and some associations provide recommendations for data presentation. The
breakdown of an energy bill concerns supply costs (“leveringskosten”), network costs and
metering costs, and then taxes (“Belasting”). While using green energy, some taxes are
refunded (“Belastingvermindering”).
Poland (MI) The Energy Law, Art. 5. 6a - 6c. regulates the communication of charges and consumption
information to electricity consumers in Poland. Electricity suppliers are to inform
consumers about the fuel supply mix used in the previous calendar year and about a place
where information is available about the impact of the production of energy on the
environment (at a minimum in terms of carbon dioxide emissions and radioactive waste
created). Electricity suppliers must also inform consumers about the amount consumed in
the previous year and the place where information is available about the average electricity
consumption for each connection group of recipients, energy efficiency improvement
measures and the technical characteristics of energy-efficient appliances.
Portugal (BF) Art. 54 d) and Art.55 c) and d) of Decree Law of 15 February 2006 regulate the
communication of charges and consumption information to electricity consumers in
Portugal. Under the law, consumers are entitled full and adequate information to enable
their participation in the electricity market, access information in a transparent and non-
discriminatory manner on applicable prices and tariffs, as well as complete and adequate
information in order to promote energy efficiency and the rational use of resources.
Romania (HP) Law 123/2012 (modified in 2014) ART.62 (1) h9
) and art. 145 (4) p) and Law 123/2012
(modified in 2014) ART. 66 (1),(2) regulate the content of bills. The Energy Authority
ANRE has made available to the consumer an explanatory sample of the components that
have to be included in the bill. This model has been adopted by electricity suppliers, who
can also opt to display the same document at their websites, in order to inform consumers
about the contents of their bill.
Slovakia (MI) The supplier of electricity and gas is, according to the § 17 article 14 of the Law 251/2012,
obliged to inform the customer on the invoice or attached material about the particular
components of the energy supply including the unit price. Information about the
composition of the price component has to include the unit price especially for electricity
purchase including the commercial activity of the supplier, distribution, losses during
distribution, system services, system operation and taxes.
Slovenia (MI) Beside standard items that must be included in every invoice issued in Slovenia that are
stipulated by the Value Added Tax Act (invoice date, number, invoice issuer’s contact
details, amounts billed, VAT rate,…), consumers also have to receive certain information
in their electricity bills, stipulated within Article 42 of the Energy Act, including the
proportion of energy source that supplier used in preceding year in a way comparison
between different suppliers can be made, the reference source where publicly available data
on environmental impacts, expressed in CO2 emissions and amounts of radioactive waste
resulting from the electricity production in the preceding year, and consumers’ rights
related to dispute resolution.
Spain (HP) Law 24/2013 establishes the type of information that should be included in an electricity
bill. This format is mandatory for the suppliers of last resort. The details of the information
are formally listed in the resolution N.5655 of 23 May 2014 of the Ministry for the Industry,
Energy and Tourism. The resolution illustrates in its annex a template to be followed when
producing electricity bills, showing in explanatory graphs and in detailed tables the
mandatory information and its granularity.
Sweden (BF) The Electricity Act chapter 8, §14-16 specifies that an electricity supplier’s billing shall be
clear. It shall contain information on the measured consumption and current electricity
prices that the billing shall be based on. The Swedish Energy Markets Inspectorate specifies
in detail what shall be contained in electricity bills. The electricity cost consists of two
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parts: (1) a payment to the grid operator to stay connected and (2) payment for the actual
electricity consumption and the electricity cost.
UK (MI) The consumers’ right to accurate consumption information is captured in Condition 31A of
the Standard Licence which makes it incumbent on suppliers to provide customers with
electricity consumption information in each bill (or, within the space of 30 days from a
notice of increase in charges in cases where the latter is issued). In addition, suppliers must
send an annual statement to all customers in a pre-defined format. Schedule 2ZB to the
Electricity Act stipulates that licence-exempt suppliers must also provide consumption data
to customers on an annual basis. Under Condition 12 of the Standard Licence, suppliers
must take meter readings at least once every two years. Condition 21B of the Standard
Licence allows customers to read their own meters as often as they choose. Suppliers are
to reflect that reading in the subsequent bill. The structure of the bill is not fixed by any
legislation.
In addition to EU and national legislative requirements, suppliers communicate and present
information in different ways as a part of their non-price competition with other suppliers.
For example, information may be presented in a certain format for branding purposes, or
to target different customers with different kinds and levels of information to increase
consumer satisfaction.
As a result of these three different factors – EU legislation, national legislation and
commercial competition – there is therefore currently a broad divergence in Member States
with regards to the individual elements in electricity and gas consumer bills and the total
amount of information in these bills.
Figure 1 below from ACER summarizes the information provided to household customers
on their bills. It includes general billing requirements put forward in Article 3 and Annex
I of the Electricity and Gas Directives (for example, information on the single point of
contact), as well as items not covered by EU law (price comparison tools). Whereas
customers in the majority of Member States are currently provided with information on the
consumption period, actual and/or estimated consumption, and a breakdown of the price,
there is a greater diversity of national practices with regards to other potentially beneficial
information, such as switching information, information about price comparison tools, and
the duration of the contract.
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Figure 1: Information on household customer bills in Member States – 2014
Source: CEER Database, National Indicators (2014-2015)
The results of a mystery shopping exercise on the information in energy bills covering ten
representative Member States263
provide a more detailed impression of the differences in
billing practices within the EU. Mystery shoppers were instructed to analyse one of their
own monthly, bi-monthly or quarterly electricity bills for a number of information
elements identified as best practices by the Citizens' Energy Forum's Working Group on
Billing264
(Table 2) as well as a number of information elements addressed (although not
always required) by the current Electricity Directive (Table 3)265
. The exercise was carried
out between 11 December 2014 and 18 March 2015.
263
The Czech Republic, France, Germany, Italy, Lithuania, Poland, Slovenia, Spain, Sweden and the UK.
264
"Implementation of EC Good Practice Guidance for Billing", (2010) CEER, http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b1/E10-CEM-36-03_EC%20billing%20guidance_8-Sept-2010.pdf.
265
https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-billing_energy_data.pdf
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Table 2: Information included on an electricity bill in a sample of ten Member States - I266
Country
Item Item in "billing" evaluation
sheet
% who
found item
on their bill
(total)
CZ DE ES FR IT LT267
PL SE SI UK
Supplier's name Provider’s name 99% 96% 100% 100% 100% 100% 88% 100% 100% 100% 100%
Contact details (including
their helpline and emergency number)
Telephone number of customer
service/helpline
96% 92% 100% 100% 100% 100% 80% 93% 100% 100% 97%
Postal address of provider 94% 92% 100% 97% 100% 100% 60% 100% 96% 100% 83%
Email address of provider 69% 92% 95% 80% 27% 37% 40% 75% 84% 96% 60%
Emergency number (e.g. to call
in the event of an electrical
emergency or power outage)
59% 68% 8% 97% 87% 93% 28% 35% 64% 40% 87%
The duration of the contract Duration of the contract (e.g. 24
months)
22% 8% 50% 27% 17% 10% 0% 5% 40% 4% 50%
The deadline for informing the supplier about
switching to another supplier
The period of notice to
terminate your electricity
contract (e.g. 30 days before the
intended termination date)
19% 4% 50% 0% 57% 0% 12% 0% 28% 0% 27%
The tariff name Tariff name/plan (e.g. 'Day &
Night Fix')
80% 84% 65% 57% 87% 93% 60% 93% 80% 76% 100%
(A reference to) a clear price breakdown for the
tariff (the base price plus all other charges and
taxes)
A detailed price breakdown for
your tariff (e.g. division of total
price in base price, network
charge, etc.)
79% 92% 65% 100% 83% 93% 8% 88% 92% 96% 73%
266
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the EU" (2016) European Commission.
267
Lithuania stands out as the country where mystery shoppers were the least likely to find each of the items on their bill. Mystery shoppers in Lithuania (note: all shoppers were clients
of Lesto) reported that they do not receive an electricity bill; they declare usage themselves online (via www.manoelektra.lt - a site dedicated to Lesto customers) or by means of a
paper bill book.
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Country
Item Item in "billing" evaluation
sheet
% who
found item
on their bill
(total)
CZ DE ES FR IT LT267
PL SE SI UK
The base price of one energy unit (in kilowatt
hours or kWh) for the selected tariff
Base price per kWh of your
tariff
82% 68% 65% 87% 93% 83% 68% 83% 92% 88% 93%
The switching code Switching code/meter
identification (EAN or MPAN
code; a unique code for your
electricity meter)
73% 96% 58% 87% 87% 67% 44% 78% 76% 72% 67%
The amount to be paid, for which billing period,
by when and how
Amount to be paid 97% 100% 100% 97% 97% 100% 72% 100% 100% 100% 97%
Billing period (e.g. 15
November – 14 December
2014)
95% 96% 90% 100% 97% 100% 80% 93% 100% 100% 97%
Payment method (e.g. direct
deposit, cheque, bank transfer)
84% 88% 100% 87% 87% 87% 64% 65% 92% 64% 100%
Clear information on how this amount has been
calculated: is it based on an actual meter reading
or estimated only?
% of shoppers stating that it not
clear how the billing amount
was calculated
5% 4% 18% 3% 0% 0% 8% 3% 4% 4% 3%
For calculations based on actual consumption:
meter readings and consumption during the
billing period (measured in kilowatt hours or
kWh)
Details about consumption
during billing period (in kWh)
89% 95% 67% 96% 100% 100% 73% 95% 87% 91% 95%
Value of the meter reading at
the end of the billing period
89% 90% 93% 96% 86% 88% 73% 95% 87% 82% 95%
Value of the meter reading at
the beginning of the billing
period
88% 95% 93% 96% 86% 88% 73% 86% 83% 91% 90%
Where does the energy come from, how is it
generated, how environment friendly is it ("the
fuel mix")
Fuel mix/energy sources (e.g.
wind power, biomass)
32% 48% 45% 20% 47% 43% 0% 18% 52% 40% 13%
Information on how to get tips on saving energy
(e.g. a link to a website)
Tips on saving energy (e.g. link
to a website)
26% 8% 48% 17% 23% 20% 36% 8% 24% 20% 57%
Information on how to obtain the bill in
alternative formats (e.g. in large print) for
consumers with disabilities
Information on how to obtain
your bill in alternative format
(e.g. paper/online, large print)
24% 16% 8% 23% 27% 53% 28% 5% 20% 16% 50%
Base (note: figures in grey are based on a smaller sample): 300 25 40 30 30 30 25 40 25 25 30
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Table 3: Information included on an electricity bill in a sample of ten Member States - II268
Country
Item Item in "billing" evaluation sheet
% who found item
on their bill (total)
CZ DE ES FR IT LT PL SE SI UK
The contribution of each energy source to the overall fuel
mix of the supplier over the preceding year
13a. Fuel mix/energy sources (e.g. wind power,
biomass)
32% 48% 45% 20% 47% 43% 0% 18% 52% 40% 13%
Information concerning the consumer's rights as regards
the means of dispute settlement available to them in the
event of a dispute
8b. National contact information point (or single point
of contact where you can obtain information about your
energy rights)
28% 44% 43% 33% 43% 30% 4% 3% 16% 12% 53%
8c. An energy mediator or third-party assistance 23% 36% 45% 23% 57% 0% 0% 3% 12% 0% 50%
Base: 300 25 40 30 30 30 25 40 25 25 30
268
Shoppers were instructed to analyse a monthly or quarterly bill. In the Czech Republic and Germany, a considerable number of shoppers reported that they only receive an annual
bill from their electricity company. In these countries, 88% (n=22) and 50% (n=20), respectively, of shoppers analysed an annual bill. "Second Consumer Market Study on the
functioning of retail electricity markets for consumers in the EU" (2016) European Commission.
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The results show a large variation across countries for selected items; for example,
information about the period of notice to terminate a contract was not found on bills in
Italy, Poland, Slovenia and Spain, while in Germany and France, at least half of shoppers
had found such information on their bill (50% and 57%, respectively). These variations
may reflect national differences in consumer preferences and the characteristics of local
markets, as reflected in Member State rules and discretionary billing practices by suppliers.
In addition, Table 3 illustrates the possible bad application of certain EU requirements.
Only 28% of mystery shoppers (including experts) were able to find a contact point where
they could obtain information about their energy rights, as required under Article 3(9)(c)
of the Electricity and Gas Directives269
. In addition, Article 3(9)(a) of the Electricity
Directive requires suppliers to specify the contribution of each energy source to the overall
fuel mix of the supplier over the preceding year in or with consumer bills270
. However,
more than a third (35%) of mystery shoppers in the same study disagreed that their
electricity company informed them about how the electricity they used was produced
(scores 0 to 4 on a scale to 10)271
.
As transposition checks for the directives do not indicate particular irregularities around
these articles. This points to possible interpretation issues or the bad application of the
relevant measures by national authorities.
269'
'Member States shall ensure that electricity suppliers specify in or with the bills and in promotional
materials made available to final customers… the contribution of each energy source to the overall fuel
mix of the supplier over the preceding year in a comprehensible and, at a national level, clearly
comparable manner…'
270
'Member States shall ensure that electricity suppliers specify in or with the bills and in promotional
materials made available to final customers… information concerning their rights as regards the means
of dispute settlement available to them in the event of a dispute.'
271
This was the case for a majority of respondents in nine EU-28 countries, with the highest level of
disagreement observed in Bulgaria (78%). On the other end of the scale, the proportion of respondents
who “strongly agreed” (scores 8 to 10) that their electricity company informed them about how the
electricity they used was produced varied between 5% in Bulgaria and 46% in Austria. Germany joined
Austria at the higher end of the country ranking with 45% of respondents who “strongly agreed”.
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Figure 2: Information on household customer bills in Member States – 2014
(number of information elements)
Source: CEER Database, National Indicators (2014-2015)
To illustrate another dimension of divergence, Figure 2 above shows information load in
consumer bills in different Member States. This can have a significant impact on
consumers' ability to comprehend their bills – another issue flagged up by stakeholders and
confirmed by a Commission behavioural experiment that showed that superfluous
information in energy bills made it difficult for consumers to understand them (Figure 3).
Figure 3: Performance in bill comprehension task: standard bill vs standard bill with
additional information
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
To summarize, there is currently a broad divergence in Member States, both with regards
to the individual elements in consumer bills and the total amount of information in these
bills. The widespread divergence in national practices reflects differences in national
legislation and marketing by suppliers, which are themselves a function of consumer
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preferences and the characteristics of local markets. To a more limited extent, the
divergence may also reflect the bad application of certain requirements of the Electricity
and Gas Directives, particularly EU requirements on information on consumer rights and
energy sources.
Deficiencies of the current legislation
As addressed in more detail in Section 7.1.1 and Annex V of the Evaluation, the Electricity
and Gas Directives grant consumers the right to comparable and transparent supply
options. They also state that consumers must be properly informed of their actual energy
consumption and costs frequently enough to regulate their consumption. Building on these
general provisions, the Energy Efficiency Directive puts in place requirements on the
frequency of bills and the presentation of cost and consumption information in bills.
One of the major objectives of the Articles in the Electricity and Gas Directives relevant
to billing was enabling easier and more effective consumer choice272
. There exist various
data that help us understand how EU consumers perceive their energy bills and the extent
to which their bills are building awareness about energy use. These data are summarised
in the remainder of this Section.
Consumer organisations responding to the latest ACER Market Monitoring Report stated
that the average electricity and gas consumer in their countries is only able to compare
prices to a limited extent. The average score was 4.8 and 5.0 on a scale from 1 to 10 for
electricity and gas respectively273
.
These mediocre figures are backed by the 2016 Electricity Study that found that one in five
consumers surveyed still disagree that the electricity bills of their electricity company were
easy and clear to understand (Figure 4) – note the disparity in individual Member States
concerning the level of understanding with Bulgaria performing worst and Cyprus
performing best). This effect was even more pronounced among mystery shoppers from
ten Member States who were quizzed with their current bills to hand. Here, between 20
and 54% of respondents disagreed with the statement “My bill is easy to understand”
(Figure 5)274
.
272
Boost competition on retail markets and create consumer incentives to save energy were other major
objectives. See the Thematic Evaluation on Metering and billing.
273
"Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015.
274
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
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Figure 4: Agreement with statement: “bills of my electrify company are easy and
clear to understand”, by country275
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
Figure 5: Agreement with the statement: “My bill is easy to understand”276
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
The complaints data collected through the European Consumer Complaints Registration
System indicates the largest share (28%) of consumer complaints reported to the
Commission between 2011 and 2016 were related to billing (Figure 6). Whilst the
complaints classified as relating to "unjustified" or "incorrect" invoicing/billing (10% of
all electricity and gas complaints) are most likely related to billing on estimated rather than
actual consumption277
, complaints about unclear invoices or bills make up around 1% of
all electricity and gas complaints in the system. The category 'other billing complaints'
relates to cases where users of the European Consumer Complaints Registration System
did not encode a sub-category, or where their specific complaint could not be categorised
according to the options presented below.
275
Question: "The following question deals with the quality of services offered in the electricity retail
market. Please indicate how much you agree or disagree with each of the following statements, using a
scale from 0 to 10, where 0 means that you “totally disagree” and 10 means that you “totally agree”:
Bills of [PROVIDER] are clear and easy to understand."
276
Agreement with the statement: “My bill is easy to understand.”
277
See Thematic Evaluation on Smart Metering.
20 24 23
15
28
13 14
7 8 3 8
44 40
33
35
24
13
29
23 28
30 23
4 4
3
3
3
7 3 8
12 8
10 10 8
30
12
13 12 10 10
8 12
13 18
12 20 22 33
44
17
38
10
8
7 6
7
4
23
3
12 12
20
10
20 13 13 10 4
13
13
LT
SE
UK
DE
SI
IT
Total
FR
CZ
ES
PL
Completely agree
Agree
Somewhat agree
Neither agree nor disagree
Somewhat disagree
Disagree
Completely disagree
Q14. To what extent do you agree with the following statement: y bill is easy to u dersta d ?
%, Base: all mystery shoppers
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Figure 6: Electricity and gas consumer complaints, 2011-2016
Source: DG JUST, European Consumer Complaints Registration System.
It therefore appears that whereas a significant percentage of EU consumers do indeed have
difficulties understanding their energy bill, problems directly related to bill clarity have
not led to a large number of consumer complaints compared with other issues such as back-
billing, unfair commercial practices, and contractual clauses. However, looking at
consumer complaints alone may be insufficient as complaint levels are influenced by
consumer awareness and expectations, both of which may be low when it comes to energy
bills.
Energy bills are the foremost means through which suppliers communicate with their
customers. As such, consumers' ability to correctly answer simple questions about their
own electricity use indirectly reveals the extent to which bills have been effective in
providing information that could facilitate effective consumer choice. Figure 7 under
shows that whereas the majority of EU consumers report that they know how much they
pay for electricity, fewer were aware of their consumption in terms of kWh, what type of
tariff they have, or their sources of electricity.
Whilst this finding may certainly reflect a lack of consumer interest in this information,
the information facilitates effective consumer choice by helping consumers identify the
best offer in the market and weigh the benefits of switching. Their omission from many
bills, as the data presented in Table 2 and Table 3 over illustrates, may therefore be
impeding the achievement of one of the stated objectives of the billing provisions in the
Electricity and Gas Directives.
Unfair Commercial
Practices
16%
Contracts and
sales
11%
Quality of service
8%
Provision of
services
7%
Price / Tariff
7%
Switching
1%
Other issues
22%
Incorrect bill
6%
Unjustified invoicing
4%
Debt collection
2%
Unclear bill
1% Non-issue of invoice
0%
Other billing complaints
15%
Billing
28%
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Figure 7: Self-reported awareness of electricity use278
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
To summarize, the analysis presented in this Section indicates that there is scope to
improve the extent to which the billing provisions in the Electricity and Gas Directives
facilitate consumer choice. To help consumers accurately assess information, the
legislation can provide some degree of standardisation to allow consumers to make
accurate comparisons between offers, which is difficult to achieve through the market
alone. Standardisation of some information can also be useful to build familiarity and help
consumers recognise or retain important information.
As Figure 8 under illustrates, the difference in price between offers in the market can be
significant, and so even marginal gains in consumers' ability to identify the best deal can
result in a significant impact on consumer savings.
278
Question: "Please indicate how much you agree or disagree with each of the following statements, using
a scale from 0 to 10, where 0 means that you “totally disagree” and 10 means that you “totally agree”."
42%
38%
30%
32%
16%
24%
26%
32%
34%
52%
4.9
5.2
5.8
5.7
7.1
I know how the electricity that I use is produced (e.g. nuclear
generation, wind, gas, solar, petroleum, coal, etc.)
I know how the price I pay for electricity is calculated
I know the main characteristics of the tariff I am on (e.g. whether
I am on a fixed or variable price, the use of renewable energy,
etc.)
I know how much electricity I use (per month, year or any other
frequency) in kWh
I know how much I pay for electricity (per month, year or any
other frequency)
Disagree (0-4) Strongly agree (8-10) Average
EU 28
2.3.1 self-reported awareness
Q1_1 to 5. Please indicate how much you agree or disagree with each of the following statements, using a scale from 0 to 10,
where ea s that you totally disagree a d ea s that you totally agree .
%, EU28, Base: all respondents
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Figure 8: Dispersion in the energy component of retail prices for households in
capitals – December 2014
Source: ACER Retail Database (November–December 2014) and ACER calculations.
Presentation of the options
Option 0: BAU with stronger enforcement
Whilst no additional legislation is proposed, the Commission actively follows up evidence
suggesting possible cases of the bad application of EU law by Member States uncovered
in the evaluation. Specifically, the following elements of the current legislation may not
be being adhered to in certain Member States:
- Article 3(9)(a) of the Electricity Directive, which requires suppliers to specify the
contribution of each energy source to the overall fuel mix of the supplier over the
preceding year in or with consumer bills;
- Article 3(9)(c) of the Electricity and Gas Directives, which requires suppliers to
include information on consumer rights in or with bills.
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Option 0+: Non-regulatory approach; Commission Recommendation on billing
information
This includes general principles such as:
- Making information which is essential for understanding the price which
consumers pay for the service prominent, clear and easy to read on the bill. One
way to achieve this is to present it in a standard "comparability box" that should
feature prominently on the bill and include all the key information that consumers
need to compare offers and switch suppliers.
- Ensuring that there is a link to a national authority competent to lead a billing
review process and information campaigns.
Option 1: More detailed legal requirements on the key information
Specifically, this includes:
- Requiring electricity and gas suppliers to 'prominently display' in every household
energy bill, both paper and electronic, eight key pieces of information279
initially
identified by the Citizens' Energy Forum Working Group on Billing in 2009280
.
Not all of these data are covered by the existing legislation, and their inclusion
would help ensure that consumers have the minimum information necessary to
interact with the market, whilst leaving Member States freedom to tailor the
presentation of this information to national markets.
- Requiring the breakdown of energy costs presented to consumers to be in line with
the new Regulation on electricity and natural gas price statistics i.e. three
components (energy costs, network charges, taxes & levies) with standard
definitions throughout the EU. This could help improve consumer awareness on
the factors affecting price changes and enable the cross-border comparison of bills.
Option 2: A fully standardized 'comparability box' in bills
This option would be to develop a standard EU information box that would prescriptively
present all the key information that consumers need to compare offers and switch suppliers
prominently on the bill. It may also most require implementing legislation to define the
format and contents of the information box.
Comparison of the options
This Section compares the costs and benefits of each of the Options presented above in a
semi-quantitative manner.
279
i) The price to pay; ii) Consumption for current billing period, including comparison with previous year
(as per EED); iii) The name of the energy supplier; iv) The contact details of the energy supplier; v) The
tariff name; vi) Contract duration; vii) The customer's switching code or unique identification code for
their supply point; viii) A contact point for alternative dispute resolution (as per current Electricity and
Gas Directives).
280
"Implementation of EC Good Practice Guidance for Billing", (2010) CEER http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b1/E10-CEM-36-03_EC%20billing%20guidance_8-Sept-2010.pdf.
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In general, the costs of implementing each of the above measures can be estimated to a
reasonably certain degree using tools such as the standard cost model for estimating
administrative costs281
. However, no data or methodology exists to accurately quantify all
the benefits of the measures in terms of direct benefits to consumer (consumer surplus) or
general competition. As such, this Section draws on behavioural experiments from a
controlled environment to evaluate the impact of some policy options on consumer
decision-making. Where appropriate, it aims to illustrate the possible direct benefit to
consumers assuming certain conditions. It also highlights important qualitative evidence
from stakeholders that policymakers should also incorporate into their analysis of costs
and benefits.
Option 0: BAU with stronger enforcement
A good case can be made for a prudent, business-as-usual approach in this policy area.
First, there appear to be implementation issues on certain bill items required under current
EU legislation.
Secondly, even though there are clear issues around billing, a recent Commission survey
showed that 77% of energy consumers either agreed or strongly agreed that their bills were
"easy and clear to understand" (Figure 5), and unclear bills led to just 1% of the electricity
and gas consumer complaints reported to the Commission (Figure 6). Even after factoring
in the unreliability of some consumer report data, the absolute size of the problem itself
does not therefore appear to be very significant.
And thirdly, national regulators and energy suppliers are implementing various ways of
improving the billing experience. A business as usual approach would allow 'natural
experiments' in this area to be developed, and the Commission to gather stronger evidence
for a more targeted intervention at a later date.
In spite of these considerations, it is unlikely that Option 0 would most effectively
address the problem of poor consumer engagement. Whilst adherence to certain billing
requirements does seem to be lacking, this only relates to one or possibly two information
items, and so even ensuring 100% compliance would therefore not result in significant
change to energy bills. Whilst consumers report satisfaction with bill clarity,
questionnaires reveal glaring shortcomings in their knowledge of basic market-relevant
information that would help them identify the best offer in the market and weigh the
benefits of switching – information that could be more effectively conveyed in bills.
Accordingly, consumer groups strongly support further legislative measures to ensure bills
inform consumer better and help them to engage with the market. Indeed, all major
stakeholder groups – except for energy suppliers and industry associations – indicate that
there may be at least some scope for further EU action to ensure bills facilitate consumer
engagement in the market.
There are no implementation costs associated with Option 0.
281
http://ec.europa.eu/smart-regulation/guidelines/tool_53_en.htm
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Option 0+: Non-regulatory approach e.g. a Commission Recommendation on billing
information
This option can be discarded because a very similar set of recommendations have already
been developed by the Commission-chaired Working Group on Billing (more details
below). Whilst the group's findings were published and presented to the Citizens' Energy
Forum in 2009, these recommendations have not been fully adhered to (Table 2), and it is
unlikely that putting them in a non-binding Commission Recommendation would change
this. It is thus unlikely that voluntary cooperation between Member States would address
this problem.
Option 1: More detailed legal requirements on the key information
To recap, this option would involve ensuring that all EU suppliers use the same definitions
of price components (energy, network charges, and taxes) when communicating with
consumers. It would also involve prominently displaying the eight pieces of information
presented in every EU energy bill. These eight items are drawn from a guidance document
on billing originally proposed by a Commission-led Working Group in 2009282
. The
importance of the information items was then reaffirmed by a Working Group on e-Billing
and Personal Data Management in 2013283
. Whilst the former comprised of representatives
from NRAs and the Commission, the latter also included representatives from consumer
groups and industry. The identification and selection of these items is therefore based on
comprehensive of stakeholder dialogue process.
The economic benefits of Option 1 will primarily be indirect, and come in terms of greater
competition (lower prices, higher standards of service and a broader variety of products on
the market). These benefits are unquantifiable.
In addition, Option 1 will directly result in greater consumer surplus, something that can
be estimated using the following assumptions.
As a whole, EU households spend a total of 147 billion euros on electricity and 97 billion
euros on gas annually, the average annual household bill being 773 euros for electricity
and 795 euros for gas284
. According to CEER, 6.3% of electricity consumers and 5.5% of
gas consumers switched energy suppliers in 2014.
If we assume that:
282
"Implementation of EC Good Practice Guidance for Billing" (2010) CEER http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b1/E10-CEM-36-03_EC%20billing%20guidance_8-Sept-2010.pdf.
283
"Working Group Report on e-Billing and Personal Data Management", (2013) Report prepared for the
6th Citizens' Energy Forum, https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-
billing_energy_data.pdf.
284
Not including MT or CY. Based on latest data available: 2014 for BE, BG, CZ, DK, EL, HR, HU, IT,
LV, PL, RO, and SK; 2013 for DE, ES, LU, NL, UK; 2012 for EE, FI, LT, SE and SI; 2011 for FR;
2010 for AT, IE and PT. Source: Eurostat.
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- The average EU switching rates for electricity and gas remained unchanged at
6.3% and 5.5% respectively285
;
- The measures improved the ability of one out of every one-hundred customers
who switched to identify a better offer286
;
- The measures benefitted consumers using comparison tools just as much as
those comparing the market directly through suppliers287
;
- These consumers were able to save an additional 5 euros from both their
electricity and gas bills a year as a result of the measures put in place288
;
- The financial advantage of being able to identify the best deal as a result of
these measures persists for four years289
;
- All EU households are able to benefit from these changes equally in relative
terms290
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in an increase in consumer surplus of between 0.9 and 3.2
million euros annually (depending on the year of implementation), and 27.6 million
euros in total for the period 2020-2030.
285
This is a conservative assumption given that 40% more consumers would have access to their unique
switching code with every bill (a piece of information important for switching) and significantly more
consumers on fixed term contracts are likely to be aware of when their current contracts expired (24%
of household consumers report that they only compare tariffs when they needed to renew their contracts).
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
286
This equates to just 0.063% of electricity consumers and 0.055% of gas consumers in any given year –
again, a conservative assumption. Taken as a whole, the eight information items in Option 1 aim to arm
the consumer with all the most relevant information necessary to engage with the market, including
helping consumers identify the best offer.
287
One of the benefits of this intervention would also be to give consumers easy access to all information
relevant to using comparison tools in every bill (switching code, tariff name, consumption).
288
This figure seems proportionate given that the average 80% range of the dispersion of electricity and
gas household offers in the market is around EUR 150 (Figure 8). Assuming that those switching would
tend to be moving from a tariff at the more expensive side of this distribution to a tariff at the cheaper
side of this distribution, this amounts to saying that the greater market awareness engendered by this
intervention would enable consumers to identify an offer that was just c. 3% cheaper than the offer they
would have otherwise identified without the intervention.
289
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
290
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we have
no reliable data to quantify these differences in this specific context.
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Table 4: The prevalence of eight key information items in consumer bills
Item Item in "billing" evaluation sheet % who
found item
on their bill
(total)
i) The amount to be paid, for which billing period, by
when and how (existing EU legal requirement)
Amount to be paid 97%
Billing period (e.g. 15 November
– 14 December 2014)
95%
ii) For calculations based on actual consumption:
meter readings and consumption during the billing
period (measured in kilowatt hours or kWh) (existing
EU legal requirement)
Details about consumption during
billing period (in kWh)
89%
Value of the meter reading at the
end of the billing period
89%
Value of the meter reading at the
beginning of the billing period
88%
iii) Supplier's name Provider’s name 99%
iv) Contact details (including
their helpline and emergency number)
Telephone number of customer
service/helpline
96%
Postal address of provider 94%
Email address of provider 69%
Emergency number (e.g. to call in
the event of an electrical
emergency or power outage)
59%
v) The tariff name Tariff name/plan (e.g. 'Day &
Night Fix')
80%
vi) The duration of the contract Duration of the contract (e.g. 24
months)
22%
vii) The switching code Switching code/meter
identification (EAN or MPAN
code; a unique code for your
electricity meter)
73%
viii) Information concerning the consumer's rights as
regards the means of dispute settlement available to
them in the event of a dispute (existing EU legal
requirement)
National contact information
point (or single point of contact
where you can obtain information
about your energy rights)
28%
An energy mediator or third-party
assistance
23%
Base (note: figures in grey are based on a smaller sample): 300
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
The implementation costs of Option 1 will most likely be modest because:
- All Member States have legislation with billing requirements that are more prescriptive
than those in the EU acquis (Table 1);
- National legislation is periodically revised independently of EU requirements, and so
minor EU requirements would not lead to significant additional implementation costs
to national administrations;
- It is already an EU legal requirement to display three out of the eight pieces of
information this measure proposes should be 'prominently displayed' (information on
consumption, information on costs, and information on dispute settlement);
- Only one piece of information (the contract duration) would have to be added to around
80% of EU bills;
- Two pieces of information (the tariff name and switching code) can already be found
in over 70% of bills;
- The remaining two pieces of information (the suppliers name and contact details) can
already be found in over 95% of bills (Table 4);
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- The requirement to use standardised definitions of energy price component would not
result in any additional information requirements, per se.
This option would therefore result in the following one-time implementation costs to the
2752 electricity and 1595 gas suppliers in the EU291
. No running costs are associated
with this option due to the computerisation of billing systems.
Table 5: Option 1 implementation costs (all one-time costs)292
Obligation Action Suppliers
concerned
Staff type Hourly
rate
(EUR)
Man
hours
Activity cost
(EUR)
Ensuring 8 key
information items
are prominently
displayed in every
energy bill
Bill design 2174293
Professionals 32.10 16 1,116,566.40
Bill design 1449294
Professionals 32.10 72 3,348,928.80
Ensuring that all
EU suppliers use
the same
definitions of
price components
in bills
Understanding
information
obligation
3434295
Professionals 32.10 4 440,925.60
Adjusting
existing data
3434 Professionals 32.10 24 2,645,553.60
Total 7,551,974.40
As regards stakeholder views, Option 1 would likely enjoy broad support amongst
stakeholders, apart from energy suppliers and the industry associations who represent
them. It responds to the input from consumer groups, the European Parliament and the
Committee of the Regions that legislative action is necessary to ensure that energy bills
meet minimum standards. It also accommodates feedback from NRAs that prescriptive or
detailed EU requirements could reduce the scope for innovation among suppliers and could
become outdated quickly.
Option 2: A fully standardized 'comparability box' in bills
To recap, this option would be to develop a standard information box that would
prescriptively present key information in all EU energy bills.
The economic benefits of Option 2 would primarily be indirect, and come in terms of
greater competition (lower prices, higher standards of service and a broader variety of
products on the market). These benefits are unquantifiable.
291
Source: CEER National Indicators Database (2015).
292
Derived from the standard cost model for estimating administrative costs.
293
This assumes that 50% of all suppliers would need to make minor changes to their bills to accommodate
one additional piece of information (contract duration). 2 man days of work. Estimate based on the
figures in Table 4
294
This assumes that 30% of all suppliers would need to make moderate changes to their bills to
accommodate three additional pieces of information (contract duration, switching code, tariff name). 9
man days of work. Estimate based on the figures in Table 4.
295
79% of consumers found a breakdown of energy costs in their bills (Table 2). This legal requirement
would only apply to suppliers providing a breakdown.
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In addition, Option 2 would directly result in greater consumer surplus, something that
can be estimated with the aid of the following behavioural experiments.
10,056 respondents completed behavioural experiments to test if bill presentation impacts
consumer awareness and decision making. The behavioural experiment included a task on
bill comprehension, in which respondents were shown a best practice bill with a
comparison box or a standard bill and tested on how well they understood key pieces of
information contained in the bill. Respondents were also tested on their ability to identify
the best offer after having seen a best practice bill or a standard bill.
The “best practice” bill drew on the Working Group Reports on Billing, and Personal Data
Management cited earlier, as well as the electricity bill model/prototype developed
following input received from working group members, which makes suggestions for both
the content and format of an electricity bill and encourages the use of a “comparability
box”.
Figure 9: Best practice comparability box design
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
The “standard bill” was developed based on the bills collected through desk research on
actual providers in Europe. It does not have a comparability box and, although it provides
consumers with the same information, the presentation of the information is not as clear
(i.e. key information on tariff characteristics are not presented in a simple box on the first
page of the bill).
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Figure 10: Excerpt of standard bill
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
In the comprehension exercise, respondents were asked eight questions about the
information provided in the bill, each of which had a single correct answer (respondents
could see the bill next to the questions they had to answer). Generally, viewing the bill in
the best practice format helped respondents pick out the correct answer when compared to
the standard bill. On average across all questions, 84% of respondents who saw the best
practice bill selected the correct answers, compared to 79% of respondents who saw the
standard bill. This result is statistically significant for all eight questions as illustrated in
the table below.
Table 6: Shares of respondents who correctly answered the bill comprehension test
questions, by basic bill type
Question
Best practice
bill
Standard bill Difference
What is the name of your tariff? 90% 86% 5 pp***
How much are you being charged in total? 90% 87% 3 pp***
How much electricity did you consume? 91% 87% 4 pp***
What is the total unit cost of energy excl. VAT? 77% 72% 6 pp***
What is the standing charge incl. taxes and charges? 82% 78% 4 pp**
What is the duration of your contract? 90% 80% 10 pp***
When does your contract expire? 90% 88% 2 pp*
How much energy did you consume last year? 60% 52% 8 pp***
Average across all questions 84% 79% 5 pp***
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
In the 'stay or switch' task, designed to test if the presentation format of consumers’ bills
impacts their propensity to switch to the cheapest tariff, best practice bills also led to better
performance, albeit to a limited extent. Respondents viewing the “best practice” bill were
TARIFF NAME STANDARD FIX
Base unit price [insert currency symbol/amount]/kWh
Standing Charge [insert currency symbol/amount]/kWh
National levy( the Green Energy Fund) [insert currency symbol/amount]/kWh
TOTAL UNIT COST WITHOUT VAT [insert currency symbol/amount]/kWh
+ VAT at 20% [insert currency symbol/amount]/kWh
TOTAL UNIT COST incl. VAT [insert currency symbol/amount]/kWh
YOUR TARIFF INFORMATION
DATE GENERAL METER NO 7546 - reading
Previous reading* 32250kWh (a)
15 August 33570kWh (a)
14 November 34100kWh (a)
Your consumption
15 August – 14 November 2014
530 kWh
*A reviatio s: a : a tual, e : esti ate
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more likely to choose the cheapest deal compared to those viewing the “standard” bill
(61% compared to 59%), this impact is small and only marginally statistically significant
overall (Table 7).
Table 7: Share of respondents who selected the cheapest deal296
Bill type
All
countries
CZ DE ES FR UK IT LT PL SE SI
Best practice 61% 59% 64% 53% 59% 72% 52% 60% 59% 63% 59%
Standard 59% 59% 61% 51% 55% 70% 55% 58% 53% 57% 58%
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
If we assume that:
- The average EU switching rates for electricity and gas remained unchanged at
6.3% and 5.5% respectively297
;
- The measures improved the ability of two out of every one-hundred customers
who switched to identify a better offer, reflecting the results in Table 7298
;
- The measures benefitted consumers using comparison tools just as much as
those comparing the market directly through suppliers299
;
- These consumers were able to save an additional 5 euros from both their
electricity and gas bills a year as a result of the measures put in place300
;
- The financial advantage of being able to identify the best deal as a result of
these measures persists for four years301
;
- All EU households are able to benefit from these changes equally in relative
terms302
;
296
Note: Weighted base varies by treatment: Best practice = 5,042; Standard = 5,014.
297
As with Option 1, this is a conservative assumption given that 40% more consumers would have access
to their unique switching code with every bill (a piece of information important for switching) and
significantly more consumers on fixed term contracts are likely to be aware of when their current
contracts expired (24% of household consumers report that they only compare tariffs when they needed
to renew their contracts). "Second Consumer Market Study on the functioning of retail electricity markets
for consumers in the EU" (2016) European Commission.
298
This assumes the size of improvement in decision making in the real world is as significant as the size
of the effect in the experiment. However, many consumers in the real world would not even have access
to all the information in the 'standard' bill in the behavioural experiment (see Table 2). The true effect
can therefore be expected to be greater.
299
Whilst the behavioural experiment addressed the latter mode of comparison, one of the benefits of this
intervention would also be to give consumers easy access to all information relevant to using comparison
tools in every bill (switching code, tariff name, consumption).
300
This figure seems proportionate given that the average 80% range of the dispersion of electricity and
gas household offers in the market is around EUR 150 (Figure ). Assuming that those switching would
tend to be moving from a tariff at the more expensive side of this distribution to a tariff at the cheaper
side of this distribution, this amounts to saying that the greater market awareness engendered by this
intervention would enable consumers to identify an offer that was just c. 3% cheaper than the offer they
would have otherwise identified without the intervention.
301
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
302
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we have
no reliable data to quantify these differences in this specific context.
540
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- A discount rate of 4% for the consumer benefits year on year;
then Option 2 would result in an increase in consumer surplus of between 1.8 and 6.5
million euros annually (depending on the year of implementation), and 55.3 million
euros in total for the period 2020-2030.
However, there is significant uncertainty as to these benefits because it may prove difficult
to devise a standard EU comparability box that can fully accommodate all differences
between national energy markets. Such as box may downplay the non-quantitative value
of energy services (green offers, or offers bundled with home insulation services) when
compared to 'plain vanilla' supply contracts. Finally, the prescriptive approach would
inhibit beneficial innovation by national regulators and suppliers, and make it difficult to
adapt bills to evolving technologies and consumer preferences.
Indeed, the Commission-chaired Working Group on e-Billing and Personal Data
Management found that bill design "should not be imposed by regulation but rather be
developed on the basis of better understanding of consumer interests also drawing on the
results of behavioural research"303
.
The implementation costs of Option 2 will most likely be significant because:
- All Member States have legislation with billing requirements that are relatively
prescriptive, and that will need to be significantly revised (Table 1);
- All energy suppliers would need to significantly revise the design of their
household bills in order to comply with the new EU requirements.
This option would therefore result in the following one-time implementation costs to
public administrations as well as the 2752 electricity and 1595 gas suppliers in the EU304
.
No running costs are associated with this option due to the computerisation of billing
systems.
303
Working Group Report on e-Billing and Personal Data Management", (2013) Report prepared for the
6th Citizens' Energy Forum, https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-
billing_energy_data.pdf.
304
Source: CEER National Indicators Database (2015).
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Table 8: Option 2 implementation costs (all one-time costs)305
Obligation Action Entities
concerned
Staff type Hourly
rate
(EUR)
Man
hours
Activity cost
(EUR)
Incorporating
comparison box
into bills
Revising
national
legislation
28306
Legislators,
senior
officials,
managers
41.50 320 371,840.00
Understanding
information
obligation
4347307
Professionals 32.10 8 1,116,309.60
Bill design 4347 Professionals 32.10 144 20,093,572.80
Total 21,581,722.40
As regards stakeholder views, Option 2 would not enjoy as much support as Option 1. In
particular, it would be resisted by NRAs as well as industry as it would significantly reduce
the scope for beneficial innovation by national authorities and suppliers, as well as their
ability to tailor information to specific national markets or consumer groups308
. In addition,
whilst consumer groups, the European Parliament and the Committee of the Regions have
pushed for greater standardisation of the format of bills, it may prove impossible to devise
a format that pleases all of these diverse stakeholders in practice.
Conclusion
Option 1 is the preferred option as it likely leads to significant economic benefits and
increased consumer surplus without significant administrative costs or the risk of overly-
prescriptive legislation at the EU level.
Subsidiarity
Consumers are not taking full advantage of competition on energy markets due, in part, to
poor awareness of basic, market-relevant information that could be provided in energy
bills.
The Options envisage reinforcing legal requirements on key information to include in
consumers' bills. National legal regimes for billing remain fragmented with diverging
content and format, and do not always facilitate comparison with offers and pre-contractual
information, which would improve switching rates and effectiveness. There is also a need
to standardise the definitions of energy costs, network charges, and taxes and levies used
in all EU bills in order that consumers understand what they are paying for and are better
aware of the extent to which they can control their energy costs.
305
Derived from the standard cost model for estimating administrative costs.
306
All Member States. 40 man-days each.
307
All electricity and gas supply companies. 18 man-days each.
308
In a workshop on effective billing that the UK energy regulator, Ofgem, recently held, attendees
generally agreed that the level of prescribed information on bills and other communications in the UK
is too high, leading to consumers being overwhelmed with information, and that a one size fits all
approach doesn’t allow for tailored information to be provided to a consumer. See 'Memo: Effective
billing workshop', (2015) Ofgem,
https://www.ofgem.gov.uk/system/files/docs/2016/03/effective_billing_workshop_251115_.pdf.
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Well designed and implemented consumer policies with a European dimension can enable
consumers to make informed choices that reward competition, and support the goal of
sustainable and resource-efficient growth, whilst taking account of the needs of all
consumers. Increasing confidence and ensuring that unfair trading practices do not bring
a competitive advantage will also have a positive impact in terms of stimulating growth.
The legal basis for the legislative options proposed (Options 1 and 2) is therefore likely to
be Article 114 TFEU. This allows for the adoption of "measures for the approximation of
the provisions laid down by law, regulation or administrative action in Member States
which have as their object the establishment and functioning of the internal market". In
doing this, in accordance with Article 169 TFEU, the Commission will aim at ensuring a
high level of consumer protection.
Option 0: BAU with stronger enforcement
Business as usual/stronger enforcement does not change the status quo. Member States
would continue to have a significant degree of discretion in specifying the content of
consumers' bills.
From a subsidiarity perspective, this option allows Member States to decide on the extent
to which they wish to create an environment where customers are encouraged to switch
more freely. If the status quo continues, this may not always result in lower overall prices,
depending on the national situation.
From the perspective of proportionality, however, this option would not necessarily lead
to sufficient improvements in the market.
Option 1: More detailed legal requirements on the key information
The principles of subsidiarity and proportionality are best met through this Option as it is
not overly prescriptive and will concretely reduce levels of consumer detriment that are
currently not addressed at a national level by all Member State authorities.
This option aims primarily at reinforcing existing legislation but without being overly
prescriptive. As billing is already addressed in EU provisions, the subsidiarity and
proportionality principles have clearly been assessed previously and deemed as met.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the preceding
pages, accrue predominantly to consumers who do not engage in the market or better control their energy
consumption because of insufficient billing information or confusing bills. This may include certain
vulnerable consumers, or those who are time poor.
Option 2: A fully standardized 'comparability box' in bills
Implementing a standardised comparability box for billing would help to create a level
playing field for consumers within Member States and between Member States. At this
point, however, it would be disproportionate to impose such a requirement as consumer
research in this area is ongoing and current findings are inconclusive.
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Stakeholder's opinions
Public Consultation
222 out of 237 respondents to the Commission's Consultation on the Retail Energy
Market309
believed that transparent contracts and bills were either important or very
important for helping residential consumers and SMEs to better control their energy
consumption and costs. 110 out of 237 believed that prices and tariffs that were difficult
to compare were a key factor influence switching rates. And 66 out of 133 respondents
who thought that bills did not provide sufficient information thought this was the case
because they were not sufficiently transparent and meaningful.
43% of all 332 respondents to the Commission's Consultation on the Review of Directive
2012/27/EU on Energy Efficiency310
think the EED provisions on metering and billing are
sufficient to guarantee all consumers easily accessible, sufficiently frequent, detailed and
understandable information on their own consumption of energy, versus 32% who opposed
this view, and 25% who had no view. Most comments were provided by participants who
did not think that the provisions are sufficient. Many argued that energy bills would remain
too complex to be properly understood by most customers.
Citizens' Energy Forum, February 2016
The European Commission established the Citizens' Energy Forum in 2007. The Forum
meets on an annual basis in London and is organised with the support of Ofgem, the UK
regulatory authority. The overall aim of the Forum is to explore consumers' perspective
and role in a competitive, 'smart', energy-efficient and fair energy retail market. The
London Forum brings together representatives of consumer organisations, energy
regulators, energy ombudsmen, energy industries, and national energy ministries.
The 8th Citizens' Energy Forum, organised by DG Energy in collaboration with DG
Justice, took place in London on Tuesday 23 and Wednesday 24 February. In its
conclusions, the forum: "Call[ed] for improved and comparable pre-contractual
information, including green offers, contract and billing information to increase consumer
engagement." It addition, the Forum: "Call[ed] for phasing out regulated prices and more
clarity on the costs of the components of energy bills to remove barriers to effective
competition and allow consumers to choose from more diverse offers."
European Commission Working Group on e-Billing and Personal Energy Data
Management
Including representatives from national NRAs, consumer groups and industry, this
working group concluded in December 2013 that data presented in e-bills and e-billing
information, as well as in paper bills and consumption data presented on paper, needed to
be correct, clear, concise and presented in a manner that facilitates comparison and
309
Held from 22 to 17 April 2014. https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-
market
310
Held from 4 November 2015 to 29 January 2016.
https://ec.europa.eu/energy/sites/ener/files/documents/Public%20Consultation%20Report%20on%20th
e%20EED%20Review.pdf
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provides all relevant information to consumers – including complaint handling and contact
points for consumer information e.g. on their energy bills and consumption.
It acknowledged that clear and accurate information on energy consumption, feedback
devices, as well as information on historical consumption can help consumers to be better
aware of their consumption.
It also suggested that information is presented to consumers in a 'tiered' manner from basic
towards more complex data, enabling consumers to look for additional, e.g. more
'technical' data, in an educational manner311
.
National Regulatory Authorities
ACER suggests that there is still a lack of information relevant to switching suppliers on
the bill in many Member States. However, it point out that too much information can also
lead to too complex bills inhibiting the beneficial role of information to consumers.
The body representing the EU's national regulatory authorities in Brussels, CEER312
,
points out that detailed requirements can reduce the scope for innovation among suppliers
and could become outdated quickly (e.g. there are more people opting for electronic
billing). To this end, it feels that minimum standards or slightly higher-level requirements
might be more appropriate. It states that understandable billing information as well as
readily comparable information are critically important for consumers and welcomes the
proposal from the European Commission to identify, in collaboration with national
regulators, minimum standards for key information in advertising and bills. It agrees that
information on consumption patterns is important for consumers.
The Czech NRA ERO states that bills are very difficult to understand, not easy to read and
overloaded. Consumers need clear and transparent information, to be able to compare
offers, contract termination information, and information for switching.
The French NRA CRE suggests that the layout of energy bills should contain two levels:
essential / minimal information and detailed information (including where relevant, meter
reading, all tariffs, taxes and levies). In a consumer centric model, the exact layout should
be the suppliers’ responsibility. The breakout pages of the bill might not be relevant in the
near future, with the development of web-only / paperless offers. Detailed legislation on
paper bills is probably irrelevant in a forward looking perspective, considering the general
trend in recurrent billing services. Paper bills should not be made compulsory. Paperless
should be promoted as interactive relations allow the supplier to develop a higher
competitive advantage.
The UK NRA Ofgem does not support prescription beyond ensuring that the key
information is presented clearly. The layout of bills should be broadly left to suppliers.
Testing and trials is the best route through which to identify the most effective way to
present information on bills. It is important to ensure that consumers have access to key
information and that this is not hidden away. In GB on key communications consumers are
311
Working Group Report on e-Billing and Personal Data Management", (2013) Report prepared for the
6th Citizens' Energy Forum, https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-
billing_energy_data.pdf.
312
The Council of European Energy Regulators.
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presented with a Tariff Information Label (TIL) that houses key information about their
tariff and consumption. This provides them with easy access to the information they need
to switch tariffs. Ofgem considers this to be a useful/effective tool for consumers. Ofgem
has received feedback from a number of sources that consumers find their bills confusing
and overly complex.
Consumer Groups
BEUC states that the current EU legislative provisions related to billing are insufficient.
Bills should be clear and concise and include the necessary information for the consumer
to compare offers and to switch supplier. BEUC welcomes the Commission’s plan to put
forward proposals to improve the information provided on the bill in order to facilitate
comparability and switching among others.
Simpler bills are welcome by consumers. EU legislation should also prescribe the
outcomes required for consumers (e.g. that consumers have the data required to switch).
As bills are often packed with a lot of information, a way to avoid the overload and simplify
the overall bill would be to provide only fundamental elements on the bill (for example in
a standardized box). The bill could then include a reference to find more detailed but
perhaps less crucial information online.
The first page of the bill should contain specific elements which are standardised. A
comparability box showing the key information for switching is needed on the first page
of the bill. The Commission should respect the consumer’s choice not to play an active
role. Clear and accurate bills require high level principles for bills at the EU level.
Consumers have a diverse range of preferences and of accessible tools so the approach to
information should be shaped by consumer research at the national level. The focus should
be on less, simpler and more meaningful is better.
The Swedish consumer group Konsumenternas highlights that issues with the bill are
often connected to lack of knowledge or understanding the difference between supply and
distribution and the respective prices/tariffs. Billing should be subject to competition.
Legal provisions on the clarity of bills are difficult to sanction by the regulator. Paper bills
are likely to decrease in number and become less relevant.
The Portuguese consumer group DECO Highlights that while we already have a
standardized information model of pre-contractual information, we don't have the same for
energy bills. It could be useful to have a comparability box in the bill, which shows key
elements (including energy used compared with previous year, contract end date etc.) and
also have information about new promotions and discounts of the same supplier.
DECO believes that some elements that are similar on all energy bills should be
standardised at EU level, namely:
1. Energy supplier identification
2. Customer/Consumer identification
3. Invoice date information
4. Invoice number information
5. Commercial supply/services identification (base product/campaign)
6. Specific offer conditions
7. Fees and taxes
8. Bundled Services
9. Payment Methods
10. Social Tariffs/Mechanisms for vulnerable consumers
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11. Information about savings/sustainability and energy poverty measures.
Citizens Advice (UK) believes that a comparability box showing the key information for
switching is needed on the first page of the bill. EU legislation should prescribe the
outcomes required for consumers (e.g. that consumers have the data required to switch).
This should be supported by actions to monitor and enforce this (e.g. with a link across to
the indicators for market monitoring, including by CEER/ACER). The format and layout
should be subject to consumer testing/consumer research. It is useful to provide consumers
with information on similar properties in the area but the ‘bill’ may not be the best location.
For instance, the information could be provided in a separate report, sent to the household,
outside of the standard billing cycle.
Germany's VZBV believes that a clear requirement to show the price per kWh including
taxes is missing in the regulation. A requirement to access the meter is missing in the
regulation as well. Although legislations exists, these are partly insufficiently implemented
from the consumer point of view (esp. in terms of understand ability).
Suppliers
EURELECTRIC states that many consumers across Europe complain that there is too
much information on their bills, making them difficult to read. At the same time, regulation
does not always allow suppliers to simplify or improve them to fit with specific consumer
needs. In a competitive market, bill design should be left to suppliers (and other market
parties) to diversify their brand and image. Suppliers also need flexibility to take into
account the needs of different groups of consumers. Beside, EURELECTRIC thinks the
main issue with bill is not about the “layout” per se but about its “regulated content” (e.g.
taxes, legal wording, consumption estimation, etc.). Only the most critical elements could
be standardised at national level if evidence suggests this is needed. Consumers also face
problems with the high volume of regulated information on their bills. The primary purpose
of a bill is to set out charges for energy and to allow the customer to understand how their
consumption affects those charges. Giving evidence of how the lay-out of paper bills can
create competitive advantage is not an easy thing to do. The point is that different
consumer/consumer groups may have different needs and preferences as to what they’d
like to see in their energy bill: level of details, format, use of graphs/tables, etc. This is why
suppliers should be given enough flexibility to innovate. In any competitive market,
differentiation is key to create competitive advantage. EURELECTRIC does not see any
evidence which would support the need for further standardisation of elements of the
energy bill at European level.
Eurogas states that EU legislation sets prescriptive requirements on billing frequency and
use of meter readings which can and should be left to suppliers in competitive markets.
Communications should also be able to adapt to changing technology, such as the
increasing use of digital media, including smartphones and tablets. Suppliers in
competitive markets are best-placed to work out how to engage customers. Graphs and
tables may be equally useful in certain situations but it should be up to the competitive
market to determine how to present information to customers in an engaging way.
Consumers face problems with the high volume of regulated information on bills. The
primary purpose of a bill is to set out charges for energy and to allow the customer to
understand how their consumption affects those charges. To facilitate the readability of the
bill, some information (such as general conditions) could be made available on the
dedicated customer area and signposted on the bill.
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CEDEC argues that before including new measures in the legislation it should be ensured
that the current provisions are respected. New requirements should be conditional on
technical feasibility and cost-effectiveness. The focus on measures that are technically
feasible and cost effective must remain. Consumers find more difficult to identify and
choose the cheapest deal if price structure of electricity offers is complex. In this sense, it
would be useful to avoid too many pieces of information.
UK ENERGY highlights that all markets are different and it is the role of competition
between market participants to determine what is most effective and appropriate for billing
purposes. It believes suppliers need more flexibility to determine what information they
provide to customers and how that information is provided with what frequency. Suppliers
should have increased flexibility in the layout of the bill since this is one of the few and
key contact points to engage with customers. The primary purpose of a bill is to set out
charges for energy and to allow the customer to understand how their consumption affects
those charges. It is unclear how a standardisation of the first page could keep pace with
changing technologies and markets. Consumers increasingly want to receive
communication in alternative formats such as online or via apps. It is unclear what benefits
standardisation at European level would bring.
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Parliament's Committee on Industry, Research and Energy
(ITRE): "Recommends improving the frequency of energy bills and the transparency and
clarity of both bills and contracts in order to aid interpretability and comparison, and to
include in or alongside energy bills peer-based comparisons and information on
switching; insists that clear language must be used, avoiding technical terms; requests the
Commission to identify minimum information requirements in this respect, including best
practices; stresses that both fixed charges and taxes and levies should be clearly identified
as such in the bills, allowing the customer to distinguish them easily from the variable,
consumption-related cost; recalls existing requirements for suppliers to specify in or with
bills the contribution of each energy source to the overall fuel mix of the supplier over the
preceding year in a comprehensible and clearly comparable manner, including a reference
to where information can be found on the environmental impact in terms of CO2 emissions
and radioactive waste. Recommends that consumers should be notified in or alongside
energy bills about the most suitable and advantageous tariff for them, based on historic
consumption patterns, and that it should be possible for consumers to move to that tariff,
if they so wish, in the simplest way possible. Considers that incentives and access to quality
information are key in this respect and asks the Commission to address this in upcoming
proposals."
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Parliament's Committee on the Internal Market and
Consumer Protection (IMCO) called for: "the Commission to take further action to
improve the frequency of energy bills and the associated meter readings, and their clarity,
comparability, and transparency as regards types of energy sources, consumption, price
structure and the processing of enquiries and complaints."
The Committee of the Regions
In its April 2016 opinion on the Commission's Communication on Delivering a New Deal
for Energy Consumers, the Committee of the Regions:
- calls on the European Union to examine the different components of energy bills,
in order to put together a "standard" bill incorporating a number of elements that
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are uniform, legible, clear and comparable at European level and which would
allow consumers to optimise their energy use. In this regard, the European
Committee of the Regions supports the Council of European Energy Regulators'
initiative to set out harmonised definitions of different elements that should be
included in energy bills;
- calls for standardisation to be accompanied in the final bill by information about
the free tools and services that are available for comparing supply offers, as well
as information and support for households and businesses with regard to the
protection of consumers' rights;
- calls on Member States to create tools and services that make bills easier for
households and businesses to understand, so that they can be analysed; and, where
appropriate, to provide advice and support for end-users regarding the steps which
may be necessary to rectify any irregularities identified or guide end-users towards
supply contracts that are better suited to their needs;
- recommends that bills and any information issued by suppliers to their end-users
should be sent in the format requested by the latter, i.e. via post or e-mail, without
any discrimination;
- stresses that vulnerable consumers are particularly likely to encounter difficulties
in identifying the best tariffs amongst the wide range of offers, and that they often
seek the assistance of the closest level of governance. Consequently, the European
Committee of the Regions calls upon the European Union to assist local and
regional authorities in setting up support systems in the field of energy if this is not
being done by the Member States.
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8. DESCRIPTION OF RELEVANT EUROPEAN R&D PROJECTS
Technological developments are both part of the drivers that affect the present initiative
and part of the solutions of the problems they affect.
Technological developments have created the opportunities for consumers to transit from
being passive consumers of electricity to prosumers that can actively manage their
consumption, storage and production of electricity and particiapte in the market. This
provides opportunities for innovative business models of service provisions, often based
on advanced technologies, based on enabling smaller consumers and distributed generation
to interact with the market and have their resources being managed. At the same time,
networks should be managed more actively in order to meet the challenges more
decentralised generation brings about.
As the transition path is also created by technological progress and the solutions to the
problems they entail are equally shaped by technology, the present annex provides for a
sample of projects, supported by the EU through its 6th
and 7th
Framework Programme and
Horizon2020, that have developed technologies and innovations that render these
developments more concrete but also provide insights as to the direction the transition may
take.
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Project FP7-DISCERN
Title: Distributed Intelligence for Cost-Effective and Reliable Distribution Network Operation
The project linked with six large-scale smart grids demonstration projects financed at national level. The
project developed methods to characterise outcomes and aimed to find ways to replicate solutions from one
country to another.
Fact Sheet: http://cordis.europa.eu/project/rcn/106040_en.html
Web Site: http://www.discern.eu/
Important project outcome include:
The practical testing and tuning of performance metrics (Key Performance Indicators – KPI) and evaluation
of their values based on actual measurements. The project concludes that use of the KPI framework is a valid
approach for revealing the impact of a technical solution and its function(s) on a DSO grid, system or
organisation and to set the expected set of outcomes. These can be used to analyse cost/benefit ratios at
design stage and after implementation. Cost KPIs are a valid method for assessing cost structures for Use
Cases, however as the creation of a common cost list to support impartial comparisons of the various Use
Cases was found impractical within the constraints of DISCERN, the evaluation of costs and determination
of initial investments relied on individual Use Case information, which by its nature incorporates company
specific cost drivers
Project FP7-ITESLA
Title: Innovative Tools for Electrical System Security within Large Areas
The project developed methods and tools for the coordinated operational planning of power transmission
systems, to cope with increased uncertainties and variability of power flows, with fast fluctuations in the
power system as a result of the increased share of resources connected through power electronics, and with
increasing cross-border flows. The project aims at enhancing cross-border capacity and flexibility while
ensuring a high level of operational security.
Fact Sheet: http://cordis.europa.eu/project/rcn/101320_en.html
Web Site: http://www.itesla-project.eu/
Important project outcomes include:
- a platform of tools and methods to assist the cooperation of transmission system operators in dealing
with operational planning from two days ahead to real time, particularly to ensure security of the system.
These tools support the optimisation of security measures, in particular to consider corrective actions,
which only need to be implemented in rare cases that a fault occurs, in addition to preventive actions
which are implemented ahead of time to guarantee security in case of faults. The tools provide risk-
based support for the coordination and optimisation of measures that transmission operators need to take
to ensure system security. The platform also supports "defence and restoration plans" to deal with
exceptional situation where the service is degraded, e.g. after storms, or to restore the service after a
black-out. The platform has been made publicly available as open-source software.
- A clarification of the data and data exchanges that are necessary to enable the implementation of these
coordination aspects.
- A framework to exchange dynamic models of power system elements including grids, generators and
loads, and a library of such models covering a wide range of resources. These models are essential to
produce accurate prediction of the rapid fluctuations that take place in the power grid after faults, and to
prevent cascading failures.
- The tools and models allow to reduce the amount of necessary preventive measures. The reliance on
risk-based approaches can avoid or mimimise costly preventive measures such as re-dispatching while
the overall risk of failure is decreased.
- A set of recommendations to policymakers, regulators, transmission operators and their associations
(jointly with the UMBRELLA project). These foster the harmonisation of legal, regulatory and
operational framework to allow the exploitation of the newly developed methods and tools. They also
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identify the need for increased formalised data exchange among TSO's to support the new methods and
tools.
Project FP7-UMBRELLA
Title: Toolbox for Common Forecasting, Risk assessment, and Operational Optimisation in Grid Security
Cooperations of Transmission System Operators (TSOs)
The project developed methods and tools for the coordinated operational planning of power transmission
systems, particularly to cope with high shares of variable renewable energy. They aimed at enhancing cross-
border capacity and flexibility while ensuring a high level of operational security.
Fact Sheet: http://cordis.europa.eu/project/rcn/101318_en.html
Web Site: http://www.e-umbrella.eu/
Important project outcomes include:
- The demonstration of probabilistic forecasting of power generation and power flows on a regional basis.
These are important to plan ahead of time, the most effective methods for relieving expected congestions.
Such forecasts will also be important for intraday trading on wholesale markets.
- Validated methods and tools for a coordinated optimisation of measures to ensure the security of the
pan-European grid. Of particular importance is the to coordination of measures for relieving expected
congestions, starting from low-cost measures such as switches to coordinated generation redispatching.
- The tools and models allow to reduce the amount of necessary preventive measures. The reliance on
risk-based approaches can avoid or mimimise costly preventive measures such as re-dispatching while
the overall risk of failure is decreased.
- a set of recommendations to policymakers, regulators, transmission operators and their associations
(jointly with the ITESLA project). These foster the harmonisation of legal, regulatory and operational
framework to allow the exploitation of the newly developed methods and tools. They also identify the
need for increased formalised data exchange among TSO's to support the new methods and tools.
Project FP7-eHIGHWAY2050
Title: Modular Development Plan of the Pan-European Transmission System 2050
The project developed new methods for the top-down long-term foresight of the power system infrastructure
in a 2050 perspective, and applied these to depict grid requirements under a number of scenarios, and outlined
a "future proof" modular development pathway to this horizon.
Fact Sheet: http://cordis.europa.eu/project/rcn/106279_en.html
Web site: http://www.e-highway2050.eu/e-highway2050/
Important project outcomes include:
- a number of basis scenarios framing possible evolution of demand, generation and delivery infrastructure
in the 2050 perspective
- a foresight of expected power system technology evolution in this time frame
- optimised grid architectures to efficiently respond to the delivery needs for each of the selected scenarios
- a modular development plan with intermediate steps that largely fit all the future pathways
- new methods for optimal long-term planning of power systems in the presence of major uncertainties
- a well-documented proposal for the clarification of the concept of "electricity highways" in the context
of the EU energy infrastructure package. This proposal has largely been adopted in the process of
selecting the second round of "projects of common interest" and has resulted in a substantial number of
projects identified as "electricity highways" as part of a double label.
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Project FP6 : VSYNC –
Title: Virtual Synchronous Machines (VSG's) For Frequency Stabilisation In Future Grids with a Significant
Share of Decentralized Generation.
The project developed methodologies to enable a generator to behave like a "Virtual Synchronous
Generator" (VSG) during short time intervals and contribute to the stabilisation of the grid frequency.
Cordis website: http://cordis.europa.eu/project/rcn/85687_en.html
Project website: http://www.vsync.eu/
Important project outcomes include:
- The Virtual Synchronous Generator technology can contribute to the stabilisation of the grid frequency
at distribution level. The Vsync technology could allow PV to provide balancing services replacing the
inertia of 'traditional' generators. As a result, the RES absorption capacity of the grid is increased.
- Today frequency control is handled by TSOs mainly with the help of generators connected to the
transmission network. The provision of Ancillary Services of assets connected to the distribution grid is
currently not standard practice and is not standardized. However, it is possible that these will be required
or offered in future, due to increased system needs, increasing share of decentralized generation (also
reducing the possibility to rely exclusively on large generation) and possible connection and
reinforcement cost optimization at distribution..
IEE project REServiceS –
Title: Economic grid support from variable renewables
RESERVICES addresses changes in the future European power system:, in particular the need for
development of an ancillary services market in which RES can participate.
IEE website: http://ec.europa.eu/energy/intelligent/projects/en/projects/reservices
Project website: http://www.reservices-project.eu/
Important project outcomes include:
- Ancillary services are grid support services required by the power systems (transmission or distribution
system operators TSOs or DSOs) to maintain integrity, stability and power quality or the power system
(transmission or distribution system). Ancillary services can be provided by connected generators,
controllable loads and/or network devices. Some services are set as requirements in Grid Codes and
some services are procured as needed by TSOs and DSOs to keep the frequency and voltage of the power
system within operational limits or to recover the system in case of disturbance or failure.
- There are different procurement and remuneration practices for Ancillary services, and these practices
are evolving. There are already markets for some services. Some services are mandatory (not necessarily
paid for) and some services are subject to payments according to regulated (tariff) pricing or tendering
process and competitive pricing.
- RES (in particular PV and wind) can provide ancillary services both at DSO and TSO level, from a
technology point of view, but due to the way the markets are defined (and the way ancillary services are
managed) in practice they cannot participate.
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Project FP6 Integral
Title: Integrated ICT-platform based Distributed Control in electricity grids with a large share of Distributed
Energy Resources and Renewable Energy Sources.
The INTEGRAL project demonstrated how Distributed Energy Resources and Demand Side Response in
the distribution grid can be controlled and coordinated, based on commonly available ICT components,
standards and platforms. The project treated the operating conditions of the grid with DER/RES
aggregations in three different operating conditions:
- Normal operating conditions of DER/RES aggregations – Stakeholders involved: consumers,
aggregators, utilities.
- Critical operating conditions of DER/RES aggregations – Stakeholders involved: consumers, DSO
- Emergency operating conditions – Stakeholders involved: DSO
Cordis website: http://cordis.europa.eu/project/rcn/86362_en.html
Project website: http://integral-eu.com/
Important project outcomes include
- The test field A of the INTEGRAL project (grid in normal operational conditions), the PowerMatching
City, demonstrated that the control of DER through an automated market based concept by means of
"agents" distributed in the grid and the Powermatcher application, satisfies the needs of consumers,
aggregators and DSO. On the Data and communication aspects, the project demonstrated the absence of
technological barriers as public networks were used for transport of private data by means of Virtual
Private Networks (VPN), a proven technology to transfer encrypted data.
- The test field B (critical operation of the grid) demonstrated that DSO or aggregators can control the
grid through controlling loads and generation of prosumers. Under critical conditions, the Demand Side
Management (DSM) system disconnects the critical loads.
- The test field C (emergency operation of the grid) demonstrates that the self-healing concept helps to
minimize the average outage time of the grid. It is a high automation levels that allows DSO reducing
the average number of interruptions, enhancing hence the service quality of the grid.
Project FP7 SuSTAINABLE
Title: Smart distribution System operaTion for mAximising the Integration of renewable generation
The SuSTAINABLE project developed and demonstrated the efficient and cost-effective management of the
grid with high penetration of RES configured as a virtual power plant through elaboration of data related
to load forecast, grid infrastructure protection and renewable energy production forecast.
Cordis website: http://cordis.europa.eu/project/rcn/106534_en.html
Project website: http://www.sustainableproject.eu/Home.aspx
Important project outcomes include:
- Concerning data management, the project demonstrated that intelligent management supported by more
reliable load and weather forecast can optimise the operation of the grid. The results show that using the
distributed flexibility provided by DRD – Dynamic Response of Demand can bring an increase of RES
penetration while, at the same time, avoiding investments in network reinforcement.
- Concerning DSO benefits, the results of the project demonstrated that the active management of the
renewable generation can lead to a decrease in the investment costs of distribution lines and substations.
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Project FP7 IDE4L
Title: Ideal Grid for All
The IDE4L project focuses on
- improving distribution network monitoring and controllability by introducing hierarchical decentralized
automation solution for complete real-time MV and LV grid management,
- utilizing existing distribution networks more efficiently and managing fast changing conditions by
integrating large number of distributed energy resources in distribution network through real-time
automation and market based flexibility services,
- guaranteeing continuity and quality of electricity supply by distributed real-time fault location, isolation
and supply restoration solution cooperating with microgrids, and
- improving visibility of distributed energy resources to TSOs by synthesizing dynamic information from
distribution system and to commercial aggregators by validating and purchasing flexibility services.
Cordis website: http://cordis.europa.eu/project/rcn/109372_en.html
Project website: http://ide4l.eu/
Important project outcomes include:
- Concerning data management and interoperability, the project aims to create a single concept for
distribution network companies to implement active distribution network today based on existing
technology, solutions and future requirements.
- All data exchange and data modelling are based on international standards IEC 61850, DLMS/COSEM
and CIM to enable interoperability, modularity, reuse of existing automation components and faster
integration and configuration of new automation components.
IDE4L develops the entire system of distribution network automation, IT systems and functions for active
network management.
- Fault location, isolation and supply restoration
- Congestion management
- Interactions between distribution and transmission network companies
Project FP7 NRG4Cast
Title: Energy Forecasting
NRG4Cast project developed advanced solutions for predicting behaviour of local energy networks for the
three functions:
- Predicting energy demand on several network granularity levels (region, municipality, city, business,
household and energy service provider),
- Predicting energy network failures on interlinked local network topologies,
Detecting short-term trends in energy prices and long-term trends in national and local energy policies.
Cordis website: http://cordis.europa.eu/search/result_en?q=nrg4cast
Project website: http://www.nrg4cast.org/
Important project outcomes include:
- From the data collection point of view, the project demonstrates (as other similar projects) that the
optimization of the use of energy (and hence a higher business margin) in a distributed generation can
be achieved with the support of IT dedicated tools. DSOs as well as other actors (utilities, municipalities,
etc.) can use these tools in their activities.
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Project FP7 EEPOS
Title: Energy management and decision support systems for Energy Positive neighbourhoods
EEPOS is a central energy management system for neighbourhoods that performs coordinated energy
management. Additionally, it actively participates in energy trading with external parties on behalf of
the neighbourhood members.
Cordis website: http://cordis.europa.eu/project/rcn/105854_en.html
Project website: http://eepos-project.eu/
Important project outcomes include:
- Regarding the right to self-produce, consume, store electricity and use flexibility, optimization of use of
energy use can be achieved at neighbourhood or district level more effectively than at household level
through ad hoc energy management systems (IT support as other similar projects).
- Consequence: Matching supply and demand automatically relieves grid unbalance providing hence
indirectly grid services.
H2020: BRIDGE project network
The BRIDGE initiative collects policy recommendations from the use cases which are currently under
demonstration in the ongoing H2020 energy projects.
Important findings for the market design initiative:
Balancing:
- barriers on access to the balancing market. It is observed that not all markets in practice allow load to be
included. This is discriminatory for the energy storage assets demonstrated in the projects and does not
allow the correct valorisation of their double operative nature.
Ancillary services:
- barriers on access to the ancillary market. Participants in the project include Energy Service companies
that provide e.g. Frequency Response, Congestion management, Reserve and Ramping Duty. It is
recommended that products for ancillary services should be consistent and standardized from
transmission and down to the local level in the distribution network. Such harmonization will increase
the availability of the services, enable cross-border exchanges and lower system costs.
Project H2020: SMARTNET
Title: Smart TSO-DSO interaction schemes, market architectures and ICT Solutions for the integration of
ancillary services from demand side management and distributed generation
The project SmartNet aims at providing architectures for optimized interaction between TSOs and DSOs in
managing the exchange of information for monitoring and for the acquisition of ancillary services (reserve
and balancing, voltage regulation, congestion management) both at national level and in a cross-border
context.
Cordis web site: http://cordis.europa.eu/project/rcn/200556_en.html
Project web Site: http://smartnet-project.eu/
Important project outcomes include:
- Validated acquisition of ancillary services from specific resources such as thermal inertia of indoor
swimming pools and batteries in telecommunication base systems. In addition the project will
demonstrate modalities to exchange monitoring signals between transmission and distribution networks.
The architectures for dataflow and control signals will be tested in full replica lab considering various
levels of responsibilities for the DSOs. These ranges from a model with extended central dispatch where
TSO contracts ancillary services directly from DER owners connected to the DSO grid to a more
decentralized model where TSO, DSO and BRPs contract ancillary services connected at distribution
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level for their own need in a common market. The preferential architectures and data flow models will
be defined during the course of the project that is running until the end of 2018.
Project FP7: ECOgrid-EU
Title: Large scale Smart Grids demonstration of real time market-based integration of DER and DR
ECOGRID-EU is a large-scale demonstration project which included 1,900 test households, out of which
~1,200 houses were equipped with home automation equipment and 500 were manually controlled
households. The project focused on direct (resistance based) and indirect (heatpump) electricity heating
applications for households since these has the highest volume potential for demand response
Cordis web site: http://cordis.europa.eu/project/rcn/103636_en.html
Project web Site: http://www.eu-ecogrid.net/
Important project outcomes include:
- Dynamic pricing needs a short time-interval, i.e. 15 minutes or less. It shows as well that this is
technically possible: even a 5-minute period is technically possible although not cost-effective in the
project setting.
- The FP7 project ECOGRID has successfully demonstrated a "real time" power market concept with 5
min time resolution. The concept provides the customers with real time prices and the local ICT control
system in the houses make it possible to optimize the use of electricity by automated adjustment of the
consumption. The concept included both a global price signal for balancing and a locational price signals
for congestion management, although the latter wasn't fully validated. In the basic concept of the
EcoGrid EU project, control of active power is generally done by leveraging the global real-time market
price and its corresponding forecast. Based on this, price deviations for each of the local areas can be
computed in order to relief active power issues within that area. The ICT concept consists of a new
market place and local control schemes which are implemented by three different technology vendors,
thereby allowing a wider base of appliances.
- It showed as well the importance of a reliable communication and automation channel, in particular for
'legacy equipment' (i.e. already installed heat pumps or electric heating).
- An important learning was that automated control has responded much better to price signals than
manually controlled. A customer with manual control gave a 60 kW total peak load reduction while
automated or semi-automated customers gave an average peak reduction of 583 kW.
- For the households equipped with fully automated demand response, the communication interface was
the highest share of the equipment cost, but in future these costs could be virtually zero when appliances
are cloud connected anyway.
- For the demonstration area (Bornholm in Denmark) wind power curtailment (virtually) was reduced by
almost 80%, and the use of (virtual) spinning reserves has been reduced by 5.5%.
- In the replication roadmap it is shown that the Belgian market could give a EUR 2 million/year reduction
of balancing cost if 10%, of the 18% of the households that have a hot water buffer tank, is used for
demand response.
Project FP7 Grid4eu
Title: Large-Scale Demonstration of Advanced Smart GRID Solutions with wide Replication and
Scalability Potential for EUROPE
Grid4EU aims at testing in real size some innovative system concepts and technologies in order to highlight
and help to remove some of the barriers to the smart grids deployment and the achievement of the 2020
European goals. It focuses on how distribution system operators can dynamically manage electricity supply
and demand, which is crucial for integration of large amounts of renewable energy, and empowers consumers
to become active participants in their energy choices. It is organized around large-scale demonstrations
networks located in six different countries,
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Cordis web site: http://cordis.europa.eu/project/rcn/103637_en.html
Project web Site: http://www.grid4eu.eu
Important project outcomes include:
- Demonstration of enhanced functionalities of Online Tap Change Transformers (OLTC) that will enable
higher levels of PV to be integrated in the downstream LV grid. This function consists in fine-tuning the
voltage set point according to a set of parameters and inputs that includes real-time solar radiation, used
as an indicator of the amount of PV energy being produced. This enhanced control allows varying the
voltage set point that takes into account the amount of PV energy being produced, including reaction to
real time perturbations (e.g. temporary reduction in PV production due to a cloud).
- Demonstration of technical viability of islanding in a segment of a distribution network to alleviate e.g.
critical situations at TSO level.
- Demonstration of the "Network Energy Manager (NEM) that provides an integrated flexibility
marketplace for the TSO and DSO to specify their flexibility needs to solve their respective grid
operational constraints. These needs can be automatically computed by the NEM based on renewable
production forecasts and individual load forecasts. The NEM also provides a portal for various DER and
flexibility aggregators to offer their flexibility services to satisfy the requests. As a result, the NEM
performs a global optimisation to address needs in the most economical way while still enforcing the
technical constraints. This fully automated process notifies the aggregators of their awarded flexibility
for implementation and activation for demand response, load shifting or storage device dispatch.
Project H2020: Futureflow
Title: Smart TSO-DSO interaction schemes, market architectures and ICT Solutions for the integration of
ancillary services from demand side management and distributed generation
FutureFlow links interconnected control areas of four transmission system operators of Central-South Europe
which today do face increasing challenges to ensure transmission system security: the growing share of
renewable electricity units has reduced drastically the capabilities of conventional, fossil-fuel based means
to ensure balancing activities and congestion relief through redispatching. Research and innovation activities
are proposed to validate the enabling conditions for consumers and distributed generators to provide
balancing and redispatching services, within an attractive business environment.
Cordis web site: http://cordis.europa.eu/project/rcn/200558_en.html
Project web Site: http://www.futureflow.eu/
Important project outcomes include:
- The project Futureflow will demonstrate in near-to-real-life conditions that balancing and redispatching
service providers are able to provide cross-border balancing and redispatching services to control zones
outside their Member State borders, including automatic frequency restoration reserve services. Each
transmission system operator connected to the regional platform is able to perform its activities by using
the offers from generators and consumers possibly located in the control area of another transmission
system operator also connected to the regional balancing and redispatching platform.
Project FP7-AFTER
Title: A Framework for electrical power sysTems vulnerability identification, dEfense and Restoration
The AFTER project addresses the challenges posed by the need for vulnerability evaluation and contin-gency
planning of the energy grids and energy plants considering also the relevant ICT systems used in protection
and control. Project emphasis is on cascading events that can cause catastrophic outages of the electric power
systems.
Cordis web site: http://cordis.europa.eu/project/rcn/100196_en.html
Project web Site: http://www.after-project.eu
Important project outcomes include:
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- The FP7 project AFTER has developed a framework for electrical power systems vulnerability
identification, defense and restoration. It uses a large set of data (big data) coming from on-line
monitoring systems available at TSOs’ control centres. A fundamental outcome of the tool consists in
risk-based ranking list of contingencies, which can help operators decide where to deploy possible
control actions.
Project FP7-SESAME
Title: Securing the European Electricity Supply Against Malicious and accidental threats
SESAME develops a Decision Support System (DSS) for the protection of the European power system and
applies it to two regional electricity grids, Austria and Romania.
Cordis web site: http://cordis.europa.eu/project/rcn/98988_en.html
Project web Site: https://www.sesame-project.eu/
Important project outcomes include:
- SESAME, developed a comprehensive decision support system to help the main public actors in the
power system, TSOs and Regulators, on their decision making in relation to network planning and
investment, policies and legislation, to address and minimize the impacts (physical, security of supply,
and economic) of power outages in the power system itself, and on all affected energy users, based on
the identification, analysis and resolution of power system vulnerabilities.
Project H2020: Nobelgrid
Title: New Cost Efficient Business Models for Flexible Smart Grids
NOBEL GRID will develop, deploy and evaluate advanced tools and ICT services for energy DSOs
cooperatives and medium-size retailers, enabling active consumers involvement –i.e. new demand response
schemas – and flexibility of the market – i.e. new business models for aggregators and ESCOs.
Cordis web site: http://cordis.europa.eu/project/rcn/194422_en.html
Project web Site: http://nobelgrid.eu/
Important project outcomes include:
- The H2020 project NOBEL Grid will develop, deploy and evaluate advanced tools and ICT services for
energy DSOs cooperatives and medium-size retailers, enabling active consumers and prosumers
involvement. Particularly for domestic and industrial prosumers they will develop an Energy Monitoring
and Analytics App. Demonstration and validation of the project solutions will be done in real conditions
in five different electric cooperatives and non-profit sites in five EU members’ states.
Project FP7-S3c
Title: Smart Consumer - Smart Customer – Smart Citizen
The S3C project’s overall objective is to foster the ‘smart’ energy behaviour of energy customers in Europe
by assessing and analysing technology and user-interaction solutions and best practices in scientific
literature, test cases and pilot projects. Based on these insights, the S3C consortium has developed a practical
toolkit for everyone who is involved or intends to become involved in the active engagement of end users in
smart energy projects or rollouts.
Cordis web site: http://cordis.europa.eu/project/rcn/105831_en.html
Project web Site: http://www.s3c-project.eu/
Important project outcomes include:
- The project suggests that energy system actors (e.g. DSOs, suppliers, ESCOs, regulators) must adapt the
way and the content of their communication with customers and citizens, taking into account the
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diversity of consumer segments with different backgrounds and needs. The content of communication
must be transformed into something more visual, tangible and understandable, showing exactly the
benefits customers may experience (e.g. saved money, reduction of CO2 emission) instead of a purely
technical information.
Project FP7-metaPV
Title: Metamorphosis of Power Distribution: System Services from Photovoltaics
The goal of the demonstrator was to explore in real life how PV systems can provide grid services for
increasing the hosting capacity of existing grids. This was pursued by adding a significant amount of
controllable inverters to a confined grid where the PV penetration was high already before. The demonstrator
is split up in a low voltage (LV) and a medium voltage (MV) part. On LV, the project aimed to convince 128
households' consumers to install PV systems of an average PV generation capacity of 4 kW, for a total of
512 kW. On MV, the target was to realise 31 installations of on average 200 kW, for a total of 6,2 MW,
located at commercial and industrial sites connected to the MV grid.
Notably, all PV inverters generate low voltage at their output; however, the so-called MV systems are directly
connected to the medium voltage grid through a transformer..
Cordis web site: http://cordis.europa.eu/project/rcn/94493_en.html
http://cordis.europa.eu/project/rcn/107957_en.html
Project web Site: http://metapv.eu
Important project outcomes include:
- MetaPV demonstrated that remotely controllable inverters connecting PV-panels to the distribution grid
can offer congestion management services to the distribution grid (in the form of voltage control
obtained via reactive power modulation).
- For medium-voltage grids, the hosting capacity of the network can be increased by more than 50% at
the cost of 10% of traditional grid reinforcement. For low-voltage grids, the same is also possible as
long as the costs of sophisticated features for communication do not eat up the savings from the
substituted grid reinforcement.
In MetaPV, the household received a commercial offer for the demonstrator. This offer was attractive, partly
because the inverter was offered by the inverter manufacturer at the cost (not price). DSO paid for
additional equipment needed (like hardware for data logging and communication, batteries, etc.). In
exchange, the customers acknowledged that the installations made part of a demonstration and that DSO
had the right to control them from time to time.
- MetaPV suggests that DSO makes a multiannual investment plan that takes into account flexibility
(MetaPV suggests to do this through a cost-based analysis).
- The case of MetaPV raises the question if the DSOs have the right to use or impose functions to the
customers where the PV inverters are placed. Direct control over the inverter is only granted (in special
cases) in Austria and Germany whereas in several countries DSO can impose functions to PV inverters.
Project FP7-INTrEPID
Title: INTelligent systems for Energy Prosumer buildings at District level
INTrEPID developed technologies that enable energy optimization of residential buildings, allowing control
of internal sub-systems within the Home Area Network and interaction with other buildings, local producers,
and electricity distributors, as well as enabling energy exchange capabilities at district level. The project had
three main objectives: A. Energy optimization, which is provided by the development of three INTrEPID
technological components (Indoor Home networks, Supervisory control strategies and Energy Brokerage);
B. Integration and validation of the integrated system. C. Dissemination and Exploitation.
Cordis web site: http://cordis.europa.eu/project/rcn/105992_en.html
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Project web Site: http://www.fp7-intrepid.eu/ intrepid@telecomitalia.it
Important project outcomes include:
- A methodology to extract individual power consumption of home appliances with a measurement at a
single point, using non-intrusive load monitoring (NILM) has been developed. NILM algorithms utilize
machine learning to detect and extract features from the aggregated consumption data. For the
households considered in the INTrEPID project, the algorithm disaggregates the individual consumption
of major appliances, without the added cost of an individual meter per device. The tested algorithm
performs well in the experiments and delivers on its promises in simple settings, where the models
account for all of the loads. However, in the final scenario, the algorithm has to give up due to lack of
models and detailed datasets. Producing the Markov models for the algorithm proves to be the biggest
disadvantage of the algorithm. Attempts were made to construct these by manual inspection of the
dataset, which did prove to be quite successful. However, it was necessary to make assumptions about
the states of the refrigerator. For the general case this works quite well, but the possible defrost cycle
was not taken into account, and only one program in the dish washer was considered. This indicates that
exhaustive knowledge about the appliance is required, when reasoning about the number of states and
transitions.
- This project shows that direct access to the meter should be considered for other parties to be able to
develop innovative services based on NILM algorithm. It is therefore not good for innovation if all
information from the smart meter has to go via the DSO first.
- The project also demonstrates that there are further dimensions to investigate when considering the data
customer confidentiality
Project FP7- INCREASE
Title: Increasing the Penetration of Renewable Energy Sources in the Distribution Grid by Developing
Control Strategies and using Ancillary Services
INCREASE focuses on how to manage renewable energy sources in LV and MV networks, to provide
ancillary services (towards DSO, but also TSOs), in particular voltage control and the provision of reserve.
INCREASE investigates the regulatory framework, grid code structure and ancillary market mechanisms,
and propose adjustments to facilitate successful provisioning of ancillary services that are necessary for the
operation of the electricity grid, including flexible market products
Cordis web site: http://cordis.europa.eu/project/rcn/109974_en.html
Project web site: http://www.project-increase.eu/
Important project outcomes:
- The market access for aggregators is improving in some EU countries, while others are still lagging
behind. Often the regulatory frameworks are not supportive for demand response or participation of
distributed renewable generation.
- Important adjustments of market regulations can be observed in a few countries, namely the reduction
of the minimum bid sizes to allow small renewable generations to participate in tenders, and shorter
scheduling periods. However in several EU countries no suitable frameworks to enable participation of
flexibility aggregators yet exist.
Project FP7- evolvDSO
Title: Development of methodologies and tools for new and evolving DSO roles for efficient DRES
integration in distribution networks
With the growing relevance of distributed renewable energy sources (DRES) in the generation mix and the
increasingly pro-active demand for electricity, power systems and their mode of operation need to evolve.
evolvDSO will define future roles of distribution system operators (DSOs) and develop tools required for
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these new roles on the basis of scenarios which will be driven by different DRES penetration levels, various
degrees of technological progress, and differing customer acceptance patterns.
Cordis web site: http://cordis.europa.eu/project/rcn/109548_en.html
Project web Site: http://www.evolvdso.eu/
Important project outcomes include:
- DSOs can create additional value by offering/using services to/from different stakeholders in the interest
of the entire power system and its users. A sound regulatory framework can support them in these
activities.
- Future markets and regulatory frameworks should recognize the need and should provide incentives for
possible innovative flexibility levers to be procured and activated on distribution grid level. Different
stakeholders may benefit from these flexibility levers. DSOs may need these services in different
timeframes as alternatives for grid investment (long-term ahead, procured via tender) and/or
conventional operational planning actions (short-term ahead, procured via a (flexibility) market
platform). DSOs will have to gradually increase their network monitoring capacities, as well as their
active involvement in flexibility services.
Future regulatory frameworks should set clear rules for the recognition of the costs (both CAPEX and OPEX,
over all timeframes) associated with innovative smart grid solutions, taking into account their interaction
with conventional solutions and the uncertainty on cost recovery.
- Future regulatory frameworks should continue to safeguard the availability of neutral, secure, cost-
efficient and transparent data and information management on distribution grid level for all concerned
stakeholders.
- Future electricity markets will need to take into account the location of system flexibility sources and
their impact on distribution grids.
Project FP7- DREAM
Title: Distributed Renewable resources Exploitation in electric grids through Advanced heterarchical
Management
DREAM is working on an innovative organisational and technological approach for connecting electricity
supply and demand. Heterarchical principles, in which coordination is configurable, are used to coordinate
users, producers and technical/commercial/financial operators to achieve benefits. These are expected to well
exceed the technological investments required to final users. This will be pursued also through the
introduction of a new layer in the energy market, placed at distribution level and allowing for cost-effective
dynamic aggregations of users and local exchange/sales of capabilities (e.g. ancillary services from shed-
able loads or from time-flexible use of electric power), while ensuring integration with upper level national
energy marketplaces and their international interactions..
Cordis web site: http://cordis.europa.eu/project/rcn/109909_en.html
Project web Site: http://www.dream-smartgrid.eu/
Important project outcomes include:
- The intrinsic control capability made available at distribution network level through the innovative
heterarchical paradigm of DREAM, will accommodate for improved real time local balancing of energy
demand and provision, thus limiting the request of voltage and frequency regulation capacity at
transmission and distribution control level.
- The net effect of additional local balancing capacity will be reflected into a reduction of network
reinforcement requirements, and thus will increase the allowance for safe management of renewable and
distributed energy resources at the same level of deployed reinforcements.
Project FP7-PlanGridEV
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Title: Distribution grid planning and operational principles for electric vehicles mass roll-out while enabling
integration of renewable distributed energy sources.
The increasing number of electric vehicles (EVs) (and their batteries) on the one hand and of distributed
energy sources (DER) on the other, both connected to the low-voltage (LV) and the medium-voltage (MV)
grid, are a major challenge for Distribution System Operators (DSOs) with regard to secure and reliable
energy supply and grid operation. The project developed a planning tool for DSOs which copes with this
new challenge and facilitates the transformation of the grid towards a smart grid (with controllable loads).
With the help of the tool, investment strategies regarding the reinforcement of infrastructures can be
downsized while the service quality and efficiency can be improved at the same time (reduction of peak loads
and increased renewable energy supply). PlanGridEV developed architectures to build smart grids that
support a successful and economical rollout of charging infrastructure. In addition to paving the way into a
new way of mobility these architectures are able to activate new markets where the costumers’ (EV users)
can participate and benefit from (change from costumer to prosumer e.g. by offering battery capacity for grid
stability services).
Cordis web site: http://cordis.europa.eu/project/rcn/109374_en.html
Project web site: http://www.plangridev.eu/
Important project outcomes include
- The new planning tool for DSOs: it considers the controllability of the loads (i.e. EVs) with the
(estimated) electricity generation from renewable resources;
- Tests with controllable loads DER performed in a large variety of grid constellations have shown that
peak loads could be reduced (up to 50%) and more renewable electricity could be transported over the
grid compared to scenarios with traditional distribution grid scenarios; as a result, critical power supply
situations can be avoided, and grids, consequently, do not call for reinforcement;
- Smart grids on LV/MV level require the introduction of more information and communication
technologies (ICT) allowing the exchange of operation data and control schemes between independent
market actors. PlanGridEV outlines changes of the regulatory framework allowing for a new market
design embedded within a roadmap and tangible recommendations for (i) industry, (ii) grid operators
and service providers, (iii) policy makers, and (iv) regulators with the aim that investments in grid
intelligence can be rewarded via modified tariff systems and market borders can be broken down.


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 1/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
2
Abstract of the Impact Assessment of the Market Design Initiative
I. POLICY CONTEXT AND KEY CHALLENGES
The Energy Union framework strategy puts forward a vision of an energy market 'with
citizens at its core, where citizens take ownership of the energy transition, benefit from
new technologies to reduce their bills, participate actively in the market, and where
vulnerable consumers are protected'.
Well-functioning energy markets that ensure secure and sustainable energy supplies at
competitive prices are essential for achieving growth and consumer welfare in the
European Union and hence are at the heart of EU energy policy.
To live up to this vision, a series of legislative proposals have been prepared, following
the objectives of secure and competitive energy supplies and building on the EU's 2030
climate commitments reconfirmed in Paris last year.
The electricity sector will be one of the main contributors to decarbonise the economy.
Currently, 27.5% of Europe's electricity is produced using renewable energy and the
modelling shows that close to half of our electricity will come from renewables by 2030.
With increasing use of electricity in sectors like transport or heating and cooling,
traditionally dominated by fossil fuels, it is ever more important to further increase the
share of renewable energies in electricity and to unlock flexible demand, generation and
storage solutions.
A new regulatory framework is needed to address these challenges and opportunities.
The new proposals for a revised Renewable Energy Directive and for a new Market
Design will precisely do this, by deepening integration of the internal energy market,
empowering consumers, stepping up regional and EU-wide cooperation and providing
the right signals for investment, thus ensuring secure, sustainable and competitive
electricity systems.
A successful transition of the energy system delivering on the ambition to become world
leader in renewables will require substantial investment in the sector, and in particular
investments in low-carbon generation assets as well as network infrastructure. This
requires a revised Emissions Trading System in order to address the current surplus of
allowances and to deliver a strong investment signal to reach 40% greenhouse gas
emissions reductions by 2030, but also specific rules to complement market revenues if
those are not sufficient to attract investments in renewable electricity. In addition,
measures to promote renewable energies in sectors like transport or heating and cooling
are also crucial. Reaching the 2030 framework targets and achieving an Energy Union
will be underpinned by a strong Energy Union governance, which will ensure the
necessary ambition level in an iterative dialogue between the Commission and all
Member States. Finally, a successful transition of the energy system will also require
continued commitment and support for infrastructure development both locally as well as
across borders.
3
At the same time the transition will only be successful if consumers are given the
information, opportunities and rewards to actively participate in it. The availability of
new technologies that allow consumers to both consume electricity in a smarter way as
well as produce it themselves at costs which are more and more competitive opens up
manifold possibilities. What is still needed to fully reap these opportunities is the
appropriate regulatory framework accompanying the digital transformation and
technological development that will empower consumers to take part in the energy
transition by becoming active market participants. Empowering consumers in this way
will also contribute to a more efficient use of energy and is therefore an integral part of
implementing the efficiency first principle.
Finally, the EU will only be able to manage the energy transition successfully and cost-
effectively in a more deeply integrated internal electricity market. Only a more
competitive and better interconnected market will allow Europe to drive cost-efficient
investment and in particular to integrate the rising share of renewable energy production
in a cost-efficient and secure manner into the system, profiting fully from
complementarities between Member States and broader regions.
Such a deeply integrated and competitive market is also a key building block for
guaranteeing security of supply and policies and mechanisms intended to reach this
objective should follow a cooperative logic. National security of supply policies need to
be better coordinated and aligned. This will ensure that Member States are duly prepared
to tackle possible crisis situations, in particular those that affect several countries at the
same time.
The present package of legislative measures directly contributes to the Energy Union
dimensions of energy security, solidarity and trust, a fully integrated internal energy
market as well as decarbonisation of the economy, while also indirectly contributing to
the other two.
II. LESSON LEARNED AND PROBLEM DEFINITION
Three consecutive legislative packages have transformed what used to be fragmented
energy markets in Europe into a more integrated Internal Electricity Market, thus
increasing competition. However, Europe's energy markets are undergoing further
profound changes.
The transition towards a low-carbon electricity production poses a number of
challenges for the secure and cost-effective organisation and operation of Europe’s power
grids and electricity markets. The increasing penetration of variable and decentralised
renewable energy – driven inter alia by the EU’s goals for climate change and energy in
line with the 2020 and 2030 targets – requires the electricity sector to be operated
more flexibly and efficiently.
Today, most new installed capacity is based on wind and solar power which are
inherently more variable and less predictable when compared to conventional sources of
4
energy (predictable central, large-scale fossil fuel-based power plants) or flexible
renewable energy technologies (e.g. biomass, geothermal or hydropower). By 2030, this
trend is expected to be ever more pronounced. As a result, there will be times when
variable renewables could cover a very large share - even 100% - of electricity demand
and times when they only cover a minor share of total consumption. The overall
electricity supply and demand needs to be in balance in physical terms at any given point
in time (including production or storage of electricity). This balance is a precondition for
the secure operation and stability of the electricity grid, thus avoiding the risk of black-
outs.
Current market arrangements do not adequately incentivize all market participants –
including renewable energy generation - to adjust their portfolios by revising production
and consumption plans on short notice. The manner in which the trading of electricity is
arranged and in which the methods for allocating the network capacity to transport
electricity are organized, allow only for efficient trading of electricity in timeframes of
one or more days ahead of physical delivery. Yet, the increasing penetration of variable
renewable sources of electricity ('RES E') requires efficient and liquid short-term markets
that can operate as close to real time as possible – until very shortly before the time of
physical delivery (i.e. the moment when electricity is consumed). Indeed, most renewable
generation can only be accurately predicted shortly before the actual production (due to
weather uncertainties). Flexibility is essential to deal effectively with an increased share
of variable renewable generation. Besides, these markets do not fully take into account
possible contribution of cross-border resources.
Retail markets for energy in most parts of the EU suffer from persistently low levels
of competition, consumer choice and engagement. In spite of falling prices on
wholesale markets, retail prices have risen steadily for households as a result of
significantly increased network charges, taxes and levies in recent years. Market
concentration remains generally high due to persisting barriers to new entrants.
Switching related fees such as contract termination charges continue to constitute a
significant financial barrier to consumer engagement. In addition, the high number of
complaints related to billing suggests that there is still scope to improve the
comparability, clarity and accuracy of billing information.
Despite technical innovations that allow consumers to better and more easily manage
their energy use – smart grids, smart homes, rooftop solar panels and storage, for
example – consumers are not sufficiently able to actively participate in electricity
markets and match demand with supply during peak times, particularly through demand-
response. This is because households and businesses often have scarce knowledge and
little or no incentive to change the amount of electricity they use or produce in response
to changing prices in the markets. Indeed, a host of issues such as a slow roll out of fully
functional smart metering systems, regulated prices, lacklustre competition between
retailers and an increasing portion of fixed charges in energy bills mean that real-time
price signals are usually not passed on to final consumers.
5
In some Member States, up to 90% of renewable electricity generation is connected at
distribution level, putting more pressure on distribution system operators ('DSOs') to
actively manage their grids and to efficiently adjust to the increasing share of variable
and decentralized renewable electricity injected into their networks. However – in
contrast to transmission system operators ('TSOs') – the current regulatory framework
does not always provide appropriate tools to DSOs to do this, resulting in network
charges that are often higher than they could be for end consumers. Ensuring that all
DSOs become more flexible would create a level playing field for the deployment of
renewable generation that would make attaining the EU's climate and energy objectives
easier.
The deployment of information technology offers the possibility to address these issues,
facilitating the development of new services, improving consumer's comfort and making
the market more contestable and efficient. However, to fully benefit from the
digitalisation of the electricity market we need a non-discriminatory data management
framework that makes the right information immediately available to the right market
actors, while at the same time ensuring a high level of data protection.
With regard to consumer protection, there is a need to ensure that the move towards more
efficient retail markets does not lead to any group of consumers being left behind. In
particular, rising energy poverty as well as a lack of clarity on the most appropriate
means of tackling consumer vulnerability and energy poverty can hamper the further
deepening of the internal energy market.
In the current context, wholesale electricity prices have been decreasing due to
number of coinciding drivers: a decline in primary energy prices, a surplus of carbon
allowances and an overcapacity of power generation facilities in some regions of the EU
caused by a drop in electricity demand, rising investments in renewables driven by EU
policies and increased sharing of resources among Member States through market
coupling.
For most regions in Europe, current electricity wholesale prices do not indicate the
need for new investments into electricity generation. However, in the current market
arrangement, prices often do not reflect the real value of electricity due to regulatory
failures such as the lack of scarcity pricing and inadequately delimited price (or bidding)
zones. These regulatory failures, taken together with the increasing penetration of
electricity generated from renewable sources with low operating costs, affect the
remuneration of conventional electricity generation units that operate less often but
contribute to providing security and flexibility to the system – alongside non-
conventional flexible generation, interconnections, storage and demand response.
In light of the 2030 objective for renewable energy, considerable new investment in
electricity generation capacity will be required. The largest part will be provided by
variable renewable generation, complemented to a certain extent by more predictable,
flexible, less carbon-intensive forms of power generation. Independently of current
overcapacities, there are growing concerns in some areas of Europe that current average
6
wholesale prices may not provide appropriate signals for the necessary investments into
future generation or for keeping sufficient capacity in the market. A number of Member
States anticipate inadequate generation capacity in future years and introduce capacity
mechanisms at national level to support investment in capacity and ensure system
adequacy (i.e. the ability of the electricity system to serve demand at all times). When
uncoordinated and designed without a proper assessment of the appropriate level of
supply security, capacity mechanisms may risk affecting cross-border trade,
distorting investment signals, affecting thus the ability of the market to deliver any new
investments in conventional and low-carbon generation, and strengthening market
power of incumbents by not allowing alternative providers to enter the market.
Despite best efforts to build an integrated and resilient power market, crisis situations can
never be excluded. The potential for crisis situation increases with climate change (e.g.
extreme weather conditions) and the emergence of new areas that are subject to
criticalities such as malicious attacks and cyber-threats. Such crises tend to often have an
immediate cross-border effect in electricity. Where systems are interconnected, incidents
that start locally can rapidly spread beyond borders and crisis situations might also affect
several Member States at the same time (e.g. prolonged heat waves or cold spells).
Today, risk assessments as well as plans and actions for dealing with electricity crisis
situations focus on the national context only and there is insufficient information-
sharing and transparency across Member States. In addition, there are different views on
what is to be considered as a risk to security of supply. In an increasingly inter-connected
electricity market, the lack of common approach and coordination can seriously imperil
security of supply across borders and dangerously undermine the functioning of the
internal electricity market.
In addition, missing opportunities to exchange energy with neighbours remains a key
obstacle to the internal energy market. Even where interconnectors are in place, they
often remain unused due to a lack of coordination between Member States. Rules are
therefore needed that ensure that the use of interconnection is not unduly limited by
national interventions.
Based on the above-mentioned shortcomings and underlying drivers, the present impact
assessment has identified four key problem areas that are addressed in the proposed
initiative: i) the current market design is not fit for integrating an increasing share
of variable, decentralised generation and for reaping the potential of technological
developments; ii) uncertainty about sufficient future generation investments and
uncoordinated capacity mechanisms; iii) Member States do not take sufficient
account of what happens across their borders when preparing for and managing
electricity crisis situations; and iv) as regards retail markets, there is a slow
deployment and low levels of services and poor market performance are wide-
spread in the EU.
7
III. SUBSIDIARITY
Article 194 of the Treaty of the Functioning of the EU consolidated and clarified the
competences of the EU in the field of energy and is the legal basis of the current
proposal.
Electricity markets have become more integrated and interdependent physically,
economically and from a regulatory point of view, due to increasing cross-border
electricity trade, growing share of renewable energy sources and more interconnections
in the European electricity grid. The challenges can no longer be addressed as effectively
by individual Member States. New frameworks to further integrate the internal energy
market and improve the conditions for competition while at the same time adjusting to
the decarbonisation targets and ensuring a more coordinated policy response to security
of supply, can most effectively be achieved at European level.
IV. SCOPE AND OBJECTIVES
Against this background and in line with the Union's policy on climate change and
energy, the general policy objective of the present initiative is to make electricity markets
more secure, efficient and competitive, while ensuring that electricity is generated in a
sustainable way and remains affordable to all consumers. The present impact assessment
reflects and analyses the need and policy options for a possible revision of the main
framework governing electricity markets and security of supply policies in Europe.
There are four specific objectives: i) adapt the market design for the cost effective
operation of variable and often decentralised generation, taking into account
technological developments; ii) facilitate investments in generation capacity in the right
amount and type of resources for the EU: iii) improve Member States' resilience on each
other in times of system stress and reinforce their coordination and cooperation regarding
crisis situations; and iv) address the root causes of weak competition on energy retail
markets and improve consumer protection and engagement.
Interlinkages with parallel initiatives
The proposed initiative is strongly linked to other energy and climate related legislative
proposals brought forward in parallel, including the renewable energy package which
covers a number of measures deemed necessary to attain the EU binding objective of
reaching a level of at least 27% renewables in final EU energy consumption by 2030.
The renewable energy directive has synergies with the present initiative, which seeks to
adapt the current market design to the increasing share of variable decentralised
generation and technological development and to create an environment conducive for
investments in renewables.
In particular, the reflections on a revised Renewables Energy Directive will include
framework principles on support schemes for market-oriented, cost-effective and more
regionalised support to RES E up to 2030, in case Member States were opting to have
them as a tool to facilitate target achievement. Conversely, measures aimed at the
integration of RES E in the market, such as provisions on priority dispatch and access
8
previously contained in the Renewables Directive are part of the present market design
initiative. The Renewable Package also deals with legal and administrative barriers for
self-consumption, whereas the present package addresses market related barriers to self-
consumption.
Both the market design and renewable energy impact assessments come to the conclusion
that the improved electricity market, supported through a revised Emission Trading
System ('ETS'), could, under certain conditions, by 2030 deliver investments in the most
mature low-carbon technologies (such as PV and onshore wind). However, until such
conditions materialise, market-based support schemes will still be needed in order to
provide investment certainty. Less mature RES E technologies, such as offshore wind,
will likely need some form of support throughout the transitional period.
The Energy Union governance initiative also has synergies with the present initiative and
will contribute to ensure policy coherence and reduce administrative impact. It will also
streamline the reporting obligations by Member States and the Commission that are
presently enshrined in the Third Package.
In general terms, energy efficiency measures also interact with the present initiative as
they affect the level and structure of electricity demand. In addition, energy efficiency
measures can alleviate energy poverty and consumer vulnerability. Besides consumer
income and energy prices, energy efficiency is one of the major drivers of energy
poverty. The provisions previously contained in the energy efficiency legislation on
demand response, billing and metering will be set out in the present initiative.
The present initiative is furthermore consistent with the findings of the sector inquiry on
capacity mechanisms. Pointing out that there is a lack of adequate assessment of the
actual need for capacity mechanisms, the sector inquiry emphasizes that where needed
capacity mechanisms need to be designed with transparent and open rules of participation
that does not undermine the functioning of the electricity market, taking into account
cross border participation.
The Commission Regulation establishing a Guideline on Electricity Balancing
('Balancing Guideline') is also closely related to the present initiative as it aims to
harmonise certain aspects of the EU's balancing markets and to optimise cross-border
usage. Indeed, efficient, integrated balancing markets are an important building block for
the consistent functioning and flexibility of the market which in turn is needed for a cost
effective integration of RES E into the electricity market.
V. DESCRIPTION OF POLICY OPTIONS AND METHODOLOGY
In assessing all possible options (ranging from non-regulatory to legislative policy
options) the following approach was taken:
- Identification of a set of high level options for each problem area. Each of these high
level options contains sub-options for specific measures;
9
- Assessment of each specific measure, comparing a number of options in order to
select the preferred approach.
The following policy options have been considered:
Regarding Problem Area I: the need to adapt the market design to the increasing
share of variable decentralised generation and technological developments,
Option 0+ (Non-regulatory approach) provides little scope for improving the market and
the level-playing field among resources. Indeed, the current EU regulatory framework is
limited in certain areas (e.g., balancing and intraday markets) and even non-existent for
other areas (e.g., role of DSOs in data management). Besides, voluntary cooperation may
not provide for the appropriate levels of harmonisation or certainty to the market and
legislation. This option was therefore discarded.
Two possible paths going beyond the baseline scenario were however identified and
assessed: (i) enhancing current market rules through EU regulatory action in order to
increase the flexibility of the system, retaining to a certain extent the national operation
of the systems (Option 1) and, (2) moving to a fully integrated approach via relatively
far-reaching changing to the current regulatory framework (Option 2).
Option 1 of enhancing the current market rules comprises three different sub-options:
Option 1(a) Creating a level-playing field among all generation technologies and
resources and remove existing market distortions. It addresses rules that
discriminate between resources and which limit or favour the access of
certain technologies to the electricity grid (such as so-called 'must-run'
provisions and rules on priority dispatch and access). In addition, all
market participants would bear financial responsibility for the imbalances
caused on the grid and all resources would be remunerated in the market
on equal terms. Barriers to demand-response would be removed.
Exemptions from certain regulatory provisions may, in some cases, be
required, notably for certain small-scale installations and emerging
technologies.
Option 1(b) (In addition to sub-option (a)) Strengthening the short-term markets by
bringing them closer to real-time in order to provide maximum
opportunity to meet the flexibility needs and balance the market. The
sizing of balancing reserves and their use would be harmonised in larger
balancing zones in order to optimally exploit interconnections and cross-
border exchange in shorter term markets.
Option 1(c) (In addition to sub-option (a) and (b)) Pulling all flexible distributed
resources concerning generation, demand and storage, into the market via
proper incentives and a market framework better adapted to them. This
would be based on smart-metering allowing consumers to directly react to
price signals and measures to incentivise DSOs to manage their networks
in a flexible and cost-efficient way.
10
Option 2 (fully integrated market) considers measures that would aim to deliver a truly
integrated pan-European electricity market through the adoption of far-reaching measures
changing the current regulatory framework.
Regarding Problem Area II: uncertainty about sufficient future generation
investments and uncoordinated capacity mechanisms, four options were considered.
As regards Option 0+ (Non-regulatory approach), existing provisions under EU
legislation are not sufficiently clear and robust to cope with the challenges facing the
European electricity system. In addition, voluntary cooperation may not provide for
appropriate levels of harmonisation across all Member States or certainty to the market.
Legislation is needed in this area to address the issues in a consistent way. This Option
was therefore discarded.
Various policy options going beyond the baseline scenario were assessed. They differ
according to which extent market participants can rely on energy market payments. Each
policy option also considers varying degrees of alignment and coordination among
Member States at EU-level.
Option 1 (energy-only market without capacity mechanisms) builds upon Option 1(a) to
1(c) under problem area I and would be based on additional measures to further
strengthen the internal electricity market. Under this option, it is assumed that European
markets, if sufficiently interconnected and undistorted, can provide for the necessary
price signals to incentivise investments in new generation thus also reducing the need for
government interventions in support thereof. This option consists of improving price
signals by removing price caps in order to allow scarcity pricing during peak time. At the
same time, price signals could drive the geographical location of new investments and
production decisions, via price zones aligned with structural congestion in the
transmission grid.
Option 2 and 3 include the measures presented in Option 1, but allow capacity
mechanisms under certain conditions and propose possible measures to better align them
among Member States in order to avoid negative consequences for the functioning of the
internal market. These options build on the European Commission's 'EEAG' state aid
Guidelines and the Sector Inquiry on capacity mechanisms. In Option 2, capacity
mechanisms are based on a transparent and EU-wide resource adequacy assessment
carried-out by the European Network of Transmission System Operators for electricity
('ENTSO-E'). Such EU-wide assessment would also allow for effective cross-border
participation. Additionally, Option 3 would provide for common design features for
better compatibility between national capacity mechanisms and harmonised cross-border
cooperation.
Under Option 4 based on regional or EU-wide generation adequacy assessments, entire
regions or ultimately all EU Member States would be required to roll out capacity
mechanisms on a mandatory basis. This option was found to be disproportionate and was
discarded.
11
Regarding Problem Area III: the lack of coordination among Member States when
preparing for and managing electricity crisis situations, five policy options ranging
from the baseline scenario (Option 0) to the full harmonization and decision making at
regional level have been identified.
Option 0+ (Non-regulatory approach). As current legislative provisions do not prescribe
how Member States should prevent and manage crisis situations nor mandate any form of
cross-border co-operation, better implementation and enforcement actions will be of no
avail. In addition, whilst there is some voluntary cross-border cooperation in this area, it
is limited to a few regional parts of the EU. This option was discarded.
Under Option 1 (Common minimum EU rules), Member States would have to respect a
set of common rules and principles regarding crisis prevention and management, agreed
at the European level ('minimum harmonisation'). Accordingly, non-market measures
should only be introduced as a means of last resort, when duly justified. Member States
would be obliged to address electricity crisis situations, in particular situations of a
simultaneous crisis, in a spirit of co-operation and solidarity. Member States should
inform each other and the Commission without undue delay when they see a crisis
situation coming or when being in a crisis situation. Member States would be obliged to
develop national Risk Preparedness Plans ('Plan') with the aim to avoid or better tackle
crisis situations. Plans could be prepared by TSOs, but need to be endorsed at the
political level. On cyber-security, Member States would need to set out in the Plan how
they will prevent and manage cyberattack situations.
Option 2 (EU rules + regional cooperation) would include all common rules included in
Option 1. In addition, it would put in place rules and tools to ensure that effective cross-
border co-operation takes place in a regional and EU context. Thus, there would be a
systematic assessment of rare/extreme risks at the regional level. The identification of
crisis scenarios would be carried out by ENTSO-E in a regional context and tasks would
be delegated to Regional Operation Centres (ROCs). For cybersecurity, the Commission
would propose the development of a network code/guideline which would ensure a
minimum level of harmonization in the energy sector throughout the EU. The Risk
Preparedness Plans would contain two parts – a part reflecting national measures and a
part reflecting measures to be pre-agreed in a regional context (including regional 'stress
tests', procedures for cooperation in different crisis scenarios and agreement on how to
deal with simultaneous electricity crisis situations).
Option 3 (Full harmonisation) entails full harmonisation and decision-making at regional
level. The risk preparedness plans would be developed on regional level in order to allow
a harmonised response to potential crisis situation in each region. On cybersecurity,
Option 3 would go one step further and nominate a dedicated body (agency) to deal with
cybersecurity in the energy sector. Crisis would have to be managed according to the
regional plans agreed among Member States. A detailed 'emergency rulebook' for crisis
handling would be put in place, containing an exhaustive list of measures that can be
taken by Member States in crisis situations.
12
Regarding Problem Area IV: retail markets and the slow deployment and low levels
of services and poor market performance, four policy options have been considered
ranging from baseline scenario (Option 0) to full harmonization and extensive safeguards
for consumers.
Option 0+ (Improved implementation/enforcement and non-regulatory approach)
consists in sharing of good practices and increasing the efforts to correctly implement the
legislation. This non-regulatory approach addresses competition and consumer
engagement issues by strengthening the enforcement of the existing legislation as well as
through bilateral consultation with Member States to progressively phase-out price
regulation, starting with prices below costs. It also considers developing a
Recommendation on energy bills. However, this option does not tackle the third problem
driver of the market failures that prevent effective data flow between market actors.
Under Option 1 (Flexible legislation), all problem drivers are addressed through new
legislation. To improve competition, Member States progressively phase-out blanket
price regulation by a deadline specified in new EU legislation, starting with prices below
costs, while allowing transitional price regulation for vulnerable consumers. To increase
consumer engagement, the use of contract termination fees is restricted. Consumer
confidence in comparison websites is fostered through national authorities implementing
a certification tool. In addition, high-level principles ensure that energy bills are clear and
easy to understand, through minimum content requirements. A generic adaptable,
definition of energy poverty based on household income and energy expenditure is
proposed in the legislation for the first time. Finally, to allow the development of new
services by new entrants and energy service companies, non-discriminatory access to
consumer data is ensured.
Building on Option 1, Option 2 (Full harmonisation and extensive consumer safeguards)
aims to provide maximum safeguards for consumers and extensive harmonisation of
Member States action throughout the EU. Exemptions to price regulation are defined at
EU level on the basis of either a consumption threshold or a price threshold. A standard
data handling model is enforced and assigns the responsibility to a neutral market actor
such as a TSO. All switching fees including contract termination fees are banned and the
content of energy bills is partially harmonized. Finally, an EU framework to monitor
energy poverty based on an energy efficiency survey done by Member States of the
housing stock as well as preventive measures to avoid disconnections are put in place.
VI POLICY TRADE-OFFS
The measures considered in this impact assessment are highly complementary. Most of
the different options considered in each problem area would reinforce the effect of
options in other problem areas, with little trade-offs between the different areas. The
overall beneficial effects will be achieved only if all measures are implemented as a
package
The measures under Problem Area I and II are strongly linked in that they collectively
aim at improving market functioning, including the delivery of investment by the market.
13
Measures under Problem Area I and Option 1 of Problem area II thus reduce the need for
market government intervention by means of capacity mechanisms. The other measures
under Problem Area II reduce their distortive effects if such mechanisms are nonetheless
justified.
Scarcity pricing and capacity mechanisms can to a certain degree be seen as alternative
measures to foster investments. With assets remunerated by capacity mechanisms, the
effectiveness of scarcity prices may be reduced. It needs also to be noted that scarcity
prices and market-wide capacity mechanisms incentivise different investment decisions:
whereas such capacity mechanisms may reward any firm capacity, scarcity pricing will
improve remuneration of flexible capacity in particular.
The measures aiming at providing adequate price signals (measures under Problem Area
I and Problem Area Option 1) are no-regret options. Until these conditions are achieved
and under specific circumstances (like energy isolation), State intervention in the form of
some type of capacity mechanism may be necessary. That is why it is essential that such
mechanisms are properly designed, taking into account the wider regional and European
resources and allowing cross-border participation in a technology-neutral manner.
The measures assessed under various options in the impact assessment seek to improve
the overall flexibility of the electricity system. However, they do this by employing
different means. Investment in new interconnection capacity may reduce the need for
new generation and vice-versa, new generation can reduce the incentives for new
interconnector capacity. Similarly, pulling demand response into the market will reduce
the profits of generation capacity. Ultimately, the efficient markets should opt for the
most cost-efficient solutions.
Energy poverty safeguards whose costs directly accrue to suppliers – particularly, the
disconnection safeguards considered in Option 2 (Harmonization and extensive consumer
safeguards) of Problem Area IV (Retail markets) – may act as a barrier to retail-level
competition, and diminish the associated benefits to consumers, including lower prices,
new and innovative products, and higher levels of service. Although the implementation
costs of these safeguards will be passed on to consumers, and therefore socialized,
different energy suppliers may have different abilities to do this, and to deal with the
additional consumer engagement costs. Some may therefore choose not to enter markets
with such safeguards in place.
VII. ANALYSIS OF IMPACTS AND CONCLUSIONS
All options have been compared against each other using, the baseline scenario as a
reference and applying the following criteria:
- Effectiveness: the options proposed should first and foremost be effective and thus be
suitable to addressing the specified problem;
- Efficiency: this criterion assesses the extent to which objectives can be achieved at
the least cost (benefits versus the costs).
14
Policy options regarding the need to adapt the market design to the increasing share
of variable decentralised generation and technological developments (Problem Area
I)
Options 1(a) (level playing field), 1(b) (strengthening short-term markets) and 1(c)
(demand response/distributed resources) represent an interlinked set of measures
regarding the integration of the national electricity markets and present a compromise
between bottom-up initiatives and top-down steering of the market development, without
substituting the role of national governments, regulators and TSOs by a centralised and
fully harmonised system.
However, Option 1(a) (level playing field) and Option 1(b) (strengthening short-term
markets) do not cover measures to pull all distributed flexible resources (demand-
response, renewable electricity and storage) into the market. These options do not take
advantage of the potential offered by these resources to efficiently operate and
decarbonise the electricity market.
In this context, Option 1(c) (demand response/distributed resources) provides a more
holistic, effective and efficient package of solutions. While this option may lead to minor
additional administrative impacts for Member States and competent authorities regarding
the implementation and monitoring of the measures, these impacts will be offset by lower
barriers to entry to start-ups and SMEs, by the benefits to market parties from more
stable regulatory frameworks and new business opportunities as well as by the benefits to
consumers from more competition and access to wider choice.
As regards Option 2 (fully integrated market), while having advantages in terms of less
coordination requirements (i.e., a fully integrated EU-market can be operated more
efficiently), the results of the assessment indicate that the move towards a more
integrated European approach has less significant economic added value since most of
the benefits will have already been reaped under the regional, more decentralised
approach under option. In addition, it has significant impacts on stakeholders, Member
States and competent authorities since it requires significant changes to established
practices.
Preferred option for Problem Area I: Option 1(c) (demand response/distributed
resources, also encompassing options 1(a) (level playing field) and 1(b) (strengthening
short-term markets))
Policy options regarding uncertainty about sufficient future generation investments
and uncoordinated capacity mechanisms (Problem Area II)
Option 1 (reinforced energy only market without capacity mechanisms) can in principle
provide the right signals for market operation and ensure system adequacy and ensure
better utilisation of resources across borders, demand participation and renewable
integration without subsidies. Improving the functioning of electricity markets will
improve the conditions for investment in the electricity market to ensure reliable and
effective supply of electricity, even in times of scarcity. This will in turn decrease the
need for capacity mechanisms.
15
However, markets are today still characterised by manifold regulatory distortions today
and removing the distortive effects will not be possible with immediate effects in many
Member States. Besides under such option, uncertainty about future policy directions or
governmental interventions still exists. Such uncertainty may hamper investment and in
turn create the need for mechanisms that address the lack of investments ('missing
money').
It should be noted that undistorted energy price signals are fundamental irrespective of
whether generators are solely relying on energy market incomes or also receive capacity
payments. Therefore the measures aimed at removing distortions from energy-only
markets discussed under Option 1(a) to 1(c) (e.g. scarcity pricing or reinforced locational
signals) are 'no-regrets' and assumed as being integral parts of Options 2, 3 and 4.
Option 2 (Improved energy markets – Capacity Mechanisms ('CM's) only when needed,
based on a common EU-wide adequacy assessment can improve the overall cost-
efficiency of the electricity sector through establishing an EU-wide approach to system
adequacy assessments as opposed to national-based adequacy assessments. At the same
time Option 2 does not allow reaping the full benefits of cross-border participation in
capacity mechanisms.
A more coordinate approach to state interventions across Member States is needed and is
a clear priority for reform. Placing capacity mechanisms into a more regional/EU context
is a pre-requisite to reduce market distortions. It is indeed necessary that the schemes
Member States introduce are compatible with internal market rules.
Option 3 (Improved energy market – CMs only when needed, plus cross-border
participation) proposes additional measures to avoid fragmentation of capacity
mechanisms and ensures that foreign resource providers can effectively participate in
national capacity mechanisms and avoids competition and market distortions resulting
from capacity payments which are reserved to domestic participants. As a result, it
reduces investment distortions that might be present in Option 2 because of
uncoordinated approaches to cross-border participation.
Preferred option for Problem Area II: Option 3 (Improved energy market – CMs
only when needed, plus cross-border participation) (encompassing also Options 1 and
2)
Policy options regarding the lack of coordination among Member States when
preparing for and managing electricity crisis situations (Problem Area III)
Based on a set of clear common rules, Option 1 (Common minimum EU rules) would
improve the level of transparency and crisis management across Europe and is likely to
reduce the chances of premature market intervention. The policy tools proposed under
this option would bring economic benefits to businesses and consumers by helping to
prevent costly blackout situations. However, this option does not solve the issue of
uncoordinated planning and preparation ahead of a crisis since Member State are not
required to take into account cross-border risks and crisis.
16
Under Option 2 (EU rules + regional cooperation), the regionally coordinated plans
ensure the regional identification of risks and the consistency of the measures for
prevention and managing crisis situations while respecting national differences and
competences. This significantly improves the level of preparedness (compared to Option
1) at national, regional and EU level, as the cross border considerations are duly taken
into account since the beginning. A regional approach to security of supply results in a
better utilisation of power plants and guarantees risk preparedness at a lesser cost.
Under Option 3 (Full harmonisation), the estimated impact on cost is likely to be high
(notably with the creation of an EU agency on cyber-security) and the measures put
forward appear disproportionate compared to the expected effectiveness. Indeed, this
option represents a highly intrusive approach – with significant administrative impact -
by resorting to a full harmonisation of principles and the prescription of concrete
solutions.
Preferred option for Problem Area III: Option 2 (EU rules + regional cooperation)
Policy options regarding retail markets and the slow deployment and low levels of
services and poor market performance (Problem Area IV)
Given its low implementation costs, Option 0+ (Non-regulatory approach) is a highly
efficient option. However, the effectiveness of Option 0+ is significantly limited by the
fact that non-regulatory measures are not suitable for tackling the poor data flow between
retail market actors that constitutes both a barrier to entry and a barrier to higher levels of
service to consumers. In addition, shortcomings in the existing legislation make it
impossible to significantly improve consumer engagement and energy poverty
safeguards. They also introduce great uncertainty around the drive to phase out price
regulation which does not provide sufficient incentives to consumers to play an active
role in the market and which also limits competition and new entrants into the market.
Option 1 (Flexible legislation) would lead to substantial economic benefits. Retail
competition would be improved as a result of the progressive phase-out of blanket price
regulation, non-discriminatory access to consumer data, and increased consumer
engagement. In addition, consumers would see direct benefits through improved
switching.
In Option 2 (Harmonization and extensive consumer safeguards) there is uncertainty over
the size of the economic benefits. This uncertainty stems from the tension some of the
measures in Option 2 may have with competition (stronger disconnection safeguards, an
outright ban on all switching-related charges), and from the difficulty of prescribing EU-
level solutions in certain areas (defining exceptions to price deregulation, implementing a
standard EU bill design). Besides, a single EU data management model would have high
implementation costs, thus reducing the efficiency of the option.
Preferred option for Problem Area IV: Option 1 (Flexible legislation)
***
17
TABLE OF CONTENTS
1. INTRODUCTION.............................................................................................................21
1.1. Background and scope of the market design initiative............................................................21
Context of the initiative.............................................................................................................21
1.1.1.
1.1.1.1. The gradual process of creating an internal electricity market .......................................21
1.1.1.2. The Union's policy concerning climate change................................................................21
1.1.1.3. Paradigm shift in the electricity sector ............................................................................22
1.1.1.4. The vision for the EU electricity market in 2030 and beyond..........................................23
Scope of the initiative................................................................................................................29
1.1.2.
1.1.2.1. Current relevant legislative framework ...........................................................................29
1.1.2.2. Policy development subsequent to the Third Package....................................................30
1.1.2.3. Scope and summary of the initiative ...............................................................................32
Organisation and timing ............................................................................................................32
1.1.3.
1.1.3.1. Follow up on the Third Package.......................................................................................32
1.1.3.2. Consultation and expertise ..............................................................................................33
1.2. Interlinkages with parallel initiatives......................................................................................34
The Renewable Energy Package comprising the new Renewable Energy Directive and
1.2.1.
bioenergy sustainability policy for 2030 ('RED II') ...................................................................................34
Commission guidance on regional cooperation ........................................................................35
1.2.2.
The Energy Union governance initiative....................................................................................35
1.2.3.
The Energy Efficiency legislation ('EE') and the related Energy Performance of Buildings
1.2.4.
Directive ('EPBD') including the proposals for their amendment............................................................36
The Commission Regulation establishing a Guideline on Electricity Balancing ('Balancing
1.2.5.
Guideline')................................................................................................................................................36
Other relevant instruments.......................................................................................................37
1.2.6.
2. PROBLEM DESCRIPTION ............................................................................................38
2.1. Problem Area I: Market design not fit for an increasing share of variable decentralized
generation and technological developments........................................................................................38
Driver 1: Short-term markets, as well as balancing markets, are not efficiently organised......40
2.1.1.
Driver 2: Exemptions from fundamental market principles......................................................42
2.1.2.
Driver 3: Consumers do not actively engage in the market and demand response potential
2.1.3.
remains largely untapped........................................................................................................................44
Driver 4: Distribution networks are not actively managed and grid users are poorly
2.1.4.
incentivised..............................................................................................................................................50
2.2. Problem Area II: Uncertainty about sufficient future generation investments and
uncoordinated capacity markets..........................................................................................................52
Driver 1: Lack of adequate investment signals due to regulatory failures and imperfections in
2.2.1.
the electricity market...............................................................................................................................55
Driver 2: Uncoordinated state interventions to deal with real or perceived capacity problems
2.2.2.
58
2.3. Problem Area III: Member States do not take sufficient account of what happens across their
borders when preparing for and managing electricity crisis situations..................................................63
Driver 1: Plans and actions for dealing with electricity crisis situations focus on the national
2.3.1.
context only .............................................................................................................................................65
Driver 2: Lack of information-sharing and transparency...........................................................67
2.3.2.
Driver 3: No common approach to identifying and assessing risks...........................................69
2.3.3.
2.4. Problem Area IV: The slow deployment of new services, low levels of service and questionable
market performance on retail markets ................................................................................................69
Driver 1: Low levels of competition on retail markets ..............................................................70
2.4.1.
18
Driver 2: Possible conflicts of interest between market actors that manage and handle data 74
2.4.2.
Driver 3: Low levels of consumer engagement .........................................................................76
2.4.3.
2.5. What is the EU dimension of the problem?.............................................................................77
2.6. How would the problem evolve, all things being equal? .........................................................78
The projected development of the current regulatory framework...........................................78
2.6.1.
Expected evolution of the problems under the current regulatory framework .......................79
2.6.2.
2.7. Issues identified in the evaluation of the Third Package..........................................................80
3. SUBSIDIARITY................................................................................................................81
3.1. The EU's right to act...............................................................................................................81
3.2. Why could Member States not achieve the objectives of the proposed action sufficiently by
themselves?........................................................................................................................................81
3.3. Added-value of action at EU-level ..........................................................................................83
4. OBJECTIVES.....................................................................................................................84
4.1. Objectives and sub-objectives of the present initiative...........................................................84
4.2. Consistency of objectives with other EU policies.....................................................................85
5. POLICY OPTIONS ...........................................................................................................88
5.1. Options to address Problem Area I (Market design not fit for an increasing share of variable
decentralized generation and technological developments).................................................................89
Overview of the policy options..................................................................................................89
5.1.1.
Option 0: Baseline Scenario – Current Market Arrangements..................................................90
5.1.2.
Option 0+: Non-regulatory approach ........................................................................................91
5.1.3.
Option 1: EU Regulatory action to enhance market flexibility ..................................................92
5.1.4.
5.1.4.1. Sub-option 1(a): Level playing field amongst participants and resources .......................94
5.1.4.2. Sub-option 1(b): Strengthening short-term markets.......................................................97
5.1.4.3. Sub-option 1(c): Pulling demand response and distributed resources into the market100
Option 2: Fully Integrated EU market......................................................................................104
5.1.5.
For Option 1 and 2: Institutional framework as an enabler ....................................................105
5.1.6.
Summary of specific measures comprising each Option.........................................................108
5.1.7.
5.2. Options to address Problem Area II (Uncertainty about sufficient future generation
investments and uncoordinated capacity markets)............................................................................111
Overview of the policy options................................................................................................111
5.2.1.
Option 0: Baseline Scenario – Current Market Arrangements................................................112
5.2.2.
Option 0+: Non-regulatory approach ......................................................................................113
5.2.3.
Option 1: Improved energy market - no CMs..........................................................................114
5.2.4.
Option 2: Improved energy market – CMs only when needed, based on a common EU-wide
5.2.5.
adequacy assessment)...........................................................................................................................116
Option 3: Improved energy market - CMs only when needed, based on a common EU-wide
5.2.6.
adequacy assessment, plus cross-border participation.........................................................................117
Option 4: Mandatory EU-wide or regional CMs ......................................................................118
5.2.7.
Discarded Options ...................................................................................................................119
5.2.8.
Summary of specific measures comprising each Option.........................................................119
5.2.9.
5.3. Options to address Problem Area III (When preparing or managing crisis situations, Member
States tend to disregard the situation across their borders) ...............................................................121
19
Overview of the policy options................................................................................................121
5.3.1.
Option 0: Baseline scenario – Purely national approach to electricity crises..........................121
5.3.2.
Option 0+: Non-regulatory approach ......................................................................................123
5.3.3.
Option 1: Common minimum rules to be implemented by Member States...........................124
5.3.4.
Option 2: Common minimum rules to be implemented by Member States, plus regional co-
5.3.5.
operation ...............................................................................................................................................125
Option 3: Full harmonisation and decision-making at regional level ......................................129
5.3.6.
Discarded Options ...................................................................................................................129
5.3.7.
Summary of specific measures comprising each Option.........................................................129
5.3.8.
5.4. Options to address Problem Area IV (Slow deployment and low levels of services and poor
market performance) ........................................................................................................................133
Overview of the policy options................................................................................................133
5.4.1.
Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer
5.4.2.
engagement and poor data flows..........................................................................................................133
Option 0+: Non-regulatory approach to address competition and consumer engagement...134
5.4.3.
Option 1: Flexible legislation addressing all problem drivers..................................................135
5.4.4.
Option 2: EU Harmonization and extensive safeguards for consumers addressing all problem
5.4.5.
drivers 137
Summary of specific measures comprising each Option.........................................................138
5.4.6.
6. ASSESSMENT OF THE IMPACTS OF THE VARIOUS POLICY OPTIONS ....... 140
6.1. Assessment of economic impacts for Problem Area I (Market design not fit for an increasing
share of variable decentralized generation and technological developments .....................................140
Methodological Approach .......................................................................................................140
6.1.1.
6.1.1.1. Impacts Assessed ...........................................................................................................140
6.1.1.2. Modelling and use of studies .........................................................................................141
6.1.1.3. Summary of Main Impacts .............................................................................................142
6.1.1.4. Overview of Baseline (Current Market Arrangements) .................................................142
Policy Sub-option 1(a) (Level playing field amongst participants and resources)...................145
6.1.2.
6.1.2.1. Economic impacts ..........................................................................................................145
6.1.2.2. Who would be affected and how...................................................................................148
6.1.2.3. Administrative impact on businesses and public authorities ........................................148
Impacts of Policy Sub-option 1(b) (Strengthening short-term markets).................................148
6.1.3.
6.1.3.1. Economic Impacts ..........................................................................................................148
6.1.3.2. Who would be affected and how...................................................................................151
6.1.3.3. Administrative impact on businesses and public authorities ........................................151
Impacts of Policy Sub-option 1(c) (Pulling demand response and distributed resources into the
6.1.4.
market) 152
6.1.4.1. Economic Impacts ..........................................................................................................152
6.1.4.2. Who would be affected and how...................................................................................153
6.1.4.3. Impact on businesses and public authorities.................................................................155
Impacts of Policy Option 2 (Fully integrated EU market) ........................................................155
6.1.5.
6.1.5.1. Economic Impacts ..........................................................................................................155
6.1.5.2. Who would be affected and how...................................................................................156
6.1.5.3. Impact on businesses and public authorities.................................................................156
Environmental impacts of options related to Problem Area I.................................................157
6.1.6.
Summary of modelling results for Problem Area I ..................................................................158
6.1.7.
6.2. Impact Assessment for Problem Area II (Uncertainty about future generation investments and
fragmented capacity mechanisms) ....................................................................................................166
Methodological Approach .......................................................................................................166
6.2.1.
6.2.1.1. Impacts Assessed ...........................................................................................................166
6.2.1.2. Modelling .......................................................................................................................166
6.2.1.3. Overview of Baseline (Current Market Arrangements) .................................................167
Impacts of Policy Option 1 (Improved energy markets - no CMs )..........................................168
6.2.2.
6.2.2.1. Economic Impacts ..........................................................................................................168
20
6.2.2.2. Who would be affected and how...................................................................................169
6.2.2.3. Administrative impact on businesses and public authorities ........................................170
Impacts of Policy Option 2 (Improved energy markets – CMs only when needed, based on a
6.2.3.
common EU-wide adequacy assessment) .............................................................................................170
6.2.3.1. Economic Impacts ..........................................................................................................170
6.2.3.2. Who would be affected and how...................................................................................171
6.2.3.3. Impact on businesses and public authorities.................................................................172
Impacts of Policy Option 3 (Improved energy market – CMs only when needed, plus cross-
6.2.4.
border participation)..............................................................................................................................172
6.2.4.1. Economic Impacts ..........................................................................................................172
6.2.4.2. Who would be affected and how...................................................................................173
6.2.4.3. Impact on businesses and public authorities.................................................................173
Environmental impacts of options related to Problem Area II................................................174
6.2.5.
Overview of modelling results for Problem Area II .................................................................174
6.2.6.
6.2.6.1. Improved Energy Market as a no-regret option ............................................................174
6.2.6.2. Comparison of Options 1 to 3 ........................................................................................176
6.2.6.3. Delivering the necessary investments ...........................................................................181
6.2.6.4. Level and volatility of wholesale prices..........................................................................189
6.3. Impact Assessment for problem Area III (reinforce coordination between Member States for
preventing and managing crisis situations) ........................................................................................191
Methodological Approach .......................................................................................................191
6.3.1.
Impacts of Policy Option 1 (Common minimum rules to be implemented by Member States)
6.3.2.
191
6.3.2.1. Economic impacts ..........................................................................................................191
6.3.2.2. Who would be affected and how...................................................................................192
6.3.2.3. Impact on businesses and public authorities.................................................................193
Impacts of Policy Option 2 (Common minimum rules to be implemented by Member States
6.3.3.
plus regional co-operation)....................................................................................................................193
6.3.3.1. Economic impacts ..........................................................................................................193
6.3.3.2. Who would be affected and how...................................................................................195
6.3.3.3. Impact on businesses and public authorities.................................................................196
Impacts of Policy Option 3 (Full harmonisation and full decision-making at regional level)...197
6.3.4.
6.3.4.1. Economic impacts ..........................................................................................................197
6.3.4.2. Who would be affected and how...................................................................................197
6.3.4.3. Impact on businesses and public authorities.................................................................198
6.4. Impact Assessment for Problem Area IV (Increase competition in the retail market).............198
Methodological Approach .......................................................................................................198
6.4.1.
Impacts of Policy Option 0+ (Non-regulatory approach to improving competition and
6.4.2.
consumer engagement).........................................................................................................................198
6.4.2.1. Economic Impacts ..........................................................................................................198
6.4.2.2. Who would be affected and how...................................................................................199
6.4.2.3. Impact on businesses and public authorities.................................................................200
Impacts of Policy Option 1 (Flexible legislation addressing all problem drivers) ....................200
6.4.3.
6.4.3.1. Economic Impacts ..........................................................................................................200
6.4.3.2. Who would be affected and how...................................................................................201
6.4.3.3. Impact on businesses and public authorities.................................................................202
Impacts of Policy Option 2 (Harmonization and extensive safeguards for consumers
6.4.4.
addressing all problem drivers) .............................................................................................................203
6.4.4.1. Economic Impacts ..........................................................................................................203
6.4.4.2. Who would be affected and how...................................................................................204
6.4.4.3. Impact on businesses and public authorities.................................................................205
Environmental impacts............................................................................................................206
6.4.5.
Impacts on fundamental rights regarding data protection .....................................................207
6.4.6.
6.5. Social impacts......................................................................................................................209
21
7. COMPARISON OF THE OPTIONS............................................................................ 213
7.1. Comparison of options for adapting market design for the cost-effective operation of variable
and often decentralised generation, taking into account technological developments .......................213
7.2. Comparison of Options for facilitating investments in the right amount and in the right type of
resources for the EU..........................................................................................................................215
7.3. Comparison of options for improving Member States' reliance on each other in times of system
stress and reinforcing coordination between Member States for preventing and managing crisis
situations..........................................................................................................................................218
7.4. Comparison of options for addressing the causes and symptoms of weak competition in the
energy retail market..........................................................................................................................220
7.5. Synergies, trade-offs between Problem Areas and sequencing .............................................222
Synergies..................................................................................................................................222
7.5.1.
Trade-offs ................................................................................................................................224
7.5.2.
Sequencing of measures..........................................................................................................225
7.5.3.
8. MONITORING AND EVALUATION.......................................................................... 225
8.1. Future monitoring and evaluation plan ................................................................................225
8.2. Annual reporting by ACER and evaluation by the Commission ..............................................226
Annual reporting by ACER .......................................................................................................226
8.2.1.
Evaluation by the Commission ................................................................................................226
8.2.2.
8.3. Monitoring by the Electricity Coordination Group ................................................................227
8.4. Operational objectives.........................................................................................................227
8.5. Monitoring indicators and benchmarks................................................................................228
9. GLOSSARY AND ACRONYMS.................................................................................... 230
22
Introduction
1. INTRODUCTION
1.1. Background and scope of the market design initiative
Context of the initiative
1.1.1.
1.1.1.1.The gradual process of creating an internal electricity market
Well-functioning energy markets that ensure secure energy supplies at competitive prices
are key for achieving growth and consumer welfare in the European Union.
Since 1996, the European Union has put in place legislation to enable the transition from
an electricity system traditionally dominated by vertically integrated national incumbents
that owned and operated all the generation and network assets in their territories to
competitive, well-functioning and integrated electricity markets. The first step was the
adoption of the First Energy Package (1996 for the electricity sector and 1998 for the gas
sector), which allowed for the partial opening of the market where the largest consumers
were given the right to choose their supplier. The Second Energy Package (2003)
introduced changes concerning the structure of the vertically integrated companies (legal
unbundling), the preparation of the full opening of the market by 1 July 2007 and the
reinforcement of the powers of the national regulators. The most recent comprehensive
reform of European energy market rules, the Third Internal Energy Market Package
(2009)1
('Third Package') has principally aimed at improving the functioning of the
internal energy market and resolving structural problems.
Since the adoption of the Third Package, electricity policy decisions have enabled
competition and increasing cross-border flows of electricity, notably with the
introduction of so called "market coupling"2
and "flow-based" capacity allocation. In
spite of significant differences in the maturity of markets in Europe, overall electricity
wholesale markets are increasingly characterised by fair and open competition, and –
though still insufficient – competition is also taking root at the retail level.
1.1.1.2.The Union's policy concerning climate change
The decarbonisation of EU economies is at the core of the EU’s agenda for climate
change and energy. The targets in the Climate and Energy Package (2007) require
Member States to cut their greenhouse gas emissions by 20% (from 1990 levels), to
produce 20% of their energy from renewable energy sources (RES), and to improve
energy efficiency by 20 % (the '2020 targets').3
In 2011, the European Union committed to reduce greenhouse gas emissions to 80-95%
below 1990 levels by 2050. For this purpose, the European Commission adopted an
1
Section 1.1.2.1 provides a more detailed explanation of the Third Energy Package.
2
A mechanism that manages cross-border electricity flows in an optimal way, smoothing out price
differences between Member States.
3
http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52008DC0030&from=EN
23
Introduction
Energy Roadmap4
and a roadmap for moving to a competitive low carbon economy5
exploring the transition of the energy system in ways that would be compatible with this
greenhouse gas reductions target while also increasing competitiveness and security of
supply. The 2050 roadmap will require a higher degree of decarbonisation from the
electricity sector compared to other economic sectors.
These ambitions were reaffirmed by the European Council of October 2014, which
endorsed targets for 2030 of at least 40 % for domestic greenhouse gas emissions
reduction (compared to 1990 levels), at least 27 % for the share of renewable energy
consumption, binding at EU level and at least 27 % energy savings, to be reviewed by
2020, having in mind an EU level of 30% (the '2030 targets').6
At the Paris climate conference (COP21) in December 2015, 195 countries adopted the
first-ever legally binding global climate deal. The European Council of March 2016
confirmed the EU's commitment to implement the 2030 targets. The Paris Agreement
was ratified by the European Union and entered into force on 4 November 2016..
1.1.1.3.Paradigm shift in the electricity sector
The Union's goals for climate change and energy have led to a paradigm shift in the
means employed to generate electricity: since the adoption of the Third Package, there
has been a move towards the deployment of capital-intensive low marginal cost, variable
and often decentralised electricity from RES E (mostly from solar and wind
technologies) that is expected to become more pronounced by 2030.
The increasing penetration of RES E is driven inter alia by the objective to reduce
greenhouse gas emissions in line with the 2020 and 2030 targets. The 2030 greenhouse
gas emission reduction target is to be delivered through reducing emissions by 43%
compared to 2005 for the sectors in the EU's ETS7
(including the electricity sector and
industry) and by 30% compared to 2005 for the sectors outside the ETS. Within the
electricity sector, the reduction of greenhouse gas emissions is supported by the
Renewable Energy Directive8
, the ETS and the additional national policies by Member
States to increase the share of renewables in the energy mix.
The Renewable Energy Directive established a European framework for the promotion of
renewable energy, setting mandatory national renewable energy targets for achieving a
20% EU share of renewable energy in the final energy consumption and a 10% share of
energy from renewable sources in transport by 2020. These objectives have translated
4
http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52011DC0885&from=EN
5
COM (2011) 112; http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:52011DC0112
6
http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdata/en/ec/145397.pdf
7
The ETS works on the 'cap and trade' principle. A 'cap', or limit, is set on the total amount of certain
greenhouse gases that can be emitted by the factories, power plants and industrial installations in the
system. The cap is reduced over time so that total emissions fall. This policy instrument equally fosters
penetration of RES E as it renders production of electricity from non- or less-emitting generation
capacity comparatively more economical in relation to more carbon intensive capacity.
8
Directive 2009/28/EC on the promotion of the use of energy from renewable sources, OJ L 140/16,
5.6.2009
24
Introduction
into a need to foster the increased production of electricity from reneweble energy
sources.9
In parallel with the increased deployment of variable and decentralized RES E, the
increasing digitalisation of electricity networks and the environment behind the meter
now enables many elements of the electricity system to be operated more flexibly and
efficiently in the context of RES E generation. It also allows smaller actors to play an
increasingly important part in the market on both the supply side and – crucially – the
demand side, potentially untapping a vast new system resource.
From the consumer's perspective, increasingly intelligent grids unlock a host of other
possibilities, including innovative new products and services, lower entry barriers for
new suppliers, and improved billing and switching. This promises to unlock value and
improve the consumer experience – provided the legislative framework adapts to the
changing needs and possibilities. Indeed, fully engaging end consumers will be essential
to realizing the full benefits that the digital transformation can bring in terms of grid
flexibility.
Moreover, electricity demand will progressively reflect the increasing electrification of
transport and heating.
The challenges the EU's electricity systems face are reflected in the European
Commission Communication of February 2015 on “A Framework Strategy for a
Resilient Energy Union with a Forward-Looking Climate Change Policy”10
where the
Commission announced a new electricity market design linking wholesale and retail
markets. As part of the legislative reform process needed to establish the Energy Union,
it also announced new legislation on security of electricity supply.
In the light of the Energy Union Framework Strategy, the present impact assessment
reflects and analyses the need and policy options for a possible revision of the main
framework governing electricity markets and security of electricity supply policies in
Europe. The new electricity market design contributes strongly to the overall Energy
Union objectives of securing low carbon energy supplies to the European consumers at
least costs.
1.1.1.4.The vision for the EU electricity market in 2030 and beyond
The Energy Union Framework Strategy sets out the vision of an Energy Union "with
citizens at its core, where citizens take ownership of the energy transition, benefit from
new technologies to reduce their bills, participate actively in the market, and where
vulnerable consumers are protected". Well-functioning energy markets that ensure
secure energy supplies at competitive prices are important for achieving growth and
9
Moreover, following the 2030 targets set by the European Council in October 2014, the Commission
published a Communication on A Framework Strategy for a Resilient Energy Union with a Forward-
Looking Climate Change Policy of February 2015 confirming the political commitment for the
European Union to become the world leader in renewable energy.
10
EC (2015a) - COM(2015) 80 final
25
Introduction
consumer welfare in the European Union. The future of the entire energy sector will, to a
significant extent, be shaped by the evolution of the electricity sector, which is key to
addressing climate change. With the quick ratification of the global Paris Agreement on
climate change and its subsequent entry into force, it becomes clear how important it is
for all parties to the agreement, including the EU, to deliver on the clean energy
transition on the ground. In fact, amongst all sectors that make up our energy system,
electricity is the most cost-effective to decarbonise. Currently 27.5% of Europe's
electricity is produced from renewable energy sources. The share of RES E in electricity
generation needs to almost double by 2030 in order for the EU to meet its 2030 energy
and climate targets cost-effectively. This will require creating the right conditions for the
massive amount of investment needed for this energy transition to come about. At the
same time electricity markets will have to adapt to the radical change in the structure of
the generation pattern which will foremost require creating a more flexible market, going
across borders, that is able to allow more active participation of a much wider range of
actors.
The EU's vision of the electricity system in 2030 is therefore based on a functioning
market that is adapted to implementing the decarbonisation agenda at least cost together
with a revised EU ETS. A well-functioning electricity market is also the most efficient
tool to ensure secure electricity supplies at the lowest reasonable cost.
The transition of the energy system towards the 2030 vision
The starting point is the existing reality, which dates back to an era with large-scale,
centralised power plants, largely fuelled by fossil fuels, had the key aim of supplying
every home and business in a delineated area – typically a Member State – with as much
electricity as they wanted, and in which consumers – households, businesses and industry
– were passive users.
However, the electricity market is undergoing profound change and requires a new set of
rules to ensure secure supplies, competitiveness while enabling cost-effective
decarbonisation. The electricity market of the next decade will be characterised by more
variable and decentralised electricity production, an increased interdependence between
Member States and new technological opportunities for customers to reduce their bills
and actively participate in electricity markets through demand response, self-
consumption or storage.
The electricity market design initiative aims to improve the functioning of the internal
electricity market in order to allow electricity to move freely to where and when it is
most needed, empower consumers, reap maximum benefits for society from cross-border
competition and provide the right signals and incentives to drive the right investments
compatible with climate change, renewable energy and energy efficiency ambitions.
The proposed initiative constitutes a next-step in a wider and longer evolutionary process
that will guide the EU's electricity markets towards the 2030 vision.
The 2030 electricity market is highly flexible and provides a level playing field amongst
all forms of generation as well as demand response…
The bulk of the new generation capacity is likely to come from renewable sources,
mainly wind and sun that are variable and predictable only to a limited extent. The future
electricity market will therefore need to be more flexible and liquid than today and allow
26
Introduction
for integrated short-term trading. This would also set the ground for renewable energy
producers – who will over time acquire increasing share in generation - to equally access
energy wholesale markets and to compete on an equal footing with conventional energy
producers. Short-term markets will also allow Member States to share their resources
across all "time frames" (forward trading, day-ahead, intraday and balancing), taking
advantage of the fact that peaks and weather conditions across Europe do not occur at the
same time. This would provide maximum opportunity to meet the flexibility needs and
balance the market. The sequence of forward markets and spot markets - day-ahead,
intraday and balancing - will optimise prices and the system in the short-run and will
reveal the true value of electricity and, therefore, provide appropriate investments signals
in the long-run.
The closer to real time electricity is traded (supply and demand matched), the less the
need for costly interventions by TSOs to maintain a stable electricity system. Although
TSOs would have less time to react to schedule deviations and unexpected events and
forecast errors, the liquid, better interconnected balancing markets, together with the
regional procurement of balancing reserves and more balancing actors and products
available from both demand and supply side, would be expected to provide them
adequate and more efficient resources in order to manage the grid and facilitate RES E
integration.
All this will help to create a level playing field not only among all modes of generation
but also the demand side. At the same time market distortions and rules that artificially
limit or favour the access of certain technologies to the grid would be removed. All
market participants would become gradually responsible for balancing their position in
the market, bearing financial responsibility for the imbalances they cause and would,
therefore, be incentivised to reduce the risk of such imbalances. The most cost-efficient
sources of electricity would be used first, curtailment of generation due to limited
transmission and distribution infrastructure would be a measure of last resort and
confined to situations in which no market-based responses (including storage and
demand response) are available, and subject to transparent rules known in advance to all
market actors and adequate financial compensation. All resources would be remunerated
in the market on equal terms.
…and active consumers.
Ensuring that all consumers – big and small – can actively participate in the energy
market would unlock a vast system resource that could play an important role in reducing
system costs. Technology – including smart grids and smart homes - is already available
and will further develop to enable consumers to modulate their demand while
maintaining comfort and reducing costs.
In the future, consumers would be sufficiently incentivised to benefit from these
opportunities and thus demand response would be provided by all willing consumer
groups, including residential and commercial consumers either directly or through
intermediaries (like aggregators). This would further increase the flexibility of the
electricity system and the resources for the TSOs and DSOs to manage it. At the same
time it should lead to a much more efficient operation of the whole energy system.
Consumers would be able to react to price signals on electricity markets both in terms of
consumption and production; they would consume when prices are low, when there is
plenty of electricity available, and reduce their consumption at times of low electricity
27
Introduction
production and high prices. To make this possible, consumers have access to a fit-for-
purpose smart metering system, smart homes and storage as well as electricity supply
contracts with prices linked dynamically to the wholesale markets.
More and more consumers would produce their own electricity. Such decentralised
production further strengthens security of supply and helps to implement the
decarbonisation agenda as most of this production comes from renewable sources. If
combined with local storage solutions, consumers could significantly contribute to
balancing the distribution grids at local level. Analysis suggests that this development
will be progressive, and that most consumers would still remain connected to the
distribution grid to use it as back-up for when the prosumers' own generation is
inadequate (e.g. for sustained periods of low sunlight) or for the opportunity to sell
excess electricity to the market (e.g. during prolonged sunny periods when their installed
storage is at full capacity).
Reducing barriers to market entry for electricity suppliers and consumer engagement –
notably phasing out price regulation – results in increased competition at the retail level
allowing consumers to save money through better information and a wider choice of
action. This also helps drive the uptake of innovative new products and services that
increase system flexibility through demand response whilst catering to consumers'
changing needs and abilities.
In addition, DSOs would be enabled and incentivised, without compromising their
neutrality as system operators, to manage their networks in a flexible and cost-efficient
way – inter alia through revised tariff structures.
Increased cross-border trade is a pillar of the electricity market.
Competition and cross-border flows of electricity would further increase, with fully
coupled markets where price differences between Member States are smoothened out.
Electricity wholesale markets will be characterised by fair and open competition,
including across borders. Cooperation between TSOs will be enhanced by regional
operational centres. The cross-border cooperation of TSOs would be accompanied by an
increased level of cooperation between regulators and governments. An adequate cross-
border infrastructure remains crucial to underpin a well-functioning electricity market.
Increasingly investments are triggered by the market with a decreasing need for state
subsidies.
The enhanced market design, the revised renewables directive and the strengthened ETS
will all help to improve the viability of RES E investments, in particular as follows:
- Where the marginal producer is a fossil fired power plant, a higher carbon price
translates into higher average wholesale prices. The existing surplus of
allowances is expected to decrease due to the implementation of the Market
Stability Reserve and the higher Linear Reduction Factor, reducing the current
imbalance between supply and demand for allowances;
28
Introduction
- greater system flexibility will be critical for better integration of RES E in the
system, reducing their hours of curtailment and the related forgone revenues;
improving overall system flexibility is equally essential to limit the merit-order
effect11
and thus in avoiding the erosion of the market value of RES E
produced electricity;
- the revision of priority dispatch rules, removal of must-run units, increasing
demand response and storage, together with the better functioning of the short-
term markets will strongly reduce or even eliminate the occurrence of negative
prices – leading again to higher average wholesale prices (especially during the
hours with significant variable RES E generation);
- improved rules for intraday and balancing markets will increase their liquidity
and allow access to those markets for all resources, thus helping generators
reduce their balancing costs;
- removing existing (explicit or implicit) restrictions for the participation of all
resources to the reserve and ancillary services markets will allow RES E to
generate additional revenues from these markets;
- price signals reflecting the actual value of electricity at each point of time, as
well as the value of flexibility, will ensure that the flexible assets most needed
for the system are invested in or, at least, are less likely to be decommissioned.
- Low exit barriers to facilitate exit of overcapacities.
The above mentioned changes will all help to improve the competitive situation of RES
E and reduce the need for dedicated support.
The results of the modelling for this Impact Assessment indicate that investments in the
most mature renewable technologies could be driven by the market by 2030 (such as
certain solar PV and onshore wind). At the beginning of the period, generation over-
capacity in certain areas, weaker investment signal from the ETS and low wholesale
market prices and still high RES E technology costs, make the case for investments in
RES E technologies more difficult. The underpinning modelling and analysis, points that
the RES E funding gap in 2020 is gradually reducing towards 2030 as the market
conditions improve. Less mature RES E technologies, needed for meeting the 2030 and
2050 energy and climate objectives, such as off-shore wind, will likely need some form
of support to cover at least a fraction of total project costs (complementing the revenues
obtained from the energy markets) throughout the 2021-2030 period.
The picture also depends on regions. RES E technologies could be more easily financed
by the market in the regions with the highest potential (e.g. onshore wind in the Nordic
region or solar in Southern Europe), while RES E could continue to require support in the
British Isles and in Central Europe. Conditions however also depend on the cost of
capital.
At the same time it has to be acknowledged that whether and what point in time
financing of RES E through markets alone will actually take off remains difficult to
predict. This is because financing of capital intensive technologies such as most RES E
11
Also occasionally referred to as the 'cannibalisation effect'.
29
Introduction
through markets based on marginal cost pricing will remain challenging. In the absence
of measures that address system flexibility, higher penetration of RES with low marginal
cost could reduce the market value that such RES E can actually achieve. Removing
barriers to the flexibilisation of demand and improving the responsiveness of demand and
supply to price signals stands out as a key measure in this regards in order to further
stabilise the revenue of RES E producers from the market.
On the other hand the future capacity of RES to be financed through the market will also
depend on certain conditions outside of the market design and ETS prices, such as
continued decrease in the costs of technologies, availability of capital at a reasonable
price, social acceptance and sufficiently high and stable fossil fuel prices.
While the market reforms described above are therefore no regret options to facilitate
RES investment, support schemes will still be needed at least for a transitional period. It
is therefore essential to further reform such schemes to make them as market-oriented as
possible.
… with a market-based and more Europeanised approach to support schemes to cover
any investment gap .
Where needed, support will be (i) cost-effective and kept to a minimum, and (ii) will
create as little distortions as possible to the functioning of electricity markets, and to
competition between technologies and between Member States. The legal frame for RES
E support schemes would ensure sufficient investor certainty over the 2021-2030 period
and require the use (where needed) of market-based and cost-effective schemes, based on
the design of emerging best practices. Auctions could introduce competitive forces to
determine the level of support needed on top of market revenues and incentivise RES E
producers to develop business models that maximise market-based revenues. The use of
tenders would imply a natural phase-out mechanism for support, determining the
remaining level of support required to bridge any financing gap. The continued
participation of small and local actors, including energy communities, in the energy
transition should be ensured in this process.
The market should also provide, as a principle, security of supply.
By 2030, the market, as described above, could in principle successfully attract the
required investments to ensure adequate matching of supply and demand.
Today, most of the EU's power markets have more capacity than needed. However, with
demand increasing, e.g. due to E-Mobility and heat pumps, and older power plants
retiring supply margins are likely to get tighter. Therefore, a legal framework needs to be
in place to allow for the formation of electricity prices that send the signals for
tomorrow's investments. In this context, scarcity prices will become more and more
important to provide the right incentives for the operation of resources (including for
demand response) when they are most needed. Hedging products which suppliers can
buy to protect themselves against peaks are already available now and more innovative
tools are expected to be brought forward by market participants without the need for
additional intervention by national authorities. This will also provide opportunities for
generators (who will be natural provider of such hedging tools) to secure further
revenues.
30
Introduction
In the new market framework capacity mechanisms might only be considered if a
residual risk to security of supply can be proven after underlying market distortions have
been removed and the contribution of market integration to security of supply has been
taken into account.
The legal framework will provide tools to facilitate an objective case-by-case judgement
on whether the introduction of capacity mechanisms is needed and set out measures to
ensure that their potentially distortive effects are kept at a minimum, while placing them
in a more regional context. Accordingly, their need would have to be proven against an
EU-wide system adequacy assessment and they would have to allow for cross-border
participation to minimise distortions of investment incentives across the borders.
Capacity mechanisms would be designed in a way as to not discriminate against different
generation technologies and demand side capacities. Additionally, where need has been
demonstrated for such mechanisms, Member States should take into account how such
mechanisms would impact the achievement of the decarbonisation objectives.
Member States should regularly review their resource adequacy12
situation and phase out
capacity mechanisms once the underlying market or regulatory concerns have been
resolved.
Despite best efforts to build an integrated and resilient power market, crisis situations can
never be excluded. The potential for crisis situation increases with climate change (i.e.
extreme weather conditions) and with the emergence of new areas that are subject to
criticalities (i.e. malicious attacks, cyber-threats). Such crises tend to often have an
immediate cross-border effect in electricity. The legal framework would provide tools to
ensure that national security of supply policies are better coordinated and aligned to
tackle possible crisis situations, in particular those that affect several countries at the
same time.
Scope of the initiative
1.1.2.
1.1.2.1.Current relevant legislative framework
EU's electricity markets are currently regulated at EU level by a series of acts collectively
referred to as the "Third Package"13
.
12
As not only generation, but also demand response or storage can solve problems of situations in which
demand exceeds production, this Impact Assessment uses the term "resource adequacy" instead of
"generation adequacy" (other authors refer to "system adequacy").
13
The relevant elements of the Third Package as regards electricity are Directive 2009/72 of the
European Parliament and of the Council of 13 July 2009 concerning common rules for the internal
market in electricity and repealing Directive 2003/54/EC, OJ L 211, 14.8.2009, p. 55–93; Regulation
(EC) No 714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for
access to the network for cross-border exchanges in electricity repealing Regulation (EC) No
1228/2003. OJ L 211, 14.8.2009, p. 15–35 and Regulation (EC) No 713/2009 of the European
Parliament and of the Council of 13 July 2009 establishing an Agency for the Cooperation of Energy
Regulators. OJ L 211, 14.8.2009, p. 1–14. The Third package also covered other acts, in particular acts
related to the regulation of gas markets. However, only one of these acts is pertinent for the present
impact assessment – the Gas Directive.
31
Introduction
The main objectives of the Third Package were:
- Improving competition through better regulation, unbundling and reducing
asymmetric information;
- Improving security of supply by strengthening the incentives for sufficient
investment in transmission and distribution capacities; and,
- Improving consumer protection and preventing energy poverty.
The Third Package mainly focused on improving the conditions for competition as
resulting from previous generations of legislation by improving the level playing field.
The most important root cause for the lack of competition identified at the time14
was the
existence of vertically integrated companies, which not only controlled essential facilities
(such as electricity transmission systems) but also enjoyed significant market power in
the wholesale and, often, retail markets. Many of the measures associated with the Third
Package sought to directly or indirectly address this issue, such as by improving the
unbundling regime, strengthening regulatory oversight, improving the conditions for
cross-border market integration and lowering entry barriers such as by improving
transparency.
The Third Package also created the possibility to enact secondary legislation concerning
cross-border issues, often referred to as network codes or guidelines ('network codes')15
,
and provided a mandate for developing these network codes (as well as other tasks
related to the EU's electricity markets) to transmission system operators within the
ENTSO-E16
and to national regulatory authorities, within the Agency for the
Cooperation of Energy Regulators ('ACER')17
.
The main framework for electricity security of supply in the Union is currently Directive
2005/89/EC ("Security of Electricity Supply Directive' or 'SoS Directive'")18
. This
SoS Directive requires Member States to take certain measures with the view to ensuring
security of supply, but leaves it by and large to the Member States how to implement
these measures. The Third Package complemented the SoS Directive and superseded de
facto some of its provisions.
1.1.2.2.Policy development subsequent to the Third Package
The present initiative builds on previous related policy initiatives and reports that
intervened since the adoption of the Third Package and the Security of Electricity Supply
Directive, in particular:
14
In the impact assessment for the Third Package (SEC(2007) 1179/2 http://ec.europa.eu/smart-
regulation/impact/ia_carried_out/docs/ia_2007/sec_2007_1179_en.pdf.
15
For an overview of these network codes and guidelines and their pertinence to the present initiative,
please refer to Annex VII.
16
https://www.entsoe.eu/about-entso-e/inside-entso-e/official-mandates/Pages/default.aspx
17
http://www.acer.europa.eu/en/The_agency/Mission_and_Objectives/Pages/default.aspx
18
Directive 2005/89/EC of the European Parliament and of the Council of 18 January 2006 concerning
measures to safeguard security of electricity supply and infrastructure investment, OJ L 33, 4.2.2006,
p. 22–27.
32
Introduction
- "Report on the progress concerning measures to safeguard security of electricity
supply and infrastructure investment" COM (2010) 330 final19
;
- "Delivering the internal electricity market and making the most of public
interventions" (C(2013) 7243). This Communication was accompanied inter alia
by a Commission Staff working document (SWD(2013)438) entitled "Generation
Adequacy in the internal electricity market – guidance on public intervention";
- Communication on the "Progress towards completing the Internal Energy
Market" COM(2014) 634 final. This Communication emphasized that energy
market integration has delivered many positive results but that, at the same time,
further steps are needed to complete the internal market;
- "Communication on Energy Security" (COM(2014)330). This Communication
emphasised inter alia the need achieve a better functioning and a more integrated
energy market;
- Special Report by the European Court of Auditors "Improving the security of
energy supply by developing the internal energy market: more efforts needed".
This special report made nine recommendations to reap the benefits of market
integration20
;
- "Communication on energy prices and costs in Europe" (COM(2014) 21 /2) and
the accompanying "Energy prices and costs report" (SWD(2014)020 final 2)
highlighting inter alia the competiveness of the EU's retail electricity markets, the
missing link between wholesale and retail prices and the need for EU cooperation
by DSOs as well as the Energy prices and costs report (SWD(2016)XX21
, this
report inter alia that shed light on the drivers of retail and wholesale price
developments;
- "Delivering a new deal for energy consumers" (COM(2015) 339). This
Communication laid out the Commission's intention to enable all consumers to
fully participate in the energy transition, taking advantage of new technologies
that enable wholesale and retail markets to be better linked.
- The Commisison published a study on "Investment perspectives in electricity
markets"22
- Technical Report23
by the European Commission on "The economic impact of
enforcement of competition policies on the functioning of EU energy markets".
The report includes an assessment of the intensity of competition in the energy
markets24
(both wholesale and retail) and points out that, between 2005 and 2012,
the intensity of competition in European energy markets may have declined25
.
- The Commission Staff working document (SWD(2015)249) entitled "Energy
Consumer Trends 2010 - 2015" presents market research into the problems that
energy consumers continue to be confronted with.
19
http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52010DC0330&from=EN
20
http://www.eca.europa.eu/en/Pages/DocItem.aspx?did=34751
21
Report to be published in conjunction with the present impact assessment..
22
"Energy Economic Developments, Investment perspectives in electricity markets". Institutional paper
003, 1 July 2015 http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf
23
Published on 16.11.2015, at http://ec.europa.eu/competition/publications/reports/kd0216007enn.pdf
24
Ibid Section 3.3 of the non-technical summary at p. 23.
25
Based on the productivity dispersion and the Boone indicator over this period, ibid Section 3.4
"Summary of key findings" at p. 25.
33
Introduction
- The Commission launched a a sector inquiry into national capacity mechanisms,
The resulting "Interim Report of the Sector Inquiry on Capacity Mechanisms"
(SWD SWD(2016) 119 final)26
points out that there is a lack of adequate
assessment of the actual need for capacity mechanisms. It also appears that some
capacity mechanisms in place could be better targeted and more cost effective. It
emphasizes the need to design capacity mechanisms with transparent and open
rules of participation and a capacity product that does not undermine the
functioning of the electricity market, taking into account cross-border
participation.
1.1.2.3.Scope and summary of the initiative
In line with the Union's policy on climate change and energy, the proposed initiative
aims at deepening energy markets and setting a framework governing security of supply
policies that enables the transition towards a low carbon electricity production.
The transition towards a low carbon electricity sector as well as technical progress will
have profound implications on the manner in which the electricity sector is organised and
the roles of market actors and consumers, not all of which can be foreseen with accuracy
today. As it cannot be predicted how the electricity markets and progress of innovation
will look like in a few decades from now, the proposed initiative constitutes a next step in
a wider and longer evolutionary process that will guide the EU's electricity markets
towards the future. The initiative will consequently not address the challenges that might
arise when operating a fully decarbonised power system.27
This initiative also aims at improving consumer protection and engagement for both
electricity and gas consumers28
.
Organisation and timing
1.1.3.
1.1.3.1.Follow up on the Third Package
Full and timely transposition of the Directives of the Third Package has been a challenge
for the vast majority of the Member States. In fact, by the end of the transposition
deadline (March 2011), none of the Member States had achieved full transposition.
However, progess has been made and at present all of the infringement proceedings29
for
partial transposition of the Electricity Directive have been closed as the Member States
achieved full transposition in the course of the proceedings.
26
Published on 13.04.2016 at: :
http://ec.europa.eu/competition/sectors/energy/capacity_mechanism_report_en.pdf
27
For some of the arising issues and challenges see Chapter 2.3 in Investment Perspectives in Electricity
Markets, European Commission, DG EFCIN, 2015
http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf
28
With regards to gas consumers, only the consumer-related provisions of the Gas Directive are
concerned: Article 3 and Annex I. These address issues such as public service obligations, metering,
billing and a broad range of consumer rights that Member States shall ensure.
29
The Commission opened 38 infringement cases against 19 Member States for not transposing or for
transposing only partially the Directives.
34
Introduction
In addition to ensuring compliance of national rules with the Third Package, the
Commission has carried out assessments to identify and resolve problems concerning
incorrect transposition or bad application of the Third Package. On this basis, the
Commission has opened EU Pilot cases against a number of Member States. As of 7th
July 2016, 8 of these EU Pilot cases have resulted in infringement procedures where,
inter alia, the violation of the EU electricity market rules is at stake.
In January 2014 the Directorate General for Energy of the European Commission ('DG
ENER') launched a public consultation on retail markets for energy.
Whilst preparing the single market progress report (COM(2014) 634 final), published on
13 October 2014, DG ENER decided to study a number of changes to the current
legislation.
The Commission (DG ENER) started in 2015 the preparatory work for the present impact
assessment to assess policy options related to the internal energy market for electricity
and to security of electricity supply and consulted in July 2015 the public on a new
energy market design (COM(2015) 340 final)30
.
In April 2015, the Commission (DG Competition) launched a sector inquiry into national
capacity mechanisms. The Commission interim report and the accompanying
Commission staff working document, adopted on 13 April 2016 have provided a
significant input for the proposed initiative. This will be further completed by the final
report.
1.1.3.2.Consultation and expertise
The Commission has conducted a number of wide public consultations on the different
policy areas covered by the present Impact assessment which took place between 2014
and 2016. In addition to the public consultations, it has organised a number of targeted
consultations with stakeholders throughout 2015 and 201631
.
Given the cross-cutting nature of the planned impact assessment work, the Commission
set up an inter-service steering group which included representatives from a selected
number of Commission Directorate Generals. The inter-service steering group held
regular meetings to discuss the policy options of the proposed initiatives and the
preparation of the impact assessment32
.
In parallel, the Commission has also conducted a number of studies mainly or
specifically for this impact assessment33
.
30
https://ec.europa.eu/energy/sites/ener/files/documents/1_EN_ACT_part1_v11.pdf and
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
31
For more information on the consultation process, please refer to Annex 3
32
For more information on inter-service steering group, please refer to Annex 1.
33
For the list of studies and a summary description, please refer to Annex 5.
35
Introduction
1.2. Interlinkages with parallel initiatives
The proposed initiatives are strongly linked to other energy and climate related
legislative proposals brought forward in parallel with the present initiative equally aimed
at delivering upon the five dimensions of the Energy Union, namely energy security,
solidarity and trust, a fully integrated European energy market, energy efficiency
contributing to moderation of demand, decarbonisation, research, innovation and
competitiveness. These other energy related legislative proposals include:
The Renewable Energy Package comprising the new Renewable Energy Directive
1.2.1.
and bioenergy sustainability policy for 2030 ('RED II')
The RED II covers a number of measures deemed necessary to attain the EU binding
objective of reaching a level of at least 27% RES in final energy consumption by 2030
across the electricity, heating and cooling, and transport sectors. As regards electricity in
particular, the Renewables Directive proposes a framework for the design of support
schemes for renewable electricity, a framework for renewable self-consumption and
renewable energy communities, as well as various measures to reduce administrative
costs and burden.
Conversely, measures aimed at the integration of RES E in the market, such as provisions
on priority dispatch and access previously contained in the renewables directive are part
of the present market design initiative. The reflections on a revised Renewables Energy
Directive will include specific initiatives on support schemes for market-oriented, cost-
effective and more regionalised support to RES up to 2030 in case Member States were
opting to have them as a tool to facilitate target achievement. The Renewable Package is
expected to deal with legal and administrative barriers for self-consumption, whereas the
present package will address market related barriers to self-consumption.
The Renewable Energy package has synergies with the present initiative as it seeks to
adapt the current market design, optimised for large-scale, centralised power plants, to a
suitable one for the cost-effective operation of variable, decentralised generation of
electricity whilst taking into account technological progress creating the conditions for a
cost efficient achievement of the binding EU RES target in the electricity sector.
The enhanced market design will improve the viability of RES E investments, but
electricity market revenues alone might not prove sufficient in attracting renewable
investments in a timely manner and at the required scale to meet EU's 2030 targets. The
MDI and RED II impact assessments thus jointly come to the conclusion that the
improved electricity market, in conjunction with a reformed EU ETS could, under certain
conditions, deliver investments in the most mature renewable technologies (such as solar
PV and onshore wind). The underpinning modelling and analysis, points that the RES E
funding gap in 2020 is gradually reducing towards 2030 as market conditions improve.
Less mature RES E technologies, needed for meeting the 2030 and 2050 energy and
climate objectives, such as off-shore wind, will likely need some form of support to
cover at least a fraction of total project costs (complementing the revenues obtained from
the energy markets) throughout the 2021-2030 period. These technologies are required if
RES E technologies are to be deployed to the extent required for meeting the 2030 and
2050 energy and climate objectives, and provide an important basis for the long-term
competitiveness of an energy system based on RES E.
36
Introduction
Similarly, the progressive reform of RES E support schemes as proposed by the RED II
initiative, building on the Guidelines on State aid for environmental protection and
energy 2014-2020 ('EEAG'), is a prerequisite for the results of the present initiative to
come about. In order to ensure that a market can function, it is necessary that market
participants are progressively exposed to the same price signals and risks. Support
schemes based on feed-in-tariffs prevent this and would need to be phased-out – with
limited exemptions – and replaced by schemes that expose all resources to price signals,
as for instance by means of premium based schemes. Such schemes would be made even
more efficient by setting aid-levels through auctioning as RES E investments projects
will then be incentivised to develop business models that optimise market based
returns34
.
The issue is explored in more detail in section 6.2 of the present impact assessment and,
in particular, the RED II impact assessment.
Commission guidance on regional cooperation
1.2.2.
The forthcoming guidance on regional cooperation may set out general principles for
regional cooperation across all five dimensions of the Energy Union, described how these
principles are being addressed in this initiative and other legislative proposal for
Renewables and Energy Union governance, and will offer suggestions on how regional
co-operation, where it applies, can be made to work in practice.
The present initiative seeks to improve market functioning, and calls for a more regional
approach to system operation and security of supply. The guidance document should help
Member States best achieve regional co-operation, including in areas where the present
initiative mandates effective co-operation (e.g. the initiative calls on Member States to
prepare risk preparedness plans in a regional context, cf. infra).
The Energy Union governance initiative
1.2.3.
The Energy Union governance initiative aims at ensuring a coordinated and coherent
implementation of the Energy Union Strategy across its five dimensions with emphasis
on the EU's energy and climate targets for 2030. This is established through a coherent
combination of EU-level and national action, a strengthened political process and with
reduced administrative burden.
With these objectives in mind, the draft Regulation is based on two pillars:
- Streamlining and integration of existing planning, reporting and monitoring
obligations in the energy and climate fields, in order to reduce unnecessary
administrative burden;
- A political process between Member States and the Commission with close
involvement of other EU institutions to support the achievement of the Energy
34
See Box 7 and Annex IV for more information
37
Introduction
Union objectives, including notably the 2030 targets for greenhouse gas emission
reductions, renewable energy and energy efficiency.
In relation to this initiative the governance initiative will also streamline reporting
obligations by Member States and the Commission that are presently enshrined in the
Third Package.
The Energy Efficiency legislation ('EE')35
and the related Energy Performance of
1.2.4.
Buildings Directive ('EPBD')36
including the proposals for their amendment.
In general terms, energy efficiency measures interact with the present initiative as they
affect the level and structure of electricity demand. In addition, energy efficiency
measures can alleviate energy poverty and consumer vulnerability. Besides consumer
income and energy prices, energy efficiency is one of the major drivers of energy
poverty.
The provisions currently still in the current energy efficiency legislation concerning
metering and billing (to the extent related to electricity) may become part of the present
initiative as these relate to consumer conduct and their participation in the market which
are important issues in the context of the present initiative. This logic is reinforced by the
fact that the Third Package already contains closely related provisions on smart metering
deployment and fuel mix and comparability provisions in billing.
Similarly, all provisions on priority dispatch for Combined Heat and Power ('CHP')
previously contained in the energy efficiency legislation will be set out in the present
initiative as these provisions relate to the integration of these resources in the market and
as they are very similar to the priority dispatch provisions for RES E, also dealt with in
the present initiative.
The provisions previously contained in the energy efficiency legislation on demand
response will be set out in the present initiative37
because these relate to incentivising
flexibility in the market and participation of consumers in the market, both core subjects
of the present initiative. This logic is reinforced by the fact that the Third Package
already contains related provisions on demand response.
The Commission Regulation establishing a Guideline on Electricity Balancing
1.2.5.
('Balancing Guideline')
The Balancing Guideline constitutes an implementing act that will be adopted using the
Electricity Regulation as a legal basis. The Balancing Guideline is closely related to the
present initiative. This is because efficient, integrated balancing markets are an important
35
Directive 2012/27/EU of the European Parliament and of the Council of 25 October 2012 on energy
efficiency, amending Directives 2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC
and 2006/32/EC; OJ L 315, 14.11.2012, p. 1–56.
36
Directive 2010/31/EU of the European Parliament and of the Council of 19 May 2010 on the energy
performance of buildings. OJ L 153, 18.6.2010, p. 13–35.
37
In a manner that will preserve DG Energy's ability to continue infringing Member States that have not
correctly implemented what is now Article 15(8) of the Energy Efficiency Directive.
38
Introduction
building block for the consistent functioning of wholesale markets which in turn are
needed for a cost effective integration of RES E into the electricity market.
The Balancing Guideline aims at harmonising certain aspects of the EU's balancing
markets, with a focus on optimising the cross-border usage that TSOs make of the
balancing reserves that each have decided to contract individually, such as harmonisation
of the pricing methodology for balancing; standardisation of balancing products and
merit-order activation of balancing energy.
The present initiative seeks in contrast to focus on a more integrated approach to
deciding and contracting of the balancing reserves, as opposed to their usage, which
touches upon the optimal allocation of the cross-border transmission capacities and a
regional approach to balancing reserves.
Thus, the Balancing Guideline deals principally with exchanges of balancing energy
whereas the present initiative focusses on the exchange and sharing of balancing
capacity. The latter issue is much more political than the exchange of balancing energy
and closely related to other questions dealt with in the present initiative, such as regional
TSO cooperation or the reservation of transmission capacities. The assessments of the
two initiatives are fully coherent. Indeed, the implementation of the guidelines on
electricity balancing is part of the baseline for the present impact assessment38
.
Other relevant instruments
1.2.6.
Other relevant instruments are the Commission proposal for setting national targets for
2030 for the sectors outside the EU's ETS, the revision of the EU's ETS for the period
after 2020, EU's competition instruments and the EU state aid rules applicable to the
energy sector and clarified in the EEAG. and the decarbonisation of the transport sector
initiative. The manner in which this policy context is interacting with the present
initiative is explored further in section 4.2.
38
See also Section 5.1.2 of the present impact assessment and in the Annex IV on the modelling
methodology.
39
Problem Description
2. PROBLEM DESCRIPTION
2.1. Problem Area I: Market design not fit for an increasing share of variable
decentralized generation and technological developments
The European Union's policy to fight global warming will require the electricity systems
to shift from a generation mix that is mostly based on fossil fuels to a virtually
decarbonised power sector by 2050. Indeed, with the 2030 targets agreed by the October
2014 European Council (EuCo 169/14) the share of electricity generated from renewable
sources is projected to be close to 49% of total electricity produced, while their share in
total net installed capacity is projected to be 62.45%39
.
Table 1: RES E % share in total net electricity generation
Year 2000 2005 2010 2015 2020 2025 2030
RES E total (TWh) 422 467 683 916 1,193 1,443 1,654
Total net generation (TWh) 2,844 3,119 3,168 3,090 3,221 3,317 3,397
RES E 15% 15% 22% 30% 37% 43% 49%
Source: PRIMES; based on EUCO27 scenario
Whereas renewable electricity can be produced by a variety of technologies, most new
installed capacity today is based on wind and solar power. By 2030, this is expected to be
even more pronounced.
Table 2: Share of variable RES E (solar and wind power) in RES E and total net
generation
Year 2000 2005 2010 2015 2020 2025 2030
Variable RES E (TWh) 22 72 171 378 618 820 995
Total RES E (TWh) 422 467 683 916 1,193 1,443 1,654
Variable RES E in RES E 5% 16% 25% 43% 52% 57% 62%
Variable RES E in total net generation 1% 2% 5% 12% 19% 25% 29%
Source: PRIMES; based on EUCO27 scenario
The patterns of electricity production from wind and sun are inherently more variable and
less predictable when compared to conventional sources of energy (e.g. fossil-fuel-fired
power stations) or flexible RES E technologies (e.g. biomass, geothermal or
hydropower). Weather-dependent production also implies that output does not follow
demand. Consequently, there will be times when renewables could cover a very large
share – even 100% – of electricity demand and times when they only cover a minor share
of total consumption. While the demand-side and decentralized power storage could in
theory react to the availability of renewable energy sources and even to extreme
variations, current market arrangements do not enable most consumers to actively
participate in electricity markets either directly through price signals or indirectly through
aggregation.
39
These figures are based on the PRIMES EUCO27 results.
40
Problem Description
While renewable technologies and individual projects differ significantly in size (from
rooftop solar on households with 5 to 20 kW to several hundreds of MW for large
offshore wind parks), the majority of renewable investments are developed at
comparatively small scale. Given that the typical installation size of an onshore wind
farm or a solar park is generally multiple40
times smaller than of a conventional power
station, the number of power producing units and operators will increase significantly.
Consequently, the transition towards more renewables implies that more and more power
will be generated in a decentralised way. Market roles and responsibilities will have to be
adapted.
Finally, these new installations will not necessarily be located next to consumption
centres but where there are favourable natural resources. This can create grid congestion
and local oversupply.
The transition towards a low carbon electricity production poses a number of challenges
for the cost-effective organisation and operation of Europe's power system and its
electricity markets. The existing market framework was designed in an era in which
large-scale, centralised power stations, primarily fired by fossil fuels, supplied passive
customers at any time with as much electricity as they wanted in a geographically limited
area – typically a Member State. This framework is not fit for taking up large amounts of
variable, often decentralised electricity generation nor for actively involving more
consumers in electricity markets.
The main underlying drivers are: (i) the inefficient organisation of short-term electricity
markets and balancing markets, (ii) exemptions from fundamental market principles, (iii)
consumers that do not actively engage in the market, (iv) consumers do not actively
engage in the market and demand response potential remains largely untapped; and (v)
distribution networks that are not actively managed and grid users are poorly
incentivised.
40
The largest solar PV park in the EU is the 300 MW Cestas Park in France, http://www.pv-
magazine.com/news/details/beitrag/frances-300-mw-cestas-solar-plant-
inaugurated_100022247/#axzz4Cxalbrhc. The largest wind farm is the offshore farm "London array"
with 630 MW distributed over 175 turbines. By comparison, the largest nuclear power plant in Europe
is the Gravelines plant in France, with a net capacity of 5460MW. The largest coal-fired power station
in Europe is the Polish Bełchatów plant with a capacity of 5420 MW.
41
Problem Description
Driver 1: Short-term markets, as well as balancing markets, are not efficiently
2.1.1.
organised
Today's short-term markets are not efficiently organised, because they do not give all
resources – conventional power, renewables, the demand-side, storage – equal
opportunities to access these markets and because they do not fully take into account the
possible contribution of cross-border resources. The latter problem often originates from
a lack of coordination between national entities and a lack of harmonisation of rules,
while the former relates to the trading products themselves, e.g. their commitment period,
which sometimes are too restrictive to allow for a level playing field of all kinds of
resources41
.
Short-term markets play a major role in any liberalised power system due to the
characteristics of electricity as a product. Electricity must be generated and transmitted as
it is consumed. The overall supply and demand needs to be in balance in physical terms
at any given point in time. This balance guarantees the secure operation of the electricity
grid at a constant frequency. Imbalances between injections and withdrawals of
electricity render the system unstable and, ultimately, may give rise to a black-out.
As a consequence, market participants need to be incentivised to have a portfolio of
electricity injections into and withdrawals from the network that net-out. Market
participants can adjust their portfolio by revising production and consumption plans and
selling or buying electricity42
. Efficient and liquid markets with robust price signals are
crucial to guide these decisions43
.
The fact that the production patterns from weather dependent RES E can only be
predicted with acceptable accuracy within hours, creates challenges for market parties
and for system operation. In the absence of efficient and liquid short-term electricity
wholesale markets, system operators have to take actions to balance the system and
manage network congestions once the production forecasts become more precise.
Moreover, operators of RES E are unable to adjust their portfolios once the production
forecasts become more precise, leaving them exposed to risks and costs, when they
deviate from their plans. An increasing penetration of RES E thus requires efficient and
liquid short-term markets that can operate until very shortly before the time of physical
delivery i.e. the moment when electricity is consumed. The entire electricity system must
become more flexible, also through the progressive introduction of new flexible
resources such as storage, to accommodate variations in RES E production.
41
EPRG Working paper 1614 (2016) "Overcoming barriers to electrical energy storage: Comparing
California and Europe" by F. Castellano Ruz and M.G. Pollitt concludes: "In Europe, there is a need
to clarify the definition of EES, create new markets for ancillary services, design technology-neutral
market rules and study more deeply the necessity of EES."
42
Depending on the delivery period, bulk electricity can be traded on "spot markets" or "forward
markets". Spot markets are currently mainly "day-ahead markets" on which electricity is traded up to
one day before the physical delivery takes place. On "forward markets", power is traded for delivery
further ahead in time.
43
IEA "Re-powering markets" (2016) suggests: "A market design with a high temporal and geographical
resolution is therefore needed".
42
Problem Description
Current trading arrangements are however not optimised for a world in which market
participants have to adjust portfolios on short notice. The manner in which the trading of
electricity is arranged and the methods for allocating the network capacity to transmit
electricity are organised, allow for efficient trading of electricity in timeframes of one or
more days ahead of physical delivery. These arrangements befit well a world of
conventional electricity production that can be predictably steered but not the new
electricity landscape with a high share of renewables with limited forecasting abilities in
a day-ahead timeframe.
The current market framework already envisages that these short-term adjustments can
be made in intraday markets to correct. However, whilst liquidity has increased over the
past few years, there remains significant scope for further increases in these markets44
.
As way of illustration, in 2014, in the intraday timeframe, only five markets in Europe
had a ratio of traded energy to demand of greater than 1%45
. Further, progress remains in
connecting ('coupling') national intraday markets in the same way as day-ahead markets.
This can lead to a low level of cross-border competition in intraday markets. In 2014
only 4.1% of available interconnection capacity at the intraday stage was used, compared
to 40% at day-ahead.
Improving liquidity of intraday markets requires addressing various issues, including
removing the barriers that today exist for trading power across borders as well as
providing proper incentives to rebalance portfolios by trading until short notice before
markets close. In addition, technical rules of the market (i.e. products, bid sizes, gate
closure times) are often not defined with renewables or demand response in mind
creating de facto barriers for its participation.
Specific issues include a variation in commitment periods across Europe, with some
Member States choosing 15-minute and other Member States choosing 60-minute
products, and the time to which market participants can trade, which can be as short as 5
minutes or, in some instances, upto several hours before real time. There is also a
difference in how markets are organised: in continuously traded markets, transactions are
concluded throughout the trading period every time there is a match between bids and
offers. Transactions are concluded differently in auction markets, where previously
collected bids and offers are all matched at once at the end of the trading period.
The last market-based measure to net out imbalances between injections and withdrawals
of electricity is the balancing market. As such, the balancing market is not solely a
technicality ensuring system stability but has significant commercial implications and, in
turn, implications for competition. Procurement rules often fit large, centralised power
stations but do not allow for equal access opportunities for smaller (decentralised)
resources, renewables, demand-side and batteries. ACER's market monitoring reports
revealed high levels of concentration within national balancing markets. TSOs are often
faced with few suppliers or (in case of vertically integrated TSOs) procure balancing
reserves from their affiliate companies. This, combined with a low degree of integration,
44
See Annex 2.2 for further details.
45
Spain (12.1%) Portugal (7.6%), Italy (7.4%) Germany (4.6%) Great Britain (4.4%). ACER, Market
Monitoring Report 2015
43
Problem Description
enables a limited number of generators to influence the balancing market outcome.
Moreover, the procurement rules can lower the overall economic efficiency of the power
system by creating so-called must-run capacity, i.e. capacity that does not (need to) react
to price signals from other markets, because it generates sufficient revenues from
balancing markets.
Beside procurement rules, there is a potential issue with procurement volumes due to
national sizing of reserves. Possible contributions of neighbouring resources are not
properly taken into account, thus over-estimating the amount of reserves to be procured
nationally.
Driver 2: Exemptions from fundamental market principles
2.1.2.
Two fundamental principles of today's market framework are that (i) market participants
should be financially responsible for any imbalance in their portfolio and that (ii) the
operation of generation facilities should be driven by market prices. For a number of
reasons a wide range of exceptions from these principles exist today which could lead to
distortions, thus diminishing market efficiency.
The principle of financial responsibility for imbalances is often referred to as balancing
obligation. In many Member States, some market participants are fully or partly
exempted from this obligation, notably many renewable energy but also CHP generators.
Exemptions are typically granted on policy grounds, e.g. the existence of policy targets
for renewables. Such a special treatment constitutes a challenge for the cost-effective
functioning of electricity markets, because these technologies represent a significant
share in total power generation already and are expected to further grow in importance in
the forthcoming decade. For RES E, exemptions from balancing responsibility were
initially justified on the basis of significant errors in production forecasts being
unavoidable (as production for many RES E technologies is based on wheather) and on
the absence of liquid short-term markets which would have allowed RES E generators to
trade electricity closer to real time, thus reducing the error margin. Significant
improvements have been made in wheather forecasts, reducing the error margin. Part of
these improvements was based on financial incentives from increased balancing
responsibilities46
. Furthermore, cross-border integration and liquidity of short-term
markets has improved over the last years, with further progress expected over the coming
years, such as through the progressive penetration of storage, and following the present
proposal. Thus, the underlying reasons for the exemption of RES E from this principle
have to be revisited.
A consequence of this lack of balancing obligation is that plant operators have no
incentive to maintain a balanced portfolio. The balancing obligation is typically passed
on to the responsible system operator, a regulated party, meaning that their balancing
costs will be socialised. This represents a market distortion and lowers the liquidity and
46
ENTSO-E provided figures that following the introduction of balancing responsibility in one Member
States, the average hourly imbalance of PV installations improved from 11.2 % in 2010 to 7.0 % in
March 2016, and the average hourly imbalance of wind improved from 11.1 % to 7.4 % over the same
period.
44
Problem Description
efficiency of short-term markets as the concerned market operators do not become active
on the short-term market to balance their portfolio. So the absence of full balancing
responsibility is in fact a major driver preventing the emergence of liquid and efficient
short-term markets. Moreover, costs arising from forecast errors for renewables are likely
higher than necessary due to a lack of incentive to minimise them by short-term market
operations. This creates a higher than necessary burden on consumers' electricity bills.
The principle that the operation of generation facilities should be driven by market prices
is also referred to as economic dispatch. When a unit's variable production costs are
below market price, it is economically efficient to dispatch it first, because the operator
generates (gross) profits from selling electricity. This principle guarantees that power is
produced at the lowest cost to reliably serve consumers, while taking into account
operational limits. However, priority dispatch deviates from this principle, by giving
certain technologies priority independent of their marginal cost. This represents a market
distortion and leads to a sub-optimal market outcome.
Given the expected massive increase in share of wind and solar technologies, it is likely
that unconditional dispatch incentives for these technologies will aggravate the situation,
as will the fact that certain RES E technologies and often CHP have positive variable
production costs. The review of priority dispatch rules for RES E is thus closely related
to the review of rules on public support in the RED II. Compared to the impact on RES E
from low marginal cost technologies, fully merit order-based dispatch has more
significant impact on conventional generation (CHP and indigenous fuels) and high
marginal cost RES E (e.g. RES E based on biomass), as these technologies will not be
dispatched first under the normal merit order. Achieving merit order based dispatch will
in these cases allow to use flexibility resources to their maximum extent, creating e.g.
incentives for CHP to use back-up boilers or heat storage to satisfy heat demand in case
of low electricity demand, and use flexible biomass generation to satisfy demand peaks
rather than producing as baseload generation.
Similarly, the principle of priority access reduces system efficiency in situations of
network congestion. When individual grid elements are congested, the most efficient
solution is often to change the dispatch of power generation or demand located as closely
as possible to the congested grid element. Priority rules deviate from this principle,
forcing the use of other, potentially much less efficient resources. With sufficient
transparency and legal certainty on the process for curtailment and redispatch, and
financial compensation where required, priority access should be limited to where it
remains strictly necessary.
45
Problem Description
R&D results47
: In relation to dispatching and curtailment, the Integral project showed that load-shedding
based on software tools and remote control can be a useful tool to manage grid constraints and prevent
network problems. It demonstrated that load-shedding can be done on a procurement basis by the grid
operator and is a viable alternative to RES E curtailment. Thus, the grid operator can find the most cost-
efficient solution on market based terms as opposed to taking recourse to simply curtailing certain sources
of generation.
Driver 3: Consumers do not actively engage in the market and demand response
2.1.3.
potential remains largely untapped
The active participation of consumers in the market is currently not being promoted,
despite technical innovation such as smart grids, self-generation48
and storage equipment
that allow consumers – even smaller commercial and residential consumers – to generate
their own electricity, store it, and manage their consumption more easily than ever. While
more and more consumers have access to smart meters and distributed renewable energy
resources such as roof-top solar panels, heat pumps and batteries, a minor share manages
their consumption and these resources actively.
Large-scale industrial consumers already are active participants in electricity markets.
However, the vast majority of other consumers neither has the ability nor the incentive to
take consumption, production and investment decisions based on price signals that reflect
the actual value of electricity and grid infrastructure. The metering and billing of
consumers does not allow them to react to prices within the time frames in which
wholesale markets operate. And even where technically possible, many electricity
suppliers appear reluctant to offer consumer tariffs that enable this. This leads to the
overconsumption/underproduction of electricity at times when it is scarce and the
underutilisation/overproduction of electricity at times when it is abundant.
Indeed, current markets do not enable us to reap the full benefits of technological
progress in terms of reducing transaction costs, reducing information asymmetries, and
(thereby) reducing barriers to market participation for smaller commercial and residential
consumers.
Periods of abundance and scarcity will increasingly be driven by high levels of RES E
generation. To deal with an increased share of variable renewables generation in an
efficient way, flexibility is key. Traditionally, almost all flexibility was provided in the
electricity systems by controlling the supply side. However, it is now possible to provide
demand side flexibility cost effectively. New technological developments such as smart
metering systems, home automation, etc. but also new flexible loads such as heat pumps
and electric vehicles allow for the reduction of demand peaks and, hence, significantly
reduce system costs.
47
Technological developments are both part of the drivers that affect the present initiative and part of the
solutions of the identified problems they affect. Therefore reference is made to finding of various
research and development projects that provide insights where these are pertinent. A list of the
research and development projects mentioned in this box and their findings relevant to the present
impact assessment is provided in Annex 8.
48
The specific issue of self-generation and self-consumption is analysed in detail in the Impact
Assessment for the RED II.
46
Problem Description
The current theoretical potential of demand response adds up to approximately 100,000
MW and is expected to increase to 160,000 MW in 2030. This potential lies mainly with
residential consumers, and its increase will greatly depend on the uptake of new flexible
loads such as electric vehicles and heat pumps.
Figure 1: Theoretical demand response potential 2016 (in MW)
Source: Impact Assessment support Study on downstream flexibility, demand response
and smart metering, COWI, 2016
For the industrial sector demand response is mainly related to flexible loads in electric
steel makings. In the commercial sector, a high theoretical potential exist for ventilation
of commercial buildings while in the residential sector mainly freezers and refrigerators,
and the electric heater with storage capacity show a high theoretical potential.
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
Industrial
Commercial
Residential
47
Problem Description
Figure 2: Theoretical potential of demand response per appliance
Source: Impact Assessment support Study on downstream flexibility, demand response
and smart metering, COWI, 2016
Approximately 30-40% of this potential can be considered technically and economically
viable and, hence, can expected to be activated if the right technologies, incentivising
mechanisms and market arrangements are in place. Demand response service providers
(often referred to as aggregators) can play an important role in activating this potential by
enabling smaller consumers and distributed generation in general to interact with the
market and have their resources being managed based on price signals, or provide
balancing or grid congestion services. These aggregators effectively reduce transaction
0 4000 8000 12000 16000
Aluminum
Copper
Zinc
Chlorine
Mechanical Pulp
Paper Machines
Paper Recycling
Electric Steel
Cement
Calcium Carbide
Air Seperation
Industrial Cooling
Industrial Building Ventilation
Cooling Retail
Cold storage houses
Cooling Hotels/Restaurants
Ventilation Commercial Buildings
AC Commercial Buildings
Storage hot water commercial sector
Electric storage heater commercial sector
Pumps in water supply
Waste water treatment
Residential refrigerators/freezers
Washing machines
Laundry driers
Dish washers
Residential AC
Storage hot water residential sector
Electric storage heater residential sector
Residential heat circulation pumps
MW
Theorertical potential of demand response per
appliance
2030 2020 2010
48
Problem Description
costs and information asymmetries in the market, enabling a large number of smaller
and/or distributed resources to praticipate.
Of this potential, currently only around 21,000 MW demand response is used in the
market. Approx. 15,000 MW are contracted from large industrial consumers through
direct participation in the market while approx. 6,000 MW come from residential
consumers who are on traditional time of use tariff (usually just differentiating between
day and night). Only in the Nordic markets a slow uptake of dynamic price contracts
linked to the wholesale market is taking place. This shows that especially in the
residential and commercial sector with a theoretical potential of more than 70,000 MW
the uptake of deman dresponse is slow.
The main reasons for residential and commercial consumers not taking part in the
demand response schemes are mostly technical but can also be explained by currently
relative small benefits for those consumer groups:
- The technological prerequisites are not yet installed and even where smart meters
are being rolled out they do not always have the functionalities necessary for
consumers to take active control of their consumption;
- Dynamic electricity price contracts are only available for commercial/residential
consumers in very few Member States and hence consumers do not have a
financial incentive to shift consumption;
- In many Member States, third-party service providers helping consumers to
manage their consumption can not freely engage with consumers and do not have
full access to the markets;
- In many European markets price spreads are reletively small and price peaks
either not incur often or only lead to peak prices that are slightly higher than the
average price which makes demand response currently not very interesting from
a financial point of view. However, with an increase in renewables generation
this price spreads are likely to increase and participating in demand response will
become more profitable for consumers in the future. Variable network tariffs can
equally contribute to increasing the price spread;
- Consumers are more likely to participate in demand response when they have
significant single loads such as electric heating or electric boilers that are easy to
shift. In that respect the uptake of electric vehicles and heat pumps will also open
new opportunities for consumers to engage in demand response;
- Finally, automatisation is key to untap the full potenial of demand response in
the residential and commercial sector. Considering the relatively small economic
benefit residential consumers are likley to realise by participating in demand
response it is essential that theparticipation does not require active efforts but
devices can react automatically to price signals. Hence, interoperability of smart
metering systems will be crucial for the uptake of demand response.
In addition, the current design of the electricity market has not evolved to fully
accomodate demand side flexibility. It was meant for a world where consumers are
passive consumers of electricity that do not actively participate in the market. Hence,
current market arrangements at both the wholesale and retail level often make it very
difficult for demand-side flexibility to compete on a level playing field with generation:
49
Problem Description
- Similar to RES E, consumption is variable and subject to forecast errors. As a
consequence, it is often infeasible for most individual customers to offer
demand-response many days ahead of the moment when electricity is actually
consumed
- The liquidity of intraday markets – where demand response at short notice can
fetch a high price – is currently limited, providing little incentive to offer
demand-side flexibility;
- Procurement timeframes for balancing reserves capacity have generally long lead
times (week-, month- or year-ahead) for which demand response cannot always
secure firm capacity.
- Balancing markets often require that units can offer both upward regulation (i.e.
increasing power output) and downward regulation (i.e. reducing power output;
offering demand reduction) at the same time, making it difficult for demand
response to participate in those markets;
- And finally, product definitions make it difficult for aggregated loads to compete
in many markets.
The table below summarizes in which Member States markets are open to demand
response and the volume of demand response contracted. While demand response is
allowed to participate in most Member States, volumes of more than 100MW can only be
found in 13 Member States.
50
Problem Description
Table 3: Participation of explicit Demand Response in different markets
Member State
Demand Response
in energy markets
Demand Response
in balancing
markets
Demand
Response in
Capacity
mechanisms
Estimated
Demand
Response for
2016 (in MW)
Austria Yes Yes 104
Belgium Yes Yes Yes 689
Bulgaria No No 0
Croatia No No 0
Cyprus No market No market 0
Czech Republic Yes Yes 49
Denmark Yes Yes 566
Estonia Yes No 0
Finland Yes Yes Yes 810
France Yes Yes Yes 1689
Germany Yes Yes Yes 860
Greece No (2015) No 1527
Hungary Yes Yes 30
Ireland Yes Yes Yes 48
Italy Yes No Yes 4131
Latvia Yes No Yes 7
Lithuania unclear No 0
Luxembourg No information No information
Malta No market No market
Netherlands Yes Yes 170
Poland Yes Yes No 228
Portugal Yes No 40
Romania Yes Yes 79
Slovakia Yes Yes 40
Slovenia No Yes 21
Spain Yes No Yes 2083
Sweden Yes Yes Yes 666
UK Yes Yes Yes 1792
Total 15628
Source: Impact Assessment support Study on downstream flexibility, demand response and smart metering,
COWI, 2016
R&D results: VSync demonstrated that PV or wind generation, if equipped with a technology as
demonstrated in the VSync project, can replace the inertia that large power plants possess that is needed to
reduce frequency variations. Therefore, such technologies could in principle be used to provide balancing
services to the TSO.
EvolvDSO has identified and worked-out the details of future roles for actors active in the management of
power systems at the distribution level. The project identifies ways in which flexibility of resources
connected at distribution level could be revealed, valorised, contracted and exploited by various actors of
the power system. It identified roles that could be fulfilled by DSOs and by market parties and asks that
these are clarified
Several European demonstration projects such as ECOGRID-EU, Integral, EEPOS, V-Sync and S3C have
provided evidence that demand response is sufficiently mature from a technical point of view, while
stressing the need to removing market related barriers to its deployment.
In particular, Integral and ECOGRID-EU show that valuing flexibility through price signals is possible and
easy, that local assets can participate and earn money in the wholesale market, and that the economic
viability depends on the value of flexibility. Integral also demonstrated that flexibility of a household's
energy consumption (and hence the ability to provide demand response) was higher than initially expected,
probably due to the automated response that did not require active consumer participation. ECOGRID-EU
showed that a customer with manual control gave a 60 kW total peak load reduction while automated or
semi-automated customers gave an average peak reduction of 583 kW.
51
Problem Description
RES E and flexible electricity systems
Demand response, like other measures that improve the degree of flexibility in the
system, have an connection to the ability of RES E to finance itself in the market,
through what is often referred to as the 'merit order effect'. 49
During windy and sunny
days the additional electricity supply reduces the prices. Because the drop is larger with
more installed capacity, the market value of variable renewable electricity falls with
higher penetration rate, translating into a gap to the average market value of all electricity
generators over a given period. Inflexible markets where demand and generation are non-
responsive to price signals (including through measures such as priority dispatch or
'must-run' obligations) render this effect more pronounced. This effect is already visible
today in certain Member States, and in the absence of measures, can be expected to
become even more relevant as renewables penetration increases further.
At the one hand, this implies that as renewables are further gaining market shares in the
coming decade, the regulatory framework should not only incentivise the deployment of
renewables where costs are low (e.g. due to abundant wind or solar resources), but also
where and when the value of the produced electricity is the highest. On the other hand,
by improving the market framework in which RES E operates by rendering it more
flexible, unnecesarry erosion of the value of RES E assets can be prevented.
Reference is made to the box in Section 6.2.6.3 and Section 6.2.6.4 for further
information.
Driver 4: Distribution networks are not actively managed and grid users are
2.1.4.
poorly incentivised
Most of the time, the present regulatory framework does not provide appropiate tools to
distribution network operators to actively manage the electricity flows in their networks.
It also does not provide incentives to customers connected to distribution grids to use the
network more efficiently. Because smaller consumers have historically participated in the
broader electricity system only to a limited extent, currently no framework exists that
puts such incentives in place. This has led to fears over the impact that the deployment of
distributed resources could have at system-level (e.g. that the costs of upgrading the
network to integrate them would outweigh their combined benefits in other terms).
Moreover, the regulatory framework for DSOs, which most of the times is based on cost-
plus regulation, does not provide proper incentives for investing in innovative solutions
which promote energy efficiency or demand-response and fails to recognise the use of
flexibility as an alternative to grid expansion.
49
See Hirth, Lion, "The Market Value of Variable Renewables", Energy Policy, Volume 38, 2013, p.
218-236). The merit order effect is occasionally also referred to as the 'cannibalisation effect'.
52
Problem Description
With RES E being a source of electricity generation that is often decentralised in nature,
DSOs are gradually being transformed from passive network operators primarily
concerned with passing-on electricity from the transmission grid to end-consumers, to
network operators that, not unlike TSOs, actively have to manage their grids. At the same
time, technological progress allows distribution system operators to reduce network
investments by managing locally the challenges that more decentralised generation
brings about. However, outdated national regulatory frameworks may not incentivise or
even permit DSOs to make these savings by operating more innovatively and efficiently
because they reflect the technological possibilities of yesteryear. The resulting
inflexibility of distribution networks significantly increases the cost of integrating more
RES E generation, particulary in terms of investment.
R&D results: Reduced network investment by managing locally decentralised generation is demonstrated
in European projects like: SuSTAINABLE, MetaPV, evolvDSO, PlanGridEV, BRIDGE and REServices50
.
According to EvolvDSO, flexibility procurement and activation by DSOs are not addressed in the
regulatory framework in most Member States: they are not excluded in principle but not incentivised either
and, because they are not explicitly addressed, this creates uncertainty for the DSO to apply them.
The REServices study has analysed the possible services that wind and solar PV energy can provide to the
grid in theory but concludes that they are not able to (in the Member States analysed) due to the way the
market rules are defined.
The project SuSTAINABLE demonstrated that intelligent management supported by more reliable load
and weather forecast can optimise the operation of the grid. The results show that using the distributed
flexibility provided by demand-side response can bring an increase of RES E penetration while, at the same
time, avoid investments in network reinforcement, and this leads to a decrease in the investment costs of
distribution lines and substations.
The BRIDGE project recommended that products for ancillary services should be consistent and
standardized from transmission and down to the local level in the distribution network. Such harmonization
will facilitate the participation of demand-side response and small-scale RES in the markets for these
services, and thereby increase the availability of the services, enable cross-border exchanges and lower
system costs.
Tests in the project PlanGridEV with controllable loads (demand response, electric vehicles) performed in
a large variety of grid constellations have shown that peak loads could be reduced (up to 50%) and more
renewable electricity could be transported over the grid compared to scenarios with traditional distribution
grid scenarios. As a result, critical power supply situations can be avoided, and grids, consequently, do not
call for reinforcement
Both MetaPV and EvolvDSO suggest that a DSO makes a multiannual investment plan that takes into
account flexibility it can purchase from connected demand-side response or self-producers and consumers
(MetaPV suggests to do this through a cost-based analysis)
MetaPV also demonstrated that remotely controllable inverters connecting PV-panels to the distribution
grid can offer congestion management services to the distribution grid (in the form of voltage control
obtained via reactive power modulation). This increases the capacity of the distribution grid to integrate
intermittent RES by 50%, at less than 10% of the costs of ‘traditional’ investments in hardware such as
copper.
50
A list of the research and development projects mentioned in this box and their findings relevant to the
present impact assessment is provided in Annex 8.
53
Problem Description
2.2. Problem Area II: Uncertainty about sufficient future generation investments
and uncoordinated capacity markets
In light of the 2030 objectives, considerable new investment in electricity generation
capacity will be required. The power sector is likely to play a central role in the energy
transition. First, it has been the main sector experiencing decarbonisation since the last
decade and its challenges still remain high. Second, in the near future, the power sector is
expected to support the economy in reducing its dependence on fossil fuels, notably in
the transport and heating and cooling sectors.
Generation capacity in the EU increased sharply from 2009 onwards due to the addition
of new renewables technologies to the already existing capacity. The composition of the
capacity mix progressively changed. Nuclear capacity started declining in recent years
(2010-2013) due to phasing out decisions in some Member States. Other conventional
capacity showed a decline in 2012-2013 as well51
.
The largest part of the required new capacity will be variable wind and solar based,
complemented by more firm, flexible and less carbon-intensive forms of power
generation. At the same time, in light of the ageing power generation fleet in Europe with
more than half of the current capacity expected to be decommissioned by 204052
, it is
important to maintain sufficient capacity online to guarantee security of supply. The
modelling results nevertheless indicate that investment needs in additional thermal
capacity will be limited especially in the period 2021-2030. According to PRIMES
EUCO27, about 81% of net power capacity investments will be in low-carbon
technologies, of which 59% in RES E and 22% in nuclear generation53
.
51
See on this and for further information, European Commission, Investment perspectives in electricity
markets, Institutional Paper 003, July 2015, page 8.
http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf.
52
World Energy Outlook 2015, IEA
53
The challenge to attract sufficient investment in RES E is examined in detail in the RED II impact
assessment
54
Problem Description
Table 4: Investment Expenditure (including new construction, life-time extension
end refurbishment) in generation capacity by technology (average over 5 year
period) in MEuro'13
Period 2000-2005 2005-2010 2010-2015 2015-2020 2020-2025 2025-2030
Nuclear 1,502 739 270 6,291 11,011 14,312
Renewable energy 16,789 28,672 43,393 38,957 25,217 21,911
Hydro (pumping
excl.)
5,995 2,557 3,289 2,239 354 633
Wind 9,238 17,095 19,614 28,553 14,059 14,219
Solar 1,556 9,019 20,487 7,870 10,581 6,728
Other renewables - 2 3 295 223 332
Biomass-waste
fired
2,626 3,438 4,157 11,779 465 433
Geothermal heat 100 90 110 182 - -
Thermal 11,989 14,019 13,391 17,151 3,355 3,274
Solids fired 1,029 1,237 5,333 2,610 870 192
Oil fired 639 373 362 75 33 9
Gas fired 7,595 8,880 3,427 2,505 1,987 2,641
Hydrogen plants - - 1 - - -
Total (incl. CHP) 30,280 43,430 57,054 62,399 39,583 39,497
Source: PRIMES; based on EUCO27 scenario
At the same time, short-term market prices at wholesale level have decreased
substantially over the past years. In parallel with high fossil fuel prices, European
wholesale electricity prices peaked in the third quarter of 2008; then fell back as the
economic crisis broke out, and slightly recovered between 2009 and 2012. However,
since 2012 wholesale prices have been decreasing again. Compared to the average of
2008, the pan-European benchmark for wholesale electricity prices were down by 55% in
the first quarter of 2016, reaching 33 EUR/MWh on average, which was the lowest in the
last twelve years54
.
54
See the "main findings" of Section 1.1 on Wholesale electricity prices from the 2016 Commission
Staff Working Document accompanying the forthcoming 'Report on energy prices and costs in
Europe'.
55
Problem Description
Figure 3 on pan-European wholesale market prices
Source: Platts and European power exchanges
Prices declined for a number of reasons55
including (i) a decrease in primary energy
prices (e.g. coal, and more recently also natural gas), (ii) an increasing imbalance
between the supply and demand for carbon allowances, leading to a surplus of over 2
billion allowances by 2012 and a corresponding decrease in carbon allowance prices56
,
and (iii) an overcapacity of power generation facilities57
, putting a downward pressure on
wholesale prices.
55
The influence of each market factor might strongly very across different regions. For example, the
share of renewables and carbon prices have strong impact on wholesale price evolution in North
Western Europe, while in Central and Eastern Europe the main price driver is the share of coal and gas
in the generation mix.
56
Between April 2011 and May 2013 carbon emission allowance contracts underwent a significant price
fall (decreasing from 17 EUR/tCO2e to 3.5 EUR/tCO2e) reflecting the fall in demand for allowances
due to the recession. Since April 2013 carbon prices have increased, reaching an average auction
clearing price of €7,62/tCO2e in 2015.
(See: http://ec.europa.eu/clima/policies/ets/auctioning/docs/cap_report_201512_en.pdf).
The extent to which the carbon price impacts the wholesale power price depends on the carbon
intensity of the marginal power producer.
57
In parallel with decreasing fossil fuel and carbon prices (resulting in decreasing marginal costs of
electricity generation(, and the generation overcapacity, the share of renewable energy sources (wind,
solar, biomass, also including hydro) has been gradually increasing over the last few years. In most of
the EU countries fossil fuel costs set the marginal cost of electricity generation, being decisive for the
wholesale electricity price. However, increasing share of renewables in the electricity mix, together
with significant baseload generation capacities, shifted the generation merit order curve to the right,
resulting in lower equilibrium price set by supply and demand. Consequently, we can say that
increasing share of renewable energy sources, in an already oversupplied market, have significantly
contributed to low wholesale electricity prices in the EU markets.
56
Problem Description
Overcapacity was, in turn, caused by: (i) a drop in electricity demand as electricity
consumption decoupled from an already low economic growth58
, (ii) over-investments in
thermal plants59
, (iii) the increasing proportion of renewables with low marginal costs
driven by EU policies, (iv) barriers to decommission capacity60
, and (v) continuing
improvement in the field of coupling national electricity markets61
, leading to an
increased sharing of resources among Member States62
.
As a result, for most regions in Europe current electricity wholesale prices do not indicate
the need for new investments into generation capacity. There are, however, doubts
whether the market, as currently designed, would be able to produce investment signals
in case generation capacities were needed. Independently of current overcapacities of
most regions in Europe, a number of Member States anticipate inadequate generation
capacity in future years and introduce capacity mechanisms at national level.
Driver 1: Lack of adequate investment signals due to regulatory failures and
2.2.1.
imperfections in the electricity market
The internal energy market is built on competitive (short and long-term) wholesale power
markets where price signals are central to guide market participants production and
consumption decisions. Short-term prices signal prevailing supply and demand
58
Consumption of electricity in the EU decoupled from economic growth during the last few years due
to energy efficiency gains.
59
Investment decisions in the electricity sector are typically taken long before returns on investment are
effectively earned, due to the time to construct new power plants. At the same time, the decentralised
nature of investment decision-making means that each generator has limited information about the
generation capacity that competitors will make available in the coming years. The result is what has
been referred to as boom-bust cycles: alternate periods of shortages and overcapacity resulting from
lack of coordination in the investment decisions of competing generators.
60
In some Member States, there is an overcapacity situation that is in fact artificially extended by clear
regulatory exit barriers, which in the short-term depress market prices and in the mid/long-term ruin
the investment incentives.
61
In parallel, progressing market integration decreased price divergence within the EU. Indeed in the
first quarter of 2008 the price difference between the most expensive and the cheapest European
wholesale electricity market was 44 EUR/MWh, eight years later this difference has shrunk to 24
EUR/MWh. Based on "main findings" from 2016 costs and prices report and underlying studies,
published in conjunction with the present impact assessment
62
See also Box 9 behind section 6.4.6 for more on overcapacity, market exit and prices
57
Problem Description
conditions while long-term prices are formed according to expectations about future
supply and demand. Conditions, such as for example shortages or oversupply that are
expected to prevail in the future will not only determine short-term (spot) prices but also
impact long-term (forward, futures) prices.
In around half of Member States sales achieved at short and long term markets determine
the bulk of generators' income63
. This income is required to cover their full costs, mainly
fuel, maintenance and amortisation of assets (i.e. investments). These arrangements are
often referred to as energy-only markets. In the other half of Member States there are
also measures (either market based or non-market based) in place to pay generators for
keeping their capacity available (capacity mechanisms or 'CM's), regardless as to
whether they are producing electricity or not64
. For generators who operate on the market
these payments represent an additional income next to their earnings on the wholesale
markets for energy. Capacity payments, thus, represent additional support to maintain
and/or develop capacity.
Irrespective whether generators are expected to earn their investments solely on the
'energy-only' market or whether they can also rely on additional payments for capacity,
wholesale power prices are central to provide the right signals for efficient market
operations. For the EU-target model65
to function properly, prices need to be able to
properly reflect market conditions66
.
Price signals and long-term confidence that costs can be recovered in reasonable payback
times are essential ingredients for well-functioning market. In a market which is not
distorted by external interventions, the variability of the spot price on the wholesale
market, plays a role in signalling the need of investment in new resources. In the absence
of the right short- and long-term price signals, it is more likely that inappropriate
investment or divestment decisions are taken, i.e. too-late decisions or technology
choices that turn out to be inefficient in the long run. Price differentials between different
63
See below, figure 1 and ACER Market Monitoring Report 2014; generators may also collect additional
income from offering their capabilities, including the availability of (short-term) electricity to TSO's
who rely on them to manage the system (i.e. short-term balancing and ancillary Services)
64
"Capacity mechanisms exist worldwide both in regulated and in non-regulated markets": CIGRE
paper C5-213, "Capacity Mechanisms: Results from a World Wide Survey", H. Höschle, G. Doorman
(2016).
65
The "Electricity Target Model" aims at integrating wholesale power markets by harmonising the way
how transmission capacity is allocated between Member States. Central to it is market coupling which
is based on the, so-called, "flow based" capacity calculation, a method that takes into account that
electricity can flow via different paths and optimises the representation of available capacities in
meshed grids. The implementation of the target models in gas and electricity is equivalent to achieving
the completion of the internal energy market.
66
Evidently, efficient market outcome also presumes that all assets are treated equally in terms of the
risks and costs to which they are exposed and the opportunities for earning revenues from producing
electricity i.e. they operate on a level playing field as is esually fostered by the present intiative.
58
Problem Description
bidding zones should determine where generation and demand should ideally be
located,67
.
In 2013 the Commission published an assessment identifying reasons why the market
may fail to deliver sufficient new investment to ensure generation adequacy68
. These
reasons are a combination of market failures and regulatory failures. For example when
consumers cannot indicate the value they place on uninterrupted electricity supply, the
market may not be effective performing its coordination function. Equally however,
regulatory interventions, as well as the fear of such interventions, such as price caps and
bidding restrictions (regardless as to whether effectively restricting price formation at
that moment or only later) limit the price signal for new investments. Likewise the prices
on balancing markets operated by TSOs should not undermine the price signals from
wholesale markets.
Power generators and investors have argued that regulatory uncertainty and the lack of a
stable regulatory framework undermine the investment climate in the Union compared to
other parts of the world and to other industries.
In fact, current market arrangements often do not allow prices to reflect the real value of
electricity, especially when supply conditions are tight and when prices should reflect its
scarcity, affecting the remuneration of electricity generation units that operate less often
but provide security and flexibility to the system.
These regulatory failures are amplified by the increasing penetration of RES E. RES E is
capacity that often has a cost structure typified by low operational costs69
, resulting in
more frequent periods with low wholesale prices. The variability of RES E production
moreover decreases the number and predictability of the periods when conventional
electricity generators are used, thereby increasing the risk profile and risk premiums of
all investments in electricity resources70
. Whereas market participants are used to
hedging risks, and market trading arrangements are adapting to allow more risks to be
covered, the risk profile of investments will become more pronounced. This increases the
need to ensure that prices reflect the real value of electricity to ensure plants can cover
their full costs, even if they are operating less frequently.
67
See on price signals, European Commission, Investment perspectives in electricity markets,
Institutional Paper 003, July 2015, pages 32 and following.
(http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf
68
See also SWD(2013) 438 "Generation Adequacy in the internal electricity market - guidance on public
interventions", Section 3 .
69
Cost structures vary according to the underlying technology deployed. In general, wind and solar
technologies have very low operational costs whereas the opposite is true for biomass fuelled
generation.
70
Generators' expectations about future returns on their investments in generation capacity are affected
not only by the expected level of electricity prices, but also by several other sources of uncertainty,
such as increasing price volatility. The increasing weight of intermittent renewable technologies makes
prices more volatile and shortens the periods of operation during which conventional technologies are
able to recoup their fixed costs. In such circumstances, even slight variations in the level, frequency
and duration of scarcity prices have a significant impact on the expected returns on investments,
increasing the risk associated to investing in flexible conventional generation technologies.
59
Problem Description
The current market arrangements are constructed around the notion of price zones
delimited by network constraints. The price differences between such zones should drive
investments to be located where they relieve congestion by rewarding investments in
areas typified by high prices. The congestion rents collected by network operators to
transport electricity from low to high price zones are meant to be used to relieve
congestion by maintaining and constructing interconnection capacity.
However, today the delineation of price zones in practice does not reflect actual
congestion, but national borders. This prevents the establishment of prices that reflect
local supply and demand, which leads to the phenomenom of loop flows, which can
reduce the interconection capacity made available for cross-border trading and leads to
expensive out-of-market redispatching and significant distortions to prices and
investment signals in neighbouring bidding zones. To illustrate this, ACER has
estimated, in their Market Monitoring Report71
, that reductions in cross-border capacity
due to loop flows resulted in a welfare loss of EUR 445 million in 2014. Further, the
costs of re-dispatch and countertrading to deal with inaccurate dispatch can be high. In
2015 the total cost for redispatching within the German-Austria-Luxembourg bidding
zone was approximately EUR 930 million72
. There is also evidence that cross-border
capacity is being limited in order to deal with internal contraints, again limiting cross-
border trading opportunities. The impacts of this can be significant. For example, when
looking at the capacity between Germany and the Nordic power system, the Swedish
regulatory authority noted significant capacity limitations, concluding that these were
mostly due to internal contraints, and found that losses amounted to a total of EUR 20
million per annum in Norway and Sweden73
.
A further issue that can potentially distort investment is that of network charges on
generators. This includes charges for use of the network, both at distribution-level and
transmission-level (tariffs), as well as the charges applied to generators for their
connection (connection charges). There is significant variation across the EU on the
structure of these charges, which are set at Member State-level. For instance, some
Member States do not apply any tariffs to generators, others apply them based on
connected capacity and others based on the amount of electricity produced. Some include
locational signals within the tariff, some do not. With regards to connection charges,
some calculate them based only on the direct costs of accessing the system (shallow) and
others include wider costs, such as those of any grid reinforecement required (deep).
Such variations can serve to distort both investment and dispatch signals.
Driver 2: Uncoordinated state interventions to deal with real or perceived capacity
2.2.2.
problems
The uncertainty on whether the market will bring forward sufficient investment, or keep
existing assets in the market, has, in a number of Member States, fuelled concerns about
system adequacy, i.e. the ability of the electricity system to serve demand at all times.
71
"Market Monitoring report 2014" (2015) ACER, Section 4.3.2 on unscheduled flows and loop flows.
72
ENTSO-E Transparency Platform, at https://transparency.entsoe.eu/
73
"Capacity limitations between the Nordic countries and Germany" Swedish Energy Markets
Inspectorate (2015)
60
Problem Description
Certain Member States have reacted by introducing CMs designed to support investment
in the capacity that they deem necessary to ensure a secure and acceptable level of
system adequacy.
These measures often take the form of either dedicated generation assets kept in reserve
or a system of market wide payments to generators for availability when needed.
Figure 4: Capacity Mechanisms in Europe – 2015
Source: "Market Monitoring Report 2014" (2015) ACER.
These initiatives by Member States are based on non-aligned perceptions and
expectations as to the degree the electricity system can serve electricity demand at all
times and a reluctance to rely on the contribution the EU system as a whole can make to
the adequacy of the system of a given Member State.74
As reflected in the Interim Report of the Sector Enquiry75
led by DG Competition, many
existing CMs have been designed without a proper assessment of whether a security of
supply problem existed in the relevant market. Many Member States have not adequately
established what should be their appropriate level of supply security (as expressed by
their 'reliability standard') before putting in place a CM.
74
Indeed, a majority of Member States expect reliability problems due to resource adequacy in the future
even though such problems have been extremely rare in the past five years. Such issues have only
arisen in Italy on the Islands of Sardinia and Sicily which are not connected to the grid on the
mainland.
75
See also SWD(2016) 119 final "Interim report of the Sector Inquiry on Capacity Mechanisms",
http://ec.europa.eu/competition/sectors/energy/state_aid_to_secure_electricity_supply_en.html
Strategic reserve
(since 2004 ) - gradual phase-
out 2020 and considering a
permanent market system
after 2020
New Capacity Mechanism
under assessment by COMP
(Capacity payments from 2006
to 2014)
Capacity payment (since 2008) –
Tendering for capacity
considered but no plans
No CM (energy only market)
CM operational
Reliability option
(first auction end 2016, first
delivery contracted capacity is
expected in 2021)
Strategic reserve
(from 2016 on, for 2 years,
with possible extension for 2
years)
CM proposed/under consideration
Capacity requirements
(certification started 1 April
2015)
Capacity auction
(since 2014 - first delivery in
2018/19)
Capacity payment
(since 2007)
considering reliably options
Capacity Payment (Since 2010
partially suspended between
May 2011 and December 2014)
Strategic reserve (since 2007)
Debate pending
Strategic reserves for DK2
region from 2016-2018 (and
potentially from 2019-2020)
Strategic reserve
(since 1 November 2014)
61
Problem Description
Methods of assessing resource adequacy vary widely between Member States76
, which
make comparison and cooperation across borders difficult. Many resource adequacy
assessments take a purely national perspective and may substantially differ depending on
the underlying assumptions made and the extent to which foreign capacities77
as well as
demand side flexibility78
are taken into account. This, in turn, means some Member
States force consumers to over-pay for 'extra' capacities they do not really need.
Table 5: Deterministic vs probabilistic approaches to adequacy assessments
Source: European Commission based on replies to sector inquiry, see below for a description of capacity
margin, LOLP, LOLE, and EENS79
The introduction of CMs fundamentally change wholesale electricity markets because
generators and other capacity providers are no longer paid only for the electricity they
generated but also for their availability. Worse however is that CMs when introduced in
an uncoordinated manner can be inefficient and distort cross-border trade on wholesale
electricity markets.
In the short-term, CMs may lead to distortions if their design affects natural price
formation in the energy market (e.g. bidding behaviour of generators) and therefore alter
production decisions (operation of power generating plants) and cross-border
76
For more details, see annex 5.1. See also "Generation adequacy methodologies review", (2016), JRC
Science for Policy Report and CEER (2014), "Assessment of electricity generation adequacy in
European countries".
77
According to the CEER report, "the extent to which current generation adequacy reports take the
benefits of interconnectors into account varies a lot: 4 reports still model an isolated system (Norway,
Estonia, Romania, and Sweden); 2 reports use both interconnected and isolated modelling (France
and Belgium); 3 report methodologies are being modified to include an interconnection modelling; 9
reports simulate an interconnected system (UK, the Netherlands, Czech republic, Lithuania, Finland,
Belgium and Ireland, while France and Italy use both methods)."
78
According to the CEER report, "only 3 countries include demand response as a separate factor in
their load forecast methodology i.e. the UK, France and Spain. In Norway and Finland, the
contribution from demand response is not included as separate factor, but peak load estimation is
based on actual load curves which include the effect of demand response. Sweden does not consider
demand response, and do not assume that consumers respond to peak load in their analysis."
79
See annex 5.1 for the definition of the different methodologies.
62
Problem Description
competition. For instance, a possible distortion is when generators in a market applying a
CM, receive (capacity) payments which are determined in a way that affects their
electricity generation bids into the market, while in a neighbouring "energy-only" market
generators do not. This may tilt the playing field for generators on either sides of the
border. Another example might be if strategic reserves (a particular form of CMs) are
dispatched 'too-early' impeding the market's ability to establish equilibrium between
supply and demand. This can cause or contribute to a 'missing money' problem as
strategic reserves would outcompete existing (or future) generators who, at least partly,
rely on scarcity rents to cover their costs.
CMs may also influence investment decisions (investment in plants and their locations),
with potential impacts in the long term. If contributions from cross-border capacity are
not appropriately taken into account, they may lead to over-procurement of capacity in
countries implementing CMs, with a detrimental impact on consumers.
CMs may also cause a number of competition concerns. In this respect, the Sector
Inquiry identifies substantial issues in relation to the design of CMs in a number of
Member States. First, many CMs do not allow all potential capacity providers or
technologies to participate, which may unnecessarily limit competition among suppliers
or raise the price paid for the capacity80
.
Second, capacity mechanisms are also likely to lead to over-compensation of the capacity
providers – often to the benefit of the incumbents – if they are badly designed and non-
competitive. In many Member States the price paid for capacity is not determined
through a competitive process but set by the Member State or negotiated bilaterally
between the Member State and the capacity provider. This creates a serious risk of
overpayment81
.
Third, the inquiry revealed that capacity providers from other Member States (foreign
capacity) are rarely allowed to directly or indirectly participate in national CMs82
. This
leads to market distortions as additional revenues from CMs remain reserved to national
companies. This is particularly problematic in case of dominant national incumbents
whose dominant position may even be strengthened by a national CM.
Lastly, although there is a challenge to design penalties that avoid undermining
electricity price signals which are important for demand response and imports, where
80
In some cases, certain capacity providers are explicitly excluded from participating or the group of
potential participants is explicitly limited to certain providers. In other cases, Member States set
requirements that have the same effect, implicitly reducing the type or number of eligible capacity
providers. Examples are size requirements, environmental standards, technical performance
requirements, availability requirements, etc.
81
In Spain for example, the price for an interruptibility service almost halved after a competitive auction
was introduced.
82
For example, Portugal, Spain and Sweden appear to take no account of imports when setting the
amount of capacity to support domestically through their CMs. In Belgium, Denmark, France and
Italy, expected imports are reflected in reduced domestic demand in the CMs. The only Member States
that have allowed the direct participation of cross-border capacity in CMs are Belgium, Germany and
Ireland. For more details, see annex 5.2.
63
Problem Description
obligations are weak and penalties for non-compliance are low, there are insufficient
incentives for plants to be reliable.
All in all, the Sector Inquiry highlights that "a patchwork of mechanisms across the EU
risks affecting cross-border trade and distorting investment signals in favour of countries
with more ‘generous’ capacity mechanisms. Nationally determined generation adequacy
targets risk resulting in the over-procurement of capacities unless imports are fully taken
into account. Capacity mechanisms may strengthen market power if they for instance, do
not allow new or alternative providers to enter the market. Capacity mechanisms are
also likely to lead to over-compensation of the capacity providers – often to the benefit of
incumbents – if they are badly designed and non-competitive." All of these issues can
undermine the functioning of the internal energy market and increase energy costs for
consumers.
As reflected in the Sector Inquiry, the heterogeneous development of capacity
mechansims has led to fragmented markets across the EU. The Sector Inquiry highlights
that "the different types of capacity mechanisms are not equally well suited to address
problems of security of supply in the most cost effective and least distortive way".
The Sector Inquiry concludes that capacity payment schemes are generally problematic
as they risk over-compensating capacity providers because they rely on administrative
price setting rather than competitive allocation procedures. The risk for
overcompensation is lower for market-wide and volume-based schemes and strategic
reserves. What matters is the design of the support scheme, which can make it more or
less distortive.
Several stakeholders have proposed to address investment uncertainty by dedicated
regulatory provisions encouraging and clarifying the use of long-term contracts ('LTC's)
between generators and suppliers or consumers83
. They argue that such rules could help
mitigating the investment risk for the capital-intensive investments required in the
electricity sector, facilitating access to capital in particular for low-carbon technologies at
reasonable costs.
While mandatory LTCs may involve a risk transfer to consumers unless they are certain
they will have enduring future electricity demand, such contracts may allow them to
benefit from less volatile retail prices as electricity would be purchased long time ahead
of delivery. In terms of market functioning, it has to be stressed that current EU
electricity legislation does not discourage the conclusion of long-term electricity
purchase contracts. Even absent dedicated legislation, LTCs between a buyer and seller
to exchange electricity on negotiated terms, can anyway be freely agreed on by interested
parties without any need for further intervention by governments or regulators. Tradable
wholesale contracts are already available to market parties (albeit with limited liquidity
for contracts of more than three years84
). A dedicated framework for hedging price risks
83
See e.g. submissions to the Commission's market design consultation from a limited number of
generation companies and from energy-intensive industries.
84
See for further information, CEPS Special Report, The EU power sector needs long-term price signals,
No. 135/April 2016, page 9.
64
Problem Description
over longer terms has just been created with the EU Guideline on Forward Trading
("FCA Guidelines"). The only regulatory restriction to the use of LTCs may result, in
exceptional situations85
, from EU Treaty rules on competition law (e.g. if they are used
by by dominant companies to prevent new market entry).
It may also be noted that experience has shown that regulatory encouragement of LTCs
under EU law may also entail the risk of "lock-in risk" in the fast developing electricity
markets86
.
Options suggested to facilitate long-term contracting include (i) socialising the costs of
guaranteeing delivery of bilateral contracts (to reduce the default risk) or (ii) introducing
long-term contracts with a regulated counterparty. Both models might, however, be
considered to be capacity mechanisms and would have to be scrutinised under the
relevant State aid rules.
2.3. Problem Area III: Member States do not take sufficient account of what
happens across their borders when preparing for and managing electricity
crisis situations
In spite of best efforts to build an integrated and resilient power system, electricity crisis
situations may occur. Whilst most incidents are minor87
, the likelihood of larger-scale
incidents affecting the European electricity system might well be on the rise due to
extreme weather conditions88
, climate change (giving rise to extreme and unpredictable
weather conditions, which already today constitute a major challenge to electricity
systems)89
, fuel shortage90
and a growing exposure to cybercrime and terrorist attacks in
85
It should be noted that there is extensive guidance and case practice on the interpretation of Article 81
and 82 with respect to long-term energy contracts available.
86
The fast changing electricity markets may require different generation solutions than today (e.g. due to
new storage technology). See also the example of guaranteeing revenues for solar power producers for
timeframes ten years ago which proved to be higher than necessary in retrospective due to
technological developments.
87
In 2014 ENTSO-E identified over 1000 security of supply incidents. Most of these were minor but
there were some more serious disturbances, for example storms on 12 February 2014 leaving 250,000
homes in Ireland without power.
See: https://www.entsoe.eu/Documents/SOC%20documents/Incident_Classification_Scale/151221_ENTSO-
E_ICS_Annual_Report_2014.pdf
88
Extreme weather events are likely to affect the power supply in various ways: (i) thermal generation is
threatened by lack of cooling water (as shown e.g. in summer 2015 at the French nuclear power
stations Bugey, St. Alban and Golfech); (ii) heat waves cause high demand of air conditioning (which
e.g. resulted in price peaks in Spain in late July 2015 when occurring in parallel with low wind
output); (iii) heat waves affect grid performance in various ways, e.g. moisture accumulating in
transformers (which e.g. lead to blackouts in France on June 30th
2015) or line overheating (leading to
declaration of emergency state by the Czech grid operator CEPS on July 25th
in 2006) (source:
European Power Daily, Vol. 18, Issue 123 (2016), S&P Global, Platts).
89
"Delivering a secure electricity supply on a low carbon pathway", Energy Policy no 52. 55-59 (2013),
Boston, Andy.
90
One example proving that such risks should be taken into account is the shortage of anthracite coal in
Ukraine in June 2016 due to the political situation in Ukraine affected the rail transport of coal. As
several Ukrainian nuclear power units were offline for maintenance in parallel, the responsible
ministry called for limiting power consumption as preventive measure. (Source: European Power
Daily, Vol. 18, Issue 123 (2016), S&P Global, Platts).
65
Problem Description
Europe. Already in 2014 a series of cyberattacks by the so-called "Energetic Bear"
targeted several energy companies in Europe and US, highlighting the increasing
vulnerability of the energy sector91
.
Where crisis situations occur, they often have a cross-border effect. Even where incidents
start locally, they may rapidly proliferate across borders. Thus, a black-out in Italy in
2003 due to a tree flashover affected the electricity systems of its neighbouring states as
well, and in 2006 the tripping of an electricity line by a cruise ship in Germany affected
15 million people and had an impact on the entire continental power system92
.
Crisis situations may also affect several Member States at the same time as it was the
case during the prolonged cold spell in February 201293
, which led to a series of
uncoordinated emergency measures across Europe. Given the increasing
interconnectivity of the EU's electricity systems and linkage of electricity markets, the
risk of electricity crisis situations simultaneously affecting several Member States are set
to further rise94
.
It should be noted that risks of cross-border electricity incidents do not stop at the
European Union's borders, given increasing links between the electricity systems of EU
Member States and those of some of its neighbours (e.g., synchronisation with Western
Balkans, common infrastructure projects between e.g., Italy-Montenegro, Romania-
Moldova, Poland-Ukraine).
Given the key role of electricity to society, electricity crisis situations entail serious costs
– both economically and for the society at large95
.
91
On 23 December 2015, a cyberattack in Ukraine led to serious power cuts affecting more than 600.000
households.
92
The Italian blackout on 28/09/2003, due to a tree flashover, affected 55 million people in Italy,
Switzerland, Austria, Slovenia and Croatia. It led to a black-out situation to up to 24 hours and
interrupted energy of 17 GWh.
93
The first two weeks of February 2012 saw a prolonged colder-than-usual weather period consistently
with 12 degrees Celsius below winter average and reaching historically low temperatures exceeding 1
in 20 climatic conditions.
94
METIS simulation shows that the better integration of the markets would result in a propagation of the
stress hours across Member States. Additionally, the stress hours would be concentrated in periods
affecting simultaneously several Member States.
95
The economic impact of large scale blackouts could be estimated in billions. Thus, for instance, a
blackout in France on 26 December 1999 due to storms of unprecedented violence with devastating
effects, affected 3.5 million households (which corresponds to about 10 million people losing their
electricity supply) and entailed an economic cost of EUR 11.5 billion and interrupted energy estimated
in 400 GWh.
Recent simulations show that the damages as consequence of the power outages of 5 hours in a border
region between Belgium, France and Germany to all of the economic sectors would amount to 1
billion Euro. www.blackout-simulator.com; simulation of a blackout in following NUTS regions:
FR21 Champagne-Ardenne, FR41 Lorraine, FR42 Alsace, BE34 Prov. Luxembourg, BE35 Prov.
Namur , DEC0 Saarland, DEB Rheinland-Pfalz, FR30 Nord - Pas-de-Calais, BE32 Prov. Hainaut,
BE25 Prov. West-Vlaanderen, FR22 Picardie, BE31 Prov. Brabant Wallon, BE23 Prov. Oost-
Vlaanderen, DE1 Baden-Württemberg.
66
Problem Description
Both when preparing for and dealing with crisis situations, Member States take very
different approaches and tend to focus on their national territories and customers only,
ignoring the possible assistance of and the impact on neighbouring countries and
customers. This entails serious risks for security of supply and can also lead to undue
interferences with the internal energy market.
Driver 1: Plans and actions for dealing with electricity crisis situations focus on
2.3.1.
the national context only
First, whilst most Member States have plans to prevent and deal with electricity crisis
situations, the content and scope of these plans varies considerably and plans tend to
focus on the national situation only96
. Cross-border cooperation in the planning phase is
scarce and where it takes place at all, it is often limited to cooperation at the level of
TSOs97
. This is largely due to a regulatory failure: the existing EU legal framework does
not prescribe a common approach, and rules and structures for cross-border co-operation
are almost entirely absent98
. Cross-border cooperation is also hindered by divergent
national rules. Cooperation with Member States outside the EU is even more limited.
Further, where crisis situations do arise, Member States also tend to react on the basis of
their own national set of rules, and without taking much account of the cross-border
context. Evidence shows, for instance, that Member States have different concepts of
what an emergency situation is and entails99
, and who should do what and when in such
96
Source: Risk Preparedness Study - "Review of current national rules and practices relating to risk
preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal Network,
study prepared for DG Energy.
https://ec.europa.eu/energy/sites/ener/files/documents/DG%20ENER%20Risk%20preparedness%20fi
nal%20report%20May2016.pdf
97
There are examples of existing regional co-operation involving national authorities, e.g. among the
Nordic countries in the framework of Nord-BER (Nordic Contingency Planning and Crisis
Management Forum). However, this co-operation is mainly restricted to the exchange of best
practices.
98
See the results of the evaluation, attached as Annex VI.
99
For instance the concept of 'emergency' is not defined in all Member States and where they exist,
definitions diverge.
67
Problem Description
situations. In particular, there is considerable uncertainty and divergence as regards what
public authorities can do in emergency situations100
.
The fact that Member States tend to adopt national, 'going alone' approaches when
preparing for and managing crisis situations stands in strong contrast with the reality of
today's interconnected electricity market, where the likelihood of crisis situations
affecting several Member States at the same time, is on the rise.
Where crisis situations stretch across borders (or have the potential of doing so), joint
action is needed, as well as clear rules on who does what, and when, in a cross-border
context. Uncoordinated actions and decisions in one Member State (for instance on what
to do to prevent a further deterioration of a crisis situations or on where to shed load,
when and to whom), can have serious negative effects:
For instance, as to date, several Member States still legally foresee 'export bans'
(curtailing interconnectors) in times of crisis101
. This undermines the proper functioning
of markets and can seriously aggravate security of supply problems in neigbouring
Member States, who might no longer be able to ensure that electricity is delivered to
those that need it most. The reverse situation is also true: where in a crisis situation an
interconnected state does not restrict its own electricity consumption, it risks propagating
the crisis situation beyond its own borders.
The dangers related to a purely national, inward-looking management of electricity crisis
situations, are illustrated by an incident that occurred during a prolonged cold spell in
February 2012102
. Confronted with a situation of unexpected shortage, one Member State
100
This is for example the case of France, where the Government may "take temporary measures to
attribute or suspend exploitation authorizations of electricity infrastructures". In Portugal, the
Minister for Energy can adopt transitory and temporary safeguard measures which include the use of
fuel reserves and the imposition of demand restrictions.
101
One Member State specifically includes a legal provision on export bans in its legislation; eleven more
Member States include forms of export restrictions in national law, TSO regulations or multilateral
agreements. (Source: Risk Preparedness Study - "Review of current national rules and practices
relating to risk preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark
Legal Network, study prepared for DG Energy).
102
Another example where domestic consumption was prioritized over exports occurred in the Nordic
region over the winter 2009/2010, where the region experienced a scarcity situation (in fact a series of
them that lead to three price spikes: on December 17, January 8 and February 22) with prices reaching
1000 EUR/MWh. The initial cause was the loss of approximately 5000 MW of Swedish nuclear
capacity. Maintenance on these plants over the summer was not completed on time, and so the plants
were functioning at diminished capacity (61% of normal operating capacity, on average) into the
winter Production reached a minimum on December 18, driving prices to the technical limit. This
coincided with a winter that was already colder that average. The limited nuclear capacity continued
for a period of a few weeks, and on January 8th
was exacerbated by a reduction in transmission
capacity between Norway and Sweden to 0MW because of higher than anticipated demand in Oslo.
The Norwegian TSO, Statnett, decided to prioritise domestic consumption over exports by eliminating
the interconnector. Finally, on February 22, continued low nuclear production combined with low
hydro reservoirs in Norway led to a general state of limited generation capacity. Statnett again reduced
transmission capacity (not to 0 MW but to 150 MW) and prices were again pushed to 1000 EUR/MWh
or higher. Source: IEA (2016): Electricity Security Across Borders. Case Studies on Cross-Border
Electricity Security in Europe.
68
Problem Description
decided to resort to an export ban in an effort to protect its national consumption. This
aggravated however problems in other, neighbouring Member States, who in turn also
resorted to export bans. The ensuring cascade of export bans seriously imperiled security
of supply in an entire region of Europe103
.
Purely national approaches to crisis prevention and management can also lead to
premature (and therefore unnecessary) market interventions, such as for instance a
premature recourse to an emergency extra reserve capacity, or to a demand interruption
scheme.
Finally, different approaches to crisis prevention and management might also lead to
cases of 'under-protection. For instance, where Member States do not take the measures
needed to prevent (e.g., cyber-incidents), the entire region or even synchronous area is
likely to suffer. A similar problem might arise if Member States do not take the measures
necessary to protect assets that are critical from a security of supply perspective against
possible take-overs by foreign entities, in circumstances in which such take-overs could
lead to any undue political influence. Experience with recent take-overs (or planned take-
overs) of certain strategic energy assets in Europe shows that such risks are serious,
notably where the buyer is controlled by a third country. At this stage however, Member
States address this issue from a purely national perspective, based on national rules,104
without taking necessarily account of the wider European implications possible problems
could have. This could lead to situations wherein some Member States take foreign
ownership risks too lightly, whilst other Member States might overreact.105
Evidence shows that in an inter-connected market, stronger co-operation on how to
prevent and manage crisis situations brings clear benefits: it leads to a better security of
supply overall, at a lesser cost. The recent METIS results106
point in this direction, as
well as experiences with a few voluntary arrangements in place in parts of Europe107
.
Driver 2: Lack of information-sharing and transparency
2.3.2.
Today, national plans to prepare for crisis situations are not always public, nor shared
across Member States108
. It is not clear who will act in crisis situations, and what the
103
Export limitations were imposed by Bulgaria on 10 February, by FYROM on the 13 February, by
Bosnia Herzegovina on 14 February, by Greece on 15 February and by Romania on 16 February.
104
An increasing number of Member States adopt so called 'foreign investment screening laws', covering
notably changes of control over strategic energy assets.
105
See also the Impact Assessment accompanying the proposal for a Regulation concerning measures to
safeguard security of gas supply and repealing Council Regulation 994/2010 (SWD (2016) 25 final.
106
See Section 6.3.3. (Impact of policy Option 2).
107
For example, a co-operation agreement worked out amongst Nordic countries contains detailed
arrangements on how to deal with situations of simultaneous crisis, e.g., on curtailment sharing.
108
Nine Member States keep Risk Preparedness Plans confidential, eight make them public and eleven
others have a mixed framework with some measures being released and others being kept confidential.
(Source: Risk Preparedness Study - "Review of current national rules and practices relating to risk
preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal Network,
study prepared for DG Energy).
69
Problem Description
roles are of the different actors (governments, TSOs, DSOs, NRAs). This makes any
cross-border co-operation in times of crisis very difficult109
.
In addition, Member States do not systematically inform each other or the Commission
when they see crisis situations emerge. In fact, whilst ENTSO-E's seasonal outlooks110
already point at the likelihood of upcoming crisis situations in Europe, Member States
affected by such crisis situations do not systematically communicate on actions they
intend to take, nor on the possible effect of such actions on the functioning of the internal
market or the electricity situation in neighbouring Member States. In fact, in spite of the
fact that Member States are legally obliged to notify the Commission in case they take
'safeguard measures', such notifications have been very rare, and tend to take place ex
post (e.g., Poland in 2015)111
.
Likewise, there is no systematic exchange of information on how past crisis situations
have been handled.
Such lack of information-sharing and transparency limits the capacity of reaction of
potential Member States affected, may lead to premature interventions in the market, and
reduces the possible benefits that cooperation can bring.
In addition, even though the Electricity Coordination Group could be used as a tool to
discuss how to prevent and mitigate crisis situations112
, this does not happen in practice,
in the absence of clear and proper roles given to the group, and clear obligations on
Member States to report on how they address electricity crisis situations, both ex ante
(before incidents occur) and ex post.
109
A recent simulation of an electricity crisis situation across Europe, showed that Member States were
neither adequately equipped to deal with the crisis nor the consequences thereof, largely because it was
not clear who did what in which country on what moment (cf. results of VITEX 2016 exercise,
organized by the Dutch Ministry: https://english.nctv.nl/currenttopics/news/2016/successful-
international-exercise-vitex.aspx?cp=92&cs=38 ). VITEX 2016 is an international table top exercise
on the improvement of Critical Infrastructure Protection. The main goal of the exercise is to strengthen
the ties between EU Member States on this subject. VITEX 2016 aims to create a shared
understanding of what the Critical Infrastructures within Member States are and how European
cooperation can contribute to improve the resilience of Critical Infrastructure.
110
ENTSO-E has the obligation to carry out seasonal outlooks as required by Article 8 of the Electricity
Regulation. The assessment explores the main risks identified within a seasonal period and highlights
the possibilities for neighbouring countries to contribute to the generation/demand balance in critical
situations.
111
Poland activated a crisis protocol mid-August 2015 allowing the TSO to restrict power supplies to
large industrial consumers (load restrictions did not apply however to households and some sensitive
institutions such as hospitals). Poland notified the adoption of these measures under Article 42 of the
Electricity Directive one month after.
112
According to Article 2 of Commission Decision of 15 November 2012 setting up the Electricity
Coordination Group, the Group shall in particular "promote the exchange of information, prevention
and coordinated action in case of an emergency within the Union and with third countries".
70
Problem Description
Driver 3: No common approach to identifying and assessing risks
2.3.3.
Whilst all Member States identify and assess risks that can affect security of supply, there
are many different understandings of what constitutes a 'risk' and methods for assessing
and addressing such risks vary considerably.
Different risks are assessed in different ways113
, by different people114
, and in different
time horizons115
.
There is also no common agreement on what indicators to use to assess security of
supply overall116
.
In the absence of a common approach to risk identification and assessment, it is difficult
to get an exact picture of what risks are likely to occur, in a cross-border context. This, in
turn, seriously hampers the possibility for relevant actors – TSOs, NRAs, Member States
– to prevent and manage crisis situations in a cross-border context.
2.4. Problem Area IV: The slow deployment of new services, low levels of service
and questionable market performance on retail markets
Retail markets for energy in most parts of the EU suffer from persistently low levels of
competition and consumer engagement. In addition, whilst information technology now
offers the possibility of greatly improving the consumer experience and making the
market more contestable, realising these benefits could be hampered by the lack of a
data-management framework that unlocks the full benefits of smart energy management
to all market actors – incumbents and new entrants alike.
113
There exists a patchwork of types of risks covered under the assessments in the Member States. The
level of detail in which the types of risks are described varies and a high level of detail was found in
three Member States. In five Member States the types of risks to be assessed are not or very generally
described. (Source: Risk Preparedness Study - "Review of current national rules and practices relating
to risk preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal
Network, study prepared for DG Energy).
114
The combination of national entities (TSOs, the competent Ministries, the NRAs and the DSOs)
responsible for risk assessment and the division of their roles, which are often defined by law, vary
across the Member States. TSOs play a major role in the assessment of risks in a majority of the
countries. (Source: Risk Preparedness Study - "Review of current national rules and practices relating
to risk preparedness in the area of security of electricity supply" (2016), VVA Europe, Spark Legal
Network, study prepared for DG Energy).
115
Time horizons covered can vary from one year to fifteen years. Moreover, some Member States set no
limits of validity for their measures, others have a system of continuous updates whist at least eleven
countries do not specify time horizons. (Source: Risk Preparedness Study - "Review of current
national rules and practices relating to risk preparedness in the area of security of electricity supply"
(2016), VVA Europe, Spark Legal Network, study prepared for DG Energy).
116
A wide variety of metrics and methodologies to assess security of supply and system adequacy is used,
but there is no specific reference to an economic value of adequacy (in particular to VOLL). Several
Member States have established standards, generally in terms of LOLE targets. However, information
is lacking on the criteria (if any) used to establish those standards. Metrics and standards have been set
through subjective decision, despite the evident fact that setting a standard (and the generation or
transmission capacity necessary to achieve that standard) will have an economic impact on consumers.
(Source: "Identification of Appropriate Generation and System Adequacy Standards for the Internal
Electricity Market" (2016), AF Mercados, E-Bridge, REF-Em, study prepared for DG Energy).
71
Problem Description
These closely inter-related issues result in the slow deployment of innovative products
that would help to make the electricity system function better in today's changing
context, as well as excessive prices for some end-consumers and/or poor levels of
service.
R&D results: Retail level innovative products and services such as dynamic pricing, self-consumption
incentives, and local flexibility and energy markets, have been tested in European projects, EEPOS,
ECOGRID-EU, Grid4EU, INTrEPID, INCREASE, DREAM, Integral117
.
For example, ECOGRID-EU showed that the highest cost is in the installation of the automation
technologies, control systems and sensors in the household. These costs could be virtually zero in the
future when appliances are connected anyway.
Integral states that large scale implementation of demand-side response services based on a market for
flexibility requires standardised solutions (for the communication of the devices (smart meters and devices
controllers…) and for the framework within which market players communicate to each other) to reduce
the cost per household and to lower the price of the smart energy services.
Driver 1: Low levels of competition on retail markets
2.4.1.
Competition on retail markets is multifaceted, and recent trends in several indicators
suggest that it can be improved in many Member States.
The price of energy for end consumer can be broken down into three main components:
i) energy, ii) network and iii) taxes and levies. The energy component typically includes
cost elements such as the wholesale price of the commodity and various costs of the
supply companies, including their operating costs and profit margins. The network
component mainly consists of transmission and distribution tariffs. It might also include
further cost elements such as ancillary services. The taxes & levies component includes a
wide range of cost elements that significantly vary from country to country. Levies are
typically designated to specific technology, market or socially bound policies, while
taxes are general fiscal instruments feeding into the state budget. On average in the EU in
2015 energy made up 36% of the final household consumer price, the network
component 26%, and taxes and levies 38%.
117
A list of the research and development projects mentioned in this box and their findings relevant to the
present impact assessment is provided in Annex 8.
72
Problem Description
In spite of falling prices on wholesale markets (analysed earlier), overall electricity prices
for household consumers rose steadily between 2008 and 2015 at an annual rate of
around 3%. This trend was largely driven by increased network charges, taxes and
levies118
, the various causes of which have been touched upon in the preceeding sections:
the over reliance of RES E assets on government support due to barriers to fully
participating in all markets; inflexible distribution networks that increase the cost of
integrating RES E; and fragmented balancing markets that increase the costs of ancillary
services, amongst others.
However, a proxy for mark-ups119
on the energy component of consumer bills in several
Member States also seem to be higher than could be expected, posing questions about the
extent of price competition. Indeed, whereas there has been a significant reduction in
wholesale prices between 2008 and 2015, the nominal level of the energy component of
household electricity bills actually increased in 13 Member States during this period120
.
In these countries, the fall in wholesale prices has not translated into a reduction in the
energy component of retail prices despite the fact that this is the part of the energy bill
(representing around 36% of average household prices) where energy suppliers should be
able to compete.
118
The average network component in consumer bills has increased by 25% since 2008, and cost EU
households 5.45 euro cents per kWh in 2015. Taxes and levies increased by 70% in the same period,
and stood at 7.92 euro cents per kWh in 2015. Energy taxation is not fully harmonized at the EU-level.
Source: DG ENER data.
119
As defined in "Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015, pp. 288-295. This proxy essentially measures the relationship between the
wholesale price and the energy component of the retail price. However, other factors apart from the
mark-up may affect this relationship, notably including a higher proportion of fixed charges in
wholesale prices.
120
DG ENER Data.
73
Problem Description
Figure 5: Relationship between the wholesale price and the energy component of the
retail price in household segments in countries with non-regulated retail prices from
2008 to 2014 for electricity and from 2012 to 2014 in gas (EUR/MWh)
Source: ACER Database, Eurostat, NRAs and European power exchanges data (2014) and ACER
calculations. Note: Gas data are available only for the period 2012-2014.
Abnormally low mark-ups are equally problematic as they make it difficult or impossible
for a new supplier to compete against an incumbent. A reasonable mark-up is necessary
for a new entrant to cover consumer acquisition and retention costs which are higher than
those of the incumbent who usually retains the most loyal (‘sticky’) customers. Mark-ups
that are too low and low levels of competition can be observed in several markets with
regulated prices (developed further on the next page)121
.
As for non-price competition, whilst sampling data from European capitals suggest that
'choice' for consumers in European capitals widened in recent years, a closer inspection
reveals that this has largely been driven by just two products – 'green' and dual-fuel
(electricity + gas) tariffs122
. The offer and uptake of other, more innovative consumer
products, such as aggregation services or dynamic price tariffs linked to wholesale
markets123
, remains limited.
Facilitating competition can be seen as means of improving consumer satisfaction.
However, the data indicate that there is clearly scope for improvement in this dimension,
too. According to the 2016 edition of the Commission's Consumer Scoreboard – a
comprehensive study measuring consumer conditions – electricity services rank 26th
and
gas services 14th
among the 29 markets for services across the EU. Indeed, the total
detriment to EU electricity consumers124
has recently been quantified at over EUR 5
121
Based on Annex 5, "Market Monitoring Report 2014" (2015) ACER and VaasaETT 2015
122
Source: ACER database.
123
See also the evaluation as regards Demand Response.
124
Consumer detriment involves consumers suffering harm or damage. Research for the Commission has
suggested the following two definitions of consumer detriment, for use in different policy contexts:
74
Problem Description
billion annually125
. Both markets can therefore be considered low performing from the
consumer standpoint.
High levels of market concentration also suggest that competition could be improved:
The cumulative market share of the three largest household suppliers (CR3) is greater
than 70% in 21 out of 28 Member States for electricity and in 20 out of 28 Member
States for gas. CR3 values above 70% are indicative of possible competition problems.
Also significant is the fact that some form of non-targeted price regulation for electricity
and/or gas still exists in 17 out of 28 Member States126
. The regulation of electricity and
gas prices may result in an environment that strongly impairs healthy competition,
particularly in terms of the level of customer service, or the development and provision
of innovative new services that consumers would be willing to pay extra for. Reliance on
the government to set prices can result in consumer disengagement. In addition,
regulatory intervention in price setting can have a direct impact on suppliers' ability to
offer products that are differentiated in terms of pricing-related aspects – dynamic price
tariffs that reflect the minute-by-minute fluctuations on wholesale markets, for example.
When justifying price regulation Member States cite the need to protect the vulnerable
and energy poor along with the need to protect all customers against the risk of market
abuse. Around 10.2% of the EU population might be affected by the problem of energy
poverty, based on a proxy indicator measuring "the inability to keep home adequately
warm"127
. If energy prices continue to increase, it is likely that energy poverty across the
EU will increase and therefore more pressure to maintain energy price regulation.
Under the existing provisions in the Electricity and Gas Directive, Member States have to
address energy poverty where identified. The evaluation of the provisions found
important shortcomings stemming from the unclarity of the term energy poverty,
particularly in relation to consumer vulnerability, and the lack of transparency with
regards to the number of households suffering from energy poverty across Member
States.
Addressing the issue of energy poverty through blanket price regulation can be
disproportionate as it affects all consumers big or small, rich or poor. It can also lead to a
1. Personal detriment — negative outcomes for individual consumers, relative to reasonable
expectations.
2. Structural detriment — the loss of consumer welfare (measured by consumer surplus) due to market
failure or regulatory failure.
"An analysis of the issue of consumer detriment and the most appropriate methodologies to estimate it;
Final report for DG SANCO by Europe Economics” (2006) Europe Economics.
125
Sum of total post-redress financial detriment & monetised time loss. "Study on measuring consumer
detriment in the European Union" (2016) Civic Consulting,
126
This figure is comprised of Member States which regulate both electricity and gas prices, as well as
Member States which regulate exclusively gas or electricity prices. In addition, Commission classifies
Italy as having regulated electricity prices whereas ACER does not in their "Market Monitoring report
2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015, pp 88-96,
127
The indicator is measured as part of the Eurostat Survey on Income and Living Conditions (EU-SILC).
75
Problem Description
chicken-and-egg problem whereby price regulation leads to distortions to the market and
low competition, which are in turn used to justify the continuation of price regulation.
Resolving this impasse would allow one of the most fundamental aspects of the market –
the price mechanism – to function properly.
ACER's Retail Competition Index – a composite indicator that draws upon many of the
abovementioned statistics, as well as others128
– was developed to achieve a full picture
of retail market competitiveness which is not dependent on a single indicator. It
illustrates the disparities in retail markets that still exist between Member States, and
clearly suggests that competition can be improved in a number of them (see Graph 3).
Figure 6: ACER Retail Competition Index (ARCI) for electricity household markets
in 2014
Source: ACER
Driver 2: Possible conflicts of interest between market actors that manage and
2.4.2.
handle data
High levels of information asymmetry (between incumbents and potential entrants) and
high transaction costs impede competition and the provision of high levels of service on
retail markets for energy.
128
1) Concentration ratio, CR3; 2) Number of suppliers with market share > 5%; 3) ability to compare
prices easily; 4) average net entry (2012-2014); 5) switching rates (supplier + tariff switching) over
2010-2014; 6) non-switchers; 7) number of offers per supplier; 8) measure of whether the market
meets consumer expectations; 9) average mark-up (2012–2014) adjusted for proportion of consumers
on non-regulated prices.
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Problem Description
For example, studies from NRAs cite discriminatory access to information on potential
customers as a key barrier for new entrants to EU retail energy markets (Box 1 below).
As most DSOs are also energy suppliers, safeguards are necessary to prevent them using
privileged access to consumer data – especially smart metering data – to gain a
competitive advantage in their supply operations.
In addition, "unjustified" or "incorrect" invoices are one of the largest sources of
electricity and gas consumer complaints reported to the Commission129
– an issue that
can be largely resolved if accurate metering information were made quickly and readily
available to suppliers and consumers.
Information technology could directly address these issues, making the market more
contestable, facilitating the development of new services and improving the customer
experience around day-to-day operations such as billing and switching. Although 80% of
EU consumers should have smart meters by 2020, the experience from Member States
that have already rolled them out indicates that robust rules are necessary to ensure the
full benefits of smart metering data are realised, and that data privacy is respected. Such
rules, however, are not fully developed in the existing EU legislation, and the diverse
interests of market actors who may be involved in data handling mean that they are
unlikely to emerge without regulatory intervention.
129
These made up around 10% of all electricity and gas complaints. Source: European Consumer
Complaints Registration System.
77
Problem Description
Box 1: Data management as a market entry barrier130
Data management comprises the processes by which data is sourced, validated, stored,
protected and processed and by which it can be accessed by suppliers or customers
The necessity to adapt to different data management models for each market can have an
impact on the resources of the potential market newcomers. Non-discriminatory and
smooth accessibility of data is naturally most important during the pre-contractual phase
as well as for running contractual situations. The fact that not all countries have rolled
out smart meters yet also creates significant differences in the availability and
accessibility of data.
A standardised approach to the provision and exchange of data creates a level playing
field among stakeholders and helps to encourage new challenging market actors to enter
a new market.
Driver 3: Low levels of consumer engagement
2.4.3.
Consumer engagement is essential for the proper functioning of the market. As such, it is
closely inter related with competition (Driver 1). However, consumers are also put-off
from engaging in the market by behavioural biases and bounded rationality that make it
harder for them to take the decision to search for, and to switch to, the best offer.
In particular, three key barriers to consumer engagement have been identified. First, the
broad variety of fees that consumers may be charged when they switch diminishes the
(perceived) financial gains of moving to a cheaper tariff in what is already a marginal
decision for many consumers. The evidence suggests around 20% of electricity
consumers in the EU currently face a fee of between EUR 5 and EUR 90 associated with
switching suppliers. A portion of those fees – affecting around 4% of consumers – may
be illegal under existing EU legislation (see Section 2.6.2).
Secondly, whereas online comparison websites play an important role in helping
consumers to make an informed decision about switching suppliers, recent reports of
unscrupulous practices have damaged consumer trust in them. Identified issues include
the default presentation of deals by some websites, the use of misleading language, and a
lack of transparency about commission arrangements. Indeed, a third of respondents to a
recent EU survey somewhat or strongly agreed that they did not trust comparison
websites because they were not impartial and independenct.131
130
Adapted from: CEER Benchmarking report on removing barriers to entry for energy suppliers in EU
retail energy markets, (2016) p. 19,
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/tab6/C15-RMF-70-03_BR_barriers_to_entry_for_suppliers_1-Apr-2016.pdf. See also VaasaETT
(2014), ' Market Entrant Processes, Hurdles and Ideas for Change in the Nordic Energy Market', p.22,
http://www.nordicenergyregulators.org/wp-content/uploads/2014/12/VaasaETT-Report-
Market_Entry_Barriers.pdf.
131
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, pp. xix, 191.
78
Problem Description
And thirdly, consumer groups report that consumers have difficulties understanding their
energy bills and comparing offers in spite of existing EU legislation aiming to facilitate
this. There is a broad divergence in national requirements around billing and consumer
satisfaction with their bills varies significantly between different Member States.
Whereas energy bills are the foremost means through which suppliers communicate with
their customers, consumers' inability to correctly answer simple questions about their
own electricity use reveals that bills are not effective in providing information that could
facilitate effective consumer choice.132
Addressing this will be increasingly important
with the shift to more varied consumer products.
R&D results: The project S3C has developed a toolkit for the active engagement of end users and
identifies improvements to the way and content of the communication of energy system actors with
customers and citizens.
2.5. What is the EU dimension of the problem?
The EU's electricity market is strongly integrated physically, economically and from a
regulatory point of view. The discretion of Member States to act individually has been
substantially reduced by the resulting interdependencies and, in fact, can create
significant externalities if not adequately framed within an EU-wide context.
RES E deployment is expected to increase in all Member States. The need to spur the
emergence of a more flexible electricity system thus exists EU-wide. Moreover, as the
EU electricity system is both physically and economically integrated, non-coordinated
action is likely to increase the costs of RES E integration.
The same applies to CMs where the externalities of non-coordinated action are one of the
underlying reasons for the proposed measures. It is true that not all Member States have
enacted CMs, however the benefits of a more coordinated approach will benefit all
Member States. Member States that have implemented a CM will be able to lower their
costs by increased cross-border competition whereas the avoidance of negative spill-over
effects will benefit all Member States regardless as to whether they enacted a CM or not.
In an integrated electricity market, considering the prevention and management of
electricity crisis a purely national issue leads to serious problems. Where crisis situations
occur, they often have a cross-border effect, and can entail serious adverse consequences
for the EU as a whole. Evidence shows that non-coordinated approaches to preventing
and managing electricity crisis may seriously distort the internal electricity market and
put at risk the security of supply of neighbouring Member States.
Well designed and implemented consumer policies with a European dimension can
enable consumers to make informed choices that reward them through healthy
competition, and support the European goal of sustainable and resource-efficient growth,
whilst taking account of the needs of all consumers. Increasing confidence and ensuring
that unfair trading practices do not bring a competitive advantage will also have a
132
For example, less than one third of consumers recently surveyed strongly agreed that they knew what
kind of a contract they currently had (fixed price, variable price, green, etc.).
79
Problem Description
positive impact in terms of stimulating growth. The consumer-related measures
undertaken as part of this initiative therefore play an essential role in the establishment
and functioning of the internal market.
2.6. How would the problem evolve, all things being equal?
The projected development of the current regulatory framework
2.6.1.
In the absence of additional measures, the electricity market would continue to be
governed by the Third Package and the Electricity Security of Supply Directive. Various
network codes may still be adopted and implemented133
, such as the draft Network Code
on Emergency and Restoration and the Balancing Guideline. Whilst these network codes
will help address some of the issues identified above, they will not offer a sufficient
remedy on their own.
Solving the above-identified problems requires measures that cannot be addressed in the
current legal framework. As the network codes constitute secondary implementing
legislation designed to amend non-essential elements of the Third Package by
supplementing it, their scope is confined to the same limits drawn by the Third Package
and hence, developing new network codes cannot be expected to provide for adequate
solutions either.
In view of the fact that the proposals in essence develop new areas for which currently no
clear legal basis exist in the Third Package or in the Electricity Security of Supply
Directive, stronger enforcement is not an option either (with some limited exceptions,
which are further developed below).
Member States have developed forms of voluntary collaboration that attempt to address
some of the problems identified. However, these initiatives cannot be expected to resolve
all problems and with the same effectiveness as EU action (See also EU value added).
Regarding security of supply in particular, both the evaluation and the results of the
public consultation clearly show that Directive 2009/89 is outdated. It does not take
account of the current, fast evolving situation of the electricity market. And it offers no
framework for coordinating national policies in the area of security of electricity supply.
With regards to consumer issues, the Commission may develop guidance to tackle
implementation issues caused by difficulties in interpreting the existing legislation. In
particular, it may issue an interpretative note on the existing provisions in the Electricity
and Gas Directives covering switching-related fees, as well as further guidance on how
the dozen or so consumer Directives relevant to comparison tools should be applied.
On energy poverty, the Commission will already set up the EU Energy Poverty
Observatory using funds already secured from the European Parliament. However, the
extent to which the Observatory continues to share good practices and improve data
gathering is uncertain, as continued funding is not secured beyond the first year of
133
For a full overview of network codes, see Annex VII.
80
Problem Description
operation. Moreover, the impact of this measure may be limited as the current legislation
does not require Member States to measure energy poverty and hence to address it.
Expected evolution of the problems under the current regulatory framework
2.6.2.
Both this and the impact assessment for the parallel RED II initiative come to the
conclusion that the electricity market, provided that it is improved, together with
projected CO2 prices, may deliver investments in most mature low-carbon technologies
such as solar PV and onshore wind by 2030. However, in the absence of a market
optimised for increasing levels of renewable penetration, achieving the 2030 objectives
will only be possible at significantly higher costs.
In the absence of a better defined framework for government interventions, the current
trend of non-coordinated implementation of national resource adequacy measures risks
proliferating, undermining the efficiency of the market to deliver efficient production and
investment decisions and defragmenting its regulatory framework.
In fact, in the absence of measures that will improve investment incentives and efficient
market functioning, it is likely that more Member States will have to take recourse to
means other than the market to secure sufficient investments for resource adequacy
purposes, setting in motion a negative spiral in which government interventions increase
the need for the subsequent one.
Failing to integrate all participants in the market means that their decisions will not be
guided by market signals, entailing the risks that their investment and production
decisions will be sub-optimal from a welfare perspective, if not distort markets.
In addition, in the absence of a clear framework for co-ordinated action between Member
States when it comes to preventing and managing crisis situations, the EU's electricity
system risks being increasingly exposed to risks of serious incidents, without the EU or
its Member States having any means to properly tackle them. There is a real risk that
Member States will continue to do as they see fit in crisis situations, thus undermining
the proper functioning of the internal electricity market.
Regarding active consumer engagement, Member States have committed to deploying
smart meters to around two thirds of the population while access to innovative services
such as demand response or in the area of self generation remains limited in many
Member States. Individual action by Member States would perpetuate current differences
in the Union regarding consumer awareness, choice and access to dynamic prices,
demand response and integrated smart services. Consumer-friendly functionalities would
be taken up partially and the flexibility consumers can provide to the electricty system
would remain largely untapped.
With regards to consumer protection and engagement, enforcement could help diminish
the illegal switching-related costs currently faced by an estimated 4% of all EU
electricity consumers. And some Member States may also voluntarily cease or reduce
excessive regulatory interventions in price-setting as their retail markets mature.
However, shortcomings in the existing legislation will greatly limit the Commission's
ability to tackle these and other consumer-related problem drivers more effectively.
The issue of energy poverty is likely to remain relevant. Pressure on energy prices may
continue as a result of the efforts to decarbonise the energy system. If energy prices grow
81
Problem Description
faster than household income, more and more households will find it difficult to pay their
energy bills. This may have a knock-on effect on Member States willingness to lift price
regulation which will ultimately impact suppliers' ability to innovate, competition and
consumer welfare. Thus, the greater the importance of enhanced transparency to estimate
the number of energy poor households.
And whilst many Member States may seek to ensure the neutral, expedient, and secure
management of consumer data, it is highly likely that national requirements will vary
significantly, leading to an uneven playing field for new suppliers and energy service
companies in the EU. Here, the only credible approach to effectively tackling the
potential conflicts of interest among market actors is a legislative one.
2.7. Issues identified in the evaluation of the Third Package
A retrospective evaluation was carried out in parallel with the present impact assessment
and has been added as Annex VI. Its main conclusions are:
- That the initiative of the Third Package to further increase competition and to
remove obstacles to cross-border competition in electricity markets has generally
been effective and that active enforcement of the legislation has led to positive
results for electricity markets and consumers. Markets are in general less
concentrated and more integrated than in 2009. As regards retail markets, the set
of new consumer rights introduced by the Third Energy Package have clearly
improved the position of consumer in energy markets.
- However, the success of the rules of the Third Package in developing the internal
electricity market further to the benefit of customers remains limited in a number
of fields concerning wholesale and retail electricity markets.
- Moreover, while the principles of the Third Package achieved its main purposes
(e.g. more supplier competition), new developments in electricity markets such as
the increase of RES E, the increase of state interventions into the electricity
markets and the changes taking place on the technological side have led to
significant changes in the market functioning in the last five years and have
dampened the positive effect of the reforms for customers. There is a gap in the
existing legislation regarding how to deal with these developments.
The conclusions of the evalution are also reflected in section 3 of each of the Annexes
1.1 throught to 7.6 to the present impact assessment.
82
Subsidiarity
3. SUBSIDIARITY
3.1. The EU's right to act
In order to create an internal energy market, the EU has adopted three consecutive
packages of measures between 1996 and 2009 aiming at the integration and liberalisation
of the national electricity and gas markets and addressing a wide range of elements such
as market access, the improvement of the level playing field, transparency, increased
rights for consumers, stronger independence of regulatory authorities, etc. In
February 2011, the European Council set the objective of completing the internal energy
market by 2014 and of developing interconnections to put an end to any isolation of
Member States from the European gas and electricity grids by 2015. In June 2016, the
European Council called for Single Market strategies, including on energy, and action
plans to be proposed by the Commission and to be completed and implemented by 2018.
Article 194 of the Treaty on the Functioning of the European Union ('TFEU')
consolidated and clarified the competences of the EU in the field of energy. According to
Article 194 TFEU, the main aims of the EU’s energy policy are to: ensure the
functioning of the energy market; ensure security of energy supply in the Union; promote
energy efficiency and energy saving and the development of new and renewable forms of
energy; and promote the interconnection of energy networks.
The planned measures of the present intiative further progress towards the objective of
improving the conditions for competition by improving the level playing field, while at
the same time adjusting to the decarbonisation targets and enhancing the solidarity
between Member States in relation to security of supply.
Therefore, Article 194 TFEU is the legal basis of the current proposal.
3.2. Why could Member States not achieve the objectives of the proposed action
sufficiently by themselves?
The section below provides a high-level summary of the necessity of EU action, based on
the four problem areas identified in section 2.
The issue of subsidiarity is also discussed in section 6 of Annexes 1.1 to 7.6 to the
present impact assessment.
As regards the issue concerning a market design that is not fit for taking up large
amounts of variable, decentralised electricity generation and allowing for new technical
developments, it is important to note that EU action is necessary to ensure that national
markets are comparable in order to improve the functioning of the internal electricity
market and enable maximum cross-border trading to happen. EU-action is also necessary
in order to enhance the transparency in the functioning of the electricity markets and
avoid discrimination between market parties. Moreover, a number of the measures
proposed to address this issue (e.g., measures for the common sizing and procurement of
balancing reserves) require full cooperation of neighbouring TSOs and NRAs, and hence
individual Member States might not be able to deliver a workable system or might only
provide suboptimal solutions. Moreover, existing provisions under the Third Package are
arguably not sufficiently clear and robust and their implementation of such rules has
highlighted areas with room for improvement and hence EU action will be necessary to
address the identified shortcomings.
83
Subsidiarity
With specific respect to DSOs, distribution grids will have to integrate even greater
amounts of RES E generation in the future, and so ensuring all DSOs can efficiently
manage their networks will help to reduce distribution costs and thereby support the
achievement of EU RES targets. In addition, widely divergent distribution tariff regimes
may affect the development of the internal energy market as they affect the conditions
under which RES E generation or other resources can access the grid and participate in
the national and cross-border energy markets. EU action in these areas would thereby
facilitate the deployment of RES E and create a level playing field for flexibility services
such as demand response by ensuring a coherent approach by Member States based on
common principles. Developing this through independent Member State action would
not be feasible given the heterogeneity of current national networks and regulations.
Concerning the uncertainty about future investments in generation capacity and
uncoordinated government interventions, the measures in the proposed initiative aim at
improving the functioning of the electricity markets and at improving the coordination
between Member States for capacity mechanisms. The necessity of EU action derives
from the fact that as regards the measures for improving the functioning of the electricity
markets, these are already covered by EU legislation, although not sufficiently clearly,
and therefore an amendment to such measures to address the distortions and deficiencies
identified would require EU action. For the measures concerning the improvement of the
coordination between Member States for capacity mechanisms, given that the aim is to
address the shortcomings identified from resource adequacy assessments carried out at
national level and to develop the cross-border participation in capacity mechanisms, the
EU is best placed to provide for a harmonised framework.
In relation to the problem that Member States do not take into account of what happens
across their borders when preparing for and managing electricity crisis situations, the
necessity of EU action is based on the evidence that uncoordinated national approaches
not only lead to the adoption of suboptimal measures but that they also make the impacts
of a crisis more accute. Given the interdependency between the electricity systems of
Member States, the risk of a blackout is not confined to national boundaries and could
directly or indirectly affect several Member States. Therefore, the actions concerning
preparedness and mitigation of crisis situations cannot be defined only nationally, given
the potential impact on the level of security of supply of a neighboring Member State
and/or on the availability of measures to tackle scarcity situations.
Regarding the slow deployment of new services, low quality of services and increasing
mark-ups on retail markets, there is a clear need for EU action to ensure convergence of
national rules, which is a precondition for the development of cross-border activity in the
retail markets. Moreover, national regulations have in some instances led to distortions,
weakening the internal energy market. Such distortions can be observed in relation to the
protection of vulnerable and energy poor consumers which is a policy area characterised
by a great variety in types of public internvention across Member States, both in terms of
the definitions used and in terms of the levels of protection established. In that case EU
action is justified not only to ensure customer protection and enhanced transparency but
also to improve the functioning of the internal market through a more cohesive approach
across all markets.
84
Subsidiarity
3.3. Added-value of action at EU-level
The initiative aims at amending existing EU legislation and at creating new frameworks
for cross-border cooperation, which can legally and practically only be achieved at the
European level.
National policy interventions in the electricity sector have direct impact on neighbouring
Member States. This even more than in the past as the increasing cross-border trade, the
spread of decentralised generation and more enhanced consumer participation increases
spill-over effects. No state can effectively act alone and the externalities of unilateral
action have become more important.
To illustrate, uncoordinated national policies for distribution tariffs may distort the
internal market for distributed resources such as distributed generation or storage, as such
resources will increasingly participate in energy markets and provide ancillary services to
the system, including across borders. Furthermore, the lack of appropriate incentives for
DSOs may slow down the integration of RES E, and the uptake of innovative
technologies and energy services. EU action therefore has significant added value by
ensuring a coherent approach in all Member States.
It is true that certain Member States collaborate on a voluntarily basis in order to address
certain of the identified problems (e.g. Pentalateral Energy Forum –PLEF-, CEEE).
However, these fora are characterised by different levels of ambition and effectiveness
and are held-back by the fact that no means exist to enforce agreements on market design
related arrangements. Moreover, even if one would presume that they would be fully
effective in these regards, they geographically cover only part of the EU electricity
market.
It should be added that clear synergies exist between the present initiative and other EU
policy objectives, notably the EU's climate policies and other policy objectives in the
energy field. Indeed, a well-functioning market is the base upon which the ETS can most
efficiently deliver its goals and will permit a cost effective integration of RES E in the
EU's electricity markets.
Consequently, the objectives of this initiative cannot be achieved only by Member States
themselves and this is where action at EU-level provides an added value.
85
Objectives
4. OBJECTIVES
4.1. Objectives and sub-objectives of the present initiative
86
Objectives
4.2. Consistency of objectives with other EU policies
The consistency of the present initiative with various parallel initiatives in the energy
policy area was already explored in section 1.2.
The ETS constitutes a cornerstone of the European Union's policy to combat climate
change and its key tool for reducing industrial and electricity sector greenhouse gas
emissions cost-effectively. To achieve the at least 40% greenhouse gas emission
reduction target, the sectors covered by the ETS, which includes electricity generation,
have to reduce their emissions by 43% compared to 2005. The ETS interacts with the
electricity markets as it places a price on emissions of CO2, which is proportional to the
emissions' intensity of electricity production. This can be taken into account for both
operational decisions as well as for investment decisions, in which price expectations for
the future will also play a larger role due to the long-term nature of investments in the
electricity sector. (By contrast, decommissioning decisions may be primarily driven by
short-term considerations relating primarily to operational costs and revenues). The ETS
thus functions by affecting production and investment decision of electricity market
actors134
. It follows that an ETS can only function if its is complemented by an efficient
electricity market is. The objectives of the ETS and the present proposals are hence
complementary to one another and mutually reinforcing.
The Effort Sharing Decision establishes binding annual greenhouse gas emissions for
Member States for the period 2013-2020 in sectors not covered by the ETS and forms
part of the climate and energy package. As part of the 2030 climate and energy
framework, a similar binding emission reduction framework is proposed for the period
2021-2030. Reducing greenhouse gas emissions by 30% in effort sharing sectors below
2005 levels can have an indirect impact on the projection for the demand of electricity in
2030 and this has been taken into account in the Impact Assessment by using the
EUCO27 scenario in the baseline against which the impacts of the present initiative is
being assessed.
The Communication on the decarbonisation of transport in 2030 aims at setting out a
strategy covering several legislative and non-regulatory initiatives covering the transport
sector which will be subsequently proposed to contribute to meeting the agreed 2030
greenhouse gas reduction targets. The decarbonisation of transport in 2030 has an impact
on the projection for the demand of electricity in 2030, primarily via the electrification of
transport, and this has been taken into account in the Impact Assessment by using the
EUCO27 scenario in the baseline against which the impacts of the present initiative is
being assessed. The efficient integration of electric vehicles into the electricity system
134
The existing imbalance between the supply and demand for ETS allowances has limited the impact of
the carbon price in recent years. However, the agreement in 2014 to postpone the auctioning of 900
million allowances, and the decision in 2015 to introduce a Market Stability Reserve from 2019
onwards, as well as the proposal to revise the EU ETS, including a higher annual reduction to the
number of allowances in the ETS from 2021 onwards, will gradually address the surplus of
allowances. With the introduction of the auctioning of allowances as the default method of allocation
for installations in the power sector from 2013 onwards and a single EU wide limit or cap on the
overall number of allowances in the system, the EU ETS already provides a largely harmonised
incentive for decarbonisation at EU level.
87
Objectives
requires incentivising their charging to take place at times of low electricity demand
and/or high supply. The present initiative aims at enabling and rewarding consumers to
manage their consumption, including when charging their electric vehicles, actively via
demand response thus enabling smart charging. In essence, electric vehicles will thus
become part of the supply of flexibility to the electricity system.
EU's competition instruments and, in particular, the EU state aid rules are applicable to
the energy sector. They have been clarified in the Guidelines on State aid for
environmental protection and energy 2014-2020135
. These EEAG aim at supporting
Member States in reaching their 2020 targets while addressing the market distortions that
may result from subsidies granted to RES. To this end, the EEAG promote a gradual
move to market-based support for RES E. They also include provisions on aid to energy
infrastructure and rules on aid to secure adequate electricity capacity, allowing Member
States to introduce CMs when there is a real risk of insufficient electricity generation
capacity. The objectives and the rules of the EEAG are set to avoid undue competition
distortions from national support provided in the energy sector. The proposed initiative to
strenghten efficient, integrated and functioning electricity markets is complementary to
this framework.
The existing EEAG already go a considerable way in guiding CMs. The present initiaitve
intends to complement this framework. For instance:
- The EEAG require that state intervention in support of resource adequacy must be
necessary. The MDI impact assessment136
thus explores options for creating a
robust framework for assessing the EU's adequacy situation which could give a
good sense how much intermittent renewables can contribute to security of supply
or to what extent Member States can rely on supplies from their neighbours.
Today, Member States introduce capacity mechanisms based on national reports
which assess these factors very differently and underestimate the contribution of
RES E or foreign supplies to a Member States' security of supply. Therefore a
genuine and high quality assessment which will help assessing real needs and
question unfounded national claims.
- The EEAG already require that national capacity markets are open to foreign
resources. However, organising effective foreign participation in national
mechanism requires active contributions of several parties. The MDI impact
assessment137
explores options for defining clear roles and responsibilities to
capacity providers, transmission system operators and regulators so that foreign
participation becomes effective and that investment incentives are not distorted
across the borders.
The proposed changes on the new performance based remuneration framework for DSOs
would also support the Digital Single Market Strategy in the sense that those would
provide further incentives to enable cross sector synergies in electronic communication
infrastructure deployment allowing win win solutions for the cost efficient and timely
135
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A52014XC0628(01)
136
See the preferred option in problem area II
137
See the preferred option in problem area II
88
Objectives
smartening of grids and high speed connectivity for EU citizens, also decreasing the
digital divide and providing the backbone for digital products and services which have
the potential to support all aspects of the lives of EU citizens, and drive Europe's
economic recovery. The proposed measures would complement from the energy
regulatory side the measures already introduced with Directive 2014/61/EU which aims
at reducing the cost of high speed broadband infrastructure deployment partly via cross
sector synergies.
The proposed measures do in general have no interaction with the fundamental rights laid
down in the Charter of Fundamental Rights, with the exception of the processing of
personal data and improvement of consumer protection. These elements are discussed in
more detail in section 6.4.6, Annex 7.1 and Annex 7.3.
The New Skills Agenda for Europe focuses on skills as an elevator to people's
employability and prosperity, in line with the objective of a "social triple-A" for Europe.
It will promote life-long investment in people, from vocational training and higher
education through to digital and high-tech expertise and the life skills needed for citizens'
active engagement in changing workplaces and societies. The energy transition will bring
significant shifts in employment and skill sets required for employees active in the
energy sector as traditional means of generation will be replaced by RES E. This
transition is however primarily driven by EE and RED II related measures as well as
national choices as to the generation mix. More relevant for the present initiative are the
measures aiming at inducing the development of the retail markets from electricity
supply markets towards including more service oriented product offerings facilitating the
participation of consumers in the electricity market.
As regards consumer rights, the Unfair Commercial Practices Directive is the
overarching piece of EU legislation regulating unfair commercial practices in business-
to-consumer transactions. It applies to all commercial practices that occur before (i.e.
during advertising or marketing), during and after a business-to-consumer transaction has
taken place. Where sector-specific EU law is in place and its provisions overlap with the
provisions of the UCPD, the corresponding provisions of the sector-specific EU rules
prevail, so no contradictions exist.
Research, Innovation and Competitiveness being Energy Union's 5th
dimension, cuts
across all its elements. The Strategic Energy Technology Plan implements the energy
union's fifth dimension, promotes research and innovation for low carbon technologies,
contributing to the transformation of the EU's energy system and creating jobs, growth
and global export opportunities in the fast-growing clean-technology sector.
Technological developments create opportunities for citizens to turn from being passive
consumers of electricity into prosumers that actively manage their consumption, storage
and production of electricity and participate in the market and allow for the increasing
penetration of distributed resources. A new Research, Innovation and competitiveness
strategy, encompassing energy, transport and industrial competitiveness aspects is
expected to be presented in the months to come. This strategy builds on the achievements
of the SET Plan and further addresses the R&I challenges particularly towards
industrialisation of innovative low carbon technologies.
The present initiative is fully coherent as it seeks to remove barriers for the participation
of consumers, for bringing new resources to the market and seeks to improve price
formation with a view to create the conditions for new business models to emerge and for
innovative products to be absorbed by the market.
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Policy options
5. POLICY OPTIONS
A fully functioning European wide electricity market is the best means to ensure that
electricity can be delivered to consumers in the most cost-efficient way at any time. To
continue fulfilling that purpose, the electricity market needs to be able to adapt to the
significant increase of variable renewable electricity production, integrate new enabling
technologies such as smart grids, smart metering, smart-home, self-generation and
storage equipment, empower citizens to take ownership of the energy transition and
assure security of electricity supply at least costs. Market mechanisms may need to be
complemented by initiatives which help preventing and managing electricity crisis
situations.
Any EU action aimed at strengthening the market should build on the gradual
liberalisation of the EU energy markets resulting from the three Energy Packages
described earlier in this document.
The following policy options have been considered to address the problems of today's
electricity market and to meet the broad energy policy objective of ensuring low carbon
electricity supply to European customers at least costs. In assessing all possible options
to achieve this broad objective, the following approach was taken:
- Identification of the main areas where initiatives might be needed to achieve
the main objectives of a new electricity market design. These Problem Areas
are set out in Box 2 below: "Overview of Problem Areas".
- To address each Problem Area a set of high level options was identified (set-
out in the following paragraphs). Each of these high level options groups
options for specific measures.
- A bottom-up assessment was performed for each specific measure, comparing
a number of options in order to select the preferred approach. The assessments
of the specific measures can be found in the Annexes to the present impact
assessment.
To help the reader, a table matching the assumed measures for each high level option is
included at the end of each problem area with references to the Annexes.
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Policy options
Box 2: Overview of Problem Areas
Problem Area I: Market design not fit for taking up large amounts of variable,
decentralised electricity generation and allowing for new
technological developments
Problem Area II: Uncertainty about sufficient future investments in generation
capacity and un-coordinated government interventions
Problem Area III: Member States do not take sufficient account of what happens
across their borders when preparing for and managing electricity
crisis situations
Problem Area IV: The slow deployment of new services, low levels of service and
poor retail market performance
5.1. Options to address Problem Area I (Market design not fit for an increasing
share of variable decentralized generation and technological developments)
Overview of the policy options
5.1.1.
With a significant part of the produced electricity coming from variable renewable
sources and distributed resources, new challenges will be arising in terms of security of
supply and electricity price volatility. The options examined here aim to address these
challenges in the most cost-effective way for the whole European electricity system.
These system cost savings will be passed on to consumers by way of lower network
charges. They will also make it easier for RES E assets to earn a higher fraction of its
revenues through the market.
Two possible paths were identified: the path of enhancing current market rules in order to
increase the flexibility of the system, retaining to a certain extent the national operation
of the systems (with more or less coordination assumed depending on the related sub-
options) and the path of moving to a fully integrated approach.
Box 3: Overview of the Policy Options for Problem Area I
Each policy option consists of a package of measures which address the drivers of the
problem. In the following sub-sections, the high level policy options and the packages of
measures they contain are described. Details on the individual measures are included in
the Annexes. It is then explained if any of those options are to be discarded at this stage,
prior to assessment, or whether other options were considered but were discarded from
the outset. The section is closed by a table summarising all specific measures included in
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Policy options
each option and references to the Annexes where each measure is described and asessed
in more detail.
The relevant Annexes addressing the policy options below in more detail are: 1.1 to 3.4.
Option 0: Baseline Scenario – Current Market Arrangements
5.1.2.
Under this option no new legislation is adopted, but there is some effort to implement
existing legislation including via the adoption of so-called network codes or guidelines.
The network codes, provided for in Article 6 and the guidelines provided for in Article
18 of the Electricity Regulation specify technical rules on the operation of European
electricty markets138
. They are, as such, only designed to amend non-essential elements
of the Electricity Regulation and can only be adopted in areas specifically mentioned in
the above mentioned Articles.139
Under these limitiations, network codes/guidelines are not the suitable instrument to
achieve all objectives of this initiative. For instance, whereas the implementation of the
Guideline on Capacity Allocation and Congestion Management ('CACM Guideline') will
bring a certain degree of harmonisation of cross-border intraday markets, gate closure
times and products for the intraday, as well as a market clearing, there is no guarantee
that the local market will adapt to reflect the cross-border approach and practices
(auctions / continuous trading) and local intraday markets across Europe will continue to
remain non-harmonised. This means that the EU-wide intraday market coupling
envisaged by the CACM Guideline will not be able to reach its full potential.
The Balancing Guideline is expected to bring certain improvements to the balancing
market, namely the common merit order list for activation of balancing energy, the
standardisation of balancing products and the harmonisation of the pricing methodology
for balancing. Nonetheless, other important areas like balancing capacity procurement
rules, frequency, geographical scope and sizing will not be affected by this regulation.
Priority dispatch rules, must-run priorities and other technology specific rules related to
the scheduling and operation of the system do not change at all with the adoption of
network codes. The same applies for the possibility for demand and distributed resources
to access the markets, and to compete on a level playing field with thermal generation.
The baseline assumes that demand response exists only in countries where it currently
has access to the market, with only industrial consumers being able to participate.
Overall, this option assumes that the future situation will remain more or less the same as
today, except from some specific measures included in the network codes (as above). The
138
More detail as regards network codes and guidelines is provided in Annex VII.
139
CIGRE paper C5-202 (2016): "Market coupling, facing a glorious past?" by R.Hirvonen, A.Marien,
B.Den Ouden, K.Purchala, M.Supponen, describes the past and future challenges of implementing
market coupling.
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Policy options
baseline does not consider explicitly any type of existing support schemes for power
generation plants, neither in the form of RES E subsidies nor in the form of CMs140
.
Stakeholders' opinions141
: None of the respondents to the public consultation expressed
the opinion that there is no need for further upgrade of the current market
arrangements.142
Option 0+: Non-regulatory approach
5.1.3.
Whilst systematically considered143
, no such option could be identified144
.
Stronger enforcement provides little scope for improving the level playing field among
resources. To the extent the lack of a level playing field is due to the variety of provisions
in national law, a clear and transparent EU framework is a prerequisite for any
improvement. If the lack of a level playing field is due to exemptions in the EU
regulatory framework, stronger enforcement of these would actually be counter
productive. In this regard, the Evaluation report indicates that the rules of the Third
Energy Package appear to be insufficient to cope with the challenges facing the European
electricity system.145
Moreover, voluntary cooperation has resulted in significant developments in the market
and a lot of benefits. However, it it unlikely to provide for appropriate levels of
harmonisation or certainty to the market and legislation is needed in this area to address
the issues in a consistent way.
The current EU regulatory framework contains very limited rules on balancing and
intraday markets in a manner that allow to strengthening these short-term markets. In
particular, the Third Package does not address regional sizing and procurement of
140
More details on the baseline and the reasons for not considering existing support schemes can be found
in Annex IV.
141
Stakeholders' opinions are reflected through-out Section 5 (and occasionally Section 6) of the main
text of this impact assessment to provide insides into their views as to the various options considered.
Stakeholder views are moreover reflected in detail in Section 7 of of each of the Annexes 1.1 throught
to 7.6 to the present impact assessment.
142
Some stakeholders propose to preserve only particular rules of the current market arrangements, while
being supportive to other Commission proposals for upgrading of the electricity market. E.g., one
stakeholder is supportive to more aligned framework for balancing markets and European measures to
incentivise demand side flexibility and in the same time supports the priority dispatch and priority
access for renewables. Similarly, one stakeholder strongly supports measures to incentivise the
demand side response and strengthening the powers of ACER, but considers that power exchanges
should not be subject to governance rules as well as that redesigning of the balancing markets is the
task of Member States and not the EU.
143
For each measure the opportunities for stronger enforcement have also been assessed in the annexes
with measures associated with each option. References to the relevant annexes are provided in
Sections 5.1.7, 5.2.9, 5.3.8 and 5.4.6
144
The Commission has conducted – and is still conducting – a systematic ex-officio compliance check of
national legislation with the Third Energy Package. While EU-Pilot or formal infringement procedures
are still ongoing, they will however not be able to fulfil the policy objectives of the proposed
measures.
145
See Section 7.3.1., 7.34 and 7.3.4 of the Evaluation.
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Policy options
balancing reserves nor contain rules allowing achieving a larger degree of harmonisation
of intraday trading arrangements.
Given that the existence of Regional Security Coordinators ('RSCs') depends on the
implementation of the System Operation Guideline, RSCs may only be fully operational
around mid-2019. Hence, stronger enforcement is currently not a possible option. Any
progress beyond the framework in the System Operation Guideline and the application of
other network codes would depend on the voluntary initiatives of TSOs. However, these
voluntary initiatives would be limited due to constraints deriving from differing national
legal frameworks.
As to demand response, stronger enforcement of existing provisions in the electricity and
energy efficiency directives are unlikely to untap the potential of flexibility. This is
because the existing provisions give Member States a high degree of freedom that has
proven not to be specific enough to ensure a full removal of existing market barriers.
Evidence suggests that voluntary cooperation will not result in progress in this area, as
there has been to date already significant opportunity to effect the necessary changes
voluntarily.
In the case of DSOs the current EU regulatory framework does not provide a clear set of
rules when it comes to additional tools that DSOs can employ to improve their efficiency
in terms of costs and quality of service provided to system users. Moreover, the current
framework does not address the role of DSOs in activities which are expected to have a
key impact in the development of the market (e.g. data management).
Option 1: EU Regulatory action to enhance market flexibility
5.1.4.
Electricity production from wind and sun is more variable and less predictable than
electricity production from conventional sources of energy. Due to this, there will be
times when renewables cover a very large share of electricity demand and times when
they only cover a minor share of it. The large scale integration of such variable electricity
production thus requires a more flexible electricity system, one which matches the
variable production.
Options to deliver the desired flexibility may comprise:
a. Abolishing (i) those measures that enhance the inflexibility of the current system,
namely priority dispatch for certain technologies (e.g. RES E, CHP, indigenous
fuels) and "must-runs" of conventional generation, (Creating a level playing
field) and (ii) barriers preventing demand response from participating in the
energy and reserve markets;
b. In addition to the measures under a), better integrating short-term markets,
harmonizing their gate closure times and bringing them closer to real-time, in
order to take advantage of the diversity of generation resources and demand
across the EU and to improve the estimation and signalling of actual flexibility
needs (Strengthening the short-term markets);
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Policy options
c. In addition to the measures under a) and b), pulling all flexible distributed
resources concerning generation, demand and storage, into the market via
proper incentives and a market framework better adapted to them, based on active
aggregators, roll-out of smart-metering and time-of-use supply tariffs linked to
the wholesale prices.146
The sub-options described above reflect a different degree of ambition to change the
market, as well as the different views expressed among stakeholders on how strong the
proposed interventions should be. Sub-option 1(a) (level playing field) retains a more
national status of the markets, Sub-option 1(b) (strengthening short-term markets) moves
also to more regionally coordinated markets, while Sub-option 1(c) (demand
response/distributed resources) makes an additional step towards a more decentralised
electricity market and system.
146
IEA "Re-powering markets" (2016) suggests: … “dispatching” demand response as a generator
requires complex market rules. Demand response can only be assessed according to a baseline
consumption levels, which are difficult to define and can lead to hidden subsidies. Setting the right
level of remuneration for aggregators has proven to be complex. Instead, dynamic pricing should be
encouraged, using new measurement and automation technologies such as smart meters.
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Policy options
European Parliament: "…[I]n order to achieve the climate and energy targets, the
energy system of the future will need more flexibility, which requires investment in all
four flexibility solutions – flexible production, network development, demand flexibility
and storage"[.]147
European Economic and Social Committee: "The goal of a low-carbon energy supply,
with a high proportion of adjustable renewable energy sources, can only be achieved in
the short to medium term if all market participants (including new ones) have at their
disposal enough options that afford flexibility, such as sufficient storage capacity,
flexible, consumer-friendly demand options and flexible power generation technologies
(e.g. cogeneration), as well as adequately upgraded and interconnected power
distribution infrastructure. Other conditions are that consumers must receive adequate,
timely and correct information, they must have the chance to develop their own
marketing opportunities and the necessary investments in technology and infrastructure
should pay off. None of this is currently the case"148
.
Stakeholders' opinions: In the public consultation on Market Design Initiative most
stakeholders supported full integration of renewable energy sources into the market e.g.
through full balancing obligation and phasing-out priority dispatch. Also, most
stakeholders agree with the need to speed up the development of integrated short-term,
balancing and intraday, markets.
5.1.4.1.Sub-option 1(a): Level playing field amongst participants and resources
The first group of measures aims at removing market distortions resulting from manifold
different regulatory rules for generation from different sources. Creating a level playing
field among all generation modes and restoring the economic merit order curve is an
important prerequisite for a well-functioning electricity market with prices that reflect
properly actual demand and supply conditions. For this reason the measures described
here are an integral part of all sub-options under Option 1.
The measures considered under this option would mainly target the removal of existing
market distortions and create a level playing field among technologies and resources.
This could involve abolishing rules that artificially limit or favour the access of certain
technologies to the electricity market (such as so-called "must-run" provisions, rules on
priority dispatch and access and any other rules discriminating between resources149
).
Industrial consumers would become active in the wholesale markets, both for energy and
reserves, in all Member States. All market participants would become balance
responsible, bearing financial responsibility for the imbalances caused and thus being
147
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, Recital C.
148
Opinion of the European Economic and Social Committee on the ´Communication from the
Commission to the European Parliament, the Council, the European Economic and Social Committee
and the Committee of the Regions – Launching the public consultation process on a new energy
market design´(COM (2015) 340 final) (2016/C 082/03), OJ C 82, 3.3.2016, p. 13-21, § 1.4.
http://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=uriserv:OJ.C_.2016.082.01.0013.01.ENG&toc=OJ:C:2016:082:TOC
149
See in detail Annex 1(1) – 1.
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Policy options
incentivized to reduce the risk of such imbalances. Dispatch and redispatch decisions
would be based on using the most efficient resources available, curtailment should be a
measure of last resort which is limited to situations in which no market-based resources
are available (including storage and demand response), and only subject to transparent
rules.
Therefore, all resources would be remunerated in the market on equal terms. This would
not mean that all resources earn the same revenues, but that different resources face the
same prices for equal services. In most cases the TSO should follow the merit order,
allowing the market to define the dispatch of available resources, using the inherent
flexibility of resources to the maximum potential (e.g. by significantly reducing must-run
generation, creating incentives for the use of heat storage combined with CHP and the
use of biomass generation in periods of peak demand rather than as baseload, and using
demand response or storage where it is more efficient than generation). Where resources
are used on the basis of merit order (thus on the basis of the marginal cost for using a
particular resource at a given point in time)150
, supply costs are reduced.
Imposing additional obligations increases the risk and hence the financing costs of some
technologies such as RES E. Part of this risk will be hedged through the more liquid
intraday and balancing markets resulting from the full implementation of the Network
Codes, in combination with the increased participation of resources due to the removal of
must-run and priority dispatch provisions. These obligations should be also accompanied
by measures that reduce their costs of compliance, such as the introduction of transparent
curtailment rules. Additionally, exemptions from certain regulatory provisions may, in
some cases, be required. This can e.g. be the case for emerging technologies, which,
although they are not yet competitive, need to reach a minimum number of running hours
to gather experience. For certain generators, particularly small RES E (e.g. rooftop solar),
exemptions can be furthermore justified to avoid excessive administrative efforts related
to being active on the wholesale markets.
Stakeholders' opinions:151
Most stakeholders support the full integration of all
technologies into the market, e.g. through full balancing obligations for all technologies,
phasing-out priority dispatch and removing subsidies during negative price periods.
150
Where marginal costs are based on the use of fuel, this can also result in lower CO2 emissions.
However, inflexible conventional plants will include the cost of starting or stopping power generation
into their market bids, thus possibly deciding to operate at a price below their fuel costs. In this case,
the cost of not operating the power plant exceeds the cost of operating it.
151
More detailed depictions of stakeholder's opinions are provided in Sections 7 of each annexe
describing the more detailed measures i.e. annexes 1.1 to 7.6 of the Annexes to the Impact
Assessment.
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Policy options
Also stakeholders from the renewable sector often recognize the need to review the
priority dispatch framework. However, in their view, a phase-out of priority dispatch for
renewable energy sources should only be considered if (i) this is done also for all other
forms of power generation, (ii) liquid intraday markets with gate closure near real-time
exist, (iii) balancing markets allow for a competitive participation of wind producers;
(short gate closure time, separate up/downwards products, etc.), and (iv) curtailment rules
and congestion management are transparent to all market parties.
Cogeneration sector stakeholder seek for a least parity between CHP and RES E.
European Parliament: "European Parliament […]stresses that a new market design for
electricity as part of an increasingly decentralised energy system must be based on
market principles, which would stimulate investment, ensure that SMEs have access to
the energy market and unlock a sustainable and efficient electricity supply through a
stable, integrated and smart energy system[...]"152
"European Parliament […] [i]nsists that, with the increasing technical maturity and
widespread use of renewable energy sources, subsidy rules must be geared to market
conditions, such as feed-in premiums, in order to keep costs for energy consumers within
reasonable bounds[.]"153
"European Parliament […] recalls the existing provisions of the Renewable Energy
Directive, which grant priority access and dispatch for renewables; suggests that these
provisions should be evaluated and revised once a redesigned electricity market has been
implemented which ensures a more level playing field and takes greater account of the
characteristics of renewable energy generation[.]"154
Council: "[…] Renewable energy sources should become an integrated part of the
electricity market by ensuring a level playing field for all market participants and
enabling renewable energy producers to be fully involved in the market, including in
balancing their portfolio and reacting to market price signals."155
European Electricity Regulatory Forum, Florence: "The Forum stresses that the
renewables framework for the post 2020 period should be based on an enhanced market
design, fit for the full integration of renewables, a strong carbon price signal through a
strengthened ETS, and specific support for renewables, that when and if needed, should
be market based and minimise market distortions. To this end, the Forum encourages the
Commission to develop common rules on support schemes as a part of the revision of the
152
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, §5.
153
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, §52.
154
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, §54.
155
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, Annex, paragraph 4.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
98
Policy options
Renewables Directive that facilitate a market based and more regionalised approach to
renewables."156
5.1.4.2.Sub-option 1(b): Strengthening short-term markets
Sub-option 1(b) (strengthening short-term markets) includes the measures described
under 1(a) (level playing field ) and a set of additional measures, further enhancing the
measures foreseen in the CACM and EB Guidelines (and are assumed as part of the
baseline). As explained above, variable RES E have fundamentally different generation
characteristics compared to traditional fuel based generation (e.g. variability, only short-
term predictability). An important additional step would therefore be to have more liquid
and better integrated short-term markets, going beyond what the implementation of
technical implementing legislation ("Network Codes") will achieve, setting the ground
for renewable energy producers to better access energy wholesale markets and to
compete on an equal footing with conventional energy producers. Short-term markets
will also allow Member States to share their resources across all "time frames" (forward
trading, day-ahead, intraday and balancing), taking advantage of the fact that peaks and
weather conditions across Europe do not occur at the same time.
Also, the closer to real time electricity is traded (supply and demand matched), the less
the need for costly TSO interventions to maintain a stable electricity system. Although
TSOs would have less time to react to deviations and unexpected events and forecast
errors, the liquid, better interconnected balancing markets, together with the regional
procurement of balancing reserves, would be expected to provide them with adequate and
more efficient resources in order to manage the grid and facilitate RES E integration.
In order to support these actions and mainly in order to be able to optimally exploit
interconnections along all "time frames", a number of measures are assumed to be taken:
gate closure times could be brought closer to real-time to provide maximum opportunity
for the market to balance its positions before it becomes a TSO responsibility and some
harmonisation would be brought to trading products for intraday markets in order to
further incentivize cross-border participation of market parties. The sizing of balancing
reserves and their procurement would be harmonized in larger balancing zones, allowing
to reap benefits of cross-border exchange of reserves and use of the most efficient
reserves available.
At the same time, the integration of national electricity systems, from the market and
operational perspectives, requires the enhancement of cooperation between TSOs. The
creation of a number of regional operational centres ('ROCs'), with an enlarged scope of
functions, an optimised geographical coverage compared to the existing regional security
coordinators and with an enhanced advisory role for all functions, including the
possibility to entrust them decision-making responsibilities for a number of relevant
156
31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §6.
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
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Policy options
issues, could contribute to better TSO cooperation at regional level.157
Measures on
enhanced cooperation between TSOs could be accompanied by an increased level of
cooperation between regulators and governments.158
All these options would be expected to strongly incentivize participation in the intraday
and balancing markets, further increasing their liquidity, while at the same time
minimizing TSOs' interventions.
Stakeholders' opinions: Most stakeholders agree with the need to speed up the
development of integrated short-term (intraday and balancing) markets. A significant
number of stakeholders argue that there is a need for legal measures, in addition to the
technical network codes under development, to speed up the development of cross-border
balancing markets. Many stakeholders note that the regulatory framework should enable
RES E to participate in the market, e.g. by adapting gate closure times and aligning
product specifications.
European Parliament: "European Parliament […][c]alls for the completion of the
integration of internal market and balancing and reserve services by fostering liquidity
and cross-border trading in all market timeframes; urges that efforts to achieve the
ambitious goals of the Target Model regarding intraday and balancing markets be
speeded up, starting with the harmonisation of gate closure times and the balancing of
energy products[.]"159
Council: "An integrated European electricity market requires well-functioning short
term markets and an increased level of cross-border cooperation with regard to day-
ahead, intraday and balancing markets, without hampering the proper functioning of the
networks, as this will enhance security of supply at lower costs for the system and
consumers"160
.
European Economic and Social Committee: "The EESC underlines the particular
importance of intraday trade as a way of ensuring meaningful trade involving
VREs[variable renewable energies]"161
.
European Electricity Regulatory Forum, Florence: "The Forum supports the view that
further steps are needed beyond agreement and implementation of the Balancing
Guideline. In particular, further efforts should be made on coordinated sizing and cross--
‐border sharing of reserve capacity. It invites the Commission to develop proposals as
157
For more details concerning policy measures for the establishment of ROCs, refer to Option 1 in
Annex 2.3.
158
For more details concerning policy measures for the enhanced cooperation between regulators and
governments, refer to Option 1 in Annex 3.4.
159
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 46.
160
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, Annex, paragraph 6.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
161
31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §3.5.
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
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Policy options
part of the energy market design initiative, if the impact assessment demonstrates a
positive cost--‐benefit, which also ensures the effectiveness of intraday markets"162
.
"The Forum Acknowledges the significant progress being made on the integration of
cross - border markets in the intraday and day--‐ahead timeframes, and considers that
market coupling should be the foundation for such markets. Nevertheless, the Forum
recognises that barriers may continue to exist to the creation of prices that reflect
scarcity and invites the Commission, as part of the energy market design initiative, to
identify measures needed to overcome such barriers"163
.
"[T]he Forum invites the Commission to identify those aspects of national intraday
markets that would benefit from consistency across the EU, for example on within--‐zone
gate closure time and products that should be offered to the market. It also requests for
action to increase transparency in the calculation of cross--‐zonal capacity, with a view
to maximising use of existing capacity and avoiding undue limitation and curtailment of
cross--‐border capacity for the purposes of solving internal congestions"164
.
"The Forum stresses that, whilst scarcity pricing in short--‐term markets is critical to
creating the right signals, the importance of hedging opportunities and forward/future
markets in creating more certainty for investors and alleviating risks for consumers must
not be overlooked. Further, it considers that the Commission must recognise the risks of
State Interventions undermining scarcity pricing signals"165
.
162
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions,
§3,
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
163
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §
4,
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
164
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §
5,
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
165
30th
meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §
6,
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-
%20Florence%20Forum%20-%20Final.pdf
101
Policy options
5.1.4.3.Sub-option 1(c): Pulling demand response and distributed resources into the
market166
Sub-option 1(c) (demand response/distributed resources) includes the measures described
under 1(a) (level playing field) and 1(b) (strengthening short-term markets), as well as a
set of additional measures, aiming at using the full potential of demand response, storage
and distributed generation. The previous options would introduce a level playing field for
all resources and improve the short-term market framework. They would, however, not
include any measure intending to pull all the additional available potential from
distributed resources into the market. Such resources are most importantly demand
response, distributed RES E and storage.167
A significant part of the current costs for the electricity system stem from the new
challenges of variable generation for the system, notably the increased need to deal with
supply peaks and unexpected generation gaps. As the elecricity grid requires a constant
balance of demand and supply, grid operators need to take costly measures. Demand
response, distributed RES E and storage can play an important role to reduce these costs.
The measures considered under Option 1(c) bring demand response from all consumer
groups, including residential and commercial consumers168
, and storage as additional
resources into the market, especially to the balancing market. This would even further
increase the flexibility of the electricity system and the resources for the TSOs to manage
it. At the same time it should lead to much more efficient operation of the whole energy
system.
This option would include more in particular:
Enabling consumers to directly react to price signals on electricity markets both in terms
of consumption and production, by giving consumers access to a fit-for-purpose smart
metering system, enabling suppliers to measure and settle electricity consumption close
166
This set of measures could have been introduced alternatively as Sub-Option 1(b), thus before the
improved short-term market functioning related measures, as a further enhancement to the rules
creating a level-playing field for all technologies. However, the benefits from the participation of these
additional resources in the market are enhanced via their participation in the balancing markets and the
procurement of reserves. Introducing this set of measures in the context of improved short-term market
functioning therefore allows the full benefits of them to be realised. See also footnote 294, Section
6.1.7.
167
RSCAS Research report (2015), "Conceptual framework for the evolution of the operation and
regulation of electricity transmission systems towards a decarbonised and increasingly integrated
electricity system in the EU" by J.-M.Glachant, J.Vasconcelos, V.Rious, states: "EU has a target
model for the EU internal market and for the transmission system operation. It has none for EU “RES
pocket markets” and for the distribution system operation".
168
As big industrial consumers are assumed to already participate directly in the market in Option 1(a)
(level playing field), this sub-option extends the participation of demand response to all consumer
groups (including residential and commercial consumers) who, because of their small individual loads,
can enter the market only through third party service providers, e.g. aggregators. At the same time
though the described measures are expected to significantly increase the DR potential for all
categories, including industrial consumers who do not wish to engage directly in the market and by
allowing DSOs to procure additional flexibility services.
102
Policy options
to real time, as well as requiring suppliers to offer consumers electricity supply contracts
with prices linked dynamically to the wholesale spot market that will enable consumers
to directly react to price signals on electricity markets both in terms of consumption and
production.
Box 4: Benefits and risks of dynamic electricity pricing contracts
The preferred policy option is to provide all consumers the possibility to voluntarily
choose to sign up to a dynamic electricity price contract and to participate in demand
response schemes. All consumers will however have the right to keep their traditional
electricity price contract.
Dynamic electricity prices reflect – to varying degrees – marginal generation costs and
thus incentivise consumers to change their consumption in response to price signals. This
reduces peak demand and hence reduces the price of electricity at the wholesale market.
Those price reductions can be passed on to all consumers. At the same time, suppliers
can pass parts of their wholesale price risk on to those consumers who are on dynamic
contracts. Both aspects can explain why, according to the ACER/CEER monitoring
report 2015, on average existing dynamic electricity price offers in Europe are 5%
cheaper than the average offer.
While consumers on dynamic price contracts can realise additional benefits from shifting
their consumption to times of low wholesale prices they also risk facing higher bills in
case they are consuming during peak hours. Such a risk is deemed to be acceptable if
taking this risk is the free choice of the consumer and if he is informed accurately about
the potential risks and benefits of dynamic prices before signing up to such a contract.
Aggregators are companies that act as intermediaries between the electricity system and
distinct agents in the electricity system, mainly small, individual resoures but that exist in
large numbers, and which are usually located in the distribution grid (consumers,
prosumers and producers).169
Developing a comprehensive framework for demand,
supply and storage aggregators would facilitate their participation in the market and thus
increase flexibility in the energy system and complement large generation connected to
the transmission grid.170
Larger storage facilities can be connected at distribution or
transmission level, and provide services on a peer basis with other providers.
169
EPRG working paper 1616 (2016), "Which Smart Electricity Services Contracts Will Consumers
Accept?" by L-L.Richter and M.G.Pollit states: "By combining appropriate participation payments
with sharing of bill savings, service providers could attract the number of customers required to
provide the optimal level of demand response."
170
CIGRE paper C5-304 (2016), B. Guédou and A. Rigard-Cerison, RTE France says: "One can learn,
from French experience, that building an appropriate market for DSR requires to benefit from a
strong political commitment (intense involvement from the administration, the regulatory authorities
and the TSO) and to solve some key issues, requiring innovative answers both on the regulatory side
and the technical side (e.g. role of aggregators / independent DR operators, adaptation of the
regulatory framework to enable competition, role of TSOs and DSOs, data collection and privacy…)".
103
Policy options
R&D results: The economic and technical viability of the concept of aggregation has already been
demonstrated in European projects like: Integral, IDE4L, Grid4eu, INTrEPID, INCREASE, DREAM. The
ability of small-scale RES to participate in the balancing market or contribute to solving grid congestion
has been demonstrated in European projects like: V-Sync and MetaPV.
In order to pull all available resources into the market, it is also important to enable and
incentivise DSOs, without compromising their neutrality as system operators, to manage
their networks in a flexible and cost-efficient way, This could be achieved by
establishing a performance-based remuneration framework for DSOs that would reward
them for innovating and improving overall efficiency of their networks through synergies
with other actors, making full use of energy storage, and/or investing in electronic
communication infrastructure. This would be enabled by the deployment of intelligent
infrastructure and by ensuring coherence with other Commission policies in the field of
the Digital Single Market and the General Data Protection Regulation171
.
Measures under this option would also include defining the conditions under which
DSOs may acquire flexibility services without distorting the markets for such services,
and putting in place distribution tariff structures that send accurate price signals to all
grid users. Such initiative would be aimed at facilitating the integration of the increasing
amounts of variable RES E generation that will be connected directly to distribution grids
in the future.
Stakeholders' opinions: Many stakeholders identified a lack of smart metering systems
offering the full functionalities to consumers and dynamic electricity pricing (more
flexible consumer prices, reflecting the actual supply and demand of electricity) as one of
the main obstacles to kick-starting demand side response, along with the distortion of
retail prices by taxes/levies and price regulation.
Other factors include market rules that discriminate against consumers or aggregators
who want to offer demand response, network tariff structures that are not adapted to
demand response and the slow roll-out of smart metering. Some stakeholders underline
that demand response should be purely market driven, where the potential is greater for
industrial customers than for residential customers. Many replies point at specific
regulatory barriers to demand response, primarily with regards to the lack of a
standardised and harmonised framework for demand reponse (e.g. operation and
settlement). A number of respondents also underline the need to support the development
of aggregators by removing obstacles for their activity to allow full market participation
of renewables. Many submissions highlight the crucial role of scarcity pricing for kick-
starting demand response at industrial and household level.
Regarding the role of DSOs, the respondents consider active system operation, neutral
market facilitation and data hub management as possible functions for DSOs. Some
stakeholders point at a potential conflict of interests for DSOs who are able to actively
171
This would entail also close cooperation with TSOs, as elaborated for example in CIGRE paper C2-
111: "Increased cooperation between TSO and DSOs as precondition for further developments in
ancillary services due to increased distributed (renewable) generation", M.Kranhold, 50Hertz
Transmission GmbH (2016)
104
Policy options
menage their networks where these DSOs are also active in the supply business,
emphasizing that the neutrality of DSOs should be ensured. A large number of the
stakeholders stressed the importance of data protection and privacy, and consumer's
ownership of data. Furthermore, a high number of respondents stressed the need of
specific rules regarding access to data. As concerns a European approach on distribution
tariffs, the views are mixed; the usefulness of some general principles is acknowledged
by many stakeholders, while others stress that the concrete design should generally
considered to be subject to national regulation.
European Parliament: "European Parliament […] considers that this framework
should promote and reward flexible storage solutions, demand-side response
technologies, flexible generation, increased interconnections and further market
integration, which will help to promote a growing share of renewable energy sources
and integrate them into the market[.]"172
"European Parliament[…] recalls that the transition to scarcity pricing implies
improved mobilisation of demand response and storage, along with effective market
monitoring and controls to address the risk of market power abuse, in particular to
protect consumers; believes that consumer engagement is one of the most important
objectives in the pursuit of energy efficiency, and that whether prices that reflect the
actual scarcity of supply in fact lead to adequate investment in electricity production
capacity should be evaluated on a regular basis[.]"173
"European parliament […][c]onsiders that energy storage has numerous benefits, not
least enabling demand-side response, assisting in balancing the grid and providing a
means to store excess renewable power generation; calls for the revision of the existing
regulatory framework to promote the deployment of energy storage systems and other
flexibility options, which allow a larger share of intermittent renewable energy sources
(RES), whether centralised or distributed, with lower marginal costs to be fed into the
energy system; stresses the need to establish a separate asset category for electricity or
energy storage systems in the existing regulatory framework, given the dual nature –
generation and demand – of energy storage systems[.]"174
Council: "The future electricity retail markets should ensure access to new market
players (such as aggregators and ESCO’s) on an equal footing and facilitate
introduction of innovative technologies, products and services in order to stimulate
competition and growth. It is important to promote further reduction of energy
consumption in the EU and inform and empower consumers, households as well as
industries, as regards possibilities to participate actively in the energy market and
respond to price signals, control their energy consumption and participate in cost-
effective demand response solutions. In this regard, cost efficient installation of smart
172
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 5.
173
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 10.
174
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 28.
105
Policy options
meters and relevant data systems are essential. Barriers that hamper the delivery of
demand response services should be removed"175
.
European Electricity Regulatory Forum, Florence: "The Forum recognises that the
development of a holistic EU framework is key to unlocking the potential of demand
Response and to enabling it to provide flexibility to the system. It notes the large
convergence of views among stakeholders on how to approach the regulation of demand
response, including: the need to engage consumers; the need to remove existing barriers
to market access, including to third--‐party aggregators; the need to make available
dynamic market--‐based pricing; the importance of both implicit and explicit demand
response; and the cost--‐efficient installation of the required technology"176
.
Option 2: Fully Integrated EU market
5.1.5.
This option considers measures that would aim to deliver a single truly pan-European
electricity market via relatively far-reaching changes to the current regulatory
framework, aiming at the full integration of electricity markets and system operation, and
at mobilising all available flexibility of the EU-wide system.
For a fully integrated EU market, one would need to significantly change the current
regulatory approach of the internal market. The current EU wholesale market design of
the Third Package provides for a coordination framework between grid operators and
national regulators and sets some rules for certain issues which are relevant for cross-
border exchange of electricity (e.g. coordinated electricity trading and grid operation
measures). However, under the Third Package, regulatory decisions are in principle left
to Member States, the 28 national regulators and the 42 European grid operators if not
otherwise provided in the Third Package.
Leaving scope for national decision-making on trading and system operation may lead to
inefficiencies due to unsufficiently coordinated and contradicting decisions. A more
centralised regulatory approach could therefore be considered to achieve more integrated
EU markets.
Under this option, procurement of balancing reserves would be performed directly at EU
level, instead of a regional level. For system operation, this could mean shifting from a
system of separate national TSOs to an integrated system managed by a single European
Independent System Operator ("EU ISO"). System operation (including real time
operation) and planning functions could be performed by this EU ISO, which would be
competent for the whole Union.177
175
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, Annex, paragraph 8.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
176
31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §1.
https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf
177
For more details on policy option concerning the establishment of an EU ISO, please refer to Option 3
in annex 2.3.
106
Policy options
In order to optimally deal with congestion between countries and to let the market
transmit the right price signals, this option would entail to move from zonal to nodal
pricing178
. The values of available transmission capacities would be calculated centrally
and could be closely coordinated across market regions, thereby taking advantage of all
information available among the TSOs in different grid arreas and also taking into
account the interrelationship between different interconnectors. As a result, it is assumed
that more interconnector capacity is made available to the market(s) and resources are
expected to be utilized more efficiently across regions.
In general, Option 2 would not only entail coordination, approximation and
harmonisation of selected topics relevant for national market and grid operation rules, but
also to apply the same rules and specifications for products and services across the EU,
including centrally fixed rules for electricity trading, for common EU-wide procurement
of reserves and central system planning and operation. Such centralised integrated market
would also provide for mandatory smart meter roll-out and a full EU framework for
incentive-based demand response to better exploited demand reponse. Under Option 2,
also distribution tariff structures would be harmonised, stronger unbundling rules for
DSOs be created as well as harmonised renumeration methodologies that ensure DSOs'
incentives to invest in innovative and efficient technologies.
ACER would need to gain significant competences and take over most NRAs'
responsibilities directly or indirectly related to cross-border and EU-level issues.
ENTSO-E would need to be formally separated from its members' interest and take up
more competences.179
Such measures, intended to optimise the cost-efficiency and flexibility of the European
electricity system, would involve going significantly beyond the measures described
under Option 1, requiring also particularly far-reaching institutional changes.
Stakeholders' opinions: No stakeholder expressed support for the possibility of
designing measures leading to the creation of a fully integrated EU electricity market.
For example, as regards the establishment of an EU Independent System Operator, a
number of stakeholders emphasized that while it is necessary to reinforce TSO
coordination, this should take place through a step-wise regional integration of system
operation
For Option 1 and 2: Institutional framework as an enabler
5.1.6.
Each set of proposed measures under Options 1(a) to 1(c), as well as (2), will necessitate
a different degree of reinforcement of the institutional framework of the EU's electricity
178
Nodal Pricing is a method of determining prices in which market clearing prices are calculated for a
number of locations on the transmission grid called nodes. Each node represents the physical location
on the transmission system where energy is injected by generators or withdrawn by loads. The price at
each node represents the locational value of energy, which includes the cost of the energy and the cost
of delivering it, i.e. losses and congestion
179
For more details on ACER's and ENTSO-E's enhanced competences in a fully integrated EU market,
refer to Option 2 in Annex 3.4.
107
Policy options
markets. Since the harmonisation of regulatory aspects (e.g. gate closure times, rules for
the curtailment of cross-border capacities, bidding zones etc.) often has different
economic impacts in different Member States, an institutional framework is needed to
find the necessary compromises. Experience has shown that it will generally be more
difficult to achieve ambitious harmonisation goals with an institutional framework that
grants veto rights to each national regulator or TSO (i.e. in cooperative institutions
applying unanimous decision-making). An alignment or harmonisation of aspects
concerning the electricity market design is therefore more likely to happen with an
institutional framework which applies (qualified) majority decision-making or which
replaces the decision-making by 28 different regulators/TSOs by a central body which
takes the decision in the European interest180
.
A robust institutional framework constitutes a pre-requisite for the integration and proper
functioning of the EU market. For this reason, it is necessary that the institutional
framework reflects the realities of the electricity system and the resulting need for
regional cooperation as well as that it addresses existing and anticipated regulatory gaps
in the energy market.
In order to effectively establish a level playing field between all potential market
participants and resources (Sub-option 1(a) (level playing field)), it is necessary to
reinforce ACER's competences at EU level in order to address regulatory gaps already
identified in the implementation of the Third Package and ensure the oversight over
entities and functions with relevance at EU level.
When markets and market regulation achieve a regional dimension (Sub-option
1(b)(strenghening short-term markets)), the institutional framework needs to be adapted
accordingly, if it is to remain efficient and effective. Currently, the EU institutional
framework is based on the complementarity of regulation at national and EU law. Hence,
the regulatory framework would then need to be reinforced to address the need for
additional regional cooperation. In this regard, ACER's competences and NRAs'
cooperation at regional level should be enhanced, corresponding to increased regional
TSO cooperation and to the implementation of network codes and guidelines at regional
level. The mandate of ENTSO-E could be clarified to strengthen its obligation to take a
European / internal market perspective and to emphasize its transparency and monitoring
obligations. The role of power exchanges in cross-border electricity issues should be
acknowledged and they should be involved in all regulatory procedures relevant for
them. Finally the use of congestion income should be altered, increasing the proportion
spent on investments that maintain or increase interconnection, thus creating the basis for
the regional co-operation through a strongly interconnected system181
.
In order to facilitate distributed resources to participate in the market (Sub-option 1(c)
demand response/distributed resources), DSOs must become more active at European
level and have increased responsibilities and tasks, similar to those of the TSOs. Their
180
The transfer of decisions on cross-border cost allocation to the Director of ACER is one example of
decision-making by an independent supranational body. See Article 12(6) of Regulation 347/2013
(TEN-E Regulation).
181
As is in fact discussed under Option 1 of Problem Area II
108
Policy options
role should be formalised into a European organisation with an efficient working
structure to render their participation effective and independent. In particular, whereas
DSOs are currently represented at EU level by four associations (Eurelectric, Geode,
CEDEC and EDSO), none of these has the necessary characteristics to represent the
sector by engaging in tasks that might include the codification of formal EU market
rules: Either they or their members are listed as lobbyists on the EU Transparency
Register, none of their memberships is representative of all EU DSOs, and none has the
explicit mandate to represent EU DSOs in such activities.
Finally, Option 2 requires significantly restructuring the institutional framework, going
beyond addressing the regulatory gaps and moving towards more centralised institutional
structures with additional power and responsibilities, particularly for ACER and ENTSO-
E.
Stakeholders' opinions: Opinions with regard to strengthening ACER’s powers are
divided. There is clear support for increasing ACER's legal powers by many
stakeholders. However, the option to keep the status quo is also visibly present, notably
in the submissions from Member States and national energy regulators. While some
stakeholders mentioned a need for making ACER'S decisions more independent from
national interests, others highlighted rather the need for appropriate financial and human
resources for ACER to fulfil its tasks.
With regard to ENTSO-E, stakeholders' positions are divided as to whether ENTSO-E
needs strengthening remain divided. Some stakeholders mention a possible conflict of
interest in ENTSO-E’s role – being at the same time an association called to represent the
public interest, involved e.g. in network code drafting, and a lobby organisation with own
commercial interests – and ask for measures to address this conflict. Some stakeholders
have suggested in this context that the process for developing network codes should be
revisited in order to provide a greater a balance of in interests.
Some submissions advocate for including DSOs and stakeholders in the network code
drafting process. While a majority of stakeholders support governance and regulatory
oversight of power exchanges, particularly as regards the market coupling operator
function, other stakeholders are sceptical whether additional rules are needed for power
exchanges given the existing rules in legislation on market coupling (in the CACM
Guideline).
European Parliament: "European Parliament […][n]otes the importance of effective,
impartial and ongoing market monitoring of European energy markets as a key tool to
ensure a true internal energy market characterised by free competition, proper price
signals and supply security; underlines the importance of ACER in this connection, and
looks forward to the Commission’s position on new and strengthened powers for ACER
on cross-border issues[.]"182
182
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 70.
109
Policy options
"European Parliament […][s]tresses that in most cases renewables are fed in at
distribution system level, close to the level of consumption, and therefore calls for DSOs
to play a greater role as facilitators and to be more closely involved in the design of
European regulatory framework and in the relevant bodies when it comes to drawing up
guidelines on issues of concern to them, such as demand-side management, flexibility
and storage, and for closer cooperation between DSOs and TSOs at the European
level[.]"183
Summary of specific measures comprising each Option
5.1.7.
The following table summarizes the specific measures comprising each package of
measures, as well the corresponding specific measure option considered under each high
level option184
. The detailed presentation and assessment of each measure can be found
in the indicated Annex.
183
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 63.
184
The preferred options for the specific measures set out in the annex are highlighted in the table in
green.
110
Policy options
Table 6: Summary of Specific Measures investigated for Problem Area I
Specific Measures Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Option (a) +
Strengthening
short-term
markets
Option 1(a), 1(b) +
Demand response/distributed
resources
Fully integrated markets
Priority Access and
Dispatch
(Annex 1.1)
Maintain priority dispatch
for RES, indigenous fuels
and CHP
(Annex 1.1.4 Option 0)
Abolish priority dispatch and introduce clear curtailment rules to replace
priority access, with the exception of emerging technologies and small CHP
and RES E plants
(Annex 1.1.4 Options 2 and 3)
Fully abolish priority dispatch and access
(Annex 1.1.4 Option 1)
+ Balancing
Responsibility
(Annex 1.2)
Financial balancing
responsibility under EEAG
(Annex 1.2.4 Option 0)
Balancing responsibility for all parties, with the exception of emerging
technologies and small CHP and RES E plants
( Annex 1.2.4 Option 2)
Full balancing responsibilities for all
parties
(Annex 1.2.4 Option 1)
+ RES providing non-
frequency ancillary
services
(Annex 1.3)
Services continue to be
provided by large
conventional generation
(Annex 1.3.4 Option 0)
Principles for transparent, non-discriminatory market-based framework for
the provision of these services
(Annex 1.3.4 Option 2)
EU market framework for such services
(Annex 1.3.4 Option 1)
+ Reserves Sizing and
Procurement
(Annex 2.1)
National sizing of balancing reserves, frequency of
procurement as today (e.g. many products, not
necessarily separete upwards/downwards products)
(Annex 2.1.4 Option 0)
Regional sizing and procurement of balancing
reserves, daily procurement of upward/downward
products
(Annex 2.1.4 Option 2)
European sizing and procurement of
balancing reserves, daily procurement of
upward/downward products
(Annex 2.1.4 Option 3)
+ Remove distortions for
liquid short-term
markets
(Annex 2.2)
National non-harmonised intraday markets
(Annex 2.2.4 Option 0)
Selected harmonisation of national intraday markets
of gate closure times and products, with gradual
implementation
(Annex 2.2.4 Option 2)
Full harmonisation and coupling of
intraday markets
(Annex 2.2.4 Option 1)
+ TSO Co-operation
(Annex 2.3)
Regional Security Coordinators (RSCs) to perform
five tasks at regional level for national TSOs
(Annex 2.3.4 Option 0)
Upgrade RSCs to Regional Operational Centres
(ROCs) centralising additional functions over
relevant geographical areas
(Annex 2.3.4 Option 0)
Creation of Regional or EU Independent
System Operators
(Annex 2.3.4 Options 2 and 3)
+ Demand Response
(Annex 3.1)
Smart meter rollout remains limited in geographical scope and
functionalities, market barriers to aggregators persist, and the full
potential of demand response and self-consumption remains untapped
(Annex 3.1.4 Option 0)
Give consumers access to
enabling technologies that will
expose them to market price
signals and a common European
framework defining roles and
responsibilities of aggregators
(Annex 3.1.4 Option 2)
Mandatory smart meter roll out and full
EU framework for incentive based
demand response
(Annex 3.1.4 Option 3)
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Policy options
Specific Measures Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Option (a) +
Strengthening
short-term
markets
Option 1(a), 1(b) +
Demand response/distributed
resources
Fully integrated markets
+ Ensuring that DSOs
become active and
remain neutral towards
other market actors
(Annex 3.2)
Broad variety of national approaches to DSO roles and responsibilities
(Annex 3.2.4 Option 0)
Specific requirements and
conditions for 'active' DSOs;
Clarification of DSO's role in
specific tasks; Enhanced DSO-
TSO cooperation (Annex 3.2.4
Option 1)
EU framework for a specific set of DSO
tasks and stricter unbundling rules
(Annex 3.2.4 Option 2)
+ A performance-based
remuneration
framework for DSOs
(Annex 3.3)
Broad variety of national approaches to DSO compensation
(Annex 3.3.4 Option 0)
EU-wide principles on
remuneration schemes; NRAs
monitor the performance of
DSOs (Annex 3.3.4 Option 1)
Fully harmonize remuneration
methodologies (Annex 3.3.4 Option 2)
+ Distribution tariffs
that send accurate price
signals to grid users
(Annex 3.3)
Broad variety of national approaches to distribution tariffs
(Annex 3.3.4 Option 0)
EU wide principles to make
tariffs structures become more
transparent and more accurately
reflect the impact of each system
user on the grid, especially
during different times of the day;
NRAs to implement more
detailed requirements
(Annex 3.3.4 Option 1)
Fully harmonize distribution tariff
structures through concrete requirements
(Annex 3.3.4 Option 2)
+ Adapting Institutional
Framework to reality of
integrated markets
(Annex 3.4 institutional
framework)
Retain Status Quo (no
change)
(Annex 3.4.4 Option 0)
Adapt institutional framework to the new realities of the electricity system
and the resulting need for additional regional cooperation and to address
regulatory gaps (relevant to each respective policy sub-option)
(Annex 3.4.4 Option 1)
Restructure the EU Institutional
Framework providing for more
centralised institutional structures
(Annex 3.4.4 Option 2)
112
Policy options
5.2. Options to address Problem Area II (Uncertainty about sufficient future
generation investments and uncoordinated capacity markets)
Overview of the policy options
5.2.1.
A number of Member States anticipate inadequate generation capacity in future years and
plan to introduce or have already introduced unilateraly, unaligned capacity mechanisms.
Capacity mechanisms remunerate the guaranteed availability of electricity resources (e.g.
generation or demand response) rather than paying for electricity actually delivered. The
current regulatory market design does provide for rules on capacity mechanisms185
.
While it does not prohibit nor encourage capacity mechanisms, the Third Package is, in
principle, built on the concept of an "energy-only" market, in which generators are
remunerated mainly based on the energy delivered186
. Undistorted cross-border markets
should provide for the necessary investment signals to ensure stable generation at all
times. Price signals should drive production and investment decisions, whereas price
differentials between different bidding zones should determine where facilities should
ideally be located, provided that all assets are treated equally in terms of the risks and
costs to which they are exposed and the opportunities for earning revenues from
producing electricity i.e. they operate within a level playing field.
Several Options will be considered to address the concerns regarding investment
certainty and fragmented approaches to CMs:
Box 5: Overview of the Policy Options for Problem Area II
Each policy option consists of a package of measures which act upon the drivers of the
problem. Some of the options differ according to whether generators can only rely on
energy market payments or whether they receive additional remuneration from CMs.
Option 1 (Improved energy-only markets) would be based on additional measures to
185
Capacity markets are only indirectly addressed, e.g. through the obligation for Member States under
the Third Package to maximise cross-border capacities (see e.g. Art. 16 (3) of Regulation 714/2009)
and to avoid unnecessary limitations of cross-border flows, e.g. through State Interventions.
186
It may be noted that generators can receive additional revenues from providing frequency reserves,
which could be described as a form of (short-term) capacity markets.
113
Policy options
further strengthen the internal electricity market (complementing the measures described
above in options 1(a) (level playing field), 1(b) (strengthening short-term markets) and
(c) (demand response/distributed resources) presented in Problem Area I). Under this
option, CMs would no longer be allowed. Option 2 and 3 would also include the
proposed measures to strengthen the internal energy market as presented in Option 1, but
also propose possible measures to better align national CMs. The possibility to set up a
mandatory EU-wide CM is described in Option 4.
The following sub-sections describe the policy options and the packages of measures
they comprise. It then explains which options can be discarded at this stage, prior to
assessment, as well as present other options that were considered but were discarded
from the beginning. A table summarising all specific measures for each option is
provided at the end of this section.
The relevant Annexes addressing the policy options below are: 4.1 to 5.2.
Option 0: Baseline Scenario – Current Market Arrangements
5.2.2.
Under the baseline scenario, price formation on electricity wholesale markets is
constrained, e.g. through price caps. Prices may not be able to reach levels which truly
reflect the value of energy when the demand and supply balance is tight and, hence,
electricity is scarce. Therefore price signals from wholesale markets would, in times of
scarcity, be distorted and revenue streams of generators cannot properly reflect their
value to the system. This affects, in particular, the remuneration of assets that can provide
flexibility to the electricity system, regardless to whether this concerns flexible
generation capacity, electricity storage or demand response.
At this stage most electricity markets in Europe face generation overcapacities. In this
situation, price caps do in practice not matter – scarcity prices cannot be expected
anyway. However, once old capacities will have exited the market and the power mix has
adjusted (see in this regard the analyses presented in section 6.2.6.3), true price formation
would be essential to produce signals for new investments. This could not happen as long
as price caps exist.
Price signals are also not aligned with structural congestion in the transmission grid, thus
not revealing the locations where investments would relieve congestion and production
decisions. TSOs then can only operate sub-optimally the existing network and need to
take frequent congestion management measures. Although the CACM Guideline
provides a process for reviewing price or bidding zones, the current process lends itself to
maintaining the status quo (mostly price zones along Member State borders), making this
the most plausible assumption for the baseline. This is because there are likely to be
competing interests at stake. In particular, some Member States are unlikely to want to
amend bidding zones where it would create price differentials within their borders; it is
sometimes considered to be right for all consumers to pay the same price within a
114
Policy options
Member State, and for all producers to receive the same price. The current legislation
does not, therefore, provide for the socially optimal solution to be agreed.187
Based on perceived or real resource adequacy concerns, several Member States take
actions concerning the introduction of national resource adequacy measures or the
imposition of regulatory barriers to decommissioning. These measures are usually based
on national resource adequacy assessments and projections, which may substantially
differ depending on the underlying assumptions made and the extent to which foreign
capacities as well as demand side flexibility are taken into account in calculations. Some
of these concerns and projections are a result of the current market arrangements.
The Commission's current tool to assess whether government interventions in support of
resource adequacy are legitimate is state aid scrutiny. The EEAG require among others a
proof that the measure is necessary, technological neutral and allows for explicit cross-
border participation. However, the EEAG do not clarify how an effective cross-border
CM regime could be deployed.
The baseline is common with the one presented in 5.1.2, with only two differences: (a)
presence of price caps based on current practices and (b) existence of structural
congestion in the transmission grid.
Stakeholders' opinions: None of the respondents to the public consultation took the
view that the current market arrangements were sufficient and no further measures are
required.
Option 0+: Non-regulatory approach
5.2.3.
Whilst systematically considered188
, no such policy option could be identified.
This option would entail relying on existing legislation to improve the current market
arrangements. The likelihood of seeing any meaningful change as a result of this process
is minimal. Existing provisions under EU legislation are arguably not sufficiently clear
and robust. In this regard, the Evaluation report indicates that the rules of the Third
Energy Package appear to be insufficient to cope with the challenges facing the European
electricity system.189
In addition, certain areas, like resource adequacy, are not addressed
in the Third Package. Consequently, the Evaluation report concludes that the Third
Package does not not ensure sufficient incentives for private investments in the new
generation capacities and network because of the minor attention in it to effective short-
term markets and prices which would reflect actual scarcity.190
Voluntary cooperation has resulted in significant developments and a lot of benefits (e.g.,
the PLEF, whereby some Member States have voluntarily decided to cooperate and
187
For more details concerning the deficiencies of current legislation concerning bidding zone
configuration, see Sections 4.2.2 and 4.2.3 of Annex 4.2 to this Impact Assessment.
188
For each measure the opportunities for stronger enforcement has been assessed in the annexes.
189
See Section 7.3.1 and 7.3.3 of the Evaluation.
190
See Sections 7.3.2 of the Evaluation.
115
Policy options
deliver a regional resource adequacy assessment). However it may not provide for
appropriate levels of harmonisation across all Member States and certainty to the market
and legislation is needed in this area to address the issues in a consistent way.
Option 1: Improved energy market - no CMs
5.2.4.
Option 1 assumes that European electricity markets, if sufficiently interconnected and
undistorted, can provide for the necessary price signals to incentivise investments into
new generation. Wholesale markets would be strengthened by a set of specific measures
aiming at improving price signals so as to deliver the necessary investments based only
on price signals. CMs, whether at national, regional or European level would not be
justifiable to secure electricity supplies under this option as the market should be
incentivising investments.
Even if such price signals concern the spot price on the wholesale market corresponding
to the day-ahead market, these prices are the reference for the forward market and would
thus have a long-term effect. Having as a starting point the reformed market design as
described in section 5.1.4.3191
, it is additionaly assumed that no administrative
mechanisms directly affecting investments and price signals are allowed to be in place, in
the form of CMs or (below Value of Lost Load192
or 'VoLL') price caps. In the case of
the latter this would be effected by ensuring that any technical limits imposed by power
exchanges are merely that, and are raised in the event they are reached, and, in order to
provide maximum investor confidence, an end-date, after which such limits must not be
below VoLL.
The strengthened short and long-term markets and the participation of distributed
generation offer the necessary flexibility required to integrate variable RES E into the
market. Combined with the removal of (below VoLL) price caps,193
the market should be
able to drive investments towards the needed flexible assets, such as storage and demand
response, and sufficient generating capacity. Furthermore, proper incentives are
introduced aiming to unlock the flexibility that can be provided by existing assets, such
as demand response and storage.
At the same time price signals could drive the geographical location of new investments
and production decisions, via price zones aligned with structural congestion in the
transmission grid. The location of the price zone borders would be decided through a
robust regulatory decision-making process. Price differentials between these price zones
should help determine where investments are needed and make the best use of natural
resources (particularly important for RES E, but also for interconnectors) and, for those
assets already deployed, which one will be producing. Such locational prices would also
provide efficient signals for the location of demand – for example new energy intensive
industries would choose to locate in areas where there is excess generation and therefore
191
Sub-option 1(c) (demand response/distributed resources) from problem area I was used as the basis
here, as it was identified as the preferred option when comparing the respective options in Section 7.1.
192
Value of Lost Load is a projected value reflecting the maximum price consumers are willing to pay to
be supplied with electricity
193
For more detail on policy measures related to the removal of price caps, refer to Annex 4.1.
116
Policy options
low prices.194
Measures would also be taken to further restrict the practice of limiting
cross-border capacity in order to deal with internal network contraints and, finally,
measures would be taken to minimise, in the long-term, the most significant investment
and operational distortions on generators arising as a result of network charges.195
Stakeholder's opinions: A majority of answering stakeholders is in favour an "energy-
only" market (possibly augmented however with a strategic reserve, which is a form of a
capacity market). Many stakeholders share the view that properly designed energy
markets would make capacity mechanisms gradually redundant. Many generators and
some governments disagree and are in favour of capacity remuneration mechanisms
(assessed in Options 2, 3 and 4).
A large majority of stakeholders agreed that scarcity pricing is an important element in
the future market design. While single answers point at risks of more volatile pricing and
price peaks (e.g. political acceptance, abuse of market power), others stress that those
respective risks can be avoided (e.g. by hedging against volatility).
A large number of stakeholders agreed that scarcity pricing should not only relate to
time, but also to locational differences in scarcity (e.g. by meaningful price zones or
locational transmission pricing). While some stakeholders criticised the current price
zone practice for not reflecting actual scarcity and congestions within bidding zones,
leading to missing investment signals for generation, new grid connections and to
limitations of cross-border flows, others recalled the complexity of prices zone changes
and argued that large price zones would increase liquidity.
Many submissions highlight the crucial role of scarcity pricing for kick-starting demand
response at industrial and household level.
European Parliament:"…[N]ational capacity markets make it harder to integrate
electricity markets and run contrary to the objectives of the common energy policy, and
should only be used as a last resort once all other options have been considered,
including increased interconnection with neighbouring countries, demand-side response
measures and other forms of regional market integration[.]"196
"European Parliament
[…] [i]s sceptical of purely national and non-market-based capacity mechanisms and
markets, which are incompatible with the principles of an internal energy market and
which lead to market distortions, indirect subsidies for mature technologies and high
costs for end-consumers; stresses, therefore, that any capacity mechanism in the EU
must be designed from the perspective of cross-border cooperation following the
completion of thorough studies on its necessity, and must comply with EU rules on
competition and State aid; believes that better integration of national energy production
194
For more detail on policy measures related to the improvement of locational signals, refer to Annex
4.2.
195
For more detail, refer to Annexes 4.3 and 4.4.
196
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, Recital H.
117
Policy options
into the EU energy system and the reinforcement of interconnections could reduce the
need for, and cost of, capacity mechanisms[.]"197
Option 2: Improved energy market – CMs only when needed, based on a common
5.2.5.
EU-wide adequacy assessment)198
This Option includes the measures to strenghten the internal energy market (as described
in Option 1 above), i.e. every Member State is assumed to have in place a well-
functioning energy market.
In addition to Option 1 however, Member States would be allowed to implement national
CMs, but only under certain conditions. Additional measures are proposed in order to
avoid negative consequences of uncoordinated CMs for the functioning of the internal
market, building on the EEAG' state aid Guidelines and the Sector Inquiry on CMs.
To address the problem of diverging and purely national assessments of the needs for
CMs, ENTSO-E would be required under this option to propose a methodology for an
EU-wide resource adequacy assessment. The upgraded methodology should be based on
transparent and common assumptions199
and ENTSO-E would carry out the assessment
anually. The prerequisite for a Member State to implement a CM or prohibit capacity
from exiting the market would be that ENTSO-E's assessment indicated a lack of
generation capacity and where markets cannot be expected to close the gap. This would
avoid that back-up capacities are developed based on a purely national perspective (i.e.
national adequacy assessments, using different methodologies and not taking into
account the generation potential across borders).
When proposing or applying CMs, Member States would need to introduce resource
adequacy targets, which can be diverging (as an expression of their diverging preference
for resource adequacy). The standards should be expressed in a unique format to become
comparable across the EU – as Expected Energy Non Served ('EENS'), and it should be
derived following a methodology provided by ENTSO-E which takes into account the
value that average customers in each bidding zone put on electricity supplies (Value of
Lost Load – 'VoLL').
197
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 24.
198
Further elements of this option are presented in Annex 5.1.
199
The ENTSO-E assessment should have the following characteristics:
i. It should cover all Member States
ii. It should have a granularity of Member State/ bidding zone level to enable the analysis of
national/ local adequacy concerns;
iii. It should apply probabilistic calculations that consider dynamic characteristics of system elements
(e.g. start-up and shut-down times, ramp up and ramp-down rates…)
iv. It should calculate generation adequacy indicators for all countries (LOLE, EENS, etc.)
v. It should appropriately take into account foreign generation, interconnection capacity, RES ,
storage and demand response
vii. Time span of 5-10 years
118
Policy options
Stakeholders' opinions: There is almost a consensus amongst stakeholders on the need
for a more aligned method for resource adequacy assessment. A majority of answering
stakeholders supports the idea that any legitimate claim to introduce CMs should be
based on a common methodology. When it comes to the geographical scope of the
harmonized assessment, a vast majority stakeholders call for regional or EU-wide
resource adequacy assessment, while only a minority favour a national approach. There
is also support for the idea to align adequacy standards across Member States.
European Parliament: "[…]stresses the importance of a common analysis of resource
adequacy at regional level, facilitated by the Agency for the Cooperation of Energy
Regulators (ACER) and the European Network of Transmission System Operators
(ENTSO-E), and calls for the transmission system operators (TSOs) of neighbouring
markets to devise a common methodology, approved by the Commission, to that end;
highlights the enormous potential of strengthened regional cooperation[…]"200
Council: "Member States considering implementing capacity mechanism should take
into account synergies of cross-border regional cooperation and avoid any disincentive
for investment in interconnection, while minimising market distortion"201
.
Option 3: Improved energy market - CMs only when needed, based on a common
5.2.6.
EU-wide adequacy assessment, plus cross-border participation202
Option 3 includes the measures to strenghten the internal energy market as described in
Option 1 above. It also includes the requirement for national CMs to be justified by a
European adequacy assessment (see Option 2). In addition, Option 3 would however
provide for design rules for better compatibility between national CMs, also building on
the EEAG state aid guidelines and the Sector Inquiry on CMs notably in order to
facilitate cross-border participation ('blue-print') .
To date, in order to comply with EEAG, Member States have to individually organise,
for each of their borders separately, the necessary cross-border arrangements involving a
multitude of parties (e.g. resource providers, regulators, TSOs).
This option would provide a harmonised cross-border participation scheme across the EU
by setting out procedures including roles and responsibilities for the involved parties (e.g.
resource providers, regulators, TSOs).
200
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 14.
201
See "Messages from the Presidency on electricity market design and regional cooperation" (2016),
Note to the Permanent Representatives Committee/Council, Page 2.
http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf
202
Further elements of this option are presented in Annex 5.
119
Policy options
Stakeholders' opinions: Most of the stakeholders including Member States agree that a
regional/European framework for CMs are preferable. Indeed, 85% of market participant
respondents and 75% of public body respondents to the sector inquiry on Capacity
Mechanisms203
felt that rules should be developed at EU level to limit as much as
possible any distortive impact of CMs on cross national integration of energy markets.
Member States might instinctively want to rely more on national assets and favour them
over cross-border assets. It is often claimed that in times of simultaneous stress,
governments might choose to 'close borders' putting other Member States who might
actually be in bigger need in trouble.
European Parliament: "[…][c]alls for cross-border capacity mechanisms to be
authorised only when the following criteria, inter alia, are met: a. the need for them is
confirmed by a detailed regional adequacy analysis of the production and supply
situation, including interconnections, storage, demand-side response and cross-border
generation resources, on the basis of a homogeneous, standardised and transparent EU-
wide methodology which identifies a clear risk to uninterrupted supply; b. there is no
possible alternative measure that is less costly and less market-intrusive, such as full
regional market integration without restriction of cross-border exchanges, combined
with targeted network/strategic reserves; c. their design is market-based and is such that
they are non-discriminatory in respect of the use of electricity storage technologies,
aggregated demand-side response, stable sources of renewable energy and participation
by undertakings in other Member States, so that there is no cross-border cross-
subsidisation or discrimination against industry or other customers, and it is ensured
that they only remunerate the capacity strictly necessary for security of supply; d. their
design includes rules to ensure that capacity is allocated sufficiently in advance to
provide adequate investment signals in respect of less polluting plants; e. sustainability
and air quality rules are incorporated in order to eliminate the most polluting
technologies (consideration could be given to an emissions performance standard in this
connection) […]"204
Option 4: Mandatory EU-wide or regional CMs
5.2.7.
Under this option based on regional or EU-wide resource adequacy assessments, entire
regions or ultimately all EU Member States would be required to roll-out CMs on a
mandatory basis. The design of the CMs would follow a EU 'blue print' (i.e. a set of
design requirements for CMs), with the required resource adequacy target to be set at
regional or EU level. This approach would assess and address adequacy concerns at a
regional or EU level. Decisions on whether to introduce CMs or not would no longer be
left with individual Member States, but an EU-wide CM would be created, as a
mandatory additional layer to the "energy-only" market. Differences between Member
States (e.g. whether all areas within larger regions actually face adequacy challenges, or
network congestions) would not justify exception from the obligation to introduce a CM.
203
"Interim Report of the Sector Inquiry on Capacity Mechanisms" SWD(2016) 119 final.
http://ec.europa.eu/competition/sectors/energy/capacity_mechanisms_swd_en.pdf
204
European Parliament, Report on Towards a New Energy Market Design (2015/2322(INI)), Committee
on Industry, Research and Energy, 21.6.2016, § 25.
120
Policy options
Discarded Options
5.2.8.
Option 0+ will not be further analysed as no means were identified to implement it.
Option 4 does not consider the significant regional differences when it comes to resource
adequacy. The EU-wide or region-wide roll-out would disregard existing congestions in
the European network and it would consequently over- or underestimate the resource
adequacy in single bidding zones/ Member States belonging to a wider region. As a result
CMs might need to be introduced in bidding zones/Member States that do not face any
adequacy concerns. Alternatively, emerging resource adequacy problems in certain
bidding zones/Member States might not be identified and addressed appropriately. In
addition, as a number of Member States rely on energy-only markets to provide for the
necessary investments in their power systems it would not be appropriate to force them to
adopt CMs.
Summary of specific measures comprising each Option
5.2.9.
The following table summarizes the specific measures comprising each package of
measures, as well the corresponding specific measure option considered under each high
level option205
. The detailed presentation and assessment of each measure can be found
in the indicated Annex.
205
The preferred options for the specific measures set out in the annex are highlighted in the table in
green.
121
Policy options
Table 7: Summary of Specific Measures Examined for Problem Area II
Specific Measures Option 0 Option 1 Option 2 Option 3 Option 4
Baseline (Current market
arrangements)
Improved
energy
market/ no
CM
Improved energy
market/ CMs only
when needed, based
on a common EU-
wide adequacy
assessment)
Improved energy market/ CMs
only when needed, plus cross-
border participation)
Mandatory EU-wide or regional
CMs
Specific Measures related to the
Energy Market
As in section 5.1.2 As in section 5.1.4.3
+ Price Caps
(Annex 4.1)
Lower than VoLL
(Annex 4.1.4 Option 0)
At VoLL
(Annex 4.1.4 Option 2)
+ Locational Price Signals
(Annex 4.2)
Price Zones defined based on
arrangements in CACM Guideline
(4.2.4 Option 0)
Strengthened process for deciding on price zones, leading to the definition
of zones based on systematic congestion in networks
(4.2.4 Option 3)
Nodal Pricing
(4.2.4 Option 1)
+ Transmission Tariff Structures
(Annex 4.3)
Limited harmonisation of the
methodologies setting
transmission tariffs
(Annex 4.3.4 Option 0)
More concrete principles on the setting of transmission tariffs and other
network charges.
(Annex 4.3.4 Option 2)
Full harmonisation of the
methodologies setting
transmission tariffs
(Annex 4.3.4 Option 3)
+ Congestion Income (Annex
4.4)
Limited restrictions on the use of
congestion income
(Annex 4.4.4 Option 0)
Further prescription on the use of congestion income, with the aim of an even more European approach
(Annex 4.4.4 Option 1)
+ Resource Adequacy Plans
(Annex 5.1)
National plans following different methodologies
(Annex 5.1.4 Option 0)
Common EU-wide assessment by ENTSO-E becomes the basis for MS to introduce CMs
(Annex 5.1.4 Option 3)
+ Cross-border Participation of
CMs
(Annex 5.2)
No EU framework with rules for
cross-border participation
(Annex 5.2.4 Option 0)
N/A
No EU framework
with rules for cross-
border participation
(Annex 5.2.4 Option
0)
Harmonized EU framework for cross-border participation
(Annex 5.2.4 Option 1)
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Policy options
5.3. Options to address Problem Area III (When preparing or managing crisis
situations, Member States tend to disregard the situation across their
borders)
Overview of the policy options
5.3.1.
With the intention to meet the objectives set out in the previous section, the Commission
services have identified several policy options ranging from an enhanced implementation
of the existing legislation to the full harmonization and decision making at regional level.
Option 0 represents the baseline or the measures currently in place. Each policy option
consists of a package of measures combining existing tools, possible updated and
improved tools and new tools which act upon the drivers of the problem. This section
finalizes with a table summarising all specific measures comprising each option.
The relevant Annex addressing the policy options below is Annex 6.
Table 8: Overview of the Policy Options for Problem Area III
Option 0: Baseline scenario – Purely national approach to electricity crises
5.3.2.
Under the baseline scenario, Member States would continue identifying and addressing
possible crisis situations based on a national approach, in accordance with their own
national rules and requirements.
There would be no rules or structures facilitating and guaranteeing a proper identification
of cross-border crisis situations206
and ensuring that Member States take the necessary
action to deal with them, in co-operation with one another. Whilst some co-operation
between Member states could take place (e.g., between the Nordic countries as well as
206
In the framework of the SESAME project (which was financed under FP7) tools were developed for
the identification of grid and production plants vulnerabilities and for estimating the damage resulting
from network failures. However, this project had a more national focus (in particular on Romania and
Austria) and the identification and management of cross-border crisis was outside the scope of this
project (https://www.sesame-project.eu/).
123
Policy options
within the context of the PLEF207
), in practice such cooperation would remain entirely
voluntary, and might be hampered in practice by different national rules and procedures,
and a lack of appropriate structures at regional and EU level.
Innovative tools208
have been also developed for TSOs in the area of the system security
in the last years, improving monitoring, prediction and managing secure interconnected
power systems and preventing, in particular, cascading failures209
. In addition, the
recently adopted network codes and guidelines bring a certain degree of harmonisation
on how to deal with electricity systems in different states (normal state, alert state,
emergency state, black-out and restoration) and should bring more clarity as to how
TSOs should act in crisis situations, and as to how they should co-operate with one
another. However, network codes and guidelines focus on technical issues and co-
operation between TSOs (in implementation of the current legal framework). They do not
offer a framework ensuring a proper co-ordination and co-operation between Member
States on how to prepare for and handle electricity crisis situations, in particular in
situations of simultaneous scarcity.210
For instance, political decisions such as where to curtail, to whom and when, would still
be taken nationally, by reference to very different national rules and regulations. In
addition, any cross-border assistance in times of crisis would be hampered by a lack of
common principles and rules governing co-operation, assistance and cost compensation.
Finally, risks would still assessed and adressed on the basis of very different methods,
and from a national perspective only.
Stakeholders' opinions: Stakeholders agree that the current framework does not offer
sufficient guarantees that electricity crisis situations are properly prepared for and
handled in Europe. They also take the view that, whilst network codes and guidelines
will offer some solutions at the technical level, there is a need for a better alignment of
national rules and cooperation at the political level211
.
207
Pentalateral Energy Forum, consisting of the Ministries, NRAs and TSOs of BENELUX, Germany,
France, Austria, Switzerland.
208
ITESLA project (which was financed under FP7) developed methods and tools for the coordinated
operational planning of power transmission systems, to cope with increased uncertainties and
variability of power flows, with fast fluctuations in the power system as a result of the increased share
of resources connected through power electronics, and with increasing cross-border flows. The project
shows that the reliance on risk-based approaches for corrective actions can avoid costly preventive
measures such as re-dispatching or reduced the overall risk of failure.
209
In addition the AFTER project (which was financed under FP7) also developed tools for TSOs to
increase their capabilities in creating, monitoring and managing secure interconnected electrical power
system infrastructures, being able to survive major failures and to efficiently restore service supply
after major disruptions (http://www.after-project.eu/).
210
In addition, whilst the guidelines and codes require TSOs to co-operate, they do not require them to
engage in joint action (e.g. through the ROCs).
211
See for examle the answers to the public consultation of the International Energy Agency, ENTSO-E.
124
Policy options
Option 0+: Non-regulatory approach
5.3.3.
As current legislative framework established by the SoS Directive set general principles
rather than requires Member States to take concrete measures, better implementation and
enforcement actions will be of no avail.
In fact, as the progress report of 2010 shows212
, the SoS Directive has been implemented
across Europe, but such implementation did not result in better co-ordinated or clearer
national policies regarding risk preparedness.
In addition, the evaluation of the SoS Directive has revealed the existence of numerous
deficiencies in the current legal framework213
. It highlights the ineffectiveness of the SoS
Directive in achieving the objectives pursued, notably contributing to a better security of
supply in Europe. Whilst some of its provisions have been overtaken by subsequent
legislation (notably the Third Package and the TEN-E Regulation), there are still
regulatory gaps notably when it comes to preventing and managing crisis situations.
The evaluation also reveals that the SoS Directive intervention is no longer relevant
today as it does not match the current needs on security of supply. As electricity systems
are increasingly interlinked, purely national approaches to preventing and managing
crisis situations can no longer be considered appropriate. It also concludes that its added
value has been very limited as it created a general framework but left it by and large to
Member States to define their own security of supply standard. Whilst electricity markets
are increasingly intertwined within Europe, there is still no common European
framework governing the prevention and mitigation of electricity crisis situations.
National authorities tend to decide, one-sidedly, on the degree of security they deem
desirable, on how to assess risks (including emerging ones, such as cyber-security) and
on what measures to take to prevent or mitigate them.
The recently adopted network codes and guidelines offer some improvements at the
technical level, but do not address the main problems identified.
In addition, today voluntary cooperation in prevention and crisis management is scarce
across Europe and where it takes place at all, it is often limited to cooperation at the level
of TSOs. It is true that certain Member States collaborate on a voluntary basis in order to
addresss certain of the problems identified (e.g. Nord-BER, PLEF). However, these
initiatives have different levels of ambition and effectiveness, and they geografically
cover only part of the EU electricity market. Therefore, voluntary cooperation will not be
an effective tool to solve the problems identified timely in the whole EU.
212
Report on the progress concerning measures to safeguard security of electricity supply and
infrastructure investment COM (2010) 330 final.
213
See Evaluation of the EU rules on measures to safeguard security of electricity supply and
infrastructure investment (Directive 2005/89/EC).
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Policy options
Option 1: Common minimum rules to be implemented by Member States
5.3.4.
Under Option 1, Member States would have to respect a set of common rules and
principles regarding crisis prevention and management, agreed at the European level
('minimum harmonisation'). In particular, Member States would be obliged to develop
national Risk Preparedness Plans ('Plan') with the aim to avoid or better tackle crisis
situations. Plans could be prepared by TSOs, but need to be endorsed at the political
level. Plans should be based on an assessment of the most relevant crisis scenarios
originated by rare/extreme risks. Such assesment would be carried out in a national
context (as is the case today), but would have to based on a common set of rules. In
particular, Member States would be required, for instance, to consider at least the
following risks: a) rare/extreme natural hazards, b) accidental hazards which go beyond
N-1, c) consequential hazards such as fuel shortage, d) malicious attacks (terrorist
attacks, cyberattacks).
Plans would have to respect a set of common minimum requirements. They would need
to set out who does what to prevent and to manage crisis situations, including in a
situation of a crisis affecting more than one countrry at the same time. More specifically
on cybersecurity, Member States would need to set out in the Plans how they will
prevent and manage cyberattack situations. This would be combined with soft guidance
on cybersecurity in the energy sector, based on the NIS Directive214
. Member States
would also be required to set out how they ensure that assets that are important from a
security of supply perspective, are protected against undue influences in case ownership
control changes.
Plans should be adopted by relevant governments / ministries, following an inclusive
process, and (at least some parts of the Plans) should be rendered public. Plans should be
updated on a regular basis.
In addition, under Option 1 there would be new common rules and principles
governing crisis management, in replacement of the current Article 42 of the Electricity
Directive, which allows Member States to take 'safeguard measures' in crisis situations.
All crisis management actions (whether taken at the level of the TSOs or at the level of
governments) would need to respect three principles:
- 'Market comes first': Non-market measures (such as obligatory demand reduction
schemes) should only be introduced as a means of last resort, when duly justified,
and should be temporary in nature. Use of such measures should not undermine
market and system functioning;
- 'Duty to offer assistance': Member States would be obliged to address electricity
crisis situations, in particular situations of a simultaneous crisis, in a spirit of co-
operation and solidarity. This means agreeing in advance on practical solutions on
214
Directive (EU) 2016/1148 of the European Parliament and of the Council of 6 July 2016 concerning
measures for a high common level of security of network and information systems across the Union,
OJ L 194, 19.07.2016, p. 1-30.
126
Policy options
e.g. where to shed load and how much in cross-border crisis situations, subject to
financial compension (which is also to be agreed upon in advance).
- 'Transparency and information exchange': Member States should inform each
other and the Commission without undue delay when they see a crisis situation
coming (e.g., as a result of a seasonal outlook pointing at upcoming problems) or
when being in a crisis situation. They should also be transparent about measures
taken and their effect, both when taking them and afterwards.
The main benefits this option would bring is better preparedness, due to the fact that a
common approach is followed across Europe, thus excluding the risk that some Member
States being 'under-prepare'. In addition, better preparedness is likely to reduce the
chances of premature market interventions, where Member States act in a transparent
manner and on the basis of a clear set of rules. By imposing obligations to cooperate and
lend assistance, Member States are also less likely to 'over-protect' themselves against
possible crisis situations, which in turn will contribute to more security of supply at a
lesser cost. Since a 'minimum' harmonisation approach would be followed, Member
States would have still room to take account of national specificities, where needed and
appropriate.
Stakeholders' opinions: A large majority of stakeholders is in favour of risk
preparedness plans based on common rules and principles, as a tool to ensure a more
common and more transparent approach. Consulted stakeholders215
agree on the need for
a common approach what Member States can do in crisis situations and call for more
transparency.
Option 2: Common minimum rules to be implemented by Member States, plus
5.3.5.
regional co-operation
Option 2 would build on Option 1. It would include all common rules included in Option
1 (i.e., define a set of minimum obligations Member States would need to respect). In
addition, it would put in place rules and tools to ensure that effective cross-border co-
operation takes place, in a regional and EU context. Given the interlinked nature of EU's
electricity systems, enhanced regional co-operation brings clear benefits when it comes
to preventing and managing crisis situations.
First, under Option 2, there would be a systematic assessment of rare/ extreme risks at
the regional level. The identification of crisis scenarios would be carried out by ENTSO-
E, who would carry out such assessments in a regional context. To achieve this, ENTSO-
E would be able to delegate all or part of its tasks to the ROCs. This regional approach
would ensure that the risks originating across borders, including scenarios of a possible
simultaneous crisis, are taken into account. The crisis scenarios identified by ENTSO-E
would be also discussed in the Electricity Coordination Group, to ensure that a coherent
and transparent approach is followed across Europe. For cybersecurity, building on
Option 1, the Commission would propose the development of a network code/guidelines
215
See for example the Public Consultation answers of the Dutch and Latvian Governments, GEODE,
CEDEC, EDF UK, TenneT, Eurelectric and Europex welcoming risk preparendess plans.
127
Policy options
which would ensure a minimum level of harmonization in the energy sector throughout
the EU216.
The Risk Preparedness Plans would contain two parts – a part reflecting national
measures and a part reflecting measures to be pre-agreed in a regional context. The
latter part includes in particular preparatory measures such as simulations of
simultaneous crisis situations in neighbouring Member States ("stress tests" in regional
context organised by ENTSO-E who can delegate all or part of its tasks to the ROCs);
procedures for cooperation with other Member States in different crisis scenarios, as
well as agreements on how to deal with simultaneous electricity crisis situations.
Through such regional agreements, Member States would be required to define in
advance, in a regional context, how information will be shared, how they will ensure that
markets can work as long as possible, and what kind of assistance will be offered accross
borders, For instance, Member States would be required to agree in advance in which
situations and according to what priorities customers would be curtailed in simultaneous
crisis situations. The regional coordination of plans would build trust and confidence
between Member States, which is crucial in times of crisis. It would also allow
optimising scarce resources in times of crisis, whilst ensuring that markets can work as
long as possible.
The regional parts of the Plans should be pre-agreed in a regional context. Such
regionally co-ordinated plans would help ensure that increased TSO cooperation is
effectively matched by a more structured cooperation between Member States.217
For this
reason, Member States would be called upon to co-operate and agree in the context of the
same regional settings as are used for the ROCs. Effective regional co-operation and
agreements would help ensure that electricity crisis situations are dealt with in the most
effective manner, whilst respecting the needs of electricity consumers and systems at
large.
To facilitate cross-border cooperation, Member States should designate one 'competent
authority', belonging either to the national administration or to the NRA.
Additionally, ENTSO-E would be required to develop a common method for carrying
out short-term risk assessments, to be used in the context of seasonal outlooks and
weekly risk assessments by TSOs.
To allow for a precise monitoring, ex-ante and ex-post, of how well Member States'
systems perform in the area of security of supply, harmonised security of supply
216
The network code/guidelines should take into account at least: a) methodology to identify operators of
essential services for the energy sector; b) risk classification scheme; c) minimum cyber-security
prerequisites to ensure that the identified operators of essential services for the energy sector follow
minimum rules to protect and respond to impacts on operational network security taking the identified
risks into account. A harmonized procedure for incident reporting for the energy sector shall be part of
the minimum prerequisites.
217
For cases of crisis, in particular simultaneous scarcity, also ENTSO-E sees a need for "not only on a
technical level but political cooperation" and plans which "should cover extreme crisis situations
beyond the measures provided by e.g. network codes and RSCs services" (Source: ENTSO-E (2016):
"Recommendations to the regulatory framework on risk preparedness (WS5)").
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Policy options
indicators would be introduced, as well as obligation on Member States to inform the
Electricity Coordination Group and the Commission on crisis situations, their
impact and the measures taken. This would enhance transparency, comparability and
mutual trust in neighbours.
Further, in this option, the role of the Electricity Coordination Group218
would be
reinforced, so that it can act as an effective forum to monitor security of supply in Europe
and oversee the way (possible) electricity crisis situations are dealt with. For instance, the
Group would be asked to review the cross-border crisis scenario's developed by ENTSO-
E and to review ex ante risk preparedness plans put in place by Member States. The
Group could issue recommendations and develop best practice. Overall, the
reinforcement of its tasks and powers would contribute to enhance cooperation and to
build trust and confidence among Member States.
Figure 7: Overview of measures in Option 2
218
The members of the Electricity Coordination Group are Member States authorities (ministries
competent for Energy), National Regulatory Authorities, ACER and ENTSO-E.
Source: DG ENER
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Policy options
Stakeholders' opinions: The majority of consulted stakeholders are in favour of regional
coodination of risk preparedness plans219
and a stronger co-ordinating role of the
Electricity Coordination Group220
. Various stakeholders make the case for a common
methodology for assessing risks in various time horizons, to detect cross-border crisis
situations and guarantee comparability of results221
. Several stakeholders also see a need
for clear rules and ex-ante cross-border agreements to ensure that markets function as
long as possible in (simultaneous) crisis situations222
.
The European Electricity Regulatory Forum, Florence: The Florence Forum
welcomes a more co-ordinated approach to risk preparedness based on risk preparendess
plans and a common framework for how to deal with (simultaneous) crisis situations,
including the principle that the market should act first223
.
"The Forum recognises the need for more co-ordination across Member States and
clearer rules on coping with electricity crisis situations. It encourages the Commission to
quickly bring the draft Emergency and Restoration Network Code forward for discussion
with the Member States. It also welcomes the Commission's work on a new proposal on
risk preparedness in the electricity sector and considers that risk preparedness plans and
common framework for how to deal with critical situations should be its key builing
blocks. It stresses the need that all action on risk preparedness should respect the
principle that the market should act first."
The European Parliament224
calls for more regional co-operation, notably as regards
'action to be taken in the event of an electricity crisis, in particular when such a crisis
has cross-border effects,' and calls on the Commission 'to propose a revised framework
to that end".
Council: The Council recognizes the responsibility of Member States for ensuring
security of supply but sees a "benefit from a more coordinated and efficient approach",
"a necessity to work on a further harmonization of of methods for assessing norms and
indicators for security of supply" and "a need to develop a more common approach to
preparing for and managing crisis situations within the EU".225
219
See for example the Public Consultation answers of the Finish, Dutch, Norwegian governments,
TenneT and the German Association of Local Utilities.
220
See for example the Public Consultation answers of the Dutch government and ENTSO-E.
221
See for example the Public Consultation answers of the Dutch government, EDF, ENTSO-E.
222
See for example ENTSO-E's presentation on Capacity Mechanisms (TOP 2.4) from the Florence
Forum in June 2016 (available here: https://ec.europa.eu/energy/en/events/meeting-european-
electricity-regulatory-forum-florence).
223
See conclusions from Florence Forum, March 2016, paragraph 10.
224
See European Parliament: Towards a New Energy Market Design (2016), Werner Langen, paragraph
68.
225
See Messages from the Presidency on electricity market design and regional cooperation (2016), Note
to the Permanent Representatives Committee/Council, paragraph 7.
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Policy options
Option 3: Full harmonisation and decision-making at regional level
5.3.6.
Building on Option 2, under Option 3 the risk preparedness plans would be developed
on regional level. This would allow a harmonised response to potential crisis situations
in each region. On cybersecurity, Option 3 would go one step further and nominate a
dedicated body (agency) to deal with cybersecurity in the energy sector. The creation of
the agency would guarantee full harmonisation on risk preparedness, communication,
coordination and a coordinated cross-border reaction on cyberincidents.
Crisis would have to be managed according to the regional plans agreed among
Member States. The Commission would determine the key elements of the regional plans
such as: commonly agreed regional load-shedding plans, rules on customer
categorisation, a harmonised definition of protected customers at regional level or
specific rules on crisis information exchanges in the region.
Regarding crisis handling, under Option 3, a detailed 'emergency rulebook' would be
put in place, containing an exhaustive list of measures that can be taken by Member
States in crisis situations, with detailed indications as regards what measures can be
taken, in what circumstances and when.
Stakeholders' opinions: The results of the public consultation showed that only few
stakeholders were in favour of regional or EU wide plans. Some stakeholders mentioned
the possibility to have plans on all three levels (national, regional and EU)226
.
Whilst stakeholders generally acknowledge the need for more commonality and more
regional co-operation on risk prevention and management, there is no support for a fully
harmonised approach based on rulebooks227
.
Discarded Options
5.3.7.
Option 0+ was disregarded as no means for enhanced implementing of the existing
acquis were identified.
Summary of specific measures comprising each Option
5.3.8.
The following table summarizes the specific measures to be taken under each option 228
.
A more detailed discussion can be found in annex.
226
See for example the Public Consultation answers of Latvian government, EDSO, GEODE, Europex.
227
See for example the Public Consultation answers of the Finish and German governments.
228
The preferred options for the specific measures set out in the annex are highlighted in the table in
green.
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Policy options
Table 8: Sumary of Specific Measures Examined for Problem Area III
Specific
Measures
Option 0 Option 0+ Option 1 Option 2 Option 3
Baseline Non-regulatory
approach
Common minimum EU rules for
prevention and crisis management
Common minimum EU rules plus regional
cooperation, building on Option 1
Full harmonisation and full
decision-making at regional
level, building on Option 2
Assessments
Rare/extreme risks
and short-term risks
related to security of
supply are assessed
from a national
perspective.
Risk identification &
assessment methods
differ across Member
States.
This option was
disregarded as no
means for
enhanced
implementing of
the existing acquis
nor for enhanced
voluntary
cooperation were
identified.
Member States to identify and assess
rare/extreme risks based on common risk
types.
ENTSO-E to identify cross-border electricity
crisis scenarios caused by rare/extreme risks, in
a regional context. Resulting crisis scenarios to
be discussed in the Electricity Coordination
Group.
Common methodology to be followed for
short-term risk assessments (ENTSO-E
Seasonal Outlooks and week-ahead
assessments of the RSCs).
All rare/extreme risks
undermining security of supply
assessed at the EU level, which
would be prevailing over
national assessment.
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Policy options
Plans
Member States take
measures to prevent
and prepare for
electricity crisis
situations focusing on
national approach,
and without
sufficiently taking
into account cross-
border impacts.
No common approach
to risk prevention &
preparation (e.g., no
common rules on how
to tackle
cybersecurity risks).
- - Member States to develop mandatory
national Risk Preparedness Plans setting
out who does what to prevent and
manage electricity crisis situations.
- Plans to be submitted to the Commission
and other Member States for
consultation.
- Plans need to respect common minimum
requirements. As regards cybersecurity,
specific guidance would be developed.
Mandatory Risk Preparedness Plans including
a national and a regional part. The regional part
should address cross-border issues (such as
joint crisis simulations, and joint arrangements
for how to deal with situations of simultaneous
crisis) and needs to be agreed by Member
States within a region.
Plans to be consulted with other Member States
in the relevant region and submitted for prior
consultation and recommendations by the
Electricity Coordination Group.
Member States to designate a 'competent
authority' as responsible body for coordination
and cross-border cooperation in crisis
situations.
Development of a network code/guideline
addressing specific rules to be followed for the
cybersecurity.
Extension of planning & cooperation
obligations to Energy Community partners.
Mandatory Regional Risk
Preparedness Plans, subject to
binding opinions from the
European Commission.
Detailed templates for the plans
to be followed.
A dedicated body would be
created to deal with
cybersecurity in the energy
sector.
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Policy options
Crisis
management
Each Member State
takes measures in
reaction to crisis
situations based on its
own national rules
and technical TSO
rules.
No co-ordination of
actions and measures
beyond the technical
(system operation)
level. In particular,
there are no rules on
how to coordinate
actions in
simultaneous crisis
situations between
adjacent markets.
No systematic
information-sharing
(beyond the technical
level).
Minimum common rules on crisis
prevention and management (including
the management of joint electricity crisis
situations) requiring Member States to:
(i) not to unduly interference with
markets;
(ii) to offer assistance to others where
needed, subject to financial
compensation, and to;
(iii) inform neighbouring Member States
and the Commission, as of the moment
that there are serious indications of an
upcoming crisis or during a crisis.
Minimum obligations as set out in Option 1.
Cooperation and assistance in crisis between
Member States, in particular simultaneous
crisis situations, should be agreed ex-ante; also
agreements needed regarding financial
compensation. This also includes agreements
on where to shed load, when and to whom.
Details of the cooperation and assistance
arrangements and resulting compensation
should be described in the Risk Preparedness
Plans.
Crisis is managed according to
the regional plans, including
regional load-shedding plans,
rules on customer categorisation,
a harmonized definition of
'protected customers' and a
detailed 'emergency rulebook'
set forth at the EU level.
Monitoring
Monitoring of
security of supply
predominantly at the
national level.
ECG as a voluntary
information exchange
platform.
- - Systematic discussion of ENTSO-E
Seasonal Outlooks in ECG and follow up
of their results by Member States
concerned.
Systematic monitoring of security of supply in
Europe, on the basis of a fixed set of indicators
and regular outlooks and reports produced by
ENTSO-E, via the Electricity Coordination
Group.
Systematic reporting on electricity crisis events
and development of best practices via the
Electricity Coordination Group.
A European Standard (e.g. for
EENS and LOLE) on Security of
Supply could be developed to
allow performance monitoring
of Member States.
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Policy options
5.4. Options to address Problem Area IV (Slow deployment and low levels of
services and poor market performance)
Overview of the policy options
5.4.1.
To recap, the drivers in this Problem Area are:
- Low levels of competition on retail markets;
- Low levels of consumer engagement;
- Market failures that prevent effective data flow between market actors.
Each policy option consists of a package of measures that addresses the problem drivers
in a different way and to a different extent. They aim to tackle the existing competition
and technical barriers to the emergence of new services, better levels of service, and
lower consumer prices, whilst ensuring the protection of energy poor consumers.
Box 5: Overview of the Policy Options for Problem Area IV
In the following sub-sections the policy options and the packages of measures they
comprise are described. This section is closed by a table summarising all specific
measures comprising each option.
The relevant annexes addressing the policy options below are: 7.1 to 7.6.
Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer
5.4.2.
engagement and poor data flows
Under this option no new legislation is adopted, there are no further efforts to clarify the
existing legislation through guidance, and no additional work through non-regulatory
means to address the problem drivers. It assumes that the future situation will remain
more or less the same as today.
Stakeholders' opinions: A significant number of stakeholders consider that the level of
competition in retail markets is too low and there is no record of significant support for
current market arrangements and their organic development. The sole exception is on
billing information, where energy suppliers and industry associations indicate that there
may be little scope for EU action to ensure bills facilitate consumer engagement in the
market due to subsidiarity considerations.
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Policy options
Option 0+: Non-regulatory approach to address competition and consumer
5.4.3.
engagement
Under this option, the problem drivers are addressed to the greatest extent possible
without resorting to new legislation. This means strengthening enforcement to tackle
cases of the non-transposition or incorrect application of existing legislation, new
Commission guidance to tackle implementation issues related to difficulties in
interpreting the existing legislation, and examining new soft law provisions to address
gaps in the legislation itself.
To improve competition, bilateral consultations are held with Member States to
progressively phase out price regulation, starting with prices below costs. Should it be
clear that Member State interventions in price setting are not proportionate, justified by
the general economic interest or not compliant with any other condition specified in the
current EU acquis229
, then enforcement action is taken under the existing acquis and
recent Court judgements, which require these criteria. Section 7.1.1 of the Evaluation
argues that the regulation of electricity and gas prices limits consumer choice, restricts
competition, and discourages investment.
To improve consumer engagement, the Commission issues an interpretative note on the
existing provisions in the Electricity and Gas Directives covering switching-related fees.
Section 7.1.1 and Annex IV of the Evaluation show that the current framework remains
both complex and open to interpretation with regard to the nature and scope of certain
key obligations.
The Commission works to ensure the dissemination and uptake of the key cross-sectorial
principles for comparison tools. Enforcement action follows. Nevertheless, Section 7.3.5
and Annex V of the Evaluation show that the relevance of the existing legislation is
challenged by the fact that it is not adapted to reflect new ways of consumer-market
interaction, such as through comparison tools.
The Commission also develops a Recommendation on energy bills that builds upon the
recommendations prepared by the Citizen's Energy Forum's Working Group on e-Billing
and Personal Energy Data Management230
. Section 7.1.1 and Annex V of the Evaluation
show that there is poor consumer satisfaction with energy bills, and poor awareness of
information conveyed in bills. This suggests that there may still be scope to improve the
comparability and clarity of billing information.
Finally, to better protect energy poor and vulnerable consumers231
, the Commission
establishes the EU Energy Poverty Observatory which will contribute to the sharing of
229
Article 3(2) of the Electricity Directive and of the Gas Directive
230
https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-billing_energy_data.pdf
231
As a result of the Third Energy Package, Member States have to defined and protect vulnerable
consumers in energy markets. The evaluation of the provisions related to consumer vulnerability found
the definitions of vulnerable consumers to vary widely across Member States. ACER grouped these
definitions in two groups (i) explicit definitions when characteristics of vulnerability are stated in the
definition such as age, income, or health; and (ii) implicit definitions when vulnerability is linked to be
beneficiary of a social support measure. A study commissioned by DG ENER concluded that energy
136
Policy options
good practices and strengthens enforcement around existing requirements for National
Regulatory Authorities to monitor disconnection rates – an area identified as lacking in
the Evaluation (Section 7.1.1 and Annex III).
However, no action is taken to address the market failures that prevent effective data
flow between market actors. As this involves tackling possible conflicts of interest
among market actors, non-regulatory measures were not deemed appropriate to credibly
addressing this problem driver. Section 7.3.6 and Annex IX of the Evaluation show that
the current legislation was not designed to address currently known challenges in
managing large, commercially valuable consumption data flows.
By tackling regulatory interventions in price setting, this option would enable suppliers
to profitably develop value-added products, thus fostering innovation in energy retail
markets. It would also promote the consumer-driven uptake of such innovative products
by addressing switching fees, unreliable comparison tools and unclear bills – each a key
barrier to consumer engagement.
Stakeholders' opinions: There are no explicit opinions among the stakeholders on a
non-regulatory approach. However, some of the points raised by the stakeholders, like
increased transparency on switching suppliers, exit fees, comparison tools as well as
transparent bills, may be addressed by non-regulatory measures.
Option 1: Flexible legislation addressing all problem drivers
5.4.4.
Under this option, all problem drivers are addressed through new legislation that provides
Member States leeway to adapt their laws to the conditions in national markets.
To improve competition, Member States progressively phase out blanket price regulation
by a deadline specified in new EU legislation, starting with prices below costs.
Transitional, targeted price regulation for vulnerable consumers is permitted (e.g. in the
form of social tariffs), allowing a case-by-case assessment of the proportionality of
exemptions to price regulation that takes into account the social and economic
particularities in Member States.
To both improve competition and reduce transaction costs in the market, consumer data
management rules that can be applied independently of the national data-management
model are put in place. These include criteria and measures to ensure the impartiality of
market actors involved in data handling, as well as the implementation of standardised,
national data formats to facilitate data access. These measures aim at eliminating barriers
to entry associated with data access, and helping all market actors provide a higher level
of service to consumers through the efficiencies that information technology offers.
To increase consumer engagement, the use of contract termination fees is restricted. Such
fees are only permissible for the early termination of fixed-term contracts, and they must
be cost-reflective. Consumer confidence in comparison websites is fostered through
poverty is usually a narrower term than vulnerability as it mostly refers to lack of affordability of
energy services.
137
Policy options
national authorities implementing a certification tool for the most useful and reliable
websites in their markets. In addition, high-level principles ensure that energy bills are
clear, easy to understand, and free from unnecessary information, whilst leaving Member
States some scope to tailor billing format and content to national requirements. Certain
information elements in bills would be mandatory and would need to be prominently
displayed to facilitate the comparison of offers and switching.232
Finally, to better protect energy poor and vulnerable consumers, an improved, principle-
based EU legal framework to support Member State action on vulnerable and energy
poor consumers is put in place. A generic adaptable, definition of energy poverty based
on household income and energy expenditure is included in the legislation for the first
time. Member States would measure and report energy poverty with reference to
household income and energy expenditure, and NRAs would publish the number of
disconnections due to non-payment – figures they should already be collecting under the
current legislation. These actions are taken cumulatively, on top of the non-regulatory
measures on energy poverty described in Section 5.4.3.
These measures build upon the existing provisions on energy poverty in the Electricity
and Gas Directives which state that Member States must adress energy poverty where it
is identified. They offer the necessary clarity about the meaning of energy poverty, as
well as, the transparency with regards to the number of household in energy poverty.
Better monitoring of energy poverty across the EU will, on one hand, help Member
States to be more alert about the number of households falling into energy poverty, and
on the other hand, peer pressure will also encourage Member States to put in place
measures to reduce energy poverty. Since currently available data can be used to measure
energy poverty, the administrative cost is limited233
. Likewise, the actions proposed do
not condition Member States on their primary competence of social policy, hence,
respecting the principle of subsidiarity.
Taken together, this option would strongly promote innovation on retail markets by
ensuring that new entrants and energy service companies receive non-discriminatory
access to consumer data – access that will allow these market actors to develop and offer
the value-added products that (integrated) incumbents have not. A firm commitment to
phase out blanket price regulation would enable suppliers in many Member States to
differentiate their offers to consumers through non-price competition. And by tackling
financial barriers to switching, improving the availability of comparison tools and
helping consumers understand important information in their bills; this option would
increase consumer engagement with the market and the selective pressure for new
services.
232
EPRG Working paper 1515 (2015), "Why Do More British Consumers Not Switch Energy Suppliers?"
by X. He D. Reiner: "We conclude that policies which emphasize simplification of energy tariffs,
increasing convenience of switching, improving consumers’ concerns about energy issues, improving
consumers’ confidence to exercise switch are likely to increase consumer activity."
233
See Annex 7.1, Table 16.
138
Policy options
Stakeholders' opinions: Feedback indicates that the general principles put forward as
part of Option 1 would likely enjoy broad support amongst stakeholders. The sole
exception would be the measures on billing information, where energy suppliers and
industry associations have stated that there may be little scope for EU action. However,
even here, the general principles proposed in this option would give broad leeway to
Member States to tailor national requirements to the conditions and consumer
preferences in each market.
Option 2: EU Harmonization and extensive safeguards for consumers addressing
5.4.5.
all problem drivers
Under this option, all problem drivers are addressed through new legislation that aims to
provide maximum safeguards for consumers and the extensive harmonisation of Member
State action throughout the EU.
To improve competition, Member States progressively phase out all blanket price
regulation, starting with prices below costs, by a deadline specified in new EU
legislation, as per Option 1 (flexible legislation). However, exemptions to price
regulation are defined at the EU level in terms of either: a) a price threshold to be defined
based on principles ensuring coverage of the cost incurred by the energy undertakings
above which Member States may set retail prices; and/or b) a consumption threshold
below which household may benefit from a regulated tariff.
To both improve competition and reduce transaction costs in the market, a standard
consumer data handling model is enforced. This assigns the responsibility for data
handling to a neutral market actor, such as a TSO or independent third-party, eliminating
all possibility of conflicts of interest. Nationally standardised formats are devised to
facilitate data access to all market actors concerned, including cross-border access.
To increase consumer engagement, all switching-related fees are banned, including
contract termination fees. NRAs establish comparison websites to ensure consumers have
access to at least one neutral comparison resource, alongside private sector offerings. In
addition, the format and content of energy bills is partially harmonized through the
inclusion of a standard 'comparability box' that prescriptively presents key information in
exactly the same way in every EU bill.
Finally, to better protect energy poor and vulnerable consumers, a uniform EU
framework to monitor energy poverty and reduce disconnections is put in place. A
specific, harmonised definition of energy poverty is included in EU legislation referring
to households that fall below the poverty line after meeting their required energy needs.
In order to measure energy poverty, Member States survey the energy efficiency of their
national housing stock and calculate the amount of energy, and costs, required to make
all housing comfortable. These survey results are reported to the Commission.
In addition, a host of preventive measures on disconnections are put in place: (i) Member
States are to give all customers at least two months (approximately 40 working days)
139
Policy options
notice before a disconnection from the first unpaid bill; (ii) before a disconnection, all
customers receive information on sources of support, and are offered the possibility to
delay payments or restructure their debts; and (iii) the disconnection of vulnerable
consumers is prohibited in winter.234
These actions are taken cumulatively, on top of the
non-regulatory measures on energy poverty described in Sections 5.4.3.
As with Option 1 (Flexible legislation), this option would strongly promote innovation
on retail markets through non-discriminatory access to consumer data, a firm
commitment to phase out blanket price regulation, and by tackling barriers to consumer
engagement. However, any negative impacts to competition resulting from the stronger,
and more costly, safeguards for the vulnerable and energy poor may also reduce the
availability of new services. In addition, Member States may be better suited to design
disconnection safeguard schemes to ensure that synergies between general national social
service provisions and disconnection safeguards are achieved.
Stakeholders' opinions: Whilst many stakeholders support the objectives Option 2 aims
to achieve, several have flagged reservations regarding the prescriptive approach to
achieving them. In particular, NRAs have voiced their unease over an over-prescriptive
EU billing format, and recommend that the decision on whether or not to allow contract
exit fees is best taken at the national level. NRAs also point out that it is their role to
define the appropriate methodologies for applicable price regulation. Most of the
Member States consider that the model for data handling should be best decided at
national level. And finally, whilst many stakeholders have supported comparison tool
accreditation schemes (Option 1 – flexible legislation), none have called for government
authorities to provide comparison tools exclusively.
Summary of specific measures comprising each Option
5.4.6.
The following table summarizes the specific measures comprising each package of
measures, as well the corresponding specific measure option considered under each high
level option.235
The detailed presentation and assessment of each measure can be found
in the indicated Annex.
234
Similar legislation is already in place in 14 Member States.
235
The preferred options for the specific measures set out in the annex are highlighted in the table in
green.
140
Policy options
Table 9: Summary of Specific Measures Examined for Problem Area IV
Specific Measures Option 0 Option 0+ Option 1 Option 2
Baseline Non-regulatory approach Flexible legislation Harmonization and extensive consumer safeguards
Energy poverty
and disconnection
protection (Annex
7.1)
Sharing of good
practices(Annex 7.1.4
Option 0)
EU observatory for energy
poverty. Sharing of good
practices and increase efforts
to correctly implement
legislation (Annex 7.1.4
Option 0+)
Introducing a generic adaptable, definition
of energy poverty in EU legislation, and
setting an EU framework to monitor
energy poverty (Annex 7.1.4 Option 1)
Introducing a specific, harmonised definition of energy
poverty in EU legislation, a comprehensive EU framework
to monitor energy poverty based on an energy efficiency
survey of the housing stock, and a host of preventive
measures to avoid disconnections (Annex 7.1.4 Option 2)
Price regulation
(Annex 7.2)
Making use of existing acquis to continue bilateral
consultations and enforcement actions to restrict price
regulation to proportionate situations justified by manifest
public interest
(Annex 7.2.4 Option 0)
Requiring MS to progressively phase out
price regulation for households, starting
with prices below costs, by a deadline
specified in new EU legislation, while
allowing transitional, targeted price
regulation for vulnerable customers
(Annex 7.2.4 Option 1)
Requiring MS to progressively
phase out price regulation for
households below a certain
consumption threshold to be
defined in new EU legislation or
by MS, with support from
Commission services
(Annex 7.2.4 Option 2a)
Requiring MS to phase
out below cost price
regulation by a
deadline specified in
new EU legislation
(Annex 7.2.4Option
2b)
Data
management
(Annex 7.3)
Member States are primarily responsible on deciding roles
and responsibilities in data handling (Annex 7.3.4 Option 0)
EU data management rules that can be
applied independently of the national data-
management model (Annex 7.3.4 Option
1)
A standard EU data management model (data hub) (Annex
7.3.4 Option 2)
Consumer
engagement
(Annexes 7.4, 7.5
and 7.6)
Lacklustre consumer
engagement persists,
diminishing the demand
for new services and
competitive pressure in the
market
Improved EU guidance and
Recommendations on
switching-related charges and
comparison tools (Annexes
7.4.4, and 7.5.4 Option 0+)
Flexible legislative measures to further
limit switching-related charges,
establishing a certification scheme to
improve consumer confidence in
comparison tools, and making information
in bills clearer through minimum content
requirements (not format) (Annexes 7.4.4,
7.5.4 and 7.6.4 Option 1)
Outlawing all switching-related charges, making all
national authorities offer (or fund) an independent
comparison tool, and full EU harmonization of the
presentation of certain information in bills (Annexes 7.4.4,
7.5.4 and 7.6.4 Option 2)
141
Assessment of the impacts of the various policy options
6. ASSESSMENT OF THE IMPACTS OF THE VARIOUS POLICY OPTIONS
This section assesses the impacts of the options under each Problem Area. The analysis
focuses on the broad impacts of those options. The impacts of the specific measures included
in each option are assessed in more detail in separate annexes attached to this impact
assessment.
Each option was assessed both quantitatively and qualitatively, in an effort to capture at the
highest possible detail the impacts of the underlying measures within each option. When
reliable quantitative analysis or information was not available, the assessment could only be
performed qualitatively, based on specific criteria.
6.1. Assessment of economic impacts for Problem Area I (Market design not fit for an
increasing share of variable decentralized generation and technological
developments
Methodological Approach
6.1.1.
6.1.1.1.Impacts Assessed
The market design options are examined on the basis of their effectiveness in addressing the
identified problems and achieving the desired objectives, while at the same time facilitating
the delivery of the 2030 climate and energy targets236
in a cost-efficient and secure way for
the whole of Europe.
As the examined measures focus on the better functioning of the electricity markets237
,
economic impacts are in particular analysed with respect to competition, cost-efficiency,
better utilization of resources, as well as impacts on security of electricity supply.
The effect of the measures on the wholesale markets will induce indirect social impacts and
have limited effect on innovation and research. The effects of energy market related polices
on employment are primarily associated with the policy measures seeking to secure the
achievement of the 2030 decarbonisation objectives238
. They will therefore not be assessed in-
depth for all options.
Some indirect environmental impacts are also expected, due to the different types of fuel used
for power generation, as a well-functioning flexible electricity market would incentivize the
increase of low carbon generation.
236
See: http://ec.europa.eu/clima/policies/strategies/2030/index_en.htm .
237
Note that these options are not touching the issue of investment, which is examined under Problem Area II.
Therefore the same power generation mix is assumed for all options.
238
Reference is hence made to the impacts assessments for the EE and RED II initiatives and the one
elaborated in the context of Communication from the Commission to the European Parliament, the Council,
the European Economic and Social Committee and the Committee of the Regions, "A policy framework for
climate and energy in the period from 2020 up to 2030" (SWD(2014) 15 final)
142
Assessment of the impacts of the various policy options
Other significant impacts, direct or indirect, are not expected for the examined options, unless
specifically noted.
The assessment is presented individually for each option, with qualitative analysis and
interpretation of quantitative results. Summary tables reporting the modelling results for all
options are included in section 6.1.6.
6.1.1.2.Modelling and use of studies
For most of the quantitative analysis, the METIS239
modelling software was used to underpin
the findings on the impact of the different options. METIS is a modular energy modelling
software covering with high granularity (geographical, time) the whole European power
system and markets. Simulations adopted a Member State-level spatial granularity and an
hourly temporal resolution for year 2030 (8760 consecutive time-steps per year), capturing
also the uncertainty related to demand and RES E power generation.
For consistency with all parallel European Commission work on the 2030 Energy and Climate
Framework, in the Red II, EE and Effort Sharing Regulation impact assessments, METIS was
set-up (calibrated) such as to reflect as close as possible240
the year 2030 projection of the
power sector in the PRIMES EUCO27 scenario. The PRIMES EUCO27 scenario241
, built on
the EU Reference Scenario 2016, ensures a cost-efficient achievement of at least 40% GHG
reduction (including agreed split of reductions between ETS and non-ETS), 27% RES and
27% EE target.
A stand-alone analysis of the impact of potential policies promoting downstream price and
incentive based demand response, at all customer segments (industrial, commercial,
residential), has also been undertaken (detailed information hereon can be found in Annex
3.1). The options analysed looked at how to reach the full potential of demand response in
order to reduce overall system costs, considering (i) both price and incentive based demand
response, and their combination, as well as (ii) the level of access of demand service providers
to the market (access rules and incentives), and (iii) customers' ability to react (by means of
access to required technologies-smart metering, tariff structures and knowledge) for engaging
in price based demand response. The analysis focused on the assessment of the theoretical
potential of demand response, based on the nature of the electricity use/ability to shift demand
by different clusters of consumers, its current level, and how the different options are likely to
increase the share of the theoretical potential being realised, as well as in the estimation of
associated cost and benefits.
239
A detailed description of the METIS model can be found in Annex IV, including details on the implemented
modelling methodology.
240
A detailed description of the METIS calibration to PRIMES EUCO27 can be found in Annex IV.
241
More details on the methodological approach followed concerning the baseline, on EUCO27, as well as on
the coherence with the scenarios of all parallel initiatives can be found in Annex IV.
143
Assessment of the impacts of the various policy options
6.1.1.3.Summary of Main Impacts
Figure 8 below summarizes the annual quantified benefits of the assessed options for 2030242
,
as presented in detail in sections 6.1.2 to 6.1.5. It illustrates the significant benefits of the
measures under Options 1 to adapt the market design, with annual savings in 2030 of EUR 5.9
billion only for Sub-option 1(a) (level playing field), EUR 8.6 billion for 1(b) (strengthening
short-term markets) and EUR 9.5 billion for Sub-option 1(c) (demand response/distributed
resources). For Option 2 (fully integrated market) the calculated benefits would amount to
EUR 10.6 billion.
Figure 8: Annual cost savings for Problem Area I in 2030 by option
Source: METIS
6.1.1.4.Overview of Baseline243
(Current Market Arrangements)244
Under the baseline, the power system in 2030 relies heavily for energy on RES E generators,
as well as conventional generation which is to a large degree inflexible. In particular, the
share of RES E in electricity generation has almost reached 50%, thus being equal to the share
of all other conventional generation together (i.e. gas, coal, lignite, nuclear, oil). The share of
variable generation (solar and wind) in total generation approaches 30% across Europe.
Concerning conventional generation, nuclear holds a 22% share, coal and lignite a 15% share,
and natural gas 13%. The respective shares tend to differentiate across EU regions, based on
the particularities of each region (Figure 9).
242
All impacts were assessed for one full year (8760 hours) reflecting projected situation in 2030. Reported
figures are in annual real terms (€'13).
243
The assumptions concerning the baseline can be found in Section 5.1.2 and in Annex IV.
244
Although all modelling work was based on the PRIMES EUCO27, the PRIMES scenario has as a basic
assumption the existence of well-functioning competitive markets. As this is the ultimate goal of the
assessed measures, the baseline departs form EUCO27, reflecting the observed distortions or inefficiencies
of current market arrangements.
144
Assessment of the impacts of the various policy options
Figure 9: Shares of Electricity Generation per Region245
in EU in the Baseline
Source: METIS
A number of rules affecting dispatch remain in place, most notably priority dispatch246
for
RES E and that certain technologies are considered as must-run247
, reflecting current practices
and nominations in the market. In fact special dispatch rules concern 60% of total installed
capacity (752 GW on a total of 1,247 GW).
245
For the modelling purposes, an indicative split of Europe into five regions was made as follows (Cyprus was
excluded as assumed not directly interconnected to the rest countries):
Region 1 (CE): Austria, Belgium, Czech Republic, Demark, France, Germany, Hungary, Luxembourg,
Netherlands, Poland, Slovakia, Slovenia
Region 2 (NEE): Estonia, Finland, Latvia, Lithuania, Sweden and Norway.
Region 3 (NWE): Ireland and UK
Region 4 (SWE): Portugal and Spain
Region 5 (SEE): Bulgaria, Croatia, Cyprus, Greece, Italy, Malta, and Romania
246
In "Evaluating the impacts of priority dispatch in the European electricity market", Oggioni et al (2014),
show using a stylized model that significant increase of wind penetration under priority dispatch can cause
even the collapse of the EU Target Mode. Test-runs performed using METIS came to a similar conclusion.
Initial runs lead to significant hours of loss of load for many MS. In order to resolve this issue a "softened"
definition for priority dispatch was assumed for the modelling, allowing the curtailment of units (which
should not be normally the case under priority dispatch) but at a cost.
247
In general, when scheduled in day ahead, must-run units cannot be decommitted during intraday and are
required to operate at least at their technical minimum level. For the scope of the modelling, coal and lignite
units were assumed as being must-run in the baseline. Day-ahead scheduling was assumed though always
optimal (so only units with priority dispatch were assumed to disrupt the economic merit order in day-ahead,
namely biomass) for each national market, which may not be true in practice due to nominations, scheduling
practices, etc. Modelling performed with PRIMES/IEM, results presented in Section 6.2.6.1, captured also
the effect of nominations and other practices in the baseline.
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Region 1
Region 2
Region 3
Region 4
Region 5
Region 1 Region 2 Region 3 Region 4 Region 5
Variable RES
Generation
27% 14% 34% 48% 29%
Hydro 10% 49% 4% 19% 19%
Biomass, Waste
& Other RES
5% 8% 15% 3% 7%
Gas 9% 7% 24% 12% 20%
Oil 0% 0% 0% 0% 0%
Solids 21% 4% 1% 4% 17%
Nuclear 27% 18% 22% 14% 7%
145
Assessment of the impacts of the various policy options
Figure 10: Projected Generation Capacity in 2030 per Member State in GW248
Source: METIS
Another factor reducing the flexibility of the European power system is the limited allocation
of interconnection capacity during intraday and balancing time frames, as well as the varying
gate closures and products, which in practice reduce the opportunities for trading in the short-
term markets and thus their liquidity.
Reserves are procured on a national level and in many cases in infrequent intervals249
, with
corresponding services mainly provided by (large) thermal generators and only in some
Member States by industrial consumers.
Demand response, storage (excl. hydro) and distributed generation have very limited
participation in the market. In most cases available products are not customized for these
resources, minimum thresholds exist for participating in the market, etc. At the same time, a
large part of the generation, mainly RES E, are not balance responsible and do not have a
strong incentive to perform accurate forecasts and declare accurate schedules in the day-ahead
market (the share of variable generation is about 42% of total generation capacity). As a
consequence, the observed imbalances are large, leading to increased needs for frequency
reserves.
The deficiencies of the current regulatory framework create significant inflexibility to the
system operation; the inflexibility in turn increases further the need for reserves (notably so-
248
Please note that the assumed generation capacities in the baseline have certain differences compared to the
ones in EUCO27 PRIMES scenario, as a preliminary version of EUCO27 was used for the calibration.
Further details can be found in Annex IV.
249
For the scope of the modelling, a yearly procurement by (large) thermal generators and hydro has been
assumed for countries with no reserve market, while daily optimal procurement is modelled in countries
with such markets. More details can be found in Annex IV and in "Electricity Market Functioning: Current
Distortions, and How to Model Their Removal" COWI (2016).
-
50
100
150
200
250
AT
BE
BG
CH
CY
CZ
DE
DK
EE
ES
FI
FR
UK
GR
HR
HU
IE
IT
LT
LU
LV
MT
NL
NO
PL
PT
RO
SE
SI
SK
Nuclear
Solids
Oil
Gas
Biomass, Waste
& Other RES
Hydro
Variable RES
Generation
146
Assessment of the impacts of the various policy options
called replacement reserves)250
. Close to real-time, the TSOs can mainly rely either on units
providing replacement reserves or on very flexible (and expensive) units to avoid loss of load
(peakers). In this context, in METIS replacement reserves provide than 600 GWh of
electricity in the baseline, mainly in Poland and South East Europe. The same applies for RES
E curtailment, as curtailment is the only alternative to the encountered stress of the system
and the lack of available flexible resources: 13.0 TWh of RES E is found to be curtailed on an
annual basis, mainly in the Iberian Peninsula (8.3 TWh) and UK/Ireland (4.1 TWh).
Policy Sub-option 1(a) (Level playing field amongst participants and resources)
6.1.2.
6.1.2.1.Economic impacts
The restoration of the economic merit order curve in the wholesale electricity market has a
direct and significant positive impact to the cost-efficient operation of the power system,
leading to tangible reductions of the costs consumers. It would also allow to feed in (and
remunerate from the market) more RES E (notably from wind and solar) to the system.
With special rules concerning unit dispatching eliminated (i.e. must-runs, priority dispatch),
the TSOs are able to schedule and re-dispatch units more efficiently. As a result (in
conjunction with the other measures under this option):
- total costs of the power system are reduced by 7%;
- the activation of replacement reserves is reduced by about 500 GWh;
- RES E curtailments (e.g. wind and solar) decline by 4.7 TWh251
; and,
- the occurrence of negative prices is completely eliminated252
.
Figure 11 - which presents the merit order253
at a given hour - illustrates how preferential
dispatch rules for certain technologies shift the merit order to the right, resulting in price
decreases but at the same time in an increase of the overall costs for the system. The example
shown for biomass priority dispatch is also applicable for must-runs and priority dispatch of
other (expensive) technologies. Restoring the economic merit order thus reduces the overall
costs for the power system at times where these technologies would be out-of-the-money,
while increasing the electricity price during these hours.
250
It should be emphasized that METIS does not include a grid model. Thus the main use of replacement
reserves ('RR'), to address grid (non-frequency related) issues, is not captured. The implemented
methodology can only be considered as a proxy in an effort to capture a part of the impacts of RR. As some
of the scenarios (Options 0 (baseline) and 1(a)( level playing field)) were characterised by important values
of Loss of Load during the intraday time frame, it was assumed that this was addressed by replacement
reserves. To compute the costs related to RR, first the intraday loss of load curve was identified at country
level and then the amount of peaker capacity needed to bring the Loss of Load duration down to 3 hours in
each country was computed. A cost of 60k EUR/MW/y for peaker units and fuel costs of 180 EUR/MWh
was assumed.
251
From a system perspective, it can sometimes be economical to reduce the generation of wind and solar in
order to maintain the system balance.
252
This result is directly linked with the modelling assumption that all electricity is traded in the market.
253
Each generation fleet is represented as a block, as large as its power capacity and as high as its generation
cost. Without distortions, the market dispatches the lowest (cheapest) blocks until demand is met. The
generation cost of the most expensive dispatched power plant sets the clearing price.
147
Assessment of the impacts of the various policy options
Figure 11: Merit order effect of priority dispatch
Source: METIS
Focusing on priority dispatch, which was found to be the main distortion for the day-ahead
market scheduling for the modelling254
, the biggest impacts on generation would be observed
in Denmark, UK and Finland, where biomass holds a large share of generation capacity. The
removal of priority of dispatch would have a considerable effect on expensive biomass
production255
, which in most cases is dispatched out of the merit order. It can also be expected
that the share of CHP generation would be negatively affected, due to the relatively inflexible
character of CHP production256
. On the other hand, removing priority dispatch rules would
benefit variable RES E which could expand its production (due to the reduction in
curtailments). More importantly, variable RES E producers could significantly increase their
revenues due to the increase of the wholesale prices (partly due to the elimination of negative
prices)257
. Overall, the removal of priority dispatch and must-runs helps better integrating
variable RES E generation and leads to significant system costs reductions and thus cost
savings for consumers.
254
Data availability on must-runs, nominations and other practices affecting the day-ahead schedule, leading to
an operation of the system deviating from the economic merit order, was very limited and thus were not
captured by the model. The impacts of must-runs were captured however for the intraday market and
amounted to around EUR 0.5 billion.
255
The Commission's study indicates that up to 85% of biomass generation could be affected by removing
priority dispatch. This result is also partly due to the assumption of having only one fuel for biofuel/biogas,
this being exclusively wood, rendering biomass very expensive. Note also that the analysis focuses on
electricity dispatch and does not examine why would a biomass (or any other) plant want to operate with
losses in the wholesale market (most likely an additional revenue stream like income from selling heat or
some kind of operational support would be required), as is often the case today. A more complete analysis of
this result is presented under environmental impacts, Section 6.1.6.
256
As part of the limitations of the modelling, one should note that the effects of removing priority dispatch
from CHP are not captured in the assessment. In particular CHP and small scale RES E are not modelled as
separate assets. It can be expected though that the results on biomass would be applicable also to a large part
of the CHP generation, unless they are able to recover their losses from the heat market or are industrial
CHP, in which case industrial opportunity costs need to be considered.
257
Because of biomass' assumed flexibility, a part of the lost revenues is recovered from its participation in
reserve procurement and balancing energy activation
Without biomass priority dispatch
With biomass priority dispatch
148
Assessment of the impacts of the various policy options
Figure 12: Effect of removal of special dispatch rules to negative prices
Source: METIS
The above also leads to an increase of the share of Combined Cycle Gas Turbines ('CCGTs')
in power generation258
. RES E generation enters the market merit order, thus catering for
more efficient price formation in the day-ahead and intraday markets. The removal of priority
dispatch will offer access on equal terms to all resources. Moreover, it will more than double
the competitive segment of the market, which in the baseline was only 40% of the market.
As more resources participate under the same competitive rules in the markets, markets would
become more competitive259
. This implies an increase in wholesale prices as they will now
reflect the actual marginal cost of generation instead of one technically lowered via rules
affecting dispatch260
. As a result, this will lead to a much more cost-efficient operation of the
power system, and consequently to a 7% decrease of its total cost.
Finally, the extension of balance responsibility to all generating and consuming entities, offers
a strong incentive for variable RES E and other balance responsible parties to improve their
forecasting, bid more accurately in the day-ahead market and be more active in the intraday
markets. This leads to smaller imbalances and a lower requirement for reserve procurement
by the TSOs. In particular the needs for mFRR are reduced by around 30%. This, combined
258
Share of CCGT in total net electricity generation increases from 12.3% to 15.1%.
259
See for a more detailed discussion of the arguments for and against maintaining priority dispatch in Annex
1.
260
The elimination of the significant hours with negative prices also contributes to the increase of the average
wholesale price.
149
Assessment of the impacts of the various policy options
with the capability of the demand response to also participate261
in the reserve procurement
and balancing markets, leads to a more cost-efficient reserve procurement process.
6.1.2.2.Who would be affected and how
Abolishing priority dispatch and priority access would mainly affect RES E producers using
biofuels and CHP262
and operators that benefit from priority dispatch when producing using
indigenous resources fuels (if their marginal costs are substantial). For low marginal cost,
variable generators, such as wind and solar power plants, the impact is actually positive,
which will be amplified by measures to enable RES E access to ancillary services markets.
In any event, all generators will benefit from increased transparency and legal certainty on
redispatch and curtailment rules. For TSOs, the removal of priority dispatch and priority
access would also facilitate grid operation.
Introducing balancing responsibilities (with exemption possibilities for emerging
technologies263
and or small installations264
) will mainly impact generators currently
exempted or partly shielded from balancing responsibility. Accordingly, this measure will
mean they have to increase their efforts to remain in balance (e.g. through better use of
weather forecasts) though at the costs of being exposed to financial risks.
6.1.2.3.Administrative impact on businesses and public authorities
The removal of priority dispatch, priority access and ensuring compliance with the balancing
rules would give rise to administrative impacts for RES E (and CHP) generators, in particular
for operators of very small installations. This administrative impact can however be
significantly reduced by facilitating aggregation, allowing the joint operation and
management of a large number of small plants (as discussed in more detail under Option
1(c)).
Impacts of Policy Sub-option 1(b) (Strengthening short-term markets)
6.1.3.
6.1.3.1.Economic Impacts
Strengthening short-term electricity markets improves market coupling across time-frames,
leads to a more efficient utilization of interconnector capacity and reduces the amount of
required reserves, as well as their cost.
261
Note though that as no measures are assumed to be implemented here for incentivizing the wider
participation of demand response, only industrial consumers are assumed to be participating in the
respective markets.
262
As part of the limitations of the modelling, one should note that the effects of removing priority dispatch
from CHP are not captured in the assessment. See also footnote 254.
263
In the PRIMES EUCO27 scenario, the emerging technologies of tidal and solar thermal generation (other
technologies having insignificant shares) are projected to have a total installed capacity of 7.26 GW (0.7%
of total generation capacity) and produce 10 TWh of electricity in 2030 (0.3% of total generation).These
shares only slightly increase by 2050.
264
In the PRIMES EUCO27 scenario, RES E small-scale capacity is projected in 2030 to reach 85 GW (7.8 %
share in generation capacity) and produce 96 TWh of energy (2.9% share of total generation).
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Assessment of the impacts of the various policy options
The efficiency of the intraday markets is improved due to the harmonization of their market
specifications, including the transition to continuous trade and harmonisation of gate closures,
as well as by an improved allocation of interconnector capacity across time-frames.
Harmonising intraday markets across Europe265
allows to further reduce RES E curtailment
by 460 GWh and the utilisation of replacement reserves by 100 GWh. Note that curtailment is
not only reduced in countries where implicit auctions were not implemented in Option 1(a)
(level playing field), but in already implicitly coupled regions too. Thus, extending the
coupled area also benefits already coupled countries such as Germany, since it can export
more of its variable RES generation. The effects are illustrated in Figure 13.
Figure 13: Positive impacts of harmonising intraday markets across Europe266
Source: METIS
By improving the methodologies for reserve dimensioning and procurement of balancing
reserves, the need for balancing reserves is further reduced compared to Option 1(a). Certain
improvement comes from the separation of the bids and prices for up and down regulation in
order to reflect their true underlying marginal costs, which may be different both for
generation and load267
. The separate provision of downwards reserves greatly improves the
efficiency of the system, as now thermal plants are not forced to be online to provide such
reserves. Another means is via the procurement of reserves on a day-ahead basis, thus their
sizing being able to reflect the hourly needs for these services, while at the same time
allowing the most efficient resources at a given hour to be procured as reserves by the TSO.
265
Continuous trading was modelled as consecutive hourly implicit auctions.
266
The figures presented in this paragraph show the impact of implicit intraday auctions only. Other measures of
Option 1(b) (strengthening short-term markets), in particular interconnection reservation at day-ahead for
reserve procurement, tend to increase intraday costs.
267
Although the separation of upward and downward balancing was initially foreseen for this initiative, and
thus assessed herein, it may be introduced earlier in the EB GL.
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Assessment of the impacts of the various policy options
The reduction in the reserve needs though is mainly achieved by the regional reserve
dimensioning and more efficient exchange and sharing of balancing capacity among TSOs, as
the generation and consumption patterns differs between Member States according to the
generation mix, renewable energy sources and differences in energy consumption. Thus, the
79.6 GW of reserve needs (FCR + FRR) in Option 0, is reduced to 65.8 GW in Option 1(a)
(level playing field) and to only 42.3 GW in Option 1(b) (strengthening short-term markets) (a
reduction of 47% compared to the baseline).
It is important to note that the reduction in FRR268
is stronger in the well-interconnected
regions (about 50% reduction), namely Central Europe, the Nordics and South / South East
Europe, while the benefits for UK/Ireland and Spain/Portugal are smaller due to their limited
interconnection (about 20% reduction). In order to achieve these reductions from the sharing
of reserves, the Member States need to ensure that sufficient interconnection capacity is
reserved for this purpose, in order to ensure that despite the lower reserve requirements, the
national ability to balance the system remains the same269
. The amount of capacity that needs
to be reserved for this purpose is on average approximately 6%270
of the Net Transfer
Capacities ('NTCs'), with actual values varying significantly per interconnector and per hour
of the day.
Similarly, different market areas have different access to flexible resources and such flexible
resources are vital to the cost-efficient integration of renewable electricity generation. TSOs
may not only procure smaller volumes of reserves but providers of relatively cheap flexibility
resources may supply a larger volume thereof. Hence, overall balancing market payments are
reduced, while at the same time more interconnection capacity can be given to the market by
reducing transmission reliability margins ('TRMs').
An interesting observation coming from the assessment is the increased generation by
baseload thermal plants, compared to more flexible thermal plants. In particular, the
electricity generation of nuclear, CCGTs, coal and lignite plants increases by 10%, while the
generation of gas and oil peakers reduces by 50% compared to the baseline271
. The reason is
that by sharing resources between countries and decreasing reserve needs, the baseload plants
268
Both mFRR and aFRR
269
Adopting a regional approach to reserve dimensioning results in lower reserve requirements because of the
statistical cancellation that can occur between imbalances originating from different countries. As a result
the reserve needs are lower when adopting a regional dimensioning approach. The regional reserve need is
then translated into minimal reserve requirements at national level by using an allocation criteria (in METIS
case the national annual demand). However a national TSO still has to face the same level of risk - the
imbalances on its Control Area remain the same – and the minimal reserve requirements may not be
sufficient to balance its system. As a consequence, national TSOs have to reserve a share of the
interconnection capacity for reserves, so that the other countries can assist it to balance the system. METIS
does not explicitly model reserve exchanges, but risk pooling.
270
Considering that for Option 1(b) an assumption was made that the NTC capacities were increased by 5%,
reflecting e.g. the reduced TRM compared to Option 1(a) due to the increased co-operation between MS via
ROCs, it is interesting to notice that the average capacity that needs to be reserved for sharing balancing
reserves is around the same level. On the other hand this does not signify something, as the averaging hides
the huge variability among hours and interconnectors.
271
It should be noted that the analysis excludes the effect that increased generation by thermal plants would
have on the carbon market and how this in turn would indirectly impact electricity generation.
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Assessment of the impacts of the various policy options
do not need to retain part of their capacity on stand-by for supplying reserves and thus can
increase the quantities of energy they generate. At the same time, though, flexible plants end
up competing for reduced amounts of reserve needs, thus their revenues are significantly
reduced compared to Option 0 (baseline) and Option 1(a) (level playing field)/ Therefore,
better interconnecting markets and making them more flexible serves as a second option for
bringing more flexibility into the system, complementary to but also competing with flexible
generation plants.
Enhancing TSO regional coordination through the establishment of regional operational
centres and by optimising market, operational, risk preparedness and network functions from
the national to the regional level will entail significant efficiency gains and increase social
welfare.272
For example, the regional sizing and procurement of reserves via ROCs could lead
to benefits of EUR 3.4 billion compared to benefits of EUR 1.8 billion from national sizing
and procurement of reserves based on daily probabilistic methodologies.273
Significant
welfare benefits would, inter alia, derive from the more efficient use of infrastructure and
from a decrease of financial losses that would otherwise result from the disconnection of
demand in case of generation shortages.
6.1.3.2.Who would be affected and how
Improving short-term markets will affect all generation operators to a certain extent but it will
in particular improve the ability of variable RES E operators to participate in the market.
Improving intraday and balancing markets would impact the work of the TSOs and Power
Exchanges, because of their involvement in the operation of these markets. On the one hand
this will require operating the system and organising trade within shorter timeframes. On the
other hand, the shorter timeframe will allow TSOs to benefit from significant efficiencies and
to reduce the risk of system problems. TSOs will also be affected through the need to
collaborate closer with neighbouring TSOs through ROCs and through the changes to the
balancing markets which they operate. This has the positive effect of requiring TSOs to
consider systematically the impact of their actions on their neighbouring TSOs.
6.1.3.3.Administrative impact on businesses and public authorities
The administrative impact on businesses is marginal as compared with the baseline.
Power exchanges and TSOs would have to review and adapt their business practises to
facilitate the changes to the market functioning as envisaged under this option. Notably,
changes will have to be made to trading arrangements for intraday and balancing products.
TSOs would collaborate through ROCs, which will have to be set up. The setting up of the
272
For more information on the assessment of the economic impact of ROCs, please refer to Table 2 of Annex
2.3 of the Annexes to the Impact Assessment.
273
"Integration of electricity balancing markets and regional procurement of balancing reserves", COWI
(2016).
153
Assessment of the impacts of the various policy options
ROCs can be estimated to cost between 9.9 and 35.6 million Euros per entity, depending on
the functions and degree of responsibilities attributed to the ROCs.274
Whereas these costs are not insignificant, these costs of several million Euros (which would
be covered and compensated by grid fees) are minor when compared with the benefits this
option will bring.
Impacts of Policy Sub-option 1(c) (Pulling demand response and distributed resources
6.1.4.
into the market)
6.1.4.1.Economic Impacts
The series of measures assumed in this Option include (i) the adaptation of balancing products
closer to what distributed resources like demand response, variable RES and small scale
storage can provide, (ii) the facilitation of the participation of distributed resources in the
market mainly via aggregators and (iii) stronger incentives for the roll-out of smart-meters.
These measures significantly improve the efficiency of the market and the reduce costs.
The market set-up under Option 1(c) provides the opportunity to variable RES E to better
manage their imbalances due to forecast errors at lower cost (due to more competitive prices),
but also to receive additional revenues for any flexibility they can provide to the market.
Similarly, demand is offered the incentives and capability to respond to market prices and
thus complete existing electricity markets. This can be achieved by either shifting load from
hours of peak demand to hours with low demand (e.g. via storage or changing consumption
partterns) or by simply adjusting consumption (when load cannot be shifted or is not really
needed) 275
.
Available data coming from a standalone analysis276
performed on the impact of potential
policies promoting downstream price- and incentive-based demand response, at all customer
segments (industrial, commercial, residential), show that demand response can be of great
service, and deliver net benefits to the system as a whole while engaging all consumer
segments. More in particular, it has been demonstrated that demand response schemes can
lead to a reduction of the peak demand and thereby of the required backup capacity in both
the transmission and distribution networks. This also translates into lower investment needs.
The analysis has shown that in a business as usual scenario (reflected in Option 0) demand
response can account for approximately 34 GW, of which 19 GW will come from incentive
and 15GW from price based demand response. With a supporting policy framework in place,
as in Option 1(c), demand response can account for approximately 57 GW in 2030, of which
39 GW will come from incentive and 18 GW from price based demand response.
274
"Integration of electricity balancing markets and regional procurement of balancing reserves", COWI
(2016).
275
As part of the limitations of the modelling approach, these benefits were not fully assessed because of data
unavailability. Therefore the same load profile was used, based on the ENTSO-E’s TYNDP assumptions,
without being known at which extent it already included some DR (at least for EV charging)
276
See Annex 3.1 and "Impact Assessment support Study on downstream flexibility, demand response and
smart metering", COWI (2016).
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Assessment of the impacts of the various policy options
Allowing small-scale producers, storage and consumers to participate in the market, e.g.,
through aggregated bids, creates incentives for demand side response and flexible solutions,
pulls the above potential in the market and creates a more dynamic market. New flexible
resources are made available for reserve procurement and balancing market. These resources
bring significant short-term and mid-term flexibility277
to the system, contributing to the more
efficient handling of scarcity situations and integrating variable RES E. This abundance of
available resources significantly reduces the cost of the power system and, most importantly,
the load payments to EUR 253 billion, from EUR 278 billion in the baseline and EUR 293
billion in Option 1(a).
These reported savings278
are mainly a result of a significant shift in the provision of reserves
from thermal plants to demand side response (incl. storage) and wind. For example, while in
Option 1(b) (strengthening short-term markets), gas was providing about 20 GW of reserves,
hydro 19 GW and coal 3 GW, under Option 1(c) demand response partly replaces the above
plants by providing 5 GW of reserves. In particular demand response and small scale storage
(electric vehicles and heating storage) become the main providers of upward synchronized
reserves, providing 33% of corresponding needs279
. Wind provides an additional 90 MW of
upwards synchronized reserves and 330 MW of downward synchronized reserves.
6.1.4.2.Who would be affected and how
The new provisions opening up the markets to aggregated loads and demand response will
bring business opportunities for aggregators, new energy service providers, and suppliers who
choose to expand their portfolio of services, but will also affect generators who are likely to
face reduced turnover from lower peak prices and from providing reserves.
Furthermore, demand side flexibility, along with access to real time data coming from smart
metering, will help the network operators optimise their network investments and cost-
effectively manage their systems. In the case of TSOs, it also allows for the better calculation
of settlements and balancing penalties based on real consumption data. On the other hand,
suppliers may face higher imbalances and resulting penalties as their customers change
consumption patterns.
277
For more details on the flexibility needs of the system and how storage, interconnections and demand
response can answer such needs please see "METIS Study S7: The role and need of flexibility in 2030. Focus
on Energy Storage", Artelys (2016).
278
The proposed measures are expected to also have an impact on the day-ahead market, but as explained in
Annex IV this was not possible to assess due to the lack of sufficient detailed data. Benefits from load
shifting or load reductions were not assessed with METIS due to the lack of a dynamic profile for demand
and storage, which would better capture the reactions of demand to market prices. These impacts were
captured though with PRIMES/IEM, results presented in Section 6.2.6.1. The benefits of demand response
and its full potential is analysed in more detail in Annex 3.
279
The analysis shows the demand response does not provide any downwards balancing at all (by increasing
demand when needed), as this is provided at a much lower cost by RES and conventional generation (by
decreasing generation and saving fuel costs). This result is subject to the limitations of the modelling that
does not use dynamic load profiles for demand and storage. Therefore the relevant benefits are most likely
underestimated in the assessment.
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Assessment of the impacts of the various policy options
Finally, end consumers are expected to benefit from more competition, access to wider
choice, and the possibility to actively engage in price based and incentive based demand
response, and hence from reduced energy bills. Even those end users who choose not to
participate in demand response schemes could still profit from lower wholesale prices that
result from demand response, assuming that the respective price reductions are passed on to
consumers.
Box 6: The possibility of large-scale grid disconnection
Looking forward, our modelling (the EUCO27 scenario) shows a continuation of the general
trend of rising retail electricity prices through to 2030, stabilising from 2035 onwards. Given
the decreasing costs of small-scale renewable generation and storage technologies, concerns
have been raised that this trend could result in a growing number of prosumers becoming self-
sustainable and disconnecting from the electricity network – a development that could have
several consequences.
On the one hand, this potential 'flight from the grid' could see the remaining connected
ratepayers bear an increasing share of the burden of contributing to public finances and
financing the electricity network. On the other, grid costs may actually fall as distributed
generation and storage assets enable network operators to more efficiently manage the grid
and connect remote customers.
Predicting the full extent and implications of this trend is difficult given the current
uncertainties, including regarding future cost reductions in small scale renewables and storage
technologies, and the lack of real-world case studies. Nevertheless, our analysis suggests that
this development will be progressive, and that the risks of large scale disconnections are
limited given the difficulties of achieving complete self-sufficiency throughout the year.
In particular, even if decentralised generation and storage becomes competitive, it is
questionable whether self-sufficient prosumers will fully disconnect from the grid.
Disconnecting would imply losing the grid as back-up for when their own generation is
inadequate (e.g. for sustained periods of low sunlight). It would also mean that prosumers
forego the opportunity to sell excess electricity to the market (e.g. during prolonged sunny
periods when their installed storage is at full capacity). This is one of the reasons why the
MDI aims at ensuring full access of prosumers to electricity markets.
It should be added that the discussion of disruptive large scale disconnections is not only
connected with distributed resources but to the perception that consumers are increasingly
confronted with perverse incentives and hidden subsidies. To address this, the initiative
includes measures that should lead to more cost-reflective distribution tariffs i.e. tariffs that
allocate the costs of the grid fairly amongst system users. Cost-reflective tariffs will send the
right long-term economic signals to system users and allow a market-driven move towards a
more efficient electricity system, which will contribute to limiting network tariffs and lead to
investments that are economically rational and efficient.
What is certain is that public authorities and network operators will have to adapt in order to
effectively manage the challenges of any transition towards a more decentralized electricity
system, and make the most of the opportunities this presents. Completely self-sufficient
consumers who do not wish to be connected to the grid should not contribute to the grid costs.
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Assessment of the impacts of the various policy options
6.1.4.3.Impact on businesses and public authorities
The measures proposed to enable the uptake of demand response are designed to reduce
market barriers for new entrants and provide them with a stable operating framework. This is
particularly important for start-ups and small and medium-sized enterprises ('SMEs') who
typically offer innovative energy services and products. However, these measures may
introduce an additional administrative impact for Member States and their competent
authorities that will be required to clearly define in such a new setting: (i) roles and
responsibilities of aggregators, as well as (ii) arrangements for consumers' entitlement to
participate in price based demand response schemes, including their access to the enabling
smart metering infrastructure. At the same time, access to smart metering will support
consumer engagement, with better informed and more selective consumers also making it
easier for NRAs to ensure proper functioning of the national (retail) energy markets280
.
Moreover, thanks to the wider deployment of smart metering, the distribution system
operators will be in a position to lighten, and improve, some of their administrative processes
(linked to meter reading, billing, dis/re-connection, switching, identification of system
problems, commercial losses), and offer increased customer services281
. Similarly,
transmission system operators will optimise their settlement and balancing penalty
calculations, as they can make use of real time data coming from smart metering282
.
Impacts of Policy Option 2 (Fully integrated EU market)
6.1.5.
6.1.5.1.Economic Impacts
By creating a centralised, fully integrated European market with market design features and
procedures in place in order to deal with grid constraints and increase the available
interconnection capacity offered to the market (e.g. due to the further reduction of security
margins and the implementation of flow based market coupling across time-frames), the
European power system can be operated even more efficiently than in the options above.
Benefits coming from the further improvements in the dimensioning and procurement of
balancing reserves, now on a European level, as well as the better utilization of
interconnectors by the EU Independent System Operator, lead to further reductions of the
280
See Annex1(c).1, Stakeholders views; Reference CEER discussion paper "Scoping of flexible response", 3
May 2016
281
“Bringing intelligence to the grids – case studies” (2013) Geode Report;
http://www.geode-eu.org/uploads/REPORT%20CASE%20STUDIES.pdf; also
“Eurelectric policy statement on smart meters” (2010); http://www.eurelectric.org/media/44043/smart-
metering-final-2010-030-0335-01-e.pdf
282
“Towards smarter grids: developing TSO and DSO roles and interactions for the benefit of
consumers” (2015) ENTSO-E;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/150303_ENTSO-
E_Position_Paper_TSO-DSO_interaction.pdf;
“Market design for demand side response” (2015) ENTSO-E Position paper;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr_web.
pdf
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Assessment of the impacts of the various policy options
total costs compared to Option 1(c) by 1.5%. Reserve needs are further reduced by 30%
compared to Option 1(c) and 63% compared to the baseline, although downwards reserves,
which have a low procurement cost, are mainly procured on a national level, in order to use
interconnectors mainly for exchanging electricity instead of reserving it for potential
assistance to/from the neighbours.
The results indicate that although the economic benefits of moving from a national to a
regional approach (Option 1(b) (strengthening short-term markets)) are significant, the move
towards a more integrated European approach (Option 2) has a less significant economic
value-added, as most of the benefits have already been harvested by moving towards a
regional approach. On the other hand this result is also subject to the limitations of the
modelling, not being able to capture the positive impacts from the more efficient operation of
the network (since METIS does not include detailed network modelling).
6.1.5.2.Who would be affected and how
Under this option, TSOs, DSOs, power exchanges, electricity undertakings in general as well
as Member States and competent authorities would be subject to far-reaching organisational
changes (e.g. EU ISO and EU Regulator instead of national TSOs and regulators), and bound
by fully harmonised rules setting out the full integration of the EU electricity market. This
increases the likelihood that these rules may be difficult to implement in specific countries.
This could lead to high resource requirements amongst these stakeholders, public authorities
and Member States, that may be ultimately borne by consumers.
6.1.5.3.Impact on businesses and public authorities
The creation of a fully integrated European electricity market can be considered the most
efficient of all the options and could, in the long run, avoid frictions from coordination and
provide for a high quality electricity system with a high degree of security of supply. Under
this option, it could be argued that in the long run the impact on stakeholders (e.g., TSOs,
DSOs, power exchanges, electricity undertakings, etc.) may be reduced, since the integration
of the electricity market would ensure a high degree of consistency.
However, this option would entail significant changes compared to the current state of the art
of the electricity systems across the EU. It would be necessary to build new entities, processes
and methods without being able to draw upon established practice (e.g., for the establishment
of an EU ISO). Hence, there is a risk that this would lead to disruptions and would require a
significant amount of time to become operational.
This option would also reduce the scope to take into account regional specificities and to draw
upon established regional actors. This option would reduce the scope to develop rules at the
regional level between the parties involved in organising the cross-border trade and system
operation. This is because the key framework as well as the institutional structure would
already be set out at the pan-European level.
In light of the above, it should be noted that the political and administrative effort required
under this option would be considerable.
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Assessment of the impacts of the various policy options
Environmental impacts of options related to Problem Area I
6.1.6.
The measures proposed in this Problem Area aim to improve the cost-efficiency and the
flexibility of the power system. By doing so, climate-friendly variable RES E can be better
integrated in the market; resources are used more efficiently, and unnecessary fuel-based
generation (e.g. backup generation needed because of missing rules for cross-border short-
term markets) can be avoided by better using the aggregation potential of the internal market.
Using the full potential of demand response has also a positive effect on the environment. If
consumption can be shifted more easily to off-peak times, less backup generation from fuel-
based plants is needed.
On the other hand, the removal of privileged rules for certain production forms may lead to a
shift from some RES E production (i.e. biomass) to other generation types which will not only
be wind and solar, but also fossil fuel-based. Therefore, although direct CO2 emissions from
the power sector decrease while moving from Option 1(a) to Option 1(c), from 615 Mt CO2 to
600 Mt C02, METIS results show an increase when moving from the baseline to Option 1(a)
by 60 Mt CO2. The analysis of the impact on emissions is, however, complex283
.
The removal of priority dispatch from biomass (as well as from any other resource, including
must-run generation) is pivotal in restoring the economic merit order in the power markets
and significantly increasing their economic efficiency. Such a measure would discontinue the
use of expensive biomass as baseload generation, replacing it by the marginal technologies
(mainly coal and gas). Expensive biomass would then mainly be used in the power sector as a
flexible generation technology, as well as for providing reserves.
The replacement of biomass by gas and coal could lead in the short-term to increasing
emissions. The environmental impacts of the market design measures cannot though be
examined in isolation from all other complementary energy and climate policies. At the EU
level, the reduction in greenhouse gas emissions within the sectors covered by the EU ETS is
guaranteed by the declining cap which in turn ensures that the emissions reductions objective
is met cost-effectively. In the event of an increase in emissions from certain changes in the
power sector mix, the corresponding increase in demand for allowances would raise the
carbon price leading to an increase in abatement through other means, whether this is through
a fuel switch in power generation elsewhere or an emissions reduction in other ETS sectors.
Due to the binding limit on overall emissions a reduction in the use of biomass would
therefore eventually result in the same amount of GHG emissions over time, with a different
fuel mix at a lower total system cost.
The main effects of removing priority dispatch for biomass are therefore:
- only cheaper fractions of biomass are being used (such as waste streams), while the
more expensive one is being used as flexible dispatchable generation, rather than
subsidised baseload;
283
It should be noted that the analysis excludes the effect that increased generation by thermal plants would
have on the carbon market and how this in turn would indirectly impact electricity generation.
159
Assessment of the impacts of the various policy options
- overall higher CO2 prices and lower generation costs, and higher wholesale electricity
prices (but most likely lower retail prices, as no subsidies will need to be recuperated
outside the wholesale market).
- more favourable conditions for gas, with more operating hours;
The possible increase in emissions in the power sector is in reality the effect of current energy
policies for RES E (and specifically the incentives given by the subsidization of biomass) and
not of electricity market related policies. By removing the distortions currently present in the
electricity markets, the market is able to give clearer signals on the interactions between
climate and energy policies and help identify the right balance between cost and resource
efficiency and emissions reduction.
Summary of modelling results for Problem Area I
6.1.7.
The analysis shows that although today electricity markets function much better than in the
past, there are still significant gains to be harvested. Restoring the merit order and creating a
level-playing field for all technologies can reduce the operational cost284
from EUR 83.4
billion in Option 0 to EUR 77.5 billion in Option 1(a). Another EUR 2.7 billion can be saved
by further strengthening and linking the short-term markets; EUR 0.9 billion by better
integrating demand response and RES E into the market; and EUR 1.1 billion from fully
integrating EU markets. Overall, the measures under Option 1(c) can lead to cost reductions
up to 11.4% compared to the baseline, while the additional measures under Option 2 would
raise this to 12.7%.
When considering the above results, three important points need to be made. First of all the
cost saving estimates for each option are directly related to the volume of traded energy (and
reserves) they concern. Option 1(a) (level playing field) affects all market frames, but most
notably the day-ahead, where the largest volume of trades takes place. Options 1(b)
(strengthening short-term markets) and Option 2 (fully integrated markets) focus on
interconnections (for all market time frames), intraday and balancing; traded volumes there
are only a fraction of the ones of the day-ahead. Option 1(c) (demand response/distributed
resources) concerns mainly the balancing and reserve markets285
. Secondly, the effect of the
measures on the intraday and balancing traded volumes is much greater, but more difficult to
quantify, as it is bi-directional (upwards and downwards compared to the day-ahead
scheduled energy) and complementary to the day ahead market286
. Finally the proposed
284
Cost reflects the operational cost of the electricity system (reflecting mainly fuel cost and CO2 cost). Lower
cost implies a more efficient operation of the system.
285
The proposed measures are expected to also have an impact on the day-ahead market, but this was not
possible to assess due to the lack of sufficient detailed data. See also footnote 278.
286
There are two important connections with the day-ahead market. The closer the day-ahead schedule matches
the optimal dispatch (based on realized demand and generation), the smaller the need to act in the shorter
term markets; and how interconnection is split between day-ahead and intraday. For this reason it is
preferable to look at the results as a whole and not separately for each market frame.
160
Assessment of the impacts of the various policy options
blocks of measures were deemed as the most efficient ones, but also were found to have
limited impact on the reported results287
.
Apart from the cost savings, which relate only to the generation side costs, it is important to
also examine the final cost of the wholesale market for the consumers, referred to below as
'Load Payments' (see Glossary). With the removal of all special rules affecting dispatch, the
wholesale price begins reflecting the actual marginal value of electricity and thus increases;
this affects also the Load Payments which increase by 5%. Subsequent Options though bring
more resources into the market, better utilizing the interconnections and further improving the
cost-efficiency of the market, gradually reducing the Load payments by 6% in Option 1(b)
(strengthening short-term markets), 9% for Option 1(c) (demand response/distributed
resources) and 11.5% for Option 2 (fully integrated market) compared to the baseline. The
above are equivalent to a reduction of the wholesale market cost for the consumer288
from 78
EUR/MWh in the baseline to 71 EUR/MWh for Option 1(c) and 70 EUR/MWh for Option 2.
Table 10: Monetary Impacts (in billion EUR) of the assessed Options (for
EU28+NO+CH in 2030)
Monetary Impacts (billion EUR)289
Option 0
Option
1(a)
Option
1(b)
Option
1(c)
Option 2
Baseline
Level
playing
field
Strengtheni
ng short-
term
markets
Demand
response/
distributed
resources
Fully integrated markets
Cost day-ahead 82.5 76.9 73.5 72.7 72.4
Cost intraday 1.4 0.9 1.2 1.1 0.3
Cost balancing -0.5 -0.3 0.1 0.1 0.1
upwards 0.7 0.5 0.7 0.7 0.7
downwards -1.2 -0.8 -0.6 -0.6 -0.6
Total cost 83.4 77.5 74.8 73.9 72.8
Cost savings - 5.9 8.6 9.5 10.6
Load Payments
day-ahead
278 293 262 253 246
Load Payment
Savings
- -15 16 25 32
Source: METIS
287
A sensitivity performed with METIS introducing the Option 1(c) measures (demand response/distributed
resources) before Option 1(b) (strengthening short-term markets) shows a marginal improvement of Option
1(c) benefits by EUR 0.3 billion, despite the much higher potential for improvement still available in the
market in the context of this Option.
288
If these costs were shared equally among consumers.
289
Unless otherwise noted, figures in all tables represent annual numbers for 2030. The geographical context is
always noted in the title of each graph and in some cases it also covers NO and possibly CH because of the
market coupling of EU Member States with these countries.
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Assessment of the impacts of the various policy options
The monetary impacts described in Table 10 are very closely linked to the impacts of the
measures on the wholesale prices. In Option 1(a) (level playing field) the increase of the
competitive segment of the market from 40% (due to priority dispatch and must-runs) to
100% is the main driver for a more cost-efficient operation of the system, with no negative
prices observed in the performed model runs, leading in the end to higher day-ahead prices. In
parallel the reserve prices are generally lowered, due to the reduction of the inflexibility in the
system. Only mFRR upwards prices increase, as these services are now primarily offered by
peaking units.
In Options 1(b) (strengthening short-term markets) the trends reverse, as more resources enter
the market, thus lowering day-ahead prices. The better utilized interconnection capacity and
the improved functioning of the reserve markets allows baseload plants to produce more
electricity in the day-ahead, while the more flexible (and expensive) plants become the main
providers of reserves. As a consequence, balancing prices tend to increase (together with
intraday prices). Subsequently, the introduction of demand response and the provision of
reserves by RES E in Option 1(c) (pulling demand response and distributed resourced into the
market) further lower wholesale prices (as more resources enter the market), with the
exception of downwards reserve prices which increase290
. Finally the impacts of Option 2
(fully integrated markets) are similar to the ones of Option 1(b) (strengthening short-term
markets).
Table 11: Impacts (EUR/MWh) to Average Annual Wholesale Prices (for EU28 in 2030)
Average Wholesale Prices (EUR/MWh)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/
distributed
resources
Fully
integrated
markets
Day-ahead Market
Price291 78.4 82.5 73.9 71.3 69.6
Balancing Price -
aFRR upwards
71.9 58.3 76.2 71.3 72.3
Balancing Price -
aFRR downwards
52.8 52.5 54.4 59.8 60.6
Balancing Price -
mFRR upwards
72.1 82.3 85.6 76.3 76.3
Balancing Price -
mFRR downwards
70.1 65.2 64.7 58.4 58.3
Source: METIS
An interesting aspect to examine is the distributional impact of the various options on the
generator surplus (i.e. revenues above cost) and consumer surplus (i.e. cost below VoLL). It is
important to note that this should not be interpreted as an investment or "missing money"
analysis, since the modelling used here is static (based on the same set of capacities across the
290
Downwards balancing activation is a benefit (fuel savings) for the system, while there is no gain (in METIS)
to increase demand.
291
EU weighted average price on Member States' demand
162
Assessment of the impacts of the various policy options
options). The issue of investments is analysed in Section 6.2.6.3, using a dynamic investment
model (PRIMES/OM).
With the day-ahead prices significantly affected by the measures, so does generator surplus
(i.e. revenues above cost). The distributional impacts on the market players though are
concentrated on thermal generators, with competitive RES E generators even increasing their
day-ahead revenues (not considering the additional revenues from the other markets).
Although in the baseline thermal generation seems to be making reasonable revenues,
sufficient in many cases to cover fixed costs – especially for gas units – the improvements in
the market design introduced in Options 1(b) (strengthening short-term markets), 1(c)
(demand response/distributed resources) and 2 (fully integrated markets) lead to a significant
decrease of their revenues, turning their operation to loss-making. Note, this result is a large
extent due to the static modelling approach followed here and the increased competition in the
market, as a result of bringing more resources into it and better utilising interconnections (thus
better sharing national resources across EU). With the power generation capacities remaining
constant across Options, this leads to a market with increasing resources participating (to the
point of oversupply) and more intense competition, thus shrinking revenues.
Table 12: Generator Surplus292
(in EUR/kW) for different plant categories (for EU28 in
2030)
Generator Surplus (EUR/kW)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/
distributed
resources
Fully
integrated
markets
Solids 394 393 146 124 108
OCGT 112 102 34 19 9
CCGT 191 178 39 29 22
Nuclear 451 490 435 418 413
Hydro 204 215 200 194 190
Solar 65 73 74 74 75
Wind onshore 117 133 137 137 137
Wind offshore 176 204 211 213 213
Source: METIS
292
Reported surplus concerns day-ahead and reserve market revenues. Some additional revenues (but minor in
comparison) should be expected from the intraday and balancing markets (but were difficult to identify and
report).
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Assessment of the impacts of the various policy options
Similarly, the introduced measures have certain consequences on the generation production,
although these tend to be relatively limited. Summarizing what has already been discussed in
the dedicated assessment of each option, and presented in Table 13:
- The main impact on the electricity generation patterns appears in Option 1(a), when
dispatch begins reflecting the economic merit order. Most notably, biomass
generation is replaced mainly by gas and coal generation.
- Otherwise, generation patterns remain relatively stable across Options, except for
some shifting of gas generation to nuclear in Option 1(b) (strengthening short-term
markets). This comes as a result of the more efficient interconnection allocation and
procurement of reserves, which leads to the utilisation of nuclear and lignite plants
mainly for producing energy, while the more expensive gas plants are used more for
reserves and balancing.
- RES E curtailment and activation of replacement reserves is steadily reduced across
all options, as all measures introduce more and more flexibility to the system. In fact
replacement reserves are no longer needed in Option 2.
- Procurement of Balancing Reserves also decreases substantially, from 79.6 GW in the
baseline to only 29.6 GW in Option 2. The gradual drop in the required reserves is an
outcome of the specific measures assumed in each case and explained in more detail
in the assessment of the respective options.
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Assessment of the impacts of the various policy options
Table 13: System Operation Results (for EU28+NO+CH in 2030)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/
distributed
resources
Fully integrated
markets
Net Electricity Generation (TWh)
Total 3618 3606 3599 3588 3586
Biomass & Waste 236 78 73 72 71
Hydro293
632 623 618 609 607
Wind 722 726 728 729 729
Solar 303 303 303 303 303
Lignite 269 274 278 279 280
Nuclear 755 775 800 803 804
Coal 237 272 274 268 266
Gas 455 545 515 516 515
Others 10 10 10 10 10
RES Curtailment
(GWh)
13.0 8.3 6.0 5.0 4.6
Balancing Procurement (GW)
Reserve
Dimensioning
79.6 65.8 42.3 42.3 29.6
of which FCR 12.4 12.4 12.4 12.4 12.4
of which aFRR 20.5 20.4 10.1 10.1 6.0
of which mFRR 46.6 33.1 19.8 19.8 11.1
Reserves via
interconnections294 - - 12.2 11.7 18.7
Replacement
Reserves
Activation295
(GWh)
600 100 80 60 0
Source: METIS
In terms of distributional impacts across the EU regions, results are strongly related to the
respective generation mix of each region, as well as to how well interconnected each region is
293
Hydro includes pumped hydro storage whose utilisation decreases from Option 0 to Option 2.
294
The reserves via interconnections are computed as the difference between the reserves needed to face the
national risks and the procured reserves.
295
Activated for avoidance of Loss of Load
165
Assessment of the impacts of the various policy options
to the others. For the regions with significant biomass generation (e.g. region 3), there are
significant cost savings when moving from the baseline to Option 1(a) (level playing field).
Similarly, the benefits of Option 1(b) (strengthening short-term markets) and Option 2 (fully
integrated markets) are more significant for the Member States that are better interconnected
(Regions 1 and 2). Option 1(c) (demand response and distributed resources) reduces costs for
all regions, except for Region 5, as the competition with additional reserve resource decreases
the cost for reserve procurement. Similar observations apply for the load payments and the
wholesale prices. It is also worth noting how wholesale prices tend to converge as markets
become more harmonised and better functioning, with the exception of Region 4 (Spain &
Portugal), which has a limited interconnection to the rest of EU only via France.
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Assessment of the impacts of the various policy options
Table 14: Distributional Impacts – regional perspective296
(for EU28 in 2030)
Option 0 Option 1(a) Option 1(b) Option 1(c) Option 2
Baseline
Level playing
field
Strengthening
short-term
markets
Demand
response/distributed
resources
Fully
integrated
markets
Total cost – Day Ahead Market (billion EUR)
Region 1 42.1 40.3 39.4 38.9 38.6
Region 2 6.9 5.5 4.8 4.5 4.4
Region 3 13.3 10.7 9.6 9.4 9.3
Region 4 5.5 5.3 5.0 4.9 5.0
Region 5 14.3 14.9 14.6 14.9 14.9
Total Load Payments – Day-Ahead Market (billion EUR)
Region 1 157 161 138 131 126
Region 2 36 40 34 32 30
Region 3 26 31 30 30 30
Region 4 17 18 19 19 19
Region 5 37 37 36 36 37
Average Day-Ahead Market Price (EUR/MWh)
Region 1 88.1 90.6 77.3 73.3 70.6
Region 2 87.6 97.2 81.6 78.0 73.6
Region 3 63.3 75.5 73.8 73.0 73.0
Region 4 49.6 53.2 55.2 54.6 55.5
Region 5 70.9 71.8 70.6 70.6 70.8
Source: METIS
296
Regions as indicated in footnote 244.
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Assessment of the impacts of the various policy options
6.2. Impact Assessment for Problem Area II (Uncertainty about future generation
investments and fragmented capacity mechanisms)
Methodological Approach
6.2.1.
6.2.1.1.Impacts Assessed
Similarly to Problem Area I, the assessment focused on the economic impacts of the
examined options. The emphasis though is not on the operation of the power system and the
integration of RES E, but on whether the market revenues can incentivize the necessary
investments and – most importantly – on the relevant cost for the consumer. Inefficiencies
resulting from fragmented approaches to CMs are also considered.
The impacts of the options to the environment and the society, excluding their economic
aspects, are directly linked with the changes in the generation capacities of each option. Other
significant, direct or indirect, impacts for the examined options were not identified.
The assessment is presented individually for each option, with qualitative analysis and
references to quantitative results. The detailed modelling results for the various options, along
with their interpretation, are presented in section 6.2.6.
6.2.1.2.Modelling
The modelling for this part was performed using PRIMES/OM, a specific version of the
PRIMES model that can assume different types of competition in the electricity market, as
well as model how CMs affect the investment decisions of the market participants.
PRIMES/OM was selected over METIS for this part of the analysis, because it can model in
detail the investment decisions of the market participants over an extended time-period,
namely until 2050, while at the same time being able to capture the effect of different bidding
behaviours from the side of the market participants (necessary to assess the impact of scarcity
pricing).
In addition, PRIMES/IEM (a day-ahead and unit commitment simulator developed by NTUA)
was used to assess in more detail the benefits of the energy-only market. Contrary to
METIS297
, PRIMES/IEM places more emphasis on accurately simulating the market
behaviour of generators by assuming specific bidding strategies followed by the market
participants and departing from the usual marginal cost assumption298
. Moreover,
PRIMES/IEM was able to capture the effect of introducing locational price signals, as it
297
Due to the differences in the two modelling approaches and underpinning assumptions of METIS and
PRIMES/IEM, a direct comparison of the two sets of modelling results could be misleading.
298
The marginal cost assumption is perhaps the most usual assumption in the dispatch type of models, as it
helps focus more on the effect of market design measures and departs from competition or behavioural
issues. However, one cannot capture well the effect of measures like scarcity pricing under the marginal cost
bidding assumptions, as the prices would fluctuate between the marginal cost of the most expensive running
plant and VoLL (or price cap), which is not what is observed in practice in the market.
168
Assessment of the impacts of the various policy options
includes a network model. Further details on both models and the methodological approach
followed can be found in Annex IV, as well as in the relevant NTUA report299
.
The above tools were complemented by a study performed using METIS, analysing the
revenue related (weather-driven) risks faced by conventional generation and how these could
be mitigated, while also identifying the value of co-ordinated solutions300
.
6.2.1.3.Overview of Baseline (Current Market Arrangements)
The baseline reflects the current market arrangements of Problem Area I, similar to what is
described in section 6.1.1.4. In addition it is assumed that Member States put in place price
caps, as well as that there may be systemic congestion in the transmission grid.
Comparing the baselines of Problem Areas I and II in modelling terms, certain differences
exist in terms of figures and assumptions, mainly reflecting the differences in the respective
modelling approaches301
intended to better capture the options assessed in each Problem Area,
as well as their calibration to a different version of EUCO27302
. Under this baseline:
- Price caps apply as today303
;
- Units bid according to bidding functions by plant category304
and not marginal
costs;
- The unit commitment simulator applies a flow-based allocation of
interconnections;
- Modelling includes more detailed information on generation capacities, including
vintages, technology types and technical characteristics of plants;
- The day-ahead market covers only part of the load, as is the case today. A large
part of the energy (especially produced by inflexible units) is nominated.
- The baseline of this Problem Area fully reflects EUCO27.
Nevertheless, both models identify similar trends concerning the operation and the revenues
of the various generation types, as already presented in Problem Area I.
299
"Methodology and results of modelling the EU electricity market using the PRIMES/IEM and PRIMES/OM
models", NTUA (2016)
300
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016)
301
Further details can be found in Annex IV.
302
METIS had to be calibrated to PRIMES much earlier than PRIMES/IEM. Therefore, a preliminary version
of EUCO27 was used as the basis for the calibration. The main differences of the two versions concerning
the power sector can be found in Annex IV.
303
For more details please see: "Electricity Market Functioning: Current Distortions, and How to Model Their
Removal", COWI (2016).
304
The basis is the marginal fuel cost of the plant, increased by a mark-up defined hourly as a function of
scarcity, calculated for each market segment in which the respective plant category usually operates (e.g.
peak, mid-merit, baseload). Further details can be found in Annex IV.
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Assessment of the impacts of the various policy options
Impacts of Policy Option 1 (Improved energy markets - no CMs )
6.2.2.
6.2.2.1.Economic Impacts
Option 1 assumes that Member States can no longer put in place CMs. The analysis is hence
solely based on a strengthened energy-only market.
With sufficient economic certainty, investments should in principle be able to take place
based on the electricity price signal alone, provided that the price signal is not significantly
distorted. Further, the electricity price, and its behaviour, should stimulate not only
investment in sufficient capacity when needed (be it production or demand), but also in the
right type of capacity. A steady electricity price, one that does not vary significant on an hour-
to-hour basis, should steer investment to the types of capacity that can operate steadily at
lowest production cost. A rapidly fluctuating electricity price should steer investment to
capacity that can ramp-up and ramp-down very quickly and can take advantage of high prices
at short notice and avoid operation when prices are too low. The shift to variable generation
will increasingly require fast-ramping and highly flexible generation and cause the market
exit of less flexible types of generation capacity. Investment uncertainty and varying prices
are not a unique feature to the electricity industry305
.
In this way, the effect of variable renewables, insofar as their deployment will increase the
variability of the electricity price, should stimulate investment in the flexible capacity needed
to keep the system in balance at all times. Ensuring that prices can reflect market
fundamentals is key to this and removing as many potential distortions on electricity prices is
critical to enabling it to play this function.
Indeed, the analysis performed with PRIMES/OM supports the arguments above, showing
that an energy-only market can in general deliver cost-efficiently the necessary investments in
thermal capacity (especially flexible one). The enhanced market design will also improve the
viability of RES E investments, but electricity market revenues alone might not prove
sufficient in attracting investments in RES E in a timely manner and at the required scale to
meet EU's 2030 targets. (See in this regard also the box on RES E investments in Section
6.2.6.3).
Moreover, PRIMES/IEM results show that undistorted, energy-only markets can significantly
decrease load payments by around EUR 50 billion306
in 2030. The largest part of these
savings is attributable to the improvements in the short-term markets and the participation of
demand response in the market, representing EUR 20 billion and EUR 26 billion savings
respectively in 2030. The implementation of measures introducing a level playing for all
305
See in this respect e.g. the report by Frontier Economic on "Scenarios for the Dutch electricity supply
system", p. 134. https://www.rijksoverheid.nl/documenten/rapporten/2016/01/18/frontier-economics-2015-
scenarios-for-the-dutch-electricity-supply-system
306
The benefits become almost double compared to Option 1(c) as assessed with METIS, due to the additional
distortions included in the baseline and measures to address them, on top of the expected differences due to
the different modelling approach. The two figures give a satisfactory range on the possible benefits for
Europe from an improved energy only market design.
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Assessment of the impacts of the various policy options
technologies and removing price caps brings EUR 5 billion savings in 2030 and at the same
significant more cost-efficiency to the system, as explained in Section 6.1.2.1.
As resources are better utilised across the borders compared to the baseline, and demand can
better participate in markets, undistorted energy-only markets are able to improve the overall
cost-efficiency of the power sector significantly. Equally, it can ensure resource adequacy
(See in the regard also Section 6.2.6.3).
It thus follows that by improving the energy markets, the need of government intervention to
support investments in electricity resources is reduced
6.2.2.2.Who would be affected and how
As this option encompasses to the largest extent the options discussed under Problem Area 1,
the assessment made there as to who would be affected and how applies here as well.
With regard to more variable pricing, they will benefit owners of flexible resources, such as
flexible generation capacity, storage and demand response, and incentivise them to come
to or stay in the market. In this end, they will provide the motor for more innovative services
and assets to be deployed.
End consumers will be affected insofar as changes to the wholesale price are passed on to
them in their retail price. However, more variable prices will not necessarily be felt by end-
consumers as they can be hedged (particularly households) against this volatility in their retail
contracts or through wholesale market arrangements. In fact, more variable pricing will
incentivise the development of more sophisticated energy wholesale market products allowing
price and volume risks to be hedged more effectively. Power exchanges would be impacted
by removal of price caps as they will be required to introduce changes to systems and
practices.
Minimising investments and dispatch distortions due to transmission tariff structures would
mostly affect generators. Positive impacts on their revenues would be expected due to lower
connection charges or tarrifs.
TSOs will be affected by improvements in locational price signals as it would likely mean
that they hold and operate networks over more than one price zone. To a lesser extent this
applies to power exchanges as these are often already operating in different price zones
today.
Spending of the congestion income to increase cross-border capacity may have impact on end
consumers, where the congestion income is used for the reduction of tariffs. But this should
be outweighed by the positive effect of more cross-border capacity being available, and the
benefit this has on competition and energy prices.
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Assessment of the impacts of the various policy options
6.2.2.3.Administrative impact on businesses and public authorities
As this option encompasses to the largest extent the options discussed under Problem Area I,
the assessment made there as regards administrative impacts made there also applies here307
.
Overall, the administrative impact on businesses and public authorities should be limited as,
even if the measures associated with Option 1 (in addition to those assessed under Problem
Area I) require changes, they are not fundamentally different from the tasks performed
already under the baseline scenario.
More variable pricing will incite the development of more sophisticated energy wholesale
market products allowing price and volume risks to be hedged more effectively. This should
help reduce lower overall risks to businesses.
Impacts of Policy Option 2 (Improved energy markets – CMs only when needed,
6.2.3.
based on a common EU-wide adequacy assessment)
6.2.3.1.Economic Impacts
This option builds on a strengthened energy market (Option 1). Indeed, as developed in
Section 2.2.1, undistorted energy price signals are fundamental irrespective of whether
generators are solely relying on energy market income or also receive capacity payments.
Therefore, the measures aimed at removing distortions from energy-only markets are 'no-
regrets' and assumed as being integral parts of Options 2 and 3.
In addition, the option assumes the presence of CMs but only in those Member States for
which a resource adequacy assessment performed at European level has demonstrated a
resource adequacy problem. As no restrictions are placed on these CMs, it is assumed they
foresee implicit cross-border participation (i.e. only taking into account imports and exports in
the dimensioning of the CM, without any remuneration of foreign capacity).
In order to highlight the importance of considering the regional aspects in a generation
adequacy assessment, Artelys performed an independent study308
assessing the capacity
savings that can be obtained from a European approach in capacity dimensioning for resource
adequacy in comparison to a resource adequacy assessment conducted at Member State level.
The mode used jointly optimises peak capacities given security of supply criteria309
for two
reference cases – without cooperation (capacities are optimised for each country individually,
as if countries could not benefit from the capacities of their neighbours) vs. with cooperation
(capacities are optimised jointly for all countries, taking into account interconnection
307
For the impact of the additional measures (removing price caps, introduction of locational price signals,
etc.), a detailed analysis is also presented in Annexes 4.1 to 4.4.
308
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016). The results of this study are spelled-out in more detail in Annex 2.2.
309
A value of 15k€/MWh for loss of load is used and system adequacy is assessed on 50 years of hourly
weather data. For more details on the characteristics of capacity dimensioning, see Annex 2.2.
172
Assessment of the impacts of the various policy options
capacities (i.e. NTCs). The difference in installed capacity between the two cases reveals the
savings could be made from cooperation in investments.
Results show that almost 80 GW of capacity savings across the EU can be achieved with
cooperation in investments. This represents a gain of EUR 4.8 billion per year of
investments310
when comparing the two extremes. A reason for these savings is that Member
States have different needs in terms of capacity with peak demands that are not necessarily
simultaneous. Therefore, they can benefit from cooperation in the production dispatch and in
investments. It should be noted that this figure does not assess at which stage Member States
are currently (i.e. whether some Member States already benefit from the capacities of their
neighbours), as the benefits have already been reaped by some. It should also be noted that
this figure does not include savings on production dispatch, which could lead to much higher
monetary benefits.
PRIMES/OM was used to assess the impact of introducing CMs on a certain number of
countries, with the CMs foreseeing implicit cross-border participation. The runs assumed that
four countries were justified based on a EU-wide adequacy assessment, to have a CM: UK,
Italy, Ireland and France. This assumption was based on a selection of countries from the
Sector Inquiry on Capacity Mechanisms (as the model always ensures that the expected
security of supply levels are always met).
The analysis shows that the introduction of CMs lowers wholesale prices, but to a limited
degree, primarily in the MS introducing CMs, but also to all EU countries due to the assumed
well-functioning markets. On the other hand this does not translate to reduced Load Payments
for the consumers on a EU level, as the CM related costs slightly exceed the reductions in the
cost of the wholesale energy market in 2030. This difference though becomes quite significant
in the longer term, making Option 1 cheaper than Option 2 by an average of EUR 4
billion/annum when comparing over the period 2021-2050. Interestingly enough, the
consumers of the Member States introducing CMs face a EUR 7 billion increase in costs in
2030, while the cost for all other EU Member States drop by a similar amount.
6.2.3.2. Who would be affected and how
EU-wide resource adequacy assessments would benefit consumers through maintaining high
standards of security of supply while lowering costs through reduced risk of over procurement
of local assets as foreign contribution to national demand and demand side flexibility would
be sufficiently taken into account.
ENTSO-E would be required to carry out an EU-wide resource adequacy assessment based
on national raw data provided by TSOs (as opposed to a compilation of national assessments).
ENTSO-E would also have to provide an updated methodology with probabilistic
calculations, appropriate coverage of interdependencies, availability of RES E and demand
side flexibility and availability of cross-border infrastructure. NRAs/ ACER would be
310
The 80 GW of capacity savings are a result of optimal investment decisions on EU level, based on an EU
approach vs a national approach. Efficient market functioning can also provide efficient investment signals
leading to more efficient investments. See section 6.2.6.3.
173
Assessment of the impacts of the various policy options
required to approve the methodology used by ENTSO-E for the resource adequacy
methodology and potentially endorse the assessment. TSOs would be obliged to provide
national raw data to ENTSO-E which will be used in the EU-wide resource adequacy
assessment.
Member States would be better informed about the likely development of security of supply
and would have to exclusively rely on the EU-wide resource adequacy assessment carried out
by ENTSO-E when arguing for CMs.
With the updated methodology provided by ENTSO-E, intermittent RES generators/
demand-side flexibility would be less likely to be excluded from contributing to resource
adequacy.
6.2.3.3.Impact on businesses and public authorities
The main burden would be for ENTSO-E having to provide for a single 'upgraded'
methodology and to carry out the assessment for all EU countries. Important to note is that
ENTSO-E has already been carrying out an EU-level resource adequacy assessment based on
Union legislation. However, the methodology used has to be upgraded which would require
increased manpower. Nonetheless, the administrative costs of this 'updated' assessment are
expected to be marginal compared to the economic benefits that would be reaped. It is
estimated that these these costs311
would range from EUR 4-6 million per year (representing
mainly personnel and IT costs).
Impacts of Policy Option 3 (Improved energy market – CMs only when needed, plus
6.2.4.
cross-border participation)
6.2.4.1.Economic Impacts
This option builds on Option 2, i.e. a strengthened energy market and CMs only in Member
States where justified by a European adequacy assessment. In addition, this option provides
an EU framework for explicit cross-border participation in CMs.
Explicit cross-border participation lowers overall system costs compared to implicit
participation, as it corrects investment signals and enables a choice between local generation
and alternatives. As more capacity will be participating in the CM, than in the implicit
participation case, competition will be more intense and thus CM payments lower. In
addition, the enhanced competition will extend also to the wholesale market, thus leading to
lower market clearing prices.
Based on the same setup as in Option 2 (Improved energy market – CMs only when needed,
based on EU resource adequacy assessment) only now with explicit cross-border participation
(i.e. remunerating foreign resources for their services) instead of only implicit (i.e. only taking
into account imports and exports in the dimensioning of the CM, without any remuneration of
311
The economic costs linked to resource adequacy assessments are based on own estimations, resulting from
discussions with stakeholders and experts. For more details, see Annex 5.1.
174
Assessment of the impacts of the various policy options
foreign capacity), PRIMES/OM estimates that explicit cross-border participation would result
in significant savings. Results show that explicit participation brings savings of EUR 2 billion
(in 2030) compared to implicit participation, with savings significantly increasing in the long
run to more than EUR 100 billion over the whole projectin period of 2021-2050 (i.e. about
EUR 3.5 billion per annum). The main reason is enhancement of competition in the CM
auction and the resulting lower auction prices.
By remunerating foreign resources for their services, this option is likely to better ensure that
the investment distortions of uncoordinated national mechanisms present in Option 2 are
corrected and that the internal market able to deliver the benefits to consumers.
6.2.4.2.Who would be affected and how
A positive impact of cross-border capacity mechanism would be expected on the foreign
capacity providers, generators, interconnectors and aggregators. They would receive the
possibility to participate directly in a national capacity auction, with availability obligations
imposed on the foreign capacity providers and the interconnecting cross-border infrastructure.
Foreign capacity providers/ interconnectors would be remunerated for the security of supply
benefits that they deliver to the CM zone and but would also receive penalties in case of non-
availability.
NRAs/ACER would be required to set the obligations and penalties for non-availability for
both participating generation/demand resources and cross-border transmission infrastructure.
ENTSO-E would be required to establish an appropriate methodology for calculating suitable
capacity values up to which cross-border participation would be possible. Based on the
ENTSO-E methodology, TSOs would be required to calculate the capacity values for each of
their borders. They might potentially be penalized for non-availability of transmission
infrastructure. TSOs would also be required to check effective availability of participating
resources.
6.2.4.3.Impact on businesses and public authorities
Providing an EU framework with roles and responsibilities of the involved parties would
enable explicit cross-border participation (as already required by the EEAG). Although the
cost of designing cross-border participation in CM depends to some extent on the design of
the CMs, an expert study312
estimated that such cost corresponds roughly to 10% of the
overall cost of the design of a CM313
. In addition, they estimate costs associated with the
operation of a cross-border scheme i.e. additional costs if cross-border participation is
facilitated to amount to 6-30 FTEs314
for TSOs and regulators combined. Providing for an EU
framework would remove the need for each Member State to design a separate solution and
potentially reduce the need for bilateral negotiations between TSOs and NRAs, reducing the
overall impact on these authorities. According to the same study, TSOs and NRAs bear the
312
Thema (2016), Framework for cross-border participation in capacity mechanisms (First interim report)
313
The same expert study also found that the overall cost of of the design are fairly small compared to the
overall cost of the CM (remuneration of the participation ressources).
314
FTEs in other phases refer to (annually) recurring costs.
175
Assessment of the impacts of the various policy options
main costs related to cross-border participation as they have to check eligibility and ensure
compliance. The study estimates cost savings of 30% on these eligibility and compliance
costs compared to the baseline. It would also reduce complexity and the administrative impact
for businesses operating in more than one zone.
Environmental impacts of options related to Problem Area II
6.2.5.
The impacts of these measures to the environment are very limited, as they mainly influence
the generating capacity but not so much the operation of the units, which is the source of
emissions. The actual emissions depend on the merit order and the relation of the marginal
cost of coal in comparison to the marginal cost of gas. This in turn depends on the CO2 price
and the relation of coal versus gas price, and not on whether there is a CM in place or not.
Overview of modelling results for Problem Area II
6.2.6.
6.2.6.1.Improved Energy Market as a no-regret option
Several facts speak in favour of market design which relies on an improved energy market as
the driver for investment and operation. As already described in the assessment of Problem
Area I, the improvements in the wholesale market described under Option 1 of Problem Area
I (level playing field, strengthening short-term markets, pulling demand response and
distributed resources into the market) are expected to bring significant benefits and reduce the
need to correct market failures with capacity markets. These benefits are further enhanced
when considering the additional measures considered in this Option (e.g. removal of price
caps, a process which leads to the introduction of locational price signals reflecting systematic
congestion, limiting curtailments of interconnector capacity).
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Assessment of the impacts of the various policy options
The benefits of further improving the market in this way, assessed this time using the
PRIMES/IEM model, are presented in Table 15 below. The level of the reported figures in
Table 15 are higher compared to Table 10 due to the inclusion of more distortions in the
baseline of PRIMES/IEM, as well as the use of scarcity bidding, instead of marginal cost
bidding in METIS315
.
Table 15: Cost of supply in the wholesale market in the year 2030316
Load Payments (billion EUR)
Day-
ahead
Market
Intra Day
Market
Reserves
and
balancing
Total
Current Market Arrangements
(in context of low price caps, systematic
congestion)
326.2 22.1 7.7 356.0
Level playing field + removal of low price
caps
327.5 17.1 6.8 351.4
Strengthening short-term markets +
removal of low price caps, locational price
signals
317.6 11.6 1.9 331.2
Demand response / distributed resources
into the market + removal of low price
caps, locational price signals, demand
response in day-ahead
300.4 4.0 1.0 305.4
Source: NTUA modelling (PRIMES/IEM)
Overall, despite differences in the modelling approaches, results of PRIMES/IEM are fairly
consistent with METIS results used to access the options from Problem Area I, especially
concerning the ranking of the respective options. The results indicate that the "improved
energy market" Option could significantly decrease wholesale supply costs by around EUR 50
billion in the year 2030. As a consequence, the unit cost of generation paid by the consumers
would drop from 102.9 EUR/MWh to 94.7 EUR/MWh, the largest part of which is
attributable to the participation of demand response in the market317
.
315
At the same time the assumption that CHP, small scale RES E and biomass retain (implicitly in some cases)
priority dispatch in PRIMES/IEM in the first three examined cases – but not for small scale RES in the last
one -, implies lower percentage changes when moving between the first three options, due to the smaller
generation affected by the measures, but at the same time a more significant one for the last option. More
details on the exact assumptions can be found in Annex IV.
316
The rows correspond to the respective options of problem area I (except Option 2). In addition though
Option 1(a) (level playing field) is complemented by the removal of price caps; Option 1(b) (strengthening
short-term markets) is complemented by the introduction of locational price signals; and Option 1(c) with
demand response participating also in the day-ahead market (which could not be captured by METIS, as it
captured demand response in the intraday and balancing markets only). The last row reports the aggregate
costs of Option 1 of Problem Area II.
317
Contrary to METIS, in PRIMES/IEM demand response resources participate also in the day-ahead market,
thus bringing additional savings for the relevant Option. The impact is much more significant in this case
because the day-ahead market covers the vast majority of transactions.
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Assessment of the impacts of the various policy options
The above analysis highlights the importance of an improved market design, with all the
measures described under Option 1(c) of Problem Area I, together with scarcity pricing and
the proper locational signals (as added under Option 1 of Problem Area II), irrespective of
whether generators are solely relying on energy market income or also receive capacity
payments. Therefore the measures aimed at removing distortions from energy markets are
considered as 'no-regrets'.
6.2.6.2.Comparison of Options 1 to 3
In order to better assess the dynamic behaviour of markets and how markets can also provide
investment signals, modelling analysis was performed using PRIMES/OM318, 319
. Option 1
assumes an improved energy-only market for all Member States. Options 2 and 3 assume that
the improved energy-only market is complemented in certain cases by a national CM320,321
as
a means for the Member States to address possible forecasted resource adequacy problems in
their markets, on the basis of a resource adequacy assessment performed at the European
level. The difference between the two options is that Option 3 assumes that the CM foresees
rules for effective, explicit cross-border participation, while Option 2 does not.
For the scope of this assessment, four countries were assumed to be in need of a CM: France,
Ireland, Italy and UK. This hypothesis was not based on a resource adequacy analysis, but on
the CMs examined under DG COMP's Sector Inquiry, focusing specifically on countries with
market-wide CMs. (Results could differ if different countries were selected, which is why a
sensitivity, presented below, was performed).
The main conclusions when comparing Options 1-3 are presented in Table 16 and can be
summarized in the following:
318
PRIMES/OM delivers results complementary to the ones of market simulation models, like METIS and
PRIMES/IEM, as its focus is on investments. The main difference of PRIMES/OM with other energy
system investment models, like PRIMES, is that while PRIMES model analyses revenues/costs at the level
of the generation portfolio, the PRIMES/OM evaluates the probability of plant survival depending on the
economic performance calculated individually for each plant. A detailed description of PRIMES/OM can be
found in Annex IV.
319
The results will not be compared directly to the baseline as it was not technically possible to produce
robustly this scenario using PRIMES/OM. Nevertheless this does not affect the assessment, as all options
build upon the preferred option of Problem Area I.
320
The simulation of the CM auction by country, which is based on an estimation of a demand curve for
capacity procurement, takes into account imports and exports in the context of market integration using
power flow allocation of interconnection capacities. Therefore, the capacity procurement is configured so as
to avoid demanding for unnecessary capacities, as imports are considered to contribute to resource
adequacy. Similarly, exporting countries configure demand for capacity procurement taking into account
capacity needed to support exports.
321
When a country is assumed to have a CM in place, it is assumed that generators no longer follow scarcity
pricing bidding behaviour, but shift to marginal cost bidding. This is partly a result of competition, as more
generation remains in the market, as well as the expectation that when a plant gets a CM remuneration as a
result of an auction it foregoes revenues that would otherwise be needed to be covered from the day-ahead
market (e.g. because it signs a reliability option contract or a contract for differences with a strike price
effectively acting as a price cap to the generator's revenues from the energy market).
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Assessment of the impacts of the various policy options
- The load payments for the three Options are very comparable when assessed at the
EU28 level. For the year 2030, Option 3 (Improved energy market – CMs only when
needed, plus cross-border participation) is slightly cheaper by EUR 1 billion compared
to Option 1 (Improved energy markets - no CMs) and by EUR 2 billion compared to
Option 2 (Improved energy markets – CMs only when needed, based on a common
EU-wide adequacy assessment);
- Results actually show that Option 3 is consistently cheaper than Option 2 throughout
the projection horizon until 2050 and on a EU28 level. This is mainly due to the lower
cost of the CMs, as through the cross-border participation more resources can compete
for the relevant payments;
- As a result of the above, the average annual cost of total demand is very close for
Option 1 and Option 3, with the lowest cost option alternating along the years. Option
3 is always less costly for the consumer than Option 2 though.
- When comparing the Options for the whole projection period, i.e. 2021-2050, Option
1 is found to be EUR 17 billion cheaper than Option 3 (on average about EUR 0.5
billion/annum) and EUR 120 billion cheaper than Option 2 (on average EUR 4
billion/annum). The main reason for this difference is that CMs provide incentives to
retain capacity on the system that otherwise would have exited the market. This cost is
somewhat balanced by the slightly lower energy prices observed in the market,
although the final cost to the consumer comprises of both the energy and the CM cost.
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Assessment of the impacts of the various policy options
Table 16: Main Impacts over the projection period 2020-2050 on EU28 level
2020 2025 2030 2035 2040 2045 2050
Load Payments (billion EUR)
Option 1 241 316 351 419 447 557 516
Option 2 241 312 352 428 454 560 530
Option 3 241 306 350 426 452 553 526
Load Payments for energy and reserves (billion EUR)
Option 1 241 316 351 419 447 557 516
Option 2 241 302 340 417 443 548 518
Option 3 241 297 340 417 443 543 516
Load Payments to capacity mechanisms (billion EUR)
Option 1 - - - - - - -
Option 2 - 11 11 11 11 11 12
Option 3 - 9 10 9 10 10 10
Average SMP (billion EUR)
Option 1 74 95 103 118 115 135 122
Option 2 74 91 100 117 114 133 123
Option 3 74 89 100 117 114 132 122
Average cost of total net demand (EUR/MWh)
Option 1 80 102 111 127 125 146 132
Option 2 80 101 111 129 127 147 135
Option 3 80 99 110 129 126 145 134
Source: NTUA Modelling (PRIMES/OM)
Note:Option 1: Improved energy markets - no CMs
Option 2: Improved energy markets – CMs only when needed, based on a common EU-wide adequacy assessment
Option 3: Improved energy market – CMs only when needed, plus cross-border participation
In order to better understand the impacts322
of the CMs and the effect of cross-border
participation, Table 17 presents the impacts in 2030 for the three following groups of
countries: (a) the countries implementing a CM, (b) their direct neighbours and (c) the rest of
the EU countries.
Results for Option 2 shows that by introducing a CM in the assumed four countries, the actual
distribution of cost varies among the different groups of countries. Countries implementing a
CM are significantly burdened, mainly due to the cost of the CM, while their neighbours
benefit from it.
322
The impacts of CMs on the energy mix were very limited, inducing only some limited switching in
electricity generation from coal to gas plants.
180
Assessment of the impacts of the various policy options
In particular countries implementing the CM are burdended with an additional EUR 6.8
billion of costs, while the cost of their neighbours drops by EUR 3.6 billion. Even the cost of
the rest of the EU countries drops by EUR 2.9 billion. The cost of energy and reserves is
reduced for all countries323
. In the countries implementing a CM the cost is reduced about two
times more than in the rest coutries, thus leading to lower payments for energy and reserves.
However, these reductions are outbalanced by the CM costs, borne solely by the countries
introducing CMs. The CMs induce an additional EUR 11 billion of payments, part of which
are attributed to the 5 GW of capacity which would otherwise have retired early in the
absence of CMs.
Moving to Option 3, i.e. assuming explicit cross-border participation in the CMs, the results
compared to Option 2 improve in terms of cost-efficiency, not only for the whole EU as
presented above, but also for the countries implementing CMs. On the other hand the benefits
for the countries without a CM are slightly reduced.
In particular, the analysis for the year 2030 shows that explicit cross-border participation is
still worse-off for the countries with a CM compared to the energy-only market, costing EUR
3.6 billion more then the energy-only market, but better than implicit cross-border
participation, which costs an additional EUR 3.2 billion to the countries with CM.
In general, modelling results indicate that a CM, compared to an energy-only market, is
likelier to keep more capacity in the system, part of which would have otherwise exited due to
making losses in the energy market. As more capacity is kept in the Member States with a
CM, less capacity is needed in the other Member States, especially the neighbouring ones,
which then rely more on imports.
As it was discussed above, these results are influenced by the specific choice of countries
assumed to have a CM. To address this issue, an additional sensitivity was performed,
comparing the cases of all Member States introducing a CM, either with implicit or explicit
cross-border participation (same applying for all). Results show that the case of CMs with
explicit cross-border participation is less costly, with load payments being EUR 7 billion less
(about 2%) in the year 2030. Half of this benefit is coming from the reduced CM payments
and half from the reduced energy and reserve payments.
323
This result is related to some specific characteristics of these countries. France is heavily exporting
electricity based on nuclear and this is not affected by the establishment of a CM in France. This is also the
reason why energy costs drop across Europe. The UK and Italy heavily depend on CCGT plants in the
context of the scenario examined and, in addition, have limited free space in interconnections, because they
are saturated by import flows of nuclear energy coming from France.
181
Assessment of the impacts of the various policy options
Table 17: Distributional Impacts of Options for Member States in 2030324
Option 1 Option 2 Option 3
Improved energy
markets - no CMs
Improved energy
markets – CMs only
when needed, based
on a common EU-
wide adequacy
assessment
Improved energy
market – CMs only
when needed, plus
cross-border
participation
Load Payments in 2030 (billion EUR)
MS with CMs 133 140 137
MS directly neighbouring MS with CM 135 131 132
Rest of the MS 82 79 80
Load Payments for energy and reserves (billion EUR)
MS with CMs 133 129 127
MS directly neighbouring MS with CM 135 132 132
Rest of the MS 82 80 80
Load Payments to capacity mechanisms (billion EUR)
MS with CMs 0 11 10
MS directly neighbouring MS with CM 0 0 0
Rest of the MS 0 0 0
Average SMP (EUR/MWh)
MS with CMs 104 100 98
MS directly neighbouring MS with CM 102 100 100
Rest of the MS 103 101 101
Cancelling of Investments or Early Retirements of Capacity in 2021-2030 (GW) 325
MS with CMs 18 9 9
MS directly neighbouring MS with CM 35 41 42
Rest of the MS 10 10 11
Source: NTUA modelling (PRIMES/OM)
The main reason for the overall improved performance and reduced costs of Option 3
compared to Option 2 is the enhancement of competition in the CM auction and the resulting
lower auction prices when allowing for explicit cross-border participation. This reduction
324
Impacts comparing the effects to countries assumed to have CMs and countries without. The 4 countries
assumed to have CMs in 2030 (France, Italy, UK, Ireland) were chosen based on the finding of DG COMP
Sector Inquiry. No specific assumption was made for the design of the relevant CMs. Differences are due to
the peculiarities of each national energy system, mainly related to its power mix and its level of
interconnections. Results could be different if other MS had been chosen.
325
The values under "cancelling of investments or early retirements of capacity" represent excess capacity
which becomes redundant due to the improved market functioning. Early retirement in the model is market-
based, coming as a result of anticipating a negative present value of earnings above operation costs in the
future, in comparison to the remaining value of the plant.
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Assessment of the impacts of the various policy options
lowers the revenues of generators from a CM, but the probability of capacity reduction does
not significantly increase, compared to the case with implicit cross-border participation.
Explicit cross-border participation in the CM auctions implies that competition is stengthened
not only in the CM, but also in the electricity wholesale market.
6.2.6.3.Delivering the necessary investments
Despite the different modelling approaches followed, the analysis with both METIS and
PRIMES/IEM reach a similar conclusion: improving the electricity market design is a no
regret option for the society as a whole. It is expected to reduce both the cost of operating the
power system, as well as the final cost for the consumers.
At the same time though the two models showed that these savings come to the detriment of
the thermal generator revenues, which are expected to be reduced compared to the baseline.
This modelling conclusion is a consequence mainly of the following two reasons:
- on one hand, the improved market design increases competition in the market, by
bringing more resources into the market and better utilisation of interconnections;
- on the other hand, capacities are assumed to be constant due to the nature of the
modelling (static, focusing on 2030 based on the same capacities across all options).
The combination of the two points above leads to a market with overcapacity326
and thus low
prices, since there is no scarcity and there is sufficient capacity of flexible resources. In reality
though, the low prices in a well-functioning market would serve as a signal for lower
investments and exit of loss-making generators. Therefore this overcapacity should either
never appear or only be temporary.
The above dynamic interactions were better captured with PRIMES/OM, which simulated
investment behaviour till 2050327
. In an energy-only market context, PRIMES/OM projected
that 63 GW of capacity would either be retired early or the relevant investments would be
cancelled in the period 2021-2030. About half of it would come from (mainly old) coal plants
and another half from peaking units or steam turbines fuelled by oil and gas.
The reason for retiring capacity and cancelling investments is the unprofitable operation of the
units. From the results it is indicated that the market can be successful in maintaining CCGT
in operation and, partly, peak devices. On the other hand it does not provide sufficient
incentives to retain old coal and old oil/gas steam turbine power plants, which are loss-
making.
326
Moreover the capacity mix is not optimal any more.
327
All modelling runs assume certain reliability standards are met (i.e. security of supply concerns are always
met)
183
Assessment of the impacts of the various policy options
Table 18: Power generation328
capacity in EU28
Power Generation
Capacity (GW)
Cancelling of Investments or Early
Retirements of Capacity (GW)
2030 2040 2050 2021-2030 2031-2040 2041-2050
Total 1,094 1,271 1,504 63 68 48
Coal & Lignite 77 45 14 32 45 33
Peakers & Steam
turbines (oil/gas)
12 6 6 28 16 8
CCGT 158 165 175 0.3 7 4
Nuclear 110 124 122 2 0 2
Source: NTUA Modelling (PRIMES/OM)
In this context of adjusting capacities, the profitability329
of thermal generation changes
significantly for the better. Scarcity pricing and the reduction of overcapacity are the main
drivers for this. Table 19 below shows how the adjustment of capacities, together with
scarcity pricing, would affect wholesale prices and allow thermal plants to at least recover
their total costs from the market.
Table 19: Effect of adjusting capacities to wholesale market prices in 2030
Day-Ahead Market Price
Before Adjusting Capacities
Day-Ahead Market Price
After Adjusting Capacities
Average Price (EUR/MWh) 89 103
Baseload 80 93
Mid-merit 90 103
Peak load 94 137
Spread (EUR/MWh) 14 44
Source: NTUA Modelling (PRIMES/IEM, PRIMES/OM)330
In this context, the market seems able to deliver to a large extent the necessary investments
for all competitive technologies in the long term. A new CCGT plant, which is the marginal
technology, constructed post-2025 (when overcapacity is gradually resolving) will likely
remain profitable over the following 20 years of its operation. If this plant is part of a larger
328
Reported generation capacities do not include capacities of CHP plants. Reported figures on cancelled
investments do not include 2 GW of cancelled nuclear investments in 2021-2030 and another 2 GW in 2041-
2050.
329
Profits are highly dependent on the assumed fuel costs, technology costs and CO2 price. Therefore the
discussion in this Section should be read in a probabilistic context, i.e. the "likelihood" of the investments
being profitable, similar to how the modelling of investment decisions was performed. Concerning the
specific assumptions used, PRIMES/OM was based on the relevant PRIMES EUCO27 projections, reported
in Annex IV.
330
PRIMES/IEM results are before capacity adjustment, PRIMES/OM after adjustment. Similar assumptions and
the same bidding strategies were used in both models, thus results are comparable, within the limitations of
each modelling approach.
184
Assessment of the impacts of the various policy options
portfolio, especially if it includes competitive RES E technologies, then it will be able to
better hedge its risks and further increase the likelihood that the whole portfolio will be
profitable.
More specifically per technology:
CCGT Scarcity bidding succeeds in maintaining the vast majority of CCGT
capacity, a large part of it being new investments in the period 2021-
2030. These plants have a variety of revenue sources (day-ahead,
intraday, balancing, reserves) and the projected increase in ETS
prices makes them economically more attractive to operate. As a
result CCGT plants are dispatched more often at full capacity.
Nuclear Nuclear plants do not have any revenue issues, due to their low
marginal cost. Note that new investments in nuclear appear only in
the long-term.
Coal / Lignite These plants have the biggest revenue problems, as market revenues
prove insufficient even to cover their fuel and variable (non-fuel)
costs. There was very limited new investment in the projections even
in the baseline, so this issue mainly concerns decisions for the
refurbishment of coal plants.
Peak devices Peak units and steam turbines (many of them old) do not produce
comfortable revenues until 2035331
. Around that period though and
due to the strong investments in variable RES E and the increasing
needs for flexible capacity, the situation turns around, rendering these
units very profitable.
RES E
(excl. biomass)
The situation for RES E is contrasted, depending on the level of
maturity of RES E technologies. Even if some less advanced RES E
technologies would need support to emerge as part of the power
generation mix towards 2030, this is not the case for many
competitive RES E technologies, such as hydro, onshore wind and
solar PV (at least in some parts of Europe)332
. For a more elaborate
discussion on this point see the text box below on RES E investments
and market design.
331
"METIS Study S16" shows that peakers’ revenues highly depend on the occurrence of scarcity hours that
happen mainly during very cold years, which constitutes an additional risk for peakers who rely on scarcity
prices to generate revenues. On the contrary, base-load producers have more stable revenues from one year
to the other.
332
A more detailed analysis can be found in the RED II impact assessment, specifically in Annex 5, where a
detailed analysis on the viability of RES E projects is presented for the period post-2020.
185
Assessment of the impacts of the various policy options
CHP
(incl. biomass)
CHP333
remains unprofitable over the whole projection period when
considering only their electricity market related revenue streams. It
should be considered though that the main use of these plants is
assumed to be the production of industrial steam/heat, with electricity
being a side-product. Therefore, no conclusion should be made based
on these partial results. Similar for biomass (outside industrial CHP),
additional revenues are assumed to come from support schemes and
the value of heat when producing heat for district heating.
The following table summarizes the projected profitability for all generation technologies
over the period 2020-2050:
Table 20: Average profits or losses334
for different plant categories in the case of an
energy only market over the projected horizon 2020 – 2050 in EUR/kW for EU28
Source: NTUA modelling (PRIMES/OM)
It is important to highlight that the above analysis has been performed per individual plant
basis. Although this reflects project finance type of decisions, it does not reflect portfolio-
based decisions, which are closer to the usual power sector business model for utilities, due to
economies of scale. The portfolio approach (e.g. investing in both wind and peak generators)
333
The category of CHP plants includes only those which serve industrial steam and district heating as their
main function. Other CHP plants have been appropriately distributed within the capacities of the respective
technologies.
334
The reported results concern financial evaluation at individual plant level. In the context of PRIMES/OM,
profits or losses are defined as follows: revenues from day-ahead market, revenues from reserve market,
revenues from CM (if applicable) minus sum of fuel costs, variable non-fuel costs, O&M fixed costs and
capital costs. For capital costs the model estimates the not-yet amortized value of initial investment
expenditure for old plants (including cost of refurbishment if applicable) and the investment expenditures
for new investments. As these are aggregate numbers, they approximate but are not equal to the missing
money (as when calculating aggregate profits, one unit's losses may cancel out with another unit's profits,
while when calculating missing money you only add the losses).
2020 2025 2030 2035 2040 2045 2050
Total -46.9 9.1 35.7 78.4 68.8 129.2 80.5
Solids 69.9 94.8 1.6 -111.5 -80.9 -89.7 -207.7
Steam turbines oil/gas -66.2 -116.7 -117.3 -93.8 -90.7 -68.5 -120.9
CCGT -75.1 -55.6 -23.2 27.6 -23.5 21.1 -59.6
Peak -53.7 -50.1 -51.9 -11.8 224.2 344.1 36.8
Nuclear -47.5 102.8 141.0 249.4 233.8 374.5 259.4
Lakes 144.0 162.3 185.6 205.9 211.9 270.5 263.4
Run of River 268.4 309.3 335.4 355.3 304.9 345.3 209.0
Geothermal 153.3 235.4 313.8 438.3 477.1 443.4 356.1
Wind onshore 1.9 30.7 82.2 117.2 118.5 173.1 142.1
Solar PV (large) -63.0 -1.2 25.6 58.6 49.0 86.1 62.5
RES (small) -115.0 -101.4 -48.5 34.7 19.1 24.9 5.0
Wind offshore -6.2 -83.8 -85.9 -18.2 2.6 127.7 55.9
Biomass -137.9 -171.2 -141.3 -59.0 -74.1 20.5 13.2
Solar thermal -678.7 -666.4 -466.2 -422.0 -385.3 -265.1 -415.0
Tidal -5,569.9 -4,105.4 -308.5 -252.8 -175.7 -116.0 -130.0
CHP solids -136.9 -203.5 -208.5 -227.6 -315.5 -364.8 -434.8
CHP gas -163.8 -185.8 -169.3 -128.4 -207.7 -235.5 -328.0
CHP biomass -338.5 -336.1 -324.0 -289.9 -292.3 -128.3 -90.1
CHP oil -333.2 -459.2 -487.9 -372.3 -367.8 -629.5 -413.8
186
Assessment of the impacts of the various policy options
allows the sharing of risks between different technologies, directly improving the
performance of the investments.
Similarly the above analysis does not consider the existence of any type of contracts between
supply and demand, be it long-term contracts, futures (e.g. EEX hedging products) or even
typical contracts between utilities and residential/commercial consumers. Such contracts,
concluded on a purely voluntary market basis, would again transfer part of the risk of the
generators to consumers, in exchange of higher security of supply, protection against price
spikes and more stable payments, allowing both sides to better manage their risks. This would
in turn increase the likelihood of the investments turning out to be profitable.
The above analyses also highlights that the market, of improved along the lines with the
measures assessed in the present impact assessment, can deliver to a large extent the
necessary investments for a wide range of technologies in the long term, thereby reducing the
need for government intervention to support investment in electricity resources.
Box 7: RES E investments and market design
Amongst all sectors that make up our energy system, electricity is the most cost-effective to
decarbonize. Currently about one fourth of Europe's electricity is produced from renewable
energy sources. Modelling indicates that the share of RES E in electricity generation needs to
almost double by 2030 in order for the EU to meet its 2030 energy and climate targets.
A functioning market is the most efficient tool to implement the decarbonisation agenda at
least costs while securing electricity supplies at all times.
The Commission's ambition for the post-2020 context is that renewable electricity generators
can earn an increasingly larger fraction of their revenues from the energy markets.
This ambition requires adapting the market design for the cost-effective operation of variable,
decentralised generation, and improving the market as the catalyst for investments by
removing regulatory failures and market imperfections. In a nutshell, markets will need to:
(a) be more focused on short-term trading, including cross-border trading, to allow
electricity from wind and solar energy to effectively compete in the market;
(b) link wholesale and retail markets to increase the flexibility of the system, let
consumers benefit from times of cheap electricity, let them engage in demand
response systems and produce electricity themselves; and,
(c) become even better at generating investment signals – as a matter of principle, it
should be the market through its price signals triggering investments.
In this context, the present impact assessment investigates a number of options that improve
market functioning by removing market distortions between different types of generation, that
render the market's operation more flexible and adapted to the cost-effective operation of
variable generation and improving the conditions for the participation of decentralised,
flexible resources, such as demand and storage, into the market. Moreover, it investigates
various means to improve price signals inciting investment in the right resources and location
and investments in infrastructure.
The enhanced market design will improve the viability of RES E investments, but electricity
market revenues alone might not prove sufficient in attracting renewable investments in a
timely manner and at the required scale to meet EU's 2030 targets.
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Assessment of the impacts of the various policy options
The enhanced market design and the strengthened ETS will improve the viability of RES E
investments, in particular through the following channels:
- Where the marginal producer is a fossil fired power plant, a higher carbon price translates
into higher average wholesale prices. The existing surplus of allowances is expected to
decrease due to the implementation of the Market Stability Reserve and the higher Linear
Reduction Factor, reducing the current imbalance between supply and demand for
allowances;
- Greater system flexibility will be critical for a better integration of RES E in the system,
reducing their hours of curtailment and the related forgone revenues; improving overall
system flexibility is equally essential to limit the merit-order effect335
and thus in avoiding
the erosion of the market value of RES E produced electricity336
- The revision of priority dispatch rules and the better functioning of the short-term markets
will strongly reduce (even eliminate according to the analysis) the occurrence of negative
prices – leading again to higher average wholesale prices (especially during the hours with
significant variable RES E generation);
- Improved market rules for intraday and balancing markets will increase their liquidity and
allow access to those markets for all resources, thus helping RES E generators reduce their
balancing costs;
- Removing existing (explicit or implicit) restrictions for the participation of all resources to
the reserve and ancillary services markets will allow RES E to generate additional
revenues from these markets.
- Price signals reflecting the actual value of electricity at each point of time, as well as the
value of flexibility, will help ensure that flexible capacity is properly rewarded,
channelling investment into such capacities or prevent its decommissioning.
With technology costs gradually reducing, ETS price increasing and the electricity market
prices better reflecting the value of electricity, RES E investments in the electricity market
will gradually become more and more market-based, reflecting the balance of supply and
demand for the coming years and the associated costs to each technology.
The present impact assessment and the one on the RED II thus jointly come to the conclusion
that the improved electricity market, in conjunction with a revised ETS could, under these
conditions, deliver investments in the most mature renewable technologies (such as solar PV
and onshore wind).
However, despite best efforts in market integration, electricity market revenues alone might
not prove sufficient in attracting renewable investments in a timely manner and at the required
scale to meet EU's 2030 targets. This investment gap is analysed in more details in the RES II
335
Also referred occasionally as the 'cannibalisation effect'.
336
The inherent variability of wind exposure and solar radiation affects the price that variable renewable
electricity generators receive on the market (market value). During windy and sunny days the additional
electricity supply reduces the prices. Because the drop is larger with more installed capacity, the market
value of variable renewable electricity falls with higher penetration rate, translating into a gap to the average
market value of all electricity generators over a given period (See Hirth, Lion, "The Market Value of
Variable Renewables", Energy Policy, Volume 38, 2013, p. 218-236)
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Assessment of the impacts of the various policy options
impact assessment. The analysis shows that the picture is dynamic, with the enhanced market
design and the strengthened ETS gradually and increasingly improving RES E profitability
over the 2021-2030 period. At the beginning of the period, over-capacity, low ETS and
wholesale market prices and still high RES E technology costs, make the case for investments
in RES E technologies more difficult. However, an increasing ETS price, a more flexible and
dynamic electricity market, technology costs reductions and adjustments in capacity
increasingly facilitate investments over this period337
.
The impact assessment for RED II concludes that over the period 2021-2030 around half of
the additional RES E capacity will still need some kind of support, but with significant
decrease in the number of investments needing support towards 2030.
In particular, less mature RES E technologies, such as off-shore wind, will likely need some
form of support throughout the 2021-2030 period. These technologies are required if RES E
technologies are to be deployed to the extent required for meeting the 2030 and 2050 energy
and climate objectives, and provide an important basis for the long-term competitiveness of
an energy system based on RES E.
The picture also depends on regions. RES E technologies are more easily financed from the
market in the regions with the highest potential (e.g. onshore wind in the Nordic region or
solar in Southern Europe), while RES E continue to largely require support in the British Isles
and in Central Europe.
Additionally, it should be noted that the speed at which RES E parity338
is reached, in addition
to the successful implementation of the MDI and ETS, also depends on factors that lay
outside of the scope of these initiatives, including: (i) continued decrease in technology costs
for RES E as well as complementary technologies (e.g. storage); (ii) the availability of
(reasonably cheap) capital, which is a function of many variables, including project-specific
and RES E framework-specific risks, but also general country risk; (iii) continued social
acceptance; (iv) sufficiently high and stable fossil fuel prices.
The need for a framework for RES E support schemes
In order to address the risks associated with investments in RES E and the chance of failing to
meet EU's 2030 target for RES, the MDI and the RED II impact assessments jointly consider
that electricity market and ETS policies need to be complemented by an improved policy
framework on RES E support schemes.
Against this background, the RED II impact assessment investigates options to ensure that, if
and where support is needed, support is only applied where needed in a manner that is: (i)
cost-effective and kept to a minimum, and (ii) creates as little distortions as possible to the
338
i.e. the moment when LCOE decreases to the level of the actual market value of the asset to be
financed.
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Assessment of the impacts of the various policy options
functioning of electricity markets, and to competition between technologies and between
Member States. Indeed, the market can only deliver the full benefits sketched above, if
policies fostering RES E are compatible with the market environment in which they operate.
In particular, the RED II impact assessment suggests creating a common European framework
for support schemes. The framework would be effective as it would define design principles
(i) that ensure sufficient investor certainty over the 2021-2030 and (ii) require the use (where
needed) of market-based and cost-effective schemes based on emerging best practice design
(including principles that are not covered by the current State Aid guidelines).
At the same time, the framework would be proportionate by leaving actual implementation to
the State Aid guidelines (e.g. for the definition of thresholds applicable for any foreseen
exemptions) and, most importantly, to the case by case, evidence-based, in-depth assessment
of individual schemes by the services of DG Competition .Importantly, the framework would
enshrine in legislation and expand the requirement to tender support; it would define tender
design principles, based on emerging best practice, to ensure the highest cost-efficiency gains
and to ensure market incentives are least distorted by the support mechanism.
The framework would thus strengthen the use of tenders as a natural phase-out mechanism for
support, by which a competitive bidding process determines the remaining level of support
required to bridge any financing gap – such level of support being expected to disappear for
the most mature technologies over the course of the 2021-2030 period.
The importance of a framework for RES E support schemes for the present initiative.
It is also important to note that the progressive reform of RES E support schemes as proposed
by the RED II initiative, building on the EEAG, is a prerequisite for the results of the present
initiative to come about. In order to ensure that a market can function, it is necessary that
market participants are progressively exposed to the same price signals and risks. Support
schemes based on feed-in-tariffs prevent this and would need to be phased-out, with limited
exemptions, and replaced by schemes that expose RES E to price signals, as for instance
premium based schemes. This would be further supported by setting aid-levels through
auctioning as RES E investment projects will then be incentivised to develop business models
that optimise market-based returns339
.
How different types of CMs might affect RES E remuneration in the market
In market-wide, volume-based CMs, assets are remunerated if they can respond to specific
technical performance criteria (i.e. in practice if they are dispatchable). Hence, it is likely that
variable RES E producers (wind and solar) cannot participate in such schemes to the same
extent as dispatchable generators. As the introduction of a market-wide volume-based scheme
might render scarcity-based pricing less effective, RES E producers might receive less income
then they would otherwise be able to earn on energy-only markets. A well-designed strategic
reserve (provided it is activated (only at value of lost load and activated as a measure of last
339
See also Annex IV for more information for information on the robustness on
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Assessment of the impacts of the various policy options
resort (see above)), is less likely to have a negative impact on market revenues for
intermittent RES E, as such a scheme relies on commodity price signals only and does not
interact with scarcity-based pricing.
6.2.6.4.Level and volatility of wholesale prices
The analysis performed using all three models (METIS, PRIMES/IEM, PRIMES/OM)
confirms that the projected investments in low carbon technologies, combined with increased
demand response participation, are not expected to lead to the collapse of the wholesale
market prices in the short and medium term. Although there will be hours with low (or even
negative) prices, the wholesale prices will most probably be set by the marginal thermal
generation technology during most hours of the year. Table 21 presents the distribution of
wholesale prices in 2030, assessed for the various options of Problem Area I with
PRIMES/IEM. Results indicate that the wholesale prices will fluctuate, but within reasonable
limits on an EU level340
.
Table 21: Distribution of load weighted day-ahead market prices341
in 2030
Day-ahead price
in 2030 (EUR/MWh)
Number of Hours
Option 0 Option 1(a) Option 1(b) Option 1(c)
Baseline
Level playing
field
Strengthening
short-term
markets
Fully integrated
markets
Below 60 0 0 84 0
Between 60-80 0 0 1155 1572
Between 80-90 2482 2642 2394 3169
Between 90-100 3254 3290 2870 3121
Between 100-110 2197 2013 1288 484
Between 110-120 372 555 528 0
Between 120-140 455 260 88 150
Above 140 0 0 353 264
Source: NTUA Modelling (PRIMES/IEM)
The above results do indicate that the improved market design will lead to more volatile
average hourly prices, partly due to the introduction of locational signals which reveal the
340
Certain Member States though with very high RES E shares, like Spain and Portugal, and limited
interconnections are expected to have significantly more volatile wholesale prices than other Member States.
341
Reported results reflected assumed bidding behaviour of generators. The behaviour was relatively
conservative, reflecting though a stable condition in the market and the effects of competition (though
market power was considered). The most important assumption driving these results is that plants bid above
marginal costs and the hydro plants bid at opportunity costs. Minimum price observed (on EU28 level) was
not lower than 60 EUR/MWh, highest price did not exceed 200 EUR/MWh. There were higher and lower
prices on Member State level.
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Assessment of the impacts of the various policy options
different value of electricity in the various nodes. This volatility though will be fairly
restricted and will not be the result of extreme price fluctuations between zero and VoLL. The
observed price ranges will be fairly constrained, as long as the share of variable RES E
remains within certain limits342
. When the share of RES E, and specifically of variable RES E
technologies, exceeds these rough limits though, price volatility may increase significantly if
other resources like storage are not in place yet to absorb a large part of it.
As can be seen in the table below, in 2050 the share of RES E is projected to approach 60%.
In this case the spread between the baseload and peak load prices increases significantly,
mainly due to the lower baseload prices compared to the previous periods. The average day-
ahead market prices though remain high throughout the projection horizon, as thermal
generation is still expected to be marginal (thus setting the day-ahead market price) during
most hours of the year.
Table 22: Average wholesale prices and RES E Shares
2020 2025 2030 2035 2040 2045 2050
Average wholesale market prices343
(EUR 13/MWh)
Average day-ahead market prices 74 95 103 118 115 135 122
baseload 74 83 93 98 89 108 71
mid-merit 74 95 103 118 116 137 122
peak load 93 98 137 135 134 149 138
Spread between average
baseload and peak load SMP
19 15 44 38 45 41 67
Share of RES E in net electricity generation (%)
Share of variable RES E 30.8 36.0 40.4 43.0 49.6 53.2 57.5
Solar 4.8 7.7 8.9 9.4 9.9 11.1 13.6
Wind 14.4 17.0 20.4 22.7 29.3 32.1 34.1
Source: NTUA modelling (PRIMES/OM)
342
A study by METIS finds that as long as the share of solar generation is lower than 10-12% of total
electricity generation, solar production coincides with periods of high power demand and tends to smooth-
out residual demand over the day, which is expected to lead to less variable prices. This changes though
considerably for higher shares of solar. On the other hand, wind energy is directly related to variability and
is a significant driver for flexibility needs. "METIS Study S7: The role and need of flexibility in 2030. Focus
on Energy Storage", Artelys (2016).
343
Based on the modelling methodology followed, described in Annex IV, reported wholesale prices reflect the
level of electricity prices which would lead to the recovery of the full costs of generators only via the
wholesale market, on a plant by plant basis and over the lifetime of each asset in the case of an Energy only
Market (i.e. Option 1). This modelling context differs significantly from the current one, characterised by
different underlying market conditions (overcapacity, low fuel prices, distorted markets etc). See also Box 9
in Section 6.2.6.4 for a further discussion on this topic.
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Assessment of the impacts of the various policy options
6.3. Impact Assessment for problem Area III (reinforce coordination between
Member States for preventing and managing crisis situations)
Methodological Approach
6.3.1.
In this section the impacts of the different policy options are identified and assessed. The
options proposed should first and foremost be effective in improving trust of Member States
to rely on neighbours' electricity markets in times of system stress. They should also lead to a
more effective functioning of markets, with less undue market distortions. Additionally,
reinforced coordination and cooperation between Member States in the identification and
mitigation of risks and the management of crisis have also been identified as specific
objectives.
The methodological approach followed for this analysis is mostly qualitative; however some
quantitative analysis is provided as well, notably via the METIS simulations.
As regards the impacts, given the administrative nature of the measures and the objectives
pursued, the most relevant impacts in terms of magnitude are the economic impacts.
The measures proposed (e.g. enhanced regional coordination and information exchange)
anticipates a very limited impact, if any, on the environment. Therefore, the assessment does
not examine the impact of the proposed measures on the environment.
Impacts of Policy Option 1 (Common minimum rules to be implemented by Member
6.3.2.
States)
6.3.2.1.Economic impacts
Overall, the policy tools proposed under this option should have positive effects. Putting in
place a more common approach to crisis prevention and management would not entail
additional costs for businesses and consumers. It would, by contrast, bring clear benefits to
them.
First, a more common approach would help better prevent blackout situations, which are
extremely costly. The immense costs of large-scale blackouts provide an indication of
potential benefits of improved preparation and prevention344
.
344
Previous blackouts in Europe had severe consequences. For example, the blackout in Italy in September
2003 resulted in a power disruption for several hours affecting about 55 million people in Italy and
neighbouring countries and causing around 1.2 billion euros worth of damage. (source: The costs of
blackouts in Europe (2016), EC CORDIS: http://cordis.europa.eu/news/rcn/132674_en.html).
193
Assessment of the impacts of the various policy options
Table 23: Overview over most severe blackouts in Europe
Country & year
Number of end-
consumers
interrupted
Duration,
energy not
served
Estimated costs to
whole society
Sweden/Denmark,
2003
0.86 million
(Sweden); 2.4
million (Denmark)
2.1 hours, 18
GWh
EUR 145 – 180
million
France, 1999 1.4 - 3.5 million
2 days–2 weeks,
400 GWh
EUR 11.5 billion
Italy/Switzerland,
2003
55 million 18 hours
Sweden, 2005 0.7 million
1 day – 5 weeks,
11 GWh
EUR 400 million
Central Europe, 2006 45 million
Less than 2
hours
Source: SESAME: Securing the European Electricity Supply Against Malicious and Accidental Threats
A more common approach to emergency handling, with an obligation for Member States to
help each other, would help to avoid or limit the effects of potential blackouts. A more
common approach, with clear obligations to e.g., follow up on the results of seasonal
outlooks, would also reduce the costs of remedial actions TSOs have to face today. This, in
turn, should have a positive effect with a reduction of costs overall.
In addition, improving transparency and information exchange would facilitate coordination,
leading to a more efficient and less costly measures.
By ensuring that electricity markets operate as long as possible also in stress situations, cost-
efficient measures to prevent and resolve crisis are prioritized.
6.3.2.2.Who would be affected and how
Option 1 is expected to have a positive effect on society at large and electricity consumers in
particular, since it helps prevent crisis situations and avoid unnecessary cut-offs. Given the
nature of the measures proposed, no major other impact on market participants and consumers
is expected.
On cybersecurity, given the voluntary approach of this option, several stakeholders (TSOs,
DSOs, generators, suppliers and aggregators) could be affected, as long as they implement the
guidance proposed. However, the impact is estimated limited as the costs of cybersecurity for
regulated entities merely need to get considered and taken into account by the regulatory
authority. Thus, the TSOs and DSOs affected could recover their costs via grid tariffs. In that
case, the pass through of costs would have an impact on consumers that could see a slightly
increased in the final prices of electricity.
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Assessment of the impacts of the various policy options
6.3.2.3.Impact on businesses and public authorities
The preparation of risk preparedness plans as well as the increased transparency and
information exchange in crisis management imply a certain administrative effort345
. However,
the impact in terms of administrative impact would remain low, as currently Member States
already assess risks relating to security of supply, and all have plans in place for dealing with
electricity crisis situations346
.
In addition, it is foreseen to withdraw the current legal obligation for Member States to draw
up reports monitoring security of supply347
, as such reporting obligation will no longer be
necessary where national plans reflect a common approach and are made transparent. This
would reduce administrative impacts.
Impacts of Policy Option 2 (Common minimum rules to be implemented by Member
6.3.3.
States plus regional co-operation)
6.3.3.1.Economic impacts
This option would lead to better preparedness for crisis situations at a lesser cost through
enhanced regional coordination. The results of METIS simulations348
show that well
integrated markets and regional coordination during periods of extreme weather conditions
(i.e. very low temperature349
) are crucial in addressing the hours of system stress (i.e. hours of
extreme electricity demand), and minimizing the probability of loss of load (interruption of
electricity supply).
Most importantly, while a national level approach to security of supply disregards the
contribution of neighboring countries in resolving a crisis situation, a regional approach to
security of supply results in a better utilization of power plants and more likely avoidance of
loss of load. This is due to the combined effect of the following three factors: (i) the
variability of renewable production is partly smoothed out when one considers large
geographical scales, (ii) the demands of different countries tend to peak at different times, and
(iii) the power supply mix of different countries can be quite different, leading to synergies in
their utilization.
345
Administrative costs are defined as the costs incurred by enterprises, the voluntary sector, public authorities
and citizens in meeting legal obligations to provide information on their action or production, either to
public authorities or to private parties.
346
See Risk Preparedness Study.
347
Article 4 of the Electricity Directive; Article 7 of the Electricity SoS Directive.
348
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016).
349
Even though periods with very low temperature occur rarely (9C difference between the 50 year worst case
and the 1% centile) countries can face high demand peaks (e.g. Nordic countries and France) mainly due to
the high consumption for the electric heating. As example, the additional demand for the 50 years peak
compared to the annual peak demand is 23% for France, 18% for Sweden and 17.3% for Finland.
195
Assessment of the impacts of the various policy options
The following table compares the security of supply indicator, EENS, assessed by METIS for
the three levels of coordination (national, regional, European)350
. It highlights the highest
value of the loss of load (electricity non-served expressed as percentage of annual load) when
it is measured in a scenario of non-coordinated approach, which does not take into account the
potential mutual assistance between countries. When cooperation takes place among Member
States, the percentage of electricity non-served significantly decreases.
Table 24 - Global expected energy non-served as part of global demand within the three
approaches for scenario ENTSO-E 2030 v1 with CCGT/OCGT current generation
capacities
Level EENS (% of annual load) – ENTSO-E V1 scenario
National level 0,36 %
Regional level 0,02 %
European level 0,01 %
ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario where no
common European decision regarding how to reach the CO2-emission reductions has been reached. Each
country has its own policy and methodology for CO2, RES and resource adequacy.
Source: METIS
The EENS for the three levels of coordination are represented on the figure below. When the
security of supply is assessed at the national level, many countries of central Europe seem to
present substantial levels of loss of load. However, since these countries are interconnected, a
regional assessment of security of supply (taking into account power exchanges within this
region) significantly decreases the loss of load levels.
350
"METIS Study S04: Stakes of a common approach for generation and system adequacy", Artelys (2016).
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Assessment of the impacts of the various policy options
Figure 14 - EENS (%) estimation by country for scenario ENTSO-E 2030 v1 with
CCGT/OCGT current generation capacities. From left to right: EENS estimated at
European, regional and national levels
CCGT: Combined Cycle Gas Turbine OCGT: Open Cycle Gas Turbine
ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario where no
common European decision regarding how to reach the CO2-emission reductions has been reached. Each
country has its own policy and methodology for CO2, RES and resource adequacy.
Source: METIS
METIS simulations also show that thanks to regional cooperation the stress situations would
decrease and concentrate in a limited number of hours that may occur simultaneously351
.
Therefore, it highlights the need for specific rules on how Member States should proceed in
these particular circumstances, as proposed in this Option 2.
As the overall cost of the system would decrease thanks to enhanced coordination this could
have a positive impact on prices for consumers.
On the contrary, a lack of coordination on how to prevent and manage crisis situations would
imply significant opportunity costs. A recent study also evidenced that the integration of the
European electricity market could deliver significant benefits of EUR 12.5 to 40 billion until
2030. However, this amount would be reduced by EUR 3 to 7.5 billion when Member States
pursue security of electricity supply objectives following going alone approaches352
.
6.3.3.2.Who would be affected and how
As in the case for Option 1, Option 2 is expected to have a positive effect on society at large
and electricity consumers in particular, since it helps prevent crisis situations and avoid
351
Please also see in Annexes to the Impact Assessment: Assessment of the Measures Associated with the Main
Option: Graphs 1 and 2 in "6. Detailed measures assessed under problem area 3: a new legal framework for
preventing and managing crises situations".
352
Benefits of an Integrated European Energy Market (2013), BOOZ&CO.
197
Assessment of the impacts of the various policy options
unnecessary cut-offs. Given that, under Option 2, Member States would be required to
effectively cooperate, and tools would be in place to monitor security of supply via the
Electricity Coordination Group, such crisis prevention and management would be even more
effective.
The measures would also have a positive effect on the business community, as there would be
much more transparency and comparability as regards how Member States prepare for and
intend to manage crisis situations. This will increase legal certainty for investors, power
generators, power exchanges but also for TSOs when managing short-term crisis situations.
Among the stakeholders the most affected would be the competent authorities (e.g. Ministry,
NRA) as actors responsible for the preparation of the risk preparedness plans (see below,
assessment of impacts on public authorities).
6.3.3.3.Impact on businesses and public authorities
The assessment of this option shows a limited increase in administrative impact, although it
would be to some extent higher than Option 1, given that national authorities would be
required to pre-agree part of their risk preparedness plans in a regional context.
However, existing experiences show that a more regional approach to risk assessment and risk
preparedness is technically and legally feasible. Further, since the regional parts of the plans
would in practice be prepared by regional co-ordination centres between TSOs, the overall
impact on Member States' administrations in terms of 'extra burdens' would be limited, and be
clearly offset by the advantages such co-operation would bring in practice.353
In addition, more regional cooperation would also allow Member States to create synergies, to
learn from each other, and jointly develop best practices. This should, overtime, lead to a
reduction in administrative impacts.
Finally, European actors such as the Commission and ENTSO-E would provide guidance and
facilitate the process of risk preparation and management. This would also help reduce
impacts on Member States.
It should be noted, that under Option 2 (as is the case for Option 1) no new body or new
reporting obligation is being created, and that existing obligations are being streamlined.
Thus, the Electricity Coordination Group is an existing body meeting regularly, for the future
it is foreseen to make this group more effective by giving it concrete tasks. Further, national
reporting obligations would be reduced (e.g. repealing the obligation of Article 4 of
Electricity Directive) and EU-level reporting would take place within the context of existing
reports and existing reporting obligations (e.g. ACER annual report Monitoring the Internal
Electricity and Natural Gas Markets).
353
The Nordic TSOs, regulators and energy authorities cooperate through NordBER, the Nordic Contingency
and Crisis Management Forum. This includes information exchange and joint working groups and
contingency planning for the overall Nordic power sector as a supplement to the national emergency work
and TSO cooperation (www.nordber.org).
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Assessment of the impacts of the various policy options
Impacts of Policy Option 3 (Full harmonisation and full decision-making at regional
6.3.4.
level)
6.3.4.1.Economic impacts
The regional coordination through the regional plans would have a positive impact in term of
cost as the number of plans would be necessary less than twenty-eight plans and limited to the
number of regions. In addition, the coordination at European level would decrease slightly the
loss of load level compared to the regional coordination (EENS 0.01% compared to 0.02%).
On the contrary, on cybersecurity, the creation of a dedicated agency at EU level would have
important economic implications as this agency would be a new body that does not exist yet
and which is also not foreseen in the NIS Directive. The costs of creating this new agency are
not only limited to the creation of a new agency itself, but the costs would also have to
include the roll-out of a whole security infrastructure. For example, the estimated costs of
putting in place the necessary security infrastructure and related services to establish a
comparable national body - cross-sectorial governmental Computer Emergency Response
Team ("CERT") with the similar duties and responsibilities at national level as the planned
pan-European sector-specific agency - would be approximately EUR 2.5 million354
per
national body. This means that the costs for the security infrastructure would be manifold for
a pan-European body. In terms of human resources, for the proper functioning of the new
agency with minimum scope and tasks at EU level, it is estimated a staff of 168 full time
equivalents (considering 6 full time equivalents per Member State sent to the EU agency).
The representation from all Member States in the agency is essential in order to ensure trust
and confidence on the institution. However, the availability of network and information
security experts who are also well-versed in the energy sector is limited.
6.3.4.2.Who would be affected and how
The obligation of regional plans would have important implications for the competent
authorities as the coordination and agreement of common issues (e.g. load shedding plan,
harmonised definition of protected customers) would be a lengthy and complex process.
On cybersecurity, the creation of the new agency at EU level would mobilize highly qualified
human resources with skills in both energy and information and communication technologies.
This could have a potential impact on national administrations and energy companies as long
as some of the experts in the field could be recruited by the new institution. However, the
impact would be limited as the representation for all Member States should be guaranteed.
Therefore, a small number of experts (around 6) per country could be recruited.
354
"Impact Assessment accompanying the document Proposal for a Directive of the European Parliament and
of the Council Concerning measures to ensure a high level of network and information security across the
Union". SWD(2013) 32 final.
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Assessment of the impacts of the various policy options
6.3.4.3.Impact on businesses and public authorities
Overall Option 3 would imply significantly administrative impact in the preparation of the
regional plans. It would require important efforts to gather information related to national and
regional circumstances and contribute to the joint task of assessing the risks and identifying
the measures to be included in the plans. In any case, it would seem difficult to coordinate
within a region the national specificities and risks originate mostly in one Member State.
The creation of a new agency on cybersecurity would imply significant administrative
impacts in the preparation and set-up of the agency, as well as in the communication structure
with already existing cross-sectorial bodies of Member States (CERTs/ Computer Security
Incident Response Teams "CSIRTs").
6.4. Impact Assessment for Problem Area IV (Increase competition in the retail
market)
Methodological Approach
6.4.1.
This section compares the costs and benefits of each of the policy options to address this
Problem Area in a semi-quantitative manner.
No data or methodology exists that would allow us to accurately quantify all the benefits of
the measures examined.
However, this section draws on behavioural experiments from a controlled environment to
evaluate the impact of some policy options on consumer decision-making. Where economic
impacts cannot be quantified, quantitative desktop research and case studies are used to
inform estimates of the extent of possible impacts, as well as possible winners and losers.
Where appropriate, this section aims to illustrate the possible direct benefit to consumers
assuming certain conditions. Implementation costs in terms of the impact on businesses and
public authorities were estimated using the standard cost model for estimating administrative
costs. And finally, this section also highlights important qualitative evidence that
policymakers should also incorporate into their analysis of costs and benefits.
Impacts of Policy Option 0+ (Non-regulatory approach to improving competition and
6.4.2.
consumer engagement)
6.4.2.1.Economic Impacts
Option 0+ would lead to an estimated EUR 415 million in benefits to consumers for the
period 2020-2030, which come as a result of an enforcement drive to tackle the switching
costs currently faced by an estimated 4% of all EU electricity consumers that do not comply
with EU law355
.
355
See Annex 7.4, Section 7.4.5.
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Assessment of the impacts of the various policy options
Other unquantifiable economic benefits include improved retail level competition resulting
from the phase-out of regulated prices in some Member States356
, and more comparison tools
that comply with the Unfair Commercial Practices Directive357
.
In addition, one may expect modest, indirect improvements to the health and well-being of
energy poor consumers from the exchange of good practices stemming from the activities of
the EU Observatory for energy poverty358
.
In spite of these considerations, it is unlikely that Option 0+ (Non-regulatory approach) would
most effectively address the problems identified.
First, this option does not address the poor data flow between retail market actors that
constitutes both a barrier to entry and a barrier to higher levels of service to consumers.
Whereas Option 0+ is non-regulatory, a credible policy to tackle conflicts of interest among
market actors around data handling would require a legislative intervention.
Secondly, as a non-regulatory option, the effectiveness of Option 0+ is significantly limited
by shortcomings in the existing legislation. This significantly reduces the ability to address
contract termination fees (which are currently legal under EU law), the partial availability of
comparison websites in Member States, as well as energy poverty, which the current
legislation does not require Member States to measure, and hence address it.
And finally, a non-regulatory approach to tackling price-regulation may lead to a fragmented
regulatory framework across the EU given: (i) the uncertainty that surrounds the
Commission's ability to convince hold-out Member States to voluntarily cease excessive
regulatory interventions in price-setting; and (ii) the uncertainty that surrounds the success of
any subsequent legal measures to infringe Member States on the issue.
6.4.2.2.Who would be affected and how
Consumers will benefit from more easily being able to compare offers in the market, as well
as lower financial barriers to switching. Whilst consumer prices may rise in Member States
phasing out price regulation, this would be offset by higher levels of service and the greater
availability of value added products on the market.
Member States will benefit from a clearer understanding and measurement of energy poverty
will have indirect positive impacts on energy poor consumers.
Suppliers would benefit from increased access to the market of any Member State phasing
out price regulation. However, certain suppliers would also face tougher competition and
increased pressure on margins as the result of the modestly greater consumer engagement
expected.
356
See Annex 7.2, Section 7.2.5.
357
See Annex 7.5, Section 7.5.5.
358
See Annex 7.1, Section 7.1.5.
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Assessment of the impacts of the various policy options
Any increase in consumer switching would increase the administrative impacts to DSOs.
However, these costs would be passed through to end consumers.
NRAs in any Member States phasing out price regulation will need to significantly step up
efforts to monitor the market, ensure efficient competition, and guarantee consumer
protection. They will need to more closely monitor and report the number of disconnections.
However, this may be offset by a reduction in price setting interventions, and increased
competition resulting from greater consumer engagement.
6.4.2.3.Impact on businesses and public authorities
Option 0+ (Non-regulatory approach) would lead to quantifiable implementation costs of
around EUR 0.9 million for the period 2020-2030, all resulting from setting up and running an
EU Observatory for energy poverty359
. It is anticipated that the soft law and enforcement
measures associated with making better use of the existing legislation on regulated prices,
switching fees and comparison tools would not result in significant additional costs compared
with a business as usual scenario.
Impacts of Policy Option 1 (Flexible legislation addressing all problem drivers)
6.4.3.
6.4.3.1.Economic Impacts
Option 1 would lead to an estimated EUR 2.2 billion in direct benefits to consumers for the
period 2020-2030, which come as a result of: (i) reducing the switching-related charges faced
by 21% of household electricity consumers, and so helping them realize the potentially
significant gains of moving to a cheaper tariff360
; (ii) further improvements to the switching
rate for both electricity and gas household consumers as a result of the improved availability
of price comparison tools361
; (iii) an improved ability for consumers to identify the best offer
in the market through improved access to information on the bill (although the gains of this
latter intervention are not easy to quantify compared for instance with interventions aimed at
making switching less costly for consumers)362
.
Other unquantifiable economic benefits include significantly improved retail competition
resulting from the definitive phase-out of blanket price regulation in the 17 Member States
still practicing it363
. The impact of phasing out price regulation on retail price levels is
impossible to quantify. However, the evidence strongly suggests it will lead to higher levels
of consumer satisfaction. Indeed, even the energy component of retail bills does increase
slightly in the short-term, consumer surplus (the difference between the price of the service
and the price a consumer would be willing to pay for that service) may actually increase too
as a result of the better service levels consumers receive in the non-regulated market. In
359
The Commission secured funding to set up the Observatory for the period 2016-2019. The costs included in
the Impact Assessment refer to the running annual cost to continue operating the Observatory. See Annex
7.4, Table 11 and Section 7.1.5.
360
See Annex 7.4, Section 7.4.5.
361
See Annex 7.6, Section 7.6.5.
362
See Annex 7.4, Section 7.4.5.
363
See Annex 7.2, Section 7.2.5.
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Assessment of the impacts of the various policy options
addition, retail price competition is an important prerequisite for new services that would
increase system flexibility (benefits examined in Section 6.1.4), and should lead to lower
system costs that are passed through to consumers in both the energy and network
components of bills in the longer term.
Non-discriminatory access to consumer data and nationally harmonized data formats will also
help new suppliers and service providers to enter the market and develop innovative new
products, resulting in further competition benefits and facilitating the transition to a more
flexible electricity system364
.
Greater consumer engagement will also drive retail competition improvements, as competitive
suppliers and service providers find it easier to take market share from less competitive
alternatives. Other benefits come in terms of the higher levels of service electricity consumers
can expect from more efficient data handling, and greater consumer awareness of the market
and their own energy situation.
In addition, one may expect improvements in the targeting of measures to tackle energy
poverty. Better measurement of the number of households on energy poverty will allow
Member States and the EU to design better policies and exchange good practices. A generic
definition of energy poverty in the legislation will clarify the concept of energy poverty,
improving the functioning of the current provision and further helping knowledge
dissemination and synergies across EU policies in energy efficiency and consumer protection.
6.4.3.2.Who would be affected and how
Consumers will benefit significantly from more easily being able to compare offers in the
market, as well as lower financial barriers to switching. Whilst consumer prices may rise in
the Member States phasing out price regulation, this would be offset by higher levels of
service and the greater availability of value added products on the market. Consumers would
also benefit from increased competition and higher levels of service resulting from rules that
ensure quick and non-discriminatory access to data.
Box 8: Impacts on different groups of consumers
The benefits of the vast majority of the measures contained in the preferred options in
Problem Areas I, II and III would manifest through lower system costs and greater system
reliability, and therefore accrue to all consumers in an even manner. However, most of the
measures contained in the preferred option of Problem Area IV, above, would benefit certain
kinds of consumers more than others.
For example, whereas energy poor households would be the chief beneficiaries of new
obligations to measure energy poverty levels, the marginally increased burdens of these
obligations would be socialized amongst other ratepayers/taxpayers. In addition, whereas
phasing out price regulation would free public finances to better protect households who
qualify for targeted social support measures (i.e. vulnerable and/or energy poor consumers),
364
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” (2016) Copenhagen
Economics, and VVA.
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Assessment of the impacts of the various policy options
the biggest losers from this policy would be high-volume, often higher-income consumers
who have hitherto benefitted from retail prices that have been set at artificially low levels.
Both these measures can therefore be considered progressive in nature i.e. they tend to
redistribute surplus from relatively high-income ratepayers/taxpayers in order to increase the
welfare of lower-income ratepayers.
The measures on switching-related fees and comparison tools would predominantly benefit
consumers who are engaged in the market i.e. those who compare offers and/or switch
regularly. Whilst the measures would also increase consumer engagement levels, and whilst
the increased competition engendered by the measures would lead to more competitive offers
on the market, disengaged consumers, including consumers who may be vulnerable, will not
reap as many direct benefits.
And finally, the benefits of the billing measures would accrue predominantly to consumers
who do not engage in the market or better control their energy consumption because of
insufficient billing information or confusing bills. This may include a varied range of
consumers, including certain vulnerable consumers, or those who are time poor.
Many Member States will benefit from a clearer understanding of energy poverty, which will
have indirect positive impacts on energy poor consumers. However, Member States will also
need to collect and report more information on energy poverty as a result of requirements in
this option.
Suppliers would benefit from increased access to the market of the Member States phasing
out price regulation. New entrants and energy service companies offering innovative
products would also benefit from quick and non-discriminatory access to data. However,
suppliers would also likely face increased pressure on margins as the result of the modestly
greater consumer engagement expected. Certain suppliers may need to adjust contractual
conditions and reformat their consumer bills in order to comply with new requirements on
contract termination fees and billing information. And they would likely also bear the brunt of
the significant costs to protect energy poor consumers.
As TSOs and DSOs are normally the market actors charged with data management, they
would be the most affected by the new data management requirements – particularly the
DSOs who currently fall below the unbundling threshold as they would need to implement
further measures to ensure non-discriminatory data handling. Any increase in consumer
switching would also increase the administrative impacts to DSOs. However, all these costs
would be passed through to end consumers. In addition, network operators would benefit from
the anticipated entrance of aggregators and other energy service companies who facilitate
network flexibility, as a result of non-discriminatory data flows.
NRAs in the 17 Member States phasing out price regulation will need to significantly step up
efforts to monitor the market, ensure efficient competition, and guarantee consumer
protection. However, these impacts may be offset by increased consumer engagement, which
would naturally foster competition in the market.
6.4.3.3.Impact on businesses and public authorities
It is estimated that implementing the consumer-related elements of Option 1 (Flexible
legislation) would lead to quantifiable costs of between EUR 21 million and EUR 24 million
204
Assessment of the impacts of the various policy options
for the period 2020-2030. These would mainly stem from national authorities having to set up
and run certification schemes for energy comparison tools or an independently run energy
comparison tool themselves365
. However, many suppliers would also bear costs associated
with modifying their consumer bills to comply with the modest requirements in this option366
.
Unquantifiable impacts come in the form of the reduced contractual freedom that suppliers
have, which is associated with the restriction on contract termination fees for certain kinds of
contracts only367
.
Implementing the energy poverty provisions in Option 1 (Flexible legislation) would result in
quantifiable costs of EUR 2.3 million for the period 2020-2030. These primarily result from
measuring energy poverty making reference to household income and household energy
expenditure using data already collected by Member States368
.
Significant, albeit unquantifiable costs are associated with creating a level playing field for
access to data in Option 1 (Flexible legislation). In particular, ensuring that Member States
implement a standardised data format at the national level will significantly impact many
market actors (suppliers, DSOs, third parties such as energy service companies, data
administrators), who would have to redesign their IT systems to accommodate this format.
However, these costs will be mitigated by the fact that measures can be applied independently
of the data management model that each Member State has chosen. This reduces the
potentially very significant scope for sunk costs if Member States were to all conform to a
common data management model369
.
Impacts of Policy Option 2 (Harmonization and extensive safeguards for consumers
6.4.4.
addressing all problem drivers)
6.4.4.1.Economic Impacts
Option 2 (Harmonization and extensive safeguards) could lead up to up to EUR 3.5 billion in
direct benefits to consumers for the period 2020-2030, which come as a result of: (i) an
outright ban on all switching-related charges370
; (ii) further improvements to the switching
rate as a result of every Member State establishing a government (funded) price comparison
tool guaranteed to work in the consumer's interest371
; (iii) an improved ability for consumers
to identify the best offer in the market through fully standardised billing information372
.
However, there is greater uncertainty surrounding the benefits that stem from these
interventions. Whilst an outright ban on all switching-related charges would increase the
financial incentive to switch, it could also make it more difficult to finance certain energy
365
See Annex 7.5, Section 7.5.5.
366
See Annex 7.6, Section 7.6.5.
367
See Annex 7.4, Section 7.4.5.
368
See Annex 7.1, Section 7.1.5 and Table 16.
369
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” Copenhagen Economics,
and VVA (2016).
370
See Annex 7.4, Section 7.4.5.
371
See Annex 7.5, Section 7.5.5.
372
See Annex 7.6, Section 7.6.5.
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Assessment of the impacts of the various policy options
service investments (i.e. solar panels or energy efficiency upgrades packaged with energy
supply contracts) if implemented poorly. It might also result in a smaller range of tariffs
available to consumers. Not all government (funded) price comparison tools may work better
for consumers than the comparison tools already available on the market. And it may be
difficult, if not impossible, to devise a standard EU bill design that accommodates differences
in consumer preferences and market conditions in all Member States.
Whilst phasing-out blanket price regulation in the 17 Member States still practicing it would
lead to improved retail competition, defining the conditions under which price regulation
could continue at the EU level would be problematic. In particular, permitting price regulation
for households who consume below a certain price threshold would not accurately target those
most in need of assistance. In addition, permitting regulators to only set price caps above cost
would be difficult to enforce due to opaque cost structures. It also risks holding back
investments in product innovation and service quality, which require higher margins373
. As
with Option 1 (Flexible legislation), the impact of phasing out price regulation on retail price
levels is impossible to quantify, whereas the evidence strongly suggests it will lead to higher
levels of consumer satisfaction.
Defining a specific EU data management model for all Member States, such as an
independent central data hub, would bring similar benefits to Option 1 in terms of helping
new suppliers and service providers to enter the market. In addition, it would be easier to
enforce at the EU level374
.
6.4.4.2.Who would be affected and how
Consumers will benefit from more easily being able to compare offers in the market, as well
as lower financial barriers to switching. However, these gains may be tempered by a reduction
in the availability of beneficial products on the market. Whilst consumer prices may rise in
the Member States phasing out price regulation, this would be offset by higher levels of
service and the greater availability of value added products on the market. Consumers would
also benefit from increased competition and higher levels of service resulting from rules that
ensure quick and non-discriminatory access to data.
Energy poor consumers in many Member States would enjoy significant benefits from the
comprehensive set of disconnection safeguards outlined as they are more likely to be on risk
of disconnection. Whilst many Member States will benefit from a prescriptive EU definition
of energy poverty and from better information on the energy efficiency of the housing stock,
the benefits of better measurement may not composite for the significant resources required to
survey the housing stock at national level. Energy poor and vulnerable consumers may also be
impacted by more poorly targeted support as the result of permissible instances of price
setting being defined at the EU-level, rather than being assessed on a case by case basis.
373
See Annex 7.2, Section 7.2.5.
374
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” Copenhagen Economics,
and VVA (2016)
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Assessment of the impacts of the various policy options
Suppliers would benefit from increased access to the market of the Member States phasing
out price regulation. However, all suppliers would need to significantly reformat their bills in
order to comply with a standard EU bill design. They would likely also bear the brunt of the
very significant costs to protect energy poor consumers introduced under Option 2
(Harmonization and extensive safeguards) – in particular the complete ban on winter
disconnections. However, new entrants and energy service companies offering innovative
products would benefit from quick and non-discriminatory access to data.
As TSOs and DSOs are normally the market actors charged with data management, they
would be the most affected by the requirement to establish a standard EU data management
model that all Member States. Indeed, since many would incur significant sunk costs in
adopting a model different from their own, the impacts could be significant. However, all
these costs would be passed through to end consumers. In addition, network operators would
benefit from the anticipated entrance of aggregators and other energy service companies who
facilitate network flexibility, as a result of non-discriminatory data flows.
NRAs in the 17 Member States phasing out price regulation will need to significantly step up
efforts to monitor the market, ensure efficient competition, and guarantee consumer
protection. However, these impacts may be offset by increased consumer engagement, which
would naturally foster competition in the market.
6.4.4.3. Impact on businesses and public authorities
It is estimated that implementing the consumer-related elements of Option 2 ((Harmonization
and extensive safeguards) would lead to quantifiable costs of between EUR 42 million and
EUR 51 million for the period 2020-2030. These would mainly stem from national authorities
having to set up and run energy comparison tools375
, and energy suppliers having to heavily
modify their consumer bills to comply with the requirements in this option376
. Unquantifiable
impacts come in the form of the greatly reduced contractual freedom that suppliers have,
which is associated with the ban on contract termination fees377
.
Implementing the energy poverty provisions in Option 2 (Harmonization and extensive
safeguards) would result in quantifiable costs of between EUR 1.2 billion and EUR 3.8 billion
for the period 2020-2030. Unless public authorities step in, these costs would most likely fall
on suppliers and result from: (i) the additional costs of unpaid bills resulting from the
requirement for suppliers to give all customers a disconnection notice of at least two months;
(ii) the additional costs of unpaid bills resulting from the cessation of winter disconnections;
and (iii) refinancing costs resulting from the obligation to offer all consumers the possibility
to delay payments or restructure their debt prior to disconnection378
.
As these costs associated with disconnection safeguards are large, it is likely that this option
would result in distortions to competition in Member States where the public does not cover
375
See Annex 7.5, Section 7.5.5.
376
See Annex 7.6, Section 7.6.5.
377
See Annex 7.4, Section 7.4.5.
378
See Annex 7.1, Section 7.1.5 and Table 24.
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Assessment of the impacts of the various policy options
these costs. Whilst suppliers active in such markets could raise margins to socialize losses
from unpaid bills, certain suppliers – especially smaller ones who are less well equipped to
deal with the additional pressure on their operations – may seek to avoid entering markets
where there are likely to be significant risks of disconnections.
Member States may be better suited to design these schemes to ensure that synergies between
national social services and disconnection safeguards are achieved. These synergies may also
result in public sector savings which may be significant given the substantial costs of these
measures and the overlap between social policy and disconnections for non-payment.
Very significant costs are associated with creating a level playing field for access to data in
Option 2 (Harmonization and extensive safeguards). A mandatory data handling model will
imply the administrative costs of defining and designing such a model, and more importantly
high sunk costs for existing data models and additional costs for rebuilding a new one, both in
terms of personnel costs and IT infrastructure. Designing and building a new data handling
model is a complex procedure and may well take several years of planning and
implementation. For example, in Denmark alone, the central data hub took more than 4 years
to design and develop in its simple form, and 7 years in its enhanced form, and is estimated to
a cost of approximately EUR 165 million, where approximately EUR 65 million accrued to
the data hub administrator (the TSO), and around EUR 100 million accrued to DSOs and
energy suppliers379
.
Environmental impacts
6.4.5.
The legislative options examined above – Option 1 (Flexible legislation) and Option 2
(Harmonization and extensive safeguards) – can each be expected to have significant, albeit
indirect, environmental benefits because they enable the uptake of technologies that help the
electricity system become more flexible, thus enabling higher levels of variable and
decentralized RES E penetration. Non-discriminatory access to consumer data and a phase-
out of regulated prices will allow new entrants and energy service companies to develop and
offer value-added products such as dynamic price supply contracts, incentive-based demand
response services, green tariffs, and supply contracts with bundled energy efficiency or
rooftop solar investments. In addition, tackling the barriers to consumer engagement will
increase the selective pressure for such new services. The measures will benefit smaller
consumers in particular, the group of market actors which the analysis has shown represents
the greatest remaining source of low hanging fruit in terms of system flexibility potential.
In addition, phasing out blanket price regulation – particularly in Member States with very
low margins – will help address the high levels of electricity and gas consumption caused by
artificially low prices. This will make it easier to achieve climate objectives and provide a
proper price signal for energy efficiency investments.
379
See Annex 7.3, and “Policies for DSOs, Distribution Tariffs and Data Handling” Copenhagen Economics,
and VVA (2016).
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Assessment of the impacts of the various policy options
Impacts on fundamental rights regarding data protection
6.4.6.
A key building block for the completion of the Digital Single Market and the Energy Union
includes strong and efficient protection of fundamental rights in a developing digital
environment. The proposed policy measures on data management were developed in this
context, to ensure widespread access and use of digital technologies while at the same time
guaranteeing a high level of the right to private life and to the protection of personal data as
enshrined in Articles 7 and 8 of the Charter of Fundamental Rights of the EU.
As data on individual consumers' consumption and billing become central to the deployment
of distributed energy resources and the development of new flexibility services, the measures
on data management in the various policy options proposed (from compliance with data
protection legislation and the Third Energy Package - Option 0 (Baseline); to further
introduction of specific requirements on data handling responsibilities based on principles of
transparency and non-discrimination – Option 1 (Flexible legislation); and implementation of
a specific data management model to be described in EU legislation – Option 2
(Harmonization and extensive consumer safeguards)) seek to ensure the impartiality of the
entity which handles data and to ensure uniform rules under which data can be shared. Indeed,
consumers must be reassured that their consumption and metering data remain under their
control. Access to a consumer's metering or billing details can only happen when authorised
by that consumer and under the condition that the personal data protection and privacy are
guaranteed.
In this light, the data management policy options are therefore fully aligned and further
substantiate the fundamental rights to privacy and protection of personal data of Articles 7
and 8 of the Charter of Fundamental Rights of the EU, as well as with the General Data
Protection Regulation and with the Commission Recommendation on the Data Protection
Impact Assessment Template for Smart Grid and Smart Metering Environments.
Box 9: External factors and the assessment of the impacts
Price signals and long-term confidence that costs can be recovered in reasonable payback
times are essential ingredients for a well-functioning market. In a market which is not
distorted by external costs and interventions, the level and variability of the spot price on the
wholesale market, plays a role in signalling the need for investments in new resources. With
external costs and in the absence of the right short- and long-term price signals, it is more
likely that inappropriate investment or divestment decisions are taken, i.e. too-late decisions
or technology choices that turn out to be inefficient in the long run. It also renders it more
likely that capacity exits that is valuable for the system as a whole.
The impact assessment demonstrates that an improved market design can lead to a much more
efficient utilisation of resources and establish the market as a main driver of investments in
generation assets (even if only progressively and not fully for all RES E technologies (See
Box 7)). This will be mainly driven by the restoration of the economic merit order curve (see
Section 6.1.2, Figure 11) and the improved reflection of scarcity in short term electricity
prices (see Section 6.2.6.4, Table 21), both resulting from the measures proposed by the
current initiative, combined with the exit of non-economical units as a result of the transition
towards a market equilibrium (See section 6.2.6.3, Table 18) from the current overcapacity.
Market exit should be brought about by market forces and the initiative generally aims at
removing existing obstacles to this in regulation. Market exit is framed to some degree by the
measures proposed under Problem Area II. The extent to which a system with capacity
209
Assessment of the impacts of the various policy options
remuneration exacerbate or not existing excess capacity depends on how the capacity
requirement is set within the mechanism. If the system is correctly calibrated by means of a
genuine resource adequacy assessment (See Problem Area II, Option 2) there will be no
overcapacities. This is both important to ensure that CMs do not incite lower than
economically optimal wholesale prices, which would inhibit investments, and prevent delays
upon the transition path by preventing exit of non-essential resources. Moreover, the measures
under Problem Area I and Problem Area II, option I, will ensure that prices better reflect the
real value of electricity, affecting specifically the remuneration of electricity generation units
that operate less often but provide security and flexibility to the system. For the same reason,
it is important that TSOs (as responsible entities for overall operation of the system) define
and remunerate ancillary services appropriately, remunerating generators for the full range of
services they provide. These market improvements affect exit in the sense that they ensure
that only those resources will exit that genuinely have no value for the system as a whole.
It is true that overall price developments in the electricity sector will also depend on cost
factors beyond the present initiative, such as the carbon prices, prices for primary fuels or
technological costs.
These external factors would mainly impact the level of wholesale prices380
, possibly
affecting to a certain extent the overall level of benefits to be expected from the present
initiative or their distribution among individual options (in manners which are not easily
predictable in view of the many interactions that take place). However, such changes are not
expected to affect the order of preferred options. Indeed, the proposed measures in essence
derive their benefits from the removal of current market distortions and imperfections, while
at the same time having comparably small implementation costs. These are benefits that are
inherent to the measures themselves and do not depend on the precise context in which they
are implemented. Moreover, strong synergies exist between the sets of options within the
package (See Section 7.5.1), meaning that the overall benefits of a given option are more
affected by the coherence of the package as a whole, than by its interactions with factors
outside the present initiative.
Low wholesale prices though would affect investments in electricity resources such as
demand response, RES E and peaking plant investments. Concerning demand response, the
aim of the initiative is to offer to the consumers the opportunity to participate in the market if
they wish to, either directly (e.g. industrial consumers) or indirectly (e.g. via aggregators).
The initiative is not aiming to affect the level and variability of wholesale prices, but to make
the functioning of the markets more efficient so that it can deliver price signals reflecting the
value of electricity at each moment of time and the need for future investments (and in what
type). Although persistent low electricity wholesale prices could lead to low investments, this
380
For example the prices projected by PRIMES/OM tend to be quite higher even in 2020 compared to the
currently observed market prices. Several reasons contribute to this: (a) fuel costs are projected to increase
by 25% for gas and coal, (b) demand increases, (c) few new investments take place (mainly RES to reach
the 2020 target); this point combined with demand increase described above , make it the first step in
reducing the currently observed overcapacity, (d) a well-functioning EoM without distortions is assumed, (e)
scarcity bidding is assumed, in the sense that there is a mark-up on the bids so that generators can recover
their full costs only from the market in the long-run.
210
Assessment of the impacts of the various policy options
is a normal outcome if it is a result of market dynamics and not distortions. For example a
system characterized by overcapacity should have low prices to signal that investments are
not needed.
It is equally noteworthy that the modelling work (as presented in section 6.2.6.4) indicates
that in the mid-long term, even in the presence of larger shares of variable RES E,
conventional generators will set the marginal price in a sufficient number of hours to produce
meaningful price signals to guide overall market operations. Increasing RES E penetration
therefore does not necessarily give rise to low(er) average wholesale market prices.
The assessment of the benefits also depends to a certain degree on the progress made in the
implementation of measures proposed by parallel initiatives, considered as part of the baseline
for the present initiative, most notably the REDII. In this context, it is important to note that
the assessment of the present initiative assumes the full phase-out of non-market based
support mechanisms by 2030 for RES E, i.e. feed-in-tariffs would be phased-out and replaced
by schemes that expose RES E to price signals, as for instance premium based schemes. Such
investments would be further triggered by setting support-levels through auctioning as RES E
investments projects would then be incentivised to develop business models that optimise
market based returns. These are reasonable assumptions in view of the rules that are expected
to be in place well before 2030 (see in particular Annex IV).
The success or failure to implement such measures for RES E in time would have a direct
impact on the effectiveness of the present initiative. A partial or delayed implementation of
the closely associated policies, as proposed in the revised Renewable Energy Directive,
especially if combined with the prolongation of existing distortions, would reduce the
efficiency of the market design initiative in the medium term and postpone its expected
benefits further into the future. On the contrary, an expedient implementation would achieve
the establishment of efficient markets and the delivery of the associated benefits sooner.
6.5. Social impacts
European social partner's joint position381
:
"Citizens and especially low-income households should be able to pay their bills"
The new market design should be: "ensuring that the provision of electricity is secure, safe,
reliable and reasonably priced"
It was also underlines that: "workers in and outside of the electricity sector are relying on a
stable electricity market for their jobs. There is currently a precarious situation for many
workers in the electricity sector, especially among power plant workers. Many plants are not
211
Assessment of the impacts of the various policy options
adequately remunerated for the services they provide (e.g. flexibility, security of supply) and
therefore several companies foresee closure. Workers could lose their jobs".
A shown above, more efficiently organised cross-border electricity markets can avoid
significant costs for energy customers. Given the importance of energy costs for many
companies and for individual households, realising the possible cost savings can be expected
to improve competitiveness of commercial players (with positive impact on jobs and growth)
and on private customers (especially relevant for low-income households).
The electricity industry (i.e. production, transmission, distribution and trade of electricity) is a
key economic sector with a turnover amounting to not less than EUR 1.182 billion in 2014382
.
EU households spent EUR 148.2 billion on electricity bills (EUR 97.4 billion on gas), which
means that every household had to pay EUR 686,- per year for electricity (EUR 451,- for
gas) on average, with important variations between single Member States383
. Especially for
low-income households, costs for electricity can eat up large parts of the available income384
.
Also for many industries, especially those in competition at a world-wide scale, energy costs
are an important factor for competitiveness. EU wholesale electricity prices are still higher
than in other regions in the world (e.g. around 30% compared to the U.S.385
). Avoiding
unnecessary prices increases by an intelligent organisation of electricity markets (e.g. market-
based solutions and using advantages of aggregation across borders) can therefore save jobs
and create growth in the EU.
The possible measures analysed to better adapt the current market rules to decarbonised
electricity markets through revised legislation (See options in 'Problem Area I' e.g. re-
establishing the level playing field, improving short-term markets and removing barriers for
demand response and distributed resources) would allow to integrate electricity generated
from RES E at lower costs. They would also increase the potential for cross-border trade,
leading to more competition and better possibilities to level out production and demand
differences across larger areas.
Grid fees and other system costs have increased in recent years due to the suboptimal
organisation of markets, but also through the need to adapt the infrastructure to decentralised
generation. Better organised electricity markets would therefore not only save costs for
electricity, but also keep grid costs in check (e.g. by limiting the necessary costs for TSO-
interventions to keep the grid stable, so-called 're-dispatching'386
). Measures to keep the
382
Eurostat Data for 2014.
383
Eurostat Data for 2014.
384
In 2014, EU households in the lowest income quintile spent an average of 9% of their household income on
electricity and gas, whereas middle income households spent 6% on electricity and gas. Source: DG ENER
Data.
385
See e.g. Communication on "A Framework Strategy for a Resilient Energy Union with a Forward-Looking
Climate Change Policy" of 25.2.2015 COM (2015), p.3.
386
See e.g. the estimations for Germany, where grid tariff component already exceeds the energy costs and
where re-dispatching costs are estimated to grow to EUR 4 billion/year in the next years, see e.g.
http://www.zfk.de/artikel/bis-zu-vier-milliarden-fuer-engpassmanagement-2023.html .
212
Assessment of the impacts of the various policy options
further expansion of grid fees in check can therefore bring tangible benefits to industry and
private (low-income) customers387
.
The analysed measures to improve investors' certainty and limit state interventions ('Problem
Area II', e.g. better co-ordinating capacity mechanisms between countries) can also be
expected to have a positive impact on competitiveness and on energy bills to of households.
As shown above, fragmented adequacy planning and capacity mechanisms leads to higher
energy costs and network charges. If each Member State builds its backup generation in its
own country without taking into account generation from neighbours, this will necessarily
lead to inefficiencies through unnecessary duplication of investments388
. Notably Options 2
(regional adequacy assessment) and Option 3 (cross-border openness of capacity
mechanisms) would help to keep the prices for state interventions concerning capacity
mechanism in check. 389
In a similar manner, the analysed measures to improve risk preparedness ('Problem Area
III', e.g. better co-ordinated planning and rules to better coordinate possible load shedding in
case of crises) options are likely to have a positive impact for EU citizens and businesses.
Previous blackouts have shown that even in the "traditional" electricity market with low
shares of RES E so-called "cascade blackouts" resulting from problems in other Member
States can seriously harm businesses and customers, in particular those depending on
electrical heating (see on the system blackouts in 2003 and 2006 above, section 6.3.2.1).
Amounts of variable RES E have increased ever since, and so has the importance of a reliable
electricity grid for citizens and customers (e.g. increased risks of blackouts for internet-driven
businesses and private communication). Minimising blackout risks through better regional
coordination will therefore contribute to avoid negative impacts on businesses and
households.
Finally, the analysed measures to enhance performance of retail markets (Problem Area IV,
e.g. measures facilitating to change suppliers, more targeted support for "energy-poor")
customers in the transition to market-based prices, etc.) will also have a positive impact on
businesses and households. In addition, the proposals relative to the phasing out of regulated
prices, should incentivise Member States which currently use blanket price regulation to
provide targeted support for vulnerable and energy poor consumers instead of providing an
indirect support to all consumers regardless of their circumstances as is currently often the
case.
387
According to the Commission's modelling, the assessed options under Problem Area I reduce the average
cost of total demand, i.e. the cost of each MWh generated, apart from Option 1(a) (level playing field). More
specifically and compared to the baseline, Option 1(a) (level playing field) increases it by 6%, while Options
1(b) (strengthening short-term markets), 1(c) (demand response/distributed resources) and Option 2 decrease
it by 6%, 9% and 11%, respectively.
388
See for further evidence on the disadvantages of fragmented CMs above, Problem Area II (investment
uncertainty/fragmented CMs), discussion of Option 3.
389
Option 4 (EU wide capacity market) is not considered here as it was already discarded above. However, it is
useful to note that it would also be more costly (about 5% pursuant to the Commission's model) than the
other options.
213
Assessment of the impacts of the various policy options
Improvements to the health390
and well-being of energy poor consumers, savings to the health
sector391
, and economy-wide productivity gains392
can be expected from the packages of
energy poverty measures evaluated above. Due to the indirect nature of the way these
measures would address energy poverty, and a lack of specific data on their impact, these
benefits are impossible to quantify.
Health impacts most commonly associated with energy poverty and under-heated dwellings
can be fatal, resulting in higher mortality during winter period. Benefits of effective action to
reduce excess winter mortality could be substantial given the scale of the issue. In fact
independent research shows that over 200,000 excess winter deaths have occurred across 11
Western European countries alone393
during the winter of 2014/2015. In addition to the
physical impacts, cold homes are directly related to mental health problems.
The energy transition and decarbonisation policies play a key role in developing Europe’s
competitive edge internationally as growth and jobs increasingly will have to come from
innovative products and services which are closely linked to sustainable and smart solutions.
Recent studies on the impact of EU’s energy and climate targets suggest a net increase in job
demand in the power generation market as a result of the transition of the energy system. One
factor behind this is the higher labour intensity in power generation from renewable sources
compared to gas or nuclear. There will also be a change in the employment structure as many
of the jobs associated with the energy transition require higher skills and increased supply of
workers that outweigh job losses in somewhat less qualified jobs in conventional energy
generation. The total number of jobs in the power sector (operation, maintenance,
construction, installation, and manufacturing) is forecast to increase by around a half by
2030394
. Further positive impacts are expected in the indirect and substitution effects. 395
Whereas these effects are related to the energy transition as such and cannot be attributed
solely to the measures assessed here, by ensuring a cost effective transition in more smoothly
functioning markets, these beneficial social effects stand a much increased chance of being
realised and retained.
390
"Fuel Poor & Health. Evidence work and evidence gaps. DECC. Presented at Health, cold homes and fuel
poverty Seminar at the University of Ulster". 2015. Cole, E. Available at:
http://nhfshare.heartforum.org.uk/HealthyPlaces/ESRCFuelPoverty/Cole.pdf; "Towards an identification of
European indoor environments’ impact on health and performance - homes and schools. 2014. Grün &
Urlaub, Excess winter mortality: a cross-country analysis identifying key risk factors. Journal of
Epidemiology & Community Health" 2003. Healy.
391
"2009 Annual Report of the Chief Medical Officer (London: Department of Health", 2010. Donaldson, L.
392
"Indoor cold and mortality. In Environmental Burden of Disease Associated with Inadequate Housing",
(Bonn: World Health Organisation (Regional office for Europe)). 2011. Rudge, J.
393
Excess mortality in Europe in the winter season 2014/15, EuroMOMO, source:
http://www.euromomo.eu/methods/pdf/winter_season_summary_2015.pdf
394
Between 2 and 2.5 million in 2030, depending on the decarbonisation scenario (source Neujobs/CEPS)
395
Neujobs/CEPS report “Impact on Decarbonisation of the Energy System on Employment in Europe” 2015 ,
The methodology is based on applying “employment factors” (i.e. labour intensities) of different energy
technologies to changing energy mixes as projected by the EU decarbonisation scenarios.
214
Comparison of the options
7. COMPARISON OF THE OPTIONS
Taking into account the impacts of the options and the assessment presented in Section 6, the
following section compares the different options against each other using, the baseline
scenario as the reference and applying the following criteria:
- Effectiveness: the options proposed should first and foremost be effective and thus
be suitable to addressing the specified problem;
- Efficiency: this criterion assesses the extent to which objectives can be achieved at
the least cost (benefits versus the costs).
The tables provide a summary of the assessment of the policy options against these criteria.
The options are measures against the criteria applied for the assessment of the impacts
specified for options developed to address each Problem Area (See Sections 6.1, 6.2, 6.3 and
6.4 respectively) and the comparison of the options below. Each policy option is rated
between "---" (very negative), 0 (neutral) and "+++" (very positive).
The options are not compared here on the basis of their coherence with parallel initiatives.
The design of the baseline already assures that all option are compatible with parallel
initiatives. In particular, the baseline in the present impact assessment ensures that under all
investigated options, the RES E targets (as well as other policy targets) are met.
Consequently, comparing options on the basis of their compatibility with the RED II initiative
is meaningless.
7.1. Comparison of options for adapting market design for the cost-effective
operation of variable and often decentralised generation, taking into account
technological developments
All options, except for Option 0 (baseline scenario) can contribute to achieving to a degree the
objective of adapting the market design to make it suitable for the cost-effective operation of
variable, often decentralised generation of electricity and capture some of the potential social
welfare and environmental opportunities (e.g. lower wholesale electricity prices; incentivise
the increase of low carbon electricity generation). However, the effectiveness and efficiency
of the different options, as well as their impact, vary significantly.
215
Comparison of the options
Table 25: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Impact on business
and public
authorities
Policy Option 0
(Baseline)
0 0 0 0 0
Policy Option
1(a) (level
playing field)
+ + + - -
Policy Option
1(b)
(strengthening
short-term
markets)
++ ++ ++ -- --
Policy Option
1(c) (demand
response/
distributed
resources )
+++ ++ +++ -- --
Policy Option 2
(fully integrated
markets)
+++ +++ ++ --- ---
Source: DG ENER
In summary:
Option 0 (baseline scenario): will fall short in providing for the adaptation of the market
design to the new realities of the interconnected electricity system and will not allow the
internal electricity market to reach its full potential.
Options 1(a) (level playing field), 1(b) (strengthening short-term markets) and 1(c) (demand
response/distributed resources) reflect an increasing degree of ambition regarding the
integration of the national electricity markets, with Option 1(c) building on the packages of
measures covered under Options 1(a) and 1(b) and including additional measures. All these
options present a compromise between bottom-up initiatives and top-down steering of the
market development, without substituting the role of national governments, regulators and
TSOs by a centralised and fully harmonised system. Option 1(a) and Option 1(b) are
significantly more efficient than Option 0 but cannot be expected to fully meet the specific
objectives, given that these options do not cover measures for including additional resources
(i.e., demand response, distributed RES E and storage) in the electricity markets to further
increase the flexibility of the electricity system and the resources for the TSOs to manage it.
The value of these additional resources for the efficient operation of decarbonised electricity
markets and hence for the energy transition should not be underestimated. Option 1(c)
provides a more holistic, effective and efficient package of solutions and has the added value
that it will not lead to significant additional impacts on stakeholders or on businesses and
public authorities. Indeed, while Option 1(c) may lead to additional administrative impacts for
Member States and competent authorities regarding the implementation and monitoring of the
measures, these impacts will be offset by lower barriers to entry to start-ups and SMEs, by the
benefits to market parties from more stable regulatory frameworks and new business
opportunities as well as by the benefits to consumers from more competition and access to
wider choice.
216
Comparison of the options
As regards Option 2 (fully integrated market), while having advantages in terms of lower
coordination requirements (i.e., a fully integrated EU-market can be operated more
efficiently), the results of the assessment indicate that the move towards a more integrated
European approach has less significant economic added value since most of the benefits will
have already been reaped under the regional, more decentralised approach under Option 1(c)
(demand response/distributed resources). Moreover, Option 2 (fully integrated market) has the
disadvantage of requiring significant changes to established practices, systems and processes
and hence a significant impact on stakeholders, businesses, Member States and competent
authorities. Such profound changes of national competences in favour of centralised powers
"across the board" would also raise serious questions concerning the subsidiarity of the
measure. Therefore, in view that for Option 2 (fully integrated market) the efficiency gains
are not significantly higher compared to Option 1(c) (demand response/distributed resources)
but the impacts and required changes to national competences much greater, it appears
disproportionate and not the most appropriate option at the current stage of development of
the internal electricity market.
In the light of the previous assessment, the preferred option would be Option 1(c)
(pulling demand response and distributed resources in the market) (which encompasses
Options 1(a) (level playing field) and 1(b) (strengthening short-term markets). This
option is the best in terms of effectiveness and, given its impacts, has been demonstrated
to be the most efficient as well as consistent with other policy areas.
This preferred Option has large support among stakeholders. No support exists for retaining
the status quo (i.e. Option 0 or 0+) whereas Option 2 (fully integrated market) was generally
deemed a step too far. It is noted that hesitations by stakeholders on aspects of the preferred
option, such as the removal of priority dispatch provisions under Option 1(a) (level playing
field), are based on the notion that this should go hand in hand with a reform rendering the
market more adapted to RES E resources, which is what is foreseen under Option 1(b)
(strengthening short-term markets) and Option 1(c) (demand response/distributed
resources)396
.
7.2. Comparison of Options for facilitating investments in the right amount and in the
right type of resources for the EU
All options, except for Option 0 (baseline scenario), can improve the overall cost-efficiency of
the electricity sector and contribute towards achieving the objective of facilitating investments
in the right amount and in the right type of resources for the EU. However, the effectiveness
and efficiency of the different options, as well as their viability and impact, vary significantly.
396
Reference is made to Section 5.1.1 through to 5.1.5 and Sections 7 of Annexes 1.1 through 3.4 for more
detailed representations of stakeholders' opinions.
217
Comparison of the options
Table 26: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Impact on business
and public
authorities
Policy Option 0
(Baseline
scenario)
0 0 0 0
0
Policy Option 1
(Reinforced
energy-only
market without
CMs)
+ + + +/- -
Policy Option 2
(reinforced
energy-only
market + EU
adequacy
assessment for
CMs)
+ + + + +
Policy Option 3
(reinforced
energy-only
market + EU
adequacy
assessment for
CMs + EU
framework on
cross-border
participation
CMs)
++ ++ ++ ++ ++
Source: DG ENER
In summary:
Option 0 (baseline scenario), which would assume the existence of national capacity
mechanisms without coordination at EU-level will fall short of achieving the specific
objectives of improving market functioning to reduce the need to have recourse to state
intervention and of ensuring that state-interventions, where needed, are more coordinated,
efficient and compatible with the EU's internal energy market.
Option 1 (reinforced energy-only market without CMs) can improve the overall cost-
efficiency of the electricity sector significantly. The analysis shows that undistorted energy-
only markets increase overall system efficiency as make sure that resources are better utilized
across the borders, demand can better participate in markets, and renewables can be better
integrated into the system without additional need for subsidies. This will in turn decrease the
need for capacity mechanisms (which are often introduced as a reaction to markets which do
not produce correct price signals due to state interventions).
The analysis also shows that reinforced energy-only markets can in principle provide the right
signals for market operation and ensure resource adequacy. Option 1 also has slightly more
positive environmental impacts than any of the other options.
However, markets are still characterised by manifold regulatory distortions today, and
removing the distortive effects will not be possible with immediate effects in many Member
218
Comparison of the options
States. The observation that undistorted markets can provide the necessary investment signals
has therefore to be weighed against the observation that a significant transition time to phase
out the existing distortions will be necessary. Furthermore, some national distortions (e.g.
resulting from differences in taxation) cannot be addressed by a reform of energy law and are
therefore likely to continue.
Investors also do not have perfect foresight of market conditions, and confidence that they
will not be distorted for the economic lifetime of their investments. Such certainty is
increasingly difficult to find, often due to uncertainty as to the regulatory measures that could
be taken in the future that may supress prices and reduce the load factors of plants compared
to the assumptions made when the investment decision is taken. In a market that requires
more and more varied sources of funding that in many cases are competing with other, non-
electricity, projects for capital, relying solely on the energy price as a basis for investment is
not always easy. Uncertainty about future policy developments or the perception thereof can
create 'missing money' that may require addressing397
.
The legislator should also take into account that the level of interconnection is markedly
different among Member States. This militates for a more nuanced approach than a
straightforward EU-wide prohibition of CMs.
In this perspective, not allowing Member States to introduce any type of CMs would mean
that Member States would be prevented from addressing adequacy concerns with CMs. As
those concerns might be legitimate, this option is not considered to be appropriate.
But, as developed in Chapter 2.2.1 undistorted energy price signals are fundamental
irrespective of whether generators are solely relying on energy market incomes or also receive
capacity payments. Therefore the measures aimed at removing distortions from energy-only
markets discussed under Option 1 (e.g. scarcity pricing or reinforced locational signals) are
'no-regrets' and assumed as being integral parts of Options 2 (CMs + EU adequacy
assessment) and 3 (CMs + EU framework on cross-border participation)..
When compared with the baseline, Option 2 (CMs + EU adequacy assessment) can improve
the overall cost-efficiency of the electricity sector as significant savings can be achieved
through establishing an EU-wide approach to resource adequacy assessments as opposed to
national-based adequacy assessments. At the same time Option 2 does not allow reaping the
full benefits of cross-border participation in CMs.
Option 3 (CMs + EU framework on cross-border participation) (which includes the market
reforms under Option 1 and the regional assessment under Option 2) goes beyond Option 2 as
it proposes additional measures to avoid fragmentation of CMs. This would achieve
significant additional net benefits when compared with Option 2. This is because it makes
sure that foreign resource providers can effectively participate in national capacity
mechanisms and avoids competition and market distortions resulting from capacity payments
397
It must however also be recognised that CMs by themselves are not a panacea as they can equally be a
source of regulatory uncertainty. Indeed, in practise CM designs are regularly found imperfect and
consequently adjusted on a regular basis.
219
Comparison of the options
which are reserved to domestic participants. By remunerating foreign resources for their
services this option reduces investment distortions that might be present in Option 2 as a
result from uncoordinated approaches to cross-border participation.
In view of the assessment above, Option 3 (CMs + EU framework on cross-border
participation) (encompassing options 1 and 2) is the preferred option.
This preferred Option has large support among stakeholders. There is almost a consensus
amongst stakeholders on the need for a more aligned method for generation adequacy
assessment. A majority of stakeholders support the idea that any legitimate claim to introduce
CMs should be based on a common methodology. When it comes to the geographical scope
of the harmonised assessment, a vast majority of stakeholders call for regional or EU-wide
adequacy assessments, while only a minority favour a national approach. There is also support
for the idea to align adequacy standards across Member States. Stakeholders clearly support a
common EU framework for cross-border participation in CMs398
.
Most stakeholders including Member States agree that a regional/ European framework for
CMs is preferable. Member States, however, might want to keep a large degree of freedom
when proposing a CM. They might claim that beyond a revamped regional/ EU generation
adequacy assessment, there is legitimacy for a national assessment based on which they can
claim the necessity of their CM. Similarly Member States might instinctively want to rely
more on national assets and favour them over cross-border assets.
7.3. Comparison of options for improving Member States' reliance on each other in
times of system stress and reinforcing coordination between Member States for
preventing and managing crisis situations
All options, except for Option 0 (baseline scenario), can contribute to achieve the objective of
improving Member State's reliance on each other in times of system stress and reinforcing
their coordination and cooperation at times of crisis situation. However, the effectiveness and
efficiency of the different options, as well as their viability and impact, vary significantly.
398
Reference is made to Section 5.2.1 through to 5.2.9 and Sections 7 of Annexes 4.1 through 5.2 for more
detailed representations of stakeholders' opinions.
220
Comparison of the options
Table 27: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Impact on business
and public
authorities
Policy Option 0
(Baseline
scenario)
0 0 0 0 0
Policy Option 1
(Common
minimum EU
rules)
++ ++ + + 0/-
Policy Option 2
(EU rules +
regional
cooperation)
+++ +++ ++ ++ 0/-
Policy Option 3
(Full
harmonisation)
+++ -- + + 0/--
From the point of view of impacts, particularly costs and administrative impact, Option 1
(Common minimum EU rules) could in principle appear as preferred option. However, the
performance in terms of effectiveness and efficiency is limited compared to Option 2 (EU
rules + regional cooperation) and Option 3 (Full harmonisation). Additionally, impacts
associated with Option 3 (Full harmonisation) are neither proportionate nor fully justified by
the effectiveness of the solutions, which makes Option 3 (Full harmonisation) perform poorly
in terms of efficiency compared to Option 2 (EU rules + regional cooperation).
Overall, the more harmonized approach to security of supply through minimum rules pursued
by Option 1 (Common minimum EU rules) would not solve all the problems identified, in
particular, the uncoordinated planning and preparation ahead of a crisis. As regards Option 1
(Common minimum EU rules), the main drawback of this approach is that each Member State
would be drafting and adoption the national risk preparedness plans under its own
responsibility. While the regionally coordinated plans with crisis scenarios identified at
regional level and the agreement of some aspects of the plan (e.g. load shedding plan) in a
regional context, aim at ensuring that all regional specificities are fully considered. Given the
urgency to enhance the level of protection against cyber threats and vulnerabilities, it must be
concluded that Option 1 (Common minimum EU rules) regarding cybersecurity is not
recommended, because it is not viable for reaching the policy objectives, given that the
effectiveness would depend on whether the voluntary approach would actually deliver a
sufficient level of security.
Option 2 (EU rules + regional cooperation) addresses many of the shortcomings of Option 1
(Common minimum EU rules) providing a more effective package of solutions. In particular,
the regionally coordinated plans ensure the regional identification of risks and the consistency
of the measures for prevention and managing crisis situations. For cybersecurity this option
creates a harmonised level of preparedness in the energy sector and ensures that all players
have the same understanding of risks and that all operators of essential services follow the
same selection criteria for the energy sector throughout Europe.
Overall, Option 3 (Full harmonisation) represents a highly intrusive approach that tries to
address possible risks by resorting to a full harmonisation of principles and the prescription of
221
Comparison of the options
concrete solutions. For example, the preparation of risk preparedness plans at regional level
ensures full coherence of actions ahead and during a crisis. However, the major limitation is
that national specificities could not be addressed through regional plans. The detailed
"emergency rulebook" with an exhaustive list of measures would also reduce the room of
manoeuvre of Member States to tackle local problems. The creation of a dedicated agency on
cybersecurity at EU level would be also a costly solution. The assessment of impacts in
Option 3 (Full harmonisation) shows that the estimated impact on cost is likely to be high and
looking at the performance in terms of effectiveness, it makes Option 3 (Full harmonisation) a
disproportionate and not very efficient option.
In the light of the previous assessment, the preferred option would be Option 2 (EU
rules + regional cooperation). This option is the best in terms of effectiveness and, given
its economic impacts, has been demonstrated to be the most efficient as well as
consistent with other policy areas.
This preferred Option has large support among stakeholders. The majority of stakeholders are
in favour of regional coordination of risk preparedness plans and ex-ante cross-border
agreements to ensure that markets function as long as possible in crisis situations. No support
exists for retaining the status quo (i.e. Option 0 or 0+), as stakeholders agree that the current
framework does not offer sufficient guarantees that electricity crisis situations are properly
prepared for and handled in Europe. Option 3 (Full harmonisation) was deemed a step too far;
stakeholders did not support a fully harmonised approached based on rulebooks399
.
7.4. Comparison of options for addressing the causes and symptoms of weak
competition in the energy retail market
Although there is a significant level of uncertainty in quantifying the benefits of the options in
this Problem Area, all options, except for Option 0 (baseline scenario), are expected to
improve retail competition. However, the anticipated effectiveness and efficiency of the
different options vary markedly.
399
Reference is made to Section 5.3.1 through to 5.3.6 and Section 6 of Annexes (6.1.4 presentation of options
and 6.1.8 for more detailed representations of stakeholders' opinions).
222
Comparison of the options
Table 28: Summary of assessment of policy options
Criteria 
---------
Options 
Effectiveness Efficiency
Impacts
Economic
impact
Impact on
stakeholders
Implementation
costs
Policy Option 0
(Baseline
scenario)
0 0 0 0 0
Policy Option 0+
(Non-regulatory
approach)
+ +++ + +/0 -
Policy Option 1
(Flexible
legislation)
+++ ++ +++ +++/-- --
Policy Option 2
(Harmonization
and extensive
consumer
safeguards)
+++ / ++ - +++ / ++ ++/--- ---
Option 0+ (Non-regulatory approach) can be expected to lead to modest, albeit tangible,
economic benefits primarily as a result of the voluntary phase-out of regulated prices in some
Member States and the drive to tackle illegal switching costs. Given its low implementation
costs, it is a highly efficient option. And the few stakeholders that will be affected will be
affected positively. However, the effectiveness of Option 0+ is significantly limited by the
fact that non-regulatory measures are not suitable for tackling the poor data flow between
retail market actors that constitutes both a barrier to entry and a barrier to higher levels of
service to consumers. In addition, shortcomings in the existing legislation make it impossible
to significantly improve consumer engagement and energy poverty. They also introduce great
uncertainty around the drive to phase out price regulation.
Option 1 (Flexible legislation) would probably lead to substantial economic benefits. Retail
competition would be improved as a result of the definitive phase-out of blanket price
regulation, non-discriminatory access to consumer data, and increased consumer engagement.
In addition, consumers would see direct benefits through improved switching. And the energy
poor would be better protected, leading to knock-on benefits to the broader economy. Given
that Option 1 would entail moderate implementation costs (these stem primarily from
ensuring a standardised format for consumer data, and the various burdens associated with
improving consumer engagement) it is an efficient option as these costs are considerably
outweighed by the benefits. Many stakeholder groupings are likely to be positively and
negatively affected by the collection of policy measures in Option 1. But none would bear a
disproportionate burden that would not be offset by commensurate benefits. Likewise, the
proposed measures in Option 1 respect the principle and limits of subsidiarity.
Option 2 (Harmonization and extensive consumer safeguards) would also lead to substantial
economic benefits, albeit with a greater degree of uncertainty over the size of these
benefits. This uncertainty stems from the tension some of the measures in Option 2 may have
with competition (stronger disconnection safeguards, an outright ban on all switching-related
charges), and from the difficulty of prescribing EU-level solutions in certain areas (defining
exceptions to price deregulation, implementing a standard EU bill design). Whilst a single EU
data management model would be just as effective and easier to enforce, and whilst the
energy poor would be even better protected by the stronger safeguards proposed, the high
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Comparison of the options
implementation cost of these measures would reduce the efficiency of Option 2 compared
with Option 1. Disconnection safeguards may be better designed by Member States to ensure
synergies between national social services. As social policy is a primary competence of
Member States, Option 2 may go beyond the boundaries of subsidiarity. Finally, many
stakeholders will be affected by the collection of policy measures in Option 1, both positively
and negatively. Suppliers and DSOs in particular would face significant burdens that they
would at least partially pass on to consumers i.e. socialise.
In the light of the analysis, the preferred option is Option 1 (Flexible legislation). This
option is most likely to be the most effective, is efficient, and is consistent with other
policy areas.
Most stakeholders would support (or at least be indifferent to) the measures in preferred
Option 1 (Flexible legislation). This is due to the fact that a flexible legislative approach
allows the problems identified to be largely addressed while accommodating: 1) the broad
range of national differences that still exist in retail markets for energy; and 2) the specific
concerns aired in the stakeholder outreach. Nevertheless, some Member States practising
blanket price regulation will likely oppose a phase out of this, and industry associations
representing energy suppliers have stated that they would not welcome any EU legislation
addressing the content of bills.
Almost no support exists for retaining the status quo (i.e. Option 0) or for tackling the issues
in the Problem Area through soft law (Option 0+), except for isolated instances already
mentioned. Several measures in Option 2 (Harmonization and extensive consumer safeguards)
were generally deemed a step too far by a number of stakeholders, including stakeholders
such as ACER, or NRAs who represent the interest of the public.400
7.5. Synergies, trade-offs between Problem Areas and sequencing
The measures considered in this impact assessment are highly complementary. Most of the
different Options considered in each Problem Area would reinforce the effect of options in
other Problem Areas, with little trade-offs between the different areas.
Synergies
7.5.1.
The measures to make intraday and balancing markets more flexible such as pursued under
Problem Area I, in particular Option 1(b) (strenghening short-term markets) and Problem
Area II , Option 1 (reinforced energy-only market) will foster a price signal that better reflects
the value of electricity, notably when it is scarce. It will hence provide a price signal benefical
for flexible resources, in particular demand response and storage and improve the business
case for innovative assets and service models to enter the market as assessed under Problem
Area I Option 1(c) (demand response/distributed resources). It will also reinforce liquidity and
competition in the electricity wholesale electricity markets. As choice on the wholesale
400
See Section 5.4.2 through to 5.4.5, and Sections 7 of Annexes 7.1 through 7.6 for more detailed
representations of stakeholders' opinions.
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Comparison of the options
market is a pre-condition for more competition on retail markets, more liquid wholesale
markets will also contribute to improving competition in retail markets (Problem Area VI).
Helping RES E resources to be remunerated through the market as fostered with the measures
under Problem Area I will ultimately reduce the high level of taxes and levies currently
necessary to drive RES E deployment, decreasing overall system costs and making energy
more affordable compared with a scenario where markets remain poorly adapted to RES E.
The measures proposed to improve the functioning of the electricity markets as discussed
under Problem Areas I and II, in particular Option 1 (reinforced energy market/No CMs), will
also lead to a more robust formation of price signals. Robust price signals will reduce the need
for assets to be remunerated by alternative revenue streams to be a credible investment
opportunity or avoid its decommissioning and hence reduce the need for government
intervention in the form of CMs or otherwise to ensure resource adequacy such as discussed
under Problem Area II, Option 3. Moreover, the measures assessed Problem area II, in
particular the preferred Option 3 will reduce market distorition caused by genuinly justifed
CMs and improve the ability of the market to operate optimally. In other words, improving
the energy markets will reduce the need for governement intervention to ensure investments
in electricity resources.
Measures to improve retail competition, consumer engagement and data handling as fostered
with the measures under Problem Area IV (Retail markets) will increase system flexibility as
targeted by the measures under Problem Area I, in particuler Option 1(c) (pulling demand
response and distributed resources into the market). This is because the majority of untapped
demand response potential originates from smaller consumers and because retail price
regulation can have a detrimental effect on the deployment of innovative consumer products
such as dynamic price supply contracts.
Improving the market in its ability to renumerate (in particular, flexible) resources and
removing the distortions that prevent resources to reacte to proper price signals (such as those
aimed at in Problem I area I and Option 1 of Problem Area II) will overall improve the
robustness of the system to satisfy demand at all times and, hence, the freqeuncy and overall
number of hours that recourse has to be taken to out-of-market measures to operate the
system, such as the demand curtailment, as discussed under Problem Area III (Crisis
situations).
Phasing out price regulation as fostered with the measures under Problem Area IV
(particularly in Member States with very low retail margins) will help address the high levels
of electricity and gas consumption caused by artificially low prices and provide an accurate
price signal for energy efficiency investments that would ultimately mitigate the effects of
security of supply events as targeted by the measures under Problem Area III (Crisis
situations). Removing price regulation will also allow for a more flexible organisation of the
market and increase the incentives to participate in the market through demand response as
fostered by the measures assessed un Problem Area I. Option 1(c) (pulling demand response
and distributed resources into the market)
Measures to improve retail competition as discussed under Problems Area IV, will ensure that
all benefits, including those expected under Problem Areas I, II and III are transferred to end-
consumers, ultimately increasing the beneficial effects on social welfare and competiveness.
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Comparison of the options
Overall, market improvement measures will address increasing energy poverty as discussed in
Problem Area IV. Indeed, one of the three main drivers401
of energy poverty has been the
gradual increase in retail prices.
Measures to ensure a common approach to crisis prevention and management as is the
objective under Problem Area III avoid unduly interventions in market functioning. Better
preparedness, transparency and clear rules on crisis management will build trust between
Member States to rely on the internal electicity market for resource adequacy, helping the
achievement of the objectives under Problem Area II. By imposing obligations to cooperate
and lend assistance, Member States are also less likely to "over-protect" themselves againt
possible crisis situations.
Trade-offs
7.5.2.
The mesures selected as the preferred option under Problem Area I and II are mutually
reinforcing in that they collectively aim at improving market functioning, thereby reducing
the need for market gouvernment intervention through CMs, and reducing their distortive
effects if nonetheless required. However, scarcity pricing and CMs to a certain degree can be
seen as alternative measures to foster investments. Even if CM deployment rules and design
principles are ringfenced, the mere fact that resources are also renumerated by CMs means
that the effectiveness of scarcity prices to drive investment may be reduced as the number of
hours that scarcity occurs and thus the profits that more flexible resources can earn from
selling energy in the market is reduced. It needs also to be noted that scarcity prices and CMs
(at least in its market-wide version) act differently on investment decision in a crucial manner.
Whereas such CMs rewards any capacity, removing barriers for scarcity pricing will improve
remuneration of flexible capacity in particular.
The measures assessed under various options in the impact assessment seek to improve the
overall flexibilty of the electricity system. However, they do this by employing different
means. It can therefore be expected that some trade-offs exist between these options.
Improvements in the usage of interconnection capacity (as assessed under Problem Area I,
Option 1(b) (strenghening short-term markets)) allow a given plant to exploit variations in
production and demand over a larger geographcial area allowing for a more stable
intertemporal production pattern of the plant. Improving the usage of interconnection capacity
will hence favour the usage of less flexible resources over flexible ones. Similarly, pulling
demand response into the market will reduce the profits of generation capacity and, in
particular, flexible generation capacity which may amplify the amount of capacity that needs
to exit the market into the transition towards 2030. Ultimately, efficient markets should select
the most cost-efficient solutions.
Energy poverty safeguards whose costs directly accrue to suppliers – particularly, the costly
disconnection safeguards considered in Option 2 (Harmonization and extensive consumer
safeguards) of Problem Area IV (Retail markets) – may act as a barrier to retail-level
competition, and diminish the associated benefits to consumers, including lower prices, new
401
The other two drivers being wage growth and the energy efficiency of housing stock
226
Monitoring and evaluation
and innovative products, and higher levels of service. Although the implementation costs of
these safeguards will be passed on to consumers, and therefore socialized, different energy
suppliers may have different abilities to do this, and to deal with the additional consumer
engagement costs. Some may therefore choose not to enter markets with such safeguards in
place. A uniform level of such safeguards throughout the market would help create a level
playing field and address such competition impacts.
Sequencing of measures
7.5.3.
Over all, the synergies between the measures are large and the temporal dependency low, the
overall beneficial effects will be achieved only if all measures are implemented as a package.
A sequencing of measures is not necessarily appropriate to establish at EU level. The
judgement of moving to a next stage of market development much depends on the
development stage of the electricity market at hand. The reality is that Member States are at
different, sometimes even very different stages, in the development of their market
arrangements. As an example only, as a result of the individual characteristics of national
markets, the timing of the phase out of price regulation may differ on a case-by-case basis.
This is to enable national authorities to ensure that the necessary prerequisites of a smooth
transition are in place before all regulatory interventions in price setting are discontinued.
Such prerequisites may include, for example, the number of suppliers in the market, the
market share of the largest suppliers, or retail price levels. The same is true for other measures
proposed.
The EU legislation ultimately adopted should therefore need to find the appropriate balance
between setting out a well-defined endpoint whilst allowing sufficient space for Member
States to manage their transition thereon.
8. MONITORING AND EVALUATION
8.1. Future monitoring and evaluation plan
The Commission will systematically monitor the transposition and compliance of the Member
States and other actors with the finally adopted measures and take enforcement measures if
and when required and report on the progress made in this regard on a regular basis. For this
purpose, the Commission will be supported by ACER as described below.
In addition, as it has already done in the context of the implementation of the Third Package,
the Commission will provide guidance documents providing assistance on the implementation
of the adopted measures.
Parallel to the proposed initiatives, the Commission will bring forward an initiative
concerning the governance of the Energy Union that will streamline the monitoring and
reporting requirements. Based on the initiative of the governance of the Energy Union, the
current monitoring and reporting requirements of Commission and Member States' reporting
obligations in the Third Energy Package will be integrated in a horizontal monitoring report.
More information on the streamlining of the monitoring and reporting requirements can be
found in the impact assessment for the governance of the European Union.
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Monitoring and evaluation
The annual reporting by ACER and the evaluation by the Commission, together with the
reporting from the Electricity Coordination Group are part of the proposed initiatives and
described in the sections below.
8.2. Annual reporting by ACER and evaluation by the Commission
The monitoring of the proposed initiatives will be carried out following a two tier approach:
annual reporting by ACER and an evaluation by the Commission.
Annual reporting by ACER
8.2.1.
ACER's duties402
under the Third Package include the monitoring of and reporting on the
internal electricity market. ACER prepares and publishes an annual market monitoring report
that tracks the progress of the integration process and the performance of electricity markets
and identifies any barriers to the completion of the internal electricity retail and wholesale
markets.
The sources of data on which ACER relies to compile its annual market monitoring report are:
the Commission, NRAs, ENTSO-E, the Bureau Européen des Unions de Consommateurs
(BEUC) and other relevant organisations. ACER's annual report is based on publicly available
information and the information provided by these entities.
Based on the present proposals, ACER will continue to monitor and report on the internal
electricity market on an annual basis after the adoption of the proposals. ACER's annual
reporting will replace the Commission's reporting obligations that are currently still existing
under the Electricity Directive. The present proposals also foresee extending ACER's
monitoring mandate to include matters related to security of supply.
Evaluation by the Commission
8.2.2.
The Commission will carry out a fully-fleged evaluation of the impact of the proposed
initiatives, including the effectiveness, efficiency, continuing coherence and relevance of the
proposals, within a given timeline after the entry into force of the adopted measures
(indicatively, 5 years).
In the context of this evaluation, the Commission will pay particular attention as to whether
the assumptions underlying its analyses in the present impact assessment were valid.
The evaluation report will be developed by the Commission with the assistance of external
experts, on the basis of terms of reference developed by the Commission services.
Stakeholders will be informed of and consulted on the evaluation report, and they will also be
regularly informed of the progress of the evaluation and its findings. The evaluation report
will be made public.
402
The legal basis for the Agency’s market monitoring duties is in Article 11 of Regulation (EC) No. 713/2009.
ACER equally monitors and reports on many more detailed aspects of the regulatory framework.
(http://www.acer.europa.eu/Official_documents/Publications/Pages/Publication.aspx)
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Monitoring and evaluation
8.3. Monitoring by the Electricity Coordination Group
The Electricity Coordination Group will be also a tool to monitor developments in the internal
electricity market and in particular as regards security of supply more closely. To this end a
concrete mandate will be given to the Electricity Coordination Group, in particular to monitor
the security of supply in the EU on the basis of a set of indicators (e.g. EENS, LoLE) and
regular outlooks and reports produced by ENTSO-E403
.
8.4. Operational objectives
The key objective of the present initiative is to make electricity markets more secure, efficient
and competitive whilst ensuring that electricity is generated in a sustainable way and remains
affordable to all. The operational objectives for the preferred options are listed as follows:
Problem Area I (market design not fit for an increasing share of variable decentralised
generation and technological developments):
- Adoption of measures directed at removing market distortions deriving from the
different treatment to generation from different sources;
- Adoption of measures aiming at providing for liquid and better integrated short-term
markets;
- Adoption of measures directed at removing barriers preventing demand response from
participating in energy and reserve markets;
- Adoption of measures aiming at strengthening the role of ACER, clarifying the role of
NRAs at regional level, criteria for enhancing ENTSO-E's transparency and
monitoring obligations, rules for formalising the role of DSOs at European level.
Problem Area II (uncertainty about sufficient future generation investments and
uncoordinated capacity markets):
- Adoption of measures aiming at improving the price signals of the electricity markets;
- Specific requirements to align national CMs by requiring ENTSO-E to propose a
methodology for an EU-wide resource adequacy assessment and requiring Member
States to rely on the assessment.
- Adoption of rules aiming at enhancing the compatibility between CMs.
Problem Area III (reinforce coordination between Member States for preventing and
managing crisis situations):
- Adoption of measures aiming at improving risk assessment and preparedness;
- Adoption of rules aiming at improving coordination in emergency;
- Adoption of measures aiming at improving transparency and information sharing.
403
See Preferred Option (Option 2 (EU rules + regional cooperation)) to address problem Area III (When
preparing or managing crisis situations, Member States tend to disregard the situation across their borders).
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Monitoring and evaluation
Problem Area IV (retail markets):
- Adoption of measures aiming at reducing regulatory intervention in retail price setting;
- Adoption of measures aiming at protecting energy poor and vulnerable consumers;
- Adoption of measures directed at removing barriers to market entry for new supply
and service companies;
- Adoption of measures aimed at increasing consumer engagement and choice.
8.5. Monitoring indicators and benchmarks
As of 2021, ACER will be invited to review its current monitoring indicators with a view to
ensure their continuing relevance for monitoring progress towards the objectives underlying
the present proposals. ACER will continue relying on the same sources of data used for the
preparation of the market monitoring report. It will be tasked to cover in that report the
security of supply dimension as well. Monitoring indicators could include:
Problem Area I (market design not fit for an increasing share of variable decentralised
generation and technological developments):
- Indicators relating to market and regulatory barriers that affect the level playing field
between market participant and types of resources, such as the degree of capacity
dispatched - fully, partially or not at all - on the basis of price signals only, and the
usage of market and non-market based curtailment;
- Indicators related to the degree of flexibility available within the electricity system and
the development of intraday and balancing markets, such the level of market liquidity
in intraday and balancing markets and the allocation and use of cross-border capacity
for these time-frames, and related efficiency gains;
- Indicators related to the participation of distributed resources and demand in the
market (including use from system operators), energy service operators such as
aggregators and barriers to market participation. Such for example, the capacity and
production by distributed RES E and storage, the capacity of demand response
available and its activation, the number of facilities and their capacity operated by
aggregators;
- Indicators related to consumer access to smart metring systems, their functionalities
and availability/uptake of dynamic electricity pricing contracts;
- Indicators related to the evaluation of the performance by ACER, ENTSO-E and
NRAs of their duties.
Problem Area II (uncertainty about sufficient future generation investments and
uncoordinated capacity markets):
- Indicators pointing to the effectiveness of market arrangements in providing locational
signals and reflecting the value of electricity, also in times of scarcity, such as the
extent to which market prices have been contrained by any implicit or explict limits on
prices, levels of investment and correlation with price in different bidding zones.
- State interventions to support resource adequacy and their interaction with the EU's
electricity markets, such as their incidence, design features and degree of participation
of cross-border capacity;
Problem Area III (reinforce coordination between Member States for preventing and
managing crisis situations):
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Monitoring and evaluation
- Indicators for monitoring security of supply, such as expected energy non-served
(EENS) and loss of load expectation (LoLE);
- In the case that electricity crisis situations occur, the lessons learnt from these stress
situations should also feed in the analysis of security of supply.
Problem Area IV (retail markets):
- The incidence of regulated prices and the progress towards their phase-out;
- Market developments regarding consumer switching, switching facilitation such as
switching rates, costs and incidence of price and non-price barriers to switching.
- Key performance indicators measuring the economic and technical effectiveness of
DSOs and impact on system users (level of distribution charges).
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Glossary and Acronyms
9. GLOSSARY AND ACRONYMS
ACER The Agency for the Cooperation of Energy Regulators, a European
Union Agency that was created by the Third Energy Package to
further progress the completion of the internal energy market both
for electricity and natural gas.
ACER Regulation: Regulation (EC) No 713/2009 of the European Parliament and of
the Council of 13 July 2009 establishing an Agency for the
Cooperation of Energy Regulators, OJ L 211, 14.8.2009, p. 1–14.
Adequacy (Resource) adequacy can be defined as the ability of the system to
meet the aggregate power and energy requirements of all
consumers at virtually all times. In this impact assessment the term
resource adequacy is favoured over other terms often used in this
context, such as generation or system adequacy
aFFR See FFR
Aggregator A service provider that combines multiple consumer loads
(flexibility or energy) and/or supplied energy units for sale or
auction in organised energy markets.
Ancillary Services: Services necessary to support the transmission of capacity and
energy from resources to loads while maintaining reliable operation
of the transmission service provider. They refer to a range of
functions which TSOs contract so that they can guarantee system
security. These include services like the provision of mFFR and
aFFR or reactive power.
Balancing The situation after markets have closed (gate closure) in which a
TSO acts to ensure that demand is equal to supply, in and near real
time.
Balancing Guideline Commission Regulation establishing a Guideline on Electricity
Balancing, one of the legal acts to be adopted under Article 18 of
the Electricity Regulation.
Balancing reserves All resources, if procured ex ante or in real time, or according to
legal obligations, which are available to the TSO for balancing
purposes.
BAU Business As Usual, i.e. the state of the world if no additional action
is taken.
Bidding zone A bidding Zone means a geographical area within which electricity
market wholesale prices are uniform and market participants not
have to take into account grid constraints. Market participants who
wish to buy or sell electricity in another bidding zone have to take
into account grid constraints and related congestion rent payments.
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Glossary and Acronyms
BRPs Balance responsible parties, such as producers and suppliers, keep
their individual supply and demand in balance in commerical
terms.
BSPs Balancing Service Providers, such as generators or demand
facilities, balance-out unforeseen fluctuations on the electricity grid
by rapidly increasing or reducing their power output.
CACM Guideline Guideline on Capacity Allocation and Congestion Management,
one of the legal acts adopted under Article 6 of the Electricity
Regulation.
CCGT Combined Cycle Gas Turbine, a common type of gas-fired
generation plant
CEEE Central Eastern European Electricity Forum, a platform for
cooperation between certain EU Member States.
CERT Computer Emergency Response Team.
CHP Combined Heat and Power units produce heat and electricity
simultaneously. Their production of electricity is not necesarrily
deterined only by prices for electricity.
CM Capacity Mechanism, a regulatory intervention that remunerates
the availability of electricity resources instead of the production of
electricity (or the avoidance of electricity consumption).
Congestion Means a situation in which an interconnection linking national
transmission networks cannot accommodate all physical flows
resulting from international trade requested by market participants,
because of a lack of capacity of the interconnectors and / or the
national transmission systems concerned.
Conventional generation The non-low carbon technologies, based on fossil fuels (lignite,
hard coal, natural gas, oil). They usually constitute the mid-range
and peaking plants.
Cross-zonal transmission capacity: The capability of the interconnected system to
accommodate energy transfers between bidding zones.
CSIRT Computer Security Incident Response Team.
CT Comparison Tools, websites that help consumers to compare
different offers in the market.
Curtailment Curtailment means a reduction in the scheduled capacity or energy
delivery.
Day-ahead market The market timeframe where commercial electricity transactions
are executed the day prior to the day of delivery of traded products.
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Glossary and Acronyms
DER Distributed Energy Resources, a generic term referring electricity
assets such as small-scale RES E, storage connected to distribution
grids or by end-consumers on their premises.
Digital Single Market EU policy strategy aimed at: (i) helping to make the EU's digital
world a seamless and level marketplace to buy and sell; (ii)
designing rules which match the pace of technology and support
infrastructure development; and (iii) ensuring that Europe's
economy, industry and employment take full advantage of what
digitalisation offers.
DR Demand (side) response, the ability of consumers of electricity to
actively adapt their consumption to market conditions.
DSO Distribution System Operator, the entity that operates, maintains
and develops the low voltage networks in a given area to which
most consumers are connected.
ECG The Electricity Coordination Group was created in 2012 by
Commission Decision of 15 November 2012. The Group is a
platform for the exchange of information and coordination of
electricity policy measures having a cross-border impact. It also
aims to facilitate the exchange of information and cooperation on
security of electricity supply, including the coordination of action
in case of an emergency within the Union.
EE Energy Efficiency Directive. Directive 2012/27/EU of the
European Parliament and of the Council of 25 October 2012 on
energy efficiency, amending Directives 2009/125/EC and
2010/30/EU and repealing Directives 2004/8/EC and 2006/32/EC.
This directive establishes a set of binding measures to help the EU
reach its 20% energy efficiency target by 2020.
EEAG Communication from the Commission - Guidelines on State aid for
environmental protection and energy 2014-2020, OJ C 200,
28.6.2014, p. 1–55. The Guidelines aim to help Member States
design state aid measures that contribute to reaching their 2020
climate targets. The guidelines will be in force until the end of
2020.
EENS Expected Energy Non Served, a metric to measure security of
supply and to set a reliability standard.
EESC The European Economic and Social Committee.
Electricity Directive Directive 2009/72 of the European Parliament and of the Council
of 13 July 2009 concerning common rules for the internal market in
electricity and repealing Directive 2003/54/EC, OJ L 211,
14.8.2009, p. 55–93. Together with the Electricity Regulation, the
Electricity Directive sets the main parts of the legal framework for
the EU's electricity markets.
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Glossary and Acronyms
Electricity Regulation Regulation (EC) No 714/2009 of the European Parliament and of
the Council of 13 July 2009 on conditions for access to the network
for cross-border exchanges in electricity repealing Regulation (EC)
No 1228/2003, OJ L 211, 14.8.2009, p. 15–35. Together with the
Electricity Directive, the Electricity Regulation sets the main parts
of the legal framework for the EU's electricity markets.
End-customer End-customers procure electricity for their own use.
ENTSO-E European Network of Transmission System Operators for
Electricity. ENTSO-E was established and given legal mandates by
Third Package.
ENTSO-G European Network of Transmission System Operators for Gas.
ENTSOG was established and given legal mandates by Third
Package.
EPBD Energy Performance of Buildings Directive or Directive
2010/31/EU of the European Parliament and of the Council of 19
May 2010 on the energy performance of buildings. OJ L 153,
18.6.2010, p. 13–35, concerning energy efficiency of building.
Modifications are being proposed to the EPBD.
ETS Emmission Trading System, works on the 'cap and trade' principle.
A 'cap', or limit, is set on the total amount of certain greenhouse
gases that can be emitted by the factories, power plants and other
installations in the system. The cap is reduced over time so that
total emissions fall. This policy instrument equally fosters
penetration of RES E as it renders production of electricity from
non- or less-emitting generation capacity more economical.
EU Target Model: Term refering to the current design of the EU's electricity markets.
The EU target model is based on two broad principles: (i) the
development of integrated regional wholesale markets, preferably
established on a zonal basis, in which prices provide important
signals for generators' operational and investment decisions; and
(ii) market coupling based on the so-called "flow-based" capacity
calculation, a method that takes into account that electricity can
flow via different paths and optimises the representation of
available capacities in meshed electricity grids.
EUCO27 The central policy scenario modelled by PRIMES, reflecting the
agreed 2030 climate and energy targets (and the 2050 EU's
decarbonisation objectives).
FCR Frequency Containment Reserve are reserves from reserve
providers (generators, storage, demand response) used by TSOs to
maintain frequency stable in the whole synchronous area (e.g.
continental Europe). This category typically includes automatically
activated reserves with the activation time up to 30 seconds.
235
Glossary and Acronyms
Florence Forum The Florence Forum was set up to discuss the creation of a true
internal electricity market in Europe. The participants are national
regulatory authorities, Member States, the European Commission,
international organisations in the area of energy and European-wide
associations representing transmission and distribution system
operators, electricity traders, consumers, network users and power
exchanges.
FRR Frequency Restoration Reserve are reserves from reserve providers
(generators, storage, demand response) used by TSOs to restore
system frequency and power balance after sudden system
imbalance occurrence (e.g. the outage of a power plant). Those
reserves replace FCR if the frequency deviation lasts longer than 30
seconds. This category includes operating reserves with an
activation time typically between 30 seconds up to 15 minutes.
FRR can be distinguished between reserves with automatic
activation (aFRR) and reserves with manual activation (mFRR).
Gas Directive: Directive 2009/73 of the European Parliament and of the Council
of 13 July 2009 concerning common rules for the internal market in
gas and repealing Directive 2003/55/EC, OJ L 211, 14.8.2009, p.
94–136. Together with the Gas Regulation, the Gas Directive sets
the main parts of the legal framework for the EU's gas markets.
Gas Regulation: Regulation (EC) No 715/2009 of the European Parliament and of
the Council of 13 July 2009 on conditions for access to the natural
gas transmission networks and repealing Regulation (EC) No
1775/2005, OJ L 211, 14.8.2009, p. 36-54. Together with the Gas
Directive, the Gas Regulation sets the main parts of the legal
framework for the EU's gas markets.
Gate closure The moment when contracts are frozen. After gate closure, no
trading is allowed anymore. At this point, parties are expected to
adhere to the physical data submitted to the System Operator and to
the contracted volumes submitted before Gate Closure.
G-charges Charges for network usage imposed on generators
Generator A generator produces electricity and sells this to suppliers or end-
customers
Independent aggregator Aggregator that is not affiliated to a supplier or any other market
participant.
ITC Regulation Commission Regulation (EU) No 838/2010 of 23 September 2010
on laying down guidelines relating to the inter-transmission system
operator compensation mechanism and a common regulatory
approach to transmission charging
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Glossary and Acronyms
LFC block Load-Frequency Control block or balancing zone, defines the size
of the network area for which the balancing reserves are being
procured.
Load The total electricity demand
Load Payments Load Payments correspond to the amount of money retail
companies/consumers need to pay to generators for the electricity
bought from the wholesale market. For each hour, it corresponds to
the product of served demand with the electricity price.
LoLE Loss of load expectation, a metric to measure security of supply
and to set a reliability standard
LTC Long-term contract.
METIS A modelling tool used by the Commission, described in more detail
in Annex IV.
mFFR See FFR
NC ER Network Code on Emergency and Restoration
NEMO Nominated Electricity Market Operator; an entity designated by
competent authroities to perform tasks related to single day-ahead
and intraday coupling as defined in the Guideline on Capacity
Allocation and Congestion Management, one of the legal acts
adopted under Article 6 of the Electricity Regulation.
Electricity network codes and guidelines: a legal act adopted under Articles 6, 8 and 18 of the
Electricity Regulation. Examples of such codes and guidelines are
the NC ER, the CACM guideline, the RfG, the System Operation
Guideline or the Balancing guideline. For a full overview of these
network codes and guidelines, reference is made to Annex VII.
NIS Directive Directive (EU) 2016/1148 of the European Parliament and of the
Council of 6 July 2016 concerning measures for a high common
level of security of network and information systems across the
Union, OJ L 194, 19.07.2016, p. 1-30.
NRAs National Regulatory Authorities, are national authorties set up and
empowered by the Third Package to over see national electricity
(and gas) markets.
NTC Net Transfer Capacity, a metric to measure the capacity available
on interconnectors to transfer electricity.
Plan Risk Preparedness Plans, a measure proposed under Problem Area
III
PLEF Pentalateral Energy Forum, a platform for collaboration consisting
of the Ministries, NRAs and TSOs of the BENELUX, DE, FR, AT,
237
Glossary and Acronyms
CH as well as a market parties platform and the European
Commission.
Power exchange Power exchanges facilitate the trading of electricity at wholesale
level, often for delivery the next day or at even shorter intervals
(intraday). They cooperate with TSOs in optimising
interconnection capacity in the contex of market coupling.
PRIMES A modelling tool used by the Commission, described in more detail
in Annex IV.
PV Photovoltaic
RED II The Renewable Energy Package comprising the new Renewable
Energy Directive and bioenergy sustainability policy for 2030
Redispatching A measure activated by one or several system operators by altering
the generation and/or load pattern in order to change physical flows
in the transmission system and relieve a physical network
congestion.
Regional platform A platform or regionally coordinated platforms for the attribution
of Long Term Cross Zonal Capacity for a single border or set of
borders.
RES E Renewable sources of electricity
RfG Network code on Requirements for Grid Connection of Generators
ROC Regional Operational Centre
RR Replacement Reserve are reserves from reserve providers
(generators, storage, demand response) used by TSOs to restore the
required level of FCR and FRR due to their earlier usage. Contrary
to FCR and FRR, not all TSOs in the EU maintain RR. This
category includes operating reserves with activation time from
several minutes up to hours.
RSC Regional Security Coordinators, an entity foreseen under the
System Operation Guidelines to assist TSOs in maintaining the
operational security of the electricity system.
Sector Inquiry The sector inquiry into capacity mechanisms as conducted by DG
Competition of the European Commission
Smart meter An electronic device that records consumption of electric energy in
intervals of an hour or less and communicates that information at
least daily back to the utility for monitoring and billing. Smart
meters enable two-way communication between the meter and the
central system.
238
Glossary and Acronyms
SME Small and Medium-sized Enterprises as defined in the Commission
Recommendation of 6 May 2003 concerning the definition of
micro, small and medium-sized enterprises (notified under
document number C(2003) 1422), OJ L 124, 20.05.2003, p. 36-41.
SoS Directive Security of Electricity Supply Directive or Directive 2005/89/EC of
the European Parliament and of the Council of 18 January 2006
concerning measures to safeguard security of electricity supply and
infrastructure investment, OJ L 33, 4.2.2006, p. 22–27
Supplier Suppliers are active in the retail segment of the market and supply
electricity to end-consumers
Switching rate The percentage of consumers changing suppliers in any given year.
System Operation Guideline: Draft Commission Regulation which will set down rules relating
to the maintenance of the secure operation of the interconnected
transmission system in real time.
TFEU Treaty of the Functioning of the European Union
Third Package: A package of legislation adopted in 2009 comprising the Electricity
Directive, the Electricity Regulation, the ACER Regulation as well
as similar legislation concerning the gas markets.
ToU tariffs Time-of-Use tariffs: Time-based pricing is a pricing strategy where
the provider of a service or supplier of a commodity, may vary the
price depending on the time-of-day when the service is provided or
the commodity is delivered.
Transmission capacity The transmission capacity, also called TTC (Total Transfer
Capacity), is the maximum transmission of active power in
accordance with the system security criteria which is permitted in
transmission cross-sections between the subsystems/areas or
individual installations.
TRM Transmission Reliability Margin, a metric to capture the amount of
transmission transfer capability necessary to provide reasonable
assurance that the interconnected transmission system will be
secure during changing system conditions
TSO Transmission System Operator, the entity that operates, maintains
and develops the high voltage networks in a given area.
TYNDP Ten-Year Network Development Plan
VCWG The Vulnerable Consumer Working Group provides advice to the
European Commission on the topics of consumer vulnerability and
energy poverty, its membership comprising industry, consumer
associations, regulators and Member States representatives.
239
Glossary and Acronyms
VoLL Value of Lost Load is a projected value reflecting the maximum
price consumers are willing to pay to be supplied with electricity.
VoLL is typically quite high (e.g. several thousands of EUR/MWh)
and not necessarily the same for each (group of) consumer, thus
enabling DR activation by consumers before the VoLL is reached.


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 2/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
240
TABLE OF CONTENTS
ANNEXES................................................................................................................................ 241
Annex I: Procedural information..................................................................................................241
Annex II: Stakeholder consultations.............................................................................................249
Annex III: Who is affected by the initiative and how....................................................................265
Annex IV: Analytical models used in preparing the impact assessment. .....................................282
Annex V: Evidence and external expertise used ..........................................................................317
Annex VI: Evaluation.....................................................................................................................323
Annex VII: Overview of electricity network codes and guidelines ...............................................325
Annex VIII: Summary tables of options for detailed measures assessed under each main option
......................................................................................................................................................327
241
Annex I: Procedural information
ANNEXES
Annex I: Procedural information
Lead DG: DG Energy
Agenda planning/Work Programme references:
- AP 2016/ENER/007 (Initiative to improve the electricity market design)
- AP 2016/ENER/026 (Initiative to improve the security of electricity supply)
Publication of Inception Impact Assessment:
- October 2015 (Initiative to improve the electricity market design)
- October 2015 (Initiative to improve the security of electricity supply)
No feedback was received on the Inception Impact Assessments
Inter-service group:
An Inter-service group meeting was used comprising the Legal Service, the
Secretariat-general, DG Budget, DG Agriculture and Rural development, DG
Climate action, DG Communications Networks, Content and Technology, DG
Competition, DG Economic and Financial Affairs, DG Employment, Social
affairs and Inclusion, DG Energy, DG Environment, DG Financial stability,
Financial services and Capital markets, DG Internal market, Industry,
Entrepreneurship and SMEs, the Joint Research Centre, DG Justice and
Consumers, DG Mobility and Transport, DG Regional and urban development,
DG Research and innovation, DG Taxation and Customs Union.
Not all Directorate-generals did participate in each ISG meeting
Meetings of this ISG were held on: 28 October 2015, 25 April 2016, 20 June
2016 and 8 July 2016
Consultation of the RSB
The impact assessment was submitted to the RSB on 20 July 2016. On 14
September 2016, the impact assessment was discussed with the RSB. On 16 of
September 2016 the RSB issued it opinion, which was negative. It requested to
receive a revised draft of the IA report addressing its recommendations whilst
briefly explaining what changes have been made compared to the earlier draft. A
draft impact assessment was resubmitted on 17 October 2016. A positive RSB
Opinion, with reservations, was issued on 7 November 2016?
The opinions and the changes made in response are summarised in the tables
below.
242
Annex I: Procedural information
Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
Issues cross cutting to other impact assessments
This IA and the IA on the revision of the
renewables directive need a coherent analysis
of renewable electricity support schemes.
They need to reconcile different expectations
of what the market will deliver in terms of the
share of renewable electricity and of the
participation of prosumers. Given uncertainty
on these issues, both IAs should incorporate
the same range of possible outcomes in their
analysis
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4. This vision includes a section on the
connection with the share of RES E and
prosumers.
The IA should clarify and explain the content
and assumptions of the baseline scenario in
relation to the other parallel initiatives
A dedicated section was included in Annex
IV clarifying all points raised concerning the
baseline, REF2016 and EUCO27.
The baseline description in 5.1.2, 5.2.2,
6.1.1.2 and 6.1.1.4 was improved and
references were made to its more detailed
description in the Annex.
Issues specific to the present impact assessment
The IA report is too long and complex to
make it helpful in informing political
decisions. The Board recommends that this
report begin with a concise, plain-language
abstract of approximately 10-15 pages. This
abstract should summarise the key elements
of the IA and identify the main policy trade-
offs
A plain-language abstract has been added at
the beginning of the document.
The report should present a clear vision for
the EU electricity market in 2030 and beyond
with a distinction between immediate
challenges and longer term developments.
This vision needs to be coherent with EU
policies on competition, climate and energy.
It also needs to be consistent with the parallel
initiatives, notably the revision of the RES
Directive. In particular, this applies to the
assumptions and expectations on what the
new electricity market design could deliver
on its own and whether the renewable target
requires complementary market intervention.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4 covering issues mentioned.
A detailed section on in RES E in connected
with the MDI is contained in a text box in
section 6.2.6.3. Another box is located in
Section 2.1.3.
Further clarifications have been added in
section 1.2.1 on interlinkages with RED II.
Based on a common (with other parallel
initiatives) baseline scenario, the report
should prioritise the issues to be addressed,
present an appropriate sequencing and
strengthen the treatment of subsidiarity
considerations such as for action related to
energy poverty and distribution system
operators.
A dedicated section was introduced in Annex
IV clarifying all points raised concerning the
baseline, REF2016 and EUCO27.
The baseline description in 5.1.2, 5.2.2,
6.1.1.2 and 6.1.1.4 was improved and
references were made to its more detailed
description in the Annex.
243
Annex I: Procedural information
Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
A dedicated section on sequencing was
introduced as section 7.5.3
Regarding the treatment of subsidiarity for
actions related to energy poverty, please see
sections 5.4.4; and 5.4.5. The report assesses
the options with regards to subsidiarity. It
argues that measures in Option 1 are
proportionate and in line with the subsidiarity
principle while measures in Option 2 entail
significant costs and may be better carried out
by national authorities.
When assessing the impacts of the different
options, the report should indicate whether
and how the models of “energy only markets”
will coexist with capacity mechanisms and
assess the risks of an uncoordinated
introduction of capacity remuneration
mechanisms across the EU. The impact
analysis should also report on the
effectiveness of the options to deliver the
adequate investment and price responses.
On how the models of "energy only markets"
will coexist with CMs, clarifications have
been introduced in section 2.2.2.
Section 6.2.6 now includes a sub-section on
investments, discussing all relevant issues.
Main recommendations for improvements
The analysis of support schemes for
renewable electricity should be consistent
across this impact assessment and the one
covering renewable energy sources. The
reports should clarify what support schemes
will be needed, and whether these are needed
only in case the market fails to deliver the
2030 EU target of at least 27% of RES in
final energy consumption, or will be used to
promote certain types of renewable energy.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4. This includes a vision on whether
outside-the- market measures to support for
RES E are needed up to 2030. The question
what type of out-of-market support
mechanisms are needed falls within the remit
of the RED II IA.
A dedicated section was included in Annex
IV clarifying all points raised concerning the
baseline. Via the definition of the baseline,
the impact assessment for the MDI and RED
II are fully compatible, including as regards
the assessment of support schemes.
The IA should take into account the tendering
procedure envisaged for procuring support
for renewable energy producers and assess its
impact on the electricity market.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4. This includes a vision on whether
outside-the- market measures to support for
RES E are needed. A detailed section on in
RES E in connected with the MDI is
contained in a text box in section 6.2.6.3.
Further clarifications have been added in
section 1.2.1 on interlinkages with RED II.
244
Annex I: Procedural information
Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
In addition, even though the report does not
present a blueprint for a capacity
remuneration mechanism (as it is in the remit
of the state-aid guidelines/EU competition
policy), it should analyse possible detrimental
effects of such mechanisms being introduced
in the EU in an uncoordinated fashion. In
particular, the IA should examine distortions
to investment incentives and price setting
mechanisms.
The clarification in Annex IV as regards the
baseline explains how, the impact
assessments for the MDI and RES E are fully
compatible, including as regards to the
tendering procedure (see section on current
market arrangements in Annex IV).
Text adapted in section 2.2.2 and included a
reference to forthcoming report by DG
Competition.
The expected involvement of consumers and
prosumers in supplying electricity and
managing its demand has to be consistent
across the two impact assessments.
The analysis should integrate the effects of
potentially more volatile electricity prices and
high fixed network costs on prosumer
involvement and on the long-term risk that
these might disconnect from the network as
local storage technology evolves.
An explicit vision of the EU electricity
market has been incorporated in section
1.1.1.4.
This includes a vision on prosumers and the
risk of disconnection, which is further
developed in a text box in Section 6.1.4.2.
Also the RED II IA has been adjusted.
In devising the options, the report should be
proportionate to the importance of the
problems/objectives and realistic in assessing
what can be achieved. For instance, options
linked to the issue of energy poverty (being
part of the social policy) should be built
around increasing transparency and peer
pressure among Member States rather than
the single market motive.
See section 2.4.1 and section 5.4.4. The
report clarifies the main objective of the
measures linked to energy poverty (i.e.
description of the term 'energy poverty' and
measurement of energy poverty), which
already apply to Member States (Member
States should address energy poverty where it
is identified). Better monitoring of energy
poverty across the EU will, on one hand, help
Member States to be more alert about the
number of households falling into energy
poverty, and on the other hand, peer pressure
encourages Member States to put in place
measures to reduce energy poverty.
The baseline scenario should be clarified,
including the link with the 2016 reference
scenario and underlying assumptions
A dedicated section was included in Annex
IV clarifying all points raised concerning the
baseline, REF2016 and EUCO27.
Some more technical comments have been
transmitted directly to the author DG and are
expected to be incorporated into the final
version of the impact assessment report
All technical comments have been addressed.
245
Annex I: Procedural information
Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
The IA report needs to be more reader-
friendly and helpful for decision-making. The
report should contain a 10-15 page abstract
that succinctly presents the main elements of
the analysis, the policy trade-offs and the
conclusions. The main text should be
streamlined to contain the crucial elements of
the analysis in the main part of the report
A reader friendly abstract that succinctly
presents the main elements of the analysis,
the policy trade-offs and the conclusions has
been added to the main text of the IA.
246
Annex I: Procedural information
Comments made by RSB in second
Opinion on 7 November 2016
Modifications made in reaction to
comments RSB
Opinion RSB on resubmission
Restoring price signals for investments is
one crucial element of the revised market
design. The report is clearer on its view that
undistorted markets deliver the right price
signals for investment. The report should
more convincingly explain how adequate
pricing could be achieved in the presence
of national capacity markets and subsidies
for renewables which might exacerbate
excess capacity in the market.
The report should assess the risk of
persistent low electricity wholesale prices
and associated consequences for the
effectiveness of the initiative. What would
be the effects for investment, demand
response, elimination of subsidies, and
consumer benefits?
Reference is made to the new Box 9
underneath Section 6.4.6 for further
explanations, which was added following
the RSB comments.
Further recommendations for improvements
Internal coherence and risks:
The analysis in the report demonstrates that
the vision for the EU electricity market in
2030 and beyond relies on the
implementation of many different policies
and assumptions, and is subject to
numerous risks. The narrative of the report
should more clearly reflect these risks. The
report should propose modalities to review
assumptions and monitor implementation at
intermediate stages. The text of the report
should reflect the trade-off between
restoring the EU internal energy market in
its pure form and government intervention
to support renewable energy sources and to
maintain security of supply.
Text has been added to Sections 8.1 and
8.2.2 with regard to the reviewing of
assumptions and monitoring of
implementation.
The 2030 RES E objectives are part of the
base-line of the analyses. Trade-offs
between government interventions in
support of RES E are investigated in the
REDII impact assessment. However, in the
present report, it has been rendered more
clearly what elements of the RED II
initiative are important to the impacts of the
present initiative.
See in this regard Section 1.1.1, 1.2.1, Box
7 under section 6.2.6.3, Box 9 under Section
6.4.6 and Annex IV.
It is noted that improving market
functioning reduces the need for
government intervention with regard to both
RES E (See Section 1.1.1.4, Box 7 below
section 6.2.6.3 and section 7.5.1) and
resource adequacy (See section 6.2.2.1,
Section 6.2.6.3 and Section 7.5.1).
Impact analysis: The vision of an energy
Union places citizens at its core. The report
should therefore better address the risks
and benefits to consumers, especially with
regard to expected higher price variability.
It should discuss not just possible long run
benefits, but also costs (including switching
The risks of greater price variability have
been introduced in two new text boxes in
Section 5.1.4.3 (Box 4) of the main impact
assessment document, and in Section 3.1.5
of the Annexes to the Impact Assessment.
These specifically address the benefits and
risks of dynamic electricity pricing
247
Annex I: Procedural information
Comments made by RSB in second
Opinion on 7 November 2016
Modifications made in reaction to
comments RSB
fees) in the short and medium term. In the
same vein, the report should examine the
impact of the policy on various groups of
consumers
contracts, which are a frequent concern of
consumer groups.
The impacts of the measures in Problem
Area IV (Retail Markets) on different
groups of consumers have been addressed in
a text box in Section 6.4.3.2 of the Impact
Assessment Report (Box 8) and text boxes
in Sections 7.1.5, 7.2.5, 7.3.5, 7.4.6, 7.5.5,
and 7.6.6 of the Annexes to the Impact
Assessment.
While the Board takes note that impacts are
based on modelling, the results of the
modelling should be critically reviewed to
avoid false expectations, in view of many
assumptions taken. For instance, the
modelling results in the average level of
wholesale prices at 74€/MWh already in
2020 and 103€/MWh in 2030). The
attainment of these price levels is hard to
imagine in reality, given that currently that
level is around 34€ and more renewable
capacity is being deployed into the system,
still benefitting from the current support
schemes for RES-E (based mostly on feed-
in tariffs). Lower than modelled wholesale
prices could seriously undermine the
investment outcome, the assumed increased
engagement of consumers and demand
response – the cornerstones of the EU
Energy Union.
To improve clarity, the new Box 9 includes
further explanations. Please also see new
footnotes 345 and 384
.
Similarly, the effectiveness of the revised
RES-E support schemes (as proposed in the
RED II IA) is not critically discussed. First,
the report needs to emphasize that they
would not be based on any type of feed-in
tariff but premiums on top of market
revenues and these premium will be
auctioned. Second, the report needs to
consider the fact that such auctions may not
necessarily be effective in reducing the
support to renewable energy sources. This
is particularly relevant in a situation where
the share of renewables in the electricity
generation mix is expected to grow
It has been made clearer that market based
support schemes, such as premium schemes
combined with auctions, are an underlying
premise of the impacts of the present
initiative. (See section 1.1.1, 1.2.1, Box 7
under section 6.2.6.3, Box 9 underneath
section 6.4.6 and Annex IV)
The phase-out of non-market based support
schemes has already commenced under the
EEAG adopted in 2014 and is further
reinforced by the measures proposed by
RED II. It is therefore assumed that non-
market based support schemes are fully
248
Annex I: Procedural information
Comments made by RSB in second
Opinion on 7 November 2016
Modifications made in reaction to
comments RSB
substantially and the wholesale prices will
be depressed at least until the current
support schemes for RES-E are reviewed in
2024.
phased out by 2024, whereas the impact
assessment looks at the situation in 2030.
For more detail see Annex IV.
The cost effectiveness of the RES E support
schemes as such is the subject of the RED II
impact assessment.
Procedure and presentation
While the report is still very long, the
inclusion of the abstract has improved the
presentation of relevant information,
though the issue of policy trade-offs
(market vs. government interventions)
should be emphasized more explicitly
References to policy trade-offs (market
versus government intervention) have been
further emphasised. See for instance the
abstract, page 10 and 13 and Sections
6.2.2.1, 6.2.6.3 and 7.5.1. Furthermore,
Options 2 and 3 under problem area II
expressly seek to address the compatibility
of government intervention in a market
context.
An overview of evidence and external expertise used is provided in a separate annex.
249
Annex II: Stakeholder consultations
Annex II: Stakeholder consultations
Public consultations
In preparation of the present initiative, the Commission has conducted several public
consultations, in particular:
- public consultation on generation adequacy, capacity mechanisms, and the
internal market in electricity, conducted in 2013;
- consultation on the retail energy market, conducted in 2014;
- public consultation on a new energy market design, conducted in 2015;
- public consultation on risk preparedness in the area of security of electricity
supply, conducted in 2015.
These public consultation and their results are describe in more detail below.
Stakeholder opinions are also summarised in boxes for each main policy option in
section 5 and, if appropariate, elsewhere of the present impact assessment. Even more
detailed representations of stakeholder opinions are contained in Section 7 of each the
annexes assessing the options for detailed measures.
Public consultation on generation adequacy, capacity mechanisms, and the internal
market in electricity
Resource adequacy related issues were the subject of a public consultation1
conducted
from 15 November 2012 to 7 February 2013 through the "Consultation on generation
adequacy, capacity mechanisms, and the internal market in electricity". It was open to
EU and Member States' authorities, energy market participants and their associations,
and any other relevant stakeholders, including SMEs and energy consumers, and citizens.
It aimed at obtaining stakeholder's views on ensuring resource adequacy and security of
electricity supply in the internal market.
As regards the quality and representativeness of the consultation, the consultation
received 148 individual responses from public bodies, industry (both energy producing
and consuming) and academia. Most responses (72%) came from industry. Responses
were of a high standard, not only engaging with the questions posed and the challenges
being addressed, but bringing valuable insights to the Commission's reflections of this
important topic. The consultation appears representative in comparison with similar
consultations.
1
https://ec.europa.eu/energy/sites/ener/files/documents/20130207_generation_adequacy_consultation_d
ocument.pdf
250
Annex II: Stakeholder consultations
The following paragraphs provide a summary of the responses available on the
Commission's website2
. The responses and a summary thereof are also available on the
Commission's website3
.
(i) Government interventions. Respondents to the consultation responses repeatedly
highlighted the policy uncertainty and national uncoordinated interventions of
various kinds, in particular support for renewables, as being critical elements in
discouraging investment. This was highlighted frequently by industry and also by
academics and think tanks. The related issue of fixing the flaws of ETS was also
raised repeatedly by industry. For example Energy UK states that "national
measures often response to a lack of coherence in EU energy policy itself – in
particular there is a conflict between the market driven approach to liberalisation
and to EU ETS and the various sectoral targets in renewables, energy efficiency
etc." The Netherlands (Ministry of Economic Affairs) responded "the absence of
a credible carbon policy and a lack of proper market functioning cannot be
underestimated";
(ii) Market functioning. In the context of a weak demand and economic crisis,
Europe's energy markets today area was deemed characterised by two
developments: the integration of large amounts of renewables and the
implementation of the EU target model. This was clearly reflected in the
responses to this consultation. Overall respondents' opinions were split as to
whether energy-only markets could deliver investments needed to ensure
generation adequacy and security of supply. However, there is near unanimous
support from respondents for the importance of the completion of the integration
of day-ahead, and close to real time markets as a an important contributor to
security of supply although, some respondents caution that this will not address
fundamental problems with whether energy-only markets can deliver resource
adequacy Similarly, there are strong calls facilitating demand side response and
the development of grids in line with the ten year network development plan.
Almost all responses to the consultation raised the impact of RES E on the
market. For example the UK response discusses the impact that more low
marginal cost pricing will have on the market, and the issue is discussed in detail
in the Clingendael paper submitted in response to the consultation. Industry in
particular raised the issue about the impact that RES E support schemes had on
the market. While many raise the issue of any out-of-market support creating
distortions, the position set out in the response of Eneco, a Dutch company is
worth quoting "In general, support for specific energy sources does not
undermine investments to ensure generation adequacy, it just changes the merit
order. But details of support mechanisms can, specifically if a support mechanism
lowers the value of flexibility". This consideration can be seen in the numbers of
2
https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E
nergy%20Market.pdf
3
https://ec.europa.eu/energy/en/consultations/consultation-generation-adequacy-capacity-mechanisms-
and-internal-market-electricity
251
Annex II: Stakeholder consultations
respondents who cite priority dispatch or lack of balancing responsibility for RES
E producers as posing particular problems on the market, an issue which is
separate from the level of support for RES producers, as indeed recognised by
Germany who stat in their response "Allerdigs ist ein Umstieg von der
Festvergutuetung unter der garantierten Abnahme des EE-Stroms auf ein System
der Marktintergration notwendig, in dem die Erneueuerbaren ihre Einspeisung
an dem Marktpreissignal orientieren…".
(iii) Assessing security of supply. There is widespread recognition of a need for
improved assessment of generation and security of supply in the internal market
given the impact of both RES E and market integration. Proposal have been made
suggesting a need for more scenario analysis based on different weather
conditions, different timespans for the assessment (long-term, short-term), more
detailed assessment of flexibility and more coordination between TSOs and more
sensitivity analysis. In this regard the existing ENTSO-E generation adequacy
assessment is not felt to meet future needs, without suggesting that ENTSO-E is
not carrying out its current role properly. There is particularly strong support for
more regional generation adequacy assessments combined with a common
methodology for undertaking such assessments. For example France in its
response states "Il pourrait notamment être utile de renforcer la cohérence à
l’échelle régionale des différentes méthodes d’analyse et des scénarios produits
au niveau national, souvent interdépendants. Ces analyses régionales viendraient
ensuite alimenter un exercice réalisé à l’échelle de l’Union". Support for binding
standards is less strong among respondents. Many of those who, in principle,
would welcome common standards point to the difficulties in establishing such
standards while MS retain responsibility for Security of Supply (and hence
determining standards). Others (such as the Oeko institute) consider that more
harmonised activities of Member states are essential in the internal market. There
was limited support for a revision of the Security of Supply directive, which was
perceived to fulfil its limited role. Again France states that "Il apparaît préférable
de privilégier l’élaboration rapide de ces codes et achever ainsi la mise en oeuvre
des dispositions du 3ème
paquet avant d’envisager des mesures nouvelles au
travers de la refonte de cette directive." However some stated that since the
Directive was adopted before the Third Package, the situation after the Third
Package is different and therefore the level of cooperation prescribed by the
Directive does not correspond to today's situation. Summarising, there was
widespread support for a reassessment of how generation adequacy and security
of supply are assessed, and a recognition for the need for actions to be
coordinated. The question which stands out is what are the best tools to do this.
Here the electricity coordination group ('ECG') (explicitly mentioned by several
respondents) can play a critical role. The Commission will continue to examine
what are the best tools available to achieve the widely supported aim of improved
generation adequacy assessment.
(iv) Interventions to ensure security of supply. As already noted opinion is divided on
whether energy only markets can deliver the investments which will be needed to
ensure generation adequacy and security of supply in the future. However, there
were even more varied opinions on the effectiveness of different capacity
remuneration mechanisms. Given this divergence of opinion therefore there is
only limited support for a European blueprint, many respondents pointing to
divergent local circumstances and the need to address specific problems as
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Annex II: Stakeholder consultations
militating against such an approach. Against this there was very strong support,
particularly among industry and academica, for EU wide criteria, governing
capacity mechanisms extending also to the high level criteria which proposed in
the consultation paper. Among Member States the UK specifically called for
criteria to be linked to State aid assessments, and notwithstanding caution about
overly detailed assessment at EU level its detailed comments on the individual
criteria in the consultation paper were broadly supportive. FR states "Il est
toutefois utile et légitime que la Commission européenne suive de près l’impact
des choix des Etats membres sur le marché intérieur" but also cautions that "Il
semble prématuré à ce stade de définir des critères détaillés de compatibilité avec
le marché intérieur". DE states that the Commission "im Bedarfsfall eintreten,
der die Koordinierung zwischen den MS zu einer stärker gemeinsamen
…Gewährleistung der Versorgungssicherheit erleichtert.".
Consultation on the retail energy market
A public consultation dedicated to electricity retail markets and end-consumers4
was
conducted from 22 January 2014 to 17 April 2014. It was open to all EU citizens and
organizations including public authorities, as well as relevant actors from outside the EU.
This public consultation aimed at obtaining stakeholder's views on the functioning of
retail energy markets.
As regards representativeness and quality, the Commission received 237 responses to the
consultation. About 20% of submissions came from energy suppliers, 14% from DSOs,
7% from consumer organisations, and 4% from NRAs. A significant number of
individual citizens also participated in the consultation.
The following paragraphs provide a summary of the responses, which are also available
on the Commission's website5
.
(v) Retail competition. Respondents to this public consultation felt that market-based
customer prices are an important factor in helping residential customers and
SMEs better control their energy consumption and costs (129 out of 237
respondents considered that it was a very important factor while other 66
qualified it as important for the achievement of the said objective). Moreover, out
of 121 respondents who considered that the level of competition in retail energy
markets is too little, 45 recognised regulation of customer prices as one of the
underlying drivers.
81% of the respondents agreed that allowing other parties to have access to
consumption data in an appropriate and secure manner, subject to the consumer's
explicit agreement, is a key enabler for the development of new energy services
for consumers.
4
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
5
https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E
nergy%20Market.pdf
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Annex II: Stakeholder consultations
As regards whether it is sufficiently easy without facing disproportionate
permitting and grid connection procedures for a consumer to install and connect
renewable energy generation and micro-CHP pursuant to the provisions of the
RES and Energy performance in buildings Directives the views are split.
(vi) Consumer issues. 222 out of 237 respondents to the retail market public
consultation believed that transparent contracts and bills were either important or
very important for helping residential consumers and SMEs to better control their
energy consumption and costs.
When asked to identify key factors influencing switching rates, 89 respondents
out of 237 stated that consumers were not aware of their switching rights, 110
stated that prices and tariffs were too difficult to compare due to a lack of tools
and/or due to contractual conditions, and 128 cited insufficient benefits from
switching.
178 out of 237 agreed that ensuring the availability of web-based price
comparison tools would increase consumers' interest in comparing offers and
switching to a different energy supplier. 40 were neutral and 4 disagreed.
Only 32 out of 237 respondents agreed with the statement: "There is no need to
encourage switching". 98 disagreed and 90 were neutral.
(vii) DSOs and network tariffs. The majority of the respondents consider that DSOs
should carry out tasks such as data management, balancing of the local grid,
including distributed generation and demand response, and connection of new
generation/capacity (e.g. solar panels). The majority of stakeholders thought these
activities should be carried out under good regulatory oversight, with sufficient
independence from supply activities, while a clear definition of the role of DSOs
(and TSOs), but also of the relationship with suppliers and consumers, is
required.
Regarding distribution network tariffs, 34% of the respondents consider that
European wide principles for setting distribution network tariffs are needed, while
another 34% is neutral and 26% disagree. Time-differentiated tariffs are
supported by ca 61% of the respondents, while the majority of stakeholders
consider that cost breakdown (78%) and methodology (84%) of distribution
network tariffs should be transparent.
The majority of stakeholders also consider that self-generators/auto-consumers
should contribute to the network costs even if they use the network in a limited
way. To this end, ca. 50% of the respondents consider that the further deployment
of self-generation with auto-consumption requires a common approach as far as
the contribution to network costs is concerned.
Regarding self- consumption, self- consumers should contribute to network costs
even if they use the network in a limited way and further deployment would
require a common approach. Moreover, however the responders think that to this
end a common approach with simplified related administrative procedures is
required. Granting of financial incentives by Member States to promote self-
generation and auto-consumption splits views evenly.
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Annex II: Stakeholder consultations
(viii) Demand response. Over 50% of the responders think that residential consumers
lack sufficient information to use energy efficiently and make use of advances in
innovation that have enabled a broad range of distributed generation and demand
response for industrial and commercial consumers. While the views are split in
respect to the ESCOs role to facilitate the favourable contractual arrangements
and other related services and as regards the access to respective choices of
energy efficiency services consumers have. Similarly, responders' views diverge
when assessing whether there should be done more to support the establishment
of ESCOs that are active in the field of energy efficiency. In particular, 44% of
the answers indicate that indeed there is more room to support ESCOs
establishment and 28% of the answers received point out that are satisfied with
the related service.
Moving on, the overwhelming majority industrial consumers are satisfied by their
access to demand response and balancing services while on the same question the
views coming from SMEs and commercial suppliers are split. Further, 24 of the
residential consumers have access to demand response and balancing services
while this percentage is 35% for the commercial sector and SMES and reached
the 66% for industrial customers. As to the entity of the demand response service
provider, over than 70% of the responders believe that this service should be
provided by the suppliers, though 50% thinks that aggregators are also fit to
provide the service while a minority would allocate this task to the DSOs.
Most responders view that they should be able to be participating in aggregation
programmes irrespective of their load size in primary balance markets. The best
way of making this happen is through aggregators and developing products taken
into account consumers flexibility characteristics and size. In addition,
responders' tend to agree that related demand response products should be hassle-
free, applicable to all consumers' profiles. People also disagree with the claim that
very specific data management tasks with regards to various distribution network
actors should be defined at European level.
Suppliers are perceived as having the most access to dynamic pricing and/or time
differentiated tariffs. They should first and aggregators, as a second choice, offer
demand response services and dynamic pricing to residential consumers, SMEs.
Unclear benefits, regulatory barriers and then unclear legal framework are
identified as the greatest barriers to limited dynamic pricing in a country. Some
respondents indicated that strengthening of infrastructure will allow greater retail
market competition
Responses agree that consumers should have a right to a smart meter installed at
their own request and at their expense also in regions without general rollout.
However, there is a slight tendency against having the choice of a smart meter
with functionalities of their own choice even if a different type is rolled out in
their area. In respect to smart appliances and energy management systems,
responders consider them as important to make the field of demand response
accessible to a broad range of consumers and that they can work as facilitators to
this end. The views also favour the display of consumption and consumption
patterns by the smart appliances and do not consider this as a detriment to the
consumers' comfort.
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Annex II: Stakeholder consultations
Public consultation on a new energy market design
A wide public consultation6
on a new energy market design (COM(2015)340 was
conducted from 15 July 2015 to 9 October 2015. It was open to EU and Member States'
authorities, energy market participants and their associations, SMEs, energy consumers,
NGOs, other relevant stakeholders and citizens. This public consultation aimed at
obtaining stakeholder's views on the issues that may need to be addressed in a redesign of
the European electricity market.
As regards representativeness and quality, the Commission received 320 replies to the
consultation. About 50 % of submissions come from national or EU-wide industry
associations. 26% of answers stem from undertakings active in the energy sector
(suppliers, intermediaries, customers), 9% from network operators. 17 national
governments and several national regulatory authorities submitted also a reply. A
significant number of individual citizens and academic institutes participated in the
consultation.
The first assessment of the submissions confirmed broad support of a number of key
ideas of the planned market design initiative, while views on other issues vary. The
following paragraphs provide a summary of the responses, also available on the
Commission's website7
.
(i) Electricity market adaptations. A large majority of stakeholders agreed that
scarcity pricing, i.e. price formation better reflecting actual demand and supply, is
an important element in the future market design. It is perceived, along with
current development of hedging products, as a way to enhance competitiveness.
While single answers point at risks of more volatile pricing and price peaks (e.g.
political acceptance, abuse of market power), others stress that those respective
risks can be avoided (e.g. by hedging against volatility). Regulated prices are
perceived as one of the most important obstacles to efficient scarcity pricing.
A large number of stakeholders agreed that scarcity pricing should not only relate
to time, but also to locational differences in scarcity (e.g. by meaningful price
zones or locational transmission pricing). While some stakeholders criticised the
current price zone practice for not reflecting actual scarcity and congestions
within bidding zones, leading to missing investment signals for generation, new
grid connections and to limitations of cross-border flows, others recalled the
complexity of prices zone changes and argued that large price zones would
increase liquidity.
Many submissions highlight the link between scarcity pricing and incentives for
investments/capacity remuneration mechanisms, as well as the crucial role of
scarcity pricing for kick-starting demand response at industrial and household
level.
6
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
7
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
256
Annex II: Stakeholder consultations
Most stakeholders agree with the need to speed up the development of integrated
short-term (balancing and intraday) markets. A significant number of
stakeholders argue that there is a need for legal measures, in addition to the
technical network codes under development, to speed up the development of
cross-border balancing markets, and provide for clear legal principles on non-
discriminatory participation in these markets.
Most stakeholders support the full integration of Renewable energy sources
(RES) into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price
periods. Many stakeholders note that the regulatory framework should enable
RES to participate in the market, e.g. by adapting gate closure times and aligning
product specifications. A number of respondents also underline the need to
support the development of aggregators by removing obstacles for their activity to
allow full market participation of renewables.
As concerns phasing out of public support schemes for RES, stakeholders take
different positions. While some argue for phasing out support schemes as soon as
possible, others argue that they will remain an important tool until technologies
have fully matured. They point at existing fossil fuel subsidies and the need to
continue subsidizing RES and maintaining other market corrections as long as
subsidies for traditional fuels and nuclear are not removed. Certain stakeholders
underline that support could progressively take more and more the form of
investment aid (as opposed to operating aid). A large majority of stakeholders is
in favour of some form of coordination of regional support schemes. The need for
an ETS reform to allow full market integration of RES was mentioned very often.
Most stakeholders agree that diversified charges and levies are a source of market
distortions.
(ii) Resource adequacy. A majority of answering stakeholders is in favour an
"energy-only" market, possibly augmented with a strategic reserve. Many
generators and some governments disagree and are in favour of capacity
remuneration mechanisms. Many stakeholders share the view that properly
designed energy markets would make capacity mechanisms redundant.
There is almost a consensus amongst stakeholders on the need for a more aligned
method for resource adequacy assessment. A majority of answering stakeholders
supports the idea that any legitimate claim to introduce capacity remuneration
mechanisms should be based on a common methodology. When it comes to the
geographical scope of the harmonized assessment, a vast majority stakeholders
call for regional or EU-wide adequacy assessment, while only a minority favour a
national approach. There is also support for the idea to align adequacy standards
across Member States. Stakeholders clearly support a common EU framework for
cross-border participation in capacity mechanisms.
(iii) Retail issues. Many stakeholders identified a lack of dynamic pricing (more
flexible consumer prices, reflecting the actual supply and demand of electricity)
as one of the main obstacles to kick-starting demand side response, along with the
distortion of retail prices by taxes/levies and price regulation. Other factors
include market rules that discriminate consumers or aggregators who want to
offer demand response, network tariff structures that are not adapted to demand
response and the slow roll-out of smart metering. Some stakeholders underline
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Annex II: Stakeholder consultations
that demand response should be purely market driven, where the potential is
greater for industrial customers than for residential customers. Many replies point
at specific regulatory barriers to demand response, primarily with regards to the
lack of a standardised and harmonised framework for demand response (e.g.
operation and settlement).
Regarding the role of DSOs, the respondents consider active system operation,
neutral market facilitation and data hub management as possible functions for
DSOs. Some stakeholders point at a potential conflict of interests for DSOs in
their new role in case they are also active in the supply business and emphasized
that the neutrality of DSOs should be ensured. A large number of the stakeholders
stressed the importance of data protection and privacy, and consumer's ownership
of data. Furthermore, a high number of respondents stressed the need of specific
rules regarding access to data. As concerns a European approach on distribution
tariffs, the views are mixed; the usefulness of some general principles is
acknowledged by many stakeholders, while others stress that the concrete design
should generally considered to be subject to national regulation.
(iv) Regulatory framework/electricity market governance. Stakeholders' opinions with
regard to strengthening ACER’s powers are divided. There is clear support for
increasing ACER's legal powers by many stakeholders (e.g. oversight of ENTSO-
E activities or decision powers for swifter alignment of NRA positions).
However, the option to keep the status quo is also visibly present, notably in the
submissions from Member States and national energy regulators. While some
stakeholders mentioned a need for making ACER'S decisions more independent
from national interests, others highlighted rather the need for appropriate financial
and human resources for ACER to fulfil its tasks.
Stakeholders' positions with regard to strengthening ENTSO-E remain divided.
Some stakeholders mention a possible conflict of interest in ENTSO-E’s role –
being at the same time an association called to represent the public interest,
involved e.g. in network code drafting, and a lobby organisation with own
commercial interests – and ask for measures to address this conflict. Some
stakeholders have suggested in this context that the process for developing
network codes should be revisited in order to provide a greater a balance of in
interests. Some submissions advocate for including DSOs and stakeholders in the
network code drafting process.
A majority of stakeholders support governance and regulatory oversight of power
exchanges, particularly in relation to their role in market capacity. Other
stakeholders are skeptical whether additional rules are needed given the existing
rules in legislation on market coupling (CACM Guideline).
Stakeholders mention also that the role of DSOs and their governance should be
clarified in an update to the 3rd
Package.
(v) Regionalisation of System Operation. As concerns the proposal to foster regional
cooperation of TSOs, a clear majority of stakeholders is in favour of closer
cooperation between TSOs. Stakeholders mentioned different functions which
could be better operated by TSOs in a regional set-up and called for less
fragmentation in some important of the work of TSOs. Around half of those who
want stronger TSO cooperation are also in favour of regional decision-making
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Annex II: Stakeholder consultations
responsibilities (e.g. for Regional Security Coordination Centres). Views were
split on whether national security of supply responsibility is an obstacle to cross-
border cooperation and whether regional responsibility would be an option.
Public consultation on risk preparedness in the area of security of electricity supply
A public consultation on risk preparedness in the area of security of electricity supply
was organized between July 15th and October 9th 2015. This public consultation aimed
at obtaining stakeholder's views in particular on how Member States should prepare
themselves and co-operate with others, with a view to identify and manage risks relating
to security of electricity supply.
The consulation resulted in 75 responses including public authorities (e.g. Ministries,
NRAs), international organizations (e.g. IEA), European bodies (ACER, ENTSO-E) and
most relevant stakeholders, including SMEs, industry and consumers associations,
companies and citizens. The following paragraphs provide a summary of the responses.
The responses themselves as well as a summary thereof are also available on the
Commission's website8
.
(i) Obligation to draw up risk preparedness plans. A large majority of respondents
(75 %) is in favour of requiring Member States to draw up risk preparedness
plans, covering results of risk assessments, preventive measures as well as
measures to be taken in crisis situations.
There is also a large support for having common templates, which should ensure
that a common approach is followed throughout Europe. Many respondents stress
the need for common definitions, common assessment methods, and common
rules on how to ensure security of supply.
In fact, most respondents acknowledge that in an increasingly interconnected
electricity market, characterised by an increasing amount of variable supply,
security of supply should be considered a matter of common concern (countries
are increasingly dependent on one another and measures taken in one country can
have a profound effect on what happens in neighbouring states and in electricity
markets in general). They also acknowledge that the current legal framework
(Directive 89/2005) does not offer the right framework for addressing this inter-
dependence. Therefore, they take the view that risk preparedness plans based on
common templates can help ensure that each Member State takes the measures
needed to ensure security of supply whilst co-operating with and taking account
of the needs of others. Stakeholders, in particular from the industry, also stress
that risk preparedness plans should help ensure more transparency and reduce the
scope for measures that unnecessarily distort markets.
Whilst acknowledging the need for a common approach, a significant number of
stakeholders also state that there should be sufficient room for tailor-made,
8
https://ec.europa.eu/energy/en/consultations/public-consultation-risk-preparedness-area-security-
electricity-supply
259
Annex II: Stakeholder consultations
national responses to security of supply concerns, as there are substantial
differences between national electricity systems.
Respondents further agree that plans should be drawn up on a regular basis,
proposals range from 2 to 5 years. The degree of transparency of the plans should
depend on its content and may vary in function of it (given the fact that plans
contain possibly sensitive information). Finally, respondents also warn against
creating new administrative burdens and on this basis argue that any obligation to
make risk preparedness plans should take account of already existing assessment
and reporting obligations.
The minority of stakeholders taking the view that there should be no new legal
obligation to draw up risk preparedness plans argue that such plans are already in
place at the national level, that national electricity systems are profoundly
different from one another and that priority should be given to the process of
adopting network codes and guidelines.
(ii) Content of risk preparedness plans / substantive requirements plans should
comply with. Many stakeholders take the view that it is too early at this stage to
decide on the exact content of risk preparedness plans. They stress the need for
more analysis, as well as in-depth discussions on the issue, in particular within
the Electricity Coordination Group. In spite of this general caveat, consultation
results already contain many useful pointers about substantive requirements plans
should comply with:
- Definition of risks. Various stakeholders stress the need to develop a common
definition of what security of supply means and the various risks that should
be covered. Risk preparedness plans should be comprehensive in nature,
covering generation adequacy and grid adequacy issues, as well as issues
related to more short-term security issues (such the risk of a sudden
unavailability of the grid or a power plant as a result of a terrorist attack);
- Cybersecurity. Respondents generally acknowledge the importance of
preventing risks related to cyber-attacks but there is at this stage, no
agreement on the need for further specific EU measures;
- Risk assessments and standards. Whilst the public consultation did not raise a
specific question on risk assessment methods and standards (since these
questions where covered by the market design consultation), various
stakeholders make the case for a common methodology for assessing risks, to
ensure a comparability of results, and a more common and transparent
approach to the standards that are used to assess risks and define an
acceptable level of reliability (this is also confirmed by replies to the market
design consultation). Various stakeholders also take the view that risk
preparedness plans should contain the results of various assessments made as
well as the indicators used to make the assessments;
- Preventive measures. Stakeholders in favour of risk preparedness plans agree
that such plans should identify both demand-side and supply-side measures
taken to prevent security of supply issues, in particular situations of scarcity.
They also agree on the need to assess the impact of existing and future
interconnections and to take account of the import capacity when designing
260
Annex II: Stakeholder consultations
preventive measures. Many stakeholders point in this context to the need to
ensure that markets function in an optimal way, thus allowing for flexibility in
demand and a mix of solutions to ensure that a sufficient level of supply is
guaranteed whilst keeping distortive measures at bay. Finally, stakeholders
also stress that any assessment of import capacity should take account of the
expected situation in neighbouring Member States;
- Dealing with emergency situations. A large majority of stakeholders agrees
that plans should identify actions (market and non-market based) to be taken
in emergency situations and rules on cooperation with other Member States.
A majority also believes that plans should include provisions on the
suspension of market activities, “protected customers” and cost compensation.
Additionally, some stakeholders suggest lists of specific content for the
emergency plans. As regards the development of new EU rules, many
stakeholders state that due account should be taken of the network code on
Emergency and Restoration, which is under preparation. Most say this draft
network code should be considered as the basis, whilst acknowledging a
possible need for additional common rules. A minority of stakeholders argues
that the network code on emergency and restoration should be considered
sufficient, leaving no need for additional EU-level rules, or consider that the
issues not covered by the network code should not be addressed at the EU
level;
- Definition/clarification of roles and responsibilities and what operational
procedures to be followed (e.g., who to contact in times of crisis)
(iii) Who should draw up risk preparedness plans, at what level, and with what kind of
'oversight'?
- Who should be responsible for drawing up risk preparedness plans? Whilst
most stakeholders recall that national governments have the ultimate
responsibility for ensuring security of supply, many stakeholders consider that
TSOs should take a lead role in drawing up risk preparedness plans. Most
however consider that TSOs need to co-operate however with national
ministries and/or national regulatory authorities, with the latter assuming a
monitoring or supervisory role. There is a large support for a stronger DSO
involvement in the preparation of the plans as well, as well as a clarification
of the responsibilities of DSOs in crisis situations. Whilst most stakeholders
see the added value of designating one 'competent authority' per Member
States, there is no agreement on who that competent authority should be (and
some argue that this choice should be left with the Member States).
- At what level should risk preparedness plans be drawn up? A large majority
of respondents take the view that plans should be made at national level;
however a large majority also stresses the need for more cross-border co-
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Annex II: Stakeholder consultations
operation, at least in a regional context. A significant group of respondents
argues that plans should be made at the regional level (for instance, as a
complement to cross-border co-operation by TSOs in the frame of the
regional security coordination initiatives) or call for plans at national and
regional levels (or even 'multi-level' plans).9
Those that argue in favour of
national plans highlight the fact that responsibilities (and liabilities) for
security of supply issues are national.10
There is no agreement on how to
'define' regions for planning / co-operation purposes; most stakeholders
suggest that synchronous areas and/or existing (voluntary) systems of regional
co-operation should be used as a starting point. Finally, whilst only a minority
calls for European plans, many see the need for some degree of co-ordination
/ alignment of plans in a European context (in particular via the development
of common rules and peer reviews leading to best practice).
- What oversight should there be? Most stakeholders are in favour of a system
of peer reviews, to be conducted either in a regional context, or in the frame
of the Electricity Coordination Group. The latter should in any event be
convened on a regular basis to serve as a forum for exchanging best practice.
Some stakeholders are also in favour of a stronger role for ACER/ENTSO-E,
in particular as regards more technical aspects of cross-border co-operation.
As regards the Commission, stakeholders mainly see a facilitating role, but
are often not in favour of a review system where the Commission takes
binding decisions.
Aspects of the present initiative were also part of the consultation on the preparation of a
new Renewable Energy Directive for the period after 202011
which was conducted from
18 November 2015 to 10 February 2016. It was open to EU and Member States'
authorities, energy market participants and their associations, SMEs, energy consumers,
NGOs, other relevant stakeholders and Citizens. The objective of this consultation was to
consult stakeholders and citizens on the new renewable energy directive (RED II) for the
period 2020-2030, foreseen before the end of 2016. The bioenergy sustainability policy,
which will form part as well of the new renewable energy package, will be covered by a
separate public consultation. The stakeholder responses to this consultation are descibed
in more detail in the RED II impact assessment. A summary of the responses is however
also available on the Commission's website12
.
Targeted consultations
A High Level Conference on electricity market design took place on 8 October 2015 in
Florence.
9
The rather cautious reaction to the idea of regional plans contrasts with the overwhelming support for
regional assessments of generation adequacy under the market design consultation.
10
A similar concern is reflected in the market design consultation results.
11
https://ec.europa.eu/energy/en/consultations/preparation-new-renewable-energy-directive-period-after-
2020
12
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
262
Annex II: Stakeholder consultations
The European Electricity Regulatory Forum convenes once or twice a year. The market
design initiative was discussed in this stakeholder forum at several occasions, notably the
Forum13
that took place on 4-5 June 2015, 9 October 2015, 3-4 March 2016 and 13-14
June 2016.
The consumer- and retail- related aspects of the market design initiative were also
discussed at the 8th Citizens' Energy Forum, which took place in London on 23 and 24
February 2016. The Commission established the London Forum to explore consumers'
perspective and role in a competitive, 'smart', energy-efficient and fair energy retail
market. It brings together representatives of consumer organisations, energy regulators,
energy ombudsmen, energy industries, and national energy ministries.
The Electricity Coordination Group provide a platform for strategic exchanges between
Member States, national regulators, ACER, ENTSOE and the Commission on electricity
policy. This group was used to discuss issues related to the present impact assessment on
16 November 2015 and 3 May 2016.
On demand response two specifc stakeholder workshops were organised by the
Commission: (i) Workshop on Status, Barriers and Incentives to Demand Response in
EU Member States, organised be the European Commission on 23 October 2015, and (ii)
Smart Grids Task Force, Expert Group 3 workshop on market design for demand
response and self-consumption, March 2, 2016; and Expert Group 3 workshop on smart
homes and buildings, April 26, 2016.
Member States' views
The support of Member States to the proposed initiatives is also apparent for instance
from:
- The "Council conclusions on implementation of the Energy Union" of June 2015.
In this regard, the conclusions state that: "While STRESSING the importance of
establishing a fully functioning and connected internal energy market that meets
the needs of consumers, REAFFIRMS the need to fully implement and enforce
existing EU legislation, including the Third Energy Package; the need to address
the lack of energy interconnections, which may contribute to higher energy
prices; the need for appropriate market price signals while improving
competition in the retail markets; the need to address energy poverty, paying due
attention to national specificities, and to assist consumers in vulnerable situations
while seeking appropriate combination of social, energy or consumer policy; the
need to inform and empower consumers with possibilities to participate actively
in the energy market and respond to price signals in order to drive competition,
to increase both supply-side and demand-side flexibility in the market, and to
enable consumers to control their energy consumption and to participate in cost-
13
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_WORKSHOP/Stakeholder%20Fora/Florenc
e_Fora
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Annex II: Stakeholder consultations
effective demand response solutions for example through smart grids and smart
metres."14
- The "Messages from the Presidency on electricity market design and regional
cooperation" of April 2016.15
In these messages, the Presidency acknowledges
the challenges facing the electricity markets in Europe and emphasizes, inter alia:
the need to strengthen the functioning of the internal energy market; that correct
price signals in all markets and for all actors are essential; that an integrated
European electricity market requires well-functioning short-term markets and an
adequate level of cross-border cooperation with regard to balancing markets; that
security of supply would benefit from a more coordinated and efficient approach;
that the future electricity retail markets should ensure access to new market
players and facilitate introduction of innovative technologies, products and
services.
Adherence to minimum Commission standards
The minimum Commission standards were all adhered to.
14
http://data.consilium.europa.eu/doc/document/ST-9073-2015-INIT/en/pdf
15
http://data.consilium.europa.eu/doc/document/ST-7879-2016-INIT/en/pdf
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Annex II: Stakeholder consultations
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Annex III: Who is affected by the initiative and how
Annex III: Who is affected by the initiative and how
The present initiative covers a large area of measures. The tables below provide an
overview of the parties affected, separately for each of the measures resulting from the
preferred policy options developed in the Annexes 1.1 through to 7.6.
Such matters are equally referred to in section 6 of the main text for the (more
aggregated) main policy options developed there.
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Annex III: Who is affected by the initiative and how
Table 1. Persons affected by measure for Problem Area I, Option 1(a) (level playing field)
Affected party Measure
1.1. Priority access and dispatch 1.2. Regulatory exemptions from balancing responsibility 1.3. RES E access to provision of non-frequency
ancillary services
Member States Need to change national legislation in so far as it contains priority dispatch; need to
include provisions on transparency and compensation of curtailment and redispatch
Need to change national legislation in so far as it contains
exemptions from balancing responsibility
They need to adapt national legislation to create
conditions for non-discriminatory procurement of non-
frequency ancillary services.
National
regulatory
authorities
(NRAs)
Need to oversee implementation of provisions, notably determination which generators
continue to benefit from priority rules, and ensure correct curtailment compensation.
Need to oversee implementation of provisions, notably oversight of
TSOs.
They need to oversee implementation and monitoring
of provisions, notably oversight of TSOs.
Transmission
System
Operators
(TSOs)
Reduction of priority dispatch and priority access facilitates grid operation and lowers
dispatch costs. Introduction of clear compensation rules on the other hand can increase
redispatch costs where such compensation is currently insufficient.
Implementation of balancing rules, notably settlement of parties in
imbalance.
They need to change the way non-frequency ancillary
services are contracted, procured and possibly
remunerated.
Distribution
System
Operators
(DSOs)
Where DSOs curtail generation to resolve local grid constraints, they are affected
identically to TSOs.
No direct impact, as balancing is the role of TSOs; indirectly,
increased balancing responsibility of generators increases system
transparency also to the benefit of DSOs.
DSOs very likely would also be affected, because most
RES are connected at distribution level and the DSO's
role in managing their network would have to change
in order to allow RES assets to participate to the
provision of ancillary services.
Generators Generators currently subject to priority rules will be exposed to increased curtailment
risks and lower likelihood of dispatch (for high marginal cost generators; likelihood of
dispatch actually increases for low marginal cost generators) unless they continue to
benefit from the exemptions. Generators not subject to exemptions will be less likely to
be curtailed and more likely to be dispatched where they are the most efficient
generator available. All generators will benefit from increased transparency and legal
certainty on redispatch and curtailment compensation.
Balancing responsible parties, including suppliers, traders and
generators currently subject to balancing responsibility are not
directly impacted. Generators currently exempted or partly shielded
from balancing responsibility will have to increase their efforts to
remain in balance (e.g. through better use of weather forecasts) or
will be exposed to financial risks.
Owners of generation assets (RES and not) would be
affected by changes in the rules of how non-frequency
ancillary services are procured. More transparent and
competitive procurement rules could enable market
entrance by new actors and technologies, such as
battery storage.
Suppliers Suppliers are not directly affected. Balancing responsible parties, including suppliers, traders and
generators currently subject to balancing responsibility are not
directly impacted.
Most likely not affected.
Power exchanges Power exchanges could benefit from the increased market liquidity particularly for
short-term products which results from market-based curtailment and redispatch.
Power exchanges could benefit from the increased market liquidity
particularly for short-term products which results from balancing
responsibility of RES E.
Most likely not affected.
Aggregators Aggregators are likely to benefit in particular by offering market-based resources to be
used by TSOs in redispatch or curtailment.
Aggregators are likely to benefit in particular by offering to small
generators services to fulfil their balancing responsibility.
Aggregators are likely to benefit from a more level
playing field and get access to additional remuneration
streams.
End consumers End consumers are not directly affected. End consumers are not directly affected. End consumers are not directly affected.
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Annex III: Who is affected by the initiative and how
Table 2. Persons affected by measure for problem Area I, Option 1(b) (Strengthening short-term markets)
Affected party Measure
2.1. Reserves sizing and procurement 2.2. Removing distortions for liquid short-term markets 2.3. Improving the coordination of Transmission System Operation
Member States Member State authorities define the country's overall
policy regarding energy mix and power grid investments.
Member States authorities generally play a limited direct role in the
operation of intraday markets. They will, however be impacted if they
are responsible for implementing/enforcing requirements.
Member States authorities will be impacted if they are responsible for
implementing/enforcing/monitoring the requirements. This topic is likely to have
a particularly political angle, as Member States may not be willing to entrust
ROCs with decision-making powers under the assumption that security of supply
is a national responsibility (although based on the TFEU, it constitutes a shared
responsibility between the EU and MS).
National
regulatory
authorities
(NRAs)
NRAs approve the methodology for sizing and
procurement of balancing reserves. They are also
responsible for any impact on TSOs' tariffs and how cross-
border infrastructure is allocated.
NRAs are responsible for regulatory oversight of intraday markets,
including as part of the implementation of the CACM Guideline,
where they are responsible for approving a number of methodology
developed by TSOs and power exchanges. They will, therefore, be
affected by changes in so far as it could alter the basis for their
regulatory decisions. However, the direct impact on NRAs is
anticipated to be relatively limited.
NRAs of each of the regions where a ROC is established would be required to
carry out the regional oversight of the concerned ROC. This would include
competences at least equivalent to those established for NRAs in the Third
Energy Package.
It may be necessary to entrust ACER with the EU-wide oversight of ROCs. It
would be necessary to set out a framework for the interaction between the
regional groupings of NRAs and ACER.
Transmission
System
Operators
(TSOs)
TSOs analyse system's state and propose the methodology
for sizing and procurement of balancing reserves in their
control areas.
Shifting responsibilities for sizing and procurement of
balancing reserves at regional level implies a need for
strong governance at regional level.
Existing physical constraints would still need to be taken
into account in the regional procurement platform.
Major impacts are expected on the current design of
system operation procedures and responsibilities. Cost
allocation and remuneration would have to be agreed,
requiring the development of a clear and robust framework
of responsibilities between national and regional TSOs.
TSOs are heavily involved in the operation of intraday markets,
notably in determining the cross-border capacity made available to the
market, and in using the results for operation of the system. They are
therefore likely to be significantly impacted by any changes.
National TSOs would be complemented by ROCs performing functions of
regional relevance, whilst real time operation functions would be left solely in the
hands of national TSOs.
ROCs could potentially be entrusted with certain decision making responsibilities
for a limited number of operational functions, whilst TSOs would retain their
responsibility as regards all other functions for which they are currently
responsible at national level. It may be necessary to entrust additional tasks to
ENTSO-E related to the cooperation and coordination between ROCs.
Generators Generators, as Balancing Service Providers, would have
additional opportunity to participate in the balancing
market even though significant operational impact might
increase due to the procurement frequency. Such
framework would, however, allow the participation of
renewable energy sources in the balancing market
potentially leading to a sharp decrease of balancing
reserve cost.
Generators will be affected by any changes in wholesale prices they
receive for their energy on the intraday market. More efficient price
signals, and more potential for trading, will open up the market to
smaller generators, particularly renewable.
Generators could benefit from a more secure power system and a more efficient
market leading to increased market opportunities.
Aggregators Smaller products and time units will give aggregators
more access to intraday markets.
Increased price fluctuations will give aggregators more opportunities
to operate, thereby helping to ensure that demand meets supply at any
point in time.
Limited impact on aggregators.
Suppliers Regional procurement of reserves would lead to regional
settlement of imbalances; therefore allowing for increase
competition of suppliers across borders.
Suppliers will be affected insofar as they are the ones who buy power
on the wholesale market. Any changes in intraday clearing prices will
change how much they pay for their power, the extent to which will
depend on how much trading they do in the intraday market.
Limited impact on suppliers.
Power
exchanges
In case an optimisation process for the allocation of
transmission capacity between energy and balancing
markets has to developed, day-ahead market coupling
algorithm currently operates by power exchanges might be
Power exchanges will be the most affected by any changes to intraday
arrangements, as they are the ones who operate the platforms on which
energy is traded in the intraday timeframe. They will therefore have to
adapt systems and process to meet new requirements.
Limited impact on power exchanges. It is expected that they could benefit power
exchanges as the optimisation of market-related functions such as capacity
calculation would entail more liquidity in the markets that could be exchanged.
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Annex III: Who is affected by the initiative and how
Affected party Measure
2.1. Reserves sizing and procurement 2.2. Removing distortions for liquid short-term markets 2.3. Improving the coordination of Transmission System Operation
impacted and solution will have to be found on sharing
transmission capacity in an optimal way for the markets
preceding the balancing market.
End consumers End consumers will be able to participate in balancing
markets via demand response aggregators allowing for
stronger supplier's competition at regional level.
End consumers will be affected insofar as changes to the wholesale
price are passed on to them in their retail price.
Regional TSO cooperation through the creation of ROCs would benefit
consumers through improved security of supply (by minimising the risk of wide
area events such as brownouts and blackouts), and lowering costs through
increased efficiency in system operation and maximised availability of
transmission capacity to market participants.
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Annex III: Who is affected by the initiative and how
Table 3. Persons affected by measure for Problem Area I, Option 1(c) (Pulling demand response and distributed resourced into the market)
Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
Member States Those 17 Member States that roll out smart meters
will not be affected by the new provisions on smart
meters, apart from the obligation to comply with the
recommended functionalities, which may need to
transpose into national legislation. Similarly for
those two Member States that opted for partial roll-
out and are not expected to face any other additional
burden from allowing additional consumers to
request smart meters.
However, those 9 Member States that currently do
not plan to install any smart meters will need to
establish legislation with technical and functional
requirements for the roll-out and face some
additional administrative impact by re-evaluating
their cost-benefit analyses.
What concerns market rules for demand response,
Member States are already obliged through the EED
to enable demand response. The new provisions will
rather provide additional guidance for Member
States on how to create the enabling framework
instead of imposing additional burden to them.
The competent ministries in each Member State who
will be involved in the transposition of the relevant
EU legislation and monitor the implementation and
effectiveness of the measures under the preferred
option.
The competent ministries in each Member State who
will be involved in the transposition of the relevant
EU legislation and monitor the implementation and
effectiveness of the measures under the preferred
option.
MS authorities will be in charge of national
implementation of the revised Third Package.
National
regulatory
authorities
(NRAs)
Additional administrative impact may be created for
the NRAs for enforcing actions regarding the
consumer entitlement to request a fully functional
smart meter. This includes assessing the costs to be
borne by the consumer, and overseeing the process
of deployment. At the same time, improved
consumer engagement thanks to smart metering,
would make it easier for NRAs to ensure proper
functioning of the national (retail) energy markets.
Already under the existing legislation NRAs are
obliged to encourage demand side resources to
participate alongside supply in markets. The new
provisions under the preferred option only further
specify which aspects have to be addressed by
NRAs but they do not create additional burden for
them.
As DSOs are regulated entities is expected that NRAs
will have the main role of ensuring the effective
application of measures. NRAs will be mostly
involved in the application of the measures and in
designing the necessary rules for the practical
implementation. As the measures under the preferred
option are closely linked to a suitable remuneration
methodology, NRAs will also probably have to
modify existing schemes. This will require the
availability of the necessary human, technical and
financial resources.
According to the Electricity Directive NRAs have the
main role in fixing or approving network tariffs or
their methodologies. The overall aim is to move
towards more sophisticated network tariff
methodologies. To this end, some NRAs might have
to modify the existing methodologies for distribution
tariffs. The introduction of smarter regulatory
frameworks will require the availability of the
necessary human, technical and financial resources.
Their role, powers and responsibilities will be
further clarified, especially as regards issues
which are relevant at regional/EU level. This
will affect the way NRAs have cooperated at
regional and EU-level, including within
ACER, in order to enhance the collaboration
between NRAs and ACER.
In the context of clarifying the respective roles
of NRAs and ACER, some of the powers and
responsibilities currently conferred to NRAs
may be shifted to ACER.
Agency for the
cooperation of
energy
regulators
(ACER)
Apart from the minor changes necessary to ensure
effective market monitoring in the changed market
context, ACER will not be affected by changes in
unlocking demand side response..
ACER will be affected to the extent which will be
called to oversight the activities of EU DSO entity
and its involvement in relevant network codes or
guidelines.
ACER will be affected to the extent which will be
called to oversight the activities of EU DSO entity
and its involvement in network codes or guidelines
on network tariffs.
Its role, powers and responsibilities will be
further enhanced in order to ensure that ACER
can continue fulfilling its role of supporting
NRAs in exercising their functions at EU level
and to coordinate their actions where
necessary. For a number of specific and
defined instances, some of the powers and
responsibilities of NRAs will be shifted to
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Annex III: Who is affected by the initiative and how
Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
ACER, to ensure that it can carry out an EU-
level oversight.
ACER's role will be affected by the changes
envisaged for the process of development of
Commission implementing regulations in the
form of network codes and guidelines.
Transmission
System
Operators
(TSOs)
A greater roll-out of smart meters allows TSOs to
better calculate settlements and balancing penalties
as the consumption figures can be based on real
consumption data and not only on profiles.
TSOs are affected by opening markets for
aggregated loads and demand response. Those
effects are dealt with in the Impact Assessment on
markets. TSOs are not directly affected by the
proposed measures on removing market barriers for
independent aggregators. However, they are
indirectly affected: A greater participation of
flexibility products in ancillary service markets (e.g.
balancing markets) can help TSOs cost-effectively
manage the network.
TSOs will be involved as more coordination with
DSOs will be required. TSOs will have to allocate the
necessary human and technical resources in order to
achieve such coordination.
TSOs will not be affected by changes in distribution
tariffs.
Some of the transparency obligations imposed
on ENTSO-E as well as some of the
governance rules applying to this association
will indirectly affect TSOs.
Some of the proposed rules (e.g. co-financing
of ACER by contributions from market
participants) might directly impact on TSOs.
European
network of
transmission
system operators
(ENTSOs)
ENTSO-E will not be affected by changes in
unlocking demand response.
ENTSO-E will have to cooperate with the EU DSO
entity on issues which are relevant to both
transmission and distribution networks.
ENTSO-E will not be affected by changes in
distribution tariffs.
ENTSO-E's mandate will be mainly clarified,
whilst ensuring that its added value of
providing technical expertise is preserved.
Transparency of ENTSO-E will be further
improved.
The role of ENTSO-E will be affected by the
changes envisaged for the process of
development of Commission implementing
regulations in the form of network codes and
guidelines.
Distribution
System
Operators
(DSOs)
In most Member States, DSOs are responsible for
organising the installation of smart meters. The
additional costs to be determined by the NRAs can
however be charged to the users.
DSOs also benefit from access to real time data
coming from smart metering. It supports them in
their work on monitoring and controlling the
network, improving its reliability and power quality,
and its overall effectiveness, particularly in the
presence of distributed generation. This ultimately
contributes to the increased distribution network
efficiency and increased revenue for the DSOs (e.g.
via reduced technical and commercial losses)
DSOs are not directly affected by the proposed
measures on removing market barriers for
independent aggregators. However, DSOs can
DSOs will be directly affected by the possible
measures under the preferred option as they will have
to have in place the necessary human and technical
resources in order to implement the envisaged
measures. Additional personnel or infrastructure
might be necessary. However, DSOs will use
flexibility solutions in order to increase efficiencies,
only where benefits will outweigh additional costs.
It is expected that the envisaged measures under the
preferred option will positively affect DSOs as they
aim to a more efficient utilisation of the distribution
system and the incentivisation of DSOs towards more
optimal development and operation of their grids.
More advanced tariff schemes may require the
availability and monitoring of detailed data (financial
and technical) and the achievement of specific
targets. Any additional administrative costs should be
offset by the expected benefits.
DSOs will be able to participate more actively
as a result of the changes envisaged for the
process of development of Commission
implementing regulations in the form of
network codes and guidelines.
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Annex III: Who is affected by the initiative and how
Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
indirectly benefit from a better uptake of demand
response as the reduction in peaks it will reduce the
need to invest in distribution networks.
Generators Demand response is designed to reduce peak
demand and thereby effectively replace marginal
power plants and reduce electricity prices at the
wholesale market. As such generators are likely to
face reduced turnover from lower peak prices and
from operating reserve capacities.
Generators are not likely to be effected by an
accelerated smart meter roll out.
Generators will not be affected by the measures under
the preferred option.
The envisaged measures aim to the overall reduction
of network costs through the incentivisation of DSOs
to raise efficiencies, which will have an overall
positive impact to system users. The envisaged
measures also aim to a fair allocation of costs among
different system users. Therefore, to the extent to
which the envisaged measures will incite changes in
existing tariffs, generators or other system users
may be affected from any new tariffs which will
result to reallocation of costs.
Generators will be able to participate more
actively as a result of the changes envisaged
for the process of development of Commission
implementing regulations in the form of
network codes and guidelines.
Suppliers Smart meters can have a direct impact on suppliers,
as they enable consumers to easily switch.
Furthermore, there is one Member State where
suppliers are responsible for the roll-out. Moreover,
smart metering allows suppliers to offer dynamic
pricing contracts that reduce suppliers' risk of
changing wholesale prices.
The effect of demand response on suppliers can be
positive as suppliers will benefit from lower
wholesale prices. On the other hand demand
response will make it more difficult for suppliers to
calculate retail prices. Also as balancing responsible
parties they may face higher penalty payments for
imbalances incurred due to their customers changing
consumption patterns. Finally, new competition
from aggregators may reduce their income.
However, suppliers can also offer demand response
services to their customers and expand their range of
services and thereby turnover.
The overall financial impact of smart meters and of
more competition through demand response on
suppliers will hence depend on the ability of the
individual supplier to adapt to the new market with
innovative services and competitive pricing offers.
Suppliers will not be affected as the envisaged
measures will not affect their normal business.
It is not expected that the envisaged measures will
affect the suppliers.
Suppliers will be able to participate more
actively as a result of the changes envisaged
for the process of development of Commission
implementing regulations in the form of
network codes and guidelines.
Power exchanges No impact expected No impact expected No impact expected Power exchanges will be subject to an
enhanced regulatory oversight at EU level
exercised by ACER and NRAs.
Power exchanges will be able to participate
more actively as a result of the changes
envisaged for the process of development of
Commission implementing regulations in the
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Annex III: Who is affected by the initiative and how
Affected party Measure
3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO
remuneration
3.4. Improving the institutional framework
form of network codes and guidelines.
Aggregators (and
other new
market entrants)
Aggregators are likely to benefit from an accelerated
roll out of smart meters as this technology facilitates
market access for demand service providers and
aggregators. Equally all measures aimed at removing
market barriers and increasing competition in the
retail market will immediately facilitate market
access for aggregators and new energy service
providers and hence opens new business
opportunities for them.
Aggregators will be positively affected as DSOs will
request their services in order to use flexibility for
managing congestion in their networks.
Insofar as distribution tariffs incentivise grid users to
use the network more efficiently, aggregators will not
be called upon as much to help to manage network
congestion..
Aggregators and other new market entrants
will be able to participate more actively as a
result of the changes envisaged for the process
of development of Commission implementing
regulations in the form of network codes and
guidelines
End consumers End consumers will get the right to request smart
meters and have access to dynamic electricity
pricing contracts which clearly gives puts them in a
position to become active market participants.
Furthermore, provision of accurate and reliable data
flows due to smart metering would enable easier and
quicker switch between suppliers, access to choices,
smart home solutions and innovative automation
services, and can also lead to energy savings.
Consumers will equally benefit from more
competition, wider choice, and the possibility to
actively engage in price based and incentive based
demand response and hence from reduced energy
bills. But also those consumers who do not engage
themselves in demand response can profit from
lower wholesale prices as a result of demand
response if those price reductions are being passed
on to consumers.
Use of flexibility from DSOs will result to lower
network costs. This reduction will be reflected in
distribution tariffs and the final electricity bill of the
consumer.
The envisaged measures aim to the overall reduction
of network costs through the incentivisation of DSOs
to raise efficiencies, which will have an overall
positive impact to system users. The measures also
aim to a fair allocation of costs among different
system users. Therefore, to the extent to which the
envisaged measures will incite changes in existing
tariffs, consumers or other system users may be
affected from any new tariffs which will result to
reallocation of costs.
Consumers will be able to benefit from
enhanced transparency and in general from
well-functioning energy markets.
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Annex III: Who is affected by the initiative and how
Table 4. Persons affected by measure Problem Area II, Option 1 (Improved energy market without CMs)
Affected party Measure
4.1. Removing price caps 4.2. Improving locational price signals 4.3. Minimise investment and dispatch
distortions due to transmission tariff
structures
4.4. Congestion income spending to increase cross-
border capacity
Member States Member States authorities will be impacted if they
are responsible for
implementing/enforcing/monitoring the
requirements.
Member States authorities will be impacted if they are
responsible for implementing/enforcing/monitoring the
requirements. This topic is likely to have a particularly
political angle, as splitting price zones within a Member
State will result in different wholesale electricity in that
Member State depending on location (although not
necessarily retail prices).
Member States authorities will be impacted if
they are responsible for
implementing/enforcing/monitoring the
requirements.
Member States authorities will be impacted if they are
responsible for implementing/enforcing/monitoring the
requirements.
National
regulatory
authorities
(NRAs)
NRAs will be impacted if they are responsible for
implementing/enforcing/monitoring the
requirements.
Member States authorities will be impacted if they are
responsible for implementing/enforcing/monitoring the
requirements.
NRAs play a significant role in monitoring,
authorising, etc. tariffs and connection
charges. Any change would impact on how
they do this.
NRAs are currently responsible for reviewing the use
of congestion income, and for authorising it to be spent
on the reduction of tariffs. They will be affected by
Option 2 and 3 as they no longer need to authorise it to
be spent on the reduction of tariffs. Option 1 could
require them to make a more them to make a more
thorough assessment.
ACER will be affected by changes to monitoring and
transparency requirements and the requirement on
them to develop harmonised rules.
Transmission
System
Operators
(TSOs)
There will be limited impact on TSOs. TSOs will be affected as it will likely mean they hold
and operate networks over more than one price zone. It
will also change those transmission lines that
accumulate revenue from congestion.
Changes would have limited impact on TSOs
themselves, as proposals are not generally
looking at how TSOs are remunerated, but
rather how the money is collected.
It will change how transmission system operators are
able to use congestion income. Options 1-3 could lead
to more investment activity of the TSO.
Generators Increased price variability will impact the revenue
generators will see from the energy market – they
will likely see higher prices for short periods of
time, which will incentivise flexible generation.
Different price zones will change the prices that
generators receive depending on their location.
Changes would most affect generators –
lower connection charges or tariffs (where
they are applied to generators) would have a
positive impact on their revenues.
If Option 1, 2 and 3 lead to more investment in
networks, this would impact generators by delivering
more cross-border competition and present further
trading opportunities to sell energy by an increases in
the liquidity of cross-border markets.
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Annex III: Who is affected by the initiative and how
Affected party Measure
4.1. Removing price caps 4.2. Improving locational price signals 4.3. Minimise investment and dispatch
distortions due to transmission tariff
structures
4.4. Congestion income spending to increase cross-
border capacity
Suppliers Increased price variability will impact the price
paid by suppliers - – they will likely see higher
prices for short periods of time.
Different price zones will change the prices that
suppliers pay depending on their location.
Limited impact on suppliers. If Option 1, 2 and 3 lead to more investment in
networks, this would impact generators by delivering
more cross-border competition and present further
trading opportunities to buy energy by an increase in
the liquidity of cross-border markets.
Power
exchanges
Power exchanges will be required to implement the
requirements, which could require changes to
systems and practices.
Different price zone will change the practices of power
exchanges – currently they operate based on MS-level
markets (in general) – they would need to differential
markets based on different price boundaries.
Limited impact on power exchanges. If Option 1, 2 and 3 lead to more investment in
networks, this would impact power exchanges if it
leads to greater cross-border trade on their platforms.
End
consumers
End consumers will be affected insofar as changes
to the wholesale price are passed on to them in their
retail price. However, more variable prices will not
necessarily be felt by end-consumers as they may
be hedged (particularly household) against this
volatility in their retail contracts.
Different price zones could affect end-consumers
depending on their location. However, possibilities exist
to retail MS-level retail prices,
End consumers could be affected if more
tariffs were charged on load, as opposed to
production. However, overall the impact is
likely to be similar as the overall cost basis
would not changing.
End consumers may be affected by any reduction in the
amount that can be offset against tariffs. However, this
may be outweighed by the positive effect of more
cross-border capacity being available, and the benefit
this has on competition and energy prices.
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Annex III: Who is affected by the initiative and how
Table 5. Persons affected by measures of Problem Area II, Option 2 (Improved energy market, CMs based on an EU-wide adequacy assessment) and
Option 3 (Improved energy market, CMs based on an EU-wide adequacy assessment, plus cross-border participation
Affected party Measure
5.1. Improved generation adequacy methodology 5.2. Cross-border operation of capacity mechanisms
Member States Member States would be better informed about the likely development of security of supply indicators
and would have to exclusively rely on the EU-wide generation adequacy assessment carried out by
ENTSO-E when arguing for CMs.
Each Member State would not need to design a separate individual solution – and this would potentially
reduce the need for bilateral negotiations between TSOs.
National regulatory
authorities (NRAs)
NRAs/ ACER would be required to approve the methodology used by ENTSO-E for the generation
adequacy methodology and potentially endorse the assessment.
NRAs/ ACER would be required to set the obligations and penalties for non-availability for both
participating generation/ demand resources and cross-border transmission infrastructure.
Transmission System
Operators (TSOs)
TSOs would be obliged to provide national raw data to ENTSO-E which will be used in the EU-wide
generation adequacy assessment.
ENTSO-E would be required to establish an appropriate methodology for calculating suitable capacity
values up to which cross-border participation would be possible.
Based on the ENTSO-E methodology, TSOs would be required to calculate the capacity values for each
of their borders. They might potentially be penalized for non-availability of transmission infrastructure.
TSOs would be required to check effective availability of participating resources.
ENTSO-E may also be required to establish common rules for crediting foreign capacity resources for
the purpose of participation in CMs reflecting the likely availability of resources in each country/zone.
Generators ENTSO-E would also have to provide for an updated methodology with probabilistic calculations,
appropriate coverage of interdependencies, availability of RES and demand side flexibility and
availability of cross-border infrastructure.
Foreign capacity providers would participate directly into a national capacity auction, with availability
rather than delivery obligations imposed on the foreign capacity providers and the cross-border
infrastructure.
Foreign capacity providers/ interconnectors would be remunerated for the security of supply benefits
that they deliver to the CM zone and would receive penalties for non-availability.
Suppliers ENTSO-E would be required to carry out an EU-wide or regional system adequacy assessment based
on national raw data provided by TSOs (as opposed to a compilation of national assessments).
Limited impact on suppliers
Aggregators With the updated methodology provided by ENTSO-E, intermittent RES generators/ demand-side
flexibility would be less likely to be excluded from contributing to generation adequacy.
Just like generators they shall be able to participate in cross-border CMs.
Power exchanges Limited impact on suppliers Limited impact on power exchanges
End consumers Limited impact on aggregators Explicit cross-border participation in CMs would preserve the properties of market coupling and ensure
that the distortions of uncoordinated national mechanisms are corrected and the internal market is able
to deliver the benefits to consumers.
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Annex III: Who is affected by the initiative and how
Table 6. Persons affected by measures for Problem Area III
Affected party Measure
Member States Member States (i.e. responsible ministries) would bear the main responsibility of preparing Risk Preparedness Plans and coordinating relevant parts with other
Member States from their region, including ex-ante agreements on assistance during (simultaneous) crisis and financial compensation.
Member States would designate a ministry or the NRA as 'competent authority' as responsible body for preparing the Risk Preparedness Plan and for cross-border
coordination in crisis.
As members of an empowered Electricity Coordination Group they would consult and coordinate Plans.
The above described responsibilities might involve an increased administrative impact. However, most of the tasks are already carried out in a purely national
context and there might also be benefits from exploiting synergies of improved cooperation. In addition, existing national reporting obligations would be reduced
(e.g. repealing the obligation of Article 4 of Electricity Directive "Monitoring security of supply").
National regulatory
authorities (NRAs)
NRAs could possibly fulfil certain tasks as part of the Risk Preparedness Plan of their Member State.
Furthermore they might be appointed as 'competent authority' by Member States. In this case, they would be responsible for preparing the Risk Preparedness Plan
and for cross-border coordination during crisis, possibly requiring additional resources.
Transmission System
Operators (TSOs)
ENTSO-E would be responsible for identification of crisis scenarios and risk assessment in a regional context. A common methodology for short-term assessments
(ENTSO-E Seasonal Outlooks and the week-ahead assessments of the RSCs) should be developed by ENTSO-E.
This might require additional resources within ENTSO-E and within the RSCs, in case that ENTSO-E delegates all or part of these tasks to them. However,
additional costs would be limited as some of these tasks are already carried out today. Giving these bodies a clear mandate, it would however significantly improve
cross-border coordination.
Generators Generation companies and other market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from
clearer rules on crisis management and the prevention of unjustified market intervention.
Suppliers Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis
management and the prevention of unjustified market intervention.
Aggregators Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis
management and the prevention of unjustified market intervention.
Power exchanges Market operators would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management
and the prevention of unjustified market intervention.
End consumers As described above the impacts of blackouts on industry and society proved to be severe. Consequently, end consumers benefit extensively from improved risk
preparedness as it would help to prevent future blackouts more effectively.
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Annex III: Who is affected by the initiative and how
Table 7.a Persons affected by measure for Problem Area IV
Affected party Measure
7.1. Monitoring energy poverty 7.2. Options for phasing out regulated prices 7.3. Creating a level playing field for access to data
Member States Option 1 leads to an improved framework to measure energy poverty.
Member States will have a better understanding of energy poverty as a
result of a clearer conceptual framework (through the common
understanding of energy poverty) and better information on the level of
energy poverty (measuring energy poverty). Ultimately, this will contribute
to better identification and targeted public policies to alleviate energy
poverty.
Those Member States still practicing some form of price regulation will
have to make the necessary legislative and market changes in order to
ensure a smooth and effective phase out.
The competent ministries and authorities who will be
involved in the transposition of the relevant EU legislation
and will monitor the implementation and effectiveness of
the measures under the preferred option.
National regulatory
authorities (NRAs)
NRAs will need to monitor and report to the European Commission and
ACER the number of disconnections. According to ACER Market
Monitoring Report, only 16 Member States met this requirement.
In most countries with price regulation, NRAs are the bodies
responsible for setting the level of regulated prices for a defined
regulatory period. In few cases NRAs are only giving their opinion on
regulated prices set by the government. Phasing-out regulated prices
would remove these responsibilities of the NRAs therefore reducing
administrative costs and resource needs. However new tasks for the
NRAs might be defined by Member States in the follow-up of the price
deregulation process such as monitoring the level of market prices with
the possibility to intervene ex post in the price setting in case of market
abuse. The costs of carrying out such new tasks are likely to be less
important than the costs of setting regulated prices, resulting overall in
reduces resource needs for the NRAs.
The envisaged measures will partly affect the NRAs as most
probably will have a role in the implementation of the
measures at national level. Other authorities such as data
protection authorities may be involved in the
implementation of the envisaged measures at national level.
NRAs will have to monitor the data handling procedures as
part of the retail market functioning. The involvement of
NRAs is expected to be higher in Member States where
smart metering systems are deployed.
Transmission
System Operators
(TSOs)
The preferred option would not directly affect TSOs. The preferred option would not directly affect TSOs. TSOs might be affected in terms of costs in cases where
Member States will decide that they are responsible for the
operation of the data-hub. However, the envisaged measures
do not impose an obligation to Member States regarding the
data management model and the party responsible for acting
as a data-hub. The measures under the preferred option will
benefit TSOs and other operators as the will allow them,
under specific terms, to have access to aggregated
information which will be useful for network planning and
operation.
Distribution System
Operators (DSOs)
The preferred option would not directly affect DSOs. The preferred option would not directly affect DSOs. In the large majority of Member States DSOs will be
involved directly in the data handling process. DSOs will
have the same benefits as TSOs in terms of system
operation and planning. Under the preferred option DSOs
which are not fully unbundled (DSOs below the 100.000
threshold) will have to implement measures which link to
the non-discriminatory treatment of information. The
implementation of such measures will most probably create
costs which will vary depending on the national framework.
It is not expected however that these costs will create a high
burden, as they can implemented through automated IT
systems.
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Annex III: Who is affected by the initiative and how
Affected party Measure
7.1. Monitoring energy poverty 7.2. Options for phasing out regulated prices 7.3. Creating a level playing field for access to data
Generators The preferred option would not directly affect generators. In countries where artificially low regulated end-user prices are backed
up by generation deliveries at non cost-reflective level agreed by long-
term contracts, deregulation of end user prices could trigger a
rethinking of such system by a renegotiation of long-term contracts
which would stimulate investment in efficient generation capacities
with positive effects on the competition on the generation market.
Generators will not be affected under the preferred option.
Suppliers The preferred option would not directly affect suppliers.
However, should the improved monitoring of energy poverty lead to
increased action to tackle the problem by Member States, then the costs of
these measures may be borne by suppliers. Depending on each Member
States, these costs may then be recovered as network charges, passed on to
consumers or taken against energy providers overall benefits.
Preventative measures, such as debt management or providing additional
information on where to find support, represent an additional cost to
energy retailers in those Member States where these measures are not yet
in place. A moratorium of disconnection will reduce energy retailers'
revenue as energy will be supplied free of charge. However, such costs will
to some extent be mitigated by lower numbers of bad debtors in the long
run.
Alternative (non-regulated) suppliers would benefit from the
deregulation of prices by increased possibilities to compete on the price
and therefore to gain more market share. This is particularly true for
countries where regulated prices set at non cost-reflective levels
prevent alternative suppliers from contesting the regulated offer. For
the regulated suppliers (usually former incumbents) the removal of
price regulation would lead to increased operational costs related to the
implementation of the transition from the regulated offer to market
based offer for its customer base. Moreover, regulated suppliers are
likely to lose significant market shares if customers will switch to
competitive offers of alternative suppliers.
The availability of consumption data under non-
discriminatory terms and interoperability of data formats
will have positive effects on suppliers and other retailers.
The aim of the measures under the preferred option is to
bring down the administrative costs for the various retail
service providers including suppliers.
Power exchanges The preferred option would not directly affect power exchanges. The preferred option would not directly affect power exchanges.
However, power exchanges could benefit from increased liquidity due
to better functioning competition on retail and wholesale markets
following price deregulation.
-
Aggregators The preferred option would not directly affect aggregators. Removing price regulation would stimulate the development of energy
services which create market opportunities for aggregators.
In the preferred option aggregators and other retail service
providers will have equal access to data as suppliers in a
transparent and non-discriminatory way. This will allow
aggregators to develop new services for consumers and will
facilitate their entrance in the market.
Consumers Consumers in a situation of energy poverty or at risk of energy poverty will
be positively impacted by the preferred option. A clearer understanding
and measuring of energy poverty will have positive impacts on Member
States efforts to tackle energy poverty..
Phase-out of regulated prices for end customers would stimulate
competition on retail markets which translates for customers into more
choice and better offers in terms of price and service quality. Customers
would be able to better manage their own energy consumption by using
energy services and technologies such as demand response, self-
generation, and self-consumption. However, notably in countries where
prices are artificially regulated at low levels, price deregulation could
be followed by substantial increases in end user prices; to help
customers face such price increases, appropriate protection measures
for vulnerable customers should be in place prior to deregulation.
The envisaged measures under the preferred option aim to
support the development of a competitive retail market. It is
expected that the measures will bring developments which
will affect positively consumers through the availability of
wider choice of services, focusing on demand response and
energy efficiency.
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Annex III: Who is affected by the initiative and how
Table 7.b Persons affected by measures for Problem Area IV
Affected party Measure
7.4. Facilitating supplier switching 7.5. Comparison Tools 7.6. Improving Billing Information
Member States The preferred option may need to be transposed into national
law, resulting in administrative impacts.
Some Member States (e.g. BE, IT) have eliminated exit fees
already, the latter reporting increased consumer trust as a
result. Others with a relatively high preponderance of exit fees
(NL, IE, SI) are likely to be more reserved, particularly in
light of the fact that they may have relatively competitive
markets already.
The preferred option will need to be transposed into national law, resulting in
administrative impacts.
However, some 13 Member States already have at least one independent CT run by a
government or government-funded body. As these are free of conflicts of interest, we
can assume they are likely to meet the accreditation criteria.
The preferred option will need to be transposed into national
law, resulting in modest implementation costs.
National
regulatory
authorities
(NRAs)
The preferred option would likely lead to additional
stakeholder engagement and enforcement actions, resulting in
increased administrative impacts to NRAs.
However, any clarification and simplification of EU legal
provisions may lead to greater ease of enforcement, and
commensurate savings.
In addition, improved consumer engagement would make it
easier for NRAs to ensure the proper functioning of national
(retail) energy markets they are charged with.
The preferred option would likely lead to additional stakeholder engagement and
enforcement actions, resulting in increased administrative impacts. However, this
would not necessarily be a role for the NRAs as an independent body might be assigned
the task (e.g. GB where an independent auditor audits the CT).
However, any strengthening of EU legal provisions should lead to a reduction in the
number of consumer complaints.
In addition, improved consumer engagement would make it easier for NRAs to ensure
the proper functioning of national (retail) energy markets.
The preferred option would likely lead to additional
stakeholder engagement and enforcement actions, resulting
in increased administrative impacts to NRAs.
However, improved billing clarity would make it easier for
NRAs to ensure the proper functioning of national (retail)
energy markets they are charged with.
Transmission
System
Operators
(TSOs)
Not affected. Not affected. Not affected.
Distribution
System
Operators
(DSOs)
Any change in consumer switching behaviour resulting from
the preferred option would be reflected in switching
operations, and their associated administrative impacts.
However, as DSOs are regulated monopolies, these costs (or
savings, if switching decreases) will eventually be passed
through to end consumers.
Insofar as the measures lead to increased switching, this will result in increased
administrative costs to DSOs. However, these costs will be passed through to
consumers through network charges.
Not affected.
Suppliers Most suppliers are unlikely to welcome measures to further
restrict switching-related fees, as these limit their ability to
tailor tariffs to different consumers.
Some may also financially benefit from the increased
'stickiness' switching-related fees create amongst their
consumer base.
In addition, any change in consumer switching behaviour
resulting from the policy options would be reflected in
switching operations, and the associated administrative
impacts to suppliers.
Industry associations (EURELECTRIC and Eurogas) have publicly supported
consumer access to neutral and reliable comparison tools. In particular, increased
reliability and impartiality in comparison tools may encourage new market entrants,
thereby improving the likelihood of a level playing field.
However, some suppliers are unlikely to welcome measures to certify comparison tools
as this may have an impact on how and where their offers are published, and their
ability to tailor tariffs to different consumers (in terms of cost, etc.).
Some may also lose out financially if they are no longer able to influence the ranking of
search results to promote certain offers; this applies both to energy suppliers and to CT
providers.
Insofar as the measures lead to increased switching, this will result in increased
administrative costs to suppliers.
Most suppliers are unlikely to welcome EU legislation
addressing the content or format of energy bills, as this limit
their ability to tailor bills to different consumers.
Some may also benefit from the low awareness amongst
their consumer base of information that may be contained in
bills, such as switching information, consumer rights, and
consumption levels.
Comparison tool
providers
Not affected. More stringent requirements in terms of reliability and impartiality may increase their
costs, as may the need for accreditation. However, such costs may be offset by an
increase in sales due to improved trustworthiness of the comparison tool.
Not affected.
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Annex III: Who is affected by the initiative and how
Affected party Measure
7.4. Facilitating supplier switching 7.5. Comparison Tools 7.6. Improving Billing Information
End consumers Some end consumers would benefit from contract exit fees
(permitted in the preferred option) if such fees mean that
suppliers are able to offer them lower prices or better levels of
service.
However, all consumers are likely to benefit from a complete
ban on other switching-related fees (as per the preferred
option), as well as greater transparency around any switching-
related fees they may be charged.
More generally, the majority of consumers would benefit
from further restricting the use of switching-related charges.
Such charges are a financial barrier to accessing better deals,
disproportionately affect decision making, foster uncertainty
on the benefits of switching, and reduce retail-level
competition.
The preferred option would benefit many consumers, as the offers displayed would be
more representative of the best ones (e.g. those offering the best value for money and
the best service levels) available on the market. Asymmetric access to information
would be reduced. Consumers would have greater trust in their ability to select the best
offer through improvements in levels of service, and they would be better protected.
They will be better able to make informed choices, and to benefit from the internal
market.
Some end consumers would benefit from contract exit fees if
such fees mean that suppliers are able to offer them lower
prices or better levels of service.
However, all consumers are likely to benefit from a
complete ban on other switching-related fees, as well as
greater transparency around any switching-related fees they
may be charged.
More generally, the majority of consumers would benefit
from further restricting the use of switching-related charges.
Such charges are a financial barrier to accessing better deals,
disproportionately affect decision making, foster uncertainty
on the benefits of switching, and reduce retail-level
competition.
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Annex III: Who is affected by the initiative and how
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Annex IV: Analytical models used in preparing the impact assessment.
Annex IV: Analytical models used in preparing the impact assessment.
Description of analytical models used
In order to perform the quantitative analysis for the various Problem Areas, most notably
Problem Areas I and II, as well as for the evaluation of certain individual measures
described in the Annexes, a number of specialized energy modelling tools were used. The
selection of the modelling tool to be used in each case was made based on its ability to
answer the specific questions raised in each Problem Area.
METIS
For assessing the benefits of specific market design measures and their effect to power
system operation and market functioning, a new optimization software – METIS – was
used, currently being developed for the Commission16
.
METIS was presented to the Member States' Energy Economists Group on April 5th
2016. The Commission will be eventually the owner of the final tool. For transparency
reasons, all deliverables related to METIS, including all technical specifications
documents and studies, are intended to be published on the website of DG ENER17
.
Global Description
METIS is an on-going project initiated by DG ENER for the development of an energy
modelling software, with the aim to further support DG ENER’s evidence-based policy
making, especially in the areas of electricity and gas. The software is developed by a
consortium (Artelys, IAEW (RWTH Aachen University), ConGas, and Frontier
Economics) and a first version covering the power and gas system has already been
delivered to DG ENER.
It is an energy model covering with high granularity (geographical, time etc.) the whole
European energy system for electricity, gas and heat. In its final version it should be able
to simulate both system and markets operation for these energy carriers, on an hourly
level for a whole year and under uncertainty (capturing weather variations and other
stochastic events). METIS works complementary to long-term energy system models
(like PRIMES and POTEnCIA), as it focuses on simulating a specific year in greater
detail. For instance, it can provide hourly results on the impact of higher shares of
intermittent renewables or additional infrastructure built, as determined by long-term
energy system models.
Upon final delivery, METIS will be able to answer a large number of questions and
perform highly detailed analyses of the electricity, gas and heat sectors. A number of
16
http://ec.europa.eu/dgs/energy/tenders/doc/2014/2014s_152_272370_specifications.pdf
17
Once operational, the envisaged link is expect to be the following:
https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis
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Annex IV: Analytical models used in preparing the impact assessment.
topics will be possible to tackle with METIS for the whole EU and/or specific regions,
like:
- The impacts of mass Renewable Energy Sources integration to the energy system
operation and markets functioning (for one or all sectors);
- Cost-benefit analysis of infrastructure projects, as well as impacts on security of
supply;
- Studying the potential synergies between the various energy carriers (electricity,
gas, heat).
On the other hand METIS is not designed to answer (at least in its first stage) questions
like:
- Optimal investment planning (capacity expansion) for the EU generation or
transmission infrastructure;
- Impacts of measures on network tariffs and retail markets;
- Short-term system security problems for the electricity and gas system (requiring
a precise estimation of the state of the network and potential stability issues);
- Flow-based market coupling and measures on the redesign of bidding areas;
- Any type of projection for the energy system.
Description of the Power Markets and System Models
The software replicates in detail market participant's decision processes, as well as the
operation of the power system. For each day of the studied year, all market time frames
are modelled in detail: day-ahead, intraday, balancing. Moreover METIS also simulates
the sizing and procurement of balancing reserves, as well as imbalances.
Uncertainties regarding demand and RES E power generation are captured thanks to
weather scenarios taking the form of hourly time series of wind, irradiance and
temperature, which influence demand (through a thermal gradient), as well as PV and
wind generation. The historical spatial and temporal correlation between temperature,
wind and irradiance are preserved.
Calibrated Scenarios – METIS has already been calibrated to a number of scenarios of
ENTSO-E's Ten-Year Network Development Plan ('TYNDP') and PRIMES. METIS
versions of PRIMES scenarios include refinements on the time resolution (hourly) and
unit representation (explicit modelling of reserve supply at cluster and Member State
level). Data provided by the PRIMES scenarios include: demand at Member State-level,
primary energy costs, CO2 costs, installed capacities at Member State-level and
interconnection capacities.
Geographical scope – In addition to EU Member States, METIS scenarios incorporate
ENTSO-E countries outside of the EU (Switzerland, Bosnia, Serbia, Macedonia,
Montenegro and Norway) to model the impact of power imports and exports to the EU
power markets and system.
Market models –METIS market module replicates the market participants’ decision
process. For each day of the studied year, the generation plan (including both energy
generation and balancing reserve supply) is first optimized based on day-ahead demand
and RES E generation forecasts. Market coupling is modeled via NTC constraints for
interconnectors. Then, the generation plan is updated during the day, taking into account
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Annex IV: Analytical models used in preparing the impact assessment.
updated forecasts and asset technical constraints. Finally, imbalances are drawn to
simulate balancing energy procurement.
Figure 1: Simulations follow day-ahead to real-time market decision process
Source: METIS
Reserve product definition – METIS simulates FCR, aFRR and mFRR reserves. The
product characteristics for each reserve (activation time, separation between upward and
downward offers, list of assets able to participate, etc.) are inputs to the model.
Reserve dimensioning – The amount of reserves (FCR, aFRR, mFRR) that has to be
secured by TSOs can be either defined by METIS users or be computed by METIS
stochasticity module. The stochasticity module can assess the required level of reserves
that would ensure enough balancing resources are available under a given probability.
Hence, METIS stochasticity module can take into account the statistical cancellation of
imbalances between Member States and the potential benefits of regional cooperation for
reserve dimensioning.
Balancing reserve procurement – Different market design options can also be compared
by the geographical area in which TSOs may procure the balancing reserves they require.
METIS has been designed so as to be able to constrain the list of power plants being able
to participate to the procurement of reserves according to their location. The different
options will be translated in different geographical areas in which reserves have to be
procured (national or regional level). Moreover, METIS users can choose whether
demand response and renewable energy are allowed to provide balancing services.
Balancing energy procurement – The procurement of balancing energy is optimized
following the same principles as described previously. In particular, METIS can be
configured to ban given types of assets, to select balancing energy products at national
level, to share unused balancing products with other Member States, or to optimize
balancing merit order at a regional level.
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Annex IV: Analytical models used in preparing the impact assessment.
Imbalances – Imbalances are the result of events that could not have been predicted
before gate closure. METIS includes a stochasticity module which simulates power plant
outages, demand and RES E generation forecast errors from day-ahead to one hour
ahead. This module uses a detailed database of historical weather forecast errors (for 10
years at hourly and sub-national granularity), provided by the European Centre for
Medium-Range Weather Forecasts ('ECMWF'), to capture the correlation between
Member State forecast errors and consequently to assess the possible benefits of
imbalance netting. The stochasticity module will be further extended in the coming year
to include generation of random errors picked from various probability distributions
either set by the user or based on historical data.
Figure 2: Example of wind power forecast errors for a given hour of the 10 years of
data.
Source: METIS
PRIMES suite of models
In order to assess the impacts of the various market design options on generator profits
and investments, as well as the impact of capacity remuneration mechanisms and their
different designs, a suite of models built by NTUA were used, with PRIMES model
being at its core.
PRIMES
PRIMES18
is a partial-equilibirum model of the energy system. It has been used
extensively by the European Commission for settting the EU 2020 targets, the Low
Carbon Economy and the Energy 2050 Roadmaps, as well as the 2030 policy framework
for climate and energy.
18
http://ec.europa.eu/clima/policies/strategies/analysis/models/docs/primes_model_2013-2014_en.pdf.
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Annex IV: Analytical models used in preparing the impact assessment.
PRIMES is a private model which has been developed and is maintained by
E3MLab/ICCS of National Technical University of Athens19
in the context of a series of
research programmes co-financed by the European Commission. The model has been
peer reviewed successfully, most recently in 201120
.
The PRIMES model is suitable for analysing the impacts of different sets of climate,
energy and transport policies on the energy system as a whole, notably on the fuel mix,
CO2 emissions, investment needs and energy purchases as well as overall system costs.
It is also suitable for analysing the interaction of policies on combating climate change,
promotion of energy efficiency and renewable energies. Through the formalised linkages
with GAINS non-CO2 emission results and cost curves, it also covers total GHG
emissions and total non-ETS sector emissions. It provides details on the Member State
level, showing differential impacts across Member States.
Decision making behaviour is forward looking and grounded in micro-economic theory.
The model also represents in explicit way energy demand, supply and emission
abatement technologies, and includes technology vintages. The core model is
complemented by a set of sub-modules modelling specific sectors. The model proceeds
in five year steps and has been calibrated to Eurostat data for the years 2000 to 2010.
For the electricity sector, the PRIMES model quantifies projection of capacity expansion
and power plant operation in detail by Member State distinguishing power plant types
according to the technology type (more than 100 different technologies). The plants are
further categorised in utility plants (plants with as main purpose to generate electricity for
commercial supply) and in industrial plants (plants with as main purpose to cogenerate
electricity and steam or heat, or for supporting industrial processes). The model finds
optimal power flows, unit commitment and capacity expansion as a result of an inter-
temporal non-linear optimisation; non-linear cost supply functions are assumed for all
resources used by power plants for operation and investment, including for fuel prices
(relating fuel prices non-linearly with available supply volumes) and for plant
development sites (relating site-specific costs non-linearly with potential sites by
Member State); the non-linear cost-potential relationships are relevant for RES E power
possibilities but also for nuclear and CCS.
The simulation of plant dispatching considers typical load profile days and system
reliability constraints such as ramping and capacity reserve requirements. Flow-based
optimisation across interconnections is simulated by considering a system with a single
bus by country and with linearized DC interconnections. Capacity expansion decisions
depend on inter-temporal system-wide economics assuming no uncertainties and perfect
foresight.
The optimisation of system expansion and operation and the balancing of demand and
supply are performed simultaneously across the EU internal market assuming flow-based
allocation of interconnecting capacities. The outcome of the optimisation is influenced by
policy interventions and constraints, such as the carbon prices (which vary endogenously
19
http://www.e3mlab.National Technical University of Athens.gr/e3mlab/.
20
https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_1569_2.pdf'.
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Annex IV: Analytical models used in preparing the impact assessment.
to meet the ETS allowances cap), the RES E feed-in tariffs and other RES E obligations,
the constraints imposed by legislation such as the large combustion plant directive,
constraints on the application of CCS technologies, policies in regard to nuclear phase-
out, etc.
The optimality simulated by the model can be characterised either by a market regime of
perfect competition with recovery of stranded costs allowed by regulation or as the
outcome of a situation of perfectly regulated vertically integrated generation and energy
supplying monopoly. This is equivalent of operating in a perfect way a mandatory
wholesale market with marginal cost bidding just to obtain optimal unit commitment and
a perfect bilateral market of contracts for differences for power supply through which
generators recover the capital costs.
According to the model-based simulations, the capital costs of all plants, taken all
together as if they belonged to a portfolio of a single generating and supplying company,
are exactly recovered from revenues based on tariffs applied to the various customer
types. This result does not guarantee that the optimal capacity expansion fleet suggested
by the model-based projections cam be delivered in the context of more realistic market
conditions with fragmentation and imperfections.
PRIMES was not directly used in this impact assessment, although the PRIMES
EUCO27 setup was the basis for all analyses, with all inputs exogenous to the power
sector, as well as generation capacities, coming from it. The main obstacle in using
PRIMES for this impact assessment was that it assumes a perfectly competitive and well-
functioning market.
For this scope two sub-modules closely linked to PRIMES were used instead:
- PRIMES/IEM is a day-ahead and unit commitment simulator, modelling the
operation of the European electricity markets and system for a given year, being
able to capture different market designs and market participant behaviours.
- PRIMES/OM is a variant of PRIMES, modifying the use of PRIMES in order to
simulate investments under various competition regimes and with the possibility
to capture the effect of CMs.
The two models are described below in more detail21
.
PRIMES / IEM
PRIMES/IEM aims at simulating in detail the sequence of power markets - Day-ahead,
Intraday, Balancing and Reserve Procurement - in the EU for one year, covering all EU
28 Member States and their interconnections (also linked to non-EU European countries).
PRIMES/IEM is calibrated to PRIMES projections, taking as exogenous inputs:
21
The detailed methodology followed, along with results, is described in a relevant report prepared for
the scope of the impact assessment: "Methodology and results of modelling the EU electricity market
using the PRIMES/IEM and PRIMES/OM models", NTUA (2016)
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- Load (hourly);
- Power plant capacities (as projected) and their technical-economic characteristics,
including old plants as available in projection period, new investments and
refurbishments as projected by PRIMES;
- Fuel prices, ETS carbon prices, taxes, etc.;
- Resource availability for intermittent renewables;
- Interconnection capacities;
- Heat or Steam serving obligations of CHP plants having production of heat or
steam as main purpose;
- Restrictions derived from policies, e.g. operation restrictions on old plants,
renewable production obligations, if applicable, support schemes of renewables,
biomass and CHP.
PRIMES/IEM disaggregates the interconnection network, considering more than one
node per country, with connecting grids within the countries, in order to represent intra-
country grid congestions. The assumptions about the grid within each country and across
the countries change over time, reflecting an exogenously assumed grid investment plan.
It also uses a more disaggregated hourly resolution than PRIMES, in representing load
and availability of intermittent RES E resources, as well as more disaggregated technical
and economic data for each plant than PRIMES, to represent cyclical operation of plants,
possible shut-downs and start-ups. Finally, PRIMES-IEM uses detailed data on ancillary
services (reserves) and the capability of plants to offer balancing services.
The day-ahead algorithm (GAMS program, written by E3MLab) is based on the
EUPHEMIA22
algorithm. The code runs for all countries and the user can select countries
to simulate market coupling. The power plant capacities, demand (hourly for the days
selected) and other information (e.g. grid) come from PRIMES database and projections.
The linkage of data to PRIMES is fully automatic. The user can define rules for bidding
by the plants, and the power plants (production hourly) which are 'must-take' and/or
nominations. Available transfer capacities between countries can also be specified in the
interface.
The unit commitment algorithm (GAMS program written by E3MLAB and solved as a
mixed integer linear program) is a fully detailed plant operation scheduling algorithm. It
includes the technical features of the power plants (technical minimum, minimum up-
time, minimum down-time, ramp-up rates, ramp-down rates, time to synchronize, time to
shut down and capability of providing ancillary reserve services to the system), the
technical features of the interconnectors (applying DC linear power flows) and the
reserve requirements of the system (primary, secondary, spinning tertiary, non-spinning
tertiary and optionally ramping-flexibility reserves). The program runs simultaneously
for the selected countries, which are assumed to operate under a coordinated-
synchronized unit commitment. The program runs on an hourly basis and simultaneously
for the sequence of typical days; runs fully one day having assumed next day, and so on.
22
EUPHEMIA (Pan-European Hybrid Electricity Market Integration Algorithm) is the single price
coupling algorithm used by the coupled European PXs (http://energy.n-side.com/day-ahead/).
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The code is fully consistent with the unit commitment codes ran by TSOs in Europe and
in the USA (compatible with the recommended code by FERC in the USA).
The day-ahead market Simulator (DAM_Simul) runs all EU countries simultaneously,
solving market clearing by node (one node per country) and calculating interconnection
flows restricted by DC power flows and by Available Transfer Capacities (defined by
pair of countries).
Market participant bidding23
is based on marginal costs plus mark-up reflecting scarcity.
Must take CHP, RES and nominated capacities are included in DAM simulation as fixed
(unchanged) hourly amounts. Similarly the reservation of cross-border capacity for
nominations is fixed. In some policy-options these assumptions are relaxed. The
wholesale prices of DAM are calculated from the relaxed problem, after having run the
mixed integer problem. The DAM-Simulator runs pan-European and includes
interconnection flows subject to limitations of power flow and NTC/ATC restrictions as
applicable and if applicable in each policy option.
The unit commitment simulator (UC_Simul) includes exogenously defined reserve
requirements, the outcomes of the event generator, the operation schedule of all units, the
bids in DAM and penalty factors for slack variables (re-dispatching). Operation of small-
RES E and must-take CHP is fixed. The unit commitment simulator runs pan-European
limited by power flows and NTC values.The purpose of this run is to determine the
deviations from DAM schedule, to be used in the intraday and balancing simulator.
The Intraday and Balancing Simulator (IDB_Simul) runs the above intraday and
balancing market (once for 24-hours all together) and determines a price for deviations,
the financial settlement of deviations and a revised schedule for operation of units and
interconnectors.
In IDB_Simul, eligible resources can bid for supplying power to meet the deviations. The
bids can differ for upward and for downward changes of power supplied by the eligible
resources. Eligibility is defined specifically for each policy option. Capacity from
interconnectors may be eligible but only if remaining capacities (beyond the schedule of
the unit commitment) allow for this.
23
Bidding functions are defined by plant in DAM on the basis of the marginal fuel cost of the plant,
increased by a mark-up defined hourly as depending on scarcity. The modelling of the bidding
behavior of generators, similar in PRIMES/IEM and PRIMES/OM, is discussed in detail in the
PRIMES/OM Section.
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Figure 3: Modelling Sequence in PRIMES/IEM
Source: PRIMES/IEM
In the Reserve and ancillary services procurement Simulator (RAS-Simul) demand for
reserves is defined exogenously (equal to demand used in the UC_Simul). The outcome
of RAS-Simul is the remuneration of the resources for providing reserves and a possible
(small) modification of the schedule of units and interconnection flows.
For each policy option the demand for reserves is differentiated. Eligible resources can
bid for supplying power to meet the demand for the different types of frequency reserves.
Also, a subset of plants are eligible in each market for reserve. When the bids are
endogenous and market-based, the prices include scarcity markups, with scarcity
referring to the market for reserves. Eligibility of resources is defined differently for each
policy option. Resources available cross-border can participate (differently constrained
by policy option) in the markets for reserves subject to limitation from availability of
interconnection capacity, which is the capacity remaining after the schedule of the unit
commitment and intraday. Resources not scheduled after the unit commitment and the
intraday can submit bids to the markets for reserves (only for tertiary reserve) but only
gas turbines are eligible for this purpose.
For the finalisation of the simulation, the unit commitment simulator is run again
assuming as given the schedule of units and interconnection flows resulted from previous
steps and the load (hourly). The objective function includes only penalties for deviation
from the schedule resulted from the previous step. The ascending order of penalties is
RES E, interconnection flows, gas, solids, nuclear, demand or another order defined
specifically by policy option. If must-take CHP and small-RES E can be curtailed then
they are also included with penalties, otherwise they are fixed. The unit commitment
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simulator runs at this stage pan-European and applies flow based allocation of
interconnections. The purpose of this run is to calculate the production by plant,
consumption of fuel, operation cost by plant and emissions.
Demand response is modelled similarly to pumping transferring power from peak- to
baseload; the amount of energy reduced in peak hours is compensated in the same day by
additional energy consumption in other time segments, chosen endogenously. Therefore
demand response bids for differential demand reduction and demand increase at different
times, the bidding price reflecting costs (exhibiting decreasing return to scale), scarcity
cost opportunity and the bidding quantity being subject to potential. Demand response
(defined differently for each policy option) can be incorporated in all stages, i.e. DAM,
intraday, reserves.
The simulation cycle closes by the reporting of financial balances (load payments,
revenues and costs) for each generator, load and the TSO and calculating unit cost
indicators (e.g. for reserves, etc.). As the simulation is stochastic, the expected values of
the outcomes are calculated as the average of results by case of random events weighted
by the frequency of the case.
PRIMES / OM
PRIMES/OM is a modified version of the power sector model of PRIMES, tailored to the
needs of the impact assessment. It uses the PRIMES database, as well as its scenario
assumptions. By departing from the usual perfect competition assumption of PRIMES, it
can simulate investment behavior and the influence of CMs under various competition
regimes and bidding behaviours. Simulations are dynamic, demand is price elastic and
cross-border flows endogenous.
The model variant covers the power sector of all EU Member States linked together. The
model simulates an organized wholesale market, calculating prices, revenues and costs,
and estimating the probability of eventual mothballing of old plants and the cancelling
(partially or entirely) of investment in new plants as a consequence of the revenues
associated to the individual plant.
The model includes as an option a stylized CM auction, with or without cross-border
participation, which is general in scope in terms of eligibility and covers all dispatchable
generators. The inclusion or not of national CMs varies by scenario simulated. The model
considers that the presence of a CM leads to lower risk premium factors which are used
by generators to decide mothballing of old plants or cancelling of investments. However,
the CM demand functions, as specified according to the logic of the model, are such that
they may grant unnecessarily capacity payment to some plant categories.
Figure 4: Modelling Sequence in PRIMES/OM
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Annex IV: Analytical models used in preparing the impact assessment.
Source: PRIMES/OM
The model runs dynamically from 2020 until 2050, in 5-year steps. It uses a full PRIMES
model scenario as starting point, from where it takes the first input for load, renewables
and the projection of power plant capacities. Subsequently it modifies load based on
demand response, capacity availability and investment (except for renewables, industrial
and district heating CHP) as a result of the mechanism described above.
A fundamental assumption of the oligopoly model is that the economics on which
capacity-related decisions are made by generators are specified individually for each
plant. However, the standard PRIMES model looks at the economics of portfolios of
plants to determine the outcome of capacity-related decisions. It also, enables us to
quantify the differences between market outcomes in perfect competition, where
marginal cost bidding is applied, and under the oligopoly market structure where uplift is
applied to the bids of market participants.
Main characteristics of PRIMES/OM
Investment Evaluation – A stochastic analysis is performed with respect to the main
uncertainty factors affecting investments or early retirement of old plants, thus
introducing a probability space for the simulation of investment decision under
uncertainty. These factors have been identified as follows: (a) ETS carbon prices, (b)
natural gas prices in relation to coal prices, and (c) the volume of demand for electricity
net of renewables. In addition to the uncertainties pertaining to the framework conditions,
the heterogeneity of decision makers in the investment evaluation process has also been
taken into account. This is accomplished by considering a distribution probability of the
hurdle rates that an investor considers (subjectively) for undertaking an investment. The
hurdle rates are equivalent to the minimum Internal Rate of Return value for deciding
positively upon an investment. The frequency distribution is modified in terms of mean
and standard deviation dependent upon the certainty or lack thereof of revenues;
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Annex IV: Analytical models used in preparing the impact assessment.
revenues coming from the energy only market compared to those coming from a CM
imply higher mean and standard deviation of the distribution of hurdle rates.
Combining all of the above, a sample of about 100 combinations is generated around the
EUCO27 trajectory for the three stochastic factors for the whole time period (as vectors
over time) and 100 hurdle rate cases with combined probabilities. For the purposes of
investment evaluation, the pan-EU energy-only market is run for each sample of the
stochastic factors and revenues and costs for each plant are calculated for their total
lifetime, including possible extension of operation. Two sources of revenues are
accounted for: from operation in the energy-only market and from supplying reserve to
the system. For the cost calculation, capital annuity payments were excluded. Using the
revenues and costs calculated as such, the economic performance of each power plant is
found, defined as the present value of future earnings above operation costs for each
sample of uncertain factors and each hurdle rate case. The expected economic
performance of a plant is the result of an average of performances weighted by the
probabilities.
Heterogeneous decision makers, identified by the distribution of the hurdle rates as
mentioned above, have a different threshold probability in order to decide whether or not
to continue operating a plant or cancelling investment. In other words, there is an
association of expected economic performance of each plant, as represented by its
present value, with investment cost of new plants or with salvage value (remaining
capital value) for plants, which are distributed across the decision makers according to a
normal probability distribution function. Therefore, the frequency of decision about
survival of a plant’s capacity as a function of the economic performance indicator is used
as the probability of survival. The capacity volume of the plant as projected by PRIMES
in the context of the EUCO27 scenario multiplied by the probability of survival provides
us with an update of the capacity volume.
Modelling of CMs – When a CM is assumed to be in place, it is modelled in a stylized
manner. All capacities are eligible, if dispatchable, including hydro lakes and storage,
provided that they are not under a different support scheme. For example, CHP, biomass,
etc. are excluded. Also, plants in the process of decommissioning or operating few hours
per year due to environmental restrictions as projected in PRIMES are excluded. All
capacities are remunerated for the available capacity excluding outages.
The CM payment is a result of an auction. The CM price is derived from the intersection
of demand for capacity and the offers, sorted in ascending price order. Demand for
capacity is defined as a negative-sloped linear line depending upon a price cap and
linking two capacity points: the minimum and maximum requirements. For all capacity
offered up to the minimum requirement the auction clearing price is equal to the price
cap, while for the maximum requirement it is equal to zero. The definition of the demand
curve takes into account trusted imports at peak load times and the guaranteed proportion
of exports. Therefore, implicit participation of flows over interconnections is taken into
account. Cross-border participation, when applicable, increases capacity offering.
Removal of capacities (due to mothballing or cancelling of investment, or because the
capacity is offered to a foreign CM) also decreases capacity offering. The CM winners
sign a reliability option (one way option) which has a strike price. If the wholesale
market price is above the strike price they are assumed to return the revenues above
strike price. The results of the CM auctions, namely the stream of revenues they provide
to generators, are taken into account by the oligopoly model in the final step of
investment evaluation.
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Annex IV: Analytical models used in preparing the impact assessment.
Bidding Behaviour - The model assumes a scarcity bidding function as a means to mimic
the strategic behaviour of market players in an oligopoly. The bidding function is specific
to each individual plant and it takes into account hourly demand, plant technology and
plant fixed costs in order to evaluate the hourly bid price of each generator.
In order to model the bidding behaviour of plants, they are assigned to one of four
different types of merit order: no-merit, baseload, mid-load, and peak load. Hydro-
reservoirs consider also water availability. The assignment of plants takes place based on
their technology as well as on whether they participate in the energy only market; non-
dispatchable generators are considered as must-take, and therefore are assumed to bid at
zero price. The no-merit order type is intended to include this type of plants. The
baseload category includes mainly nuclear and coal/lignite plants, the mid-load CCGTs,
and the peak load of GTs and Reservoir Hydro.
Subsequently, the capacities of all plants within a merit order type are summed up in
order to determine the total capacity of every type, developing a merit stack. Then the
hourly demand is compared with the merit stack in order to estimate for every hour
which merit order type is expected to be on the margin. This is the type on which a
scarcity mark-up will be applied, assuming this is the market segment in which all
strategic behaviour of market participants takes place for a specific hour. The marginal
cost which sets the basis for the price at which each plant offers its energy is calculated
based on variable cost data from the PRIMES database. The mark-up is calculated based
on the following equation:
[ ]
P is the plant identifier, the merit order type, the Marginal cost, the total
supply (capacity) of merit order type, the hourly demand specific to merit order
type, the price ceiling for merit order type, the (inverse) rate of mark-up and
the scarcity bid. The demand specific to a generation type is calculated as the residual
of hourly demand minus the capacity of the merit order types which lie below the
marginal.
The price ceiling is specific to every merit order type and is applied in order to guarantee
that the merit order is never reversed, i.e. peak load plants being dispatched before mid-
load plants, mid-load before baseload, etc. Also, the rate specific to each plant is
dependent upon the fixed costs of the plant, which comprise mainly of capital costs, in a
risk averse manner. This convention is in place so that plants with high fixed costs are
more reluctant to apply a mark-up to their marginal cost in fear of staying out-of-merit
and not being dispatched due to the mark-up being too high. Finally, if in post-
calculation the scarcity bid exceeds the price ceiling, it is set equal to the ceiling.
Description of methodological approach followed concerning baseline
PRIMES EU Reference Scenario 2016
A common starting point to all Impact Assessments is the EU Reference Scenario 2016
('REF2016'). It projects greenhouse gas emissions, transport and energy trends up to
2050 on the basis of existing adopted policies at national and EU level and the most
recent market trends. This scenario was prepared by the European Commission services
in consultation with Member States. All other PRIMES scenarios build on results and
modelling approach of the REF2016.
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Annex IV: Analytical models used in preparing the impact assessment.
Although REF2016 presents a comprehensive overview of the expected developments of
the EU energy system on the basis of the current EU and national policies, and could be
considered as the natural baseline for all impact assessments, it fails doing so for an
important reason. This scenario does not have in place the policies to achieve the 2030
climate and energy targets that are already agreed by Member States in the European
Council Conclusions of October 2014. It also does not reflect the European Parliament's
position on these targets.
Therefore, although it was important for all initiatives to have a common "context" in
order to ensure coherent assessments, each Impact Assessment required the preparation
of a specific baseline scenario, which would help assess specific policy options relevant
for the given Impact Assessment.
Central Policy Scenario: PRIMES EUCO27
Because of the need to take into account the minimum agreed 2030 climate and energy
targets (and the 2050 EU's decarbonisation objectives) when assessing policy options for
delivery of these targets, a central policy scenario was modelled ('EUCO27').
This scenario is the common policy scenario for all Impact Assessments. Additional
baseline and policy scenarios were prepared for each Impact Assessment, addressing the
specific issues to be assessed by each initiative, notably which measures or arrangements
have to be put in place to reach the 2030 targets, how to overcome market imperfections
and uncoordinated action of Member States, etc. A summary of the approach followed in
each respective impact assessment can be found in the Annex IV of the RED II impact
assessment.
This approach of separating a central policy scenario reaching the 2030 targets in a cost-
effective manner and other scenarios that look into specific issues related to
implementation of cost effective policies enables to focus on "one issue at a time" in the
respective separate analysis. It enabled to assess in a manageable manner the impacts of
several policy options and provide elements of answers to problem definitions listed in
the 2016 impact assessment, without the need to consider the numerous possible
combinations of all the options proposed under each respective initiative.
PRIMES EUCO27 scenario is based on the European Council conclusions of October
201424
. In particular, the following were agreed among the heads of states and
governments:
- Substantial progress has been made towards the attainment of the EU targets for
greenhouse gas emission reduction, renewable energy and energy efficiency,
which need to be fully met by 2020;
- Binding EU target is set of an at least 40% domestic reduction in greenhouse gas
emissions by 2030 compared to 1990;
- This overall target will be delivered collectively by the EU in the most cost-
effective manner possible, with the reductions in the ETS and non-ETS sectors
amounting to 43% and 30% by 2030 compared to 2005, respectively;
24
http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdata/en/ec/145397.pdf.
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Annex IV: Analytical models used in preparing the impact assessment.
- A well-functioning, reformed ETS with an instrument to stabilise the market in
line with the Commission proposal will be the main European instrument to
achieve this target; the annual factor to reduce the cap on the maximum permitted
emissions will be changed from 1.74% to 2.2% from 2021 onwards;
- An EU target of at least 27% is set for the share of renewable energy consumed in
the EU in 2030. This target will be binding at EU level;
- An indicative target at the EU level of at least 27% is set for improving energy
efficiency in 2030 compared to projections of future energy consumption based
on the current criteria. It will be delivered in a cost-effective manner and it will
fully respect the effectiveness of the ETS-system in contributing to the overall
climate goals. This target will be reviewed by 2020, having in mind an EU level
of 30%;
- Reliable and transparent governance system is to be established to help ensure
that the EU meets its energy policy goals, with the necessary flexibility for
Member States and fully respecting their freedom to determine their energy mix;
The above requirements, with a minimum energy saving level of 27%, are reflected in
EUCO27. Concrete specifications on assumptions were made by the Commission in
order to reach the relevant targets by using a mix of concrete and yet unspecified
policies. A detailed description of the construction of this scenario is presented in Section
4 of the EE impact assessment and its Annex IV.
As this scenario is not directly used in the present impact assessment, the reader is
referred to the relevant technical annexes of the EE and RED II impact assessments for
more details on its main assumptions and results. Table 1 below presents the main
projections for 2030 related to the power system for EU28.
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Table 1: PRIMES EUCO27 Modelling Results for the power system (EU28)
2000 2015 2030
Share in
total for
2030 (%)
% diff
2015-
2010
% diff
2030-
2015
Electricity consumption (in TWh) 3,029.0 3,271.8 3,525.6 8% 8%
Final energy demand 2,530.7 2,802.4 3,081.3 11% 10%
Industry 1,061.1 1,001.4 1,054.8 30% -6% 5%
Households 713.8 833.6 899.7 26% 17% 8%
Tertiary 683.5 899.3 982.2 28% 32% 9%
Transport 72.3 68.2 144.6 4% -6% 112%
Energy branch 281.7 262.6 231.2 7% -7% -12%
Transmission and distribution losses 216.2 206.7 213.1 6% -4% 3%
Net Installed Power Capacity (in GWe) 683.5 965.6 1,131.0 41% 17%
Nuclear energy 139.6 120.8 109.9 10% -13% -9%
Renewable energy 129.0 366.7 652.2 58% 184% 78%
Hydro (pumping excluded) 115.8 127.5 133.3 12% 10% 5%
Wind on-shore 12.7 130.6 246.1 22% - 88%
Wind off-shore 0.1 11.0 37.9 3% - 246%
Solar 0.2 97.4 233.8 21% - 140%
Biomass-waste fired 12.7 27.9 53.1 5% 121% 90%
Other renewables 0.8 1.1 2.1 0% 32% 86%
Thermal power 414.9 478.1 368.9 33% 15% -23%
Solids fired 194.5 176.6 99.4 9% -9% -44%
Oil fired 83.3 53.1 15.3 1% -36% -71%
Gas fired 123.8 219.6 200.1 18% 77% -9%
Net Electricity generation by plant
type (in TWh)
2,844.0 3,090.0 3,396.7
9% 10%
Nuclear energy 893.9 825.7 738.4 22% -8% -11%
Renewable energy 374.5 736.2 1,372.8 40% 97% 86%
Hydro (pumping excluded) 351.6 357.7 375.1 11% 2% 5%
Wind on-shore 22.2 241.4 564.4 17% - 134%
Wind off-shore - 32.8 127.3 4% - 288%
Solar 0.1 103.8 303.6 9% - 193%
Biomass-waste fired 42.9 130.6 238.1 7% 204% 82%
Other renewables 5.0 7.1 9.7 0% 42% 37%
Thermal power 1,575.6 1,528.0 1,285.6 38% -3% -16%
Solids fired 866.3 780.3 448.6 13% -10% -43%
Oil fired 178.4 30.2 14.6 0% -83% -52%
Gas fired 483.4 580.4 576.8 17% 20% -1%
Source: PRIMES
Baseline: Current Market Arrangements ('CMA')
The Market Design Initiative addresses four different Problem Areas. The first two,
addressing market functioning and investments, share a common baseline which is highly
dependent on the context (e.g. based on REF2016 or EUCO27). The other two Problem
Areas, concerning risk preparedness and retail markets, are more independent of the
overall context, as in each case the envisaged baseline and options can apply in either
context (moreover the assessment tends to be mainly qualitative). Therefore the
discussion on the baseline is meaningful mainly for the first two Problem Areas.
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Annex IV: Analytical models used in preparing the impact assessment.
Similar to the other 2016 Energy Union initiatives, EUCO27 was chosen as the starting
point (i.e. context) of the baseline for the Market Design Initiative (so-called "Current
Market Arrangements" – CMA). The EUCO27 scenario is the most relevant to the
objectives of the initiative, as it provides information on the investments needed and the
power generation mix in a scenario in line with the EU's 2030 objectives.
As all analysis focuses on the power sector, all assumptions exogenous to the power
sector were taken from the EUCO27 scenario. This also applied for the energy mix, the
power generation capacities for each period, the fuel and carbon prices, electricity
demand, technology costs etc. The main obstacle in further using the EUCO27 as a
baseline for this impact assessment was that it assumes a perfectly competitive and well-
functioning European electricity market, more matching the end point than the starting
point of the analysis. Therefore CMA differs from the EUCO27 scenario by including
existing market distortions, as well as current practices and policies on national and EU
level.
The CMA assumes implementation of the Network Codes, including the CACM and the
EB Guidelines (the later in their proposed form). It is assumed that the CACM Guideline
will bring a certain degree of harmonisation of cross-border intraday markets, gate
closure times and products for the intraday, as well as a market clearing. National
intraday and balancing markets will be created across EU and a certain degree of market-
coupling of intraday markets will be achieved. At the same time, the EB Guideline is
expected to bring certain improvements to the balancing market, namely the common
merit order list for activation of balancing energy, the standardisation of balancing
products and the harmonisation of the pricing methodology for balancing. Nonetheless,
other important areas like harmonisation of intraday markets and balancing reserve
procurement rules will not be affected by the guidelines.
The baseline does not consider explicitly any type of existing support schemes for power
generation plants, neither in the form of RES E subsidies nor in the form of CMs25
. This
is governed to a large degree from the 2014 EEAG applicable as of 1 July 2014. Aid
schemes existing at that moment have to be amended in order to bring them into line with
EEAG no later than 1 January 2016. This with the exception of schemes concerning
operating aid in support of energy from renewable sources and cogeneration that only
need to be adapted to the EEAG when Member States prolong their existing schemes,
have to re-notify them after expiry of the 10 years-period or after expiry of the validity of
the Commission decision or change them. This implies that all existing schemes will
expire by 2024 at the latest and will be adapted to the EEAG, applicable at the time of
their notification. Current guidelines allows operational aid only as feed-in premium, not
attributed for the hours with negative prices and with its level determined via tenders. In
essence this means that non-market based support schemes are fully phased out by 2024
assuming that the rules as regards RES E and CHP aid schemes well remain unaltered
when the EEAG is reviewed in 2020.
25
Admittedly this assumption is strong, but necessary to simplify the analysis. Otherwise a riskier (for
the analysis) assumption would need to be made on the future share, type and level of support for the
various support schemes per Member States in the end becoming a major driver for the results and
complicating their interpretation.
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Annex IV: Analytical models used in preparing the impact assessment.
Moreover, the RED II proposals (part of the baseline of the present impact assessment)
will enshrine and reinforce the market-based principles for the design of support
schemes. As it is reasonable to assume that the RED II will enter into force prior to 2024,
assuming that all support to RES E by 2030 is market based is a prudent assumption.
The effect of RES E subsidies is relevant to the MDI impact assessment only when it
directly affects the merit order. Overall the cost-efficient level of investments in RES E26
is taken as given across all assessed options, as projected in EUCO27, without examining
how the costs of these investments are recuperated (topic addressed in the RED II impact
assessment). The baseline assumes one of the main objectives of the RED II initiative is
achieved and a framework strengthening the use of tenders as a market-based phase-out
mechanism for support is in place, gradually reducing the level of subsidies over the
course of the 2021-2030 period (still support schemes would exist for all non-competitive
RES E technologies). Moreover it is assumed that existing FiT contracts have been
phased-out by 2030 to a large degree, most importantly the ones targeted on biomass,
being the ones most distorting to the merit order. As a result the assumption of not
considering any non-market based support for RES E generation is reasonable and not
significantly affecting the results.
As for CMs, existing or planned, they are mainly relevant for Problem Area II and did
not need to appear in the common baseline of the two Problem Areas. The analysis for
Problem Area I did not touch issues related to investments, thus the assumption of CMs
(which would be present in all assessed options) would have a limited influence on the
impacts and the ranking of the options27
. As far as Problem Area II is concerned, again
their inclusion was avoided, as any results would be highly dependent on the specific CM
assumptions over the examined period. Moreover, in line with the results of the analysis
in section 6.2.6.2, the effect of adding a CM would most likely be to further increase the
cost of the power system. As the baseline was already a very costly scenario compared to
the preferred energy-only market one, the conclusion from the comparison of the options
would remain the same.
METIS calibration to EUCO27
As mentioned above, for the scope of this impact assessment METIS was calibrated to
the PRIMES EUCO27 scenario. In fact, as the calibration needed to take place much
before the finalisation of the PRIMES EUCO27, it was performed on one of its
preliminary versions. The main elements of the calibration process, as well as the most
important differences between the preliminary and the final version of EUCO27 are
described below. A significantly more detailed description of the calibration has been
reported on a separate document, to be found on the METIS website28
.
Preliminary EUCO27
26
The same applies for CHP, when the main use of those plants is the production of heat/steam.
27
The CMs would not affect the merit order in problem area I, as the analysis assumes bidding based on
marginal costs (not scarcity pricing, which is introduced in problem area II).
28
Once operational, the envisaged link is expect to be the following:
https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis
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Annex IV: Analytical models used in preparing the impact assessment.
The two versions of EUCO27 are in general quite close from an EU energy system
perspective. Two differences can be found in 2030, one in the RES E shares and the other
in CO2 prices, slightly affecting power generation capacities and production.
RES E overall share is in both cases 27%, with a differentiation in the sectoral
contribution: in the preliminary version the share of RES E is at 48.4%, while being
47.3% in the final EUCO27 version. This was mainly driven by differences in off-shore
wind deployment. There is more switching from coal to gas in the final version. This is
translated to 2 p.p. increase of gas in the share of power gas generation, while solids
decreased by 0.5 p.p. and RES E by 1.3 p.p.. The CO2 price, which was 38.5 EUR/tCO2
in the preliminary version is 42 EUR/tCO2 in the final EUCO27 version.
The effect of these differences is not very significant on the EU level, although it does
have some implication on the results of specific Member States with a projected high
capacity of off-shore wind in the preliminary version, e.g. the UK.
METIS calibration to PRIMES EUCO27
For the scope of this impact assessment, simulations adopted a country level spatial
granularity and an hourly temporal resolution of year 2030 (8760 consecutive time-steps
year), capturing also the uncertainty related to demand and RES E power generation.
Modelling covered all ENTSO-E countries, not only EU Member States, as follows:
 All ENTSO-E countries for the day-ahead market;
 EU28+NO+CH for intraday, balancing and reserve procurement29
;
 EU28+NO for regional co-operation for reserve procurement, CH reserve
assumed to be procured nationally.
For configuring METIS to match the (preliminary) PRIMES EUCO27 projections, a
number of steps were taken, the most important of which are described in the following.
Details can be found in the relevant METIS report30
.
1. The data provided for the calibration concerned only EU28. Missing data for
other countries modelled with METIS (i.e. Bosnia, Switzerland, Montenegro,
FYROM, Norway and Serbia) were complemented by other sources, mainly
ENTSO-E 2030 vision 1 of TYNDP 2016.
2. The hourly power demand time series were based on ETNSO-E's 2030 vision 1
scenario. Data were adjusted so that on average (over 50 weather data
realizations) the power demand of each country corresponds to the PRIMES
EUCO27 projections.
3. Installed capacities were computed based on PRIMES EUCO27 scenario31
. For
certain EU28 countries the split between hydro lake and run-of-river of PRIMES
29
Actually reserve procurement was not modelled for other non-EU28 Member States, as well as for
Malta, Cyprus and Luxembourg.
30
"METIS Technical Note T04: Methodology for the integration of PRIMES scenarios into METIS",
Artelys (2016)
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Annex IV: Analytical models used in preparing the impact assessment.
was reviewed based on historical data form ENTSO-E, due to differences in the
definitions used in PRIMES (based on Eurostat) and METIS (based on ENTSO-
E).
4. Generation of ten historical yearly profiles for wind and solar power was
performed according to the methodology depicted in Figure 5. The methodology
followed delivered annual load-factors closely matching the ones of PRIMES
EUCO27.
Figure 5: PV and wind generation profiles
Source: METIS
5. Thermal plant fleets comprised of the following technologies: hard coal, lignite,
CCGT, OCGT, oil, biomass. The various fleets, except oil and biomass, were
divided into two or three classes (only CCGT were divided into three). Thermal
installed capacities were based on PRIMES EUCO27, without though enforcing
any type of constraint on the net electricity generation of these plants (which was
a pure result of the modelling). The technical-economic assumptions of PRIMES
were used for the power plants, complemented by other sources or databases
when missing.
6. Water inflow profiles, as well as storage parameters, required important
reconciliation work combing data from ENTSO-E, TSOs and PRIMES.
7. The international fuel price assumptions of PRIMES EUCO27 were used for
calculating the marginal production costs of the thermal fleets. Specifically for
coal and biomass, end-user fuel prices coming again from PRIMES EUCO27–
including also transportation costs – were used instead.
31
CHP units were treated as electricity-only gas plants, as currently METIS does not model the heat
sector. Division of RES to small and large scale (e.g. rooftops solar) was also not captured.
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Annex IV: Analytical models used in preparing the impact assessment.
8. METIS used the same NTC values as in PRIMES EUCO2732
. NTC values
between European and non-European countries are completed using ENTSO-E
2030 v1 scenario.
9. As METIS focuses in particular on the economics of security of supply, a key
point is that installed capacity is consistent with peak demand. Consequently,
provided OCGT capacities were optimized to satisfy security-of-supply criteria.
To optimize OCGT capacities, supply-demand equilibrium was computed with
“State of the art” OGCT capacities as variables over 50 years of weather data.
Capacities of “oldest” OCGT fleets remain fixed to the installed capacities in
2000 which have not been replaced by 2030. Table 2 presents the results of the
OCGT capacity optimization consisting in the added OCGT installed capacities
per country. These additional capacities are added to the installed capacities in
2030 excluding the investment between 2000 and 2030.
Table 2: Additional OCGT capacities needed to satisfy security of supply standards
Source: METIS, Artelys Crystal Super Grid
METIS policy scenarios for the options of Problem Area I
This section provides information on the market design options that were modelled and
assessed using METIS. Each scenario was run using the full capabilities of METIS. In
fact certain aspects of METIS were further developed in order to be possible to better
assess a number of the measures covered in the impact assessment.
Each scenario was intended to match the setup of one assessed option. For this purpose
the options were first decomposed into a number of "fields", reflecting existing market
distortions or design features that were addressed within each option. Following
subsequent analysis, these fields were then narrowed down to the twelve presented in
Table 3 below. For each of these fields, two or three sub-options were considered across
the different scenarios. The sub-options considered (entitled "a"/"'b"/"c") are identified
on the right had columns of Table 3, while their description is provided in Table 4.
For all fields, sub-option "a" reflects current practices and existing market distortions, as
well as the possible evolution of markets in the near future in the absence of new
policies. The identification and methodology for the quantification of current practices
was supported by a study performed specifically for this purpose33
.
32
- Regarding grid development and the interconnectors between countries, they are based on the ENTSO-
E TYNDP, following the respective timelines. After the end of the TYNDP, expansions are based on
known plans and the development of RES E.
33
"Electricity Market Functioning: Current Distortions, and How to Model their Removal", COWI
(2016).
BE DK FI FR IE NO SE UK
OCGT added capacity
(GW)
5 2 4 6 1 4 3 19
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Annex IV: Analytical models used in preparing the impact assessment.
Table 3: Overview of MDI impact assessment Problem Area I scenarios as modelled
by METIS (read in conjunction with Table 4)
Action Field
MDI options
0 1(a) 1(b) 1(c) 2
1 DR deployment a b b c c
2 RES E priority dispatch a b b b b
3 Biomass reserve procurement a b b b b
4 Coal/lignite unit commitment at intraday a b b b b
5 Balance responsibility a b b b b
6 Intraday coupling a a b b b
7 Time granularity for reserve sizing a a b b b
8 Reserve procurement methodology a a b b b
9 Joint/separate upward/downward reserve a a b b b
10 Use of NTC a a b b c
11
Reserve dimensioning and risk sharing
a a b b c
12 PV, Wind and RoR reserve procurement a a a b b
Source: METIS
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Annex IV: Analytical models used in preparing the impact assessment.
Table 4: Overview of the sub-options for each measure modelled in METIS
Measure Topic Description of the options
1 DR deployment
Three levels of DR deployment (sub-options a, b and c, with
increasing economic potential, based on COWI BAU and PO2
scenarios34
) were considered.
In sub-option "a" DR can considered only for countries where DR
has currently access to the market and only for industrial resources
based on BAU potentials. In sub-option "b" DR by industrial
resources appears in all countries based on BAU potentials. In sub-
option "c" all DR resources participate based on the potential of the
PO2 scenario, adjusted to better match EUCO27 projections and the
activation limits of DR potential.
2
RES E priority
dispatch
Two options were considered:
a. Penalty factor for PV and Wind curtailment, priority
dispatch for Biomass
b. No penalty factor or priority dispatch for PV, Wind and
Biomass
For sub-option "a", modelling RES E priority dispatch for wind and
PV was performed via a penalty factor and not by explicit priority
dispatch. The reason was that there were a number of hours for
certain Member States that if an explicit priority dispatch was
enforced for all RES E, their power system collapsed (solution was
infeasible). In reality this would most likely be addressed by the
TSOs via the curtailment of RES E.
3
Biomass reserve
procurement
Two options for participation of biomass in reserve procurement:
a. Biomass does not participate in FCR or FRR
b. Participation of Biomass (the absence of priority dispatch is
a prerequisite)
4
Coal/lignite unit
commitment at
intraday
Two options for coal and lignite unit commitment:
a. The day-ahead unit commitment decision (i.e. which plants
are turned on or off) for coal and lignite power plants cannot
be refined during intraday, i.e. coal and lignite plants are
treated as must-runs in intraday once scheduled in day-
ahead.
b. Coal and Lignite can re-optimise their commitment in
intraday (subject to their technical constraints).
5
Balance
responsibility
By making RES E producers financially responsible for the
imbalances they are encouraged to improve their generation
forecasts. Two options were considered:
a. H-2 forecasts were used for Wind and PV generation for
reserve dimensioning and generation of imbalances.
b. H-1 forecasts were used for demand and PV, while 30 min
forecasts were used for Wind, leading to lower imbalances
and lower reserve requirements.
34
"Impact Assessment support Study on downstream flexibility, demand response and smart metering",
COWI (2016)
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Annex IV: Analytical models used in preparing the impact assessment.
Measure Topic Description of the options
6 Intraday coupling
Auctions for interconnections capacity can either be explicit,
captured in METIS as if assuming the flows are fixed in H-4, or
implicit, in which case flows can be updated in H-1. Two options
were considered:
a. Auctions were mostly explicit, except in specific areas
based on current practices.
b. Auctions were implicit for all interconnections.
In any case, the reserve procured at day-ahead remained fixed during
intraday.
7
Time granularity
for reserve sizing
Two options were considered for aFRR reserve sizing:
a. Fixed reserve size computed as 0.1% and 99.9% centiles of
imbalance distribution over the year. While some Member
States have different reserve sizes depending on demand
variation, this option assumes that the reserve size is
constant over the year for all Member States.
b. Variable reserve size depending on the hour of the day and
wind energy generation. Size is computed with 0.1% and
99.9% centiles of imbalance conditional distribution
8
Reserve
procurement
methodology
Reserve can be procured either day-ahead (which was modelled in
METIS as a joint optimization of power and reserve hourly
procurement at day-ahead) or on a fixed basis per year (in which case
the mean annual value of optimal reserve procurement is used). The
options were:
a. Current practices
b. Day-ahead procurement
9
Joint/separate
upward/downward
reserve
Two options were considered for upwards and downwards reserve:
a. Joint procurement according to current practices
b. Being two separate products which can be procured
independently
10 Use of NTC
To model the process of interconnection allocation, three options
were considered:
a. National TSOs need to have a high security margin. For the
scope of METIS, EUCO27 NTCs were reduced by 5%.
b. Collaboration between TSOs reduces the need for security
margins. EuCo NTC values were used.
c. The introduction of a supranational entities will result in a
further reduction of the security margins, leading to an
increase by 5% of the EuCO NTCs.
11
Reserve
dimensioning and
risk sharing
To assess whether risk sharing can reduce the needs for national
reserves, three options were considered. Reserve was sized using a
probabilistic approach:
a. At national level
b. At regional level
c. At EU level
In order to ensure Member States can face similar security of supply
risks when less reserves can be procured (Options b. and c.), part of
the interconnections' capacity was reserved for mutual assistance
between Member States.
12
PV, Wind and RoR
reserve
procurement
Two options:
a. PV, Wind and Hydro RoR do not participate in FCR or FRR
b. Participation of PV, Wind and Hydro RoR in FCR or FRR
Source: METIS
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Annex IV: Analytical models used in preparing the impact assessment.
A more detailed description of the scenarios, how each option/measure was modelled and
what were the identified relevant current practices, can be found in an explanatory
technical report35
.
It is important to highlight that the scenarios under Problem Area I do not consider
explicitly the possible existence of capacity mechanisms nor support schemes for RES E,
focusing strictly on the wholesale market operation over the various time frames (day-
ahead, intraday, balancing). Nevertheless, certain assumptions (like priority dispatch for
biomass) would make economic sense only in the case of existing economic subsidies.
Figure 6: Regions used for cooperation in reserve sizing and procurement
Source: METIS
35
"METIS Technical Note T05: METIS market module configuration for Study S12: Focus on day-ahead,
intraday and balancing markets", Artelys and THEMA Consulting (2016).
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Annex IV: Analytical models used in preparing the impact assessment.
Figure 7: DR deployment in METIS for options a, b and c and current practices in
DR participation in balancing markets
Source: METIS
PRIMES/IEM policy scenarios for the options of Problem Area II
PRIMES/IEM scenarios were setup very similarly to the METIS scenarios. As can be
deduced from the description of the model, PRIMES/IEM puts more emphasis on the
simulation of the bidding behaviour of market participants and the modelling of the grid,
thus making it a better tool to capture the additional measures considered in Option 1 of
Problem Area II (on top of Option 1(c) of Problem Area I), i.e. the removal of low price
caps and the addition of locational price signals.
The consideration of market participant bidding behaviour and internal grid congestion,
made it necessary to re-run the baseline (Option 0) also of Problem Area I under these
new assumptions, in order to be used as the baseline of Problem Area II, with one caveat:
similar to METIS, PRIMES/IEM cannot model CMs. On one hand this implies an
underestimation of the benefits of the energy only market (Option 1) related to the more
efficient operation of the system. On the other hand the modelled baseline could not be
used for the comparison with Options 2 and 3. The approach followed to resolve this
issue is described in the next section.
In order to enrich the analysis, and provide more comparability with the analysis
performed for Problem Area I, it was decided to run also Options 1(a) (level playing
field) and Option 1(b) (strengthening short-term markets) of Problem Area I. For the
better understanding of the reader, the construction of these options is presented in a
similar manner as for the METIS scenarios, highlighting that Option 0 corresponds to the
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Annex IV: Analytical models used in preparing the impact assessment.
baseline and Option 1(c) to Option 1 of Problem Area II. Options 1(a) (level playing
field) and 1(b) (strengthening short-term markets) do not correspond to any specific
option of Problem Area II, but are presented for completeness. The identification and
methodology for the quantification of current practices was supported by the same study
used for the METIS modelling.
Table 5: Overview of MDI impact assessment Problem Area II scenarios as
modelled by PRIMES/IEM (read in conjunction with Table 4)
Action Field
MDI options
0 1(a) 1(b) 1
1 DR deployment a b b c
2 RES E priority dispatch a b c d
3 Day-ahead and intraday liquidity a b c c
4 Intraday coupling a b c c
5 Reserve dimensioning a b c c
6 Reserve procurement methodology a a b b
7 Use of NTC and bidding zones assumption a a b b
8 Price Caps a b b b
Source: PRIMES/IEM
Table 6: Overview of the sub-options for each measure modelled in METIS
Measure Topic Description of the options
1 DR deployment
Three levels of DR deployment (sub-options a, b and c, with increasing
economic potential, based on COWI BAU and PO2 scenarios) were
considered. Assumptions were similar to METIS. As load shifting and
load reductions could be captured in PRIMES/IEM, DR was modelled
also for the day-ahead (not only for balancing / reserves as in METIS).
2
RES E priority
dispatch
Four sub-options were considered:
a. Priority dispatch for must take CHP, RES E, biomass and
small-scale RES E
b. As in (a), but biomass bids at marginal costs.
c. As in (b), with no priority dispatch of RES E except small
scale. RES E bidding at marginal costs minus FIT (wherever
applicable).
d. As in (c) but with no priority of small-scale RES E thanks to
aggregators.
Note that removal of priority dispatch is assumed to imply balance
responsibility and capability to participate in intraday and offer
balancing services. Thus for sub-option (d) all resources participate in
intraday, offer balancing services and have balancing responsibilities.
3
Day-ahead and
intraday liquidity
Three options were considered:
a. Low liquidity. DAM covers part of the load, with many
bilateral contracts nominated. ID illiquid in certain countries, in
which case TSO has significant RR.
b. Improved liquidity. DAM covers the large majority of the load,
no nominations. ID illiquid in certain countries, in which case
TSO has significant RR.
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Annex IV: Analytical models used in preparing the impact assessment.
Measure Topic Description of the options
c. Liquid markets. DAM covers the whole load. Liquid and
harmonised ID markets.
4 Intraday coupling
Three options were considered:
a. Very limited participation of flows over interconnectors (as
available capacity for intraday is restricted to the minimum –
defined by country)
b. Limited participation of flows over interconnectors
c. Entire physical capacity of interconnectors allocated to IDM
and flow-based allocation of capacities, after taking into
account remaining capacity of interconnectors.
5
Reserve
dimensioning
Reserve was sized exogenously (own calculations). Three options were
considered:
a. High reserve requirements (national)
b. High reserve requirements (national) but slightly reduced than
in Option 0
c. EU-wide reserve requirements (nonetheless taking into account
areas systematically congested)
6
Reserve
procurement
methodology
The options were:
a. Current practices
b. Day-ahead procurement(which was modelled in PRIMES/IEM
as a joint optimization of power and reserve day-ahead
procurement)
7
Use of NTC and
bidding zones
assumption
Two options were considered:
a. Restrictive ATC (NTC – bilateral contracts – TSO reserves) –
defined by country. National Bidding Zones (NTC values are
given on existing border basis)
b. Entire physical capacity of interconnectors allocated to DAM
and flow-based allocation of capacities
8 Price Caps
Two options:
a. Reflecting current practices
b. Equal to VoLL, being the same for all Member States.
Source: PRIMES/IEM
PRIMES/OM policy scenarios for the options of Problem Area II
As already discussed in the previous section, the technical difficulty to model
simultaneously specific wholesale market measures (removal of low price caps,
locational signals for investments) with the issues on the coordination of CMs led to a
two-step approach:
- Initially PRIMES/IEM was used to model Option 0 and Option 1 of Problem
Area II. This was sufficient to show the benefit of Option 1.
- Subsequently PRIMES/OM was used to model Options 1 to 3 of Problem Area II,
but not Option 0, this time the focus being on CMs. Comparison was performed
among these three Options.
Due to the limitations of PRIMES/OM, all the detailed measures and assumptions under
Option 1 could not be captured. Concerning bidding behaviour, the same approach as in
PRIMES/IEM was followed. Table 7 presents a short comparison of the main results
related to power generation for 2030 for the three models (PRIMES, PRIMES/IEM and
PRIMES/OM).
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Annex IV: Analytical models used in preparing the impact assessment.
Table 7: Comparison of results for PRIMES EUCO27, PRIMES/IEM Option 1(b)
and PRIMES/OM Option 1 for 2030.
PRIMES
EUCO27
PRIMES/IEM
Option 1(b)
PRIMES/OM
Option 1
Net Installed Power Capacity (in MWe) 1,131,045
as in
EUCO27
1,094,290
Nuclear energy 109,905 109,905
Hydro (pumping excluded) 133,335 133,335
Wind on-shore 246,064 246,064
Wind off-shore 37,949 37,949
Solar 233,813 233,813
Biomass-waste fired 53,073 53,073
Other renewables 2,079 2,066
Solids fired 99,396 80,844
Oil fired 15,304 15,930
Gas fired 200,127 181,312
Net generation by plant type (in GWh) 3,396,680 3,339,769 3,378,950
Nuclear energy 738,363 678,318 737,365
Hydro (pumping excluded) 375,138 364,089 375,020
Wind on-shore 564,407 552,893 564,539
Wind off-shore 127,334 126,953 127,388
Solar 303,625 266,644 299,070
Biomass-waste fired 238,108 231,813 200,828
Other renewables 9,732 9,732 9,268
Solids fired 448,640 368,460 469,182
Oil fired 14,572 28,81636
11,754
Gas fired 576,760 712,051 584,537
Source: PRIMES
Apart from the differences in the installed capacities for solids and gas plants, explained
in more detail in Section 6.2.6.3, the main difference is the increased generation of gas
plants in detriment of solids and nuclear in PRIMES/IEM, most likely due to the better
capturing of the flexibility needs of the system.
With Option 1 described above, Options 2 and 3 assume on top the inclusion of CMs for
specific countries. Both Options assume CMs only in the case of Member States
foreseeing adequacy problems in their markets. Therefore certain Member States needed
to be chosen indicatively for this role. For the scope of this assessment, four countries
were assumed to be in the need of a CM: France, Ireland, Italy and UK. This assumption
was not based on a resource adequacy analysis, but on the CMs examined under DG
COMP's Sector Inquiry, focusing specifically on countries with market-wide CMs.
When a country was assumed to have a CM in place, it was assumed that generators no
longer followed scarcity pricing bidding behaviour, but shifted to marginal cost bidding.
36
As the reported technology categories of PRIMES do not entirely match PRIMES/IEM, for
PRIMES/IEM the reported figure in the table for oil fired generation includes peak units, steam
turbines (both oil and gas) as well as CHP with oil as main fuel.
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Annex IV: Analytical models used in preparing the impact assessment.
Therefore in Options 2 and 3 a hybrid market was considered for EU28, with 24 Member
States having an energy only market (with scarcity pricing behaviour), while 4 Member
States having and energy market (with marginal pricing behaviour) supplemented with a
capacity mechanism.
Finally the only difference between Options 2 and 3, is that in Option 3 the CM is
assumed to include rules foreseeing explicit participation of cross-border capacities.
Cross-border capacities were assumed to participate to a CM up to a certain upper bound.
The main idea for this calculation of this upper bound was similar to the concept of
unforced available capacity, which is used in CMs for the generation capacities. Note
though that using this concept for calculating unforced available capacity (or de-rated
capacity) of interconnectors during system stress times is more complex because the
probability of non-delivery is not due only to technical factors but it is mainly due to
congestion factors, which can considerably vary depending on power trade circumstances
during system stress times. To do this calculation it was necessary to dispose simulation
results of the operation of the multi-country system. Alternatively, the calculation could
be based on statistical data on system operation in past years. In both cases, the
simulation requires calculation of power flows over the interconnection system.
Data collection and data gaps
The modelling performed for the impact assessment had significant data requirements.
For example METIS requires about twenty different types of data (such as installed
capacities, variable costs, availabilities, load factors and such). Depending on the type of
simulation, over 25 million individual data points can be required for each single test
case, mostly coming from hourly data (such as hourly national demands). For the NTUA
models an ever larger set of data was required (multiple times larger), as PRIMES covers
the whole European energy sector and all existing or emerging technologies, from
household appliances to industrial processes and means of transport. The respective data
were collected from public and commercial databases, as well as DG ENER EMOS
database.
Moreover, in order to assess the impact of various measures and regulations aimed at
improving the market functioning, one needs to compare the market outcome in the
distorted situation, i.e. under current practices, with the market outcome after the
implementation of new legislative measures. These distortions should be based on the
current situation and practices and form the baseline for the impact assessment.
For this purpose the Commission requested assistance in the form of a study providing
the necessary inputs, i.e. facts and data for the modelling of the impacts of removal of
current market distortions. Although a significant amount of data was collected, a large
number of desired data sets was either unavailable or undisclosed. This unavailability of
data sometimes applied only for specific Member States for certain series, creating
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Annex IV: Analytical models used in preparing the impact assessment.
difficulties in using the collected data for the rest of the Member States. In these cases
proxies need to be defined that could fill in the data gaps37
.
Modelling limitations
Every model is a simplification of reality. Thus, a model itself is not able to capture all
features and facets of the real world. While one may be tempted to include as many
features and options as possible, one has to be careful in order to avoid over-complication
of models. This can very quickly result in overfitting (i.e. modelling relationships and
cause and effects that do in this way not apply to reality, but yielding a better fit), and
transparency issues (i.e. understanding in the end not the model results, or drawing
wrong conclusions). It is therefore essential to find the right balance between complexity
and transparency, taking the strengths and weakness of each modelling approach into
account.
For these reasons, considering the limitations of each modelling approach, a number of
compromises were made. There was an effort these compromises to retain the complexity
of the modelling at the lowest possible level, in order to allo interpretability of results.
The aforementioned study on market distortions also contributed in identifying the best
modelling approaches to capture all major distortions.
One should also expect that the different models used, although all of them focus on the
power sector, can produce different results due to the varying methodological approaches
followed. As long as these differences are well-founded on the underlying methodology
and scope of each model, while being based on the same underlying assumptions and
input data, they can be considered as complementary, as they give a better overview of
the impacts of the various policy options and help producing a more robust assessment.
37
"Electricity Market Functioning: Current Distortions, and How to Model their Removal", COWI
(2016).
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Annex IV: Analytical models used in preparing the impact assessment.
Tool
Concerned
Main Modelling Limitations
Leading to a possible overestimation of
benefits
Leading to a possible underestimation of
benefits
With an unclear effect
METIS &
PRIMES/IEM
The baseline assumes current practices for a number
of market design related measures and policies, not
considering their possible evolution and the expansion
of existing initiatives.
As the situation is very unclear how these will
advance in the coming years, and since modelling
requires a specific assumption for each of these
measures, it was decided for these cases (e.g. DR
participation in the markets) to reflect a more
pessimistic view, where only few advancements are
made. In this respect the costs of the baseline are quite
likely overestimated.
The detrimental effects of capacity mechanisms or
support schemes for RES E to the efficiency of the
electricity market operation over the various time
frames, as well as the external costs to the power
system (in relation to the energy market), were not
considered.
Still these are touched in Problem Area II and the
RED II impact assessment, as well as strong
indication on the impacts of RES E subsidies can be
deduced by the effect of the removal of priority
dispatch for biomass plants.
The softer approach used for the modelling of
priority dispatch of variable RES E (wind, solar)
underestimates the relevant cost of the baseline
scenario. Similarly for the balancing responsibility,
where H-2 forecasts for RES E are used, even when
balance responsibility is not assumed to apply to
them.
METIS did not model CHP and small scale RES E
separately, which would further enhance the impacts
of priority dispatch, currently assessed only for
biomass.
Modelling of the day-ahead and reserve procurement is
based on the so-called co-optimization of energy and
reserves. This approach was the one implemented for
simplicity and transparency. At the same time though it
does lead to the optimal scheduling of units. This on one
hand underestimates the costs of the baseline (in the case
of METIS), but at the same time possibly over-estimates
the benefits of the policy options.
Still overall the specific choice should not be considered
pivotal. Well-designed markets should lead to the same
efficient operation of the power system. Liquid intraday
and balancing markets should optimize operation and
resolve possible infeasibility issues resulting from the DA
schedule.
METIS
The yearly dimensioning and procurement of reserves
overestimates the cost of current practices, not even
considering their possible evolution, based on which
are very likely to be brought even closer to real time in
the coming years.
This is partially compensated by assuming that
dimensioning is performed based on the more accurate
probabilistic approach (despite currently performed in
many Member States based on the deterministic one).
Also by the fact that in all sub-options dimensioning
of mFRR and FCR does not vary (thus no benefits are
reported for this).
The issue of the limited liquidity currently observed
in intraday and balancing markets is not captured in
the modelling. Thus METIS assumed that markets
would be liquid in 2030, which may very well be
indeed the case without any policy action. Note
though that in certain Member States these markets
may not even exist today,
Continuous intraday trading was modelled as consecutive
hourly implicit auctions.
METIS Even in the baseline, interconnector capacity is The assumed effect of the measures on the interconnector
314
Annex IV: Analytical models used in preparing the impact assessment.
Tool
Concerned
Main Modelling Limitations
Leading to a possible overestimation of
benefits
Leading to a possible underestimation of
benefits
With an unclear effect
assumed to be allocated and used relatively
efficiently.
Moreover the absence of network modelling implied
that all relevant (and in many cases significant) costs
were not considered, especially related to internal
congestion (within Member States).
capacities (i.e. the increase of NTC capacities) for the
various options was performed in a stylized manner. It was
based on very rough estimations due to the significant lack
of relevant data.
METIS
DR was modelled as if participating only in
balancing markets and reserves, but not in day-ahead
/ intraday.
Benefits from load shifting or load reductions were
not assessed due to the lack of sufficient detailed
data.
A standard load profile was used for demand, based
on ENTSO-E's TYNDP 2016 assumptions. A
dynamic profile for demand and storage would better
capture the reactions of demand to market prices
(and the associated benefits).
Stylized modelling approach concerning costs of DR.
METIS
Competition issues, effects of nominations and
block-bids, as well as possible strategic behaviour of
the market participants were not considered. On the
contrary, perfect competition was assumed based on
marginal pricing.
PRIMES/IEM
& PRIMES/OM
Assumed bidding behaviour on behalf of market
participants was not considered very aggressive, with
the electricity price rarely reaching the price caps.
Modelling required a significant amount of inputs and
exogenous assumptions, e.g. on market behaviour etc.,
with data not necessarily available (generally, not just
publicly).Moreover significant amount of data (e.g.
detailed data on RR, nominations, technical details on the
transmission grid) were missing, so had to be estimated by
the modellers. Thus results are quite dependant on these
inputs. Still every effort was made to confirm assumptions
based on currently observed market operation data.
PRIMES/OM
The fact that the baseline does not capture the
possible overcapacity in the power markets, e.g. due
to existing CMs or RES E support schemes or due to
unrealised forecasts of the market participants, takes
The selection of the countries assumed to have a CM may
be influencing the results (in an uncertain direction). Each
combination of countries could possibly lead to different
results.
315
Annex IV: Analytical models used in preparing the impact assessment.
Tool
Concerned
Main Modelling Limitations
Leading to a possible overestimation of
benefits
Leading to a possible underestimation of
benefits
With an unclear effect
away part of the benefits that would be realised from
well-functioning markets (and CMs). For this reason a sensitivity was performed assuming the
existence of CMs for all countries, and then performing
the comparison of Options 2 and 3 in this context.
316
Annex IV: Analytical models used in preparing the impact assessment.
317
Annex V: Evidence and external expertise used
Annex V: Evidence and external expertise used
The present impact assessment is based on a large body of material, all of which is
referenced in the footnotes. A number of studies have however been conducted mainly or
specifically for this impact assessment. These are listed and described further in the table
below.
The Commission (DG Competition) has also been conducting a sector inquiry into
national capacity mechanisms and organised Working Groups with Member States with a
view to help them implement the provisions in the EEAG related to capacity mechanisms
and to share experience in the design of capacity mechanisms38
.
38
http://ec.europa.eu/competition/sectors/energy/state_aid_to_secure_electricity_supply_en.html
318
Annex V: Evidence and external expertise used
Study
Study serve to study/substantiate
impact of
Contractor Published
METIS
Study 12: Assessing Market Design
Options in 2030.
Assessing elements for upgrading the market
(all options under Problem Area I) with a focus
on the more efficient operation of the power
system:
- Removing Market Distortions
- Allocating interconnection capacity
across time frames
- Procurement and Sizing of Balancing
Reserves
Impacts of the participation of Distributed
Generation in the market
Modelling tool DG ENER/METIS
Consortium
To be published39
METIS
Study 04: Stakes of a common approach
for generation and system adequacy.
Assessing the benefits from a coordinated
approach in Generation and System Adequacy
Analysis
Modelling tool DG ENER/METIS
Consortium
To be published
METIS
Study 16: Weather-driven revenue
uncertainty for power producers and ways to
mitigate it .
Effect of weather related uncertainty to
revenues. Capacity savings due to cooperation.
CM coordination/cross-border participation.
Modelling tool DG ENER/METIS
Consortium
To be published
METIS
Technical Note T04: Methodology for the
integration of PRIMES scenarios into
METIS.
Technical note providing details on the
methodological approach followed with METIS.
METIS Consortium To be published
METIS
Technical Note T05: METIS market module
Technical note providing details on the METIS Consortium / Thema
To be published
39
Once operational, the envisaged link is expected to be the following: https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis. Same applies for all METIS studies.
319
Annex V: Evidence and external expertise used
Study
Study serve to study/substantiate
impact of
Contractor Published
configuration for Study S12 - Focus on day-
ahead, intraday and balancing markets.
methodological approach followed with METIS. Consulting
"Methodology and results of modelling the
EU electricity market using the
PRIMES/IEM and PRIMES/OM models"
A. Assessing elements for upgrading the market
(main options under Problem Area I) with a
focus on the revenues for the market players,
including:
- Scarcity pricing
- Bidding Zones
B. Assessing investment incentives and the
need for coordination of CMs:
- Profitability of power generation
investments
Coordination of CMs
NTUA To be published
Electricity Market Functioning: Current
Distortions, and How to Model Their
Removal
Impact removing market distortions:
- Identifying market distortions
Providing data input and support for the
modelling
COWI / Thema / NTUA To be published
Framework for cross-border participation in
capacity mechanisms
CM cross-border arrangements COWI/Thema/NTUA To be published
Transmission tariffs and Congestion income
policies
Options for locational signals/regulatory
framework IC construction
Trinomics To be published
320
Annex V: Evidence and external expertise used
Study
Study serve to study/substantiate
impact of
Contractor Published
Integration of electricity balancing markets
and regional procurement of balancing
reserves
Main study supporting Balancing Guidelines
IA. For MDI: regional sizing and procurement
balancing reserves40
COWI/Artelys To be published
Impact Assessment support Study on
downstream flexibility, demand response
and smart metering
Costs and benefits of measures to remove
market barriers to demand response and make
dynamic price tariffs more accessible
COWI / ECOFYS / THEMA /
VITO
To be published
Study on future European electricity system
operation Future model TSO collaboration Ecorys, DNV-GL,ECN
https://ec.europa.eu/energy/sites/ener/files/documents/
15-
3071%20DNV%20GL%20report%20Options%20for
%20future%20System%20Operation.pdf
System adequacy assessment Methodology for system adequacy assessments JRC To be published
Identification of Appropriate Generation
and System Adequacy Standards for the
Internal Electricity Market
System adequacy standards practises and
methods
Mercados, E-bridge, ref4e
https://ec.europa.eu/energy/sites/ener/files/documents/
Generation%20adequacy%20Final%20Report_for%2
0publication.pdf
Impact assessment support study on:
“Policies for DSOs, Distribution Tariffs and
Data Handling”
Cost and benefits of different options
concerning DSO roles, distribution network
tariffs, data handling models
Copenhagen Economics, and VVA To be published
Second Consumer Market Study on the
functioning of retail electricity markets for
consumers in the EU
Billing information; contract exit fees; price
comparison tools; disclosure and guarantees of
origin
Ipsos, London Economics, and
Deloitte
To be published
National policies on security of electricity
supply
Review of current national rules and practices
relating to risk preparedness in the area of
security of electricity supply
VVA Consulting & Spark
https://ec.europa.eu/energy/sites/ener/files/documents/
DG%20ENER%20Risk%20preparedness%20final%2
0report%20May2016.pdf
Measures to protect vulnerable consumers
in the energy sector: an assessment of
disconnection safeguards, social tariffs and
financial transfers
Removing market distortions by phasing-out
regulated prices
Appraisal of disconnection safeguards across
the EU.
INSIGHT_E To be published
40
Examines in more detail issues that are going to be examined also on METIS Study S12.
321
Annex V: Evidence and external expertise used
Study
Study serve to study/substantiate
impact of
Contractor Published
Energy poverty and vulnerable consumers
in the energy sector across the EU: analysis
of policies and measures
Review of measures to protect energy poor and
vulnerable consumers
INSIGHT_E
https://ec.europa.eu/energy/sites/ener/files/documents/
INSIGHT_E_Energy%20Poverty%20-
%20Main%20Report_FINAL.pdf
Selecting indicators to measure energy
poverty
Review, appraisal and computation of indicators
to measure energy poverty
Trinomics, University College
London, and 7Seven
https://ec.europa.eu/energy/sites/ener/files/documents/
Selecting%20Indicators%20to%20Measure%20Energ
y%20Poverty.pdf
Fuel poverty in the European Union: a
concept in need of definition?
Critical assessment of the pros and cons of an
energy poverty definition at the EU level
Harriet Thomson, Carolyn Snell
and Christine Liddell
http://extra.shu.ac.uk/ppp-online/wp-
content/uploads/2016/04/fuel-poverty-european-
union.pdf
The role of DSOs in a Smart Grid
environment
Assessment of the future role of DSOs in
specific activities
ECN & Ecorys
https://ec.europa.eu/energy/sites/ener/files/documents/
20140423_dso_smartgrid.pdf
Study on the effective integration of
Distributed Energy Resources for providing
flexibility to the electricity system
Assessment of distributed energy resources and
their effectiveness in providing flexibility to the
energy system
PwC, Sweco, Ecofys, Tractebel
https://ec.europa.eu/energy/sites/ener/files/documents/
5469759000%20Effective%20integration%20of%20
DER%20Final%20ver%202_6%20April%202015.pdf
From Distribution Networks to Smart
Distribution Systems: Rethinking the
Regulation of European Electricity DSOs
Assessment of the DSO role in the context of
four regulatory areas including remuneration,
network tariff structure and DSO activities
THINK
http://www.eui.eu/projects/think/documents/thinktopi
c/topic12digital.pdf
Options on handling Smart Grids Data
Description of different data handling options
for smart grids
EC Smart Grids Task Force
https://ec.europa.eu/energy/sites/ener/files/documents/
xpert_group3_first_year_report.pdf
Regulatory Recommendations for the
Deployment of Flexibility
Description of the flexibility context,
commercial and regulatory arrangements,
incentives for the development of flexibility,
policy recommendations
EC Smart Grids Task Force
https://ec.europa.eu/energy/sites/ener/files/documents/
EG3%20Final%20-%20January%202015.pdf
Identifying energy efficiency improvements
and saving potential in energy networks and
demand response
Analysis of different options for improving
efficiency in energy networks according to
Article 15 of the EED
Tractebel, Ecofys
https://ec.europa.eu/energy/sites/ener/files/documents/
GRIDEE_4NT_364174_000_01_TOTALDOC%20-
%2018-1-2016.pdf
Study on tariff design for distribution
systems
Benchmarking of different distribution tariff
structures and levels for electricity and gas
across EU
AF Mercados, refE, Indra
https://ec.europa.eu/energy/sites/ener/files/documents/
20150313%20Tariff%20report%20fina_revREF-
E.PDF
322
Annex V: Evidence and external expertise used
This page was deliberately left empty
323
Annex VI: Evaluation
Annex VI: Evaluation
The evaluation is presented as a self-standing document.
324
Annex VI: Evaluation
This page was deliberately left empty
325
Annex VII: Overview of electricity network codes and guidelines
Annex VII: Overview of electricity network codes and guidelines
This annex provides an overview of electricity network codes and guidelines adopted or
envisaged under Articles 6, 8 and 18 of the Electricity Regulation as well as a brief
description to the present initiative, if any.
326
Annex VII: Overview of electricity network codes and guidelines
Electricity network codes
and guidelines adopted or
envisaged under Articles
6, 8 and 18 of the
Electricity Regulation
State of play Brief description of contents
I
Link to MD
Commission Regulation
establishing a Guideline on
capacity allocation and
congestion management
Adopted on 24 July
2015
Legal implementation of day-ahead
and intraday market coupling, flow-
based capacity calculation
Linked to short-term
markets
For more details, see
Annex 2.2
Commission Regulation
establishing a Network code on
requirements for grid connection
of generators
Adopted on 14 April
2016
Defines the necessary technical
capabilities of generators in order to
contribute to system safety and to
create a level playing field.
No direct link with MD
Commission Regulation
establishing a Network Code on
High Voltage Direct Current
Connections and DC-connected
Power Park Modules
Adopted on 26 August
2016
Technical connection rules for
HVDC lines, e.g. used for
connections of offshore wind farms
No direct link with MD
Commission Regulation
establishing a Network code on
demand connection
Adopted on 17 August
2016
Defines the necessary technical
specifications of demand units
connected to a grid and DSOs in
order to contribute to system safety
and to create a level playing field.
Link to demand response
and to measures on
ancillary services For
more details, see Annex
3.1
Commission Regulation
establishing a Guideline on
Forward Capacity Allocation
Adopted on 26
September 2016
Creation of hedging opportunities for
the electricity market; important to
facilitate cross-border trade; capacity
to be allocated through auctions on a
central booking platform;
harmonisation of capacity products
Link to short-term
markets, scarcity pricing
and locational signals.
See Annexes 2.2, 4.1,
4.2
Commission Regulation
establishing a Guideline on
electricity transmission System
Operation
Text voted favourably
by MS on 4 May
Target date for
launching scrutiny:
December 2016
Rules to react to system incidents
(TSO interaction when the system
goes beyond acceptable operational
ranges)
Creation of a framework for TSO
cooperation in the preparation of
system operation (i.e. planning ahead
of real time).
Guidance for how TSOs should
create a framework for keeping
system frequency within safe
operational ranges
Linked to TSO
cooperation in the
planning and operation of
transmission systems.
For more details, see
Annex 2.3
Draft Commission Regulation
establishing a Guideline on
Electricity Balancing
('Balancing Guideline')
Target for vote in
comitology: by end
2016
First step to the development of
common merit order lists for the
activation of balancing energy and
the start of a harmonisation of
balancing products.
Linked to procurement
rules and sizing of
balancing reserves.
For more details, see
Annex 2.1
Draft Commission Regulation
establishing a Network code on
Emergency and Restoration
Target for vote in
comitology: first quarter
2017
Defines requirements of the plans to
be adopted by TSOs concerning
procedures to be followed when
blackouts happen
Linked to security of
supply measures.
For more details, see
Annex 6
327
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Annex VIII: Summary tables of options for detailed measures assessed
under each main option
The tables provided here reflect the in-depth assessment made of the options for detailed
measures described in the Annexes to the impact assessment Chapter 1.1 through to 7.6
The manner in which they correspond to the main options assessed in the present document is
set out in Table 6, Table 7, Table 8 and Table 9 in the present document
328
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Measures assessed under Problem Area 1, Option 1(a): level playing field amongst participants and resources
Priority access and dispatch
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain
rules allowing priority
dispatch and priority
access for RES,
indigenous fuels and
CHP.
Abolish priority dispatch and priority
access
This option would generally require full
merit order dispatch for all technologies,
including RES E, indigenous fuels such as
coal, and CHP. It would ensure optimum
use of the available network in case of
network congestion.
Priority dispatch and/or priority access only for emerging
technologies and/or for very small plants:
This option would entail maintaining priority dispatch
and/or priority access only for small plants or emerging
technologies. This could be limited to emerging RES E
technologies, or also include emerging conventional
technologies, such as CCS or very small CHP.
Abolish priority dispatch and introduce clear
curtailment and re-dispatch rules to replace
priority access.
This option can be combined with Option 2,
maintaining priority dispatch/access only for
emerging technologies and/or for very small
plants
Pros
Lowest political
resistance
Efficient use of resources, clearly
distinguishes market-based use of
capacities and potentially subsidy-based
installation of capacities, making subsidies
transparent.
Certain emerging technologies require a minimum number
of running hours to gather experiences. Certain small
generators are currently not active on the wholesale market.
In some cases, abolishing priority dispatch could thus bring
significant challenges for implementation. Maintaining also
priority access for these generators further facilitates their
operation.
As Option 1, but also resolves other causes for
lack of market transparency and discrimination
potential. It also addresses concerns that
abolishing priority dispatch and priority access
could result in negative discrimination for
renewable technologies.
Cons
Politically, it may be criticized that
subsidized resources are not always used if
there are lower operating cost alternatives.
Adds uncertainty to the expected revenue
stream, particularly for high variable cost
generation.
Same as Option 1, but with less concerns about blocking
potential for trying out technological developments and
creating administrative effort for small installations.
Especially as regards small installations, this could
however result in significant loss of market efficiency if
large shares of consumption were to be covered by small
installations.
Legal clarity to ensure full compensation and
non-discriminatory curtailment may be
challenging to establish. Unless full
compensation and non-discrimination is
ensured, priority grid access may remain
necessary also after the abolishment of priority
dispatch.
Most suitable: Option 3. Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to actively
participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should be
combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or emerging
technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.
329
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Regulatory exemptions from balancing responsibility
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated,
thus ensuring that the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances
caused.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain the status
quo, expressly requiring financial
balancing responsibility only
under the state aid guidelines
which allow for some exceptions.
Full balancing responsibility for all
parties
Each entity selling electricity on the
market has to be a balancing responsible
party and pay for imbalances caused.
Balancing responsibility with exemption
possibilities for emerging technologies
and/or small installations
This would build on the EEAG.
Balancing responsibility, but possibility to
delegate
This would allow market parties to delegate the
balancing responsibility to third parties.
This option can be combined with the other
options.
Pros
Lowest political resistance Costs get allocated to those causing
them. By creating incentives to be
balanced, system stability is increased
and the need for reserves and TSO
interventions gets reduced. Incentives to
improve e.g. weather forecasts are
created.
This could allow shielding emerging
technologies or small installations from the
technical and administrative effort and
financial risk related to balancing
responsibility.
The impact of this option would depend on the
scope and conditions of this delegation. A
delegation on the basis of private agreements,
with full financial compensation to the party
accepting the balancing responsibility (e.g. an
aggregator) generally keeps incentives intact.
Cons
Financial risks resulting from the
operation of variable power generation
(notably wind and solar power) are
increased.
Shielding from balancing responsibilities
creates serious concerns that wrong
incentives reduce system stability and
endanger market functioning. It can
increase reserve needs, the costs of which
are partly socialized. This is particularly
relevant if those exemptions cover a
significant part of the market (e.g. a high
number of small RES E generators).
The impact of this option would depend on the
scope and conditions of this delegation. A full and
non-compensated delegation of risks e.g. to a
regulated entity or the incumbent effectively
eliminates the necessary incentives. Delegation to
the incumbent also results in further increases to
market dominance.
Most suitable: Option 2 combined with the possibility for delegation based on freely negotiated agreements.
330
Annex VIII: Summary tables of options for detailed measures assessed under each main option
RES E access to provision of non-frequency ancillary services
Objective: transparent, non-discriminatory and market based framework for non-frequency ancillary services
Option 0 Option 1 Option 2
BAU
Different requirements, awarding procedures and
remuneration schemes are currently used across MS.
Rules and procedures are often tailored to conventional
generators and do not always abide to transparency,
non-discrimination. However increased penetration of
RES displaces conventional generation and reduces the
supply of these services.
Description
Set out EU rules for a transparent, non-discriminatory and
market based framework to the provision of non-frequency
ancillary services that allows different market players
/technology providers to compete on a level playing field.
Description
Set out broad guidelines and principles for MS for the adoption of
transparent, non-discriminatory and market based framework to the
provision of non-frequency ancillary services.
Stronger enforcement
Provisions containing reference to transparency, non-
discrimination are contained in the Third Package.
However, there is nothing specific to the context of
non-frequency ancillary services.
Pro
Accelerate adoption in MS of provisions that facilitate the
participation of RES E to ancillary services as technical
capabilities of RES E and other new technologies is available,
main hurdle is regulatory framework.
Clear regulatory landscape can trigger new revenue streams
and business models for generation assets.
Pro
Sets the general direction and boundaries for MS without being too
prescriptive.
Allows gradual phase-in of services based on local/regional needs
and best practices.
Con
Resistance from MS and national authorities/operators due to
the local/regional character of non-frequency ancillary
services provided.
Little previous experience of best practices and unclear how
to monitor these services at DSO level where most RES E is
connected.
Con
Possibility of uneven regulatory and therefore market developments
depending on how fast MS act. This creates uncertain prospects for
businesses slowing down RES E penetration.
Most suitable option(s): Option 2 is best suited at the current stage of development of the internal electricity market. Ancillary services are currently procured and sometimes used in very
different manners in different Member States, Furthermore, new services are being developped and new market actors (e.g. batteries) are quickly developing. Setting out detailed rules required
for full harmonisation would thus preclude unknown future developments in this area, which currently is subject to almost no harmonisation.
331
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Measures assessed under Problem Area 1, Option 1(b) Strengthening short-term markets
Reserves sizing and procurement
Objective: define areas wider than national borders for sizing and procurement of balancing reserves
Option 0: business as usual Option 1: national sizing and
procurement of balancing reserves on
daily basis
Option 2: regional sizing and procurement of
balancing reserves
Option 3: European sizing and procurement
of balancing reserves
Description
The baseline scenario consists of a
smooth implementation of the
Balancing Guideline. Existing on-
going experiences will remain and be
free to develop further, if so decided.
However, sizing and procurement of
balancing reserves will mainly
remain national, frequency of
procurement as foreseen in the
Balancing Guideline.
Active participation in the Balancing
Stakeholder Group could ensure
stronger enforcement of the
Balancing Guideline.
This option consists in developing a
binding regulation that would require
TSOs to size their balancing reserves on
daily probablistic methodologies. Daily
calculation allows procuring lower
balancing reserves and, together with
daily procurement, enables participation
of renewable energy sources and demand
response.
This option foressees separate
procurement of all type of reserves
between upward (i.e. increasing power
output) and downward (i.e. reducing
power output; offering demand
reduction) products.
This option involves the setup of a binding
regulation requiring TSOs to use regional
platforms for the procurement of balancing
reserves. Therefore this option foresees the
implementation of an optimisation process for
the allocation of transmission capacity between
energy and balancing markets, which then
implies procuring reserves only a day ahead of
real time.
This option would result in a higher level of
coordination betwRReen European TSOs, but
still relies on the concept of local
responsibilities of individual balancing zones
and remains compatible with current
operational security principles.
This option would have a major impact on the
current design of system operation procedures
and responsibilities and current operational
security principles. A supranational independent
system operator ('EU ISO') would be
responsible for sizing and procuring balancing
reserves, cooperating with national TSOs. This
would enable TSOs to reduce the security
margin on transmission lines, thus offering
more cross-zonal transmission capacity to the
market and allowing for additional cross-zonal
exchanges and sharing of balancing capacity.
Pros
Optimal national sizing and procurement
of balancing reserves.
Regional areas for sizing and procurement of
balancing reserves.
Single European balancing zone.
Cons
No cross-border optimisation of
balancing reserves.
Balancing zones still based on national borders
but cross-border optimisation possible.
Extensive standardisation through replacement
of national systems, difficult and costly
implementation.
Most suitable: Option 2. Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the physical
topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the preferred
option.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Removing distortions for liquid short-term markets
Objective: to remove any barriers that exist to liquid short-term markets, specifically in the intraday timeframe, and to ensure distortions are minimised.
Option 0 Option 1 Option 2
Description
Business as usual
Local markets mostly unregulated, allowing for national
differences, but affected by the arrangements for cross-
border intraday and day-ahead market coupling.
Stronger enforcement and volunatry cooperation
There is limited legislation to enforce and voluntary
cooperation would not provide certainty to the market
Fully harmonise all arrangements in local
markets.
Selected harmonisation, specifically on issues relating to gate closure
times and products.
Pros
Simplest approach, and allows the cross-border
arrangements to affect local market arrangements. Likely to
see a degree of harmonisation over time.
Would minimise distortions, with very limited
opportunity for deviation.
Targets issues that are particularly important for maximising liquidity of
short-term markets and allows for participation of demand response and
small scale RES.
Cons
Differences in national markets will remain that can act as a
barrier.
Extremely complex; even the cross-border
arrangements have not yet been decided and
need significant work from experts.
Additional benefit unclear.
May still be difficult to implement in some Member States with
implication on how the system is managed – central dispatch systems
could, in particular, be impacted by shorter gate closure time.
Most suitable: Option 2 – Provides a proportionate response targeting those issues of most relevance.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Improving the coordination of Transmission System Operation
Objective: Stronger coordination of Transmission System Operation at a regional level
Option 0 Option 1 Option 2 Option 3
Description
BAU
Limit the TSO coordination efforts to the
implementation of the new Guideline on
Transmission System Operation (voted at the
Electricity Cross Border Committee in May 2016
and to be adopted by end-2016) which mandates the
creation of Regional Security Coordinators (RSCs)
covering the whole Europe to perform five relevant
tasks at regional level as a service provider to
national TSOs.
Enhance the current set up of existing RSC by
creating Regional Operational Centers (ROCs),
centralising some additional functions at regional
level over relevant geographical areas and
delineating competences between ROCs and
national TSOs.
Go beyond the establishment of ROCs
that coexist with national TSOs and
consider the creation of Regional
Independent System Operators that can
fully take over system operation at
regional level. Transmission
ownership would remain in the hands
of national TSOs.
Create a European-wide
Independent System Operator
that can take over system
operation at EU-wide level.
Transmission ownership would
remain in the hands of national
TSOs.
Pros
Lowest political resistance. Enlarged scope of functions assuming those tasks
where centralization at regional level could bring
benefits
A limited number (5 max) of well-defined regions,
covering the whole EU, based on the grid topology
that can play an effective coordination role. One
ROC will perform all functions for a given region.
Enhanced cooperative decsion-making with a
possibility to entrust ROCs with decision making
competences on a number of issues.
Improved system and market operation
leading to optimal results including
optimized infrastructure development,
market facilitation and use of existing
infrastructure, secure real time
operation.
Seamless and efficient system
and market operation.
Cons
Suboptimal in the medium and long-term. Could find political resistance towards
regionalisation. If key elements/geography are not
clearly enshrined in legislation, it might lead to a
suboptimal outcome closer to Option 0.
Politically challenging. While this
option would ultimately lead to an
enhanced system operation and might
not be discarded in the future, it is not
considered proportionate at this stage
to move directly to this option.
Extremely challenging
politically. The implications of
such an option would need to
be carefully assessed. It is
questionable whether, at least
at this stage, it would be
proportionate to take this step.
Most suitable option(s): Option 1 (Option 2 and Option 3 constitute the long-term vision)
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Measures assessed under Problem Area 1,Option 1(c); Pulling demand response and distributed resources into the market
Unlocking demand side response
Objective: Unlock the full potential of Demand Response
Option O: BAU Option 1: Give consumers access to
technologies that allow them to participate
in price based Demand Response schemes
Option 2: as Option 1 but also fully enable
incentive based Demand Response
Option 3: mandatory smart meter roll out and
full EU framework for incentive based demand
response
Stronger enforcement of existing
legislation that requires MS to roll out
smart meters if a cost-benefit analysis
is positive and to ensure that demand
side resources can participate
alongside supply in retail and
wholesale markets
Give each consumer the right to request the
installation of, or the upgrade to, a smart
meter with all 10 recommended
functionalities.
Give the right to every consumer to request a
dynamic electricity pricing contract.
In addition to measures described under Option
1, grant consumers access to electricity markets
through their supplier or through third parties
(e.g. independent aggregators) to trade their
flexibility. This requires the definition of EU
wide principles concerning demand response
and flexibility services.
Mandatory roll out of smart meters with full
functionalities to 80% of consumers by 2025
Fully harmonised rules on demand response
including rules on penalties and compensation
payments.
No new legislative intervention. This option will give every consumer the
right and the means (fit-for-purpose smart
meter and dynamic pricing contract) to fully
engage in price based DR if (s)he wishes to
do so.
This option will allow price and incentive based
DR as well as flexibility services to further
develop across the EU. Common principles for
incentive based DR will also facilitate the
opening of balancing markets for cross-border
trade.
This guarantees that 80% of consumers across the
EU have access to fully functional smart meters by
2025 and hence can fully participate in price based
DR and that market barriers for incentive based DR
are removed in all MS.
Roll out of smart meters will remain
limited to those MS that have a
positive cost/benefit analysis.
In many MS market barriers for
demand response may not be fully
removed and DR will not deliver to
its potential.
Roll out of smart meters on a per customer
basis will not allow reaping in full system-
wide benefits, or benefits of economies of
scale (reduced roll out costs)
Incentive based demand response will not
develop across Europe.
As for Option 1, access to smart meters and
hence to price based DR will remain limited.
Member States will continue to have freedom to
design detailed market rules that may hinder the
full development of Demand Response.
It ignores the fact that in 11 MS the overall costs of
a large-scale roll out exceed the benefits and hence
that in those MS a full roll out is not economically
viable under current conditions.
Fully harmonised rules on demand response cannot
take into account national differences in how e.g.
balancing markets are organised and may lead to
suboptimal solutions.
Most suitable option(s): Option 2. Only the second option is suited to untap the potential of demand response and hence reduce overall system costs while respecting subsidiarity principles.
The third option is likely to deliver the full potential of demand response but may do so at a too high cost at least in those Member States where the roll out of smart meters is not yet
economically viable. Options zero and one are not likely to have a relevant impact on the development of demand response and reduction of electricity system cost.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Distribution networks
Objective: Enable DSOs to locally manage challenges of energy transition in a cost-efficient and sustainable way, without distorting the market.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding on the detail
tasks of DSOs.
- Allow and incentivize DSOs to acquire flexibility services from distributed
energy resources.
- Establish specific conditions under which DSOs should use flexibility, and
ensure the neutrality of DSOs when interacting with the market or consumers.
- Clarify the role of DSOs only in specific tasks such as data management, the
ownership and operation of local storage and electric vehicle charging
infrastructure.
- Establish cooperation between DSOs and TSOs on specific areas, alongside the
creation of a single European DSO entity.
- Allow DSOs to use flexibility under the conditions set in
Option 1.
- Define specific set of tasks (allowed and not allowed) for
DSOs across EU.
- Enforce existing unbundling rules also to DSOs with less
than 100,000 customers (small DSOs).
Pro
Current framework gives more
flexibility to Member States to
accommodate local conditions in their
national measures.
Pro
Use of flexible resources by DSOs will support integration of RES E in distribution
grids in a cost-efficient way.
Measures which ensure neutrality of DSOs and will guarantee that operators do not
take advantage of their monopolistic position in the market.
Pro
Stricter unbundling rules would possibly enhance competition
in distribution systems which are currently exempted from
unbundling requirements.
Under certain condition, stricter unbundling rules would also
be a more robust way to minimizing DSO conflicts of interest
given the broad range of changes to the electricity system, and
the difficulty of anticipating how these changes could lead to
market distortions.
Con
Not all Member States are integrating
required changes in order to support
EU internal energy market and targets.
Con
Effectiveness of measures may still depend on remuneration of DSOs and regulatory
framework at national level.
Con
Uniform unbundling rules across EU would have
disproportionate effects especially for small DSOs.
Possible impacts in terms of ownership, financing and
effectiveness of small DSOs.
A uniform set of tasks for DSOs would not accommodate
local market conditions across EU and different distribution
structures.
Most suitable option(s): Option 1 is the preferred option as it enhances the role of DSOs as active operators and ensures their neutrality without resulting in excess administrative costs.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Remuneration of DSOs
Objective: A performance-based remuneration framework which incentivize DSOs to increase efficiencies in planning and innovative operation of their networks.
Option: O Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible on deciding on the detailed
framework for remuneration of DSOs.
- Put in place key EU-wide principles and guidance regarding the remuneration of
DSOs, including flexibility services in the cost-base and incentivising efficient
operation and planning of grids.
- Require DSO to prepare and implement multi-annual development plans, and
coordinate with TSOs on such multi-annual development plans.
- Require NRAs to periodically publish a set of common EU performance indicators
that enable the comparison of DSOs performance and the fairness of distribution
tariffs.
- Fully harmonize remuneration methodologies for all
DSOs at EU level.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Performance based remuneration will incentivise DSOs to become more cost-efficient
and offer better quality services.
It would support integration of RES E and EU targets.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards regulatory
schemes which incentivize DSOs and
raise efficiencies.
Con
Detail implementation will still have to be realized at Member State level, which may
reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO remuneration schemes
would not meet the specificities of different distribution
systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective remuneration schemes and enhancing transparency
requirements
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Distribution network tariffs
Objective: Distribution tariffs that send accurate price signals to grid users and aim to fair allocation of distribution network costs.
Option: 0 Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible on deciding on the detailed
distribution tariffs.
- Impose on NRAs more detailed transparency and comparability requirements for
distribution tariffs methodologies.
- Put in place EU-wide principles and guidance which ensure fair, dynamic, time-
dependent distribution tariffs in order to facilitate the integration of distributed
energy resources and self-consumption.
- Harmonization of distribution tariffs across EU; fully
harmonize distribution tariff structures at EU level for all
EU DSOs, through concrete requirements for NRAs on
tariff setting.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Principles regarding network tariffs will increase efficient use of the system and
ensure a fairer allocation of network costs.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards distribution
network tariffs which effectively
allocate costs and accommodate EU
policies.
Con
Detail implementation will still have to be realized at Member State level, which
may reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO structures would not meet
the specificities of different distribution systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective distribution network tariffs and enhancing transparency
requirements
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Improving the institutional framework
Objective: To adapt the Institutional Framework, in particular ACER's decision-making powers and internal decision-making to the reality of integrated regional markets and the
proposals of the Market Design Initiative, as well as to address the existing and anticipated regulatory gaps in the energy market.
Option 0 Option 1 Option 2
Description
Maintain status quo, taking into account that the implementation
of network codes would bring certain small scale adjustments.
However, the EU institutional framework would continue to be
based on the complementarity of regulation at national and EU-
level.
Adapting the institutional framework to the new
realities of the electricity system and to the
resulting need for additional regional cooperation
as well as to addressing existing and anticipated
regulatory gaps in the energy market.
Providing for more centralised institutional structures with
additional powers and/or responsibilities for the involved
entities.
Pros
Lowest political resistance. Addresses the shortcomings identified and
provides a pragmatic and flexible approach by
combining bottom-up initiatives and top-down
steering of the regulatory oversight.
Addresses the shortcomings identified with limited
coordination requirements for institutional actors.
Cons
The implementation of the Third Package and network codes is
not sufficient to overcome existing shortcomings of the
institutional framework.
Requires strong coordination efforts between all
involved institutional actors.
Significant changes to established institutional processes with
the greatest financial impact and highest political resistance.
Most suitable: Option 1, as it adapts the institutional framework to the new realities of the electricity system by adopting a pragmatic approach in combining bottom-up initiatives and top-
down steering of the regulatory oversight.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Measures assessed under Problem Area 2, Option 2(1); Improved energy-only market without CMs)
Removing price caps
Objective: to ensure that prices in wholesale markets are not prevented from reflecting scarcity and the value that society places on energy.
Option 0: Business as usual Option 1: Eliminate all price caps Option 2: Create obligation to set price caps, where they
exist, at VoLL
Description
Existing regulations already require harmonisation of
maximum (and minimum) clearing prices in all price zones to
a level which takes "into account an estimation of the value of
lost load".
Stronger enforcement/non-regulatory approach
Enforceability of "into account an estimation of the value of
lost load" in the CACM Guideline is not strong. Enforcement
action is unlikely to be successful or expedient. Relying on
stronger enforcement would leave considerable more legal
uncertainty to market participants than clarifying the legal
framework directly.
Voluntary cooperation would not provide the market with
sufficient confidence that governments would not step in
restrict prices in the event of scarcity
Eliminate price caps altogether for balancing,
intraday and day-ahead markets.
Removes barriers for scarcity pricing Avoids setting
of VoLL (for the purpose of removing negative
effects of price caps).
Reinforced requirement to set price limits taking "into account
an estimation of the value of lost load"
Allow for technical price limits as part of market coupling,
provided they do not prevent prices rising to VoLL.
Establish requirements to minimise implicit price caps.
Pros
Simple to implement – leaves administration to technical
implementation of the CACM Guideline.
Measure simple to implement; unequivocally and
creates legal certainty.
Compatible with already existing requirement to set price limit,
as provided for undert the CACM regulation, provides concrete
legal clarity
Cons
Difficult to enforce; no clarity on how such clearing prices
will be harmonised. Does not prevent price caps being
implemented by other means.
Can be considered as non-proportional; could add
significant risk to market participants and power
exchanges if there are no limits.
VoLL, whilst a useful concept, is difficult to set in practice. A
multitude of approaches exist and at least some degree of
harmonisation will be required.
Most suitable: Option 2 - this provides a proportionate response to the issue –, it would allow for technical limits as part of market coupling and this should not restrict the markets ability to
generate prices that reflect scarcity..
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Improving locational price signals
Objective: The objective is to have in place a robust process for deciding on the structure of locational price signals for investment and dispatch decisions in the EU electricity
wholesale market.
Option 0 Option 1 Option 2 Option 3
Description
Business as Usual – decision on bidding
zone configuration left to the arrangements
defined under the CACM Guideline or
voluntary cooperation, which has, to date,
retained the status quo .
Move to a nodal pricing system. Introduce locational signals by new means,
i.e. through transmission tariffs.
Improve currently existing the CACM
Guideline procedure for reviewing bidding
zones and introducing supranational
decision-making, e.g. through ACER.
This would be coupled with a strengthened
requirement to avoid the reduction of cross-
zonal capcity in order to resolve internal
congestions.
Pros
Approach already agreed. Theoretically, nodal pricing is the most
optimal pricing system for electricity
markets and networks.
Would unlock alternative means to provide
locational signals for investment and
dispatch decisions.
This improvement will render revisions of
bidding zones a more technical decision.
It will also increase the available cross-
zonal capacity.
Cons
Risks maintenance of the status quo, and
therefore misses the opportunity to address
issues in the internal market.
Nodal pricing implies a complete,
fundamental overhaul of current grid
management and electricity trading
arrangements with very substantial
transition costs.
Incentives would be not be the result of
market signals (value of electricity) but cost
components set by regulatory intervention
of a potentially highly political nature.
Does not address the underlying difficulty
of introducing locational price zones,
namely the difficulties to arrive at decisions
that reflect congestion instead of political
borders.
Does not address a situation where the
results of the bidding zone review are sub-
optimal. I.e. this option only covers
procedural issues.
Most suitable: Option 3 – this option will rely on a pre-established process but improve the decision-making so that decisions take into account cross-border impact of bidding zone
configuration. Other options – e.g. tofundamentally change how locational signals are provided, would be dispropritionate.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Minimise investment and dispatch distortions due to transmission tariff structure
Objective: to minimise distortions on investment and dispatch patterns created by different transmission tariffs regimes.
Option 0: Business as usual Option 1: Restrict charges on producers (G-
charges)
Option 2: Set clearer principles for transmission
charges
Option 3: Harmonisation
transmission tariffs
Description
This option would see the status quo
maintained, and transmission tariffs set
according to the requirements under
Directive 72 and the ITC regulation.
Stronger enforcement and voluntary
cooperation:
There is no stronger enforcement action to
be taken that would alone address the
objective. Voluntary cooperation would, in
part, be undertaken as part of
implementation of Option 2.
This option could see the prohibition of
transmission charges being levied on
generators based on the amount of energy they
generate (energy-based G-charges)
This option would see a requirement on ACER to
develop more concrete principles on the setting of
transmission tariffs, along with an elaboration of
exiting provisions in the electricity regulation where
appropriate.
Full harmonisation of
transmission tariffs.
Pros
Pros: Minimal change; likely to receive
some support for not taking any action in the
short-term.
Eliminating energy-based G-charges would
serve to limit distortionary effects on dispatch
of generation caused by transmission tariffs.
Social welfare benefits of approximately EUR
8 million per year. Would impact a minority of
Member States (6-8 depending on design).
Provides an opportunity to move in the right
direction whilst not risking taking the wrong
decisions or introducing inefficiencies because of
unknowns; consistent with a phased-approach;
could eliminate any potential distortions without the
need to mandate particular solutions; consistent
with the introduction of legally binding provisions
in the future, e.g. through implementing legislation.
Minimises distortion between
Member States on both
investment and dispatch;
creates a level-playing field.
Cons
In the longer-term, likely to be a drive to do
more and maintaining the status quo unlikely
to be attractive; risks of continued
divergence in national approaches.
Social welfare benefits relatively small – could
be outweighed by transitional costs in the
early years. Can be considered 'incomplete' as
a number of other design elements of
transmission tariffs contribute to distortionary
effects.
Still leaves the door open for variation in national
approaches; will not resolve all potential issues.
Unlikely to a proportionate
response to the issues at this
stage; given the technicalities
involved, it could be more
appropriate to introduce such
measures as implementing
legislation in the future.
Most suitable option(s): Option 2 – aside from some high-level requirements, given the complexity of transmission charges, the precise modalities should be set-out as part of implementing
legislation in the future if and when appropriate. The value in Option 2 will be to set the path for the longer-term.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Congestion income spending to increase cross-border capacity
Objective: The objective of any change should be to increase the amount of money spent on investments that maintain or increase available interconnection capacity
Option 0: Business as usual Option 1 Option 2 Option 3
Description
This option would see the current situation
maintained, i.e. that congestion income can be
used for (a) guaranteeing the actual availability
of allocated capacity or (b) maintaining or
increasing interconnection capacities through
network investments; and, where they cannot
be efficiently used for these purposes, taken
into account in the calculation of tariffs.
Stronger enforcement: current rules do not
allow for stronger enforcement.
Voluntary cooperation: would offer no
certainty that the allocation of income would
change.
Further prescription on the use of
congestion income, subjecting its use on
anything other than (a) guaranteeing the
actual availability of allocated capacity or
(b) maintaining or increasing
interconnection capacities (i.e. allowing it
to be offset against tariffs) to harmonised
rules.
Require that any income not used for (a)
guaranteeing availability or (b)
maintaining or increasing interconnection
capacities flows into the Energy part of
CEF-E or its successor, to be spent on
relieving the biggest bottlenecks in the
European electricity system, as evidenced
by mature PCIs.
Transfer the responsibility of using the
revenues resulting from congestion and not
spent on either (a) guaranteeing availability
or (b) maintaining capacities to the
European Commission. De facto all
revenues are allocated to CEF-E or
successor funds to manage investments
which increase interconnection capacity.
Pros
Minimal disruption to the market; consumers
can benefit from tariff reductions – unclear
whether benefits of better channelling income
towards interconnection would provide more
benefits to consumers, given that it may offset
(at least in part) money spent on
interconnection from other sources.
More guarantee that income will be spent
on projects that increase or maintain
interconnection capacity and relieve the
most significant bottlenecks; could provide
around 35% extra spend; approach reflects
the EU-wider benefits of electricity
exchange through interconnectors; can be
linked to the PCI process.
Guarantees that income will be spent on
projects that increase or maintain
interconnection capacity and relieve the
most important bottlenecks; could provide
up to 35% extra spend; approach reflects
the EU-wider benefits of electricity
exchange through interconnectors; firm
link with the PCI process.
Best guarantee that income will be spent on
the biggest bottlenecks in the European
electricity system, ensuring the best deal for
European consumers in the longer run;
approach reflects the EU-wider benefits of
electricity exchange through
interconnectors; to be linked to the PCI
process.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Cons
Missing a potentially significant source of
income which could be spent on
interconnection and removing the biggest
bottlenecks in the EU.
Restricts regulators in their tariff approval
process and of TSOs on congestion income
spending.
Additional reporting arrangements will be
necessary.
Requires stronger role of ACER.
Restricts regulators in their tariff approval
process and of TSOs on congestion
income spending.
Could mean that congestion income
accumulated from one border is spent on a
different border or different MS.
Additional reporting arrangements will be
necessary.
Requires stronger role of ACER.
Could prove complicated to set up such an
arrangement; could mean that congestion
income accumulated from one border is
spent on a different border or different MS.
Requires a decision to apportion generated
income to where needs are highest in
European system. Will face national
resistance.
Will require additional reporting
arrangements to be put in place.
Requires stronger role of ACER.
Most suitable option(s): Option 2 – provides additional funding towards project which benefit the EU internal market as a whole, while still allowing for national decision making in the first
instance. Considered the most proportionate response.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Measures assessed under Problem Area 2, Option 2(2) CMs based on an EU-wide resource adequacy assessment
Improved resource adequacy methodology
Objective: Pan-European resource adequacy assessments
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
National decision makers would continue to
rely on purely national resource adequacy
assessments which might inadequately take
account of cross-border interdependencies.
Due to different national methodologies,
national assessments are difficult to
compare.
Binding EU rules requiring TSOs to
harmonise their methodologies for
calculating resource adequacy +
requiring MS to exclusively rely on them
when arguing for CMs.
Binding EU rules requiring ENTSO-E to
provide for a single methodology for
calculating resource adequacy +
requiring MS to exclusively rely on them
when arguing for CMs.
Binding EU rules requiring ENTSO-E to carry
out a single resource adequacy assessment for
the EU + requiring MS to exclusively rely on it
when arguing for CMs.
Pros
Stronger enforcement:
Commission would continue to face
difficulties to validate the assumptions
underlying national methodologies including
ensuing claims for Capacity Mechanisms
(CMs).
National resource adequacy assessments
would become more comparable.
In addition to benefits in Option 1, it
would make it easier to embark on the
single methodology.
In addition to benefits in Options 1 & 2, it
would make sure that the national puzzles neatly
add up to a European picture allowing for
national/ regional/ European assessments.
Results are more consistent and comparable as
one entity (ENTSO-E) is running the same
model for each country.
Cons
Even in the presence of harmonised
methodologies national assessment
would not be able to provide a regional
or EU picture.
Even in the presence of a single
methodology, national assessments
would not be able to provide a regional
or EU picture.
National TSOs might be overcautious
and not take appropriately cross-border
interdependencies into account.
Difficult to coordinate the work as the
EU has 30+ TSOs.
It would potentially reduce the 'buy-in' from
national TSOs who might still be needed for
validating the results of ENTSO-E's work.
Most suitable option(s): Option 3 - this approach assesses best the capacity needs for resource adequacy and hence allows the Commission to effectively judge whether the proposed
introduction of resource adequacy measures in single Member States is justified.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Cross-border operation of capacity mechanisms
Objective: Framework for cross-border participation in capacity mechanisms
Option 0 Option 1 Option 2
Description
Do nothing.
No European framework laying out the details of an effective cross-
border participation in capacity mechanisms. Member States are likely
to continue taking separate approaches to cross-border participation,
including setting up individual arrangements with neighbouring
markets.
Harmonised EU framework setting out procedures including roles
and responsibilities for the involved parties (e.g. resource
providers, regulators, TSOs) with a view to creating an effective
cross-border participation scheme.
Option 1 + EU framework harmonising
the main features of the capacity
mechanisms per category of
mechanism (e.g. for market-wide
capacity mechanisms, reserves, …).
Pros
Stronger enforcement
The Commission's Guidance on state interventions41
and the EEAG
require among others that such mechanisms are open and allow for the
participation of resources from across the borders. There is no reason to
believe that the EEAG framework is not enforced. To date, however,
there are not many practical examples of such cross-border schemes.
It would reduce complexity and the administrative impact for
market participants operating in more than one MS/bidding zone.
It would remove the need for each MS to design a separate
individual solution – and potentially reduce the need for bilateral
negotiations between TSOs and regulators.
It would preserve the properties of market coupling and ensure that
the distortions of uncoordinated national mechanisms are corrected
and internal market able to deliver the benefits to consumers.
In addition to benefits in Option 1, it
would facilitate the effective
participation of foreign capacity as it
would simplify the design challenge
and would probably increase overall
efficiency by simplifying the range of
rules market participants, regulators
and system operators have to
understand.
Cons
As the conclusion of individual cross-border arrangements depend on
the involved parties' willingness to cooperate it is likely that this option
will cement the current fragmentation of capacity mechanisms.
Arranging cross-border participation on individual basis is likely to
involve high transaction costs for all stakeholders (TSOs, regulators,
ressource providers).
It would be a cost for TSOs and regulators which would have to
agree on the rules and enforce them across the borders. These
costs would be lower than in Option 0 though.
In addition to the drawback of Option
1, it would limit the choice of
instruments.
Most suitable Option(s): Options 1 and 2
41
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Options for measures assessed under Problem Area 3: a new legal framework for preventing and managing crises situations
Objective: Ensure a common and coordinated approach to electricity crisis prevention and management across Member States, whilst avoiding undue government intervention
Option 0: Do nothing Option 0+: Non-
regulatory
approach
Option 1: Common minimum EU
rules for prevention and crisis
management
Option 2: Common minimum EU rules plus regional
cooperation, building on Option 1
Option 3: Full
harmonisation and full
decision-making at regional
level, building on Option 2
- This option was
disregarded as no
means for enhanced
implementation of
the existing acquis
nor for enhanced
voluntary
cooperation were
identified
-
Assessments
Rare/extreme risks and
short-term risks related
to security of supply are
assessed from a national
perspective.
Risk identification &
assessment methods
differ across Member
States.
- - Member States to identify and assess
rare/extreme risks based on common
risk types.
-
ENTSO-E to identify cross-border electricity crisis
scenarios caused by rare/extreme risks, in a regional
context. Resulting crisis scenarios to be discussed in the
Electricity Coordination Group.
Common methodology to be followed for short-term risk
assessments (ENTSO-E Seasonal Outlooks and week-
ahead assessments of the RSCs).
All rare/extreme risks
undermining security of
supply assessed at the EU
level, which would be
prevailing over national
assessment.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Plans
Member States take
measures to prevent and
prepare for electricity
crisis situations
focusing on national
approach, and without
sufficiently taking into
account cross-border
impacts.
No common approach
to risk prevention &
preparation (e.g., no
common rules on how
to tackle cybersecurity
risks).
a)
- - Member States to develop mandatory
national Risk Preparedness Plans
setting out who does what to prevent
and manage electricity crisis situations.
-
- Plans to be submitted to the
Commission and other Member States
for consultation.
-
- Plans need to respect common
minimum requirements. As regards
cybersecurity, specific guidance would
be developed.
Mandatory Risk Preparedness Plans including a national
and a regional part. The regional part should address
cross-border issues (such as joint crisis simulations, and
joint arrangements for how to deal with situations of
simultaneous crisis) and needs to be agreed by Member
States within a region.
Plans to be consulted with other Member States in each
region and submitted for prior consultation and
recommendations by the Electricity Coordination Group.
Member States to designate a 'competent authority' as
responsible body for coordination and cross-border
cooperation in crisis situations.
Development of a network code/guideline addressing
specific rules to be followed for the cybersecurity.
Extension of planning & cooperation obligations to
Energy Community partners.
Mandatory Regional Risk
Preparedness Plans, subject to
binding opinions from the
European Commission.
Detailed templates for the
plans to be followed.
A dedicated body would be
created to deal with
cybersecurity in the energy
sector.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Crisis
management
Each Member State
takes measures in
reaction to crisis
situations based on its
own national rules and
technical TSO rules.
No co-ordination of
actions and measures
beyond the technical
(system operation)
level. In particular,
there are no rules on
how to coordinate
actions in simultaneous
crisis situations between
adjacent markets.
No systematic
information-sharing
(beyond the technical
level).
Minimum common rules on crisis
prevention and management (including
the management of simultaneous
electricity crisis) requiring Member
States to:
(i) not to unduly interference with
markets;
(ii) to offer assistance to others where
needed, subject to financial
compensation, and to;
(iii) inform neighbouring Member
States and the Commission, as of the
moment that there are serious
indications of an upcoming crisis and
during a crisis.
Minimum obligation as set out in Option 1.
Cooperation and assistance in crisis between Member
States, in particular simultaneous crisis situations, should
be agreed ex-ante; also agreements needed regarding
financial compensation. This also includes agreements on
where to shed load, when and to whom. Details of the
cooperation and assistance arrangements and resulting
compensation should be described in the Risk
Preparedness Plans.
Crisis is managed according
to the regional plans,
including regional load-
shedding plans, rules on
customer categorisation, a
harmonized definition of
'protected customers' and a
detailed 'emergency rulebook'
set forth at the EU level.
Monitoring
Monitoring of security
of supply predominatly
at the national level.
ECG as a voluntary
information exchange
platform.
- - Systematic discussion of ENTSO-E
Seasonal Outlooks in ECG and follow
up of their results by Member States
concerned.
Systematic monitoring of security of supply in Europe, on
the basis of a fixed set of indicators and regular outlooks
and reports produced by ENTSO-E, via the Electricity
Coordination Group.
Systematic reporting on electricity crisis events and
development of best practices via the Electricity
Coordination Group.
A European Standard (e.g. for
EENS and LOLE) on Security
of Supply could be developed
to allow performance
monitoring of Member States.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Pros
Minimum requirements for plans
would ensure a minimum level of
preparedness across EU taking into
account cyber security.
EU wide minimum common principles
would ensure predictability in the
triggers and actions taken by Member
States.
Common methodology for assessments would allow
comparability and ensure compatibility of SoS measures
across Member States. Role of ENTSO-E and RSCs in
assessment can take into account cross-border risks.
Risk Preparedness Plans consisting of a national and
regional part would ensure sufficient coordination while
respecting national differences and competences.
Minimum level of harmonization for cybersecurity
throughout the EU.
Designation of competent authority would lead to clear
responsibilities and coordination in crsis.
Common principles for crisis management and
agreements regarding assistance and remuneration in
simultaneous scarcity situations would provide a base for
mutual trust and cooperation and prevent unjustified
intervention into market operation.
Enhanced role of ECG would provide adequate platform
for discussion and exchange between Member States and
regions.
Regional plans would ensure
full coherence of actions taken
in a crisis.
Cons
Lack of cooperation in
risk preparedness and
managing crisis may
distort internal market
and put at risk the
security of supply of
neighbouring countries.
Risk assessment and preparedness
plans on national level do not take into
account cross-border risks and crisis
which make the plans less efficient and
effective.
Minimum principles of crisis
management might not sufficiently
adress simultaneous scarcity situations.
The coordination in the regional context requires
administrative resources.
Cybersecurity here only covers electricity, whereas the
provisions should cover all energy sub-sectors including
oil, gas and nuclear.
Regional risk preparedness
plans and a detailed templates
would have difficulties to fit
in all national specificities.
Detailed emergency rulebook
might create overlaps with
existing Network Codes and
Guidelines.
Most suitable: Option 2, as it provides for sufficient regional coordination in preparation and managing crisis while respecting national differences and competences.
350
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Measures assessed under Problem Area 4: The slow deployment of new services, low levels of service and poor retail market performance
Addressing energy poverty
Objective: Better understanding of energy poverty and disconnection protection to all consumers
Option: 0 Option: 0+ Option 1 Option 2
BAU: sharing of good practices. BAU: sharing of good
practices and increasing the
efforts to correctly implement
the legislation.
Voluntary collaboration across
Member States to agree on
scope and measurement of
energy poverty.
Setting an EU framework to monitor
energy poverty.
Setting a uniform EU framework to monitor energy
poverty, preventative measures to avoid disconnections
and disconnection winter moratorium for vulnerable
consumers.
Energy poverty EU Observatory of Energy
poverty (funded until 2030).
- Option 0+: EU Observatory of Energy
Poverty (funded until 2030).
Generic description of the term energy
poverty in the legislation. Transparency
in relation to the meaning of energy
poverty and the number of households in
a situation of energy poverty
Member States to measure energy
poverty.
Better implementation of the current
provisions.
- Option 0+: EU Observatory of Energy Poverty (funded
until 2030).
Specific definition of energy poverty based on a share
of income spent on energy.
Member States to measure energy poverty using
required energy.
Better implementation and transparency as in Option 1.
Disconnection
safeguards
NRAs to monitor and report
figures on disconnections.
NRAs to monitor and report figures on
disconnections.
NRAs to monitor and report figures of disconnections.
A minimum notification period before a disconnection.
All customers to receive information on the sources of
support and be offered the possibility to delay
payments or restructure their debts, prior to
disconnection.
Winter moratorium of disconnections for vulnerable
consumers.
Pros Continuous knowledge exchange. Stronger enforcement of
current legislation and
continuous knowledge
exchange.
Clarity on the concept and measuring of
energy poverty across the EU.
Standardised energy poverty concept and metric which
enables monitoring of energy poverty at EU level.
Equip MS with the tools to reduce disconnections.
Cons - Existing shortcomings of the
legislation are not addressed: lack
of clarity of the concept of energy
poverty and the number of energy
Insufficient to address the
shortcomings of the current
legislation with regard to
energy poverty and targeted
New legislative proposal necessary.
Administrative costs.
New legislative proposal necessary.
Higher administrative costs.
- Potential conflict with principle of subsidiarity.
Specific definition of energy poverty may not be
351
Annex VIII: Summary tables of options for detailed measures assessed under each main option
poor households persist.
Energy poverty remains a vague
concept leaving space for MS to
continue inefficient practices such
as regulated prices.
Indirect measure that could be
viewed as positive but insufficient
by key stakeholders.
protection. suitable for all MS.
Safeguards against disconnection may result in higher
costs for companies which may be passed to
consumers.
Safeguards against disconnection may also result in
market distortions where new suppliers avoid entering
markets where risks of disconnections are significant
and the suppliers active in such markets raise margins
for all consumers in order to recoup losses from unpaid
bills.
Moratorium of disconnection may conflict with
freedom of contract.
Most suitable option: Option 1 is recommended as the most balanced package of measures in terms of the cost of measures and the associated benefits. Option 1 will result in a clear
framework that will allow the EU and Member States to measure and monitor the level of energy poverty across the EU. The impact assessment found that the propose disconnection
safeguards in Option 2 come at a cost. There is potential to develop these measures at the EU level. However, Member States may be better suited to design these schemes to ensure that
synergies between national social services and disconnection safeguards can be achieved. Please note that Option 1 and Option 2 also include the measures described in Option 0+.
5
352
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Phasing out regulated prices
Objective: Removing market distortions by achieving the phase-out of supply price regulation for all customers.
Option: 0 Option 1 Option 2a Option 2b
Making use of existing acquis to continue
bilateral consultations and enforcement
actions to restrict price regulation to
proportionate situations justified by general
economic interest, accompanied by EU
guidance on the interpretation of the current
acquis.
Requiring MS to progressively phase out price
regulation for households by a deadline
specified in new EU legislation, starting with
prices below costs, while allowing transitional,
targeted price regulation for vulnerable
customers (e. g. in the form of social tariffs).
Requiring MS to progressively phase
out price regulation, starting with
prices below costs, for households
above a certain consumption threshold
to be defined in new EU legislation or
by MS.
Requiring MS to progressively phase out below
cost price regulation for households by a deadline
specified in new EU legislation.
Pros:
- Allows a case-by-case assessment of the
proportionality of price regulation, taking into
account social and economic particularities in
MS
Pros:
- Removes the distortive effect of price
regulation after the target date.
- Ensures regulatory predictability and
transparency for supply activities across the
EU.
Pros:
- Limits the distortive effect of price
regulation.
- Would reduce the scope of price
regulation therefore limiting its
distortive impact on the market.
Pros:
- Limits the distortive effect of price regulation
and tackles tariff deficits where existent.
Cons:
- Leads to different national regimes following
case-by-case assessments. This would
maintain a fragmented regulatory framework
across the EU which translates into
administrative costs for entering new markets.
Cons:
- Difficult to take into account social and
economic particularities in MS in setting up a
common deadline for price deregulation.
Cons:
- Difficult to take into account social
and economic particularities in MS in
defining a common consumption
threshold above which prices should
be deregulated.
Cons:
- Defining cost coverage at EU level is
economically and legally challenging.
- Implementation implies considerable regulatory
and administrative impact.
- Price regulation even if above cost risks holding
back investments in product innovation and
service quality.
Most suitable option(s): Option 1 - Setting an end date for all price intervention would ensure the complete removal of market distortions related to end-user price regulation and help create a
level playing field for supply activities across the EU while allowing targeted protection for vulnerable customers and/or energy poor.
353
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Level playing field for access to data
Objective: Creating a level playing field for access to data.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding roles and
responsibilities in data handling.
- Define responsibilities in data handling based on appropriate definitions in the
EU legislation.
- Define criteria and set principles in order to ensure the impartiality and non-
discriminatory behaviour of entities involved in data handling, as well as timely
and transparent access to data.
- Ensure that Member States implement a standardised data format at national
level.
- Impose a specific EU data management model (e.g. an
independent central data hub)
- Define specific procedures and roles for the operation of
such model.
Pro
Existing framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
The above measures can be applied independently of the data management model
that each Member State has chosen.
The measures will increase transparency, guarantee non-discriminatory access and
improve competition, while ensuring data protection.
Pro
Possible simplification of models across EU and easier
enforcement of standardized rules.
Con
The current EU framework is too
general when it comes to
responsibilities and principles. It is not
fit for developments which result from
the deployment of smart metering
systems.
Con Con
High adaptation costs for Member States who have already
decided and implementing specific data management models.
Such a measure would disproportionally affect those Member
States that have chosen a different model without necessarily
improving performance.
A specific model would not necessarily fit to all Member
States, where solutions which take into account local
conditions may prove to be more cost-efficient and effective.
Most suitable option(s): Option 1 is the preferred option as it will improve current framework and set principles for transparent and non-discriminatory data access from eligible market
parties. This option is expected to have a high net benefit for service providers and consumers and increase competition in the retail market.
354
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Facilitating supplier switching
Objective: Facilitating supplier switching by limiting the scope of switching and exit fees, and making them more visible and easier to understand in the event that they are
used.
Option 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Stronger enforcement, following the
clarification of certain concrete
requirements in the current legislation
through an interpretative note.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers, apart from: 1) exit fees
for fixed-term supply contracts; 2) fees
associated with energy efficiency or other
bundled energy services or investments. For
both exceptions, exit fees must be cost-
reflective.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers.
Pros:
- Evidence may suggest a degree of non-
enforcement of existing legislation by
national authorities.
- No new legislative intervention necessary.
Pros:
- Non-enforcement may be due to complex
existing legislation.
- No new legislative intervention necessary.
Pros:
- Considerably reduces the prevalence of
fees associated with switching suppliers,
and hence financial/psychological barriers
to switching.
Pros:
- Completely eliminates one
financial/psychological barrier to switching.
- Simple measure removes doubt amongst
consumers.
- The clearest, most enforceable
requirement without exceptions.
Cons:
- Continued ambiguity in existing
legislation may impede enforcement.
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
Cons:
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
- Certain MS might ignore the interpretative
note.
Cons:
- Marginally reduces the range of contracts
available to consumers, thereby limiting
innovation.
- An element of interpretation remains
around exceptions to the ban on fees
associated with switching suppliers.
Cons:
- Would further restrict innovation and
consumer choice, notably regarding
financing options for beneficial investments
in energy equipment as part of innovative
supply products e.g. self-generation, energy
efficiency, etc.
- Impedes the EU's decarbonisation
objectives, albeit marginally.
Most suitable option(s): Option 1 is the preferred option, as it represents the most favourable balance between probable benefits and costs.
355
Annex VIII: Summary tables of options for detailed measures assessed under each main option
Comparison tools
Objective: Facilitating supplier switching by improving consumer access to reliable comparison tools.
Option 0+ Option 1 Option 2
Cross-sectorial Commission guidance addressing the applicability of the Unfair
Commercial Practices Directive to comparison tools
Legislation to ensure every Member State has at
least one 'certified' comparison tool that complies
with pre-specified criteria on reliability and
impartiality
Legislation to ensure every Member State appoints an
independent body to provide a comparison tool that
serves the consumer interest
Pros:
- Facilitates coherent enforcement of existing legislation.
- Light intervention and administrative impact.
- Cross-sectorial consumer legislation already requires comparison tools to be
transparent towards consumers in their functioning so as not to mislead
consumers (e.g. ensure that advertising and sponsored results are properly
identifiable etc.).
- Cross-sectorial approach addresses shortcomings in commercial comparison
tools of all varieties.
- Cross-sectorial approach minimizes proliferation of sector-specific
legislation.
Pros:
- Fills gaps in existing legislation vis-à-vis energy
comparison tools.
- Limited intervention in the market, in most cases.
- Allows certifying all existing energy comparison
tools regardless of ownership.
- Proactively increases levels of consumer trust.
- Ensures EU wide access.
- The certified comparison websites can become
market benchmarks, foster best practices among
competitors
Pros:
- NRAs able to censure suppliers by removing their
offers from the comparison tool.
- No obligation on private sector.
- Reduces risks of favouritism in certification
process.
- Proactively increases levels of consumer trust.
Cons:
- Does not apply to non-profit comparison tools.
- Does not proactively increase levels of consumer trust.
- The existing legislation does not oblige comparison tools to be fully impartial,
comprehensive, effective or useful to the consumer.
Cons:
- Existing legislation already requires commercial
comparison tools to abide by certain of the criteria
addressed by certification.
- Requires resources for verification and/or
certification.
- Significant public intervention necessary if no
comparison tools in a given MS meet standards.
Cons:
- To be effective, Member States must provide
sufficient resources for the development of such tools
to match the quality of offerings from the private
sector.
- Well-performing for-profit tools could be side-lined
by less effective ones run by national authorities.
Most suitable option(s): Option 1 is the preferred option because it strikes the best balance between consumer welfare and administrative impact. It also gives Member States control over
whether they feel a certification scheme or a publicly-run comparison tool best ensures consumer engagement in their markets.
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Annex VIII: Summary tables of options for detailed measures assessed under each main option
Improving billing information
Objective: Ensuring that all consumer bills prominently display a minimum set of information that is essential to actively participating in the market.
Option: 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Commission recommendation on billing
information
More detailed legal requirements on the key
information to be included in bills
A fully standardized 'comparability box' in bills
Pros:
- 77% of energy consumers agree or strongly
agree that bills are "easy and clear to
understand".
- Allows 'natural experiments' and other
innovation on the design of billing information
to be developed by MS.
- Recent (2014) transposition of the EED means
premature to address information on energy
consumption and costs.
Pros:
- Low administrative impact
- Gives MS significant flexibility to
adapt their requirements to national
conditions.
- Allows best practices to further
develop.
Pros:
- Ensures that the minimum baseline of
existing practices is clarified and raised.
- Allows best practices to further develop,
albeit less than Option 0.
- Improves comparability and portability of
information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
- Bill design left free to innovation.
Pros:
- Highest legal clarity and comparability of
offers and bills.
- A level playing field for all consumers and
suppliers across the EU.
- Very little leeway for suppliers to differently
interpret the legislation with regards to the
presentation of information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
Cons:
- Poor consumer awareness of market-relevant
information can be expected to continue.
- Does not respond to stakeholder feedback on
need to ensure minimum standards.
Cons:
- A recommendation is unenforceable
and may be ignored by MS/utilities.
- Poor consumer awareness of market-
relevant information can be expected to
continue.
- Does not respond to stakeholder
feedback on need to ensure minimum
standards.
Cons:
- Limits innovation around certain bill
elements.
- Remaining leeway in interpreting legal
articles may lead to implementation and
enforcement difficulties.
Cons:
- Challenging to devise standard presentation
which can accommodate differences between
national markets.
- Highest administrative impact.
- Prescriptive approach prevents beneficial
innovation.
- Difficult to adapt bills to evolving technologies
and consumer preferences.
Most suitable option(s): Option 1 is the preferred option as it likely to leads to significant economic benefits and increased consumer surplus without significant administrative costs or the
risk of overly-prescriptive legislation at the EU level.
-


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 3/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
2
TABLE OF CONTENTS
1. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(A):
LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES......................4
1.1. Priority access and dispatch........................................................................................................... 4
Summary table.................................................................................................................................4
1.1.1.
Description of the baseline..............................................................................................................5
1.1.2.
Deficiencies of the current legislation .............................................................................................6
1.1.3.
Presentation of the options .............................................................................................................9
1.1.4.
Comparison of the options ............................................................................................................11
1.1.5.
Subsidiarity.....................................................................................................................................14
1.1.6.
Stakeholders' opinions...................................................................................................................14
1.1.7.
1.2. Regulatory exemptions from balancing responsibility ...................................................................17
Summary table...............................................................................................................................18
1.2.1.
Description of the baseline............................................................................................................19
1.2.2.
Deficiencies of the current legislation ...........................................................................................20
1.2.3.
Presentation of the options ...........................................................................................................22
1.2.4.
Comparison of the options ............................................................................................................24
1.2.5.
Subsidiarity.....................................................................................................................................25
1.2.6.
Stakeholders' opinions...................................................................................................................26
1.2.7.
1.3. RES E access to provision of non-frequency ancillary services ........................................................29
Summary table...............................................................................................................................30
1.3.1.
Description of the baseline............................................................................................................31
1.3.2.
Deficiencies of the current legislation ...........................................................................................33
1.3.3.
Presentation of the options ...........................................................................................................34
1.3.4.
Comparison of the options ............................................................................................................35
1.3.5.
Subsidiarity.....................................................................................................................................36
1.3.6.
Stakeholders' opinions...................................................................................................................37
1.3.7.
2. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(B)
STRENGTHENING SHORT-TERM MARKETS..................................................................39
2.1. Reserves sizing and procurement..................................................................................................41
Summary table...............................................................................................................................42
2.1.1.
Description of the baseline............................................................................................................43
2.1.2.
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation) .........................47
2.1.3.
Presentation of the options ...........................................................................................................48
2.1.4.
Comparison of the options ............................................................................................................49
2.1.5.
Subsidiarity.....................................................................................................................................50
2.1.6.
Stakeholders' opinions...................................................................................................................50
2.1.7.
2.2. Removing distortions for liquid short-term markets......................................................................53
Summary table...............................................................................................................................54
2.2.1.
Description of the baseline............................................................................................................55
2.2.2.
Deficiencies of the current legislation ...........................................................................................58
2.2.3.
Presentation of the options ...........................................................................................................59
2.2.4.
Comparison of the options ............................................................................................................60
2.2.5.
Subsidiarity.....................................................................................................................................62
2.2.6.
Stakeholders' opinions...................................................................................................................63
2.2.7.
2.3. Improving the coordination of Transmission System Operation.....................................................65
Summary table...............................................................................................................................66
2.3.1.
3
Detailed description of the baseline..............................................................................................67
2.3.2.
Deficiencies of the current legislation ...........................................................................................70
2.3.3.
Presentation of the options ...........................................................................................................72
2.3.4.
Comparison of the options ............................................................................................................76
2.3.5.
Subsidiarity.....................................................................................................................................87
2.3.6.
Stakeholders' opinions...................................................................................................................87
2.3.7.
3. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(C);
PULLING DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE
MARKET....................................................................................................................................89
3.1. Unlocking demand side response..................................................................................................91
Summary table...............................................................................................................................92
3.1.1.
Description of the baseline............................................................................................................93
3.1.2.
3.1.2.1. Smart Metering......................................................................................................................93
3.1.2.2. Market arrangements for demand response.........................................................................95
Deficiencies of current legislation................................................................................................101
3.1.3.
3.1.3.1. Deficiencies of current Smart Metering Legislation.............................................................102
3.1.3.2. Deficiencies of current regulation on demand response.....................................................103
Presentation of the options .........................................................................................................104
3.1.4.
Comparison of the options ..........................................................................................................106
3.1.5.
Subsidiarity...................................................................................................................................125
3.1.6.
Stakeholders' opinions.................................................................................................................129
3.1.7.
3.2. Distribution networks.................................................................................................................143
Summary table.............................................................................................................................144
3.2.1.
Description of the baseline..........................................................................................................145
3.2.2.
Deficiencies of current legislation................................................................................................150
3.2.3.
Presentation of the options .........................................................................................................152
3.2.4.
Comparison of the options ..........................................................................................................153
3.2.5.
Subsidiarity...................................................................................................................................157
3.2.6.
Stakeholders' opinions.................................................................................................................157
3.2.7.
3.3. Distribution network tariffs and DSO remuneration ....................................................................161
Summary table.............................................................................................................................162
3.3.1.
Description of the baseline..........................................................................................................164
3.3.2.
Deficiencies of the current legislation .........................................................................................168
3.3.3.
Presentation of the options .........................................................................................................169
3.3.4.
Comparison of the options ..........................................................................................................170
3.3.5.
Subsidiarity...................................................................................................................................172
3.3.6.
Stakeholders' opinions.................................................................................................................173
3.3.7.
3.4. Improving the institutional framework .......................................................................................179
Summary Table ............................................................................................................................180
3.4.2.
Description of the baseline..........................................................................................................181
3.4.1.
Deficiencies of the current legislation .........................................................................................185
3.4.2.
Presentation of the options .........................................................................................................189
3.4.3.
Comparison of the options ..........................................................................................................195
3.4.4.
Budgetary implications of improved ACER staffing .....................................................................198
3.4.5.
Subsidiarity...................................................................................................................................200
3.4.6.
Stakeholders' opinions.................................................................................................................202
3.4.7.
4
Priority access and dispatch
1. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(A): LEVEL PLAYING FIELD AMONGST PARTICIPANTS AND RESOURCES
1.1. Priority access and dispatch
Summary table
1.1.1.
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain
rules allowing priority
dispatch and priority
access for RES,
indigenous fuels and
CHP.
Abolish priority dispatch and priority
access
This option would generally require full
merit order dispatch for all technologies,
including RES E, indigenous fuels such as
coal, and CHP. It would ensure optimum
use of the available network in case of
network congestion.
Priority dispatch and/or priority access only for emerging
technologies and/or for very small plants:
This option would entail maintaining priority dispatch
and/or priority access only for small plants or emerging
technologies. This could be limited to emerging RES E
technologies, or also include emerging conventional
technologies, such as CCS or very small CHP.
Abolish priority dispatch and introduce clear
curtailment and re-dispatch rules to replace
priority access.
This option can be combined with Option 2,
maintaining priority dispatch/access only for
emerging technologies and/or for very small
plants
Pros
Lowest political
resistance
Efficient use of resources, clearly
distinguishes market-based use of
capacities and potentially subsidy-based
installation of capacities, making subsidies
transparent.
Certain emerging technologies require a minimum number
of running hours to gather experiences. Certain small
generators are currently not active on the wholesale market.
In some cases, abolishing priority dispatch could thus bring
significant challenges for implementation. Maintaining also
priority access for these generators further facilitates their
operation.
As Option 1, but also resolves other causes for
lack of market transparency and discrimination
potential. It also addresses concerns that
abolishing priority dispatch and priority access
could result in negative discrimination for
renewable technologies.
Cons
Politically, it may be criticized that
subsidized resources are not always used if
there are lower operating cost alternatives.
Adds uncertainty to the expected revenue
stream, particularly for high variable cost
generation.
Same as Option 1, but with less concerns about blocking
potential for trying out technological developments and
creating administrative effort for small installations.
Especially as regards small installations, this could
however result in significant loss of market efficiency if
large shares of consumption were to be covered by small
installations.
Legal clarity to ensure full compensation and
non-discriminatory curtailment may be
challenging to establish. Unless full
compensation and non-discrimination is
ensured, priority grid access may remain
necessary also after the abolishment of priority
dispatch.
Most suitable option(s): Option 3. Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to
actively participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should
be combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or
emerging technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.
5
Priority access and dispatch
Description of the baseline
1.1.2.
Dispatch rules determine which power generation facilities shall generate power at which
time of the day. In principle, this is based on the so-called merit order, which means that
those power plants which for a given time period require the lowest payment to generate
electricity are called upon to generate electricity. This is determined by the day-ahead
and intraday markets. In most Member States, dispatch is then first decided by market
results and, where system stability requires intervention, corrected by the TSO (so-called
self-dispatch systems). In some Member States (e.g. Poland) the TSO integrates both
steps, directly determining on the basis of the system capabilities and market offers made
which offers can be accepted (so-called central dispatch).
Access rules determine which generator gets, in case of congestion on a particular grid
element, access to the electricity network. They thus do not relate to the initial network
connection, but to the allocation of capacity in situations where the network is unable to
fully accommodate the market result. Priority access can thus mean that in situations of
congestion, instead of applying the most efficient way of remedying a particular network
issue, the transmission system operator has to opt for less efficient, more complex and/or
more costly options, to maintain full generation from the priority power plant.
Currently, several Directives allow the possibility or even set the obligation for Member
States to include priority dispatch and priority grid access of certain technologies in their
national legislation:
- Article 15(4) of the Electricity Directive provides that Member States may
foresee priority dispatch of generation facilities using fuel from indigenous
primary energy fuel sources to an extent not exceeding, in any calendar year, 15
% of the overall primary energy necessary to produce the electricity consumed in
the Member State concerned;
- Article 16(2)(a) of the Renewable Energies Directive obliges Member States to
provide for either priority access or guaranteed access to the grid-system of
electricity produced from renewable energy sources;
- Article 16(2)(c) of the Renewable Energies Directive obliges Member States to
ensure that when dispatching electricity generating installations, transmission
system operators shall give priority to generating installations using renewable
energy sources in so far as the secure operation of the national electricity system
permits and based on transparent and non-discriminatory criteria;
- Similarly to the provisions under the Renewable Energies Directive, Article 15
(5) b) and c) of the Energy Efficiency Directive foresee priority grid access and
priority dispatch of electricity from high-efficiency cogeneration respectively.
The introduction of priority dispatch and priority access for renewable energies on the
one hand and for CHP on the other hand are closely related. According to the impact
assessment of the Energy Efficiency Directive, Article 15 (5) aims at ensuring a level
playing field in electricity markets and help distributed CHP. Thus, the obligation of
priority dispatch, and the right to priority access, already existing under its predecessor,
6
Priority access and dispatch
Directive 2004/8/EC, have been expanded in the Energy Efficiency Directive to include
mandatory priority access for CHP1
. The new provision fully mirrored the provision
under the then new Renewable Energies Directive.
Already for Directive 2004/8/EC, priority dispatch and (the right for a Member State to
foresee) priority access were based on the "need to ensure a level playing field" and the
challenges for CHP being similar to those for renewable energies. The provision of
priority dispatch and priority access for CHP has thus since its beginning been closely
related to the provision of these rights to renewable energies. This is also reflected in the
text of Article 15(5) itself, which provides that "when providing priority access or
dispatch for high-efficiency cogeneration, Member States may set rankings as between,
and within different types of, renewable energy and high-efficiency cogeneration and
shall in any case ensure that priority access or dispatch for energy from variable
renewable energy sources is not hampered."
The current framework thus provides that the provision of priority dispatch and priority
access for CHP shall under no circumstance endanger the expansion of renewable
energies. Against this background, any change to the framework for renewable energies
would directly impact the justification underlying the introduction of priority dispatch
and priority access for CHP.
The degree to which Member States have made use of the right under Article 15 (4) of
the Electricity Directive differs significantly. Some Member States make no use of it
whereas other Member States provide for priority dispatch of power generation facilities
using national resources (most notably coal). The provisions in the Renewable Energy
Directive and Energy Efficiency Directive are mandatory and in principle applied in all
Member States, although the implementation can differ significantly due to differences in
national subsidy schemes.
Deficiencies of the current legislation
1.1.3.
European legislation allows the option (as regards indigenous resources) or sets an
obligation (for RES E and CHP) to implement priority dispatch and (for RES E and
CHP) priority grid access. This creates a framework with very high predictability of the
total power generation per year, thus increasing investment security. In particular in view
of the increasing share of RES E, this has resulted in a situation where in some Member
States very high shares of power generation are coming from "prioritized" sources.
The EU has committed to a continued increase of the share of renewable generation for
the coming decades. Until 2030, at least 27 % of final energy consumption in the EU
shall come from RES E – this requires a share of at least 45 % in power generation2
.
According to the PRIMES EuCo27 scenario, decarbonisation of EU's energy system
would require a share of RES in power generation of close to 50%, wind and solar energy
alone projected to cover 29 % of power generation.
1
https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_0779_impact_assessment.pdf, p.58.
2
2030 Communication, COM(2014) 15 final, p.6.
7
Priority access and dispatch
Today, investments in renewable generation make up the largest share of investments;
many RES E technologies can no longer be treated as marginal or emerging technologies.
The comparison of Germany and Denmark, two Member States with high shares both of
RES E and CHP, is helpful to assess the deficiencies of systems based on strong priority
dispatch and priority access principles. Taking the example of Denmark, an average of 62
% of power demand in the month of January 2014 has come from wind generation alone3
and the share of annual demand covered by wind power has risen from 19 % in 2009 to
42 % in 20154
. Adding to this the share of 50.6 % of CHP in total Danish power
generation5
, which makes Denmark one of the Member States with the highest share of
CHP6
, in many periods almost all generation would be subject to "priority dispatch".
Finally, it may be necessary to add certain generation assets which are needed to operate
for system security, e.g. because only they can provide certain system services (e.g.
voltage control, spinning reserves), further limiting the scope for fully market based
generation. However, in Denmark, market incentives on generators are set in a way that
drastically reduces the impact of priority dispatch. Almost all decentralized CHP plants
and a large number of wind turbines would be exposed to and are not willing to run at
negative prices. As CHP are not shielded from market signals by national support
systems, they have strong incentives to stop electricity generation in times of oversupply.
The integration of a high share of RES E and CHP in parallel has been successful to a
significant extent because CHP are not built and operated on the basis of a "must run"
model, where heat demand steers electricity generation. To the contrary, CHP plants have
back-up solutions (boilers, heat storage), and use these where this is more efficient for
the electricity system as expressed by wholesale prices.
Taking the example of another "renewables front runner", Germany, "must run"
conventional power plants have been found to contribute significantly to negative prices
in hours of high renewable generation and low load, with at least 20 GW of conventional
generation still active even at significantly negative prices7
. Financial incentives are so
that many conventional plants generate even at significantly negative prices, with many
power plants switching off electricity generation only at prices around minus 60
EUR/MWh. This increases the occurrence of negative prices, worsening the financial
outlook for both renewable and conventional generators, and can increase system stress
and costs of interventions by the system operator. This is not due to technical reasons –
also in Germany, CHP plants generally have back-up heat capacities, which are already
necessary to address e.g. maintenance periods of the main plant, or could technically
install these. While it may be economically and environmentally efficient to run through
short periods of low prices (to avoid ramping up or down), this is no longer the case
3
http://www.martinot.info/renewables2050/how-is-denmark-integrating-and-balancing-renewable-
energy-today.
4
http://www.energinet.dk/EN/El/Nyheder/Sider/Dansk-vindstroem-slaar-igen-rekord-42-procent.aspx.
5
https://ec.europa.eu/energy/sites/ener/files/documents/PocketBook_ENERGY_2015%20PDF%20final.
pdf, p. 183.
6
http://www.code2-project.eu/wp-content/uploads/Code-2-D5-1-Final-non-pilor-Roadmap-
Denmark_f2.pdf;
7
See: http://www.netztransparenz.de/de/Studie-konventionelle-Mindesterzeugung.htm
8
Priority access and dispatch
where the market is willing to pay a lot for electricity being not generated. Excess
electricity is in these situations not very efficiently generated, but essentially a waste
product. While there is a wide range of reasons for conventional generation to produce at
hours of negative prices (e.g. very inflexible technologies such as nuclear or lignite
which need a long time to reactivate), approximately 50 % of the plants in such a
situation in Germany had at least the capability for parallel heat production, and
approximately 8-10 % of conventional plants still producing at such moments were found
to be heat-controlled CHP generation8
.
In view of the EU target for at least 27 % of renewable energies in final energy
consumption (which according to PRIMES EuCo27 projections would require 47 % of
gross final electricity consumption to come from renewable energy), the high share of
priority dispatch and priority access-technologies will increasingly occur in other
Member States. This can have very significant impact on the well-functioning of the
electricity market. In particular:
- Subsidy schemes based on priority dispatch (such as Feed-in Tariffs) often are
based on high running hours and a mitigation of market signals to the subsidized
generator. This means that non-subsidized generation is increasingly pushed out
of the market even where this is not cost-efficient;
- Situations in which more than 100 % of demand is covered by priority dispatch
become more prevalent. This lowers the investment security provided by priority
dispatch, and can lead to results contrary to policy interests such as unnecessary
curtailment of RES E;
- The internal energy market depends on steering the use of generation by price
signals. In a situation where the clear majority of power generation does not react
to price signals, market integration fails and market signals cannot develop;
- Incentives to invest into increased flexibility which would naturally result from
price signals on a functioning wholesale market do not reach a significant part of
the generation mix. Priority dispatch rules can eliminate incentives for flexible
generation (e.g. biomass, some CHP with back-up installations) to use the
flexibility potential and instead create incentives to run independent of market
demand;
- Priority dispatch and priority grid access limit the choice for transmission system
operators to intervene in the system (e.g. in case of congestion on certain parts of
the electricity grid). This can result in less efficient interventions (e.g. re-
dispatching power plants in suboptimal locations). The increased complexity with
high shares of priority dispatch could also lower system stability, although
emergency measures may also affect generation benefiting from priority dispatch;
- Priority dispatch rules for high marginal cost technologies can result in using
costly primary ressources to generate electricity at a time where other, cheaper,
technologies were available;
8
Consentec, "Konventionelle Mindesterzeugung – Einordnung, aktueller Stand und perspektivische
Behandlung", Abschlussbericht 25. Januar 2016, p. vii and 25.
9
Priority access and dispatch
- Priority dispatch rules for generation installations using indigenous ressources
result in clear discrimination of cross-border flows and distortions to the internal
market.
Against this background, the provision of priority dispatch and priority grid access needs
to be reassessed in view of the main policy objectives of sustainability, security of supply
and competitiveness (see also Section 7.4.2 of the evaluation).
Presentation of the options
1.1.4.
For the operation of generation assets, it is recognized that the wholesale market with
merit-order based dispatch and access ensures an optimal use of generation resources.
Especially in balancing, it also ensures optimal use of congested network capacities.
Rules which deviate from these provisions reduce system efficiency and result in market
distortions, as it can sometimes be economically more efficient to curtail RES and the
guarantee of non-curtailment significantly increases price volatility9
. Where financial
compensation on market-based principles is foreseen in case of re-dispatch, priority
dispatch also does not appear to be necessary to mitigate investor risk in low marginal
cost technologies. Thus, it is proposed to abolish or at least significantly limit the
exceptions foreseen under EU law from merit-order based dispatch and network access.
Option 0: do nothing
This option does not change the legislative framework. Priority dispatch and access
provisions remain unchanged in EU legislation and the above-described problems persist.
Option 0+: Non-regulatory approach
Stronger enforcement would not adress the policy objectives. In fact, as the objective is
to ensure market-based use of generation assets with limited exceptions, stricter
enforcement of existing obligations under EU law which make those exceptions
mandatory would be counter-productive.
Voluntary cooperation does not change the legislative framework and thus maintains the
currently existing obligations. The order of dispatch for power plants and access to the
grid has clear cross-border implications. Priority dispatch/access often results in lower
availability of cross-border capacities, and significant differences in these rules can thus
distort cross-border trade.
Option 1: Abolish priority dispatch and priority access
Under this option, priority dispatch / priority access provisions would be removed from
EU legislation, and replaced by a general principle that generation and demand response
shall be dispatched on the basis of using the most efficient resources available, as
determined on the basis of merit order and system capabilities.
9
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.183 f.
10
Priority access and dispatch
This option would optimally achieve the defined objectives and thus be highly effective.
It would however result in additional administrative impact for very small RES E
installations which are currently not capable of controlling their feed-in into the grid
(notably rooftop solar) and micro-CHP installations. Furthermore, it could increase
complexity and prolong the development time for emerging technologies. As these
technologies would not yet be mature they would not be able to generate at competitive
prices and could thus not reach a number of running hours needed to generate sufficient
experience.
Option 2: Limit priority dispatch and/or priority access to emerging technologies and/or
small plants
Under this option, priority shall be given only where it can be justified to enable a certain
technology or operating model which is seen as beneficiary under other policy objectives.
As regards emerging technologies10
, this could in particular be linked to ensuring that the
technologies reach a minimum number of running hours as required to gather experience
with the non-mature technology. For particularly small generation installations11
, this
could reduce the administrative and technical effort linked to dispatching the power plant
for its owner, which may appear disproportionate for certain installations. This being
said, the administrative effort can be significantly reduced by ensuring the possibility of
aggregation, allowing the joint operation and management of a large number of small
plants. To mitigate negative impacts on market functioning, both possible exemptions
should be capped to ensure that priority dispatch and priority access does not apply to
large parts of total power generation.
This option would achieve the defined objectives, although certain trade-offs would be
made. Accepting priority dispatch and access for certain installations would reduce
market efficiency. If the share of exempted installations in the total electricity market
remains low, the negative market impact is however likely to remain very limited. On the
other hand, the positive impact of allowing the development of new technologies can
provide a significant benefit for the achievement of renewable energy targets in the
medium to long-term. Exempting very small installations would also increase public
acceptance and reduce administrative efforts required from the operators of these
installations, which are often households. This is thus the preferred option, although it
has to be ensured that exemptions remain limited to a small part of the market. The exact
definition of the emerging technologies could be left to subsidiarity.
Option 3: Abolish priority dispatch and introduce clear curtailment and re-dispatch rules
to replace priority access
This option (which can be combined with Option 2) would entail the abolishment of
priority dispatch. Priority grid access would be replaced by clear rules on how to deal
10
In the PRIMES EuCo27 scenario, the emerging technologies of tidal and solar thermal generation
(other technologies having insignificant shares) are projected to have a total installed capacity of 7.26
GW and produce 10 TWh of electricity in 2030 (13 GW and 20 TWh in 2050, respectively).
11
In the PRIMES EuCo27 scenario, RES E small-scale capacity is projected in 2030 to be 85 GW (7.8 %
share) and produce 96 TWh of energy (2.9% share).
11
Priority access and dispatch
with situations of system stress, in particular as regards congestion of grid elements. In
principle, market-based ressources should be used first, thus curtailing or redispatching
first those generators which offer to do this against market-based compensation. In a
second step, where no market-based ressources can be used, minimum rules on
compensation are foreseen, ensuring compensation based on additional costs or (where
this is higher) a high percentage of lost revenues.
It would mean that network operators would obtain a clear incentive to make an
assessment on the basis of costs as to the alternatives available to them to address the
underlying network constraints, thereby creating opportunities for more innovative
solutions such as storage.
The increase in transparency and legal certainty would notably also prevent
discrimination against certain technologies (particularly RES E) in curtailment and re-
dispatch decisions. RES E are often operated by smaller market players, who could
otherwise be subject to excessive curtailment or unable to achieve fully equal
compensation. It would also foresee principles on the financial compensation to be paid
in case of curtailment or re-dispatch, thus reducing the additional investment risk linked
to losing priority access and thereby reducing any increase in capital costs. In order to
ensure effective implementation of the new market rules prior to abolishment of priority
dispatch and access, priority dispatch and access may be maintained for an interim period
after entry into force of the other measures adressing Problem 1.
Increased transparency and legal certainty on curtailment and re-dispatch are a "no
regret" measure, in so far as they contribute to market functioning even in the absence of
changes to the priority dispatch and priority access framework. Ensuring sufficient
compensation for curtailment, notably for RES E, will increase costs to be borne by
system operators. In so far as these costs are currently integrated into renewable subsidy
schemes, total system costs will however remain similar. As regards priority grid access,
this is the preferred option, in order to ensure that the abolishment of priority grid access
has no unwanted negative consequences on the financial framework notably of RES E
but also of CHP.
Comparison of the options
1.1.5.
It should be noted that the removal of priority dispatch and priority access does not
equally affect different technologies and generators in different Member States:
- The removal of priority dispatch mostly affects high marginal cost technologies
(biomass, indigenous resources, some CHP), as low marginal cost technologies
(wind, PV) are generally dispatched when available already on the basis of the
merit order. Without priority dispatch, high marginal cost technologies thus take
up a role more generally associated with other high marginal cost plants, such as
gas-fired power plants, operating only in periods of high prices (high residual
load). Those generators are then incentivized to making best use of the inherent
flexibility that their technology can provide to a power system, and thus
accompany the change to an electricity system with a high share of variable low
12
Priority access and dispatch
marginal cost generation. For high marginal cost generation, removal of priority
dispatch can significantly reduce the number of running hours. Studies for the
Commission have shown a reduction of approximately 85 % in dispatch of wood-
based biomass generation, mostly to the benefit of gas-fired power plants12
. To
the contrary, there is a (more limited) increase in the running hours of low
marginal cost generation, including wind and solar;
- The reduction in inefficient biomass dispatch would represent a major part of the
significant reductions of system costs presented in Figure 1 below, with annual
savings of 5.9 billion Euros, expected by the removal of market distortions under
Problem Area I, Option (1a) of the impact assessment13
;
Figure 1: Reduction in system costs by abolishment of priority rules
Source: METIS
- By achieving market-based dispatch, the removal of priority dispatch for all
technologies drastically reduces the occurrence of negative prices. Whereas
negative prices can be a normal occurrence in well-functioning markets which
have opportunity costs linked to not offering a service (as is the case on the
electricity markets), the occurrence of negative prices based on priority rules
shows that priority is given also in times where the system does not require
additional generation.
12
For this assessment, biomass was assumed to consist of 22 % "must-run" waste incineration (OPEX:
3.6 EUR EUR/MWh) and 78 % wood-fired plants with high variable costs (around 90 EUR
EUR/MWh)
13
For more details please see Section 6.1.2 of the impact assessment.
13
Priority access and dispatch
Figure 2: reduction of negative price occurrences by removal of priority
dispatch
Source: METIS
- The removal of priority access on the other hand mostly affects technologies
which are producing in areas and at times of network congestion. This will more
often concern low marginal cost technologies (especially wind) as periods of high
wind feed in are more likely to result in congested network elements, requiring
curtailment or re-dispatch;
- Providing clear and transparent rules on curtailment and compensation benefits
all market actors. This is particularly true for small and/or new market actors,
including RES E;
- While the change of biomass dispatch to reflect its role as flexible back-up
generation, to the benefit mostly of gas, but also of coal and nuclear generation
thus would drastically reduce future system costs, it could possible entail an
increase of CO2 emissions in the power sector, whereas total CO2 emissions
under the ETS framework would in principle remain identical over time14
.
Option 1 would be the most effective in achieving the objective of non-discrimination
and market efficiency. However, it could result in an increase of costs to achieve other
policy objectives, notably for decarbonisation of the energy system. Fully removing
priority dispatch and access would also result in an increased need for small generators,
including households (e.g. rooftop solar) to participate in the electricity market. While
this would allow strong economic incentives, it would thus increase the administrative
impact for households and SMEs. Thus, clear and transparent rules for the market
participation of RES E and CHP as well as limited exemptions for small and emerging
technologies should be included, to accompany the phase-out of priority access and
priority dispatch. On the other hand, remaining at the status quo would, with a growing
share of priority technologies in the system, seriously undermine effective price
formation and dispatch in the wholesale market. The preferred option is thus a
14
The environmental impacts from the removal of priority dispatch for biomass are discussed in Section
6.1.6 of the impact assessment
14
Priority access and dispatch
combination of Options 2 and 3. This will allow a reduction of the administrative impact
for households and SMEs while ensuring the most efficient use of bigger mature power
generators.
Subsidiarity
1.1.6.
Priority dispatch is foreseen directly in EU law. Changing or removing those provisions
cannot be achieved on a national level. Furthermore, in an integrated electricity market,
the way to determine which power plant is operated has a direct impact on cross-border
trade. Applying discriminatory provisions for power plant dispatch in certain Member
States can thus negatively affect cross-border trade or even directly result in
discrimination against power generators in other Member States. Ensuring efficient
market integration and functioning investment signals, requires fundamental dispatch
rules to be harmonized.
Stakeholders' opinions
1.1.7.
In the public consultation, most stakeholders support the full integration of Renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods.
Many stakeholders note that the regulatory framework should enable RES E to
participate in the market, e.g. by adapting gate closure times and aligning product
specifications. A number of respondents also underline the need to support the
development of aggregators by removing obstacles for their activity to allow full market
participation of renewables.
Also stakeholders from the renewable sector often recognize the need to review the
priority dispatch framework. They make this however subject to conditions; Wind
Europe provided views on curtailment of wind power and priority dispatch and stated
that "countries with well integrated day-ahead, intraday and balancing market and a
good level of interconnections, where priority of dispatch is not granted to CHP and
conventional generators, do not need to apply priority of dispatch for wind power." They
argue that "in general, priority dispatch should be set according to market maturity and
liberalisation levels in the Member State concerned, but also taking due account of
progress in grid developments and application of best practices in system operation."
According to its paper from June 2016 on curtailment and priority dispatch, in the view
of Wind Europe15
, some EU markets, such as Sweden and the UK, which have relatively
high penetration rates of wind, do not offer priority dispatch for wind producers16
and
this does not place any restrictions on market growth. However, a phase-out of priority
dispatch for renewable energies should only be considered if (i) this is done also for all
other forms of power generation, (ii) liquid intraday markets with gate closure near real-
time, (iii) balancing markets allow for a competitive participation of wind producers;
(short gate closure time, separate up/downwards products, etc.), and (iv) curtailment rules
15
https://windeurope.org/wp-content/uploads/files/policy/position-papers/WindEurope-Priority-
Dispatch-and-Curtailment.pdf.
16
The Commission services interpret this to mean that, while priority dispatch may be foreseen under
national legislation, it has no practical impact.
15
Priority access and dispatch
and congestion management are transparent to all market parties. According to Wind
Europe, these requirements are already in 2016 fulfilled in certain markets such as the
UK, Sweden and Denmark, whereas other Markets currently still required priority
dispatch. It is the view of the Commission services that by entry into force of the present
legislative initiative, the above requirements are met in all Member States.
Regarding priority access, Wind Europe asks for curtailments to be valued by the market
as a service to ensure system security. It should be treated as downward capacity and its
price should be set via the balancing market. This would already be applied in the Danish
and UK markets. Participation of wind in the balancing markets could lead to a
significant reduction of curtailments. This is taken into account in Option 3, which
ensures the primary use of available market-based ressources prior to any non-market
based curtailment. Where balancing ressources are available, including from RES E, and
capable of adressing the system problem underlying the planned curtailment, they thus
have to be used before non-market based curtailment takes place. For this second step,
transparent compensation rules are foreseen. Wind Europe recognizes that "there may be
a benefit from not compensating 100% of the opportunity cost. Reducing slightly the
income could send an important incentive signal to investors to select locations with
existing sufficient network capacity, Curtailment would then be likely to occur less
frequently. The exact % of the opportunity cost needs to be carefully assessed in order to
find a balance between an increase in policy cost and the increase of financing costs due
to higher market risk." This position is reflected in the present proposal.
Stakeholders from the cogeneration sector underline the link to priority dispatch for
renewable energies. COGEN Europe submits that it is "important that at EU level CHP
benefits from at least parity with RES on electricity provisions, as long as there are no
additional policy measures that would compensate for the loss in optimal operation
ensured through priority of dispatch for certain types of CHPs." They also argue that
"while a significant fraction of the CHP fleet can be designed and/or retrofitted to
operate in a more flexible way (e.g. though partial load capabilities, enhanced design
from the electrical components, and the heat storage addition), this may come at the
expense of the site efficiency and industrial productivity." The parallelism to RES is
maintained in all options, whereas the additional costs and possible loss of efficiency
have to be balanced with the economic cost of significant amounts of inflexible
conventional generation in a high-RES system.
EUROBAT, association of European Manufacturers of automotive, industrial and energy
storage batteries, regards curtailing of energy as a system failure, as the "wasted" power
should be stored in batteries instead. It argues against any financial compensation to
renewable generators for being curtailed, as such a compensation would disincentivize
the installation of energy storage systems17
.
Transmission system operators would be directly affected, as they are responsible for
practical implementation of the priority rules. In May 2016, ENTSO-E has asked their
Members to provide answers to questions which had been discussed with the
17
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf p.28.
16
Priority access and dispatch
Commission services. 29 TSOs from 25 countries have replied, though not all TSOs
answered all questions, which is also due to the limited impact of priority dispatch/access
in some Member States (with a low share of CHP and RES E). TSOs from 14 Member
States answered that priority dispatch increases the costs of pursuing stable, secure and
reliable system operations. TSOs from a smaller group of Member States (4 to 6) also
stated that priority dispatch limits the possibilities to keep the grid stable, secure and
reliable. Only the TSOs of three Member States answered that priority dispatch has no
major effect on system operations. Regarding the market impact, TSOs from 12 Member
States raised increased dispatching costs and 9 raised the occurrence of negative prices.
On the other hand, TSOs from one Member State argued that priority dispatch resulted in
reduced costs for the support of RES E. TSOs also stressed the cross-border impact of
priority dispatch: TSOs from 6 Member States referred to increased congestion of
interconnectors, and an example provided was that priority dispatch in neighbouring
areas impacted the system operation in the TSOs area. When asked how European
legislation should adress the issues mentioned, no TSO wanted to retain priority dispatch,
8 TSOs wanted to retain it with exemptions, 4 TSOs wanted a phase out of priority
dispatch, and 13 TSOs wanted priority dispatch to be removed entirely.
17
Regulatory exemptions from balancing responsibility
1.2. Regulatory exemptions from balancing responsibility
18
Regulatory exemptions from balancing responsibility
Summary table
1.2.1.
Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that
the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances caused.
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
This would maintain the status
quo, expressly requiring financial
balancing responsibility only under
the State aid guidelines which
allow for some exceptions.
Full balancing responsibility for all parties
Each entity selling electricity on the
market has to be a balancing responsible
party and pay for imbalances caused.
Balancing responsibility with exemption
possibilities for emerging technologies
and/or small installations
This would build on the EEAG.
Balancing responsibility, but possibility to delegate
This would allow market parties to delegate the
balancing responsibility to third parties.
This option can be combined with the other options.
Pros
Lowest political resistance Costs get allocated to those causing them.
By creating incentives to be balanced,
system stability is increased and the need
for reserves and TSO interventions gets
reduced. Incentives to improve e.g.
weather forecasts are created.
This could allow shielding emerging
technologies or small installations from the
technical and administrative effort and
financial risk related to balancing
responsibility.
The impact of this option would depend on the
scope and conditions of this delegation. A
delegation on the basis of private agreements, with
full financial compensation to the party accepting
the balancing responsibility (e.g. an aggregator)
generally keeps incentives intact.
Cons
Financial risks resulting from the
operation of variable power generation
(notably wind and solar power) are
increased.
Shielding from balancing responsibilities
creates serious concerns that wrong
incentives reduce system stability and
endanger market functioning. It can increase
reserve needs, the costs of which are partly
socialized. This is particularly relevant if
those exemptions cover a significant part of
the market (e.g. a high number of small RES
E generators).
The impact of this option would depend on the
scope and conditions of this delegation. A full and
non-compensated delegation of risks e.g. to a
regulated entity or the incumbent effectively
eliminates the necessary incentives. Delegation to
the incumbent also results in further increases to
market dominance.
Most suitable option(s): Option 2 combined with the possibility for delegation based on freely negotiated agreements.
19
Regulatory exemptions from balancing responsibility
Description of the baseline
1.2.2.
Balancing responsibility refers to the obligation of market actors (notably power
generators, demand response providers, suppliers, traders and aggregators) to
deliver/consumer exactly as much power as the sum of what they have sold and/or
purchased on the electricity market. Predictions for demand and (to a more limited
extent) generation being not 100 % precise, market actors are often not fully balanced.
The Transmission System Operator then ensures that total demand and supply are
maintained in balance by activating (upward or downward) balancing energy, often
coming from dedicated balancing capacities.
Balancing responsibility implies that the costs of the balancing actions taken by the
transmission system operator are generally to be compensated by the market parties
which are in imbalance. In some Member States, certain types of power generation
(notably wind and solar, but possibly also other technologies such as biomass) are
excluded from this obligation or have a differentiated treatment. Most Member States
foresee some degree of balancing responsibility also for renewable generators; based on
an EWEA (now Wind Europe) study, in 14 out of 18 Member States with a wind power
share above 2-3 % in annual generation, wind generators had some form of balancing
responsibility18
. This however does not always translate into real financial responsibility
of the generator for imbalances it caused. In Austria for example, a public entity,
OEMAG, acts as balancing responsible party for all subzidized renewable generation,
thus shielding individual generators from imbalance risks of their power plants19
and
collectively purchasing/selling balancing energy for the renewable sector20
. On the other
hand, in a small number of Member States balancing costs imposed on renewable power
generation can be prohibitively high and almost reach the level of wholesale prices (e.g.
incurred balancing costs of up to 24 EUR/MWh in Bulgaria and 8-10 EUR/MWh in
Romania)21
.
Article 28 (2) of the Balancing Guideline provides that "each balance responsible party
shall be financially responsible for the imbalance to be settled with the connecting TSO".
This does not, however, preclude frameworks in which market actors are (fully or partly)
shielded from the financial consequences of imbalances caused by having this
responsibility shifted to another entity. This is part of some current support schemes.
The EEAG provide that in order for State aid to be justified, RES E generators need to
bear full balancing responsibility unless no liquid intra-day market exists. The EEAG
rules however do not apply where no liquid intraday market exists, and and also do not
apply to installations with an installed electricity capacity of less than 500 kW or
18
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf, p. 5-6.
19
https://www.energy-
community.org/portal/page/portal/ENC_HOME/DOCS/2014187/0633975ACF8E7B9CE053C92FA8
C06338.PDF
20
http://www.oem-ag.at/de/oekostromneu/ausgleichsenergie/.
21
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf p. 8.
20
Regulatory exemptions from balancing responsibility
demonstration projects, except for electricity from wind energy where an installed
electricity capacity of 3 MW or 3 generation units applies. The exemption from
balancing responsibility in the absence of liquid intra-day markets is based on the
reasoning that were liquid intra-day markets do exist, they allow renewable generators to
drastically reduce their imbalances by trading electricity on short-term markets and thus
taking account of updated wheather forecasts. This shows that imposition of balancing
responsibility is thus closely linked to the creation of liquid short-term markets, one of
the main objectives of the electricity market design initiative.
The corollary to balancing responsibility is the possibility to participate in the balancing
market, offering balancing capacity to the TSO against remuneration. This is further
described under Section 5.1.1.4 and closely linked to the Balancing Guideline.
Deficiencies of the current legislation
1.2.3.
Already today, the increased share of renewable energies in power generation
(approximately 29% in 2015) has significant impact on market functioning and grid
operation. This effect is most noticeable in Member States with RES E shares above the
EU average.
The below figure shows two relevant weeks, with production and consumption shown
together. In the left graph, generation exceeds the load (red line) in situation with lots of
solar power generation (yellow). In the right graph, less renewable power is generated
(blue, green, yellow, but minimal PV (yellow)). Supply and demand of electricity has to
match at all times despite changes in demand and variable renewable electricity
production. For both situations, flexibility options such as storage, demand side response,
flexible generation and interconnection import/export capacities are needed to take up
electricity.
Figure 1: Volatility in the German power market in June and December 2013
Source: Agora Energiewende 2013.
To integrate renewable production progressively and efficiently into a market that
promotes competitive renewables and drives innovation, energy markets and grids have
to be fit for renewables. This is not necessarily the case in many jurisdictions since
markets have traditionally been designed to cater the needs of conventional generation
rather than variable renewables. To make markets fit for renewables means developing
21
Regulatory exemptions from balancing responsibility
adequately the short-term markets such as intraday and balancing. This also means
allowing, to the maximum possible extent, renewables to participate in all electricity
markets on equal footing to conventional generation removing all existing barriers for
renewable energy sources integration. Integrating RES E into the market and allowing
them to generate a large part of their revenues from market prices requires an increase of
flexibility in the system, which is also needed for absorbing cheap renewable electricity
at times of high supply. It is for this reason that the EEAG (para.124) requires generators
to be subject to standard balancing responsibilities only unless no liquid intra-day market
exists. Liquid intra-day markets should exist in all Member States at the expected date of
entry into force of the revised legislation, accompanying the present impact assessment.
However, the term "liquid intra-day market" allows significant margin of interpretation
and can thus cause uncertainty on the application of one of the fundamental rules on the
electricity market. It will be necessary to further clarify this exemption and ensure that
market actors have legal certainty as to whether they have to bear balancing
responsibility or not.
Investment incentives should take into account the value of generation at different times
of the day or of the year. Progress has been made in this area, with support schemes
relying increasingly (but not everywhere or for all generation) on premiums instead of
fixed feed-in tariffs. Where premium-based support schemes are used, the degree of
market exposure depends on their exact implementation, differing e.g. between fixed and
floating premium models, and for the latter relative to the determination of the base price
used for the calculation of the premium. Full exposure to market signals may e.g. make a
different generation installation more efficient although it produces lower total output
(such as orienting PV to the west to increase output later in the day). By exposing
generators to the financial consequences of imbalances caused, the incentives given to
generators do not relate only to optimizing the expected generation of their power plant
in view of market needs, but also to ensuring that the electricity they sell on the market
matches as closely as possible the power produced at a certain point in time. In a
questionnaire to TSOs organized by ENTSO-E, the example was given that following the
attribution of balancing responsibility in a Member State, the average hourly imbalance
of PV installations improved from 11.2 % in 2010 to 7.0 % in March 2016, and the
average hourly imbalance of wind improved from 11.1 % to 7.4 % over the same period.
Where RES E generators do not assume balance responsibility identical to other
generators and participate in the balancing market, they lack incentives for efficient
operational and investment decisions22
. Part of this challenge is the need to avoid
inacceptable risks for RES E investors by imposing balance responsibilities without
22
KEMA study commissioned for the EU Commission (ENER/C1/427-2010, Final report of 12 June
2014), p.185
22
Regulatory exemptions from balancing responsibility
creating the market flexibility which allows staying balanced23
. Whereas many Member
States already foresee some balancing responsibility for RES E generators (2013: 16
Member States)24
this is not yet the case for all Member States, and the degree of
balancing responsibility differs considerably between Member States. This can result in
market distortions, directing investments to Member States with lower degree of
responsibility rather than to those Member States where electricity demand and
renewable generation potential are optimal, and can also result in lower liquidity of short-
term markets.
Reduced balancing responsibility can also result in increasing imbalances in electricity
trades. Whereas the TSO will generally, via the balancing market, be capable of covering
imbalances, a high degree of imbalances reduces predictability of system operation and
can increase system stress (e.g. by reducing the volume of available reserves) or increase
costs for system stability (e.g. if higher reserve volumes are procured in advance).
Finally, it should be noted that the EEAG already foresees the need to phase out
exemptions from balancing responsibilities in the post-2020 period25
. The EEAG itself
provides in its paragraph 108 that the Guidelines "apply to the period up to 2020 but
should prepare the ground for achieving the objectives set in the 2030 framework,
implying that subsidies and exemptions from balancing responsibilities should be phased
out in a degressive way".
Refrence is also made to Section 7.4.2 of the evaluation.
Presentation of the options
1.2.4.
Balancing responsibility of all market parties active on the electricity market is a
fundamental principle of EU energy law. This principle should not be included only in a
State aid guideline and in the Balancing Guideline but ensured at the level of secondary
law, thus increasing transparency and legal certainty. Exemptions currently foreseen in
the guidelines need to be reassessed and, where still necessary, further clarified. It should
also be further clarified in how far and under which conditions delegation of this
responsibility is possible. It is thus proposed to establish a general rule that all market-
related entities or their chosen representatives shall be financially responsible for their
imbalances, and that any such delegation/representation shall not entail a disruption of
incentives for market parties to remain balanced. Provisions in this direction are already
included in the Balancing Guideline which will be discussed in Comitology in the second
23
KEMA p. 185: "Experience from some EU countries has shown that RES generators are able to
provide less volatile and more predictable generation schedules if so incentivized by balancing
arrangements."
24
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd04_en.pdf
Appendix I table 6.
25
Paragraph 108 EEAG reads: "These Guidelines apply to the period up to 2020. However, they should
prepare the ground for achieving the objectives set in the 2030 Framework. Notably, it is expected that
in the period between 2020 and 2030 established renewable energy sources will become grid-
competitive, implying that subsidies and exemptions from balancing responsibilities should be phased
out in a degressive way. These Guidelines are consistent with that objective and will ensure the
transition to a cost-effective delivery through market-based mechanisms."
23
Regulatory exemptions from balancing responsibility
half of 2016. General principles and, where applicable, exemptions shall be integrated
into the Electricity Directive for added clarity and legal certainty.
Option 0: do nothing
This would mean that balancing responsibility remains subject only to State aid rules and
the rules in the Balancing Guideline. Fundamental principles of electricity market
operation should systematically not be decided upon only in acts adopted under the
Comitology process and guidelines which undergo no legislative process. Furthermore,
the EEAG are limited in time to 2020 and uncertainty as to the extent of their exemptions
and their applicability post-2020 will persist. According to their paragraph 108, it is
expected that in the period between 2020 and 2030 established renewable energy sources
will become grid-competitive, implying that subsidies and exemptions from balancing
responsibilities should be phased out in a progressive way (and thus assuming liquid
short-term markets to develop). Finally The State aid guidelines only apply to those parts
of measures which are to be seen as State aid. This concerns most, but not necessarily all,
generation which may not be fully balancing responsible. For some aspects the
qualification as State aid could potentially be put into question.
Option 0+: Non-regulatory approach
As national law is extremely varied to date, without a clear and transparent framework
setting out the degree of balancing responsibility, enforcement of existing rules (e.g.
State aid rules) is unlikely to result in a uniform and non-discriminatory legal framework.
Voluntary cooperation can contribute to reducing the negative impact of imbalances.
Imbalance netting by transmission system operators already achieves significant cost
reductions. However, voluntary cooperation does not provide sufficient legal certainty
and the minimum degree of harmonization to avoid distortions in cross-border trade. In
fact, shielding certain market parties fully or in part from balancing responsibilities
creates economic advantages which can distort cross-border trade in electricity. Where a
lack of balancing responsibility results in increased imbalances, this will negatively
impact the whole synchronous area, and thus create costs and risks for system stability
also in other Member States.
Option 1: Full Balancing responsibility for all parties
This would entail that the principles of the Balancing Guideline imposing all market-
related entities and their representatives to be financially responsible for imbalances
caused would be integrated into the Electricity Directive.
This option would thus significantly increase transparency and legal certainty. Balancing
responsibility is already an accepted concept under the EEAG, so that the market impact
would be limited to those entities currently benefitting from exemptions or not subject to
State aid rules. While this option would optimally achieve the defined objective, the
complete abolishment of the existing exemptions could result in increased administrative
effort for small installations or demonstration projects using emerging technologies.
Option 2: Balancing responsibility with exemption possibilities for emerging
technologies and/or small installations
24
Regulatory exemptions from balancing responsibility
This would allow Member States to foresee that certain emerging technologies and/or
small installations (e.g. rooftop solar) are shielded from the direct financial impact of
imbalances they cause. As imbalances need to be covered by some entity, this could be
achieved by allocating it to public bodies (essentially meaning that these entities are
acting as sellers of RES E on the wholesale market), the costs of which are then
socialized.
This option addresses the currently existing exemptions under EEAG, based on the
assumption that short-term markets have developed sufficiently by the time of entry into
force of the proposed legislation to require balancing responsibility of generators not
covered by the exemptions. Without introducing additional limitations, these exemptions
would however risk reducing effectiveness in achieving the policy objective. This is
notably the case for small installations, which under some scenarios can account for a
significant part of total electricity supply.
Option 3: Possibility to delegate balancing responsibility
This option would entail the right to delegate balancing responsibilities to a third party.
Whereas the freely negotiated delegation to a third party against financial compensation
(e.g. an aggregator) can reduce administrative impact without reducing the incentive to
reduce imbalances (as their cost will be passed on to the generator in some way),
regulated delegations without compensation drastically reduce or eliminate the incentive
to remain balanced.
The possibility to delegate on the basis of free negotiation, against financial
compensation, (combined with exemptions notably for demonstration projects and
possibly very small installations) is the preferred option. It fully achieves the policy
objectives, and allows notably smaller installations to reduce administrative efforts
without reducing market incentives.
Comparison of the options
1.2.5.
The requirement of full balancing responsibility does not affect all renewable
technologies in the same manner. Biomass and other non-variable technologies are
generally capable of being balanced to the same degree as conventional generators.
Variable generators (especially wind and PV) can increasingly predict their generation
based on wheather forecasts, but have a higher margin of error in those predictions than
conventional generators. To reduce the margin of error, those technologies need to
improve wheather forecasts, as well as sell electricity for shorter time periods in advance,
when better forecasts become available.
A study using METIS has shown very significant reductions in frequency restoration
reserve needs due to the introduction of balancing responsibilities for RES E. Whereas
FCR and aFRR needs relate to short-term frequency deviations and are thus not
significantly affected by balancing responsibility, mFRR needs are based on longer-
lasting deviations from indicated schedules. By creating incentives for improved
forecasts and more exact schedules, reserve needs are thus significantly reduced.
25
Regulatory exemptions from balancing responsibility
Figure 2: reduction in reserve needs depending on balancing responsibility
Source: METIS
Option 1 would be most effective at achieving the objective of well-functioning markets.
All exemptions from balancing responsibility, even if only partly shielding against the
financial impact of imbalances, reduce the incentive to be balanced. The complete
abolishment of the existing exemptions would however result in increased administrative
effort for small installations or demonstration projects using emerging technologies. This
could slow down roll-out of new RES E technologies and could thus render the
achievement of the decarbonisation objective more costly. Options 2 and 3 can be
combined to ensure a maximum degree of balancing responsibility with the potential to
delegate this responsibility, which allows reduction of the additional administrative
impact imposed especially on small installations. This being said, small installations are
currently often not active on the market, and it could be excessive to require balancing
responsibility even taking into account the possibility to delegate. The preferred option is
thus a derogation from balancing responsibilities for demonstration projects and small
generation (e.g. rooftop solar), and the right for other projects to delegate their balancing
responsibility against financial compensation. This significantly reduces the
administrative effort for households and small and medium enterprises (who will often
continue to benefit from exemptions from balancing responsibilities) but takes account of
the increased role renewable generation plays in the market, and the improved
capabilities particularly of larger generators to predict their output and reduce or hedge
remaining imbalance risks.
Subsidiarity
1.2.6.
Balancing responsibility is a fundamental principle in every electricity market. It ensures
that market agreements are also reflected in the physical reality, and that the costs of
imbalances created are born by those creating them. Balancing responsibiltity impacts
26
Regulatory exemptions from balancing responsibility
both investment decisions and trading on electricity markets; every decision to sell
electricity on the market entails the risk to be in imbalance, which thus has to be
integrated into bidding strategies. Deviations on a national level in an integrated market
could result in distortions of cross-border trade, e.g. by making investments into variable
generation in one Member State significantly more interesting than in other Member
States, and basic principles for balancing responsibility thus need to be harmonized.
Furthermore, increasing the share of RES E in the total energy consumption is an EU
target. For 2030, a target binding at EU level exists, without nationally binding targets;
therefore the EU has to ensure the EU target is reached. With an increasing share of RES
E, they become a relevant player on the power markets. As power markets are
increasingly integrated, this has direct cross-border impact. Equal treatment to all
generation technologies should be ensured to avoid market distortions. Markets should be
fit to allow all generation technologies and demand to compete on equal footing, while
allowing the EU to reach the policy objectives of sustainability, competitiveness and
security of supply. The increasing share of RES E also creates challenges for network
operation. In synchronous areas even exceeding the EU, this is an issue which cannot be
resolved at national level alone.
Stakeholders' opinions
1.2.7.
In the public consultation, most stakeholders support the full integration of renewable
energy sources into the market, e.g. through full balancing obligations for renewables,
phasing-out priority dispatch and removing subsidies during negative price periods.
Many stakeholders note that the regulatory framework should enable RES E to
participate in the market, e.g. by adapting gate closure times and aligning product
specifications. A number of respondents also underline the need to support the
development of aggregators by removing obstacles for their activity to allow full market
participation of renewables. The approach chosen in the State aid guidelines found broad
support by most stakeholders.
Wind Europe's predecessor EWEA submitted26
that in 14 out of 18 Member States, wind
generators were already balancing responsible in financial or legal terms, generally
subject to the same rules as conventional generation. However, in some Member States,
balancing costs for renewable generators appeared discriminatorily high. Important
considerations for wind generators to accept balancing responsibility were, for EWEA:
(i) the existence of a functioning intra-day and balancing market, (ii) balancing market
arrangements providing for the participation of wind power generators, as e.g. shorter
gate closure time and procurement timeframes, (iii) market mechanisms that properly
value the provision of non-frequency ancillary services for all market participants
including wind power, (iv) a satisfactory level of market transparency and proper market
monitoring, (v) sophisticated forecast methods in place in the power system and (vi) the
necessary transmission infrastructure. While forecast methods should be developed by
the market and cannot be provided directly in policy (which can only give incentives for
26 http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
27
Regulatory exemptions from balancing responsibility
such methods to be improved and used), the market design initiative aims at achieving all
these points.
In its consultation of national TSOs, ENTSO-E also adressed questions on balancing
responsibility. TSOs in five Member States answered that after introduction of balancing
responsibilities, RES E generators were more motivated to conclude energy production
contracts which are close to the real production in each market time unit; for four
Member States, better forecasts were used by RES E generators. 1 TSO provided figures
according to which the average hourly imbalance of PV installations improved from
11.2 % in 2010 to 7.0 % in March 2016, and the average hourly imbalance of wind
improved from 11.1 % to 7.4 % over the same period.
28
Regulatory exemptions from balancing responsibility
29
RES E access to provision of non-frequency ancillary services
1.3. RES E access to provision of non-frequency ancillary services
RES E access to provision of non-frequency ancillary services
Summary table
1.3.1.
Objective: transparent, non-discriminatory and market based framework for non-frequency ancillary services
Option 0 Option 1 Option 2
BAU
Different requirements, awarding procedures and
remuneration schemes are currently used across
Member States. Rules and procedures are often tailored
to conventional generators and do not always abide to
transparency, non-discrimination. However increased
penetration of RES displaces conventional generation
and reduces the supply of these services.
Description
Set out EU rules for a transparent, non-discriminatory and
market based framework to the provision of non-frequency
ancillary services that allows different market players
/technology providers to compete on a level playing field.
Description
Set out broad guidelines and principles for Member States for the
adoption of transparent, non-discriminatory and market based
framework to the provision of non-frequency ancillary services.
Stronger enforcement
Provisions containing reference to transparency, non-
discrimination are contained in the Third Package.
However, there is nothing specific to the context of
non-frequency ancillary services.
Pro
Accelerate adoption in Member States of provisions that
facilitate the participation of RES E to ancillary services as
technical capabilities of RES E and other new technologies is
available, main hurdle is regulatory framework.
Clear regulatory landscape can trigger new revenue streams
and business models for generation assets.
Pro
Sets the general direction and boundaries for Member States
without being too prescriptive.
Allows gradual phase-in of services based on local/regional needs
and best practices.
Con
Resistance from Member States and national
authorities/operators due to the local/regional character of
non-frequency ancillary services provided.
Little previous experience of best practices and unclear how
to monitor these services at DSO level where most RES E is
connected.
Con
Possibility of uneven regulatory and therefore market developments
depending on how fast Member States act. This creates uncertain
prospects for businesses slowing down RES E penetration.
Most suitable option(s): Option 2 is best suited at the current stage of development of the internal electricity market. Ancillary services are currently procured and sometimes used in very
different manners in different Member States, Furthermore, new services are being developped and new market actors (e.g. batteries) are quickly developing. Setting out detailed rules required
for full harmonisation would thus preclude unknown future developments in this area, which currently is subject to almost no harmonisation.
31
RES E access to provision of non-frequency ancillary services
Description of the baseline
1.3.2.
The delivery of frequency related ancillary services by RES E assets is partly covered by
the Balancing Guideline.
Non-frequency ancillary services are services procured or mandated by TSOs that
support the electricity network, such as voltage support, short circuit power, black start
capability, synthetic inertia or congestion management. They are in most cases supplied
by electricity generators, but can in some cases also be supplied by demand facilities,
electricity storage or network equipment.
Currently, the procurement of non-frequency anciliary services is not regulated at EU-
level. The situation in Member States for the provision of non-frequency ancillary
services is determined by national grid codes that inter alia specify the rules for
connection of generation assets to the electric network infrastructure. Grid codes are
evolving continuously, but a snapshot taken recently through studies funded by the
European Commission27
, a survey commissioned by ENTSO-E28
and by examining the
actual national grid codes, reveals that several approaches are considered in Europe
across more than a dozen Member States (as well as Norway and Switzerland) surveyed.
The snapshot, summarized in Figures 1 to 3, focuses only on the provision of reactive
power, i.e. voltage related ancillary services, one of the most important non-frequency
ancillary services. It is important to point out that the overview is partial and does not
cover all specific arrangements TSOs might have. For instance in Denmark, these
services are not generally remunerated, however in certain periods of the year when
thermal plants are not operating, these services are remunerated to guarantee sufficient
supply.
27 "REserviceS project" (2014) Intelligent Energy Europe programme, http://www.reservices-project.eu/
28 "Survey on Ancillary Services Procurement and Electricity Balancing Market Design" (2015) ENTSO-
E,
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
32
RES E access to provision of non-frequency ancillary services
Figure 1: Grid code requirements for generators on reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
Figure 2: Procurement procedure of reactive power
Source: National grid codes, ENTSO-E survey, REserviceS project
33
RES E access to provision of non-frequency ancillary services
Figure 3: Remuneration of reactive power delivery
Source: National grid codes, ENTSO-E survey, REserviceS project
Currently the practises with regard to requirements, procurement and renumeration of
non-frequency anciliary services can be summarised as follows:
- Requirements: most Member States demand mandatory provision from
conventional generators and in some cases specific provisions are considered for
RES E, mostly wind. The latter approach is in line with the Commission
Regulation (EU) 2016/631 establishing a network code on requirements for grid
connection of generators ('RfG');
- Procurement: a majority of Member States procure these services through
bilateral agreements and only in a small minority of Member States market based
tenders are used. In other Member States both bilateral agreements and market
based tenders are used;
- Remuneration: about half of the surveyed Member States do not have a
mechanism to remunerate the service, the other half does remunerate them either
by capability, utilisation or a combination of both. In some Member States, a
bonus is given to RES E for upgrading the infrastructure.
Deficiencies of the current legislation
1.3.3.
The current EU regulatory framework defines in Article 12 lit. d) of the Electricity
Directive the role of the TSO: it includes ensuring the availability of all necessary
ancillary services. However, there is nothing specific with regard to non-frequency
ancillary services. The RfG specifies extensively requirements for the provision of
reactive power by different power modules. However, it does neither address the
procedures by which such services should be awarded (e.g; a market based mechanism),
nor whether they should be remunerated (as such or on the basis of what criteria e.g.
capacity, utilisation or a combination thereof). Additionally, the RfG is not likely to lead
to an efficient deployment of reactive power capability on the territory as voltage support
34
RES E access to provision of non-frequency ancillary services
services have a geographical dimension and need to be provided in specific locations.
This might lead to an oversupply of reactive power capability (with associated increased
costs born by the generators) and at the same time underutilization of installed capability
because they are not suitably located. The System Operation Guideline aims at ensuring
that TSOs use market-based mechanisms as far as possible to ensure network security
and stability, but does not articulate further this high level principle.
The current legislation is insufficient and needs to be adapted to trends observed in the
market where studies project that the demand for non-frequency ancillary services across
Europe will increase over the coming decades, mainly because of increased RES E
penetration. A technical and economical study by Électricité de France (EDF)29
concluded that "it is essential that variable RES production which is displacing
conventional generation is also able to contribute to the provision of ancillary services
and also potentially provide new services (e.g. inertia)". A study commissioned by the
German Energy Agency Dena30
found that "due to increasing transport distances and
international power transit, the demand for reactive power in the transmission grid will
increase significantly by 2030."
Presentation of the options
1.3.4.
Option 0 - BAU
In a business-as-usual scenario, non-frequency ancillary services are mainly provided by
large conventional generators. Although those services are currently not remunerated in
all Member States, TSOs would need those generators to run even if not profitable.
Therefore such generators would request additional revenues. This scenario prevent the
access to additional revenue streams for new types of generation assets, mainly being
RES E.
Since RES E are displacing conventional generation assets, the supply of these services is
becoming scarcer. As a result, generation from RES E would be curtailed at certain times
to guarantee the safe operation of the electric network. This would likely slow down the
deployment of RES E and affect negatively the achievement of the European wide
renewable energy consumption targets by 2020 and 2030 and related climate goals.
Option 0+: Non-regulatory approach.
The Third Package does not address the provision of non-frequency ancillary services in
a way that could be used to enforce existing legislation stronger. Voluntary cooperation
does not provide the necessary minimum degree of harmonization and legal certainty to
allow for efficient cross-border trade. Even where non-frequency anciliary services have
to be provided on a local level, the provision of and revenues from these services can
29
"Technical and Economic analysis of the European Electricity System with 60% RES" (2015) Alain
Burtin & Vera Silva, http://www.energypost.eu/wp-content/uploads/2015/06/EDF-study-for-
download-on-EP.pdf
30
"Dena Ancillary Services Study 2030" (2014) German Energy Agency,
http://www.dena.de/en/projects/energy-systems/dena-ancillary-services-study-2030.html
35
RES E access to provision of non-frequency ancillary services
have a significant impact on the competitiveness of electricity generation, which
competes cross-border.
Option 1 - EU rules setting out a framework for a transparent, non-discriminatory, market
based framework
This option would imply setting EU wide harmonized rules in EU legislation on
requirements of generators for connection to the grid, on specifications and procurements
of products to ensure a level-playing field and fair remuneration of these services. This
would encounter a number of issues: even though the provision of non-frequency
ancillary services is necessary to run a European wide electricity market, due to the
local/regional character of these services, optimal solutions may vary across Member
States. Additionally, it would require the coordination of both transmission and
distribution system operators as a large fraction of RES E is installed at the distribution
level. These services are not generally remunerated at lower voltage levels and no clear
framework is yet available on how to regulate these services. Finally, there are still
significant challenges for market based integration of ancillary services from RES E due
to limitations of predictability of energy output.
Option 2 - Guidelines setting out the principles for the adoption of a transparent, non-
discriminatory, market based framework.
The aim is to provide a sound basis for the development of a non-discriminatory,
transparent and market based access to non-frequency ancillary services by RES E and to
allow the gradual phase-in of services based on local/regional needs and best practices.
This is a pre-requisite for a cost efficient allocation of resources to provide the necessary
supply of non-frequency ancillary services. The measures should be articulated along the
following main lines:
- ensure that the regulatory requirements for the provision of these services are
rational with respect to the expected needs (both in terms of quantity and
location) and non-discriminatory with respect to different assets capable of
providing the service.
- bring transparency to the way ancillary services are procured, for instance
through market-based tenders or auctions and allow sufficient flexibility in the
process to accommodate bids from assets with different technical characteristics;
- promote mechanisms for remuneration by system operators;
- consult stakeholders when establishing new rules to make sure all assets can
participate to these services while providing support for safe grid operation.
These measures are also conducive to a higher penetration of RES E in the electricity
network and could be further developed in a dedicated network code.
Comparison of the options
1.3.5.
The BAU scenario would not be effective in designing a level-playing field for a non-
discriminatory, transparent and market based access to non-frequency ancillary services
and in achieving the objectives of increasingly integrated RES E in a European electricity
market. It would also be an obstacle for further increase of RES E in the generation mix
with a potential negative impact on the achievement of the 2030 targets. In the current
situation, where ancillary services are provided by conventional generators, curtailment
of RES E is required at times to assure the availability of generation assets capable of
36
RES E access to provision of non-frequency ancillary services
providing ancillary services (so-called "must run"). The decision to keep these resources
online is not based on economic assessments, but only on operational considerations for a
safe operation of the grid. Such constraint would not exist or not to the same extent if
RES E resources would be used to their fullest potential to provide non-frequency
ancillary services.
Options 1 and 2 would be more effective in providing a non-discriminatory, transparent
and market-based environment for RES E and new technologies to offer and compete for
the provision of non-frequency ancillary services. Companies, especially owners of RES
E assets would benefit from additional revenue streams from ancillary markets.
Extrapolating the European wide market size for non-frequency ancillary services from
national markets (typically in the range of tens of millions of euros) puts it roughly in the
range of a few billion euros.
In addition, the investment outlook for additional power plants would be better for
owners of RES E assets. Taking Ireland as a best practice case, regulators and TSOs are
redesigning the ancillary service market in such a way that RES E can participate. It
requires introducing new services and allowing these services to be remunerated. This
has the additional benefit that the electricity generation share of RES E in such a
redesigned market can be higher without compromising the safe operation of the grid and
allows system operators to make efficiency gains: the Irish All Island TSOs compared the
estimated costs of enhancing the operational capabilities of ancillary services with the
benefits of lower market prices coming from a larger share of wind energy generation.
They concluded that the benefit outwheighted the costs already at System Non-
Synchronous Penetration levels below 50%31
.
Based on the studies and sources mentioned in this and other Sections of this annexe,
little uncertainty exists about the benefits of more transparent provision of ancillary
services, one where RES E could participate. For certain services, especially those that
have a limited geographical scope, it is unclear if and how liquid markets could be
established, with regulated cost+ payments being a possible alternative.
The second Option is preferred over the first one, because at this moment there is not
enough evidence to support European wide harmonized rules for non-frequency ancillary
services. New services are being developed and new market players are emerging. The
first option could preclude unknown future developments in this area, whereas the second
option allows the gradual phase-in of services based on local/regional needs and best
practices.
Subsidiarity
1.3.6.
Even though non-frequency anciliary services, such as voltage related ancillary services
have a local character, it does not prevent action through the market design initiative.
The efficient provision of these services is a critical enabler of an integrated European
31
"Onshore wind supporting the Irish grid" (2013) Andrej Gubina, http://www.reservices-project.eu/wp-
content/uploads/D5.1-REserviceS-Ireland-case-study-Final.pdf
37
RES E access to provision of non-frequency ancillary services
electricity market and of higher RES E penetration. Also, the assets that provide non-
frequency ancillary services are largely the same ones providing frequency-related
services: a local problem due to voltage stability could have implications for the
provision of frequency-related services and the stability of the grid at a European level as
a whole. Finally, the assets providing ancillary services are generally competing in other
markets with a larger geographical scope, including the day ahead and intraday electricity
markets. Conditions on voltage control thus have an impact on cross-border competition
in electricity markets.
Stakeholders' opinions
1.3.7.
RES E32
and demand response33
industry associations and owners of storage34
assets
assert the technical availability to provide non-frequency ancillary services, but expose
difficulties accessing the market because of non-transparent rules for contracting,
minimum product size and other product specifications, as well as procurement lead
times. Younicos, a storage provider, states that "storage is not defined in regulatory
framework on national or EU level, creating uncertainty on market access and creating
uncertainty on ownership roles." Similarly, the Association of European Manufacturers
of automotive, industrial and energy storage batteries (EUROBAT), calls for a legislative
definition of storage which allows system operators to own and operate battery storage.
The association calls for the value of services offered by storage systems, including
voltage control, frequency control and ramp control, to be financially recognized.
Anciliary services should thus be compensated35
. The European Wind Energy
Association points out that the reactive power requirements at low active power set
points imposed on RES E in the frame of the RfG code could potentially have a
substantial negative impact on the investment costs of new wind power plants..
Energinet.dk considers increased competition for the supply of ancillary services "as a
part of the continuous development of the energy only market with the objective to create
clear price signals and creating socio economic benefits and security of supply on short
and long run". Geographical requirements for delivery of ancillary services is a challenge
in developing these markets as well as the fact that grid components such as
"synchronous compensators and HVDC VSC-convertors have a potential to deliver
system supporting services in competition with commercial power plants. This
development demands transparency in the procurement process to secure optimal
planning, operations and investments"36
.
32
"Balancing responsibility and costs of wind power plants" (2015) European Wind Energy Association,
http://www.ewea.org/fileadmin/files/library/publications/position-papers/EWEA-position-paper-
balancing-responsibility-and-costs.pdf
33
"Mapping Demand Response in Europe today" (2015) Smart Energy Demand Coalition,
http://www.smartenergydemand.eu/wp-content/uploads/2015/09/Mapping-Demand-Response-in-
Europe-Today-2015.pdf
34
"Technical and regulatory aspects of the provision of ancillary services by battery storage" (2015)
Younicos
35 "Battery Energy Storage in the EU: barriers, opportunities, services and benefits" (2016) EUROBAT,
http://www.eurobat.org/sites/default/files/eurobat_batteryenergystorage_web.pdf p.30.
36
"Markets for ancillary and system supporting services in Denmark" (2016) Energinet.dk
38
RES E access to provision of non-frequency ancillary services
Two joint papers by Statkraft and Dong Energy point out that "in the past, system
services have played a marginal role in total economics of power plants. In the future,
however, system services will be more important for the individual plant and the value
(balance of supply and demand of these services) to the system are likely to be markedly
higher", and that "requirements put into tenders are crucial for the outcome".37
37
"Does the wholesale electricity market design need more products, or more control?" Part 1 (2015) &
Part 2 (2016) Dong Energy & Statkraft
39
RES E access to provision of non-frequency ancillary services
2. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(B)
STRENGTHENING SHORT-TERM MARKETS
40
RES E access to provision of non-frequency ancillary services
41
Reserves sizing and procurement
2.1. Reserves sizing and procurement
Reserves sizing and procurement
Summary table
2.1.1.
Objective: define areas wider than national borders for sizing and procurement of balancing reserves
Option 0: business as usual Option 1: national sizing and procurement of
balancing reserves on daily basis
Option 2: regional sizing and procurement of
balancing reserves
Option 3: European sizing and procurement of
balancing reserves
Description
The baseline scenario consists of
a smooth implementation of the
Balancing Guideline. Existing
on-going experiences will remain
and be free to develop further, if
so decided. However, sizing and
procurement of balancing
reserves will mainly remain
national as foreseen in the
Balancing Guideline.
Active participation in the
Balancing Stakeholder Group
could ensure stronger
enforcement of the Balancing
Guideline.
This option consists in developing a binding
regulation that would require TSOs to size
their balancing reserves on daily probablistic
methodologies. Daily calculation allows
procuring lower balancing reserves and,
together with daily procurement, enables
participation of renewable energy sources
and demand response.
This option foressees separate procurement
of all type of reserves between upward (i.e.
increasing power output) and downward (i.e.
reducing power output; offering demand
reduction) products.
This option involves the setup of a binding
regulation requiring TSOs to use regional
platforms for the procurement of balancing
reserves. Therefore this option foresees the
implementation of an optimisation process for
the allocation of transmission capacity between
energy and balancing markets, which then
implies procuring reserves only a day ahead of
real time.
This option would result in a higher level of
coordination between European TSOs, but still
relies on the concept of local responsibilities of
individual balancing zones and remains
compatible with current operational security
principles.
This option would have a major impact on the
current design of system operation procedures
and responsibilities and current operational
security principles. A supranational independent
system operator ('EU ISO') would be
responsible for sizing and procuring balancing
reserves, cooperating with national TSOs. This
would enable TSOs to reduce the security
margin on transmission lines, thus offering
more cross-zonal transmission capacity to the
market and allowing for additional cross-zonal
exchanges and sharing of balancing capacity.
Pros
Pro – optimal national sizing and
procurement of balancing reserves
Pro –regional areas for sizing and procurement
of balancing reserves
Pro – single European balancing zone
Cons
Con – no cross-border optimisation of
balancing reserves
Con – balancing zones still based on national
borders but cross-border optimisation possible
Con – extensive standardisation through
replacement of national systems, difficult and
costly implementation
Most suitable option(s) Option 2. Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the
physical topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the
preferred option.
43
Reserves sizing and procurement
Description of the baseline
2.1.2.
Balancing refers to the situation after markets have closed (gate closure) in which a TSO
acts to ensure that demand is equal to supply. A number of stakeholders are responsible
for organising the electricity balancing market:
- Transmission system operators ('TSOs') keep the overall supply and demand in
balance in physical terms at any given point in time. This balance guarantees the
secure operation of the electricity grid at a constant frequency of 50 Hertz.
- Balance responsible parties ('BRPs') such as producers and suppliers; keep their
individual supply and demand in balance in commercial terms. Achieving this
requires the development of well-functioning and liquid markets. BRPs need to be
able to trade via forward markets and at the day-ahead stage. They also need to be
able to fine-tune their position within the same trading day (e.g. when wind forecasts
or market positions change).
- Balancing service providers ('BSPs') such as generators, storage or demand facilities,
balance-out unforeseen fluctuations on the electricity grid by rapidly increasing or
reducing their power output. BSPs receive a capacity payment for being available
when markets have closed ('balancing capacity' also referred to as 'balancing reserve')
and an energy payment when activated by the TSO in the balancing market
('balancing energy'). Payments for balancing capacity are often socialized via the
transmission network tariffs, whereas payments for balancing energy usually shape
the price that BRPs who are out of balance have to pay ('imbalance price').
Currently, national balancing markets in Europe have significantly different market
designs and are operated according to different principles38
. To achieve efficiency gains
through a genuine European balancing market, it is essential to provide a set of common
principles. As one can expect the adoption of the Balancing Guideline in 2017, it is
possible to agree on the baseline, which can be built upon in the market design initiative.
The Balancing Guideline covers, in particular:
- Standardisation of balancing products39
used by TSOs to maintain their system in
balance. The starting point is a situation where, in Europe, the number of balancing
products is estimated at some hundred. TSOs will have to reduce this number as
much as possible to create a harmonised competitive market.
- Merit order activation of balancing energy based on European platforms, i.e.
operational within 4 years after the entry into force, where all TSOs will have access
while taking into account cross-zonal transmission capacity available or released after
intraday gate closure.
38
ENTSO-E survey on ancillary services, May 2016:
https://www.entsoe.eu/Documents/Publications/Market%20Committee%20publications/WGAS%20Su
rvey_04.05.2016_final_publication_v2.pdf?Web=1
39
The term "product" refers to different balancing services which can be traded, such as the provision of
balancing energy with different speeds of delivery.
44
Reserves sizing and procurement
- Single marginal pricing ('pay-as-cleared') which reflects scarcity for the remuneration
of the participants in the balancing market (i.e. the payment that a participant receives
for providing balancing energy to be the same payment as the imbalance price). Thus
being individually in imbalance but contrary to the imbalance of the system as a
whole, thus helping the system as a whole to stay balanced, gets rewarded rather than
penalized.
- Harmonisation of the length of the imbalance settlement periods ('ISP' i.e. the time
over which it is measured whether BRPs stay in balance, i.e. they did not sell more
electricity than they produced). Trading products are generally not shorter than, but
can be multiples of ISP. The length of the ISP is thus of relevance for all market
timeframes and not just for the balancing market. In cross-border trade, the biggest
common ISP has to be used. Thus, the smallest trading product across Europe is
currently 60 minutes which corresponds to the length of the longest ISP across
Member States. However, where two Member States have shorter ISPs, shorter
products can be traded across their border (e.g. 30 minutes between France and
Germany). To increase the trade of short products, the Balancing Guideline proposes
a shift to harmonized 15 minutes ISPs40
.
The Balancing Guideline also provides the baseline for integrating renewable energy
sources and demand response in the balancing market, in particular:
- Balancing energy gate closure time (i.e. the point in time after which there can be no
more balancing energy offers from BSPs) as close as possible to physical delivery,
and at least after intraday cross-zonal gate closure (thus a maximum of 60 minutes
before real time). Shorter gate closure time allows wind or PV generators and
demand response aggregators to update their forecast and to offer remaining energy
to the electricity balancing market.
- Possibility to offer balancing energy without a balancing capacity contract. The
procurement timeframes for balancing capacity have generally long lead times for
which wind or PV power producers and demand response aggregators cannot secure
firm capacity.
- Shorter procurement timeframes for balancing capacity (close to real time).
It would be, however, out of the scope of the Balancing Guideline to aim for full
harmonization of the currently very diverse balancing markets. The Balancing Guideline
includes many exemptions (e.g. central dispatch systems, procurement rules for
balancing capacity) and possible derogations (e.g. dual pricing as opposed to single
marginal pricing). It is therefore essential that all national balancing markets adhere to a
minimal set of common principles.
In addition, balancing reserves are currently mainly sized and procured by TSOs on a
national level (except for the Nordic countries and the Iberian Peninsula). This contrasts
with the increasing demand for balancing reserves across Europe over the coming
40
"Frontier Economics report on the harmonisation of the imbalance settlement period", April 2016
https://www.entsoe.eu/Documents/Network%20codes%20documents/Implementation/CBA_ISP/ISP_
CBA_Final_report_29-04-2016_v4.1.pdf
45
Reserves sizing and procurement
decades which is mainly due to large-scale cross-border flows and high volumes of
variable RES E generation. Most of the TSOs are sizing their balancing reserves based on
potential outages of HVDC interconnectors and forecast errors of renewable energy
sources. Despite trends observed in the market (see below figure from ELIA, the Belgian
TSO)41
on the evolution of balancing reserves needs from 2013 to 2018, no significant
binding harmonisation is achieved on this subject in the Balancing Guideline.
Graph 1: Interpolated ranges for the volume of reserves needed between 2013 and
2018
Source: Belgian TSO report on the evolution of ancillary services needs to balance the Belgian control
areas towards 2018, pp. 32)
In their Market Monitoring report 201442
, ACER points out that in most European
markets, the procurement of balancing capacity represents the largest proportion of the
overall costs of balancing. The excessive weight of the balancing capacity procurement
costs may suggest that the procurement of balancing capacity is not always optimised.
ACER emphasis the importance of optimising the procurement costs of balancing
capacity, including separate procurement of upward and downward balancing capacity
and shorter procurement timeframes.
41
Belgian TSO report on the evolution of ancillary services need to balance the Belgian control area
towards 2018, May 2013
http://www.elia.be/~/media/files/Elia/Grid-data/Balancing/Reserves-Study-2018.pdf
42
"Market Monitoring Report 2014" (2015) ACER, pp. 210.
46
Reserves sizing and procurement
Graph 2: Overall costs of balancing (capacity and energy) and imbalance charges
over national electricity demand in a selection of European markets – 2014
(euros/MWh)
Source: "Market Monitoring Report 2014" (2015) ACER, pp. 209
Moreover, because only flexible generation assets can provide balancing reserves,
balancing markets tend not to be very competitive. Balancing markets are regularly rather
concentrated on the supply side as only assets able to adjust production or consumption
fast can participate. In their Market Monitoring report 2014, ACER also illustrates the
very high level of concentration in the procurement of balancing capacity.
Graph 3: Level of concentration in the provision of balancing services from
automatic Frequency Restoration Reserves (capacity and energy) for a selection of
Member States – 2014 (%)
Source: "Market Monitoring Report 2014" (2015) ACER, pp. 207
Integrating balancing markets will increase competition and hence will save overall
costs. These costs are largely determined by the size of the network area for which the
balancing reserves are being procured (also referred to as 'balancing zone' or 'load-
frequency control block') and the frequency with which this is done. The size of the
47
Reserves sizing and procurement
reserves that need to be set aside depends on the size of unforeseen events within a given
balancing zone. Larger zones across TSO-control areas (effectively across Member
States) will result in lower total balancing reserve requirements and reduce significantly
the need for back-up generation, as the risks to be covered are smaller than with a simple
addition of the risks of two small zones. To this end, a limited number of wider balancing
zones should be defined by the needs of the network rather than national borders.
Deficiencies of the current legislation (see also Section 7.4.2 of the evaluation)
2.1.3.
Recitals and provisions containing reference to transparent, non-discriminatory and
market-based procedures for the procurement of balancing capacity are contained in the
Electricity Directive. However, there is nothing more specific to the procurement rules.
As part of the regional cooperation of TSOs, Article 12.2 of the Electricity Regulation
refers to the integration of balancing and reserve power mechanism. However, no further
details are being developed concerning the sizing of balancing reserves at regional level.
The Guidelines on System Operation (approved in Comitology on 4th
of May 2016)
harmonise terms, methodologies and procedures for sizing balancing reserves, but it is
expected that balancing zones (or LFC Blocks) will remain unchanged and mainly based
on national borders (except for Nordic countries and Spain-Portugal) as illustrated below.
Figure 1: Synchronous Areas, LFC Blocks (or balancing zones) and LFC Areas
Source: ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves,
2013, pp. 42
The Balancing Guideline (not yet approved in Comitology) intends to set out rules for the
procurement of balancing capacity, the activation of balancing energy and the financial
settlement of BRPs. It would also require the development of a harmonised methodology
for the reservation of cross-zonal transmission capacity for balancing purposes. However
sharing and exchange of balancing capacity would not be mandatory under the Balancing
Guideline but encouraged.
48
Reserves sizing and procurement
Presentation of the options
2.1.4.
Option 0 - BAU
The baseline scenario consists of a smooth implementation of the Balancing Guideline
where sharing and exchange of balancing capacity are not mandatory. In this way, the
existing on-going experiences (such as the regional sizing and procurement of balancing
reserves in the Nordic countries and the Iberian Peninsula) will remain and be free to
develop further and integrate, if so decided by the participating parties. Isolated and
likely incompatible projects may be implemented across Europe.
Procurement arrangements such as shorter contracting period close to real time should be
enforced in line with the development of a methodology for the reservation of cross-
zonal transmission capacity for balancing purposes.
Option 0+: Non-regulatory approach
The Third Package does not address the provision of regional sizing and procurement of
balancing reserves in a way that could be used to stronger enforce existing legislation.
Specific parts dealing with transparency, non-discrimination and market based rules can
be found in the Article 15 of the Electricity Directive. Others parts dealing with the
regional cooperation of TSOs on balancing and the optimal allocation of capacity across
timeframes can be found in Article 12.2 and Annex 1.2.6 of the Electricity Regulation.
Voluntary cooperations between TSOs for sharing and exchaning balancing capacity
could be further supported thanks to an active participation in the Balancing Stakeholder
Group established by ACER and ENTSO-E for an early implementation of the Balancing
Guideline. However no mandatory provisions in the Balancing Guideline request TSOs
to size and procure reserves at regional level.
Option 1 – National sizing and procurement of balancing reserves on a daily basis
This option consists in developing a binding regulation that would require TSOs to size
their balancing reserves on daily probabilistic methodologies (i.e. based on different
variables such as RES E generation forecasts, load fluctuations and outage statistics).
This method is opposed to a deterministic approach which consists of sizing the
balancing reserves on the value of the single largest expected generation incident. Daily
calculation allows procuring lower balancing reserves and, together with daily
procurement, enables participation of renewable energy sources and demand response.
Shorter procurement timeframes for balancing capacity facilitate the participation of
wind generators and demand response aggregators which cannot secure firm capacity
over long lead times, or storage operators, which do not have to guarantee specific
amounts of energy stored over long periods. This option foresees separate procurement of
all types of reserves between upward (i.e. increasing power output; offering demand
reduction) and downward (i.e. reducing power output; offering demand increase)
products.
Option 2 – Regional sizing and procurement of balancing reserves
This option involves the set up of a European binding regulation requiring TSOs to use
regional platforms for the procurement of balancing reserves. Mandatory sharing and
49
Reserves sizing and procurement
exchange of balancing capacity requires firm cross-zonal transmission capacity.
Therefore this option foresees the development of an optimisation process for the
allocation of transmission capacity between energy and balancing markets, which then
implies procuring reserves only a day ahead of real time.
This option thus has the focus on a more integrated approach on the sizing and
procurement of balancing reserves themselves. Mandatory regional procurement of
balancing reserves would require changing and harmonizing adjacent business and
related operational processes. Mandatory regional sizing of balancing reserves might
have an impact on system operation procedures and responsibilities, at least procedurally
shifting security of supply-related tasks (such as system's state analysis) to a
supranational level (possibly to newly-established regional operational centres ('ROCs'),
see also Section 2.3).
TSOs would still be responsible for real-time activation of the balancing capacity
procured; however they would only have access to the regional platforms for the
procurement of balancing capacity which would assume harmonized procurement
timeframes and centralised optimisation algorithm requiring firm cross-border
transmission capacity to be available. Balancing reserves would be estimated on a daily
basis and based on probabilistic methodologies.
Option 3 – European sizing and procurement of balancing reserves
This option would result in a significant evolution of the current design in which
European electricity systems are operated. This would have a major impact on the current
design of system operation procedures and responsibilities.
This option involves setting up a binding European framework to ensure that all Member
States implement a single market design for sizing and procurement of balancing
reserves. A supranational independent system operator ('EU ISO') would be responsible
for sizing and procurement of balancing reserves, cooperating with national TSOs. This
would enable TSOs to reduce the security margin on transmission lines, thus offering
more transmission capacity to the market and allowing for additional sharing and
exchanges of balancing capacity.
Comparison of the options
2.1.5.
Economic impacts
All three options can capture some of the potential social welfare opportunities. Option 3
would be the most effective in achieving an optimal sizing and procurement of balancing
reserves at European level. However, it might not be feasible as sharing and exchanges of
balancing capacity require firm cross-zonal transmission capacity. Such reservation
might be limited by the physical topology of the European grid (e.g. geographical
distribution of the balancing reserves to maintain operational security43
). Option 1, which
43
ENTSO-E supporting document for the Network Code on Load-Frequency Control and Reserves,
2013, pp. 75
50
Reserves sizing and procurement
foresees daily sizing of balancing reserves at national level and separate procurement of
downward and upward balancing capacity, would result in an increased participation of
wind power producers and demand response aggregators in the balancing market. While
the improvements of national rules regarding sizing and procurement of balancing
reserves would allow savings around EUR 1.8 billion, it would not reap the full potential
of cross-border exchanges. Daily sizing and procurement of balancing reserves could
therefore be optimally performed at regional level. The preferred option is thus Option 2,
which brings savings of around EUR 3.4 billion.
Table 1: Economic impacts by option
BAU Option 1 Option 2 Option 3
Balancing reserves needs (GW) 53.4 52.1 29.9 17.1
Balancing reserves needs reduction - 3% 44% 68%
Annual savings (EUR billion) - 1.8 3.4 4.5
Source: METIS
Regulatory impact
The costs of sizing and procuring balancing reserves at regional level are mainly linked
to the possibility to add a task to the newly-established regional operational centres
('ROCs') (see also Section 2.3 of the present annexes to the impact assessment). System
state analysis would have to be performed on a daily basis and regional level by the
ROCs, together with the setting-up of regional plaforms for the procurement of balancing
reserves. The option entailing the smallest change (Option 1) involves costs significantly
less than the other two options. Option 2 is likely to be more expensive as a result of the
additional tasks to ROCs and the setting-up of several new platforms for the exchange or
sharing of balancing reserves.
Subsidiarity
2.1.6.
The subsidiarity principle is fulfilled given that the EU is best placed to provide for a
harmonised EU framework for common sizing and procurement of balancing reserves.
Most Member States currently take national approaches to size and procure balancing
reserves including often not allowing for foreign participation. As common sizing and
procurement of balancing reserves requires neighbouring TSOs' and NRAs' full
cooperation, individual Member States might not be able to deliver a workable system or
only provide suboptimal solutions.
Providing mandatory regional sizing and procurement of balancing reserves would be
also in line with the proportionality principle given that it aims at preserving the
properties of market coupling and ensuring that the distortions of uncoordinated national
balancing mechanisms are corrected and the internal market is able to deliver the benefits
to consumers.
Stakeholders' opinions
2.1.7.
Most respondents from the Market Design consultation agreed with the need to speed up
the development of integrated short-term (balancing and intraday) markets. A significant
number of stakeholders argue that there is a need for legal measures, in addition to the
technical network codes and guidelines under development, to speed up the development
of cross-border balancing markets, and provide for clear legal principles on non-
discriminatory participation in these markets.
51
Reserves sizing and procurement
In ENTSO-E's view a parallel harmonization of balancing energy and balancing capacity
procedures would lead to unreasonably high effort for TSOs and would introduce
additional uncertainty and insecurity for the operation of the electricity system if made
mandatory. However ENTSO-E and ACER recognise that common cross-border
procurement of reserves is a good target in the long-term.
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following
relevant conclusion:
"The Forum stresses the importance of balancing markets for a well-integrated and
functioning EU internal energy market. It encourages the Commission to swiftly bring
the draft Balancing Guideline to Member States for discussion, ideally before the
summer, with a view to reaching agreeement in autumn this year. It considers, however,
that there may still be improvements needed and ask the Commission to consider the
provisions of the draft Guideline carefully before presenting a formal proposal.
The Forum supports the view that further steps are needed beyond agreement and
implementation of the Balancing Guideline. In particuler, further efforts should be made
on coordinated sizing and cross-border sharing of reserve capacity. It invites the
Commission to develop proposals as part of the energy market design initiative, if the
impact assessment demonstrates a positive cost-benefit, which also ensure the
effectiveness of intraday markets."
52
Reserves sizing and procurement
53
Removing distortions for liquid short-term markets
2.2. Removing distortions for liquid short-term markets
54
Removing distortions for liquid short-term markets
Summary table
2.2.1.
Objective: to remove any barriers that exist to liquid short-term markets, specifically in the intraday timeframe, and to ensure distortions are minimised.
Option 0 Option 1 Option 2
Description
Business as usual
Local markets mostly unregulated, allowing for national
differences, but affected by the arrangements for cross-
border intraday and day-ahead market coupling.
Stronger enforcement and volunatry cooperation
There is limited legilsation to enforce and voluntary
cooperation would not provide certainty to the market.
Fully harmonise all arrangements in local
markets.
Selected harmonisation, specifically on issues relating to gate closure
times and products.
Pros
Simplest approach, and allows the cross-border
arrangements to affect local market arrangements. Likely to
see a degree of harmonisation over time.
Would minimise distortions, with very limited
opportunity for deviation.
Targets issues that are particularly important for maximising liquidity of
short-term markets and allows for participation of demand response and
small scale RES.
Cons
Differences in national markets will remain that can act as a
barrier.
Extremely complex; even the cross-border
arrangements have not yet been decided and
need significant work from experts.
Additional benefit unclear.
May still be difficult to implement in some Member States with
implication on how the system is managed – central dispatch systems
could, in particular, be impacted by shorter gate closure time.
Most suitable option(s): Option 2 – Provides a proportionate response targeting those issues of most relevance.
55
Removing distortions for liquid short-term markets
Description of the baseline
2.2.2.
Intraday markets usually open several hours before the day of delivery and allow market
participants to trade energy products i.e. discrete quantities of energy for a set amount of
time - close to real time and as short as five minutes before delivery.
Liquid intraday markets will form a critical part of a European energy market that is able
to cost-effectively accommodate an increasing share of variable renewable sources, allow
for more demand-side participation, and allow for energy prices to reflect scarcity.
"Liquidity is a measure of the ability to buy or sell a product – such as electricity
- without causing a major change in its price and without incurring significant
transaction costs. An important feature of a liquid market is the presence of a
large number of buyers and sellers willing to transact at all times"44
.
Maximising liquidity in the intraday market will increase competitive pressure, increase
confidence in the resulting energy prices, and allow adjustment of positions close to real
time, thus reducing the need for TSO actions in the balancing timeframes (although it
should be noted that this will not by itself reduce the need for remedial actions by TSOs
to address congestion in internal grids).
- The more variable source of renewable generation in the EU energy mix, the
more impact of errors in forecasting of weather and demand. Allowing close-to-
real-time trading will allow suppliers and producers to take account of the most
up-to-date information and, therefore, reduce risk of being out of balance.
- The more trading in this market, the more likely it is to reflect the overall value of
staying in balance, thereby increasing confidence in the price. This in turn will
affect price formation in the day-ahead market and in forward markets.
Most Member States have organised intraday markets. In their Market Monitoring
Report, ACER points out a general trend to an increase in the volumes traded in national
intraday markets.
44
Ofgem, https://www.ofgem.gov.uk/electricity/wholesale-market/liquidity
56
Removing distortions for liquid short-term markets
Figure 1 – ID traded volumes in selection of EU markets – 2011-2014 (TWh).
Source: PXs and the CEER national indicators database (2015), as reported in "Market Monitoring Report
2014" (2015) ACER.
However, there remains significant scope for increasing liquidity. In the same report,
ACER analyse 13 markets that make up 95% of the liquidity in intraday markets, using
as a liquidity indicator the ratio of energy volumes traded to demand. The following
shows that only 5 markets had a ratio above 1%.
ES IT PT DE GB SI BE SE LT FR CZ NL PL
12.1% 7.4% 7.6% 4.6% 4.4% 1.0% 1.0% 1.0% 1.0% 0.7% 0.7% 0.2% 0.1%
The organisation of national intraday markets is largely unregulated in EU law. A degree
of harmonisation has developed naturally, partially due to common actors in national
markets. However, significant differences still remain. In particular:
- whilst most countries operate a continuous trading approach, some have intra-day
auctions;
- gate closure times (i.e. when the market closes) vary from between 5 minutes (BE
and NL) to 120 minutes (HU) ahead of real time. In the Iberian market, which
operates auctions, the shortest gate closure time is just over two hours, and can
extend even further depending on the hour of delivery;
- the granularity of products varies between 60 minute products and 15 minute
products;
- the minimum size of bids varies between 0.1MWh to 1MWh;
- the types of orders vary considerably;
- demand response is not consistently allowed to participate;
- whether bidding is at unit-level or portfolio-level;
- whether the organised intraday-markets are exclusive (i.e. preventing bi-lateral
trading).
Currently, cross-border trading in the intraday timeframe is not harmonised, is generally
on a border-by-border basis and the total traded volumes are low: in 2014 only 4.1% of
IC capacity was used intraday, compared to 40% day-ahead.
57
Removing distortions for liquid short-term markets
The CACM guideline45
envisages a new, EU-wide cross-border market in the intraday
timeframe. Local markets will be indirectly impacted by its introduction, essentially
because it provides an extra choice for market participants on which platform to trade.
There are important interactions, notably because the two markets co-existing in this way
has the potential to split liquidity (i.e. split the trading across two markets as opposed to
one, thereby reducing the benefits of a highly liquid market). The more differences that
exist between local markets and between local markets and the cross-border market, the
greater the impact is likely to be as arbitrage opportunities between them will be reduced.
One issue exists in particular – that of gate closure times. The below diagram is an
illustration of the potential interactions between local and cross-border markets. While
both are open for trading, market participants can chose the best one, most likely driven
by price and/or products which match their needs, but potentially also by functionality
and ease-of-use of the trading platform. As such there should be a general trend towards
convergence of prices in these two markets as they will effectively be in direct
competition with each other. The more similarities in the specificities of the markets the
more likely this is to be the case. However, if the local market closes before the cross-
border market, the arbitrage opportunities are reduced as the market participants cannot
freely trade between the two. There is also a risk that local rules will mean that continued
cross-border trading will not be possible once the local market has shut, for example
because it is on this basis which the suppliers and producers provide 'firm' details on their
contracted energy to the TSO. The existence of different products and arrangements, and
even different IT systems on which to trade, also bears the risk of splitting liquidity
between different markets. However, whilst the longer-term objective should be to have
one, common market where all trading takes place and where liquidity is 'pooled', given
the starting point it is not necessarily beneficial to deliver this by harmonising all
arrangements in the short-term, as it could involve moving to the 'lowest common
denominator,' as described further below.
45
Commission Regulation (EU) 2015/1222 establishing a guideline on capacity allocation and
congestion management.
58
Removing distortions for liquid short-term markets
Figure 2 – Example co-existence of local and cross-border markets, where local
market closes before cross-border.
The design of some national markets may limit the ability for RES E or Demand
Response to participate, as they will prefer shorter products as this will help them
accommodate more variability in generation and demand. Also, if products do not at least
reflect the imbalance settlement period, then market participants will not have the ability
to balance themselves sufficiently frequently.
Finally, the closer to real time that market parties are allowed to trade, the more likely it
is that their supply and demand will be in balance when it comes to delivering and
consuming energy. This is especially relevant in a market sensitive to weather
fluctuations where changes can happen after the market has closed and the participants
are not able to buy or sell energy to make up for this. It therefore becomes the
responsibility of the TSO as part of the balancing market. However, the risk is that, if set
too close, TSOs will not have the time they need after being informed of the final market
results to manage the system and, in particular, deal with internal bottlenecks.
Deficiencies of the current legislation
2.2.3.
As detailed above, there is very limited legislation in this area. The most significant piece
is the CACM Guideline, but this only indirectly addresses the operation of national
markets and, in most cases, will not directly lead to standardised trading within local
markets, which thereby potentially creates a barrier to cross-border trade and liquidity.
59
Removing distortions for liquid short-term markets
The Evaluation Report for market design concluded that "the Third Energy Package does
not ensure sufficient incentives for private investments in the new generation capacities
and network because of the minor attention in it to effective short-term markets and
prices which would reflect actual scarcity."46
Presentation of the options
2.2.4.
Option 0 – Business as Usual
This option would leave local markets mostly unregulated, allowing for national
differences, but influenced by the arrangements for cross-border intraday and day-ahead
market coupling. The CACM Guideline requires the definition of a gate closure time on
each bidding zone border, which can be a maximum of 60 minutes. This could impact
decisions taken at national level, but this is not certain and differences are likely to
remain. Further, the definition of the products that can be taken into account in the cross-
border system are to be determined under the CACM Guideline which could, again,
impact the products which are provided in local markets.
Option 0+ Non-regulatory approach
There is very limited legislation in this area. Stronger enforcement of current rules
therefore does not provide scope to achieve a larger degree of harmoninsation of intraday
trading arrangements.
Voluntary cooperation has resulted in significant developments in the market and a lot of
benefits. However it may not provide for appropriate levels of harmonisation or certainty
to the market and legisaltion is needed in this area to address the issues in a consistent
way.
Option 1 – Fully harmonise all arrangements in local markets.
This option would see all arrangements harmonised, including gate opening times, gate
closing times, products to be offered, whether markets are exclusive, and mandatory
continuous trading rather than auctions. Gate closure time would be established as close
to real time as possible, to provide maximum opportunity for the market to balance its
positions before it became the TSO responsibility. Markets would be exclusive – i.e. no
bilateral trading – and power exchanges would be obliged to offer small products, in size
and duration – likely a minimum of 0.1MWh in 15 minute blocks. Demand response
would be able to participate in all markets.
Given the difference in technical characteristics of different markets (i.e. some have very
limited internal congestion so very short gate closure times are technically feasible,
whilst others need more time to take remedial actions), this option would likely see some
markets becoming larger (with gate closure times closer to real time) and some smaller
(with gate closure times having to move further away from real time, depending on the
46
Section 7.3.2 of the Evaluation
60
Removing distortions for liquid short-term markets
precise time chosen). It would also mean that products would not necessarily reflect the
difference in national systems.
Given the technicalities of this option, it would likely be developed through
implementing legislation.
Option 2 - Selected harmonisation, with additional flexibility
This option would introduce standardisation of gate closure time and products in a more
flexible way, specifically allowing some flexibility in national markets to reflect their
differentiated nature. In particular, under this option, legislation would specify:
- that intraday gate closure time in national markets must not be longer than the cross-
border intraday gate closure time. This would ensure that national markets are not
'taken out of the picture' before the cross-border markets close, and would, in effect,
mean that at a minimum market participants are allowed to trade as close as one hour
ahead of real time.
- that power exchanges must offer products that reflect the imbalance settlement
period. This will ensure that market participants are able to trade at a frequency
which allows them to stay in balance.
- that barriers to demand response participating in intraday markets must be minimised
– specifically, minimum bid size should allow for participation and there should be
no administrative barriers put in place.
This option would also see more principles added to legislation, with the aim of
progressive harmonisation over time on those design features not touched.
Comparison of the options
2.2.5.
Option 0 (Business as usual) would keep the status quo and leave intraday markets to
evolve within Member States, with no guarantees they would develop along the same
lines, except in some areas that existing legislation touches (for example, on minimum
and maximum bid prices). There would likely be an impact as a result of the
implementation of market coupling in the intraday time-frame. With significant
differences, there is a risk that liquidity is split and benefits of short-term markets to the
integration of RES E and demand response muted.
Option 1 – full harmonisation – would likely see significant changes in a number of
markets. It would involve selecting a gate closure time and applying that to all national
markets. Whilst the precise timing could vary, it would mean that some countries would
need to keep their markets open longer, and some would need to close their markets
earlier than they currently do (notably in Belgium and the Netherlands, where trades can
currently take place up to 5 minutes prior to delivery) – harmonising gate closure times to
that of the shortest in Europe would likely be unachievable for many Member States,
particularly larger ones where the TSO requires more time between knowing the market
results and real time in order to solve internal congestion (the market is blind to
congestion within a bidding zone).
This option would also involve harmonising other aspects, as detailed above. Power
exchanges can be seen as the conduit for energy trades across borders so harmonising the
rules on which trading takes place will minimise differences between national markets
and with the common cross-border market. By increasing the arbitrage opportunities
across these markets, the risk of splitting liquidity is reduced.
61
Removing distortions for liquid short-term markets
On the surface, this might seem like an appropriate response akin to other single market
measures that harmonise standards so that they can be traded within the EU with minimal
barriers. However, in reality this is likely to be much more complex. A significant
amount of the process is IT-driven, and the arrangements have not yet been put in place –
it would therefore be very difficult to determine what the local arrangements should be.
Further, there is a lack of evidence that such harmonisation would indeed lead to more
cross-border trade – the costs associated with changing IT could be significant with little
benefit.
Given that the common cross-border market will likely be more complex (e.g. given the
number of variables, Member States, the fact that calculations will need to consider
available cross-border capacity) in the immediate future this market, and the IT
infrastructure that supports it, may not be able to accommodate the more granular market
arrangements that exist in some Member States. As such, moving all national markets to
the same design details of that of the cross-border market could entail some having to
reduce their granularity, move gate closure time further away from real-time, etc. This
would not fit with the objectives of the present proposal, which aims for increased
flexibility.
Option 2, however, would provide a much more proportionate response. Rather than
specifying a value for the gate closure time in local markets it would specify that it
should be no longer than the cross-border gate closure time. It will provide more
opportunity for arbitrage between markets. It will also move gate closure times closer to
real-time in many markets, which will provide more opportunities for RES E to balance
themselves and demand response to participate in the market, without forcing those
markets which already apply very short-term trading rules to switch to longer
timeframes. With regards to products the markets should be able to accommodate
demand-response and small-scale RES E. It will also leave the most technical
characteristics to the implementation of the CACM Guideline, which has the advantage
of allowing specifics to be discussed in detail with market parties and for more
flexibility, i.e. allowing for easy adaptation if and when requirements need to change.
Whilst this option will not eliminate the risk of splitting liquidity, there is in fact some
evidence that two markets can co-exist and increase overall traded volumes. In a study
looking at the impact of the introduction of an intraday auction for 15 minute products in
Germany47
, it was found that, whilst the auction pulled some value away from the
continuous intraday market, the total traded volumes increased.
47
"Intraday Markets for Power: Discretizing the Continuous Trading" Karsten Neuhoff, Nolan Ritter,
Aymen Salah-Abou-El-Enien and Philippe Vassilopoulos (2016)
62
Removing distortions for liquid short-term markets
Figure 3: Volumes on the 15mn intraday market and the share of quarters in total
trading volumes (quarters+hours), EPEX (DE)
Source: Neuhoff et al (2016)
The option will also provide a good starting point for progressively harmonising with the
longer-term aim of one, common intraday market with local specificities minimised
to situations where they are justified due to local differences.
Specific impacts relating to changes in short-term markets are discussed in Section 6.1.3.
With regards to intraday, the results of the modelling indicate positive impacts of
harmonising intraday arrangements in Europe, specifically allowing for the further
reduction of RES E curtailment and lesser use of replacement reserves by 460 GWh and
95 GWh, respectively
Subsidiarity
2.2.6.
Given that the EU energy system is highly integrated, prices in one country can have a
significant effect on prices in another, as can arrangements in local markets. Differences
in the operation of local markets can present a barrier to the cross-border trade of energy,
and continuing differences between local markets, and between local markets and the
single cross-border market, risks splitting liquidty and constraining the benefits of a
common cross-border market This will impact on liquidity and the amount of trading
which can take place, as well as erode the benefits of competition and a larger market
place in which energy can be bought and sold.
EU-level action is, therefore, necessary to ensure that the national markets are
comparable, that they enable maximum cross-border trading to happen, and facilitate
liquidity as much as possible. .
There is also a critical link with the CACM Guideline, which establishes principles and
required further methodologies for the operation of intraday markets in the cross-border
context, as well as a link with the upcoming Balancing Guideline. EU-level action is
required to ensure that trading in local markets can reap maximum benefits of the cross-
border solution under development.
63
Removing distortions for liquid short-term markets
Stakeholders' opinions
2.2.7.
Most stakeholders agree on the importance of liquid short-term markets, particularly
intraday and balancing, to the efficient operation of the internal electricity market. They
are, in general, seen as a critical part of ensuring that RES E can be propely intergrated,
notably allowing renewable generators to trade closer to real-term, as well as to
stimulating investment in sources of flexibility such as demand response. Most call for
speedy implementation of common cross-border intraday trading (market coupling) via
the XBID project, whilst recognising the progress that has already been made in day-
ahead market coupling.
Wind Europe calls upon the EU to "ensure continuous intraday trading with harmonised
gate closure times closer to real time; complementary auctions may be introduced to
increase liquidity". They argue that "implementing well-functioning intraday markets
across borders with gate-closure close to real-time will 1) provide renewable producers
with opportunities to adjust their schedule in case of forecasts errors, 2) smooth out the
variability induced by renewable in-feed over broader geographical areas"48
.
In their publication "Electricity Market Design: fit for the low-carbon transmision",
Eurelectric state:
"The development of robust cross-border intraday and balancing markets will be crucial
to ensure that the system remains balanced as the share of renewables continues to grow.
It is therefore necessary to promote a liquid continuous implicit cross-border intraday
market with harmonised products in all member states, while capacity pricing shall not
drain liquidity nor reduce the speed of market processes. The market shall be enabled to
determine the most economic dispatch until a gate closure set as close to real-time as
possible (e.g. 15 minutes). TSOs shall only perform the residual balancing of the
system."49
SolarPower Europe state "progress is needed in particular with a view to achieving
better liquidity and integration of intraday and balancing markets. These short-term
markets are crucial as variable renewable energy sources take a more important role in
the power mix. Products and services should be re-defined to improve the granularity of
these markets and enable the sale of different system services that solar power and other
renewables, but also storage and demand participation can provide." 50
ENTSO-E make the point that "Accurate short-term market price formation is needed to
reveal the value of flexibility in general and of DSR specifically"51
and ACER/CEER that
"it is imperative that everything is done to make sure that price signals reflect scarcity
and to create shorter-term markets which will reward those who provide the flexibility
services which the system increasingly needs." Further, they state that "the intraday and
48
"A market design fit for renewables". Wind Europe submission of 27 June 2016
49
"Electricity Market Design: fit for the low-carbon transmision". Eurelectirc 2016, available at
http://www.eurelectric.org/media/272634/electricity_market_design_fit_for_low-carbon_transition-
2016-2200-0004-01-e.pdf
50
"Creating a competitive market beyond subsidies" July 2015,
51
Market Design of Demand Side Response" Policy Paper, November 2015
64
Removing distortions for liquid short-term markets
balancing markets will be increasingly important to valuing flexibility and there needs to
be a push to deliver the cross-border intraday (XBID) project and to implement the
Network Code on Electricity Balancing as soon as possible."52
The March 2016 Electricity Regulatory Forum (the "Florence Forum"), a forum for
stakeholders to engage on wholesale market regulatory issues, made the following
relevant conclusion:
"The Forum acknowledges that, whilst cross-border day-ahead and intraday markets will
see significant harmonisation as part of the implementation of the Capacity Allocation
and Congestion Management guideline, there is significant scope for ensuring that
national markets are appropriately designed to accommodate increasing proportions of
variable generation. In particular, the Forum invites the Commission to identify those
aspects of national intraday markets that would benefit from consistency across the EU,
for example on within-zone gate closure time and products that should be offered to the
market. It also requests for action to increase transparency in the calculation of cross-
zonal capacity, with a view to maximising use of existing capacity and avoiding undue
limitation and curtailment of cross-border capacity for the purposes of solving internal
congestions."
52
Joint ACER-CEER response to European Commission’s Consultation on a new Energy Market
Design, October 2015
65
Improving the coordination of Transmission System Operation
2.3. Improving the coordination of Transmission System Operation
66
Improving the coordination of Transmission System Operation
Summary table
2.3.1.
Objective: Stronger coordination of Transmission System Operation at a regional level
Option 0 Option 1 Option 2 Option 3
Description
BAU
Limit the TSO coordination efforts to the
implementation of the new Guideline on
Transmission System Operation (voted at the
Electricity Cross Border Committee in May
2016 and to be adopted by end-2016) which
mandates the creation of Regional Security
Coordinators (RSCs) covering the whole
Europe to perform five relevant tasks at
regional level as a service provider to national
TSOs.
Enhance the current set up of existing RSC by
creating Regional Operational Centers (ROCs),
centralising some additional functions at regional
level over relevant geographical areas and
delineating competences between ROCs and
national TSOs.
Go beyond the establishment of ROCs
that coexist with national TSOs and
consider the creation of Regional
Independent System Operators that can
fully take over system operation at
regional level. Transmission ownership
would remain in the hands of national
TSOs.
Create a European-wide
Independent System Operator
that can take over system
operation at EU-wide level.
Transmission ownership would
remain in the hands of national
TSOs.
Pros
Lowest political resistance. Enlarged scope of functions assuming those tasks
where centralization at regional level could bring
benefits
A limited number (5 max) of well-defined regions,
covering the whole EU, based on the grid topology
that can play an effective coordination role. One
ROC will perform all functions for a given region.
Enhanced cooperative decsion-making with a
possibility to entrust ROCs with decision making
competences on a number of issues.
Improved system and market operation
leading to optimal results including
optimized infrastructure development,
market facilitation and use of existing
infrastructure, secure real time operation.
Seamless and efficient system
and market operation.
Cons
Suboptimal in the medium and long-term. Could find political resistance towards
regionalisation. If key elements/geography are not
clearly enshrined in legislation, it might lead to a
suboptimal outcome closer to Option 0.
Politically challenging. While this option
would ultimately lead to an enhanced
system operation and might not be
discarded in the future, it is not
considered proportionate at this stage to
move directly to this option.
Extremely challenging
politically. The implications of
such an option would need to be
carefully assessed. It is
questionable whether, at least at
this stage, it would be
proportionate to take this step.
Most suitable: Most suitable option(s): Option 1 (Option 2 and Option 3 constitute the long-term vision)
67
Improving the coordination of Transmission System Operation
Detailed description of the baseline
2.3.2.
Operation of the transmission system
Traditionally, prior to the restructuring of the energy sector, most electricity utilities were
run by national and very often state-owned monopolies. These were in most cases
vertically integrated utilities that owned and operated all the generation and system assets
in their allocated territories.
The adoption and implementation of the three energy packages have led to the
introduction of competition in the generation and supply of electricity, the introduction of
wholesale electricity markets for the trading of electricity as well as to different degrees
of unbundling of transmission and distribution activities, which constitute monopoly
activities.
Figure 1. The electricity value chain
Source: European Commission
The fact that the activity of electricity transmission system operation is mostly national in
scope derives from the past existence of vertically integrated utilities that were active
throughout the whole electricity supply value chain. Following the restructuring of the
electricity sector, Member States naturally tasked TSOs with the responsibility of
ensuring the secure operation of the electricity system at national level.
This approach is currently reflected in the EU legislation. Article 12 of the Electricity
Directive establishes that each TSO shall be responsible, inter alia, for managing the
electricity flows on the system, taking into account exchanges with other interconnected
systems. The Commission Implementing Regulation establishing a guideline on
electricity transmission system operation ('System Operation Guideline') specifies further
this obligation and sets out a requirement on TSOs to ensure that their transmission
system remains in the normal state and makes them responsible for managing violations
of operational security53
.
Coordination of transmission system operation: shift from a voluntary approach to a
mandatory framework
53
The System Operation Guideline was voted on 4 May 2016 and is due to be adopted after scrutiny by
the Council and the European Parliament.
https://ec.europa.eu/energy/sites/ener/files/documents/SystemOperationGuideline%20final%28provisi
onal%2904052016.pdf
Übertragung Verteilung Vertrieb
regulierter Bereich
transmission distribution supply
monopoly activity
Erzeugung
competitive activity
generation Handel
trading
competitive activity
68
Improving the coordination of Transmission System Operation
Driven by the lessons learnt from the serious electrical power disruption in Europe in
2006, European TSOs have pursued enhancing further regional cooperation and
coordination. To this end, TSOs voluntarily launched Regional Security Coordination
Initiatives (RSCIs), entities covering a greater part of the European interconnected
networks aiming at improving TSO cooperation. The main RSCIs in Europe are Coreso
and TSC, both launched in 2008, followed by the ongoing development and
establishment of additional RSCIs, such as SCC in Belgrade (launched in 2015) and an
RSCI to be launched by Nordic TSOs by the end of 2017. Currently, RSCIs monitor the
operational security of the transmission system in the region where the TSOs with
membership in the RSCIs are established and assist TSOs proactively in ensuring
security of supply at a regional level. By performing these functions, RSCIs provide
TSOs with detailed forecasts of security analysis and may propose coordinated measures
that TSOs may decide or not to implement.
In December 2015, all European TSOs except for SEPS a.s., the Slovakian TSO, signed
a multi-lateral agreement to roll out RSCIs in Europe and to have them deliver core
services to support the TSOs carry out their functions and responsibilities at national
level.
R&D results: Tools for TSOs to deal with an increase in cross-border flows and
variability of generation are being developed in European projects like ITESLA and
UMBRELLA. They show that coordinated operational planning of power transmission
systems is necessary to cope with increased uncertainties and variability of (cross-border)
electricity flows. These tools help decrease redispatching costs and the available cross-
border capacity and flexibility while ensuring a high level of operational security.
69
Improving the coordination of Transmission System Operation
Figure 2 State of play of the voluntary membership of TSOs in RSCIs across the
European Union.
Source: European Commission (June 2016)
The voluntary establishment of RSCIs has been widely recognised as a positive step
forward for the enhancement of cooperation of transmission system operation and has
been recently formalised in EU legislation with the new System Operation Guideline.
Building on the emerging regional initiatives, the System Operation Guideline takes a
further step and mandates the cooperation of EU TSOs at regional level through the
establishment of maximum six regional security coordinators (RSCs) which will cover
the whole EU to perform a number of relevant tasks at regional level as service providers
to national TSOs.
The tasks that RSCs will perform pursuant to the System Operation Guideline are: (i)
regional operational security coordination; (ii) building of the common grid model; (iii)
regional outage coordination; and (iv) regional adequacy assessment. The task of
capacity calculation follows from the implementation of the CACM Guideline and is not
assigned in the System Operation Guideline. The draft Commission Regulation
establishing a network code on Emergency and Restoration intends to extend the tasks of
RSCs to include a consistency assessment of the TSOs' system defence plans and
restoration plans.
The framework set out in the System Operation Guideline is meant to build on the
existing voluntary initiatives of TSOs (Coreso and TSC). It requires each TSO to join a
RSC and allows a degree of flexibility to TSOs to organise the coordination of regional
system operation. In this regard, the TSOs of the different capacity calculation regions
70
Improving the coordination of Transmission System Operation
will have the freedom to appoint more than one RSC for that region and to allocate the
tasks, as they deem most efficient, between them.
Based on the deadlines for implementation envisaged in the System Operation Guideline,
RSCs should be fully operational around mid-2019.
Box 1: Support functions to be carried out by RSCs under the network codes and
guidelines
Common grid model: The common grid model provides an EU-wide forecasted view of all major grid
assets (generation, consumption, transmission) updated every hour. RSCs will participate in the iterative
process starting from the collection of individual grid models prepared and shared by TSOs and aiming at
delivering to all RSCs and TSOs, a common grid model adequate for the other functions listed below. This
function is required at least for timeframes from year-ahead to intraday (year-ahead, week-ahead, day-
ahead, and intraday).
Operational planning security analysis: RSCs will identify risks of operational security in any part of
their regional area (mainly triggered by cross-border interdependencies). They will also identify the most
efficient remedial actions (i.e., actions implemented by TSOs aimed at maintaining or returning the
electricity system to the normal system state) in these areas and recommend them to the concerned TSOs,
without being constraint by national borders. This function covers at least the day-ahead and intraday
timeframes.
Coordinated capacity calculation: RSCs will calculate the available electricity transfer capacity across
borders, using flow-based (FB) or net transfer capacity (NTC) methodologies. These methodologies aim at
optimising cross-border capacities while ensuring security of supply. This function is carried out at least on
the D-2 (for day-ahead capacity allocation) and D-1/ intraday (for intraday capacity allocation) timeframes.
Short and very short-term adequacy forecasts: RSCs will provide TSOs with consumption, production
and grid status forecasts from the day-ahead up to the week-ahead timeframe. In particular, RSCs will
perform a regional check/update of short/medium term active power adequacy, in line with agreed
ENTSO-E methodologies, for timeframes shorter than seasonal outlooks. This function is carried out week-
ahead (until day-ahead only if scarcity is detected or if there are changes in relevant hypotheses compared
to week-ahead).
Outage planning coordination: This function consists in creating a single register for all planned outages
of grid assets (overhead lines, generators, etc.). RSCs will identify outage incompatibilities between
relevant assets whose availability status has cross-border impact and limit the pan-European consequences
of necessary outages in grid and electricity production by coordinating planning outages. RSCs will carry
out this function in the year-ahead timeframe with updates up to week-ahead (on TSO requests).
Consistency assessment of the TSOs' system defence plans and restoration plans: RSCs will assist
TSOs in ensuring the consistency of the system defence plans and restoration plan.
Deficiencies of the current legislation
2.3.3.
The regional TSO cooperation model resulting from the adoption of electricity network
codes and guidelines constitutes a positive development compared to the existing
voluntary cooperation. However, as explained below, this step, while being effective in
the short-term, is not sufficient in the medium and long-term.
The unprecedented changes concerning the integration of the European electricity
markets and the European agenda for a strong decarbonisation of the energy sector,
resulting in increasingly higher shares of decentralized and often intermittent renewable
energy sources, have made the operation of the national electricity systems much more
interrelated than in the past.
71
Improving the coordination of Transmission System Operation
The recently voted System Operation Guideline has not entered into force and been
implemented yet. Nonetheless, as highlighted in pp 32-33 of the Evaluation, the
challenges the EU power system will be facing in the medium to long-term are pan-
European and cannot be addressed and optimally managed by individual TSOs, rendering
the current legal framework concerning system operation not adapted to the reality of the
dynamic and intermittent nature of the future electricity system and putting into question
whether the mandated cooperation of TSOs via RSCs is fit for purpose in the post 2020
context.
First, the functions envisaged for RSCs in the System Operation and in the CACM
Guideline will not suffice in the medium to long-term as there is an increasing need for
electricity systems to be operated on a regional basis. Furthermore, there is room to
enlarge the scope of functions that would increase the efficiency of the overall system, if
performed at regional level.
Second, the geographical scope of RSCs set out in the System Operation Guideline could
not be efficient in the post 2020 context. RSCIs have grown organically with political
considerations in mind, rather than following criteria solely based on the technical
operation of the grid. The degree of flexibility envisaged in the System Operation
Guideline will allow TSOs to maintain that status quo, undermining the goal of having a
regional entity that oversees system and market operation in the region. Figure 2
representing the current membership of TSOs in RSCIs across the Union reflects this
situation (e.g., membership of TenneT NL, the TSO of the Netherlands, in TSC as
opposed to Coreso). The coordination with other regional groupings of TSOs deriving
from the implementation of other network codes and guidelines is also an issue. For
example, given the degree to which the grid is meshed in the CWE and CEE regions, it is
virtually impossible to draw permanent lines dividing the regions and still respect the
electrical interdependencies. Hence, the presence of two RSCIs (Coreso and TSC) for
this region does not seem the optimal solution to play an effective coordination role.
Third, the implementation of the System Operation Guideline will entail that RSCs will
play an increasingly important support role for TSOs. However, the full decision-making
responsibility will remain with TSOs who will have to do the grid planning while taking
into consideration also new options to grid extensions (such as energy storage). RSCs
will not have executive powers and their activities will be limited to providing planning
services to individual TSOs, who can accept or reject those services and who will retail
full control of and accountability for the planning and operation of their individual
networks. For example, when deciding about the commercial cross-border capacities in a
given region which are already calculated at regional level, the decision taken by RSCs
are non-binding meaning that they can be considered as an input that can be changed by
TSOs based on national interest (e.g. in case of scarcity of supply in one country the TSO
might be tempted to reduce their export capacities but this might not be the best decision
from a regional system security perspective) or due to constraints in the national legal
framework. In this regard, the rejection of a recommendation by a TSO would suffice to
put in question the overall set of recommendations issued by a RSC. For example, if in a
recommendation for an optimal set of remedial actions a given TSO did not agree, this
would imply the whole recalculation of remedial actions for the region since such
measures are usually interdependent. There is additional evidence pointing out to this
problem. The ACER market monitoring report 2015 (to be published in 2016) remarks
that there are strong indications that during the capacity calculation process TSOs resort
to unequally treating internal and cross-zonal flows on their networks.
72
Improving the coordination of Transmission System Operation
To conclude, while the enhanced regional TSO cooperation resulting from the adoption
of electricity network codes and guidelines constitutes a positive step forward, it is
important to note that it will not allow realising the full potential of these regional entities
in the medium to long-term. If the benefits of market integration are to be fully realised,
TSOs will have to cooperate even more closely at regional level. This will require
adjusting the way in which the operation of the electricity system will be managed under
the System Operation Guideline.
Presentation of the options
2.3.4.
Option 0 - BAU
Option 0 would be to stop the coordination efforts at this stage and limit it to the progress
achieved with the implementation of the System Operation Guideline.
The upcoming RSCs will have the following features:
i. Functions. Five main functions54
will be performed by the upcoming RSCs as
service providers to national TSOs under the network codes and guidelines (see
Box 1 above for a more detailed explanation of each of these functions).
a. Coordinated Security Analysis (including Remedial Actions-related
analysis)
b. Common Grid Model Delivery
c. Outage Planning Coordination
d. Short and Very Short Term Resource Adequacy Forecasts
e. Coordinated Capacity Calculation
The addition of new functions would mainly depend on the voluntary initiative of
TSOs, which in some instances could lead to inefficient outcomes given that they
would not always have the "regional" perspective in mind but rather their own
interest, particularly given the flexibility at the time of defining the geographical
scope.
Geographic scope. While RSCs will give full coverage across the EU, the size
and composition of the regions where they will be established may not always be
defined having the technical operation of the grid in mind. Business and political
criteria could also play a role. In particular, TSOs in a region would continue
having flexibility to decide which RSC provides a given service (including new
ones developed voluntarily) to that region. This would allow a given region to get
services from different RSCs. While this has been accepted as a valid
compromise in the short-term, it undermines the goal of having a regional entity
with enhanced overview over system and market operation in the region.
54
Six functions with the adoption of the Emergency and Restoration network code ('Consistency
assessment of TSOs' system defence plans and restoration plans').
73
Improving the coordination of Transmission System Operation
ii. Decision-making responsibilities. The upcoming RSCs will not have any
decision-making powers but a purely advisory role. The responsibility for system
operation will remain with TSOs at national level. The fact that RSCs issue
recommendations means that ultimately an individual TSO may be constrained by
the national framework and reject the implementation of such recommendation,
against the interest of all the other TSOs of the region. Hence, the set up of the
RSC being able to provide an added value at regional level would be
compromised. For example, as described above, if in a recommendation for an
optimal set of remedial actions a given TSO did not agree, this would imply the
whole recalculation of remedial actions for the region since these measures are
usually interdependent.
iii. Institutional layout/governance. The interaction between the RSCs, NRAs, TSOs,
ACER and ENTSO-E would remain as set out in the System Operation
Guideline. Essentially, TSOs and NRAs would continue to be responsible for the
direct implementation and oversight of RSCs at national level. ACER and
ENTSO-E would remain responsible for ensuring the cooperation of NRAs and
TSOs at EU level, respectively.
Option 0+: Non-regulatory approach
Stronger enforcement would not suffice to address the needs of the electricity system
regarding stronger TSO cooperation at regional level.. As in option 0, any progress
beyond the framework in the System Operation Guideline and the application of other
network codes would depend on the voluntary initiatives of TSOs. However, the
voluntary initiatives would be limited due to the constraints resulting from differing
legislation at national level. Hence, stronger enforcement or a voluntary approach is not a
possible option.
Option 1: Enhance the current set up of existing RSCs by creating ROCs, centralising
some additional functions over relevant geographical areas and optimising competences
between ROCs and national TSOs
Option 1 would aim at enhancing the current set up of existing RSCs by creating ROCs.
ROCs are not meant to substitute TSOs but to complement their role at regional level.
This option would set out a number of basic elements in legislation but allow flexibility
to TSOs to work out the details on how the ROCs will function and perform their tasks.
ROCs will present the the following features:
i. Functions. Enlarged scope of functions, assuming new tasks where centralization
at regional level could bring benefits. These functions would not cover real time
operation which would be left solely in the hands of national TSOs. In addition to
the functions emanating from existing network codes and guidelines (see Box 1),
these functions would be:
a. Solidarity in crisis situations: Management of generation shortages;
Supporting the coordination and optimisation of regional restoration
b. Sizing and procurement of balancing reserves
c. Transparency: Post-operation and post-disturbances analysis and
reporting; Optimisation of TSO-TSO compensation mechanisms
d. Risk-preparedness plans (if delegated by ENTSO-E)
74
Improving the coordination of Transmission System Operation
e. Training and certification (if delegated by ENTSO-E)
ii. Geographic scope. A limited number of well-defined regions, covering the whole
EU. TSOs establishing the ROCs will need to decide the scope of these regions
based on technical criteria (e.g. grid topology) to ensure that they can play an
effective coordination role. In contrast to what is currently in the System
Operation Guideline, each ROC would perform all functions for a given region.
Larger regions could include, if necessary, back-up centres and/or sub regional
desks when for example some functions would require specific knowledge of
smaller portions of the grid.
iii. Cooperative decision-making. ROCs would have an enhanced advisory role for
all functions. In order to respect to the maximum possible extent the regional
recommendations, TSOs should transparently explain when and why they reject
the recommendation of the ROC. Given that a role limited to issuing
recommendations may lead to sub-optimal results as regards the performance of
some of the functions55
, decision-making powers could be entrusted to ROCs for
a number of relevant issues (i.e., remedial actions, capacity calculation) either
directly by a Regulation or subsquentely by mutual agreement of the NRAs or
Member States overseeing a certain ROC. By optimising decision-making
responsibilities between ROCs and national TSOs the seamless system operation
between the ROCs and the TSOs would be ensured.
iv. Institutional layout/governance. Enhanced cooperation between TSOs would be
accompanied by an increased level of cooperation between regulators and
governments as well as by an increased oversight from ACER and ENTSO-E.
55
This sub-optimal situation would derive from the fact that the rejection by a single TSO of the
recommendation issued by the ROC would put in question the overall set of recommendations.
75
Improving the coordination of Transmission System Operation
Box 2: Additional functions performed by ROCs under Option 1
Option 2: Creation of Regional Independent System Operators
Option 2 would be to go beyond the establishment of ROCs that coexist with national
TSOs and consider the creation of Regional Independent System Operators (RISOs) that
can fully take over system operation at regional level.
RISOs would have the following features:
i. Functions. RISOs would have an enlarged scope of functions compared to ROCs.
In addition to the functions under Option 1, RISOs would also be responsible for
real time operation of the electricity system (e.g., operation of real time balancing
markets) and for infrastructure planning. Infrastructure related functions could
include for example the identification of the transmission capacity needs:
proposing priorities for network investments based on the long-term resource
adequacy assessment, the situation in the interconnected system and identified
- Solidarity in crisis situations:
- Management of generation shortages. ROCs would optimise the generation park in a region while
attempting to increase transmission capacity to the Member State which suffers generation
shortage. The aim of this function is to avoid load cuts (energy non served situations) in a country
while other countries still optimise the market and/or enjoy high generation margins.
- Supporting the coordination and optimisation of regional restoration. ROCs would recommend
the regional necessities during restoration (e.g., resynchronisation sequence of large islands in
case of the split of a synchronous area).
- Sizing and procurement of balancing reserves:
- Regional calculation of daily balancing reserves. ROCs would carry out regional sizing of daily
balancing reserves (disregarding political borders and considering only technical limitations
related to geographical dispersion of reserves) on the basis of common probabilistic
methodologies (i.e. balancing reserve needs based on different variables such as RES generation
forecast, load fluctuations and outage statistics).
- Regional procurement of balancing reserves. ROCs would create regional platforms for the
procurement of balancing reserves, complementing the regional sizing of balancing reserves.
- Transparency:
- Post operation and post disturbances analyses and reporting. ROCs would carry out centralised
post-operations analyses and reporting, going beyond the existing ENTSO-E Incidents
Classification Scale (ICS).
- Optimisation of TSO-TSO compensation mechanisms. ROCs would administer common money
flows among TSOs, such as Inter-TSO Compensation (ITC), congestion rent sharing, re-
dispatching cost sharing, cross-border cost allocation (CBCA). Furthermore, ROCs should
propose improvements to the schemes based on technical criteria and aiming for the optimal
overall incentives.
- Risk-preparedness plans. If delegated by ENTSO-E, the ROCs' function would be to identify the
relevant risk scenarios in its region that the risk preparedness plans should cover. Based on ROCs'
proposals, Member States would develop the plans. ROCs could organise crisis simulations (stress
tests) together with Member States and other relevant stakeholders. During such crisis simulations
the plans would be tested to check if they are suited to address the identified cross-border or regional
crisis scenarios.
- Medium term adequacy assessments: if delegated by ENTSO-E, ROCs would complement the
ENTSO-E seasonal outlooks with adequacy assessments carried out in a regional context where
possible crisis scenarios (e.g. prolonged cold spell), including simultaneous crisis, should be
identified and simulated.
- Training and certification. The network code on staff training and certification as foreseen in the
ACER framework guideline on system operation is still pending. ROCs could cover functions related
to trainings between TSOs as well as centralise of some trainings in issues related to cross-border
system operation. Further, this function should allow regional training on simulators (IT system
based on a relevant representation of the system, including networks, generation and load).
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Improving the coordination of Transmission System Operation
structural congestions, while considering an interconnected system without
political borders.
ii. Geographic scope. The scope of RISOs would be the same as for ROCs.
iii. Decision-making responsibilities. All system operation functions would be
performed by the RISOs, which would have decision-making powers. Existing
TSOs would remain as transmission owners and solely operate physically the
transmission assets and provide technical support to RISOs (e.g., collection and
sharing of data).
iv. Institutional layout/Governance. Additional changes in the institutional
framework would be required to enable the RISO approach. For example, it
would be necessary to amend the powers and competences of TSOs, of regulatory
authorities and of ACER in order to ensure the appropriate oversight of these
entities. It would also be necessary to consider aspects such as the financing of
RISOs or the applicability of unbundling rules.
Option 3: creation of a European-wide Independent System Operator
Option 3 would imply the creation of a European-wide Independent System Operation
(EU ISO) that would take over system operation at EU-wide level.
This entity would have the following features:
i. Functions. The functions would be the same as those proposed under Option 2 for
RISOs.
ii. Geographic scope. The EU ISO would be responsible for system operation at EU-
wide level.
iii. Decision-making responsibilities: The EU ISO would perform all system
operation functions and hence would have decision-making powers. TSOs would
solely operate physically the transmission assets and provide technical support to
RISOs (e.g., collection and sharing of data).
iv. Institutional layout/Governance: significant changes would be required in the
institutional framework to enable the creation of an EU ISO and an effective
oversight of its acitivities. It would be necessary to amend the powers and
competences of TSOs, of regulatory authorities and of ACER. It would also be
necessary to consider aspects such as its financing, monitoring of its performance,
etc.
Comparison of the options
2.3.5.
The following Section provides a comparison of the options described above based on
the four main elements identified: (i) functions; (ii) geographical scope; (iii) decision-
making competences; and (iv) institutional layout/ governance. Given that only a few
studies have been carried out on this field, the assessment of the options will be mainly
77
Improving the coordination of Transmission System Operation
qualitative, based on the feedback received from stakeholders and on the content of the
studies published to date, and providing figures where they exist.
(i) Functions
It is not possible to provide a complete quantification of the costs and benefits of each of
the Options as regards the set of functions to be performed at regional or EU level given
that few studies have assessed these costs and benefits. However, the insights from
several previous studies cover the potential benefits of a supranational approach to
system operation.
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Improving the coordination of Transmission System Operation
Table 1 Functions that would be covered under each of the options
RSCs
(Option
0)
ROCs
(Option
1)
RISOs/EU
ISO
(Options 2
and 3)
System Operation
Coordinated Security Analysis (including Remedial Actions-
related analysis)
x x
56 x
Common Grid Model Delivery x x x
Outage Planning Coordination x x x
Short and Medium Term Resource Adequacy Forecasts x x x
Regional system defence and restoration plans x x x
Centralised post operation analyses and reporting x x
Training and certification x x
Market Related
Coordinated Capacity Calculation x57
x
58 x
Coordinated sizing and procurement of balancing reserves x x
Network Planning
Identification of the transmission capacity needs x
Technical and economic assessment of CBCA cases x
Administration of TSO-TSO compensation mechanisms (ITC,
congestion rent sharing, redispatching cost sharing, CBCA)
x x
Risk-preparedness
Support Member States on development of risk preparedness plans x x
Source: DG ENER
56
It could include decision-making powers.
57
The CACM Guideline provides for regional capacity calculators. However, following the
commitments of ENTSO-E, this role could be already assumed for RSCs.
58
It could include decision-making powers.
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Improving the coordination of Transmission System Operation
Table 2 Qualitative estimate of the economic impact of the Options:
Option 0: RSC
approach
Option 1: ROC
approach
Option 2: RISO
approach
Option 3: EU
ISO approach
Economic Impact
Enhancing security of supply by
minimising the risk of blackouts
59
60
0/+ + ++ ++
Lowering costs through increased
efficiency in system operation
61
62 63
0/+ ++ +++ +++
Maximising transmission capacity
offered to the market
64
0/+ ++ +++ +++
59
The financial and social impact of wide area security breaches is enormous: as estimated by ENTSO-
E, the economic impact of wide area security breaches could be really important; the cost of a 20 GW
load disconnection during a large brownout is estimated to 800 million euros per hour (i. e. 40 euros /
kWh). Blackouts have an even higher impact. This provides quantified insight into the importance of
optimised emergency and restoration efforts with a central coordination of locally required efforts.
60
ENTSO-E (2014), "Policy Paper on Future TSO Coordination for Europe", Retrieved from:
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/141119_ENTS
O-E_Policy_Paper_Future_TSO_Coordination_for_Europe.pdf
61
The management of generation shortages should increase the regional social welfare as a result of a
decrease of financial losses that would otherwise result from disconnection of load. It would also
increase solidarity and promote trust in the internal energy market.
62
Also, some of the benefits will derive from the optimisation of training and certification. TSOs will
gain more practical experiences using same tools, practicing common scenarios and sharing best
practices. This should lead to faster system restoration and more efficient tackling of regional-wide
system events.
63
A regional approach to adequacy assessment enhances the use of cross-border connections at critical
moments, resulting in an overall less required generating capacity in Europe. The enhancement is
expected to increase with increasing variable renewable energy in the system. The IEA mentions a
benefit of 1.4 euros/MWh based on the study of Booz & co. An example for regional adequacy
assessment is provided by the Pentalateral Energy Forum.
64
A supranational approach (moving local responsibilities to ROCs) to capacity calculation can bring
significant welfare benefits due to more efficient use of infrastructure and the consequent benefits
coming from the improved arbitrage between price zones. The CACM Guideline Impact assessment
estimates the welfare gains of a supranational approach to flow-based capacity calculation to be in the
region of 200-600 million euros per year. These benefits would only partially materialise (20% of
welfare gains would not be realised) on a voluntary basis, leaving significant parts of the capacities
used in a suboptimal manner.
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Improving the coordination of Transmission System Operation
Reducing the need of remedial
actions by coordinating and
activating in a coordinated way
redispatching
65 66
0/+ ++ +++ +++
Minimising the costs of balancing
provision by taking a more
coordinated approach towards the
sizing of balancing reserves
67 68
69
0/+ ++ +++ +++
Optimisation of infrastructure
planning
70
0 0 ++ +++
65
Significant benefits are expected by the fact that enhanced TSO cooperation minimises the need for
redispatching, especially costly emergency actions. To illustrate, Kunz et al. quantified the benefits of
coordinating congestion management in Germany: in case each TSO is responsible to relief overflows
within its own zone with its own resources, which reflects the current situation in Germany closest,
redispatch costs of 138.2 million euros per year accrue. Coordinating the use of transmission capacities
renders costs of 56.4 million euros per year. As a benchmark, one single unrestricted TSO across all
zones would have to bear redispatch expenditures of 8.7 million euros per year. Kunz et al. also
quantified the benefits of coordinating congestion management cross-border (for the region comprising
Germany, Poland, Czech Republic, Austria, Slovakia): without coordination, total costs of congestion
management amount to 350 million euros per year, they decrease to 70 million euros per year for
optimised congestion management (including remedial actions and flow-based cross-border capacity
allocation).
66
Kunz et al., "Coordinating Cross-Country Congestion Management", DIW Berlin , 2016 and Kunz et
al., "Benefits of Coordinating Congestion Management in Germany", DIW Berlin, 2013
67
As regards the regional sizing and procurement of balancing reserves, the added value of this function
is gain in social welfare due to decreased size of needed balancing reserves and gains in techno-
economic optimisation of the procurement of the needed balancing reserves. Shared balancing has cost
advantages residing from netting of imbalances between balancing areas and from shared procurement
of balancing resources or reserves. This can be based on exchanging surpluses or based on a shared or
common merit order for all balancing resources. Mott Macdonald mentions potential overall benefits
from allowing cross-border trading of balancing energy and the exchanging and sharing of balancing
reserve services of the order of 3 billion euros per year and reduced (up to 40% less) requirements for
reserve capacity. This is for a European electricity supply system with roughly 45% renewable energy.
68
Mott MacDonald (2013), "Impact Assessment on European Electricity Balancing Market" Retrieved
from: https://ec.europa.eu/energy/sites/ener/files/documents/20130610_eu_balancing_master.pdf
69
According to the study carried out by Artelys on Electricity balancing: market integration & regional
procurement, regional sizing and procurement of reserves by ROCs could lead to benefits of 2.9 billion
Euros (compared to 1.8 billion euros benefits from national sizing and procurement). An EU-wide
sizing and procurement of balancing reserves would lead to benefits of 3.8 billion Euros.
70
The added value as regards the identification of the transmission capacity needs at regional level is the
provision of neutral, regional view of investments needs. The industry represented by Eurelectric
claims that "Network investment planning and the coordination of TSOs' network investment decisions
by the RISOs are the next natural steps." As regards the technical and economic assessment of cross-
border cost allocation (CBCA) cases, benefits are expected from higher efficiency and quicker
processes for important transmission infrastructure projects.
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Improving the coordination of Transmission System Operation
Enhancing transparency
71 0 0/+ + +
Costs of implementation72 0/- - --- ----
Other impacts
Administrative impacts/
governance
0/- - -- ---
Source: DG ENER.The assumptions in this table are based on the studies existing in this field as well as on
the feedback received from stakeholders in their response to the public consultation and from estimations
concerning the resources of RSCs and ENTSO-E.
In sum, as illustrated in Table 2, the set of functions in Option 0 will entail limited costs
and benefits, since many of these functions are already carried out by RSCIs in their
supporting role to TSOs. The implementation of the System Operation Guideline and
establishment of ROCs will not involve significant changes to the status quo. The set of
additional functions under Option 1 will entail efficiency gains and increase social
welfare that will derive from providing additional functions to ROCs to be optimised at
regional level (as opposed to national level)73
. In addition, it will entail costs related to
the shift of these functions from national to regional level (e.g., development of processes
and tools at regional level) and will have an impact on the institutional structures (i.e.,
need to adapt the institutional framework to ensure the proper monitoring of
implementation of the functions). Option 2 will present additional gains and costs
compared to Option 1. The benefits will result from the more integrated operation of the
system at regional level as well as from the additional set of functions to be performed by
RISOs, which will comprise real-time operation of the electricity system. The costs will
derive from the need to develop new methodologies, processes and tools to ensure the
performance of these additional functions and the need to adapt the current oversight of
71
As regards the optimisation of TSO-TSO compensation mechanisms, the added value is increased
transparency and step-by-step optimisation of the schemes, resulting in more cost-efficient operation
of the system. This is supported by Eurelectric which states that "Regarding coordination of network
investment decisions, this would require the development of mechanisms for inter-TSO money flows.
Development of inter-TSO money flows will also allow efficient coordinated redispatching, as
requested by the CACM Guideline. This is considered to be a key element for enabling efficient
intraday capacity (re-)calculation". See Eurelectric, "Develop a regional approach to system
operation", June 2016. As regards, post operation and post disturbances analyses and reporting, the
added value is increased transparency, better regional understanding and improvement process, as well
as and potential efficiency gains.
72
The costs of establishing ROCs, RISOs or an EU ISO are estimated to range between 9.9 and 35.6
million EUR per entity. See "Electricity Balancing" Artelys (2016). The study does not provide a
break out of the costs between Options 1, 2 and 3 but assumes that the costs will vary depending on the
functions and responsibilities attributed to these entities.
73
For instance, the management of generation shortages based on seasonal outlooks should increase the
regional social welfare as a result of a decrease of financial losses that would otherwise result from
disconnection of load.
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Improving the coordination of Transmission System Operation
the performance of these functions. Option 3 is the option that will entail most economic
gains (deriving from the efficiencies of performance of the functions at EU level) and
also most implementation costs.
(ii) Geographic scope
In the current context of the rolling out of RSCs (Option 0), there will be certain
flexibility for TSOs to decide which coordinator provides a given service to a region.
This could allow a given region to get services from different providers. While this is an
acceptable compromise in the short and medium term, it partly undermines the goal of
having a regional entity with enhanced overview over system operation and market
operation in the region. In addition, although there will be full European coverage by the
RSCs (with a maximum number of 6), the size and composition of the regions is not
always defined having the technical operation of the grid in mind. Business and political
criteria play also a role in it.
Option 1 would allow ROCs to play an effective coordination role leading to enhanced
system security and market efficiency – given that the ROCs would be able to optimise
the operations over larger regions74
. In contrast with Option 0, the regions would be
defined according to market and system operation criteria (e.g. grid topology). Having a
limited number of ROCs will also bring in savings in developing system operation tools.
However, there would be costs related to the need to adapt further the geographical scope
from RSCs to ROCs but this could be mitigated through a carefully planned
implementation. In Option 1, ROCs would have the possibility to include back-up centres
that ensure that one centre can take over from the other if a problem arises and/or include
sub-regional desks for looking at issues where a more detailed assessment is needed. This
could for example be the case if a ROC is created for the Continental Europe
synchronous area (or at least for Central Western Europe and Central Eastern Europe) as
a natural evolution of the existing Coreso and TSC coordinators – in this case, it could be
natural to have a set up with two locations within a ROC (e.g. Munich and Brussels, if
current coordinadors were to keep existing locations).
The benefits and shortcomings of Option 2 would be similar to those of Option 1 as the
geographical scope of both options would be the same.
Option 3 would entail that the EU ISO is responsible for performing all the functions at
EU level. This approach would lead to efficiency gains, as it would no longer be
necessary to ensure the coordination and cooperation between entities at regional level
and all the functions could be performed seamlessly. However, it is questionable whether
from a technical point of view, at this stage, a single entity would be capable of carrying
out all these functions at EU level even if it envisages setting up sub-regional desks for
the more detailed assessment of regions.
(iii) Decision-making competences
74
This would also pave the way for a further long term evolution towards Regional Independent System
Operatiors.
83
Improving the coordination of Transmission System Operation
In Option 0, RSCs have a purely advisory role i.e. the recommendations that they issue
can be overriden by TSOs75
. This would be the option less politically sensitive. However,
this can potentially lead to inefficient outcomes. For example, when deciding about the
commercial cross-border capacities in a given region which are already calculated at
regional level, the decision taken by RSCs in the form of recommendations are non-
binding. These decisions can be considered as an input that can be rejected by TSOs
based on national interest (e.g. in case of scarcity of supply in one country the TSO might
be tempted to reduce their export capacities but this might not be the best decision from a
regional system security perspective) or due to constraints in their national framework
(e.g., in the case of cross-border remedial actions, a TSO may be obliged to reject the
recommendations issued by the ROC given that the national framework requires a
different order of implementation of remedial actions).
In Option 1 ROCs would have an enhanced advisory role for all functions. Under this
option, ROCs could be entrusted with certain decision-making competences (as opposed
to a pure service provision role) to avoid the possibility of regional optimisation being
lost due to national constraints. This approach is likely to lead to more efficient outcomes
since there would be a margin for overcoming obstacles deriving from the national
framework (e.g. remedial actions, capacity calculation). In the case of the example above,
when deciding about the commercial cross-border capacities in a given region which are
already calculated at regional level, the decisions taken by ROCs could be final and
binding. Whilst this option is likely to bring more efficient outcomes, it is also likely to
be more politically controversial, especially with TSOs and Member States. However,
other stakeholders have expressed support for this option76
. This could be done either
directly enshrining the functions in legislation or subsequently by mutual agreement of
the NRAs overseeing a certain ROC.
75
Indeed, coordination between TSOs through RSCs could be successful if the national frameworks
were harmonised. However, since national frameworks may differ significantly, voluntary
coordination is not likely to be optimal in the medium term.
76
Eurelectric has recently pointed out that "A step-wise regional integration of system operation and of
planning tasks relevant to cross-border trade therefore needs to happen. Such a process should build
upon the ongoing establishment of RSCs, which are executing a certain number of system operation
tasks on behalf of the national TSOs and could be a step towards gradually allocating the
responsibility for those tasks to regional entities". Eurelectric, "Develop a regional approach to system
operation", June 2016. Also, in response to the Commission Public Consultation on a new energy
market design, Acciona emphasised that "system operation should be coordinated at the same level as
markets are, to efficiently manage electricity systems as an integrated whole. Therefore, a regional
responsibility for system security should gradually replace national responsibilities". Also in its
response to the Public Consultation, Engie submitted that "current national responsibility for system
operation indeed hampers cross-border cooperation and is not mimicking the progress made on side
of market integration: different capacity calculation in the flow based approaches are leading to lower
capacity" and that it "favours closer cooperation of TSOs and RSCs taking over new functions
progressively (eventually replacing national TSOs in those functions). Stepwise approach is needed."
In its response to the Public Consultation, Business Europe has stated that "establishing regional
system operators, based on a costs-benefits analysis, could be a first step towards more operational
coordination of TSOs in the future".
84
Improving the coordination of Transmission System Operation
In Option 2 with RISOs that can fully take over system operation at regional level, all
functions carried out by RISOs would be binding since they would fully replace the
functions performed at national level. Entrusting decision making powers to RISOs
would be justified based on the fact that system operation decisions might span well
beyond the area of a single TSO and affect the whole system. This would be the basis for
a regional system operation77
. However, this option would be extremely sensitive
politically and would likely be rejected by many Member States.
Option 3 would require entrusting the performance of the functions and associated
decision-making powers to a single entity, the EU ISO, who would take binding
decisions. This option would set the basis for a truly European operation of the electricity
system. While there would be additional efficiency gains compared to those resulting
from Option 2 (e.g., it would no longer be necessary to ensure the coordination of
operations of a number of entities at regional level), it is unclear whether this option is
technically feasible at this stage. Option 3 would also be politically unacceptable.
(iv) Institutional layout/Governance
Option 0 would not require significant institutional changes, as the interaction between
RSCs, NRAs, TSOs, ACER and ENTSO-E would remain as set out in the System
Operation Guideline. Option 1 would require increasing the level of cooperation
between NRAs and governments, as well as additional competences for ACER and
ENTSO-E, to ensure the oversight of ROCs. Options 2 and 3 would each require
substantial changes to the institutional framework in order to encompass the switch of
decision-making powers for system operation from a national to a regional or EU-wide
level. The costs and speed of implementation would also increase for each of the options,
being Option 3 the most costly and most timely.
(v) Conclusion of evaluation
The Table below provides a qualitative comparison of the Options in terms of their
effectiveness, efficiency and coherence of responding to specific criteria.
77
In this regard, Eurelectric has highlighted that "A truly regional system operation can however only be
based on a regional decision-making structure and a single operational framework. Establishing
regional integrated system operators performing system operation and planning tasks in all regions
should therefore be the end goal to allow for more operational coordination of TSOs". Eurelectric,
"Develop a regional approach to system operation", June 2016
85
Improving the coordination of Transmission System Operation
Table 1: (The assumptions in this table are based on the feedback received from
stakeholders in their response to the public consultation and from additional submissions
from ACER).
Criteria Option 0:
BAU
Option 1:
ROC approach
Option 2:
RISO approach
Option 3;
EU ISO approach
Quality 0/+
Progress remains
limited due to
zones not based
on technical
operation of the
grid
+
More efficient
as optimisation
over zones
based on
technical
operation of the
grid
++
Very efficient
because of enhanced
system operation at
regional level
+++
Most efficient because
of seamless system
operation at EU level
Speed of
implementation
+
Can build upon
established
structures
(RSCIs)
0
Can partially
build upon
established
structures;
change in
geographical
scope and
functions
--
Can partially build
upon established
structures but it will
require a substancial
centralization at
regional level;
change in
geographical scope
of functions; it would
require a substantial
amount of time for
implementation.
---
Cannot build on
established structures.
Substantial change in
geographical scope of
functions. It would
require a substantial
amount of time for
implementation
Use of
established
institutional
processes
++
Can build upon
established
structures (no
decision-making
responsibility)
-
Requires
building up new
structures/
processes
(possibly some
decision-making
responsibility)
--
Requires building up
new structures/
processes (decision-
making
responsibility for all
regional relevant
functions)
---
Requires building
additional structures
and processes that are
adapted for the
operation of this entity
at EU level (decision-
making responsibilities
for all functions at EU
level)
Secure
operation of
the network
0/+
Mandated
cooperation;
slightly reduced
risk of blackout
+
Enhanced
cooperation via
ROCs; reduced
risk of blackout
++
Integration via
RISOs; significantly
reduced risk of
blackout
+++
Seampless operation at
EU level; significantly
reduced risk of
blackout
Efficient
organisational
structure
-
Sub-optimal
organisational
structure; a given
region can get
services from
different
providers
++
Efficient
organisational
structure can be
created; all
services for a
region carried
out by one
company
+++
Efficient
organisational
structure can be
created; all services
for a region carried
out by one company
+++
Efficient
organisational
structure can be
created; all services at
EU level carried out by
a single company
Political
sensitivity
0
Politically most
acceptable as it
represents the
convergence
achieved during
discussions with
Member States
and stakeholders
for the System
-
Politically
sensitive due to
shift in
decision-making
responsibility
for relevant
functions
--
Extremely politically
sensitive due to shift
in decision-making
responsibility
---
Politically
unacceptable at this
stage
86
Improving the coordination of Transmission System Operation
Operation
Guideline
In summary:
While Option 0 will allow achieving some progress in terms of regional coordination
which might be sufficient in the short to medium term, it risks falling short and being
suboptimal in the post 2020 context with the subsequent negative consequences in terms
of system security and market efficiency78
. It would also affect the effectiveness of many
of the other proposals of the market design initiative and be a missed opportunity to
propose legislation on the field that can shape the EU power system in the future.
Option 1 is the preferred option to respond to the post 2020 challenges in system
operation. Execution of the additional functions as outlined in Option 1 will lead to the
ROCs approach, featuring benefits in efficiency and security, but also leading to
increased needs for resources at regional level (data systems, experienced staff).
Allowing ROCs to be entrusted with certain decision-making responsibilities (as opposed
to a pure service provision role) will avoid the possibility of regional optimisation being
lost due to constraints resulting from differences in the national frameworks. This option
enhances the effectiveness of many other proposals of the market design initiative.
Option 2 and Option 3 would constitute the most preferable options from the point of
view of seamless system operation, efficiency and economic gains. While they should
not be discarded as a direction that should be followed in the future, none of these
options are considered proportionate at this stage. Moreover, the feasibility of Option 3 is
questionable. Option 2 is supported by some stakeholders as a long-term goal79
.
78
Eurelectric shares this view and has recently stated that "Current TSOs coordination initiatives such as
RSCs are steps in the right direction. The harmonisation and integration requirements developed in
the System Operation Guideline are nevertheless not ambitious enough. Indeed, these approaches
remain mostly national with the aim to protect the autonomy of individual system operators. Most
importantly, those initiatives do not fully equip system operators to cope with the challenges of a low-
carbon power power system". Eurelectric, "Develop a regional approach to system operation", June
2016
79
For example, Eurelectric declares that "A truly regional system operation can however only be based
on a regional decision-making structure and a single operational framework. Establishing regional
integrated system operators performing system operation and planning tasks in all regions should
therefore be the end goal to allow for more operational coordination of TSOs". Moreover, it states that
"The transistion towards a truly integrated and decarbonised elecricity market will be more efficient if
the electricity system is optimised on a regionla and ultimately a European basis (e.g. TSOs should
operate the system as "one"). This will require a high degree of cooperation between system operators
and the harmonisation of system operation rules. […] Establishing regional integrated system
operators performing system operation and planning tasks in all regions should therefore be the end
goal to allow for more operational coordination of TSOs". Eurelectric, "Develop a regional approach
to system operation", June 2016. In addition, in response to the Commission public consultation on a
new energy market design, Fortum submitted that "the goal should be that the market, in practice, sees
only one TSO. It could be done by [an] European TSO or by current TSOs improving their
cooperation".
87
Improving the coordination of Transmission System Operation
Figure 3 below describes a stepwise approach for the implementation of the future
ROCs
Source: Commission.
Subsidiarity
2.3.6.
The subsidiarity principle is respected given that the challenges the EU power system
will be facing in the post 2020 context are pan-European and cannot be addressed and
optimally managed by individual TSOs. While the mandated TSO cooperation via the
establishment of Regional Security Coordinators (RSCs) envisaged in the System
Operation Guideline constitutes a positive step forward because they will play an
increasingly important support role for TSOs, the full decision-making responsibility will
remain with TSOs. This framework will however not suffice to address the reality of the
dynamic and variable nature of the future electricity system, in which stressed system
situations will become more frequent. This is why it would be required to make the
concept of RSCs further evolve towards the creation of ROCs, centralising some
functions over relevant geographical areas.
The creation of ROCs and allocation of competences to these entities would also be in
line with the proportionality principle given that it does not aim at replacing national
TSOs but rather at complementing the functions which have regional relevance and
cannot be optimally performed in isolation any longer. The competences of ROCs will be
limited to specific operational functions at regional level, for cross-border relevant issues
in the high voltage grid and will exclude real-time operation.
Stakeholders' opinions
2.3.7.
Based on the results of the Public Consultation, as concerns the proposal to foster
regional cooperation of TSOs, a clear majority of stakeholders is in favour of closer
cooperation between TSOs. Stakeholders mentioned different functions which could be
better operated by TSOs in a regional set-up and called for less fragmentation in some
important work of TSOs. Around half of those who want stronger TSO cooperation are
also in favour of regional decision-making responsibilities (e.g. for Regional Security
Coordinators). Views were split on whether national security of supply responsibility is
88
Improving the coordination of Transmission System Operation
an obstacle to cross-border cooperation and whether regional responsibility would be an
option.
The participants to the European Electricity Regulatory Forum have also recently
emphasised the need for closer cooperation between TSOs, enlarging the scope of
functions and optimising the geographical coverage of regional centres. It recognised,
however, that there were divering opinions as regards the delineation of responsibilities
between regional centres and national TSOs and that further consideration was needed80
.
The creation of Regional Operational Centres will be likely seen with concern by TSOs
and a large number of Member States which seem to consider that the currently foreseen
cooperation via Regional Security Coordinators is fit for purpose. In particular, Member
States are likely to oppose any step oriented to entrust regional structures with decision
making powers under the assumption that security of supply is a national responsibility.
Regarding the regions, Member States might prefer geographical dimensions based on
governance rather than what would be optimal from a technical point of view.
80
See Florence Forum conclusions of March 2016:
https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-%20Florence%20Forum%20-
%20Final.pdf
89
Improving the coordination of Transmission System Operation
3. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA I, OPTION 1(C); PULLING
DEMAND RESPONSE AND DISTRIBUTED RESOURCES INTO THE MARKET
90
Improving the coordination of Transmission System Operation
91
Unlocking demand side response
3.1. Unlocking demand side response
92
Unlocking demand side response
Summary table
3.1.1.
Objective: Unlock the full potential of demand response
Option O: BAU Option 1: Give consumers access to
technologies that allow them to participate in
price based demand response schemes
Option 2: as Option 1 but also fully enable
incentive based demand response
Option 3: mandatory smart meter roll out and full
EU framework for incentive based demand
response
Stronger enforcement of existing
legislation that requires Member
States to roll out smart meters if a
cost-benefit analysis is positive and to
ensure that demand side resources can
participate alongside supply in retail
and wholesale markets
Give each consumer the right to request the
installation of, or the upgrade to, a smart
meter with all 10 recommended
functionalities.
Give the right to every consumer to request a
dynamic electricity pricing contract.
In addition to measures described under Option
1, grant consumers access to electricity markets
through their supplier or through third parties
(e.g. independent aggregators) to trade their
flexibility. This requires the definition of EU
wide principles concerning demand response
and flexibility services.
Mandatory roll out of smart meters with full
functionalities to 80% of consumers by 2025
Fully harmonised rules on demand response
including rules on penalties and compensation
payments.
No new legislative intervention. This option will give every consumer the
right and the means (fit-for-purpose smart
meter and dynamic pricing contract) to fully
engage in price based DR if (s)he wishes to
do so.
This option will allow price and incentive based
DR as well as flexibility services to further
develop across the EU. Common principles for
incentive based DR will also facilitate the
opening of balancing markets for cross-border
trade.
This guarantees that 80% of consumers across the
EU have access to fully functional smart meters by
2025 and hence can fully participate in price based
DR and that market barriers for incentive based DR
are removed in all Member States.
Roll out of smart meters will remain
limited to those Member States that
have a positive cost/benefit analysis.
In many Member States market
barriers for demand response may not
be fully removed and DR will not
deliver to its potential.
Roll out of smart meters on a per customer
basis will not allow reaping in full system-
wide benefits, or benefits of economies of
scale (reduced roll out costs)
Incentive based demand response will not
develop across Europe.
As for Option 1, access to smart meters and
hence to price based DR will remain limited.
Member States will continue to have freedom to
design detailed market rules that may hinder the
full development of demand response.
It ignores the fact that in 11 Member States the
overall costs of a large-scale roll out exceed the
benefits and hence that in those Member States a
full roll-out is not economically viable under
current conditions.
Fully harmonised rules on demand response cannot
take into account national differences in how e.g.
balancing markets are organised and may lead to
suboptimal solutions.
Most suitable option(s): Option 2. Only the second option is suited to untap the potential of demand response and hence reduce overall system costs while respecting subsidiarity principles.
The third option is likely to deliver the full potential of demand response but may do so at a too high cost at least in those Member States where the roll out of smart meters is not yet
economically viable. Options zero and one are not likely to have a relevant impact on the development of demand response and reduction of electricity system cost.
93
Unlocking demand side response
Description of the baseline
3.1.2.
For the purpose of this exercise a clear distinction has to be made between technological
prerequisites and market arrangements for demand response as those aspects are
regulated separately. As such chapter 3.2.1 will focus on the baseline for smart metering
and 3.2.2 on dynamic prices and market regulation.
3.1.2.1. Smart Metering
Current Legislation on Smart Metering
Smart metering is a key element in the development of a modern, consumer-centric retail
energy system which encompasses active involvement of consumers. In recognition
hereof, provisions were included in the Gas Directive and in the Electricity Directive
fostering the smart metering roll-out and targeting the active participation of consumers
in the energy supply market. These provisions were then complemented with provisions
under the Energy Performance in Buildings Directive, and the Energy Efficiency
Directive.
The Electricity and Gas Directives81
require Member States to ensure the implementation
of intelligent metering systems that shall assist the active participation of consumers in
the energy supply market, and encourage decentralised generation82
, and promote energy
efficiency. Article 3 (11) of the Electricity Directive and Article 3(8) of the Gas Directive
explicitly state that “in order to promote energy efficiency, Member States or, where a
Member State has so provided, the regulatory authority shall strongly recommend that
electricity (or natural gas) undertakings optimise the use of electricity (or gas), for
example by providing energy management services, developing innovative pricing
formulas, or introducing intelligent metering systems or smart grids, where
appropriate.”
This implementation may be conditional, according to Annex I.2 of both the electricity
and gas Directive, on a positive economic assessment of the long-term cost and benefits
to be completed by 3 September 2012. For electricity, the roll-out can be limited to 80%
by 2020 of those positively assessed cases as potentially indicated in a cost-benefit
analysis ('CBA'). Furthermore, Member States, or any competent authority they
designate, are obliged according to the Electricity and Gas Directive (Annex I.2) to
“ensure the interoperability of those metering systems to be implemented within their
territories” and to “have due regard to the use of appropriate standards and best
practice and the importance of the development of the internal market” in electricity or
natural gas, respectively.
The recast of the Energy Performance of Building Directive ('EPBD'), adopted in May
2010, obliges (Art 8(2)) Member States to "encourage the introduction of intelligent
metering systems whenever a building is constructed or undergoes major renovation,
81
Annex I.2 of the Electricity Directive and of the Gas Directive.
82
Specifically for electricity and linked to smart grid deployment - Electricity Directive, recital (27)
94
Unlocking demand side response
whilst ensuring that this encouragement is in line with point 2 of Annex I to [the
Electricity Directive]".
To assist with the preparations for the roll-out, and based on lessons learned and good
practices identified through experiences accumulated in Member States, the Commission
adopted the Recommendation on preparations for the roll-out of smart metering
systems83
. It aimed at guiding Member States in their choices, drawing particular
attention to: (i) key functionalities for fit-for-purpose and pro-consumer arrangements84
;
(ii) data protection and security issues; and (iii), a methodology for a CBA that takes
account of all costs and benefits, to the market and the individual consumer, of the roll-
out. Following this Recommendation, complementary smart metering provisions were
adopted as part of the Energy Efficiency Directive85
.
Smart Metering Deployment in Member States
According to data from the Commission Report "Benchmarking smart metering
deployment in the EU-27", as also recently updated86
, to date 19 Member States have
committed to rolling out close to 200 million smart meters for electricity by 2020 at a
total potential investment of EUR 35 billion.
- 17 Member States - Sweden, Italy, Finland, Malta, Spain, Austria, Poland, UK-
GB, Estonia, Romania, Greece, France, Netherlands, Denmark, Luxembourg,
Ireland, and lately Latvia – are targeting a nation-wide roll-out to at least 80% of
customers by 2020 (with 13 of them going much beyond the target of the
Electricity Directive).
- 2 Member States – Germany, Slovakia - are moving to deployment in a selected
segment of consumers (to max. 23% by 2020).
- The rest 9 Member States have either decided against at least under current
conditions, or have not made a firm commitment yet for a mass-scale or even a
selective roll-out.
By 2020, it is projected that almost 72% of European consumers will have a smart meter
for electricity87
. Smart meters for electricity are already being rolled out across the EU.
As of 2013, nearly all consumers in Sweden, Finland and Italy, were equipped with smart
meters.
83
Commission Recommendation on preparations for the roll-out of smart metering systems (2012)
http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32012H0148
84
When it comes to functionalities for electricity smart metering, particularly important for residential
consumers are: a readings' update rate of 15 minutes and a standardised interface to transfer and
visualise individual consumption data in combination with information on market conditions and
service or price options.
85
Energy Efficiency Directive. Art 9(2), 12(2b)
86
"Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States" (2015) Smart Grids Task Force
Expert Group 1;
https://ec.europa.eu/energy/sites/ener/files/documents/EG1_Final%20Report_SM%20Interop%20Stan
dards%20Function.pdf
87
Report from the Commission "Benchmarking smart metering deployment in the EU-27 with a focus on
electricity" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN
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Unlocking demand side response
Despite the progress noted, these implementation plans are falling short of the
legislation's intentions. For various legal and technical reasons, the current advancement
is rather slow – particularly in view of the fast approaching 2020 target in the case of
electricity – and the progress gap to delivery may be further widened by recurring delays
in national programmes88
. In addition, there is a risk that the systems being rolled-out do
not bring all the desired benefits to consumers and the market as a whole as they do not
include the necessary functionalities to do so. Furthermore, they might not support in all
cases standardised interfaces89
– at home or station level – for the delivery of these
functionalities, nor be complemented with additional specifications for improving
interoperability on these interfaces and the smooth exchange of information and inter-
working between the metering infrastructure and devices or other network platforms in
the energy market.
In all cases, the successful roll-out is controlled to a large extent by Member States who
are ultimately responsible for the deployment and respective market arrangements90
, and
may or may not decide to follow the guidelines tabled by the Commission regarding
functionalities and implementation measures for data privacy and security (see Energy
Efficiency Directive (Art 9(2b)) and Commission Recommendations "on the preparations
for the roll-out of smart metering systems", and "on the data protection impact
assessment template for smart grids and smart metering systems" 91
).
3.1.2.2. Market arrangements for demand response
Legislative Background
Mechanisms to remove the barriers to demand flexibility are set out in the Electricity
Directive. The Energy Efficiency Directive ('EED') builds on those provisions and
elaborates further, promoting its access to and participation in the market and the
removal of existing barriers.
The Electricity Directive refers to demand response measures as a means to pursue a
wide range of system benefits. The Directive clearly identifies demand response as an
alternative to generation to be considered on an equal footing, e.g. when Member States
are launching tendering procedures for new capacity in situations where the resource
adequacy is insufficient to ensure security of supply (e.g. Art. 8 Electricity Directive).
Demand response, alongside energy efficiency, is viewed as one of the measures to
combat climate change and ensure security of supply. Demand response is recognised as
a means to provide ancillary services to the system in the provisions related to TSO tasks
(Art. 12(d) Electricity Directive), and demand side management/energy efficiency
88
See the Smart Metering Annex of Market Design Evaluation.
89
"Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States" (2015) Smart Grids Task Force
Expert Group 1.
90
Commission Staff Working Document "Cost-benefit analyses & state of play of smart metering
deployment in the EU-27" (2014), sections 2.4 and 2.7
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A52014SC0189
91
"Commission Recommendation on the Data Protection Impact Assessment Template for Smart Grid
and Smart Metering Systems" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=uriserv%3AOJ.L_.2014.300.01.0063.01.ENG
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Unlocking demand side response
measures must be considered as an investment alternative in the context of distribution
network development by DSOs planning for new grid capacity (Art. 25(7) Electricity
Directive).
Effective price signals are important to encourage efficient use of energy and demand
response. In this context, recital 45 of the EED indicates that Member States should
ensure that national energy regulatory authorities are able to ensure that network tariffs
and regulations support dynamic pricing for demand response measures by final
customers. Under Art. 15(1) EED, Member States must ensure that network regulation
and tariffs meet criteria listed in Annex XI of the EED, which inter alia refer to different
possibilities for network and retail tariffs to support dynamic pricing for demand
response and incentivise consumers. According to Article 15(4) EED, Member States
must ensure the removal of those incentives in transmission and distribution tariffs that
might hamper participation of demand response in balancing markets and ancillary
services procurement. Most relevant in the context of this impact assessment is however,
Article 15(8) EED. In summary, Member States must comply with the following
obligations:
- Ensure that national energy regulatory authorities encourage the participation of
demand side resources, including demand response, alongside supply in
wholesale and retail markets;
- Ensure – subject to technical constraints inherent in managing networks - that
TSOs and DSOs treat demand response providers, including demand aggregators
in a non-discriminatory way and on the basis of their technical capabilities;
- Promote - subject to technical constraints inherent in managing networks - access
to and participation of demand response in balancing, reserve and other system
services markets, requiring that the technical or contractual modalities to promote
participation of demand response in balancing, reserve and other system services
markets - including the participation of aggregators - be defined;
- Ensure the removal of those incentives in transmission and distribution tariffs that
might hamper participation of demand response in balancing markets and
ancillary services procurement92
.
Situation in Member States with regards to demand response
The EU demand response market is still in its early development phase. This early
development has proceeded very differently across Member States that have chosen
different approaches to make use of demand side flexibility and to implement demand
response. In fact, while Article 15.8 EED formulates principles for the market access of
demand service providers and demand side products it has left substantial freedom for
Member States to implement these.
While a full transposition check of Art 15.8 EED has not yet been carried out it can
already be seen that different national provisions have led to a fragmented European
market on demand response with different rules and market opportunities for
92
See guidance note on Energy Efficiency Directive Art 15 which also covered Industrial Emissions
Directive elements http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:52013SC0450
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Unlocking demand side response
(independent) demand response service providers, different market arrangements
between service providers and balancing responsible parties (including compensation
payments) and different rules for trading flexibility in the balancing, wholesale and
capacity markets.
Explicit (or incentive based) demand response
For explicit demand response, full customer participation in the electricity markets is a
prerequisite as addressed in the relevant provisions of the EED. However, because of its
complexity only very large industrial consumers can directly engage in the electricity
markets while commercial and residential consumers will in most of the cases need to go
through demand response service providers (aggregators). These require fair market
access for such aggregators and open balancing, wholesale and capacity markets for
flexibility products.
a) Market Access for aggregators
The EED stipulates that demand response providers (including aggregators) have to be
treated in a non-discriminatory manner. However, market access and market rules for
aggregators are regulated differently across Europe. In order to ensure full access to the
market at least the following main features have to be addressed in national regulation:
- Clear definition of roles and responsibilities of aggregators within the energy
market to ensure legal certainty;
- Clear definition of the relationship between aggregators and Balancing
Responsible Parties ('BRPs') that ensures market access of the aggregators at
fair conditions. Such rules are essential to ensure that the BRP (which is usually
the supplier) has no means of stopping a competitor (e.g. independent
aggregator) for engaging with one of its customers and entering the market.
In many Member States such a framework for aggregators is effectively missing or
independent aggregation is legally banned. This applies for Bulgaria, Croatia, Cyprus,
Czech Republic, Estonia, Greece Italy, Malta, Portugal, Spain and Slovakia. But also in
Member States where legislation for aggregators and demand response has been
established many differences can be noted.
To date, France is the only Member State that developed a complete framework for
demand response explicitly enabling independent aggregation by guaranteeing
contractual freedom between the consumer and the aggregator without supplier's consent.
A standardised framework also exists for the compensation mechanisms, however, it is
claimed by some stakeholders that this mechanism greatly penalises the aggregator,
overcompensates the BRP and hence renders the business case for independent
aggregators negative.
Other Member States allow (independent) aggregation but to varying degrees.
Independent aggregators are allowed in Belgium, Ireland, UK, Germany and Austria
albeit not all markets are effectively opened to them as rules, e.g. in Austria, effectively
limit their activity to aggregate loads of big consumers. In some Member States like
Poland, the Netherlands and in the Nordic markets aggregators have also to become
suppliers or offer their services jointly with suppliers but cannot act as completely
independent service providers. In all Member States, apart from France, the UK and
Ireland, the explicit consent of the consumer's supplier is required for aggregators to
enter into the market. Equally in those Member States, a clear framework for
compensation payments is missing and therefore such payments may need to be
individually negotiated between the independent aggregator and supplier as a
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Unlocking demand side response
precondition for accessing the consumer. As such, the incumbent supplier can effectively
block market access at least for independent aggregators.
b) Access of flexibility to the markets
The EED requires Member States to promote access to and participation of demand
response in balancing, reserve and other system services markets inter alia by engaging
the national authorities (or where relevant, the TSOs and DSOs) to define technical
modalities on the basis of the technical requirements of these markets and the capabilities
of demand response; these specifications must include the participation of aggregators.
Technical modalities or requirements can be for example the minimum size of a load, the
activation time or the duration for which a product needs to be provided. Traditionally,
requirements have been designed along the capacities of big generation units, e.g. coal
power plants. Demand side products naturally face problems to meet these requirements,
even if aggregated. Another aspect is that prequalification requirements often have to be
fulfilled per unit and not at the aggregated level. As the following stock-taking will show,
access of demand resources to the wholesale, balancing and recently capacity markets
varies considerably across Member States.
The analysis of the status quo suggests that in most of the Member States access to the
markets is either up-front restricted or preconditions make it difficult for demand side
products to qualify and compete. In roughly only a third of the Member States demand
side products have fair access to the markets and in even fewer Member States demand
response is actually happening. Generally, the balancing markets tend to be more open to
demand side products than the wholesale markets.
In many Member States demand side resources do not play any role in the markets.
Examples for this situation would be Cyprus, Malta and Croatia. But also in many other
Member States markets are practically closed and allow for only very restricted
participation of the demand side. Often it is only suppliers or big industrial actors that are
allowed to bid in the markets. In those cases, there are usually very specific demand
flexibility programmes for selected, mainly very large, actors. For example, in Italy,
Spain and Greece interruptibility programmes have been or are being introduced for large
industrial loads.
Other countries are one step ahead and have partly opened their markets, while practical
barriers still hamper the market access. The balancing market in Germany for example is
in principle open to demand loads, but heavy prequalification (e.g. extensive testing) and
programme requirements (e.g. bid size) block any major remand response-activity.
Similarly, practical barriers, in particular for aggregated demand, hamper access to the –
theoretically open – balancing markets in Slovenia and Denmark and to some degree also
in Sweden.
There is a group of countries where demand response has already assumed a more
important role. Belgium for example adapted their technical requirements and offers
quite a large range of possibilities for demand side resources to participate in the
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Unlocking demand side response
balancing and ancillary services markets. In the UK, the market for ancillary services93
is
open to demand response and a dedicated 'Demand Side Balancing Reserve' mechanism
was established in 2015. Meanwhile, France has become probably the Member State with
the broadest general access of demand response to both the balancing and the wholesale
market. A general framework is in place that facilitates demand side participation, which
has caused demand response providers to begin expanding onto this market.
The table below summarizes in which Member States markets are open to demand
response and the amount of incentive based demand response currently estimated in
those Member States. While demand response is allowed to participate in most Member
States, activated volumes of more than 100 GW can only be found in 13 Member States.
Table 1: Uptake of incentive-based demand response
Member State
Demand Side
Products (DSP) in
energy markets
DSP in balancing
markets
DSP in capacity
mechanisms
Estimated
demand response
for 2016 (in GW)
Austria Yes Yes 104
Belgium Yes Yes Yes 689
Bulgaria No No 0
Croatia No No 0
Cyprus No market No market 0
Czech Republic Yes Yes 49
Denmark Yes Yes 566
Estonia Yes No 0
Finland Yes Yes Yes 810
France Yes Yes Yes 1689
Germany Yes Yes Yes 860
Greece No (2015) No 1527
Hungary Yes Yes 30
Ireland Yes Yes Yes 48
Italy Yes No Yes 4131
Latvia Yes No Yes 7
Lithuania unclear No 0
Luxembourg No information No information
Malta No market No market
Netherlands Yes Yes 170
Poland Yes Yes No 228
Portugal Yes No 40
Romania Yes Yes 79
Slovakia Yes Yes 40
Slovenia No Yes 21
Spain Yes No Yes 2083
Sweden Yes Yes Yes 666
UK Yes Yes Yes 1792
Total 15628
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering"(2016) COWI
Implicit (price based) demand response
93
The range of functions which TSOs contract so that they can guarantee system security, including
black start capability, frequency response, fast reserve and the provision of reactive power.
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Unlocking demand side response
For implicit demand response, smart metering systems as well as the availability of
dynamic pricing contracts linked to the wholesale market are prerequisites. For smart
metering systems roll-out plans exist for 17 Member States, while in 2 Member States a
partial roll-out is planned and in a number of those Member States the functionalities of
the smart metering systems (enabling communication interfaces, frequent update
intervals, advanced tariffication, etc.) may not allow for automatically reacting to price
signals (a complete analysis is provided within the evaluation fiche on smart metering).
EU legislation does not currently impose any requirements on Member States to activate
price based (or implicit) demand response.
In order to activate price based demand response the availability of dynamic electricity
pricing contracts are a prerequisite as those contracts can incentivise consumers to adjust
their consumption according to the real time price signal. The ACER/CEER Market
Monitoring Report contains a dedicated analysis of the competition situation in all
Member States in the retail market and the different offers available to the customers.
This analysis shows that only in Denmark, Sweden and Finland dynamic pricing
contracts that are linked to the spot market are available to residential consumers while
only in Sweden and Norway such contracts represent more than 10% of all consumer
contracts. In terms of costs for the consumers the ACER/CEER analysis shows that
offers linked to the spot market are slightly cheaper for the consumer than fixed or
variable offers in the same country.
Graph 1: Type of energy pricing of electricity offers in EU Member States capital
cities,
Source: "Market Monitoring Report 2014" (2015) ACER
In addition to the three Member States addressed above also in Estonia, Spain, Austria,
Belgium, Netherlands and Germany dynamic pricing contracts are available on the
market – at least for certain consumer groups - which were not yet included in the
ACER/CEER analysis. However, the uptake of such tariffs is currently very low and no
detailed data is available yet.
As a high level estimate for the EU, studies and data support current load shifting due to
times of use tariffs and price based demand response ranging from negligible (most
Member States), to around 1% (most Northern European Countries) to 6-7% (Finland
and France). The overall load that is shifted due to Time-of-Use ('ToU') and dynamic
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Unlocking demand side response
tariffs to date would be of the order of 5.7GW (or 1.2% of peak load in Member States
where dynamic tariffs are offered).
While data on current demand response levels is difficult to obtain, estimates from the
impact assessment study94
indicate the use of approx. 21.4 GW of demand response per
year in Europe including the 5.7GW from ToU and dynamic tariffs referred to above.
This is only a small fraction of the demand response potential that adds up to approx.
120.000 MW in 2020 and 160.000 MW in 2030 which will lay mainly with residential
consumers. However, this potential is purely theoretical (not taking into account
commercial viability and technology restriction) and for 2030 greatly depends on the
uptake of flexible loads such as electric vehicles and heat pumps in the residential sector.
Graph 2: Theoretical demand response potential 2030
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Deficiencies of current legislation
3.1.3.
A detailed analysis of the existing legislation on smart metering systems and demand
response in European and national legislation has been carried out in the framework of
the evaluation. The detailed results of this analysis are reported in the annexes to the
Market Design Initiative evaluation (annexes on "Details on the EU framework for smart
metering roll-out and use of smart meters" and "Details on the EU framework for
Demand Side Flexibility")
94
"Impact Assessment support Study on downstream flexibility, demand response and smart metering",
(2016) COWI
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
Industrial
Commercial
Residential
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Unlocking demand side response
3.1.3.1. Deficiencies of current Smart Metering Legislation
Looking at the current situation with smart metering deployment in the Member States,
despite the progress noted, EU-wide implementation is falling short of the legislator's
intentions, in terms of level of commitment, roll-out speed, and purpose. In the light of
the developments so far, the existing provisions can be assessed as follows.
In terms of effectiveness, the evidence available generally suggests that the smart
metering provisions currently in place have been less effective than intended. This is
partly a result of the 'soft'/unspecific nature of some obligations they lay (i.e. Article 8(2)
of the EPBD. Enforcing the recommended95
minimum functionalities for smart metering
systems on an EU level, and consistently promoting the use of available standards to
ensure connectivity and 'interoperability', as well as best practices, while having due
regard to data security and privacy, would guarantee a coherent, future-proof system able
to support novel energy services and deliver benefits to consumers, in line with the
legislator's intentions.
There is not enough evidence at the moment to evaluate the efficiency of the intervention
in terms of proportionality between impacts and resources/means deployed. This is due to
the fact that most of the large-scale roll-out campaigns have yet to start unfolding making
the field data available rather scarce; there are only projections available based on
Member States cost-benefit assessments.
In terms of relevance, the evaluated smart metering provisions, considering current
needs and problems, remain highly valid. This said, they could though be further
enhanced, by elaborating them as to: (i) spell out how the term of 'active participation' is
to be understood, and expected to be realised in practical terms, namely define
requirements for functionality, connectivity, interoperability, and standards to use; (ii)
include an obligation to Member States to officially set the minimum technical and
functional requirements for the smart metering systems to be deployed, the market
arrangements, and clarify the roles/responsibilities of those involved in the roll-out.
In terms of coherence – internally and with other EU actions – even though no clear
contradictions could be pointed out, the evaluation has identified some room for
improvement. Linking of the term 'actual time of use' in Article 9(2a) and Article 9(1)
EED to smart metering provisions erroneously restricts the functional requirements of the
targeted set-ups and raises questions about coherence with the framework for promoting
smart meters. There is therefore a need to clarify that a wide range of functionalities is in
fact promoted, as those recommended by the Commission, that go much beyond the
capability of just 'actual time of use' information which usually refers to advanced, and
not smart metering.
Finally, evidence points to the need to eliminate ambiguities and to further elaborate,
clarify, and even strengthen the existing provisions, in order to give certainty to those
planning to invest and ensure that smart metering roll-outs move in the right direction,
and regain EU added-value. This is to be done by: (i) safeguarding common
functionality, and share of best practices; (ii) ensuring coherence, interoperability,
95 Commission Recommendation on preparations for the roll-out of smart metering systems (2012)
http://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:32012H0148
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Unlocking demand side response
synergies, and economies of scale, boosting competitiveness of European industry (both
in manufacturing and in energy services and product provision); and (iii), ultimately
delivering the right conditions for the internal market benefits to reach also consumers
across the EU.
3.1.3.2. Deficiencies of current regulation on demand response
It was the objective of the existing European legislation to put demand response on equal
footing with generation and to ensure that demand response providers, including
aggregators, are treated in a non-discriminatory way. While provisions aiming at
realising those objectives have been put in place in many Member States, the
development of demand response across Member States varies significantly and has led
to fragmented markets. Especially the different treatment of independent aggregators
across the EU is a matter of concern. It can therefore be concluded that additional
provisions further specifying the existing provisions are needed to ensure a harmonised
development and enable price and incentive based demand response across Europe.
In terms of effectiveness, the evidence available generally suggests that the demand
response provisions currently in place have been less effective than intended. The
provisions have not been effective in removing the primary market barriers especially for
independent demand response service-providers and creating a level playing field for
them. Instead the heterogeneous development of demand response has led to fragmented
markets across the EU. This is mainly due to the high degree of freedom the existing
provisions leave to Member States. The different treatment especially of independent
demand response service-providers in national energy markets as well as of flexibility
products in electricity markets risk undermining the large-scale deployment of demand
response needed as well as the functioning of the internal energy market.
There is not enough evidence at the moment to evaluate the efficiency of the intervention
in terms of proportionality between impacts and resources/means deployed.
In terms of relevance, the herein evaluated demand response provisions remain highly
valid. Full exploitation of demand response remains crucial to manage the energy
transition as it is an enabler for efficiently integrating variable renewables into the energy
system. However, as pointed out above, the existing provisions have not been effective in
deploying demand response sufficiently quickly across Europe.
In terms of coherence the evaluation has shown that the provisions on demand response
are fully coherent with other legislative provisions within the Electricity Directive, the
EED, the RED and the EPBD.
Finally, considering the EU added value, it remains crucial to ensure that harmonised
demand response provisions are in place across the EU to guarantee a functioning
internal energy market. Even more because under the upgrading of the wholesale market
within the market design initiative the Commission will also look into opening national
balancing markets where flexibility may then be traded across borders. Full availability
of demand response in all Member States will then be crucial for the functioning of those
cross-border balancing markets.
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Unlocking demand side response
Presentation of the options
3.1.4.
Option 0: BAU
As outlined in chapter 3 the existing provisions on smart meters and demand response
have not proven to be fully effective in reaching the goals of rolling out fully functional
smart metering systems to at least 80% of consumers EU-wide by 2020 and to put
demand response on equal footing with generation.
Option 0+: Non-regulatory approach
Considering non-legislative intervention and just resorting to Option 0+ of a potential
stronger enforcement and/or voluntary cooperation, would not allow for an improvement
of the current situation regarding the uptake of fit-for-purpose smart metering and of the
market conditions for demand response to flourish. Option 0+ is not expected to remove
market barriers for demand side flexibility to reach its full potential, and therefore will
not deliver the policy objectives.
According to the Commission's assessment, the provisions related to smart metering
systems have been correctly transposed in Member States and hence, as argued earlier,
no further enforcement leading to a greater roll out of such systems is realistic. The
provisions of Art 15(8) EED related to demand response have not yet been subject to a
full transposition check or any infringements. However, even in those Member States
where the provisions have been fully and correctly transposed market barriers for
independent service providers continue to exist. This suggests that the current provisions
are not sufficiently explicit to fully remove all remaining barriers to demand response. As
such a stronger enforcement of existing provisions may in some Member States lead to a
greater take up of demand response but this alone will not be sufficient to provide a full
level playing field as intended by European legislation, and would not deliver the policy
objectives, which is the reason this option was not further considered.
Option 1: Enable price based demand response
Smart metering systems are the key prerequisite for properly accounting for, and then
rewarding, consumers' involvement in demand response or the use of distributed energy
resources. However, it is expected that a smart meter roll-out will be realised in only 17
Member States (plus a partial roll-out in 2 Member States). In some of those Member
States the roll-out may take place without all the functionalities identified in the
Commission Recommendation on the preparations for the roll-out of smart metering
systems.
Our objective is to ensure that interoperable smart metering systems with the right
functionalities are available to all consumers. The policy measures to ensure that price
based demand response can develop include:
- Give consumers the right to request a meter with the full 10 functionalities when
roll-out without full functionality is taking place or has already been completed.
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Unlocking demand side response
- Give consumers the right to request a smart meter with full functionalities when
wide scale roll-out is not carried out96
.
- Grant consumers the right to an electricity pricing contract linked to the
development of the spot market.
Option 2: Enable price and incentive based demand response across Europe
In addition to enabling price based demand response schemes as in Option 1, the
objective in this area is to remove the key barriers to incentive based demand response
and flexibility services in order to facilitate the market-driven deployment of these
technologies to the greatest practicable and economically viable extent. The new rules
ensuring full market access for independent aggregators will address the following:
- Ensuring full non-discriminatory market access for consumers to all relevant
markets either individually or through third part aggregators.
- Ensuring that each market participant contributes to the system costs according to
the costs and benefits (s)he induces to the system.
- Removal of barriers at wholesale, balancing at capacity markets for aggregated
loads and for flexibility.
Option 3: Mandatory smart meter roll-out and full EU framework for incentive-based
demand response across Europe
The third option goes beyond the provision in Option 2. Instead of the right for
consumers to request a smart meter, it contains an obligation for a mandatory roll-out of
smart meters with the 10 recommended functionalities by 2025, for 80% of consumers in
every Member State. In addition, it contains a detailed framework for demand response
that no longer only defines principles for this framework but also defines favourable
financial rules for aggregators: The financial arrangements between aggregators and
BRPs explicitly exclude any financial transfers between aggregators and BRPs. The
provisions on access of aggregated loads to wholesale, balancing and capacity markets
remain unchanged from Option 2.
96
In both cases the requested systems must be able to ensure interoperability among the operators
responsible for metering and other participants in the electricity market and thus support the provision
of energy management and information services of benefit to the consumer.
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Unlocking demand side response
Comparison of the options
3.1.5.
a. Effectiveness of options
In the context of this impact assessment two objectives are envisaged:
- The accelerated deployment of fit-for-purpose smart metering systems that will
enable consumers to receive timely and accurate information on which they can
promptly act and accordingly adjust their consumption – in volume and time –and
benefit from new energy services (e.g. demand response)
- The uptake of demand response for consumer and system benefit
Smart Metering uptake
Assuming that no new EU intervention takes place, apart from the stronger enforcement
of existing legislation which is foreseen under option 0, and deployment plans go ahead
as they currently stand, smart meters will be installed only in those Member States where
their deployment is currently positively assessed, leading to a maximum EU penetration
rate of close to 72% by 2020. However, the systems to be rolled out will not necessarily
be interoperable, nor equipped in all cases, as recent data have shown97,98
, with those
consumer benefitting functionalities (as listed in "Commission Recommendation on
preparations for the roll-out of smart metering systems") that support his participation in
novel energy services' programmes.
It is important to note here that increased functionality is directly associated to benefits,
but not to costs; it does not push up the overall cost of the deployment, given that it is
mainly software driven and its incremental cost is relatively low99
. Issues related to
economies of scale and customisation may be more important in driving overall costs.
So, selecting fewer items from the set of common minimum functionalities does not
necessarily translate into less expensive systems. This makes a compelling case for
adhering from the start of the roll-out to the full set of the recommended functionalities100
for the smart metering systems rolled-out.
Bearing in mind the intentions of the Member States regarding smart metering
functionalities, and for rolling out standardised interfaces to support the communication
of the metering infrastructure with devices and business platforms, in practice, much
97
Commission Staff Working Document "Cost-benefit analyses & state of play of smart metering
deployment in the EU-27" (2014) Table 8
98 "
Status report based on a survey regarding Interoperability, Standards and Functionalities applied in
the large scale roll-out of smart metering in EU Member States" (2015) Smart Grids Task Force
Expert Group 1
99
"Cost benefit analysis of smart metering systems in EU Member States" (2015) ICCS-NTUA & AD
Mercados EMI ; "Impact Assessment support study on downstream flexibility, demand response and
smart metering" (2016) COWI
100
Report from the Commission "Benchmarking smart metering deployment in the EU-27 with a focus on
electricity" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN; supported with
data from the Commission Staff Working Document "Cost-benefit analyses & state of play of smart
metering deployment in the EU-27" (2014) .
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more than 30% of EU customers by 2020 will be effectively denied the means – a fully
functional smart metering system - for getting involved in demand response schemes.
Furthermore, given that the meters installed will be in place for the next 15 years, which
is their average economic lifetime, the overall demand response potential will be
significantly reduced up to 2030.
For estimating the smart metering deployment for the alternative Option 1 (smart meter
or its functional upgrade on request by the consumer) the following assumptions are
made:
- In countries with a reported large-scale roll-out of smart metering systems, the
roll-out occurs as planned, with the recommended functionalities not being
though throughout implemented. In all cases, customers will have access to
dynamic tariffs by 2020. This reflects greater customer and supplier awareness of
the benefits of smart meters;
- In countries with either a limited (in terms of customer coverage or functionality)
roll-out or no planned roll-out, fully functional smart meters (or their upgrade)
will be made available to customers on demand.
The extent to which customers will choose the installation of a smart meter (or its
functional upgrade) will depend on a range of factors, including the proportion of overall
benefits that it could capture for them. Where a customer is faced with the full cost of
smart metering installation, extremely low take up is envisaged in the relevant Member
States based on current technology and its cost.
The analysis of national cost-benefit analyses for the roll-out of smart meters in those
countries not proceeding with a large scale roll-out has shown that customer related
benefits from smart metering systems are generally significantly lower than
corresponding per metering point costs. In two cases (Germany and Slovakia) the
national CBAs have concluded that a mandatory roll-out to all consumers would not be
beneficial but only for consumers above a certain consumption threshold:
- In Germany a mandatory roll-out for all consumers with an annual consumption
above 6000kWh is proposed;
- In Slovakia, the CBA considers that consumers with annual consumption above
4000kWh (covering 23% of metering points and 53% of Low Voltage
consumption) will overall benefit from an installation.
For the purpose of analysis, it is assumed that for all countries without a full purpose (in
terms of scale - nationwide, and function) roll-out of smart meters, the uptake of a smart
meter paid for by the consumer will be low in the short to medium term (up to 2020), but
may well increase significantly in the subsequent period to 2030 as the costs of meters,
communications and information technology fall, and the spread of appliances conducive
to price-based demand response rises. Therefore, the following estimates are made:
- Take up of smart meters of around 10% of residential and small commercial
consumers by 2020 in Member States where no full purpose roll-out is planned;
- Take up of smart meters of 40% of residential and small commercial consumers
by 2030 in Member States where no full purpose roll-out is planned.
While no additional smart metering related measures are foreseen under Option 2, under
Option 3 a mandatory roll-out of smart meters to at least 80% of consumers in all
Member States is included, and this is to materialise irrespectively of the result of their
national assessments for the cost-effectiveness and feasibility of this deployment. Such a
mandatory roll-out will eventually lead to approximately 90% of all consumers having a
fully functional smart metering system installed by 2030. This reflects current experience
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with smart metering roll-out where some installations for technical reasons may be too
expensive and some consumers refusing to have a smart meter installed because of
privacy concerns.
In the light of these assumptions, the resulting estimates of smart meter roll-out and
access to dynamic tariffs under Option 1, 2 and 3 are set out below.
Table 2: Overview smart meter uptake
BAU = Option
0
Option 1 Option 2 Option 3
2016
Smart meter 35% 35% 35% 35%
2020
Smart meter 71% 72% 72% 72%
2030
Smart meter 74% 81% 81% 90%
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Uptake of dynamic price contracts
In order to participate in price based demand response schemes, consumers not only have
to have a smart meter but also a dynamic electricity price contract. Under all options, it is
considered that the consumer must voluntarily opt in for such a contract. At this stage,
only estimates can be made on the number of consumer with a smart meter opting for
dynamic contracts, time of use contracts and static contracts. The following estimates
have been used for this analysis on the basis of various studies as well as pilot projects
and initial experience in the Nordic countries101
:
101
The core estimated figures are in line with international trial studies and practical evidence, including:
- The consumer survey of “Smart Energy GB survey”, which states that around 30% of the people
were either strongly or moderately in favour of switching to a ToU tariff;
- The take-up rate of the Critical Peak Pricing ("CPP") tempo tariff in France that was slightly less
than 20% of the total consumers.
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Unlocking demand side response
Table 3: Uptake of dynamic and ToU price contracts of consumers with smart
meters
BAU Option 1 Option 2 Option 3
2016
ToU 10% 10% 10% 10%
Dynamic 0% 0% 0% 0%
2020
ToU 18% 18% 18% 18%
Dynamic 3% 3% 3% 3%
2030
ToU 26% 26% 26% 26%
Dynamic 16% 16% 16% 16%
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
The average uptake rate is identical for all options as for all options it is assumed that
dynamic tariffs are available for those consumers who wish to have one. In the case of
Member States not currently planning a large scale roll-out of smart metering systems
and for which optional take up applies under Option 1, a higher take up rate is assumed
for the calculation. This is done under the assumption that consumers actively opting for
smart meters are equally more likely to actively opt in for advanced price contracts.
Hence the take up rate for static ToU and Critical Peak Pricing (CPP) doubled in 2020
and 2030 for customers with a smart meter (52% and 32% respectively in 2030).
Demand response uptake
The uptake of demand response was calculated on the basis of the smart meter roll-out
and uptake of dynamic price contracts as presented above taking into account the overall
demand response potential as presented in chapter 3.1.2.
Option 0 (BAU)
In case no additional measures are taken demand response will still develop across
Europe. The roll-out of smart meters will be carried out as planned and dynamic price
contracts will be available to consumers in Member States where mart meters are rolled
out and where the retail market is sufficiently competitive. Under the BAU, an increase
of price based demand response from 5.8 GW to 15.4 GW in 2030 is accepted.
It is important to note that the uptake of demand response depends heavily on the
appliances/loads residential consumers have in their possession:
- For normal appliances, 4.9% of potential demand response is captured, while
- For electric vehicles, heat pumps and smart appliances, 18.6% of potential
demand response is captured.
These figures are very sensitive to the take-up of new forms of price contracts. The
proportion of potential demand response for electric vehicles and heat pumps captured
ranges from around 13% for Member States not currently supporting a widespread roll-
out of smart metering systems to around 21% if it is planning a full scale roll-out.
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Incentive-based demand response will only develop very slowly as in the absence of a
clear enabling framework independent aggregation will remain limited and access of
flexibility to the markets limited. In total, under the BAU option demand response can
increase from 21.4 GW in 2016 to 34.4 GW in 2030 or by 60%.
Option 1
In case only price based demand response is further enabled, the calculation shows that
total demand response would only increase compared to the BAU by approx. 2.5 GW by
2030 at an EU-wide level. This reflects the moderate additional uptake of smart meters
when each consumer has the right to have it installed.
Option 2
Incentive-based demand response is already represented in the wholesale energy markets
in half of the Member States. In policy Option 2, it is assumed that all Member States
having introduced some incentive based demand response already will reach a level of 5
per cent peak reduction in 2030, gradually increasing from today's level. The increased
level of demand response compared to Option 1 is due to adjustments in programme
requirements to better reflect the needs of demand side. This includes allowing
aggregated bids in the markets allowing aggregators enter the market as a service
provider for industry and large commercial consumers. There is also a standard process
for settlements between aggregators and suppliers to facilitate aggregation. Also, all
Member States will introduce incentive based demand response and the Member States
not currently having incentive based demand response, will reach a level of 3 per cent of
peak load in 2030, the potential gradually being introduced from 2021. The reasoning for
take-up of demand response in these Member States is the same, but they will start from
a lower level than Member States where demand response is already taking place.
Those measures will lead to an increase of incentive based demand response by approx.
15.6 GW or more than 80% compared to the BAU scenario. Under option 2 price based
demand response stays stable as no additional measures are introduced. Hence, total
demand response compared to the BAU scenario will increase by approx. 18GW or
52%102
.
Option 3
In policy Option 3 it is assumed that all Member States having already introduced some
incentive based demand response will reach a level of 8 per cent peak reduction in 2030,
gradually increasing from today's level. Also, all Member States will introduce incentive-
based demand response and the Member States not currently having incentive based
demand response, will reach a level of 5 per cent of peak load in 2030, the potential
gradually being introduced from 2021. The increased level of demand response
compared to Option 2 is due to aggregators entering the market as a service provider
under more favourable conditions. Also, the prices for balancing reserves have increased
due to increased imbalances in the energy market. Those measures will lead to an
increase of incentive based demand response by approx. 20 GW or approximately double
compared to the BAU scenario.
102 In this Impact Assessment only the impact demand response is being quantified. Other forms of
consumer flexibility such as self-generation are being assessed under the RED II Impact assessment.
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Unlocking demand side response
Under this option it is assumed that price based demand response will remain unchanged.
While more consumers will have access to a smart meter it is unlikely that those
additional consumers who have not opted for a smart meter in the first place will request
a dynamic tariff and hence they will not participate in demand response schemes. Total
demand response compared to the BAU scenario will therefore increase by approx.
23GW or 66% or by 4.7GW compared to Option 2.
Table 4: Overview of demand response (in GW/year) uptake for different options
BAU Option 1 Option 2 Option 3
2016
Price-based 5.8 5.8 5.8 5.8
Incentive-based 15.6 15.6 15.6 15.6
Total 21.4 21.4 21.4 21.4
2020
Price-based 6.4 6.9 6.9 6.9
Incentive-based 16.3 16.3 20.3 21.4
Total 22.7 23.3 27.2 28.4
2030
Price-based 15.4 17.9 17.9 17.9
Incentive-based 19.0 19.0 34.6 39.3
Total 34.4 36.8 52.4 57.1
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
b. Key economic impacts
Cost and benefits of smart metering
In this Section the cost-effectiveness and impact of smart metering is to be seen as part of
the bigger picture of delivering services to the consumer and enabling his participation in
price based demand response, and allowing him to offer his flexibility to the energy
system, and be rewarded for it.
Under option 0, the smart metering roll-out, following in most cases a positive CBA
undertaken by the Member States, is assumed to take place as planned. A complete
listing of costs and benefits associated with smart metering deployment in Member States
can be found in the Commission Benchmarking Report issued in 2014103
. Available data
there coming from the CBAs104
of Member States that are proceeding with the roll-out,
103
(see Table 25 in) Report from the Commission "Benchmarking smart metering deployment in the EU-
27 with a focus on electricity" (2014)
http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=COM%3A2014%3A356%3AFIN;
and accompanying (i) Commission Staff Working Document "Cost-benefit analyses & state of play of
smart metering deployment in the EU-27" (2014), (ii) Commission Staff Working Document
"Country fiches for electricity smart metering" (2014)
104
idem
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indicate, despite their divergence, that the cost of installing a smart metering system for
electricity is on average close to EUR 225 per customer, while the benefit (per customer)
is EUR 309 accompanied by energy savings in the order of 3% and up to 9.9% of peak
load shifting.
The peak load shifting expectations vary greatly across the Member States; namely from
0.75% (UK) and 1% (Poland) to 9.9% in Ireland in the cluster of Member States that are
preparing a roll-out, and from 1.2% (Czech Republic) to 4.5% quoted in Lithuania in the
batch of Member States that are not presently proceeding with large-scale deployment.
These significant differences may be due to: (i) different experiences coming from
locally run pilot projects and/or hypotheses adopted in building the scenarios;105
, and (ii),
different patterns considered in electricity consumption, e.g. presence of district heating,
wide-spread use of gas, etc.
On the cost side, meter costs (CAPEX and OPEX) are identified by the majority of
Member States as dominant followed by the capital and operational cost due to data
communication. In most countries (and relative to the electricity deployment arrangement
of the country), the smart metering investment and installation cost appears as an upfront
cost for the distribution system operator in the initial stage of the deployment; however,
in most cases they are later fully or partly passed to the final consumer through network
tariffs.
Regarding benefits, data show that in a number of Member States – the Czech Republic,
Denmark, Estonia, France, Italy, Luxembourg and Romania – the distribution system
operator is the first/large direct beneficiary of the electricity smart metering, followed by
the consumer, and the energy supplier. The associated benefits have little to do with
demand response, and are related to administrative improvements in the areas of meter
reading, dis/re-connection, identification of system problems, fraud detection, as well as
increased customer services. Finally, other benefits can also be linked to smart metering
such as CO2 emissions reduction due to first energy savings, as well as more efficient
electricity network operation (reduced technical and commercial losses); these result in
benefits accrued to the whole society.
It is important to note that to obtain full benefits, particularly consumption-related ones,
greater meter functionality is required. Yet, the CBAs show no direct link between cost
and functionality106
. So, asking Member States to give under Option 1 and Option 2 the
entitlement to consumers to request a smart meter with full functionality, or the upgrade
of an existing one, should not pose any disproportionate costs on top of the meter unit
cost. However, the fact that smart meters will end up being rolled out on customer-per
customer basis will not allow reaping in full system-wide benefits or benefits of scale and
will lead to higher per unit cost/benefit ratios.
105
e.g. consumers' participation rate in demand response programmes (time-of-use pricing, etc.), different
consumer engagement strategies (e.g. indirect vs. direct feedback)
106
Report from the Commission "Benchmarking smart metering deployment in the EU-27 with a focus on
electricity" (2014); also confirmed in (i) "Cost benefit analysis of smart metering systems in EU Member
States" (2015) ICCS-NTUA & AD Mercados EMI; and (ii) "Steering the implementation of smart
metering solutions throughout Europe: Final Report" (2014) FP7 project Meter-ON, p.9 and p.11;
http://www.meter-on.eu/file/2014/10/Meter-ON%20Final%20report-%20Oct%202014.pdf
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In those countries where a large-scale roll-out is currently not foreseen and additional
meters are to be installed on customers' request, under Option 1 and Option 2, the total
investment for installing additional meters could – as a first approximation - reach EUR 5
billion by 2030107
for a penetration rate of 81% (compared to 74% in BAU). Half of these
costs for the installation of additional meters could potentially be offset by benefits (for
example lower costs/avoided costs of meter reading and operation, reduced commercial
losses108
) other than those related to demand response109
. As a result, the total cost by
2030 for the installation of these additional meters requested by consumers within the EU
– under Option 1 and Option 2 – could go down to EUR 2.47 billion; this corresponds to
an annual cost of EUR 215 million, for a period of 15 years (which is the average
economic lifetime of smart meters) considering a discount rate of 3.5%.
A similar calculation could also be undertaken for Option 3 which will enforce the roll-
out of smart metering in all cases including those where deployment was found to be
non-beneficial according to the national economic assessment of long-term costs and
benefits. In this case, a mandatory roll-out throughout the EU could result in achieving
ultimately a penetration rate of 90% by 2030, and the additional smart metering
installation costs could rise beyond EUR 14 billion110
. This figure represents the
additional cost should a mandatory smart meter roll-out is obligated throughout the EU.
Half of these costs, as argued earlier, could potentially be balanced by benefits linked to
lower costs for meter reading and operation and avoided commercial losses111
.
Consequently, the total additional investment is halved, and the corresponding 'net'
annual cost (for 15 years modelling period, at 3.5% rate) is estimated at EUR 613 million
(per year).
The tables below present the specific costs of additional meters installation, on consumer
request or obligated by legislation (Option 3), calculated per Member State, for the
alternative options considered.
107
The calculation is based on the projected smart metering penetration rate by 2030, and on an average
cost per metering point of EUR 279. This value is worked out from data of Member States' CBAs –
both positive and negative in their outcome - that were analysed under the "Study on cost benefit
analysis of Smart Metering Systems in EU Member States-Final Report" (2015) AF Mercados EMI
and NTUA, and presented on Table 8, p. 26 of the aforementioned report. This average value of EUR
279 per metering point includes the smart meter costs, the information technology cost,
communications costs and costs for the installation of an In-Home Display (in the case of two Member
States cost-benefit analyses).
Note – The accuracy of this calculation depends on the extent that a fixed cost (which is the total cost
for rolling-out to 80% of population) can be proportionately shared, and accordingly deployed to
derive the 'unit cost', which is then used to estimate, for any penetration rate, the cost of installation of
smart metering.
108
see Figure 4, page 34 of the "Study on cost benefit analysis of Smart Metering Systems in EU Member
States-Final Report" (2015) AF Mercados EMI and NTUA.
109
"Impact Assessment support Study on downstream flexibility, demand response and smart metering"
(2016) COWI.
110
Idem
111
idem
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Table 5: Overview of estimated costs for additional smart meter installation by
2030, considering options 1 and 2
BAU=Option 0 Option 1, Option 2
Country
Metering
points
Smart meter
penetration rate
by 2030
Additional meters
by 2030
(compared to BAU)
Indicative cost
(EUR million)
by 2030
Austria 5,700,000 95% - -
Belgium 5,975,000 0% 40% 667
Bulgaria 4,000,000 0% 40% 446
Croatia 2,500,000 0% 40% 279
Cyprus 450,000 0% 40% 50
Czech Republic 5,700,000 0% 40% 636
Denmark 3,280,000 100% - -
Estonia 709,000 100% - -
Finland 3,300,000 100% - -
France 35,000,000 95% - -
Germany 47,900,000 31% 10% 1,270
Greece 7,000,000 80% - -
Hungary 4,063,366 0% 40% 453
Ireland 2,200,000 100% - -
Italy 36,700,000 99% - -
Latvia 1,089,109 95% - -
Lithuania 1,600,000 0% 40% 179
Luxembourg 260,000 95% - -
Malta 260,000 100% - -
Netherlands 7,600,000 100% - -
Poland 16,500,000 100% - -
Portugal 6,500,000 0% 40% 725
Romania 9,000,000 100% - -
Slovakia 2,625,000 23% 17% 125
Slovenia 1,000,000 0% 40% 112
Spain 27,768,258 100% - -
Sweden 5,200,000 100% - -
UK 32,940,000 100% - -
TOTAL 276,819,733 74% 7% 4,942
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
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Table 6: Overview of estimated costs for additional smart meter installation by 2030
considering Option 3
BAU=Option 0 Option 3
Country
Metering
points
Smart meter
penetration rate
by 2030
Additional meters
by 2030
(compared to BAU)
Indicative cost
(EUR million)
by 2030
Austria 5,700,000 95% - -
Belgium 5,975,000 0% 80% 1334
Bulgaria 4,000,000 0% 80% 893
Croatia 2,500,000 0% 80% 558
Cyprus 450,000 0% 80% 100
Czech Republic 5,700,000 0% 80% 1272
Denmark 3,280,000 100% - -
Estonia 709,000 100% - -
Finland 3,300,000 100% - -
France 35,000,000 95% - -
Germany 47,900,000 31% 49% 6,615
Greece 7,000,000 80% - -
Hungary 4,063,366 0% 80% 907
Ireland 2,200,000 100% - -
Italy 36,700,000 99% - -
Latvia 1,089,109 95% - -
Lithuania 1,600,000 0% 80% 357
Luxembourg 260,000 95% - -
Malta 260,000 100% - -
Netherlands 7,600,000 100% - -
Poland 16,500,000 100% - -
Portugal 6,500,000 0% 80% 1451
Romania 9,000,000 100% - -
Slovakia 2,625,000 23% 57% 417
Slovenia 1,000,000 0% 80% 223
Spain 27,768,258 100% - -
Sweden 5,200,000 100% - -
UK 32,940,000 100% - -
TOTAL 276,819,733 74% 16% 14,127
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
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Table 7: Overview of estimated 'net' yearly costs for additional smart meter
installation by 2030 considering all alternative options
BAU = Option
0
Option 1, Option 2 Option 3
2030
Smart meter
(penetration rate)
74% 81% 90%
Additional 'net' cost
(considering 15 years,
at 3.5%)
EUR 215
million/year
EUR 613
million/year
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Cost of demand response
To make demand response and its benefits possible, certain investments in the system are
necessary and operational costs will incur. For the activation costs of demand response
three classes are defined:
Table 8: Overview of cost components for demand response
Parameter Cost component Unit
Variable costs
Costs for loss of production, inconvenience costs,
storage losses
EUR/kWh
Annual fixed costs Information costs, transaction costs, control costs EUR/kW
Investment costs
Installation of measurement-equipment, automatic
measurement for control, communication equipment
EUR/kW
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Variable costs for demand response are the costs incurred at the consumer for offering
demand response. In case of load shifting these costs are considered to be zero since the
lost output can be produced later. However, it is possible that demand response causes
additional costs for inconvenience or efficiency losses due to partial load operations,
however these costs are expected to be minor and not possible to quantify and are
therefore not considered in this analysis.
The annual fixed costs are incurred on a regular basis and are not related to the actual
use of demand response. Predominantly, these costs relate to administration and to
incentivise consumers for demand response. This analysis only focusses on the system
costs, therefore the annual fixed costs are assumed zero.
Investment costs are incurred once the demand response potential is activated. Costs of
this type include
- Investments in communication equipment both at the consumer side as in the
grid. This enables remote sending of instructions to the consumers who then can
provide demand response.
- Investments in control equipment are needed to carry out load reductions
automatically. With control equipment it is possible to provide demand response
upon receipt of a signal.
- Metering equipment is required to be able to verify that the load reduction is
achieved.
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At the moment there is relatively little information available of these investment costs for
demand response. Per consumer type, the following assumptions were made:
- Industrial consumers often already have equipment installed that can activate
demand response. On average, it is however assumed that a very small investment
is still required. According to available literature112
, the investments are estimated
to be 1 EUR/kW.
- To enable demand response for residential consumers, smart appliances must be
installed. This means the costs of appliances will be higher. Currently, most new
appliances already have an electronic controller which can make the appliance
“smart”. However, the appliance also has to be equipped with a communication
module, which will typically be either a power line communication (PLC) or a
wireless module (such as WLAN or ZigBee). It is assumed that due to mass
production of smart appliances in the future, the additional costs will be between
1.70 EUR and 3.30 EUR for all appliances that enable smart operation.
Furthermore, costs incur for the smart appliance to communicate with a central
gateway in a building. This can be integrated into a smart meter or can be offered
as a separate device. The gateway enables communication between the residential
consumer and an external load manager or aggregator. The link between the
appliances and the gateway (power line or wireless communication) does not
require the installation of additional wires. Small additional costs can be assumed
due to electricity consumption as a result of standby mode of smart appliances.
This is assumed to increase the electricity consumption of the appliance between
0.1% and 2%.
- For commercial consumers, the costs for demand response are not available in
the literature. Therefore, the costs are derived from the costs of demand response
for residential consumers. Because the electricity consumption of commercial
consumers is on average higher than the electricity consumption of residential
consumers, more load can be shifted. As a result, investments are lower per
kW/year. An assumption is made that the costs for commercial consumers will be
a factor 6 lower.
In the graph below, the costs of demand response are visualized per Option. As can be
seen, the costs are mostly related to the residential sector. This is a result of the higher
price per kW that is required to activate demand response.
112
"Quantifying the costs of demand response for industrial business" (2013) Anna Gruber, Serafin von
Roon
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Graph 3: Costs of demand response in 2030 – comparison of options
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Benefits of demand response
Demand response is expected to decrease the peak demand and thereby the maximum
needed back-up capacity in the electricity market. The value of a decrease in back-up
capacity is expressed as a decrease in yearly CAPEX and fixed OPEX as a function of
installed capacity. Demand response also diminishes variable OPEX. When residual
electricity demand113
is averaged (flattened) by demand response, less back-up power
needs to be generated by back-up units high in the merit order, and the variable costs of
electricity generation will be reduced. Together the decrease in fixed and variable costs
determine the estimated value of a demand response option in the electricity market.
Table 9: benefit of demand response for reduced back-up capacity in 2030
BAU Option 1 Option 2 Option 3
Total demand response
potential 2030 (GW)
34.4 36.8 52.4 57.1
Total Value demand
response (million
EUR/y)
3517 3772 4588 4736
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
In the distribution grids, demand response options can be deployed to reduce the peak,
and thereby the required capacity, in the distribution and transmission networks. These
benefits are reflected in a lower required investment in these grids. The benefits shown in
the column ‘distribution and transmission’ in the table below are estimated based on
existing literature on this topic in combination with the calculations of the overall
113
Residual demand is the demand that remains after subtracting intermittent sources like solar and wind.
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possible peak reduction as calculated for the system level. It is shown in modelling
exercises that to a large extent peak reduction at the system simultaneously reduces peaks
in the distribution grids. This makes this peak demand reduction a good starting point for
estimating the savings in the grids.
To estimate the savings per kW of peak capacity reduced, one needs to distinguish
between demand connected on the lower voltage and higher voltage grids. The savings
on the higher voltage are lower because only investments in transmission can be avoided.
It is assumed that industrial demand is on the higher voltage grids, while domestic and
commercial demand response is connected to the medium or lower voltage grids.
The average savings are used to calculate the savings that are made possible by the peak
reduction. The results are presented in the table below.
Table 10: Benefits of demand response in the distribution and transmission grid
BAU Option 1 Option 2 Option 3
Total peak decrease
2030 (GW)
25.8 28.1 36.4 38.0
Total benefit
demand response in
distribution and
transmission grid
(million EUR/y)
980 1068 1383 1444
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Overall monetary cost and benefits for all Options
On the basis of the costs and benefits as presented above the net benefit of the different
options is calculated as summarised in the table below.
Table 11: Costs and benefits of Options for 2030 (in million EUR/year)
BAU Option 1 Option 2 Option 3
Costs 82 303 322 328
Benefits
Network 980 1068 1383 1444
Generation 3517 3772 4588 4736
Total 4497 4840 5971 6180
Net benefit
(compared to no
demand response)
4415 4537 5649 5852
Net benefit
(compared to BAU)
122 1234 1437
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
Using the approach described above, the net benefits of the alternative Options compared
to BAU amounts to about 120 MEUR/y for Option 1230 MEUR/y for Option 2 and
around 1430 MEUR/y for Option 3. The net benefit includes the estimated savings in
generation and network capacity.
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What is not included in the estimation of the benefits are the possible effects on system
costs, if the independent demand aggregators are free riders not baring any balancing
responsibility and hence risk to activate the demand response in an inefficient way: for
example by bidding in the wholesale market but in the balancing markets where the price
might be higher. This could happen under Option 3 where no compensation between
aggregators and BRPs is foreseen, and hence the aggregators have no incentive to
achieve balance as early as possible in order to improve the overall efficiency.
What is equally not directly included in this calculation are reduced electricity prices in
the wholesale market due to demand response. However, those cost reductions are
indirectly included in the reduced generation costs.
The follow-on or indirect effects depend on how the savings are distributed among the
different actors. In competitive retail markets the major share of these savings will go
into lower electricity bills for the consumers. Lower electricity costs will increase welfare
for the residential consumers and increase competitiveness for industrial and commercial
consumers. However, in less competitive markets suppliers may profit from those price
reductions.
CO₂ emission reductions
Next to the monetary impact also CO₂ reductions can be achieved through a greater
uptake of demand response. Those impacts can add up to additional savings
1.5Mton/year by 2030 compared to the BAU scenario.
Table 12: Impact on CO₂ – reduction in CO₂ emissions in Mton/y
BAU Option 1 Option 2 Option 3
Reduction in CO₂ emissions
in Mton/y
12.4 13.0 12.7 12.4114
Source: "Impact Assessment support Study on downstream flexibility, demand response and smart
metering" (2016) COWI
c. Simplification and/or administrative impact for companies and
consumers
The measures proposed under Option 2 and 3 are designed to reduce market barriers for
new entrants and provide a stable framework for them under which they can operate in
the market. This is a necessity for new entrants who currently face great difficulties
entering the markets as incumbent suppliers do not allow them to engage with their
customers. The removal of such barriers is especially important for start-ups and SMEs
who typically offer innovative energy services such as demand response.
114
For options 2 and 3 the CO2 benefits are less than for option 1, even if their total DR potential is
higher. This can be explained as follows: By applying DR, the peak demand will be diminished and
less power is generated by back-up units high in the merit order (e.g. gas plants). But at the same time
some low demand values will become higher after DR is implemented (we assume the total demand
does not change) and more power is generated by back-up units lower in the merit order (e.g. lignite
plants).
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Equally for consumers all measures are designed to facilitate their access to innovative
products and services. Those measures should reduce the administrative impact for
consumers to get a fully functional smart meter and sign service contracts with third
parties. At the same time the measures also require Member States to clearly define roles
and responsibilities of aggregators which also increases confidence for consumers in their
services and contributes to consume protection.
Moreover, thanks to a wider deployment of smart metering, under options 1, 2, and
particularly Option 3, the distribution system operators will be in a position to lighten
and improve some of their administrative processes linked to meter reading, billing,
dis/reconnection, switching, identification of system problems, commercial losses, while
at the same time offer increased customer services. Furthermore, a wider roll-out of smart
metering would allow TSOs to better calculate, and improve their processes, for
settlements and balancing penalties as the consumption figures can be based on real
consumption data and not only on profiles.
d. Impacts on public administrations
Regarding smart metering, there will be impacts on public administration, namely on
the Member States' competent authorities including the national regulators.
Those 17 Member States that roll-out smart meters will not be affected by provisions on
smart meters, under all options, apart from the obligation to comply with the
recommended functionalities, which they may need to transpose into national legislation.
Similarly, those two Member States that opted for partial roll-out are not expected to face
any major additional impacts from allowing additional consumers to request smart
meters, under Option 1 and 2. However, they will be impacted when enforcing a
mandatory roll-out under Option 3 which will require substantial changes in their
legislation as it currently stands. The remaining Member States that currently do not plan
to install smart metering in their territory will need to establish legislation with technical
and functional requirements for the roll-out – under any of the options – and face some
additional administrative impact for re-evaluating their cost-benefit analyses.
Similarly, additional administrative impact may be created for the national regulatory
authorities (NRAs) for enforcing actions regarding the consumer entitlement to request a
fully functional smart meter. This includes assessing the costs to be borne by the
consumer, and overseeing the process of deployment. At the same time, improved
consumer engagement thanks to smart metering, would make it easier for NRAs to
ensure proper functioning of the national (retail) energy markets.
No additional impact on public administration is expected from facilitating incentive
based demand response as it is just a further specification/guidance on what is already an
obligation under EED.
e. Trade-offs and synergies associated with each option with other foreseen
measures
Promoting a wider-scale deployment of smart metering with fit-for-purpose
functionalities is in line with the Commission's policy objectives namely to put the
consumer at the core of the EU's energy system, given that:
- interoperable smart metering systems, equipped with the right functionalities, and
connectivity to support novel energy services, are considered essential under the
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Energy Union Strategy for bringing tangible benefits to consumers and delivering
the "new deal";
- through smart metering, consumers can clearly experience the internal energy
market working for them based on their preferences/choices, as it:
- enables them to get accurate and frequent feedback on their energy
consumption;
- minimize errors and delays in invoices or in switching;
- maximize their benefits from innovative solutions for consumption
optimization (e.g. via demand response) and from emerging technologies
(such as home automation); and ,
 reduce the costs of the operation and maintenance of energy distribution
infrastructure (ultimately born by consumers through distribution tariffs).
Mandating the minimum functionalities for smart metering will clarify the need to go
beyond the capability of delivering just 'actual time of use' information currently
mentioned in the related provisions of the Energy Efficiency Directive.
Furthermore, the proposed smart metering functionality to collect meter data at intervals
at least equal to the market settlement frequency will support trading and the
harmonisation of balancing markets.
In addition to bringing tangible benefits to consumers, further developing demand
response is fully coherent with the objectives of other priorities in the field of energy
policy as an appropriate market framework for demand response:
- is an enabler for integrating renewables efficiently into the electricity system. It
also contributes to render energy storage and self-consumption viable;
- is a key factor for increasing energy efficiency with savings of final but mainly
primary energy;
- is a key factor in promoting new products in balancing markets where new rules
are being elaborated under the Market Design Initiative to increase competition;
- may help to reduce the need for creating capacity markets and will therefore be
considered under the rules for capacity markets to be proposed under the Market
Design Initiative;
- will be needed to make efficient use of existing networks and thereby is at the
core of the proposal concerning new distribution tariff rules;
- will likely trigger the deployment of smart homes and smart buildings
technologies while these will vice-versa increase the interest of residential and
commercial consumers in participating in demand response programmes. This
deployment is foreseen to be supported by measures to be adopted under the
Ecodesign/Energy Labelling Framework and by new approaches for smart
buildings to be proposed in the context of the review of the EPBD in 2016.
f. Uncertainty in the key findings and conclusions and how these might
affect the choice of the preferred option
The analysis on smart metering systems and especially demand response contains a lot of
uncertainty. For smart metering systems detailed national cost-benefit analyses have been
carried out in 2012. However, the underlying assumptions especially with regard to
technology costs that are significantly decreasing may change over time. Also the
potential benefits in terms of system and consumer benefits are subject to change
depending on technology development, the further integration of decentralised renewable
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energy generation and upcoming offers for consumers taking part in demand response
schemes. Considering the above it is not unlikely that currently the costs for smart
metering are over- and the benefits under-estimated in some national cost-benefit
analyses.
For incentive based demand response the uncertainty is even greater. Relatively good
estimates can be made about the theoretical potential of demand response (see chapter 2
of this annex) where most of the theoretical potential lies with the residential sector.
However, the technical and economic potential in the residential sector depends on a
number of external factors that are hard to quantify:
- The willingness for residential consumers to engage in demand response. Pilot
projects have proven that consumers do engage in the market and adjust their
consumption if the incentives are right. These incentives are not always monetary
but can also be related to access to advanced information or energy managing
tools. However, it is impossible to transfer the results of pilots with engaged
consumers to the broad majority of consumers;
- The uptake of heat pumps and electric vehicles that provide considerable shift-
able load will most probably determine if a huge number of residential consumers
will engage in demand response schemes. However, the uptake of those
technologies is yet uncertain;
- Experiences from the Nordic market are not easily transferable to all EU markets
as the shifting potential in Finland is relatively high due to e.g. electric heating;
- Experiences from the US market are equally not easily transferable to Europe as
the US market design is different. Furthermore wholesale peak prices are higher
and more frequent than in Europe. Hence, the economic value of demand
response in the US is higher than in the Europe.
The above indicates that the amount of the monetary benefits under the different options
is rather uncertain. The figures therefore rather indicate the magnitude of the potential
benefits under the different options.
As outlined earlier in this chapter there is also great uncertainty about the results
calculated for Option 3 in this impact assessment:
- The analysis only covered the EU as a whole and did not look into national
impacts of a mandatory roll-out. It equally assumes the same cost of smart meters
and their roll-out across the EU. Therefore it cannot be excluded that in some
Member States the costs of a mandatory roll-out of smart meters exceeds its
benefits as it was concluded in some national cost-benefit assessments;
- The analysis also did not quantify the potential system impact if independent
aggregators are exempted from financially covering the distortions they induce to
the system, e.g. not having any balancing responsibilities.
Therefore, the results of Option 3 are even more uncertain than under the other Options
and may very well lead to additional system costs and in some Member States to costs
for smart metering systems that are not covered by benefits for the system and/or the
consumer.
The uncertainty about the uptake of demand response does, however, not affect the
assessment of the preferred option. This option (Option 2) does not foresee any enforced
measures on the roll-out of smart meters or on the uptake of demand response. Instead,
all measures foreseen under this option are just enabling consumers to have access to the
right technologies and access to third party service providers. They also foresee to
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improve access of flexibility to the markets. Under those framework conditions it will be
the market that will show to which degree demand response can play a role as a
competitive service. Therefore, Option 2 can be considered as a no regret option.
g. Preferred Option
Flexibility is considered to be instrumental for allowing more renewables into the
European electricity system without having to make large investments in conventional
back-up generation capacity. Therefore, introducing flexibility to the energy system by
accelerating the uptake smart metering systems and of demand response are key elements
for realising the Energy Union's objectives.
All three Options are fully coherent with the objectives of the Energy Union and other
EU policies. The analysis has proven that all options are suited to accelerate the uptake of
smart metering systems and demand response as well as this uptake will lead to
significant system benefits and cost savings.
Option 1 supports the objective of increasing efficiency of the energy system by
introducing smart meters and dynamic pricing contracts. The Third Package included the
promotion of smart meters by requesting Member States to undertake a CBA of smart
meters and where the benefit-cost ratio is positive to roll-out smart meters. The
realisation of Option 1 means also in Member States where there is no general roll-out,
relevant consumers can ask for the smart meter and a dynamic price contract. It hence
provides the framework to allow all consumers to take advantage of the technological
developments. However, while better enabling price based demand is crucial for
incentivising residential consumers to benefit, it is not suited to realise the full benefits
demand response can offer. As such realising Option 1 will only lead to increase total
demand response in Europe by approximately 7% and lead to net benefits of
approximately 120 MEUR/y by 2030 (compared to BAU).
In addition to the measures proposed under Option 1, Option 2 is specifically addressing
incentive-based demand response. Article 15 of the Energy Efficiency Directive already
promotes demand flexibility and in that respect includes requirements for promotion of
demand response. The additional measures in Option 2 are based on the assessment that
in most Member States a complete legal framework for demand response is still missing.
The measures in Option 2 aim at providing this framework by creating fair market access
for independent aggregators and allow flexibility to be traded in organised markets. The
analysis has shown that those measures are indeed suited to increase the uptake of
demand response by approximately 52% which leads to system benefits of approximately
1230 MEUR/y by 2030 (compared to BAU).
Box X: Benefits and risks of dynamic electricity pricing contracts
The preferred option (Option 2) is to provide all consumers the possibility to voluntarily choose to sign up
to a dynamic electricity price contract and to participate in demand response schemes. All consumers will
have equally the right to keep their traditional electricity price contract.
Dynamic electricity prices reflect – to varying degrees – marginal generation costs and thus incentivise
consumers to change their consumption in response to price signals. This reduces peak demand and hence
reduces the price of electricity at the wholesale market. Those price reductions can be passed on to all
consumers. At the same time, suppliers can pass parts of their wholesale price risk on to those consumers
who are on dynamic contracts. Both aspects can explain why, according to the ACER/CEER monitoring
report 2015, on average existing dynamic electricity price offers in Europe are 5% cheaper than the average
offer.
While consumers on dynamic price contracts can realise additional benefits from shifting their
consumption to times of low wholesale prices they also risk to face higher bills in case they are consuming
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during peak hours. Such a risk is deemed to be acceptable if taking this risk is the free choice of the
consumer and if he is informed accurately about the potential risks and benefits of dynamic prices before
signing up to such a contract.
Under Option 3 a mandatory roll-out of smart meters to at least 80% of consumers in all
Member States is included. In addition it is assumed that under this option aggregators do
not have to cover the costs they induce to the system and hence do not pay any
compensation to BRPs. In terms of uptake of demand response (more than 100%
compared to BAU) and overall system benefits (1430 MEUR/y by 2030) this is the most
favourable option. However, there are also other impacts that need to be considered in
this respect:
- This analysis did not take into account national differences in the costs/benefits of
smart meter roll-out but instead average figures were used. This approach does
hence not exclude the possibility that the overall economic impact of a mandatory
smart meter roll can be negative in some Member States as already suggested in
national cost-benefit analyses;
- The exclusion of any compensation mechanism introduces a possibility of
demand aggregators being free riders in the markets and therefore creating
inefficiencies. This is not in line with the EU target model and generally not in
line with creating a level playing field for competition.
Option 2 is considered to be the preferred option, considering that
- the modelling used for this Impact Assessment did not account for national
differences and did not calculate the impacts per Member State;
- national cost-benefit analyses suggests that in some Member States mandatory
roll-out of smart meters yields negative net benefits; and that,
- the overall banning of any financial obligations by independent aggregators may
lead to market distortions with unknown overall impacts.
Subsidiarity
3.1.6.
The options envisage to give consumers the right to a smart meter with all functionalities
and access to dynamic electricity pricing contracts (Option 1) and in addition further
specify the roles and responsibilities of third parties offering demand response services
(Option 2). These actions promote the interests of consumers and ensure a high level of
consumer protection, and have their legal basis in Article 114 of the Treaty and Article
194 (2) TFEU. The policy measures considered under Option 3 can be based on the same
provisions.
Option1
- The principle of subsidiarity is respected and EU action is justified as access to
smart metering systems is fundamental to improving the functioning of the
internal electricity market;
- Ensuring universal consumer rights in the EU electricity markets includes the
right to actively engage in the market. This is only possible if technologies
enabling innovative energy services are available to all consumers across all
Member States.
As stated earlier, for consumers to directly react to price signals on electricity markets,
and enjoy benefits coming from the provision of new energy services and products, they
must have access to both a fit-for-purpose smart metering system as well as an electricity
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supply contract with dynamic prices linked to the spot market. However, today this is
only a reality in the Nordic Member States and Spain. In addition, under current national
smart metering rollout plans till 2020, more than 30% of EU consumers could be
excluded from access to such metering systems. The Commission's objective is to ensure
that consumers have access to all the prerequisites necessary to be rewarded for reacting
to market signals.
This cannot be achieved sufficiently by Member States acting along. Therefore, it is
herein proposed to table provisions that will give each consumer, throughout the EU, the
right to request the installation of, or the upgrade to, a smart meter with all 10
functionalities proposed in the Commission Recommendation on preparations for the
roll-out of smart metering systems115
, while ensuring that consumers fairly contribute to
associated costs. Furthermore, it needs to be ensured that every consumer has the choice
to select a dynamic price contract linked to the prices at the spot market.
Action at EU level is relevant given that the current EU provisions, which leave the roll-
out of smart metering to the Member States' discretion based on the results of their cost-
benefit analysis, led to a fragmented, and even not necessarily functionally suitable in all
cases, deployment of smart metering.
Actions by Member States alone cannot ensure a harmonised level of consumer rights
(right to a smart meter that would enable customers access certain energy services) to the
extent to which under current national smart meter rollout plans for 2020, more than 30%
of EU consumers could be excluded from access to such metering systems. The right to a
smart meter with all the ten recommended functionalities is a precondition for consumers
to access energy services116
that require accurate and frequent billing information such as
demand response or electricity supply contract with dynamic prices linked to the spot
market.
The costs of rolling out smart meters - with all the benefits that this can bring for
consumers, network and energy companies, the energy system as well as society and the
environment more widely - will greatly increase if the economies of scale of the EU's
internal market are not properly leveraged. Regional differences have already risen with
respect to functionality and interoperability of the systems being rolled out, which may
result in set-ups that are not necessarily interoperable at national level, or within the EU.
This adds complexity and costs to those, be it for instance energy services/product
developers or aggregators, who would like to trade in different European countries and
optimise their business model. It points to the need to harmonise to a certain extent
system requirements and functionalities of smart electricity meters.
In the context of completing the EU's internal electricity market and making retail work
also for consumers, it is highly relevant to ensure at EU level a degree of consistency and
alignment, as well as gain momentum, in the deployment and use of smart metering
throughout Europe. Furthermore, ability to access novel energy services and products
115
For example, provide readings directly to the customer and any third party designated by the
consumer, include advance tariff structures, time-of-use prices and remote tariff control, provide
secure data communications, etc. These also carry a host of other benefits such as improved consumer
information, enabling self-generation to be rewarded, and delivering flexibility to the system.
116
e.g. demand response, self-consumption, self-generation
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should be indiscriminately offered to all EU citizens. This is what this action – giving the
right to request the installation of, or the upgrade to, a smart meter - is meant to deliver.
Such an action will eliminate ambiguities and strengthen the existing provisions, in order
to give certainty to those planning to invest, and ensure that smart metering roll-outs
move in the right direction, and regain EU added-value, by namely (i) safeguarding
common functionality and sharing best practices; (ii)ensuring coherence, interoperability,
synergies, and economies of scale, boosting competitiveness of European industry (both
in manufacturing and in energy services and product provision), and (iii) ultimately
delivering the right conditions for the internal market benefits to reach also consumers
across the EU.
Option 2
EU intervention can be justified for several reasons, among them are:
- To improve the proper functioning of the internal market and avoid the distortion
of competition in the field of retail energy services and hence fully enable
demand response
- To empower consumers by enabling them to take advantage of the well-
functioning retail energy markets by easily accessing demand response services
under transparent and fair conditions.
Divergent national approaches related to the development of demand response services,
or the lack thereof, led to different national regulatory frameworks, raising barriers to
entry across borders to demand response aggregators. This initiative complies with the
principle of subsidiarity, as Member States on their own initiative would not be able to
remove the barriers that exist between national legislations to independent demand
response service-providers and to create a level playing field for them.
Each Member State individually would not be able to ensure the overall coherence of its
legislation with other Member States' legislations. This is why an initiative at EU level is
necessary. It will reduce costs for businesses as they will no longer have to face different
national regimes. It will create legal certainty for businesses which want to provide
demand response services in other Member States. Common rules are also crucial when
e.g. balancing markets will be opened for cross-border trade of flexibility.
Moreover, the present initiative will add value to other measures in the Market Design
Initiative. Other measures aimed at empowering customers, such as right to a smart meter
and to a dynamic ricing contract, will create new opportunities for European consumers
and energy service companies. These opportunities can only be exploited to their
maximum extent if they are completed by an initiative on addressing market barriers to
aggregators, so that they are able to provide customers with access to demand response
services.
Action from Member States alone is likely to result in different sets of rules, which may
undermine or create new obstacles to the proper functioning of the internal market and
create unequal levels of consumer rights in the EU. For example, a framework for
demand response for households is currently being developed in France, while in other
Member States there are currently no established rules for demand response aggregators
targeting household consumers. Common standards at EU level are therefore necessary
to promote efficient and competitive conditions in the retail energy sector for the benefit
of EU consumers and businesses.
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An initiative at EU level would ensure that consumers in all Member States would
benefit from demand response services under harmonised conditions. It would also help
removing entry barriers for new service providers (aggregators), including cross-border,
therefore stimulating economies of scale and setting the basis for developing flexibility
markets at regional level. Such services have a cross-border development potential (e. g.
Energy Pool is already active in more than one EU Member States – France, UK).
Option 3
The same arguments to justify EU action as for Option 1 and 2 can be used for the policy
measures under Option 3. However, what concerns smart metering there could be doubts
that a mandatory roll-out of smart meters with all recommended 10 functionalities
conforms to the principles of subsidiarity and proportionality. This is especially relevant
as Member States have already conducted national cost-benefit analyses on smart meter
roll-out. In 11 Member States those CBAs have unveiled that under current conditions
the costs of a roll-out exceed the benefits. In the Commission's analyses no evidence has
been found that those national CBAs or their underlying assumptions could be contested
or that economies of scale realised by a European roll-out would render the roll-out
economically viable. Hence, a mandatory roll-out would effectively impose undue costs
on those Member States where the CBAs have been negative. However, the underlying
assumptions of those CBAs are likely to change over time with technology cost expected
to decrease which may lead to viable roll-outs in the near future.
The principle of proportionality may equally be contested for strict harmonisation of the
legislative framework for independent aggregators and demand response. A certain
degree of freedom for Member States to design the framework for demand response
according to the national design of the markets may indeed have a similar impact than
fully harmonised rules.
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Stakeholders' opinions
3.1.7.
Outcome of the public consultation
Result of public consultation Energy Market Design
The consultation on the market design contained one question on demand response:
"Where do you see the main obstacles that should be tackled to kick-start demand
response (e.g. insufficient flexible prices, (regulatory) barriers for aggregators /
customers, lack of access to smart home technologies, no obligation to offer the
possibility for end customers to participate in the balancing market through a
demand response scheme, etc.)?"
Many stakeholders identified a lack of dynamic pricing (more flexible consumer prices,
reflecting the actual supply and demand of electricity) as one of the main obstacles to
kick-starting demand side response, along with the distortion of retail prices by
taxes/levies and price regulation. Other factors include market rules that discriminate
consumers or aggregators who want to offer demand response, network tariff structures
that are not adapted to demand response and the slow roll-out of smart metering. Some
stakeholders underline that demand response should be purely market driven, where the
potential is greater for industrial customers than for residential customers. Many replies
point at specific regulatory barriers to demand response, primarily with regards to the
lack of a standardised and harmonised framework for demand response (e.g. operation
and settlement). 117
In total, eleven Member States responded to the question with ten putting specific
emphasis on the need for effective price signals that reflect price developments at the
wholesale market and incentivise consumers to adjust their consumption. In addition,
seven Member States highlighted the need for market rules that allow demand response
to participate in wholesale, balancing and capacity markets on equal footing with
generation. Also environmental NGOs have been widely supportive of demand response
stressing the need for demand side measures to efficiently integrate renewables to the
system. Therefore, they call for opening the markets for flexibility. Some organisations
call for intensified R&D in the area and/or support schemes while one organisation also
calls for targets for demand response. However, Member States and other stakeholders
see demand response as a market driven service for which no specific support but fair
market conditions is needed. More detail on the opinion of main stakeholders is
presented under the individual stakeholder organisations.
117
IEA "Re-powering markets" (2016) suggests: Reform of retail pricing is urgently needed to better
reflect the underlying cost level and structure. Current tariff and taxation structures which do not vary
with time can lead to inefficiencies. Investments in distributed resources are not always cost-effective
as bill savings do not properly reflect the avoided costs to the electricity system. The significant
difference in speed between installing solar PV and small-scale storage and building large-scale
power infrastructure can exacerbate this problem."
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Result on public consultation on the Review of Directive 2012/27/EU on Energy
Efficiency
The consultation addressed a number of questions on metering with one specifically
addressing electricity smart meters and hence is immediately relevant to this impact
assessment:
"Do you think that
- the EED requirements regarding smart metering systems for electricity and
natural gas and consumption feedback and
- the common minimum functionalities, for example to provide readings directly to
the customer or to update readings frequently, recommended by the Commission
together provide a sufficient level of harmonisation at EU level? "
37% shared the view that the EED requirements regarding smart metering systems for
electricity and natural gas and consumption feedback and that the common minimum
functionalities recommended by the Commission together provide a sufficient level of
harmonisation at EU level. 36% had no view, and 27% did not think that these provisions
would provide a sufficient level of harmonisation.
Several participants explained that smart meters would have to provide more useful
information to consumers, potentially in 15 minute intervals, or even in real time. Some
also suggested that consumers could receive a notification once every three months with
an overview on whether they are saving energy and hence money, or whether they are
consuming more than would be expected. Yet others noted that the above factors largely
depend on market conditions, and on how providers interact with customers. In general,
many participants shared the view that EU standards should only apply to minimum
ones, as any additional standards could significantly increase the enterprise's complexity.
Additionally, several stated that harmonisation must also take into account acceptance by
citizens. Finally, some also cited evidence that calls the effectiveness of smart meters in
general into question.
Of those 27% who think that the EED requirements regarding smart metering systems for
electricity and natural gas and consumption feedback and the common minimum
functionalities, recommended by the Commission together do not provide a sufficient
level of harmonisation at EU level, 48% share the view that common minimum
functionalities should be the basis for further harmonisation. 31% had no view, and 21%
did not thing that common minimum functionalities should be the basis for further
harmonisation. Some called for additional minimum functional standards to the current
ones, for example, monthly or three monthly electronic feedback for consumers on how
much energy they are savings. Some participants also argued that the interface of smart
meters should be standardised, to facilitate their use. Yet others voiced a shared
perception that standards across the EU would be overly determined by utilities.
More detail on the opinion of main stakeholders is presented under the individual
stakeholder organisations. While among all respondents the views on the need of
additional EU actions was balanced, the opinion of national ministries signal that the
majority of Member States believe that the existing provisions are sufficient. Out of 14
replies from Member States only 2 were of the opinion that more harmonisation on EU
level would be good to ensure that consumers get the full benefit out of smart meters
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while 9 consider that the level of harmonisation provided by existing legislation is
sufficient and 3 do not state a clear opinion.
European Institutions
Council of the European Union, messages from the presidency on electricity market
design and regional cooperation, April 28, 2016, 7876/1/16 REV1
In addition to stakeholders also European Institutions in response to the communications
"Launching the public consultation process on new energy market design" (SWD(2015)
142 final) as well as "Delivering a new deal for consumers" (SWD(2015) 141 final)
clearly highlighting the need for smart metering systems, demand response and the
importance of allowing new market participants (aggregators) to compete in the markets.
European Parliament, Committee on Industry, Research and Energy, Rapporteur:
Werner Langen, DRAFT REPORT on ‘Towards a New Energy Market Design’,
27.1.2016, 2015/2322(INI)
"The future electricity retail markets should ensure access to new market players (such
as aggregators and ESCO’s) on an equal footing and facilitate introduction of innovative
technologies, products and services in order to stimulate competition and growth. It is
important to promote further reduction of energy consumption in the EU and inform and
empower consumers, households as well as industries, as regards possibilities to
participate actively in the energy market and respond to price signals, control their
energy consumption and participate in cost-effective demand response solutions. In this
regard, cost efficient installation of smart meters and relevant data systems are
essential. Barriers that hamper the delivery of demand response services should be
removed."
European Parliament, Committee on Industry, Research and Energy, Rapporteur:
Theresa Griffin, REPORT on delivering a new deal for energy consumers, 28.4.2016,
A8-0161/2016
- "5. Recalls that the ultimate goal should be an economy based on 100%
renewables, which can only be achieved through reducing our energy
consumption, making full use of the ‘energy efficiency first / first fuel’ principle
and prioritising energy savings and demand side measures over the supply side
in order to meet our climate goals…"
- "6.b empower citizens to produce, consume, store or trade their own renewable
energy either individually or collectively, to take energy-saving measures, to
become active participants in the energy market through consumer choice, and to
allow them the possibility of safely and confidently participating in demand
response;"
- "33. Stresses that to incentivise demand response, energy prices must vary
between peak and off-peak periods, and therefore supports the development of
dynamic pricing on an opt-in basis, subject to a thorough assessment of its
impacts on all consumers; stresses the need to deploy technologies that give
price signals which reward flexible consumption, thus making consumers more
responsive; … reminds the Commission that when drafting the upcoming
legislative proposals it should be guaranteed that the introduction of dynamic
pricing is matched by increased information to consumers;
- "37. Emphasises that consumers should have a free choice of aggregators and
energy service companies (ESCOs) independent from suppliers";
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Unlocking demand side response
Committee of the Regions, Opinion of the European Committee of the Regions –
Delivering a New Deal for Energy Consumers, 8 April 2016, ENVE VI -/009
- "3. notes the extremely high number of services and technical solutions that exist
or are currently being developed in the fields of management and demand
response, as well as in the management of decentralised production. The
European Union must ensure that priority is given to encouraging and supporting
the development of these tools, assessing their value and impact, whether
economic, social, environmental or in terms of energy, and monitoring their
usage to make sure that energy is safe, easy and affordable";
- "24. observes that a level playing field should be created for all future players
who generate and supply energy and/or provide new services, in order to enable,
for example, grid flexibility and integration of energy produced by "prosumers"
(including aggregators)";
- "42. reiterates its call to speed-up the development of smart systems at both grid
and producer/consumer level, to optimise the system as a whole, as well as to
introduce smart meters, which are essential to the efficient management of
demand with the active involvement of the consumer";
- "43. calls for the adoption of a strict framework at European level on the
deployment of smart meters and their range of uses and features, whilst
recalling that the aim is to streamline and reduce consumption. In this regard, the
Committee calls for all new technology options to be evaluated prior to adoption,
if they are to be introduced as standard, with regard to their potential energy,
economic, social and environmental impact";
Selected Stakeholder's views
Florence Forum of electricity regulation – Conclusions of 31 meeting on June 13, 2016
The Forum recognises that the development of a holistic EU framework is key to
unlocking the potential of demand response and to enabling it to provide flexibility to the
system. It notes the large convergence of views among stakeholders on how to approach
the regulation of demand response, including:
- The nееd to engage consumers;
- The need to remove existing barriers to market access, including to third party
aggregators;
- The need to make available dynamic market-based pricing;
- The importance of both implicit and explicit demand response; and,
- The need to put in place the required technology.
Regulators (ACER/CEER)
The Agency for the Cooperation of Energy Regulators (ACER) and the Council of the
European Energy Regulators (CEER) both welcomed the Commission's energy market
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Unlocking demand side response
design consultation paper of July 2015, and in particular the reinforced steer towards
cross-border and market-based solutions, and noted its "alignment in thinking" with
their Bridge to 2025 proposals and sharing of "the common aim of establishing liquid,
competitive and integrated energy markets that work for consumers”118
.
They consider that "a well-functioning market is characterised by innovation and a
range of products offered to consumers", which "can be a sign of healthy competition
and innovation in the market". Key features of this new consumer-centric energy market
model advocated by the regulators119
rely on "near real time frequency of smart
metering data for all", and "demand response through flexible consumption". The latter
translates into "availability of time-of-use/hourly metering and different pricing schemes
offers from suppliers and availability of aggregation services from third-party
companies". To assist realising this, CEER amongst other works towards ensuring that
"most customers have a minimum knowledge of the most relevant features for engaging
and trusting the market", access to "empowerment tools" and "a minimum level of
engagement", as well as that the "regulatory framework allows and incentivises the
availability of a range of offers"120
.
CEER when discussing121
implicit, or price-based demand response, it states that
"without smart meters (and optionally in addition other facilitators such as smart
appliances)" and in the absence of dynamic pricing contracts, there are "limited
possibilities for retailers to value demand side flexibility in their portfolio optimisation".
CEER further notes that "access to contracts that directly link the energy component to
wholesale markets with a possible granularity down to hourly-based prices create a
bridge between wholesale and retail markets, incentivising consumers to exploit
opportunities when prices are low and to adjust consumption when prices are high".
Furthermore, CEER affirms that "the availability of smart metering equipment and
systems which allow time-of-use meter readings is a pre-requisite for consumers to be
able to opt into implicit demand response schemes. Smart meters may also enable
explicit demand response services through a dedicated standard interface, either as
mandatory equipment or an option"122
. But for smart meters to be able to deliver this
service, they need to be fit-for-purpose, and therefore equipped with the right
functionalities. CEER notes that "there is a consistency and convergence between the
work of European Energy Regulators and the European Commission regarding smart
118
ACER/CEER common press release "Energy Regulators (ACER/CEER) welcome the market-based
solutions and cross-border focus of the European Commission’s energy market design", 15.07.2015;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/PRESS_RELEASES/201
5/PR-15-07_Joint-CEER-ACER%20PR%20%20-EnergyMarketDesignConsultation_FINAL.pdf
119
CEER presentation at the 12th EU-US Roundtable, 03.05.2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_INTERNATIONAL/EU-
US%20Roundtable/12th_EU-US_Roundtable/12th%20EU-US%20RT_S4-
International_deSuzzoni.pdf
120
idem
121
CEER discussion paper "Scoping of flexible response", 3 May 2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Electrici
ty/2016/C16-FTF-08-04_Scoping_FR-Discussion_paper_3-May-2016.pdf
122 CEER "Position paper on well-functioning retail energy markets", , 14 October 2015;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab5/C15-SC-36-03_V19_Well-functioning_retail_markets.pdf
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Unlocking demand side response
meter functionalities, in particular those which benefit consumers". At the same time,
however, CEER does not consider these elements sufficient for providing the necessary
level of harmonisation across the EU, "the issue being that Member States do not apply
them". Consequently, CEER are in favour of using the "minimum functionalities as a
basis for further harmonisation"123
.
TSOs (ENTSO-E)
ENTSO-E considers that "the development of demand-side response (DSR) should
ensure that demand elasticity is adequately reflected in short-term price building and
long-term investment incentives. DSR can deliver different types of products and
participate in the associated markets with large socio-economic welfare gains"124
.
Furthermore, ENTSO-E notes that "the organisation of, and timely access to, metering
and settlement data which will be made available by smart meters is essential for
facilitating the uptake of DSR"125
. Elaborating on that, ENTSO-E states that the full
potential can be unleashed if the following requirements126
are satisfied, namely:
(i)"price signals need to reveal the value of flexibility" for the electricity system;
(ii)"efficient use of DSR is based on an economic choice between the value of
consumption and the market value of electricity. This choice arises when the consumer is
exposed to variable prices or if the consumer can sell his flexibility on the market,
possibly with the help of an aggregator".
(iii) "access to price information, consumption awareness and DSR activation require
strong consumer involvement, which can be facilitated with automation or by delegating
the DSR process from the consumer to a company";
(iv) "regulatory barriers, when present, need to be removed to unlock full DSR potential,
including barriers related to the relationship between independent aggregators and
suppliers. Any evolution must preserve the efficiency and well-functioning of markets and
their design components, such as the pivotal role of balance responsible parties, their
information needs and balancing incentives. From a TSO perspective, the choice of the
market model results from a trade-off between the imperatives not to increase residual
system imbalance and to facilitate the development of additional resources";
123
CEER Response to European Commission Public Consultation on the Review of the Energy
Efficiency Directive, 29 January 2016;
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab6/C16-CRM-96-04_EC_PC_EED_Response_290116.pdf
124
ENTSO-E policy paper "Market design for demand response", November 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr
_web.pdf
125
ENTSO-E position paper "Towards smarter grids: Developing TSO and DSO roles and interactions
for the benefit of consumers", March 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/150303_ENTS
O-E_Position_Paper_TSO-DSO_interaction.pdf
126
ENTSO-E policy paper "Market design for demand response", November 2015;
https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr
_web.pdf
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Unlocking demand side response
(v)"DSR should develop itself based on viable business cases. Subsidies should remain
limited and clearly identified";
(vi)"Communication and control technologies need to enable DSR for small consumers
and provide guarantees on their reliability".
ENTSO-E also clarifies that "to enable dynamic pricing, settlements must be based on at
least hourly metering values", which means that "Member States must phase out static
consumption profiles, and introduce time-of-stamped (at least hourly) smart meter
readings for consumers"127
.
DSOs (CEDEC, EDSO for Smart Grids, EURELECTRIC, GEODE)
The four DSOs associations appreciate the contribution of demand response towards
achieving EU energy objectives, and recognise the need for active customers
participating in the markets. They state that128
"with the growing uptake of smart grids
and distributed energy connected to Europe’s distribution grids, DSOs are successfully
embracing the ‘digitalisation’ transformation", and are in favour of "the procurement
of flexibility services in an open market context where everyone, including end users, is
welcome to take part.” They have also affirmed in different fora their conviction on the
key role that smart metering plays in delivering that function and the accompanying
benefits, by providing accurate and secure data on energy consumption, while enabling
customers to make smart choices helping them to also save money and energy.
CEDEC
CEDEC considers that129
"in order to implement effective demand-response programmes,
signals about demand and supply need to be received, managed and communicated to the
relevant parties. For this, the development of smart distribution grids is indispensable".
Moreover, "for the development of smart grids, cost-reflective regulatory frameworks
need to be in place… " giving the right incentives, that should amongst others, "allow for
time-differentiated prices, which will give price signals to consumers to shift their
consumption from peak to off-peak times"130
. Such settings are more complex and in fact
"only possible with a smart meter"131
.
127
ENTSO-E "Recommendations to the regulatory framework on retail and wholesale markets"; Input to
EC Market Design Package; 10 June 2016.
128
DSOs Associations' joint event "Innovative DSOs are needed in a Decentralised Energy System",
12.04.2016,
http://www.geode-
eu.org/uploads/GEODE%20Germany/Stellungnahme/2016/0411%20FINAL%20Joint%20PR%20-
%20Innovative%20DSOs%20in%20a%20decentralised%20energy%20system.pdf
129
CEDEC position " on EC Communication - Delivering the internal electricity market and making the
most of public Intervention", December 2013; http://www.cedec.com/files/default/cedec-position-ec-
guidance-package-final.pdf
130
CEDEC publication "Smart grids for smart markets", 2014;
http://www.cedec.com/files/default/cedec_smart_grids_position_paper-2.pdf
131
CEDEC publication "Distribution grid tariff structures for smart grids and smart markets", 2014;
http://www.cedec.com/files/default/cedec%20leaflet%20grid%20tariffs-final-140403-1.pdf
136
Unlocking demand side response
EDSO for Smart Grids
EDSO considers that DSOs are at the core of the energy transformation and have "the
potential to empower consumers to take a more active part in the energy system, for
example, by rolling-out smart meters"132
. Furthermore, EDSO argues that "engaging
consumers will require appropriate incentives and technologies", as well as "clear price
signals", for flexibility markets to develop and demand response to deliver its full
benefits"133
. EDSO notes that incentives for "dynamic tariffs or incentive based demand
response" should be set up "in order for the consumer to make savings by offering
controllable loads to network operators". It also advocates that a "revision of grid tariffs
with time-dependent and site-dependent components or incentive based demand
response, is an essential step towards realising the benefits, as well as for passing on the
costs of flexibility"134
.
Furthermore, EDSO states that "DSOs could make the most of their grid provided that
they are allowed to use system flexibility services"135
. Moreover, "increasing flexibility in
the electricity market (when technically and economically appropriate) would result in a
number of benefits for DSOs, consumers (all grid users) and society as a whole".
However, according to EDSO "this implies that distribution networks are planned
differently, incorporating new risk margins and uncertainty, are not only managed as
they used to be, but rather as networks with enhanced observability, controllability and
interactions with market stakeholders".
Regarding smart metering functionalities, EDSO claims136
that the "EED requirements
and the EC recommendation" on common minimum functionalities "have been useful
in assisting the industry identify the most relevant functionalities for smart meters.
Now that most national deployments are underway or near launch, there is no need for
further action from the European Commission". Furthermore, it notes that "proposing
to further harmonise smart meter systems at this time, beyond the existing EC’s
recommendations on minimum smart metering functionalities, could further delay smart
meter deployment and thus consumers’ access to detailed and accurate information on
their energy consumption".
EURELECTRIC
132
EDSO report "Data Management: The role of Distribution System Operators in managing data", June
2014; http://www.edsoforsmartgrids.eu/wp-content/uploads/public/EDSO-views-on-Data-
Management-June-2014.pdf
133
EDSO report "Flexibility: The role of DSOs in tomorrow’s electricity market", May 2014;
http://www.edsoforsmartgrids.eu/wp-content/uploads/public/EDSO-views-on-Flexibility-FINAL-
May-5th-2014.pdf
134
idem
135
System flexibility services: any service delivered by a market party and procured by DSOs in order to
maximise the security of supply and the quality of service in the most efficient way – Reference:
EDSO report " Flexibility: The role of DSOs in tomorrow’s electricity market", May 2014.
136
EDSO response to the Consultation on the Review of Energy Efficiency Directive, January 2016;
http://www.edsoforsmartgrids.eu/wp-content/uploads/160129_Public-consultation-Energy-Efficiency-
Review_final_EDSO.pdf
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Unlocking demand side response
Eurelectric acknowledges that "demand response will be one of the building blocks of
future wholesale and retail markets", and "the development of innovative demand
response services will empower customers, giving them more choice and more control
over their electricity consumption. Phasing out regulated retail prices and rolling out
smart meters continue to be key prerequisites to advance demand response further"137
.
As Eurelectric explains138
it is "fit-for-purpose smart meters" that are needed and are
"... a key tool to empower consumers". And "…without prejudice to smart meter rollouts
which are already ongoing, it would be important to guarantee that all smart meters
across the EU had a minimum agreed common set of functionalities to make sure that
they contribute to consumer empowerment and efficient retail markets. Basic common
functionalities would include, for example, the possibility of performing remote
operations, the capability to provide actual, close to real-time meter readings to
consumers, or the possibility to support advanced tariff schemes"139
. Furthermore,
Eurelectric supports the position that "smart meters with a reading interval
corresponding to the settlement time period are a technical prerequisite for
participation of users (with aggregated flexibility units) in balancing markets"140
.
To untap the full demand response potential, Eurelectric recommends141
:
(i) "ensuring that the demand response value is market-based in order to avoid any
extra costs to the system, customers and other actors";
(ii) "implementing adequate communication between third party aggregators and
balance Responsible Parties (BRPs)/suppliers to ensure that demand response can take
place effectively";
(iii) "ensuring that BRPs/suppliers are compensated for the energy they inject and that is
re-routed by third party aggregators", and "to this end, third party demand response
aggregators and suppliers agree on the rules of compensation. Changes in market rules
and settlement adjustments could also be implemented. In addition, a clear balance
responsibility of third party aggregators is needed";
(iv) "ensuring that, on a commercial basis, BRPs/suppliers are able to renegotiate
supply contracts to take into account the indirect effects of demand response (e.g.
rebound effects) and consequent impacts on sourcing costs"; and
137
Eurelectric report "Designing fair and equitable market rules for demand response aggregation",
March 2015; http://www.eurelectric.org/media/169872/0310_missing_links_paper_final_ml-2015-
030-0155-01-e.pdf
138
Eurelectric report "The power sector goes digital - Next generation data management for energy
consumers", May 2016;
http://www.eurelectric.org/media/278067/joint_retail_dso_data_report_final_11may_as-2016-030-
0258-01-e.pdf
139
idem
140
Eurelectric report "Flexibility and Aggregation – requirements for their interaction in the market",
January 2014; http://www.eurelectric.org/media/115877/tf_bal-agr_report_final_je_as-2014-030-
0026-01-e.pdf
141
Eurelectric report "Designing fair and equitable market rules for demand response aggregation",
March 2015; http://www.eurelectric.org/media/169872/0310_missing_links_paper_final_ml-2015-
030-0155-01-e.pdf
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Unlocking demand side response
(v) "facilitating demand response aggregation at distribution network level through
information exchange between DSOs, TSOs and aggregators, for example using a
system that reflects network availability".
GEODE
The association for the local energy distributors GEODE identifies the non-wide
deployment of smart metering as one of the main barriers for demand response taking
off, stating that there is "…no demand response and actual consumption data without
smart meters - which are still being rolled-out in many Member States"142
. Furthermore,
it argues that "…demand side flexibility aggregators should have access to balancing
markets on a level playing field with other parties", and that "…the end customer
should participate [in demand response schemes] on a voluntary basis only".
Moreover, even though GEODE recognises the need, as stated in different fora, to ensure
that smart metering systems with the right functionalities are rolled out to support
demand response, it cautions on the making a set of functionalities binding without at
least foreseeing a transition period for implementation. Following a survey that the
association undertook among its members on the use of the common minimum
functionalities for smart metering systems recommended by the Commission, it
acclaimed143
that "… in those countries where the roll-out has just started or is still in a
planning phase, almost all requirements as recommended by the European Commission
are implemented". However it continues, "…if the European Commission is considering
making binding the recommendations on smart meter functionalities […] these should
apply for the next generation of meters to be rolled-out. At least, a sufficient
transitional period should be provided which is as long as the expected lifetime of the
smart metering systems already installed respectively smart metering systems which are
going to be installed in the next years - tenders are currently running or the roll-outs
have recently started with the objective to reach the 2020 target of 80%. Otherwise it
would – once again - require huge investments to be made by DSOs for replacing
existing meters."
Suppliers (Eurelectric)
Suppliers state that "while demand response has been and could continue to be deployed
by suppliers without smart metering or connected appliances, these technologies will
142
GEODE Comments to the European Parliament Draft Report on “Delivering a New Deal for Energy
Consumers",
http://www.geode-
eu.org/uploads/GEODE%20Germany/DOCUMENTS%202016/GEODE%20Final%20Comments%20
-%20EP%20Draft%20Report%20New%20Deal.pdf
143
GEODE Position paper sent to EC services, dated 20/04/2016, entitled: "GEODE Survey – to assess
whether EC common minimum functional requirements for smart metering systems for electricity - EC
Recommendation of 9 March 2012 on preparations for the roll-out of smart metering systems
(2012/148/EU) are implemented by GEODE member companies"
139
Unlocking demand side response
facilitate more advanced dynamic pricing and new demand response services"144
. They
recognise the benefits that the advent of smart metering, smart devices and overall
digitisation of the energy sector will bring in this respect, and how it will change their
interaction with consumers taking into a new level "changing their traditional business
models, based on pure delivery of kilowatt-hours towards becoming full service
providers"145
. Suppliers will "have access to new data sources and tools to communicate
with their customers and better understand their needs". Furthermore, they "…will (also)
be able to provide consumers with information on - and prediction of - their energy
usage and consumption patterns, even breaking it down into close to real-time
information…through extra devices", and enable the delivery to them of "more
personalised offers and services by market players". This includes the proposition of
"innovative demand response or time of use tariffs which contribute to the efficient
operation of the energy system whilst being financially attractive, transparent and
guaranteeing a given level of comfort to consumers through remote steering of
connected appliances."
At the same time, utilities consider that despite their experience in collecting and
processing meter readings, "dealing with more granular data generated by smart grids
and meters will carry a higher level of complexity", while competition in shaping and
trading novel energy products to consumers "will intensify from all sides", including
from new actors. Suppliers welcome the changes that are coming but recognise that they
"will have to proactively find their place in this new ecosystem".
Aggregators (SEDC)
The Smart Energy Demand Coalition (SEDC) advocates that demand-side resources
can play a crucial role in making the transition to a decarbonised energy system efficient
and affordable, and also involving in this empowered energy consumers. SEDC believes
that "a precondition for consumer empowerment is giving them a choice: citizens,
commercial and industrial consumers should be able to opt for the energy services they
prefer, the services they wish to sell, and the service provider they wish to work with.
This includes the choice to valorise the flexibility of their devices and processes on the
market, the choice to self-generate electricity, or the choice for real-time electricity
pricing to adjust parts of their consumption – automated or not – to the variability on the
market and save costs. It also includes the choice to work with their energy supplier as
well as an independent energy service provider such as a demand response aggregator
for different services"146
. For this to happen, SEDC recommends a set of "coherent
measures to remove barriers currently in place and implement a long-term vision for
144
Eurelectric brochure "Everything you always wanted to know about Demand Response", 2015;
http://www.eurelectric.org/media/176935/demand-response-brochure-11-05-final-lr-2015-2501-0002-
01-e.pdf
145
Eurelectric report "The power sector goes digital - Next generation data management for energy
consumers", May 2016;
http://www.eurelectric.org/media/278067/joint_retail_dso_data_report_final_11may_as-2016-030-
0258-01-e.pdf
146
Article by F. Thies SEDC Executive Director appearing under "Guest Corner" in EC DG ENER
Newsletter of May 2016; https://ec.europa.eu/energy/en/energy_newsletter/newsletter-may-2016
140
Unlocking demand side response
consumer engagement"147
, and advises that "the potential of demand-side flexibility (is)
adequately included in all European scenario calculations and planning for
infrastructure developments".
Amongst its recommendations, SEDC lists the following:
(i) "EU rules providing for access for demand-side flexibility to all energy markets
(wholesale, balancing, ancillary services and capacity) on an equal footing with
generation", and enabling "customers … to participate in all markets directly or
through an aggregator";
(ii) "third party aggregators should access all markets without prior agreement of the
respective customer’s energy retailer/Balance Responsible Party"; and "market prices
should reflect the real value of electricity at any moment";
(iii) "any customer should have the right to a smart meter and to choose hourly, and
where applicable quarter-hourly, market pricing; the retailer/BRP should be settled
accordingly";
(iv) "Distribution System Operators should be encouraged to make use of smart
demand-side flexibility solutions offered by market parties for system operations
purposes. Incentive structures should be revised to this end"…, "… network tariffs
should support, rather than hamper the use of demand-side flexibility, and perverse
incentives must be removed".
Consumer Groups
BEUC – the European Consumer Association, advocates that as we are moving towards a
consumer-centric energy market, we need to ensure that we address both old and new
challenges – with the latter being new technologies (smart meters, connected devices,
smart homes), friendly demand-side response and new business models and new market
players. BEUC believes that "increased consumer engagement is an important factor
for the future energy sector. This requires innovative ideas to empower consumers
backed by an appropriate legal framework". Also, "new products and services need to
respond to consumers’ demands rather than risk confusing them further. Moreover, as
new technologies148
make it technically possible to process much more data than as is
current practice in the energy sector, compliance with data protection rules and their
enforcement must be ensured"149
.
BEUC feels that these technologies "in general may offer a larger choice of products
and services as well as more information for consumers, yet the benefits for consumers
are not guaranteed"150
. It clarifies its rationale by noting that "although new
147
SEDC position paper "10 Recommendations for an Efficient European Power Market Design", 2016;
http://www.smartenergydemand.eu/wp-content/uploads/2016/02/SEDC-10-recommendations.pdf
148
E.g. smart meters, varying user interfaces, smart appliances and home automation
149
BEUC website - http://www.beuc.eu/press-media/news-events/energy-union-what-it-consumers
150
BEUC position paper "Building a consumer-centric energy union", July 2015;
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
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Unlocking demand side response
technologies such as smart meters may help those who consume large amounts of
electricity …, smart meters should not be understood as a necessity to achieve energy
savings. Therefore, instead of pushing through this technology, new services (facilitated
by new technologies) or demand response programmes should be based on
understanding market opportunities and consumer outcomes. Consumers should also
have the right to opt out and have their meter operated in dumb mode. A voluntary and
consumer-centred roll-out of smart meters rather than a mandatory one may increase
consumer participation and public support as it facilitates ownership, data protection,
security and cost allocation issues. Moreover, where smart meters are rolled out,
minimum functionalities and interoperability are essential to ensure consumers have
easy access to the information they need to take informed decisions on their
consumption, but this is only the starting point. Further work is needed to build trust and
encourage consumer engagement. Consumers urgently need clear commitments that the
investments to upgrade the infrastructure and the roll-out of smart meters will deliver
benefits to them as well as monitoring and enforcement of these commitments". BEUC
therefore calls for "a solid legal and regulatory framework" "…in order to guarantee that
the roll-out is cost efficient and that costs and benefits are fairly shared among all
stakeholders who benefit from the new technology". At this point BEUC also notes that
" the benefits to DSOs from smart meters in regard to running, surveillance, repairing
and planning the network is often undervalued when setting the share of costs covered by
consumers via their bills".
Regarding demand response, and looking at what the near future can bring to households
in terms of demand response, BEUC states that a "smart demand response scheme" that
can be of interest to consumers should be "transparent (simple and clear offers and
contracts); voluntary; rewarding flexibility and not penalising in-flexibility", "focus(ed)
on consumers' needs and experience"151
. In fact to guarantee consumers can benefit
from demand response, BEUC sees that152
(i) "transparency and comparability are key to the success of new dynamic tariffs";
(ii)it is important to assess "the degree to which consumers will likely rely on automation
to deliver the expected benefits and … how (novel energy) services (could) accommodate
consumers’ lifestyles";
(iii)"regulators should ensure consumers’ flexibility is properly rewarded and that there
are price safeguards when consumers are fully exposed to wholesale market
developments"; and
(iv) calls for the "European Commission to coordinate with Member States and national
regulators a distributional analysis on the impact of time-of-use tariffs on different
social groups and if/how these groups can access the benefits of new deals".
151
BEUC presentation at the EUSEW 2016 event "Engaged customers driving the energy transition",
16.06.2016 - http://eusew.eu/engaged-customers-driving-energy-transition
152
BEUC position paper "Building a consumer-centric energy union", July 2015;
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
142
Unlocking demand side response
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Distribution networks
3.2. Distribution networks
144
Distribution networks
Summary table
3.2.1.
Objective: Enable Distribution System Operators ('DSOs') to locally manage challenges of energy transition in a cost-efficient and sustainable way, without distorting the market.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding on the detail
tasks of DSOs.
- Allow and incentivize DSOs to acquire flexibility services from distributed
energy resources.
- Establish specific conditions under which DSOs should use flexibility, and
ensure the neutrality of DSOs when interacting with the market or consumers.
- Clarify the role of DSOs only in specific tasks such as data management, the
ownership and operation of local storage and electric vehicle charging
infrastructure.
- Establish cooperation between DSOs and TSOs on specific areas, alongside the
creation of a single European DSO entity.
- Allow DSOs to use flexibility under the conditions set in
Option 1.
- Define specific set of tasks (allowed and not allowed) for
DSOs across EU.
- Enforce existing unbundling rules also to DSOs with less
than 100,000 customers (small DSOs).
Pro
Current framework gives more
flexibility to Member States to
accommodate local conditions in their
national measures.
Pro
Use of flexible resources by DSOs will support integration of RES E in distribution
grids in a cost-efficient way.
Measures which ensure neutrality of DSOs and will guarantee that operators do not
take advantage of their monopolistic position in the market.
Pro
Stricter unbundling rules would possibly enhance competition
in distribution systems which are currently exempted from
unbundling requirements.
Under certain condition, stricter unbundling rules would also
be a more robust way to minimizing DSO conflicts of interest
given the broad range of changes to the electricity system, and
the difficulty of anticipating how these changes could lead to
market distortions.
Con
Not all Member States are integrating
required changes in order to support
EU internal energy market and targets.
Con
Effectiveness of measures may still depend on remuneration of DSOs and regulatory
framework at national level.
Con
Uniform unbundling rules across EU would have
disproportionate effects especially for small DSOs.
Possible impacts in terms of ownership, financing and
effectiveness of small DSOs.
A uniform set of tasks for DSOs would not accommodate
local market conditions across EU and different distribution
structures.
Most suitable option(s): Option 1 is the preferred option as it enhances the role of DSOs as active operators and ensures their neutrality without resulting in excess administrative costs.
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Distribution networks
Description of the baseline
3.2.2.
Legal framework
Article 25 ('Tasks of distribution system operators') of the Electricity Directive puts
forward provisions which describe the core tasks of DSOs, as well as, specific
obligations that DSOs have to comply with. Under these provisions, DSOs are mainly
responsible to operate, maintain and develop under economic conditions a secure,
reliable and efficient electricity distribution system.
Except these core tasks, the Electricity Directive sets under Article 25(6) some specific
obligations e.g. in cases where DSOs are responsible for balancing the distribution
system. Moreover, under Article 25(7), DSOs shall consider measures such as energy
efficiency and demand-side management, in order to avoid investing in new capacity.
According to Article 41 of the Electricity Directive Member States are responsible to
define roles and responsibilities for different actors including DSOs. These roles and
responsibilities concern the following areas: contractual arrangements, commitment to
customers, data exchange and settlement rules, data ownership and metering
responsibility.
Article 26 of the Electricity Directive set also unbundling requirements for DSOs similar
to Directive 2003/54/EC (the previous Electricity Directive which was part of the Second
Package). The Electricity Directive sets unbundling requirements in terms of legal form
(legal unbundling) where the DSO is a legally separate entity with its own independent
decision making board, but remains under the same ownership of a vertically integrated
undertaking ('VIU'). Under this form of unbundling it is also required that DSOs
implement functional unbundling where the operational, management and accounting
activities of a DSO are separated from other activities in the VIU. Article 31 of the
Electricity Directive also requires the unbundling of accounts (accounting unbundling)
where the DSO business unit must keep separate accounts for its activities from the rest
of the VIU in order to avoid cross-subsidisation,.
Article 26(4) of the Electricity Directive gives the option to Member States not to apply
the unbundling rules (no legal/functional unbundling) for DSOs with less than 100,000
customers. Only accounting unbundling applies to DSOs below this threshold. Member
States may choose to apply this threshold or not, or to set a lower threshold. Article 26(3)
contains obligations which seek to strengthen regulatory oversight on vertically
integrated undertakings and to mitigate communication and branding confusion.
Assessment of current situation
Electricity distribution differs widely across EU Member States in terms of the number of
DSOs in each country, voltage level of the distribution system, and tasks. According to
CEER153
(data for 24 EU Member States) there is a total of 2,600 electricity DSOs
operating across EU (see figure 1). From these DSOs, 2,347 (around 90% of the total)
fall under the 100,000 rule and according to Article 26(4), for these DSOs, Member
153
"Status Review on the Transposition of Unbundling Requirements for DSOs and Closed Distribution
System Operators" (2013) CEER.
146
Distribution networks
States are not obliged to implement unbundling provisions under Article 26 of the
Electricity Directive.
Figure 1: Number of electricity DSOs per Member State
Source: CEER (2013)
Within the framework of the Electricity Directive, Member States have to determine the
detailed tasks of DSOs. There is number of factors which may affect those tasks such as:
the structure and ownership of electricity distribution (i.e. public/private, municipalities
etc.), development of the electricity sector, size of the DSOs, voltage level of distribution
grid. For instance, in Member States with a high number of DSOs two layers of
distribution systems usually exist, local distribution systems and regional distribution
systems which connect local networks with the transmission network.
According to the Electricity Directive the core tasks of DSOs are to maintain, develop
and operate the distribution network. The Electricity Directive does not allocate other
specific tasks to DSOs such as for instance metering or data management activities. The
more specific activities are left to Member States to decide, according for instance to
Article 41. According to the Electricity Directive DSOs may also perform balancing
activity, this may be the case in some Member States for regional or larger DSOs.
Therefore, as the EU legislation leaves a quite open framework, there is a variety of tasks
for which DSOs are responsible, depending on the Member State where they are
operating. For instance, even in activities such as metering and connection that in the
majority of the Member States is traditionally performed by the DSOs, there are cases
(e.g. UK) where the activity is open to competition.
When it comes to tasks which can be performed both by TSOs and DSOs there is a
mixed picture across the EU. In general, tasks such as dispatching of generation and use
of flexibility resources are part of TSO tasks. In the majority of Member States where
DSOs can be involved in dispatching activities, this is mostly in cases of emergency in
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Distribution networks
order to ensure security of supply. Cases where flexibility resources or interruptible
contracts can be used by DSOs are rather limited154
.
In meeting the 2020 targets and 2030 climate and energy objectives155
, Member States
will have to integrate a high amount of RES with an increasing number of these resources
being variable RES E (wind and solar). A large share of these resources is connected to
distribution grids (low and medium voltage); according to available data156
this number is
estimated to be even higher than 90% in some Member States (e.g. Germany) and over
50% in others (Belgium, UK, France, Ireland, Portugal, and Spain).
Moreover, the electrification of sectors such as transport and heating will introduce new
loads in distribution networks. These elements will create new requirements and
possibilities157
for DSOs, who will have to manage higher peaks in demand while
maintaining quality of service and minimizing network costs.
The degree of the challenge of integrating high amounts of variable RES (VRES) in
networks differs among the Member States. A group of Member States such as for
example Germany, Denmark, Spain, Portugal already have integrated significant
amounts of wind and solar power in the grid and are expecting more moderate growths
rates in VRES capacity going forward to 2030 (see figure 2). The majority of Member
States have integrated a moderate amount of wind and solar power but will experience
higher growth rates of VRES compared to the group with a high VRES ratio. A minority
of Member States have VRES ratios of less than 5% but are expected to have the highest
growth rates going forward to 2030.
154
"Study on tariff design for distribution systems" (2015) AF Mercados, refE, Indra.
155
COM(2014) 15 final "A policy framework for climate and energy in the period from 2020 to 2030".
156
EvolvDSO project (Deliverable 1.1) and other sources.
157
On the one hand EVs and heating/cooling loads will require more network capacity, on the other hand
this kind of loads offer a huge storage potential (i.e. battery and heat storage) which can be coordinated
in order to offer flexibility services to the system.
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Distribution networks
Figure 2: Wind and solar growth rates and ratio to total capacity
Source: Copenhagen Economics, VVA Europe (2016).
Distribution grids will also face an increasing challenge from the integration of new loads
resulting from electric vehicles (EV) penetration and heat pumps. Currently, penetration
rates for electric vehicles are low among the European countries ranging from around
700 cars in Portugal to 44,000 cars in the Netherlands (see table 1). However, the uptake
of electric vehicles is expected to increase by over 50% per year going forward to 2030
in several EU Member States. Germany is expected to have the highest number of
electric vehicles with over 10 million cars in 2030.
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Distribution networks
Table 1: Number of Electric Vehicles in selected countries (2014 – 2030)
Country 2014 2030 (projected) Annual expected
increase
Portugal 743 867,000 55%
Denmark 2,799 436,000 37%
Spain 3,536 4,263,000 56%
Sweden 6,990 517,000 31%
Italy 7,584 6,638,000 53%
UK 21,425 3,735,000 38%
Germany 24,419 10,024,000 46%
France 30,912 5,431,000 38%
Norway 40,887 429,000 16%
Netherlands 43,762 982,000 21%
Source: Copenhagen Economics, VVA Europe (2016).
Cost-effectively adapting to these changes will require DSOs to use flexible distributed
energy resources (e.g. demand response, storage, distributed generation etc.) to manage
local congestion, which will also require enhancing DSO/TSO collaboration. The use of
such flexibility for the operation and planning of the network has the potential to avoid
costly network expansions. For example, it may be significantly cheaper for a DSO to
overcome local network congestion by occasionally procuring demand response services
than to upgrade its entire network infrastructure in an area to be able to accommodate
relatively uncommon demand peaks. This is a pressing issue for the EU in light of the
fact that electricity network costs increased by 18.5% for households and 30% for
industrial consumers between 2008 and 2012158
.
For instance, a study159
conducted for the German distribution networks estimated that
under the current conditions and depending on different scenarios, a considerable
additional overall investment will be required. The study concludes that innovative
planning concepts in conjunction with intelligent technologies considerably reduce the
network expansion requirement160
.
In the majority of Member States presented in table 2, DSOs cannot currently procure
flexibility services partially because there is a lack of a legal framework or because the
services are not covered in the regulated cost base.
158
COM(2014) 21 /2 "Energy prices and costs in Europe"
159
"Moderne Verteilernetze für Deutschland(Verteilernetzstudie)" (2014) E-Bridge, IAEW, OFFIS.
160
According to the study 90% of the capacity of installed renewable energy installations is connected up
to distribution networks. With an overall coverage of 1.7 million kilometres, these networks make up
about 98% of the overall national grid in Germany. An amount of 23 billion euros to 49 billion euros
depending on the scenario must be invested in distribution networks by 2032 for the integration of
renewable energy installations. The combination of innovative planning concepts with intelligent
technologies can halve the investment requirement and reduce by 20% the average supplementary
costs.
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Distribution networks
Table 2: Status Quo on DSOs incentives to procure flexibility services
Procurement of flexibility services Number of Member
States
Member state
DSOs cannot contract flexibility
services
8 FI, FR, IE, IT, PT, EL, NL, ES
DSOs can contract system flexibility
services for constraints management in
certain situations
3 UK, BE, DE
Source: Copenhagen Economics, VVA Europe (2016).
According to EvolvDSO project161
most DSOs surveyed (France, Ireland, Italy, Portugal)
are not able to contract flexibility for congestion management although discussions on
the topic take place in these countries. In Belgium and Germany, DSOs have the
possibility to obtain system flexibility services via the connection and distribution access
contract. These types of contracts provide for instance a reduced network fee in exchange
for the control of the unit.
In Belgium, such contracts apply to new production units requesting connection at HV
and MV grids. The contract allows to temporarily limit the active power of the unit via
distance control. In Germany DSOs offer these "non-firm" access contracts to
controllable thermal loads, i.e. heat pumps and overnight storage heating (EvolvDSO,
2016). Both countries are considering broadening these contracts to also include
flexibility contracts for congestion management under normal operation state and not just
emergency situations (EvolvDSO, 2016).
From data presented in the study by AF Mercados et al (2015) regarding the
responsibility of DSOs in dispatching of embedded generation, use of interruptible
contracts and other sources of flexibility, it is concluded that in most of Member States
where DSOs can be involved in dispatching this is most of the times for coping with
emergency situations (security reasons). In less than 1/3 of the Member States DSOs are
using solutions such as flexibility resources or interruptible contracts in order to address
grid problems.
Deficiencies of current legislation
3.2.3.
According to the conclusions of "Evaluation of the EU's regulatory framework for
electricity market design and consumer protection in the fields of electricity and gas" one
of the main objectives of the Electricity Directive was to improve competition through
better regulation, unbundling and reducing asymmetric information. In general,
unbundling measures contribute to the contestability of the retail market and thus
facilitate market entry by third party suppliers.
161
EvolvDSO (“Development of methodologies and tools for new and evolving DSO roles for efficient
DRES integration in distribution networks”) is an FP7 collaborative project funded by the European
Commission (http://www.evolvdso.eu/Home/About).
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Distribution networks
The risks of less unbundling link to suboptimal switching procedures in order to deter
market entry, competitive advantage which may come from the use of the same brand
name or privileged access to network information, consumption data information and
cross-subsidies.
On the other hand, discrimination for distribution network access appears to be less
relevant than at transmission level, with a possible exception of small generation
connected at distribution level. DSO unbundling is less relevant with respect to cross-
border flows as flows are more local.
CEER finds that in general the implementation of unbundling rules has been
satisfactory162
. Regarding the implementation of the measures, CEER is reporting
problems in the implementation of the provisions related to branding and
communication. The Commission has taken action towards the proper implementation of
the relevant provisions through compliance checks and infringement procedures,
requesting Member States to ensure a clear separation of identity of the supply and
distribution activities within a vertically integrated undertaking.
Some of the factors that may influence and raise the impact of the foreseen risks are the
increased penetration of RES E generation at distribution level and introduction of smart
metering systems.
In terms of effectiveness, the intervention mainly aimed at the unbundling of vertical
integrated distribution companies with the objective to ensure non-discriminatory and
transparent third party access in distribution networks, in order to promote competition in
the energy market. There is no evidence that the intervention within the boundaries of the
unbundling requirements, did not achieve the objective of promoting competition in the
market.
The Electricity Directive leaves it at the discretion of Member States to decide which
level of unbundling will apply for small DSOs (less than 100,000 customers) and the
detailed tasks that DSOs should carry out at a national level. There is a quite diverse
situation across EU Member States when it comes to responsibilities of DSOs across the
EU.
Provisions which aimed to enhance the DSOs position in using demand side management
and energy efficiency measures in planning their networks did not prove to be effective.
Only in few Member States, DSOs are in position to use such tools in order to avoid
costly investments and operate their networks more efficiently.
In terms of relevance, the original objectives of DSO unbundling requirements and the
framework in which Member States can decide on the responsibilities of operators still
correspond to the EU objective of a competitive internal energy market. The
implementation of smart metering systems (wide scale roll-out in 17 Member States) will
generate more granular consumption data and new business opportunities in the retail
market. Moreover, the introduction of more RES E generation at distribution level will
require a more active management of the network from DSOs. Even if the measures
under the Electricity Directive had included to a certain extent these developments the
162 "Status Review on the Implementation of Distribution System Operators’ Unbundling Provisions of the
3rd Energy Package" (2016) CEER.
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Distribution networks
focus of the intervention was not on these new needs that are estimated to grow with the
completion of smart metering systems and the installation of distributed RES E.
In terms of coherence, the measures are fully coherent with the objectives of the internal
energy market. Unbundling provisions for DSOs complement the relevant requirements
for TSOs, by providing a transparent and non-discriminatory framework for third party
access also at retail market level. These provisions are fundamental for the promotion of
competition in the energy market, the entrance of new energy service providers and the
development of new services.
In terms of EU-added value, the requirements on unbundling are fundamental for the
promotion of competition in the internal energy market. Provisions which are relevant to
DSOs have the characteristic of a permanent effect.
Gap analysis
According to the conclusions of the "Evaluation of the EU's regulatory framework for
electricity market design and consumer protection in the fields of electricity and gas"
with the deployment of smart metering systems across EU Member States a large amount
of data will be available to DSOs. This development requires a closer assessment and
consideration of specific measures.
In terms of DSO responsibilities, it is clear that there is a wide variety of roles and tasks
for DSOs across the EU. This situation does not allow for the application of a uniform set
of responsibilities for all DSOs, as such measure would have a disproportionate effect on
DSOs across the EU, based mostly on the variety of distribution voltage levels and
number of connected customers.
It seems however appropriate to enhance the role of DSOs when it comes to additional
tools such as the use of flexible resources in order to improve their efficiency in terms of
costs and quality of service provided to system users. Such measures however could only
be introduced with the parallel introduction of suitable provisions which prohibit DSOs
to take advantage of their monopolistic position in the market by clarifying their role in
specific activities. In the absence of such measures, the DSOs could foreclose the market
and reduce the benefits for the system users, leading to an inefficient allocation of
resources and reduction of social welfare.
Presentation of the options
3.2.4.
Distribution system operators
Under Option 0 (BAU) existing provisions of the Electricity Directive will continue to
apply concerning the tasks of DSOs. In this case Member States are responsible for
deciding on a number of non-core tasks as well as on remuneration of DSOs.
Option 0+ (Non-regulatory approach) was discarded as the existing EU legislative
framework does not directly address flexibility in distribution networks. This needs to be
further codified in law in order to ensure, inter alia, a level playing field for the
achievement of the EU's RES E deployment objectives given new market conditions. In
addition, it is unlikely that voluntary cooperation between Member States would deliver
the desirable policy objectives in this case.
Under Option 1 the objective is to allow the DSOs to procure and use flexibility
services. Introduce specific conditions under which DSOs should procure flexibility in
order to ensure neutrality and enable longer term investments in flexibility. Moreover,
the role of DSOs regarding specific tasks such as data management, ownership and
153
Distribution networks
operation of storage and electric vehicle charging infrastructure will be clarified under
this option. Measures under Option 1 will also seek to establish an enhanced cooperation
between TSOs and DSOs in terms of network operation and planning.
Under Option 2 measures will aim to define specific tasks that DSOs across the EU
should be allowed and not allowed to carry out. The tasks that DSOs should be allowed
to carry out would include their core tasks and tasks where there is no potential
competition, while activities which are open to competition or already forbidden (e.g.
generation or supply) should not be allowed. Also, under this option existing unbundling
rules will apply also to DSOs with less than 100,000 customers (small DSOs), abolishing
the provision of the Electricity Directive which allows Member States to exempt small
DSOs from legal and functional unbundling.
Comparison of the options
3.2.5.
a. The extent to which they would achieve the objectives (effectiveness)
The main objective is to enable DSOs to locally manage challenges of the energy
transition in a cost-efficient and sustainable way, without distorting the market.
In general the current EU framework leaves to Member States the more detailed
identification of the distribution framework at national level in terms of the specific tasks
that DSOs should carry out and the tools available for operating and developing their
grids. However, in light of the major changes the electricity system is undergoing,
Option 0 is likely to be inadequate in ensuring a cost efficient grid operation.
DSOs may in some countries not have access to appropriate tools in order to operate
efficiently, for instance by procuring flexibility from their customers through aggregators
or local markets, while in many countries they are not adequately incentivised through
the remuneration schemes in place to do so. The Electricity Directive requires DSOs to
take into account demand-side management and energy efficiency measures or
distributed generation as well as conventional assets expansion when planning their
networks. However, it is up to Member States (national authorities, NRAs and DSOs) to
ensure that this is carried out. While this option provides an open EU framework for
Member States, it is also likely to lead to national specific frameworks which are not
conducive to the use of demand side flexibility at DSO level.
Moreover, there are different approaches across Member States for the use of demand
side flexibility from DSOs and a lack of market rules under which DSOs shall procure
flexibility services, while there is no clear framework regarding the involvement of DSOs
in activities such as storage or electric vehicle charging infrastructure.
The measures under Option 1 will establish a clear legal basis for allowing DSOs to use
flexibility. Specific measures under this option will also clarify the role of DSOs in
competitive activities such as storage and electric vehicles charging, and set a specific
framework for DSO involvement. Such a regulatory framework should allow different
solutions in order to address specific needs of the network, based on market procedures
(e.g. long-term contracting of flexibility services such as large scale storage). Regarding
the involvement of DSOs in data handling, specific measures under Option 1 will ensure
neutrality of operators (see also Annexe 7.3 of the present annexes to the impact
assessment).
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Distribution networks
DSOs should harness flexibility from grid users without the risk of distorting or
hampering the development under competitive terms of distributed energy services, such
as demand response, storage, supply and generation, through discriminatory practices or
monopolistic behaviour. This Option will reduce the risk of competition distortions
compared to Option 0. By defining a common framework on how DSOs can procure
flexibility and perform specific roles such as involvement in storage, a level playing field
of a certain standard will be ensured across Member States, unlike the situation where
Member States adopt different approaches to this issue. Moreover, cooperation with
TSOs is important as resources which provide flexibility to the system are located in the
distribution system and therefore coordinated operation and exchange of information
between operators will be required.
Effectiveness of this option can be limited by the fact that the differences among
distribution system structures and tasks of DSOs across the EU, will possibly require that
measures at EU level have to remain broad enough in order to accommodate diverse
situations.
Regarding the use of flexibility, the effectiveness of this option also depends on the
implementation in each Member State, as national remuneration schemes are important
in order to provide to DSOs the right incentives to use flexibility and be properly
remunerated (links to options under distribution tariffs and remuneration, see also
Annexe 3.3 of the present annexes to the impact assessment).
Option 2 foresees a uniform framework for DSOs in terms of tasks and level of
unbundling across the EU. The procurement of flexibility from DSOs will be similar to
Option 1.
Stricter unbundling rules for small DSOs may lower the risk for discriminatory behaviour
and result in gains in retail competition. On the other hand, given that DSOs are natural
monopolies, such measures will not fully guarantee the avoidance of the dominant role of
DSOs in procuring flexibility from system users. Therefore, additional measures will be
needed in order to avoid monopolistic behaviour from DSOs which could lead to market
distortions.
The definition of a uniform set of tasks applicable to all DSOs could lead to non-effective
arrangements depending on the different market conditions as such a framework would
not be able to account for the differences between distribution systems across the EU
(e.g. different retail market conditions or structural and technical differences of
distribution systems)163
.
b. Their respective key economic impacts and benefit/cost ratio, cost-effectiveness
(efficiency) & Economic impacts
163
CEER in its public consultation paper "The future role of DSOs" (2014), proposes a set of potential
DSO activities categorized under three broad areas (core activities, 'grey area' activities and forbidden
activities). In its conclusion paper (2015), CEER remarks that there is no single model for what a DSO
can and cannot do, but rather a number of grey areas where DSOs can participate under certain
conditions.
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Distribution networks
Impacts of measures under Option 1 will be highly dependent on the detailed
implementation at national level, as for instance the extent to which DSOs under the
monitoring of the NRA will decide to supplant grid expansions with the use of flexibility
in network planning. The decision of such measures will be made on the basis of the
most beneficial solution for each distribution system taking into account avoided
investments and considering the costs of employing flexible resources.
Curtailment of RES E in grid planning as quantified in the E-Bridge et al (2014) study164
could help reducing the grid expansion requirements caused by new RES E installations
in the future by at least 22% in the higher voltage grid (>110 kV). Those savings of 22%
can be achieved when allowing for 3% curtailment in grid planning. Considered
generation for curtailment are wind and solar power installations larger than 7 kW; that
affects 52% of all installations, whose aggregated capacity accounts for more than 90%
of the total capacity installed. The benefits of curtailment are lower expansion requirements
for the grids, which do not have to be built to accommodate flows corresponding to the
maximum capacity of the connected RES E installations.
Copenhagen Economics, VVA Europe (2016)165
estimate that the total savings at EU
level from avoided distribution grid investments will be in the order of at least EUR 3.5
to 5 billion in yearly investments towards 2030 (table 3). This corresponds to a total of
approximately EUR 50-85 billion accumulated from 2016. In practice, the potential
savings could be significantly higher, to the extent which supply and demand side
flexibility measures can be used in combination rather than each measure in isolation.
Table 3: Avoided grid investments from flexibility
Extra grid investment from increased DG and load growth (EUR billion) yearly at EU
level
11
Savings from demand flexibility alone (percent) 30 - 55
Savings from supply flexibility alone (percent) 44 - 55
Savings from combination of demand and supply flexibility (percentage) At least 30-44
Very conservative estimate of avoided extra grid investments from flexibility yearly
at EU level (EUR billion)
3.5 to 5
Source: Copenhagen Economics, VVA Europe (2016).
McKinsey & Company (2015)166
found that energy storage can absorb a large share of
the power that would otherwise been curtailed even in a scenario with high share of
variable renewable power, and most of the flexibility would be located on the distribution
grid level. Decisions on which source of flexibility is more efficient should be made on
the basis of the specific needs of the network according to transparent, non-
discriminatory and market-based procedures, under close regulatory control.
164
"Moderne Verteilernetze für Deutschland (Verteilernetzstudie)" (2014) E-Bridge, IAEW, OFFIS.
165
"Impact assessment support study on: Policies for DSOs, Distribution Tariffs and Data Handling"
(2016) Copenhagen Economics, VVA Europe..
166
"Commercialisation of energy storage in Europe" (2015) McKinsey & Company.
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Distribution networks
Related measures are expected to create net benefits for the electricity system as they will
lower distribution costs. Moreover, the use of flexibility from distribution system
operators will stimulate the introduction of new services and the market entrance of new
players such as aggregators. Consumers will benefit from lower network tariffs
(reflecting lower distribution costs) and directly by participating in demand response
programmes or other services to the DSO.
The clarification of the EU framework regarding the role of DSOs in specific tasks such
as data handling, storage and electric vehicle charging, is expected to have positive net
benefits for the electricity system and positive economic societal net benefits. The main
reason is that these tasks can be carried out more efficiently by market players rather than
natural monopolies. Measures under this option will allow certain exemptions in cases
where a market is new (e.g. electric vehicles) or where there is no interest from market
parties to invest in such activities.
Option 2 would result in higher costs as small DSOs (serving less than 100,000
customers) would have to implement legal unbundling criteria. Such an option would
lead small DSOs to separate distribution from the supply activity of the VIU and possibly
merge with larger DSOs, resulting in one-off and structural costs which differ per
Member State. On the other hand, main benefits would result from more transparent third
party access which could potentially have positive impacts on competition. Such costs
and benefits are hard to be fully quantified as many parameters and different local
conditions should be taken into account.
c. Simplification and/or administrative impact for companies and consumers
Option 2 for distribution system operators is expected to have high administrative costs
on the concerned energy companies because of the unbundling requirement on small
DSOs (less than 100,000 customers) which is expected to require a restructuring of those
energy companies affected by the measures.
d. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
e. Trade-offs and synergies associated with each option with other foreseen measures
Option 1 for distribution system operators demonstrates multiple synergies with options
under demand response and smart metering. Demand response programmes through
aggregators can provide services to DSOs who wish to use flexibility in network
operation and planning.
f. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
g. Which Option is preferred and why
Option 1 is the preferred option as it demonstrates the higher potential net benefits for
electricity system and society and expected to demonstrate additional benefits compared
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Distribution networks
to Option 0 without resulting in excessive costs for the involved parties. Consumers will
benefit from lower distribution costs and improved competition in the market.
Subsidiarity
3.2.6.
EU has a shared competence with Member States in the field of energy pursuant to
Article 4(1) TFEU. In line with Article 194 of the TFEU, the EU is competent to
establish measures to ensure the functioning of the energy market, ensure security of
supply and promote energy efficiency.
Under the energy transition, distribution grids will have to integrate even higher amounts
of RES E generation, while new technologies and new consumption loads will be
connected to the distribution grid. Distributed generation has the potential directly or
through aggregation to participate in national and cross-border energy markets.
Moreover, other distributed resources such as demand response or energy storage can
participate in various markets and provide ancillary services to the system also with a
cross-border aspect.
Moreover, DSOs should have the ability to integrate new generation and consumption
loads under cost-efficient terms. The access conditions for RES E generation and other
distributed resources shall be transparent and the DSO's role should be neutral in order to
create a level playing field for these resources. As the amount of resources such as RES E
generation, but in the future also other resources such as storage, will increase, the
conditions under which these resources can access the grid and participate in the national
and cross-border energy markets is expected to become more relevant.
The neutrality of DSOs when they are using flexibility to manage local congestion is a
precondition for well-functioning retail market. While electricity distribution can be
considered a local business, harmonised rules ensuring neutrality of DSOs towards other
market actors including new energy services providers create a level playing field for
RES E development across the EU, crucial in achieving the RES E targets, and support
the completion of internal energy market.
Distribution grid issues may affect the development of the internal energy market and
raise concerns over possible discrimination among system users from different Member
States who however have access in the same energy markets. Uncoordinated, fragmented
national policies at distribution level may have indirect negative effects on neighbouring
Member States, and distort the internal market. EU action therefore has significant added
value by ensuring a coherent approach in all Member States.
Stakeholders' opinions
3.2.7.
3.2.7.1. Results of the consultation on the new Energy Market Design
According to the results of the public consultation on a new Energy Market Design167
the
respondents view active distribution system operation, neutral market facilitation and
167
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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Distribution networks
data hub management as possible functions for DSOs. Some stakeholders pointed to a
potential conflict of interests for DSOs in their new role in case they are also active in the
supply business and emphasized that the neutrality of DSOs should be ensured. A large
number of the stakeholders stressed the importance of data protection and privacy, and
consumer's ownership of data. Furthermore, a high number of respondents stressed the
need of specific rules regarding access to data.
Governance rules for DSOs and Models of data handling
Question: "How should governance rules for distribution system operators and access to
metering data be adapted (data handling and ensuring data privacy etc.) in light of
market and technological developments? Are additional provisions on management of
and access by the relevant parties (end-customers, distribution system operators,
transmission system operators, suppliers, third party service providers and regulators) to
the metering data required?"
Summary of findings:
Regulators stress the importance of neutrality in the role of the DSOs as market
facilitators. To achieve this will require to:
- Set out exactly what a neutral market facilitator entails;
- When a DSO should be involved in an activity and when it should not;
- NRAs to provide careful governance, with a focus on driving a convergent
approach across Europe.
Regulators consider that consumers must be guaranteed the ownership and control of
their data. The DSOs, or other data handlers, must ensure the protection of consumers’
data.
IFIEC considers that DSOs should not play the role of market facilitator, the involvement
of a third party is perceived to better support neutrality and a level playing field.
Moreover, coordination of TSOs and DSOs and potentially extended role of DSOs with
respect to congestion management, forecasting, balancing, etc. would require a separate
regulatory framework. However, IFIEC express concerns that some smaller DSOs might
be overstrained by this. Extended roles for DSO should be in the interest of consumers
and only be implemented when it is economically efficient.
EUROCHAMBERS believes that due to different regional and local conditions a one
size fits all approach for governance rules for distribution system operators is not
appropriate. The EU could support Member States by developing guidelines (e.g. on grid
infrastructures and incentive systems).
Most energy industry stakeholders (CEDEC, EDSO, ESMIG, ETP, EUROBAT, EWEA,
GEODE) believe that the role of DSOs should focus on active grid management and
neutral market facilitation. Some respondents state that the current regulatory framework
prevents DSOs from taking on some roles, such as procurer of system flexibility services
and to procure balancing services from third parties, and such barriers should be
eliminated.
Also SEDC envisages that DSOs should be neutral market facilitators where unbundling
is fully implemented. However, in this scenario DSOs should not be active in markets
such as for demand response, as this would undermine their neutrality.
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Distribution networks
3.2.7.2. Public consultation on the Retail Energy Market
According to the results of the 2014 public consultation on the Retail Energy Market168
the majority of the respondents consider that DSOs should carry out tasks such as data
management, balancing of the local grid, including distributed generation and demand
response, and connection of new generation/capacity (e.g. solar panels).
According to the majority of the stakeholders these activities should be carried out under
good regulatory oversight, with sufficient independence from supply activities, while a
clear definition of the role of DSOs (and TSOs), but also of the relationship with
suppliers and consumers, is required.
3.2.7.3. Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31st
EU Electricity Regulatory Forum:
- "The Forum stresses the importance of innovative solutions and active system
management in distribution systems in order to avoid costly investments and raise
efficiencies in system operation. It highlights the need for DSOs to be able to
purchase flexibility services for operation of their systems whilst remaining
neutral market facilitators, as well as the need to further consider the design of
distribution network tariffs to provide appropriate incentives. The Forum
encourages regulators, TSOs and DSOs to work together towards the
development of such solutions as well as to share best practices."
168
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
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Distribution networks
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Distribution network tariffs and DSO remuneration
3.3. Distribution network tariffs and DSO remuneration
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Distribution network tariffs and DSO remuneration
Summary table
3.3.1.
a. Table 1: Remuneration of DSOs
Objective: A performance-based remuneration framework which incentivize DSOs to increase efficiencies in planning and innovative operation of their networks.
Option: 0 Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible on deciding on the detailed
framework for the remuneration of
DSOs.
- Put in place key EU-wide principles and guidance regarding the remuneration of
DSOs, including flexibility services in the cost-base and incentivising efficient
operation and planning of grids.
- Require DSO to prepare and implement multi-annual development plans, and
coordinate with TSOs on such multi-annual development plans.
- Require NRAs to periodically publish a set of common EU performance indicators
that enable the comparison of DSOs performance and the fairness of distribution
tariffs.
Fully harmonize remuneration methodologies for all DSOs
at EU level.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Performance based remuneration will incentivise DSOs to become more cost-efficient
and offer better quality services.
It would support integration of RES E and EU targets.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards regulatory
schemes which incentivize DSOs and
raise efficiencies.
Con
Detailed implementation will still have to be realized at Member State level, which
may reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO remuneration schemes
would not meet the specificities of different distribution
systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting the subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective remuneration schemes and enhancing transparency
requirements
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Distribution network tariffs and DSO remuneration
b. Table 2: Distribution network tariffs
Objective: Distribution tariffs that send accurate price signals to grid users and aim to fair allocation of distribution network costs.
Option: O Option 1 Option 2
BAU
Member States (NRAs) are mainly
responsible for deciding on the
detailed distribution tariffs.
- Impose on NRAs more detailed transparency and comparability requirements for
distribution tariffs methodologies.
- Put in place EU-wide principles and guidance which ensure fair, dynamic, time-
dependent distribution tariffs in order to facilitate the integration of distributed
energy resources and self-consumption.
Harmonization of distribution tariffs across the EU; fully
harmonize distribution tariff structures at EU level for all EU
DSOs, through concrete requirements for NRAs on tariff
setting.
Pro
Current framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
Principles regarding network tariffs will increase efficient use of the system and
ensure a fairer allocation of network costs.
Pro
A harmonized methodology would guarantee the
implementation of specific principles.
Con
Current EU framework provides only
some general principles, and not
specific guidance towards distribution
network tariffs which effectively
allocate costs and accommodate EU
policies.
Con
Detailed implementation will still have to be realized at Member State level, which
may reduce effectiveness of measures in some cases.
Con
A complete harmonisation of DSO structures would not meet
the specificities of different distribution systems.
Therefore, such an option would possibly have
disproportionate effects while not meeting the subsidiarity
principle.
Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective distribution network tariffs and enhancing transparency
requirements
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Distribution network tariffs and DSO remuneration
Description of the baseline
3.3.2.
Legal framework
According to Article 37(1) of the Electricity Directive, National Regulatory Authorities
(NRAs) are responsible for setting or approving distribution tariffs or their
methodologies.
Article 37(6) and Article 37(8) of the Electricity Directive set some more specific
requirements for NRAs on tariff setting procedures and provide general principles. These
principles require tariffs or methodologies to allow the necessary investments in the
networks and ensure viability of the networks. NRAs shall also ensure that operators are
granted appropriate short and long-term incentives to increase efficiencies, foster market
integration and security of supply and support the related research activities.
Assessment of current situation
According to available data169
allowed revenues (remuneration) for DSOs are set or
approved by regulators in the majority of Member States, with the exception of Spain
(ES), where allowed revenues are set by the Government.
In most Member States tariffs are also being set by the national regulator. However in
some countries the responsibilities are shared between the regulator and the DSO, the
regulator mainly defines the rules and approves the tariffs proposed by the DSO. Spain is
the only country where the Government sets the tariffs. Distribution tariffs are published
in all Member States. However, in Spain distribution tariffs are bundled with other tariff
components, covering costs such as renewable generation fees.
There is a wide variety of remuneration schemes and tariff structures across the EU,
which partly reflects the different situations and local conditions in Member States. With
the exception of the UK, current incentive‐based regulatory schemes place little emphasis
on the output delivered by the distributor, but for quality of service schemes. Moreover,
the following conclusions can be derived from the assessment of the current regulatory
regimes across the EU:
- Typically DSOs are not exposed to volume risk and to the risk that their
investment turns out to be less useful than expected when they were decided, for
example because of lower than expected demand.
- Revenue setting mechanisms based on benchmarking are implemented in
countries where the distribution sector is highly fragmented.
- Regulators and stakeholders are generally less involved in the decision‐making
process on distribution network development, as compared to transmission.
- Traditional tariff structures reflect a situation of limited availability of
information on each consumer’s responsibility in causing distribution costs and
are also affected by affordability and fairness considerations.
169
"Study on tariff design for distribution systems" (2015) AF Mercados, refE, Indra..
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Distribution network tariffs and DSO remuneration
- In most countries, the share of distribution revenues from tariff components based
on energy is large, resulting in an asymmetry between the structure of distribution
costs (mostly fixed) and the way they are charged to consumers.
- In the electricity sector the energy tariff component applied to households
represent on average 69% of the total network charge. This practice is common in
most countries apart from three (The Netherlands, Spain and Sweden) where the
energy charge weights between 21% and 0%.
- In the case of industrial customers the weight of the energy component is still
dominant (around 60% for both small and large industrial clients) but there is
more variability among countries and the corresponding weight ranges between
13% and 100%.
The current distribution tariff structures have been inherited from previous regulatory
regimes, when tariff structures were a simple combination of distribution and supply
costs, including fixed and variable energy costs, for services provided by a single utility.
The distribution tariff is generally based on the distributed amount of energy,
occasionally in a way that varies across times of the day and across seasons, but only
rarely linked to peak load requirements. Historically, this type of volume based pricing
structure was appropriate, as consumers with high peak load requirements also tended to
be those who consumed most energy. Going forward the total costs on the system, which
are correlated with the size of peak demand, will be less linked to total energy
consumption.
Currently, the majority of DSO revenue is collected through volumetric tariffs, i.e. 69%
of the revenue for household consumers, 54% for small industrial consumers and 58%
for large industrial consumers (table 3). This also shows that most EU Member States
have a two-part tariff with a capacity and/or fixed component and a volumetric element.
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Table 3: Status quo on volumetric and capacity tariffs among Member States
Tariff structure elements Tariff component for
household
consumers
Tariff component
for small industrial
consumers
Tariff component
for large industrial
consumers
Member states where the
volumetric element weights over
50% of the DSO tariff
AT, CY, CZ, FR, DE,
GR, HU, IT, LU, PL,
PT, RO, SK, SI, GB
CY, CZ, FI, FR, DE,
GR, HU, RO, SE,
SK, GB
AT, CY, FI, FR,
GR, HU, PL, RO,
SE, SK, SI, NL, GB
Member states where the
capacity element + fixed charge
weights over 50% of the DSO
tariff
ES, SE, NL
AT, IT, LU, PL, PT,
SI, ES, NL
CZ, DE, IT, LU, PT,
ES
EU capacity element + fixed
component average
31% 46% 42%
EU volumetric element average 69% 54% 58%
Note: Bulgaria and Latvia are not included in the survey, Netherlands has a 100% capacity based
tariff for households and small industrial consumers as the only country in the EU. In DK,
Finland, Luxembourg and Malta time-of-use tariffs are not available for household
customers.
Source: Copenhagen Economics, VVA Europe (2016) based on Mercados (2015) and Eurelectric (2013).
Only 3 Member States (Spain, Sweden and the Netherlands) have a capacity and/or fixed
component that weighs over 50% of distribution tariff for household consumers. The
Netherlands have a 100% capacity based tariff for households and small industrial
consumers as the only country in the EU, while Romania has a 100% volumetric tariff.
Between 6 and 8 Member States apply distribution tariffs where the capacity and fixed
tariff weighs over 50% of the tariff for small and industrial consumers.
In 17 countries a time‐of‐use distribution tariff is applied, typically for non‐residential
consumers and with daily (night/day) or seasonal (winter/summer) structure (Mercados
2015). France has implemented tariffs that can incite demand response by introducing
critical peak pricing. The critical peak pricing is for consumers with a three-phase
connection where up to 21 days a year could be selected with a 24 hours' notice signal.
Table 4: Status quo on time-of-use tariffs in Member States
Tariff elements Number of Member States Member State
Time-of-use tariffs 17
AT, HR, CZ, DK, FI, FR, EE,
GR, IR, LU, LT, MT, PL, PT, SI,
ES, UK
Critical peak pricing 1 FR
“Social tariff element” to cross-
subsidize low income consumer
5 ES, IT, FR, GR, PT
Source: Copenhagen Economics, VVA Europe (2016) based on Mercados (2015) and Eurelectric (2013).
Regarding charges applied to distributed generation there is a split picture among
Member States for which data were available. In 8 Member States, distributed
generation is subject to use of system charges while in 6 Member States no charges are
applied. There is also a diverse situation regarding the connection charges that
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Distribution network tariffs and DSO remuneration
distributed generators have to pay with a wide variety of charging principles (i.e.
shallow, deep, semi-deep or semi-shallow).
Table 5: Connection charges and use of system charges for distributed generation in
Member States
Member State Connection Charge Use of system charge
Austria Deep No
Belgium Shallow Yes
Bulgaria Deep N/A
Croatia N/A N/A
Cyprus N/A N/A
Czech Republic Deep N/A
Denmark Shallow Yes
Estonia Deep N/A
Finland N/A Yes
France Semi-deep No
Germany Shallow No
Greece Shallow N/A
Hungary Semi-shallow N/A
Ireland Shallow No
Italy Shallow Yes
Latvia Deep N/A
Lithuania Semi-shallow N/A
Luxembourg N/A Yes
Malta N/A N/A
Netherlands Shallow Yes
Norway Shallow N/A
Poland Shallow N/A
Portugal Deep No
Romania Semi-deep N/A
Slovakia Deep N/A
Slovenia Shallow N/A
Spain Deep No
Sweden Semi-deep Yes
UK Semi-shallow Yes
Source: THINK report "From distribution networks to Smart distribution systems" (2013).
The above data demonstrate a wide variety of distribution tariff structures for
consumption or generation across EU Member States. This wide variety of tariffs can be
attributed to a certain extent to the different local conditions and costs structures in each
country; however, distribution tariffs do not always follow specific principles or they
introduce different diverse conditions for investments for EU consumers who wish to
invest in new technologies including self-generation.
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Distribution network tariffs and DSO remuneration
It is widely accepted170
that the developments which are taking place in the distribution
systems such as the integration of vast amounts of variable RES E generation or the
integration of new loads (e.g. heat pumps, electric vehicles), require distribution tariffs
which provide the right economic signals for the use and development of the system,
allocate costs in a fair way amongst system users and provide stability for investments
for DSOs and connected infrastructure.
Regarding remuneration schemes, DSOs across EU are not always encouraged through
appropriate regulatory frameworks to choose the most cost-efficient investments and
innovative network solutions. In many EU Member States the current regulation of DSOs
does not always provide the right incentives to efficiently develop and operate the grid,
and to consider new flexible resources in network planning made possible by distributed
energy resources171
.
Moreover, different approaches are applied on how regulatory frameworks stimulate
DSOs to deploy innovative technologies. According to Eurelectric 172
in the majority of
Member States analysed (13 out of 20), the regulatory framework is either neutral or
hampers innovation and R&D173
in distribution systems.
Deficiencies of the current legislation
3.3.3.
The Electricity Directive provides an open framework for NRAs in Member States for
setting distribution network tariffs. The current legislation already provides some
principles on the elements that national regulators should consider when deciding on the
remuneration methodology, the allocation of costs on different system users, tariff
structure etc.
In terms of governance this framework shall continue to exist, as tariff setting is one of
the expertise areas and core tasks of NRAs. However, in the context of the rapid
transformation of the energy system, new generation technologies and new consumption
loads will alter the traditional flows of energy in the system and impact the operation of
distribution and transmission grids. Distribution tariff structures will have to induce an
efficient use of the system, while remuneration schemes have to incentivise DSOs for
efficient operation and planning of their networks. This will require further steps to be
taken in EU legislation in order to create a common basis for the development of a
competitive and open retail market and support the effective integration of RES E
generation and new technologies under equal and fair terms across Member States.
170
See for instance the CEER conclusions paper on "The future role for DSOs" (2015) and the THINK
report "From distribution networks to smart distribution systems: Rethinking the regulation of
European Electricity DSOs" (2013).
171
"From distribution networks to smart distribution systems: Rethinking the regulation of European
Electricity DSOs" (2013) THINK.
172
"Innovation incentives for DSOs – a must in the new energy market development" (2016)
EURELECTRIC.
173
'Research, innovation and competitiveness' has been identified as one of the five dimensions of the
Energy Union strategy (COM(2015) 80 final). In this context, smart grids and smart home technology
are listed in the core priorities in order promote growth and jobs through the energy sector and to
create benefits for the energy consumer.
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Distribution network tariffs and DSO remuneration
CEER174
and ACER175
recognise that the current regulatory frameworks applied in many
Member States may not fully address the new challenges such as the complex electricity
flows caused by small scale generation. Addressing this kind of challenges through the
regulatory framework would require the remuneration of innovative investments and the
introduction of the right incentives for flexible solutions which can contribute in solving
short-term and long-term congestions in the distribution grids176
.
While NRAs have enough flexibility in setting distribution tariff structures which best fit
to their local conditions, often there is a lack of important principles which would lead to
a fair allocation of distribution costs amongst system users or the avoidance of implicit
subsidies amongst system users. Moreover, the right long-term economic signals to
system users which would allow for a more rational development of the network are
often not in place.
The diversity of tariff structures is also creating different conditions for system users
such as RES E generators who directly or indirectly through aggregation can participate
in the energy market. Different regulatory frameworks regarding the access conditions
including distribution tariffs of a variety of energy resources which participate in national
and cross-border energy markets could potentially distort competition in the internal
energy market and negatively affect the level of investment in RES E and new
technologies.
Therefore, a further clarification of the overarching principles might be necessary
accompanied by measures which ensure the transparency of methodologies used and the
underlying costs. In this context, issues such as fees and tariffs that distributed energy
resources such as storage facilities have to pay would also need to be clarified.
A more detailed guidance to Member States should be decided on the basis of enhancing
further the effectiveness of the distribution network tariff schemes across the EU in order
to incentivise DSOs to raise efficiencies in their networks and to ensure a level playing
field for all system users connected to distribution networks.
Presentation of the options
3.3.4.
Distribution tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
Under Option 0 (BAU) distribution tariffs and remuneration for DSOs will continue to
be set according to the current framework and principles set in the Electricity Directive.
Regulatory authorities set or approve distribution tariffs or methodologies in the
framework of the Third Package.
174
"The future role for DSOs" (2015) CEER.
175
"A Bridge to 2025 Conclusions Paper" (2014) ACER.
176
The need for incentivising grid operators to enable and use flexibility, but also to improve distribution
tariffs in order to incentivise an efficient consumer response, was widely recognised amongst the
members of the Expert Group 3 (EG3) of the Smart Grids Task Force. The full analysis in included in
the 2015 report "Regulatory Recommendations for the Deployment of Flexibility"
(https://ec.europa.eu/energy/sites/ener/files/documents/EG3%20Final%20-%20January%202015.pdf).
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Distribution network tariffs and DSO remuneration
A stronger enforcement and/or voluntary cooperation (Option 0+) has not been
considered as the existing framework does not provide the necessary policy tools and
principles for providing further guidance to Member States, while voluntary cooperation
between Member States could only be used for sharing best-practices.
Under Option 1 in addition to the existing framework, measures on key EU-wide
principles and guidance regarding the remuneration of DSOs, including flexibility
services (e.g. energy storage and demand response) in the cost-base and incentivising
efficient operation and planning of grids will be put in place. EU-wide principles will
also ensure fair, dynamic, time-dependent distribution tariffs in order to facilitate the
integration of distributed energy resources including storage facilities and self-
consumption. Such principles could be further detailed in an implementing act providing
clear guidance to Member States.
Moreover, DSOs will have to prepare and implement multi-annual development plans,
and coordinate with TSOs on such multi-annual development plans.
NRAs in addition to their existing competences will have to periodically publish a set of
common EU performance indicators that enable the comparison of DSOs performance
and the fairness of distribution tariffs. NRAs will also have to implement more detailed
transparency and comparability requirements for distribution tariffs methodologies.
Measures under Option 2 will aim to fully harmonize remuneration methodologies for
all DSOs at EU level, as well as distribution tariffs (e.g. structures and methodologies).
Full harmonization of tariff structures could include the definition of specific tariff
elements (capacity or energy component, fixed charge etc.), but also specific rules on the
allocation of distribution costs to the different tariff elements.
Comparison of the options
3.3.5.
a. The extent to which they would achieve the objectives (effectiveness)
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
The main objective is to achieve distribution tariffs that send accurate price signals to
grid users and aim at a fair allocation of distribution network costs. Regarding
remuneration of DSOs the aim is incentivize DSOs to increase efficiencies in planning
and innovative operation of their networks.
Under Option 0 Member States (NRAs) will continue to set tariffs and remuneration
methodologies according to the framework provided in the Electricity Directive.
However, the current tariff structures and methodologies do not always fulfil the
desirable results under the main objective. The current tariff structure in most Member
States does not sufficiently achieve the economic purpose of network tariffs. For instance
tariffs do not always reflect the costs of the grid from a particular type of behaviour, such
as additional consumption during peak load, or in other instances from beneficial
behaviour, such as charging a storage or electric vehicle to absorb a peak in variable
renewable generation. In several Member States different generation resources face
different tariffs, and therefore create an uneven playing field between resources or
between markets (national or cross-border).
Additionally, Member States are not obliged to provide clear transparency requirements
regarding the costs and methodologies for network tariffs. This creates an information
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Distribution network tariffs and DSO remuneration
asymmetry between various players in the market and the risk of not having a clear and
predictable framework.
Therefore, under this option the development of more advanced and transparent
distribution tariff frameworks is left to Member States, facing the risk that some Member
States will not develop the appropriate regulatory framework without clear guidance.
Moreover, it may also lead to various rules and solutions, which risk not dealing with the
issues of cost reflective use of the grid, or transparent regulatory framework and
appropriate incentives for operators.
Measures under Option 1 aim to enhance the principles of the Electricity Directive for
setting network tariffs in order to provide a clearer guidance to Member States in
achieving the policy objectives. These principles will set a framework for fair, dynamic
and time-dependent tariffs which fairly reflect costs and facilitate the integration of
distributed energy resources.
This option could be more effective if in addition to measures to be included in the
Directive, more specific guidance will be provided to Member States through
implementing legislation. A more detailed guidance would set the framework under
which NRAs can establish fair and cost reflective tariffs and incentivise DSOs to raise
efficiencies in their networks.
Specific transparency requirements are expected to effectively enhance the level of
transparency regarding the underlying costs in tariff setting and the detailed
methodologies.
A full harmonization of distribution tariffs structures and methodologies under Option 2
would require a uniform structure of tariffs across EU distribution networks. This option
is deemed as not effective in capturing different cost structures and various differences in
terms of technical characteristics which determine the final tariff structure. For instance,
the possible definition of specific tariff structures under this option would imply the
introduction of specific rules for the allocation of distribution costs in different tariff
components (e.g. capacity and energy components); however, a uniform tariff structure
could not accurately reflect the different characteristics of individual distribution
networks and support general policy objectives under diverse energy systems.
This option would reduce flexibility for Member States, as specific tariff elements would
be harmonised at EU level. A potential risk of this Option is that NRAs cannot fully
design distribution tariffs tailored to local needs, as they would be bound to a fully
harmonized tariff framework. Another issue with harmonisation is that a "one-size-fit-
all" framework for distribution tariffs might not exist and this would most probably result
in various inefficiencies.
b. Their respective key economic impacts and benefit/cost ratio, cost-effectiveness
(efficiency) & Economic impacts
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 1)
Under Option 1 Member States will be responsible for the detailed implementation of
distribution network tariffs and remuneration for DSOs. A more detailed guidance from
the Commission with EU-wide principles on tariff setting could enhance the benefits of
this option.
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Distribution network tariffs and DSO remuneration
The adoption of distribution tariffs by NRAs which are cost-reflective and provide
efficient economic signals to system users will result in lower system costs. Moreover,
the introduction of time-dependent distribution tariffs across all Member States would
aim at incentivising demand response, the detailed implementation should be linked to
specific needs of each distribution system.
Results of a 2015 study177
show that a well-defined ToU tariff can indeed provide
benefits in terms of CAPEX and OPEX for the distribution grid. The level of impact
strongly depends on the specific characteristics of the grid and of the load/generation
conditions.
Measures on transparency in tariff setting and distribution costs would increase the
performance of the agents involved in the tariff setting process resulting in an overall
higher societal benefit.
Option 2 could potentially have similar benefits as Option 1; however, if not well
designed, a fully harmonized framework could have negative impacts in some Member
States or particular distribution systems as one particular tariff methodology could not
accommodate the specificities of different distribution systems.
c. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
d. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
e. Which Option is preferred and why?
Distribution network tariffs and remuneration of DSOs (tables 1 and 2 in Section 3.3.1)
Option 1 (both for distribution tariffs and remuneration of DSOs) is the preferred option
as it will improve existing framework and provide to Member States and regulators more
concrete principles and guidance for tariff setting. Multiple benefits are expected for
consumers and resources connected to distribution systems.
Subsidiarity
3.3.6.
EU has a shared competence with Member States in the field of energy pursuant to
Article 4(1) of the Treaty on the Functioning of the European Union (TFEU). In line with
Article 194 of the TFEU, the EU is competent to establish measures to ensure the
functioning of the energy market, ensure security of supply and promote energy
efficiency.
177
"Identifying energy efficiency improvements and saving potential in energy networks, including
analysis of the value of demand response" (2015) Tractebel, Ecofys.
173
Distribution network tariffs and DSO remuneration
Under the energy transition distribution grids will have to integrate even higher amounts
of RES E generation, while new technologies and new consumption loads will be
connected to the distribution grid. Distributed generation has the potential directly or
through aggregation to participate in national and cross-border energy markets.
Moreover, other distributed resources such as demand response or energy storage can
participate in various markets and provide ancillary services to the system also with a
cross-border aspect.
The access conditions, including distribution tariffs, for suppliers, aggregators, RES E
generation, energy storage etc. shall be transparent and ensure a level playing field. As
the amount of resources such as RES E generation, but in the future also other resources
such as storage, will increase, the conditions under which these resources can access the
grid and participate in the national and cross-border energy markets is expected to
become more relevant.
Putting in place EU-wide principles on remuneration schemes will contribute in lowering
the costs of distribution and support the deployment of flexibility services across the EU.
Incentivising efficient operation and planning of distribution networks will result to an
overall reduction of distribution costs which will facilitate the cost-efficient integration of
distributed generation and support the achievement of EU RES targets. Moreover,
through common principles for incentivising research and innovation in distribution
grids, can have positive for European industry and contribute to employment and growth
in the EU.
Distribution tariff issues may affect the development of the internal energy market and
raise concerns over possible discrimination among system users of the same category
(e.g. tariffs applied asymmetrically in border regions). Uncoordinated, fragmented
national policies for distribution tariffs may have indirect negative effects on
neighbouring Member States and distort the internal market, while lack of appropriate
incentives for DSOs may slow down the integration of RES, and the uptake of innovative
technologies and energy services. EU action therefore has significant added value by
ensuring a coherent approach in all Member States.
Stakeholders' opinions
3.3.7.
3.2.7.1. Results of the consultation on the new Energy Market Design
As concerns a European approach on distribution tariffs, the results of the public
consultation on a new Energy Market Design178
were mixed; the usefulness of some
general principles is acknowledged by many stakeholders, while others stress that the
concrete design should generally considered to be subject to national regulation.
Distribution tariffs
Question: "Shall there be a European approach to distribution tariffs? If yes, what
aspects should be covered; for example, framework, tariff components (fixed, capacity vs.
energy, timely or locational differentiation) and treatment of own generation?"
178
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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Distribution network tariffs and DSO remuneration
Summary of findings:
There are split views among the respondents regarding an EU approach to distribution
network tariffs. Some stakeholders (e.g. part of electricity consumers) believe that some
degree of harmonisation across EU would be beneficial and reduce barriers to cross-
border trade. However, only half of them advocate for a full harmonisation (e.g. specific
tariff structures), while the other half is more in favour of EU wide principles.
The electricity industry and few Member States are among those who consider that
setting out common principles at EU level is more advisable than a full harmonised
framework for distribution network tariffs.
On the other hand, regulators, the majority of Member States and some electricity
consumers, do not perceive that a "one fits all" solution is appropriate for distribution
network tariffs.
All stakeholders agree that future tariff design should ensure cost efficiency and a fair
distribution of network costs among grid users. The electricity industry supports the
importance of the capacity, time and location tariff components in order to enhance
network price signals and stimulate flexibility.
Member States:
National governments agree that distribution network tariffs should stimulate efficiency
and be cost-reflective, with the possibility to easily adapt to market developments.
National decisions on tariff structure and components are currently related to the division
of network costs among the different system users and to the national distribution system
characteristics (size and structure of the grid, demand profile of consumer, generation
mix, extent of smart metering, approach to distributed generation), as well as to the
different regulatory frameworks (number and roles of DSOs, national or regional
distribution tariffs). Therefore, the majority of Member States consider that no further
harmonisation of distribution tariffs at EU level is required (e.g. France, Sweden,
Finland, Malta, Czech Republic).
Some national governments are however more open to some common approach at EU
level. The Polish government proposes the possibility of continuous exchange of
regulatory experience between NRAs and information on specific tariff parameters. The
Slovak Republic would consider as beneficial a non-binding ACER recommendation on
a methodology for distribution tariffs for NRAs, which should incentivise innovation
while guaranteeing timely recovery of costs of distribution and efficient allocation of
distribution costs. The Danish government suggests that a common framework would
increase market transparency from a retail market perspective and would be a first step to
harmonisation.
All national governments consider that any European harmonisation or framework for
distribution tariffs should not preclude the differences in national policies nor prevent
experimental tariff structures aiming at fostering demand side response.
Regulators:
Regulators do not perceive that “one size fits all” approach as appropriate for distribution
tariffs. According to them, future tariff designs need to meet the following objectives:
- To encourage efficient use of network assets;
- To minimize the cost of network expansion;
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Distribution network tariffs and DSO remuneration
- To seek a fair distribution of network costs among network users;
- To enhance the security and resilience of existing networks;
- To work as a coherent structure, consistent with other incentives.
Electricity consumers:
Some electricity consumers (BEUC, CEPI) advocate a design of distribution grids tariffs
which encourage flexibility, reflecting the various profiles of demand response operators
(e.g. ranging from industrial production sites to households running their solar PV unit).
They argue that a differentiated set of price signals would incentivise demand side
flexibility, but that distribution tariffs should comply with EU energy policy and that
regulators should have a common understanding of the reward benefits.
Other electricity consumers (CEFIC, IFIEC) believe that harmonising the tariff
methodology and structure would be beneficial and reduce barriers to cross-border trade.
They support a fair distribution of grid costs between grid users and not leading to cost
inefficiencies, and incentives to operators and system users in order to reduce total costs
of the electricity system.
European Aluminium is in favour of a harmonized methodology for grid tariffs for the
power intensive industry based on the properties and the contribution of the power
consumption profile to the transmission system. Such a tariff system must, however, take
into account national differences in grid system and market liquidity and maturity.
On the other hand, EURACOAL, EUROCHAMBERS and Business Europe disagree
with a harmonization approach because it would not take into account the geographic,
environmental, climate and energy infrastructure differences between Member States.
Energy industry:
Most of the stakeholders agree that an EU full harmonization approach to distribution
tariffs is not advisable, while some common EU principles are a more preferable
approach. In particular, EWEA advocates that the Commission should encourage NRAs
in identifying "best practices" rather than imposing a top down harmonisation of
distribution tariffs.
ESMIG, instead, believes that a more uniform approach across the EU would be
beneficial.
A number of the respondents support the importance of the capacity (CEDEC, ENTSO-
E, Eurelectric, ETP, GEODE), time (CEDEC, EASE, ETP, EWEA, GEODE) and
location (CEDEC, ETP, EWEA, ENTSO-E) tariff components in order to enhance the
network price signals and stimulate flexibility.
The energy industry stakeholders consider that network tariffs shall reflect cost-
efficiency and fairness between consumers. They view self-generation as a positive
development, but support that prosumers should contribute to the costs of back-up
generation and grid costs and avoid that other consumers bear the burden of grid costs. In
addition, they support that system charges and other levies linked to policy costs should
not artificially increase the cost of electricity, acting as a bias penalizing consumption.
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Distribution network tariffs and DSO remuneration
Network charges should provide DSOs with the required revenue to ensure that sufficient
network investments are realized and especially investments in smart grids and in
operational expenses improvements.
ESMIG advocates for the consideration of a "performance-based" approach, such that the
DSOs remuneration would be based on the performance of the network rather than the
volume of electricity.
3.2.7.2. Public consultation on the Retail Energy Market
Regarding distribution network tariffs, 34% of the respondents to the 2014 public
consultation on the Retail Energy Market179
consider that European wide principles for
setting distribution network tariffs are needed, while another 34% are neutral and 26%
disagree.
Time-differentiated tariffs are supported by ca 61% of the respondents, while the
majority of stakeholders consider that cost breakdown (78%) and methodology (84%) of
distribution network tariffs should be transparent.
The majority of stakeholders also consider that self-generators/auto-consumers should
contribute to the network costs even if they use the network in a limited way. To this end,
ca 50% of the respondents consider that the further deployment of self-generation with
auto-consumption requires a common approach as far as the contribution to network
costs is concerned.
3.2.7.3. Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31st
EU Electricity Regulatory Forum:
- "The Forum stresses the importance of innovative solutions and active system
management in distribution systems in order to avoid costly investments and raise
efficiencies in system operation. It highlights the need for DSOs to be able to
purchase flexibility services for operation of their systems whilst remaining
neutral market facilitators, as well as the need to further consider the design of
distribution network tariffs to provide appropriate incentives. The Forum
encourages regulators, TSOs and DSOs to work together towards the
development of such solutions as well as to share best practices."
European Parliament resolution of 26 May 2016 on delivering a new deal for energy
consumers (2015/2323(INI)):
"24. Calls for stable, sufficient and cost-effective remuneration schemes to guarantee
investor certainty and increase the take-up of small and medium-scale renewable
energy projects while minimising market distortions; calls, in this context, on Member
States to make full use of de minimis exemptions foreseen by the 2014 state aid
guidelines; believes that grid tariffs and other fees should be transparent and non-
179
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
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Distribution network tariffs and DSO remuneration
discriminatory and should fairly reflect the impact of the consumer on the grid,
avoiding double-charging while guaranteeing sufficient funding for the maintenance
and development of distribution grids; regrets the retroactive changes to renewable
support schemes, as well as the introduction of unfair and punitive taxes or fees which
hinder the continued expansion of self-generation; highlights the importance of well-
designed and future-proof support schemes in order to increase investor certainty and
value for money, and to avoid such changes in the future; stresses that prosumers
providing the grid with storage capacities should be rewarded;"
178
Distribution network tariffs and DSO remuneration
179
Improving the institutional framework
3.4. Improving the institutional framework
180
Improving the institutional framework
Summary Table
3.4.2.
Objective: To adapt the Institutional Framework, in particular ACER's decision-making powers and internal decision-making to the reality of integrated regional markets and the proposals of
the Market Design Initiative, as well as to address the existing and anticipated regulatory gaps in the energy market.
Option 0 Option 1 Option 2
Description
Maintain status quo, taking into account that the implementation
of network codes would bring certain small scale adjustments.
However, the EU institutional framework would continue to be
based on the complementarity of regulation at national and EU-
level.
Adapting the institutional framework to the new
realities of the electricity system and to the
resulting need for additional regional cooperation
as well as to addressing existing and anticipated
regulatory gaps in the energy market.
Providing for more centralised institutional structures with
additional powers and/or responsibilities for the involved
entities.
Pros
Lowest political resistance. Addresses the shortcomings identified and
provides a pragmatic and flexible approach by
combining bottom-up initiatives and top-down
steering of the regulatory oversight.
Addresses the shortcomings identified with limited
coordination requirements for institutional actors.
Cons
The implementation of the Third Package and network codes is
not sufficient to overcome existing shortcomings of the
institutional framework.
Requires strong coordination efforts between all
involved institutional actors.
Significant changes to established institutional processes with
the greatest financial impact and highest political resistance.
Most suitable option(s): Option 1, as it adapts the institutional framework to the new realities of the electricity system by adopting a pragmatic approach in combining bottom-up initiatives
and top-down steering of the regulatory oversight.
181
Improving the institutional framework
Description of the baseline
3.4.1.
The institutional framework currently applicable to the internal energy market is laid out
in the Third Package. It strengthened the powers and independence of national regulatory
authorities (NRAs) and mandated the creation of an Agency for the Cooperation of
Energy Regulators (ACER) and the European Networks of Transmission System
Operators (ENTSOs)180
, with the overarching aim of fostering cooperation amongst
NRAs as well as between transmission system operators (TSOs) at regional and
European level.
Figure 1 below illustrates the key actors in the energy market based on the institutional
framework introduced with the adoption of the Third Package.
Figure 1: Key actors in the energy market institutional framework
Source: European Commission
180
As the current Impact Assessment and the related legislative proposals focus on the European
electricity markets, this Annex focuses on the assessment of the options with regard to the ENTSO for
Electricity (ENTSO-E).
European
Commission
Agency for the Cooperation of
Energy Regulators
(ACER)
European Networks for
Transmission System Operators
for Electricity and for Gas
(ENTSO-E and ENTSOG)
Council of
Ministers
European
Parliament
National regulatory
authorities (NRAs)
Transmission
system operators
(TSOs)
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Improving the institutional framework
With the creation of ACER, the Third Package sought to cover the regulatory gap
concerning electricity and gas cross-border issues. Prior to the adoption of the Third
Package, this regulatory gap had been tackled with the Commission self-regulatory
forums like the Florence (electricity) forum and the Madrid (gas) forum as well as
through the independent regulatory advisory group on electricity and gas set up by the
Commission in 2003, the "European Regulators Group for Electricity and Gas"
(ERGEG). ERGEG's work positively contributed to market integration. However, it was
widely recognised by the sector – and by ERGEG itself – that cooperation between
NRAs should be upgraded and should take place within an EU body with clear
competences and with the power to adopt regulatory decisions.
To this end, the Third Package entrusted ACER with a wide range of tasks and
competences, including:
- promoting cooperation between NRAs;
- participating in the development and implementation of EU-wide network rules
(network codes and guidelines);
- monitoring the implementation of EU-wide 10-year network development plans;
- deciding on cross-border issues if national regulators cannot agree or if they
jointly request ACER to intervene;
- monitoring the functioning of the internal market in electricity and gas; and
- oversight over ENTSOs.
Based on the adoption of subsequent legislation on market transparency181
and trans-
European infrastructures182
ACER has been given additional responsibilities in these
areas.
The Third Package established ACER with the main mission to ensure that regulatory
functions performed by NRAs at national level are properly coordinated at EU level and,
where necessary, completed at EU level. As regards its governance structure183
, ACER
comprises a Director, responsible for representing the Agency, for the day-to-day
management and for tabling proposals for the favourable opinion of the Board of
Regulators184
. ACER's regulatory activities are formed in the Board of Regulators,
composed of senior representatives of the NRAs of the 28 Member States. Its
administrative and budgetary activities fall under the supervision of an Administrative
Board, whose members are appointed by European Institutions. The Board of Appeal is
part of the Agency but independent from its administrative and regulatory structures, and
deals with complaints lodged against ACER decisions185
. As regards the internal
181
Regulation EU No 1227/2011 on Wholesale Energy Market Integrity and Transparency – REMIT; OJ
L 326, 8.12.2011, p.1
182
Regulation (EU) No 347/2013 on guidelines for trans-European energy infrastructure (TEN-E
Regulation).
183
See Article 3 of the ACER Regulation and related provisions.
184
Under Articles 5, 6, 7, 8 and 9 of the ACER Regulation.
185
The ACER Board of Appeal takes its decisions with qualified majority of at least four of its six
members; it convenes when necessary; its members are independent in their decisions; some of its
costs are envisaged in the ACER budget.
183
Improving the institutional framework
decision-making, ACER decisions on regulatory issues (e.g. opinion on network codes)
require the favourable opinion of the Board of Regulators, which decides with two-thirds
majority.
In relation to the creation of ENTSOs, the Third Package sought to enhance effective
cooperation among TSOs in order to address the shortcomings and limitations shown by
the voluntary initiatives adopted by TSOs (the European Transmission System Operators
and Gas Transmission Europe). As a result, the Third Package tasked the ENTSOs with
EU-level functions such as contributing to the development of EU-wide network rules,
developing the 10-year network development plan and carrying out seasonal resource
adequacy assessments.
The establishment of ACER and the ENTSOs in order to enhance the cooperation among
NRAs and TSOs from 28 different Member States has undoubtedly been successful.
Both ACER and the ENTSOs are important partners in discussions on regulatory issues.
Further, the Third Package established a framwork for the ACER oversight of ENTSO-E,
tasking ACER e.g. with providing opinions on ENTSO-E's founding documents, on the
network code and network planning documents developed by ENTSO-E. In addition, the
Agency has the obligation to monitor the execution of the tasks of ENTSO-E186
.
As regards its financing, ACER benefits from a Union subsidy set aside specifically in
the general budget of the European Union, like most EU decentralised agencies. In
addition, ACER can collect fees for individual decisions187
.
Network Codes and Guidelines
The Third Package has set out a framework for developing network codes with a view to
harmonising, where necessary, the technical, operational and market rules governing the
electricity and gas grids. Under this framework, ACER, the ENTSOs and the European
Commission have a key role and need to work in close cooperation with all relevant
stakeholders on the development of network codes. The areas in which network codes
can be developed188
are set out in Article 8(6) of the Electricity Regulation and of the Gas
Regulation. Once adopted, these network codes become binding Commission
Regulations, directly applicable in all Member States.
The network code process is defined in Articles 6 and 8 of the Electricity and the Gas
Regulations and it can be essentially divided in two phases: (i) the development phase;
and (ii) the adoption phase.
186
Art. 6 of ACER Regulation.
187
Art. 22 of ACER Regulation. However, the fee has to be set by the European Commission, which did
not take place yet.
188
E.g., network connection, third party access, interoperability capacity allocation and congestion
management rules, etc.
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Improving the institutional framework
Figure 2 below illustrates the main stages of the network code development phase. It is
important to note that during each of these stages, the Commission, ACER and the
ENTSOs consult the proposals with stakeholders189
.
Figure 2: Main stages of the network code development process
Source: ACER
Once ACER submits a network code to the Commission recommending its adoption, the
Commission starts the adoption phase ("Commission adoption phase"), illustrated in
Figure 3190
.
189
These stakeholder consultations are not always required. For example, consultation is a requirement as
regards the preparation of the annual priority list (see Art. 6(1) Electricity Reg.) and the preparation of
the framework guidelines (Art. 6(3) Electricity Reg.). During the preparation of the network codes, the
ENTSOs have carried out stakeholder workshops, although this is not formally required in the
Electricity or Gas Regulations. In addition, the Agency may consult with stakeholders during the 3
months period for revision of the ENTSO proposal and the preparation of the reasoned opinion (Art.
6(7) Electricity Reg.).
190
Network codes are adopted according to Art. 5a (1) to (4) of Decision 1999/468/EC ("regulatory
procedure with scrutiny"), which requires a positive vote by a qualified majority of Member States and
agreement from Council and Parliament.
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Improving the institutional framework
Figure 3: Network code adoption phase
Source: unknown
The European Commission has also the possibility to develop "guidelines" which,
similarly to network codes, form legally binding Commission Regulations. The
guidelines have a different legal basis and follow a different development process191
,
under which there is no formal role for ACER or ENTSO-E, while their adoption phase
is the same as for the network codes.
Once adopted, network codes and guidelines are both acts implementing the Electricity
and the Gas Regulations. There is no difference as concerns their legally binding effects
and direct applicability.
Deficiencies of the current legislation
3.4.2.
The Third Package institutional framework aims at fostering the cooperation of NRAs as
well as between TSOs. Since their establishment, ACER and the ENTSOs have played a
key role in the progress towards a functioning internal energy market. In 2014, the
Commission undertook its first evaluation of the activities of the Agency192
and
concluded that ACER has become a credible and respected institution playing a
191
The areas in which guidelines can be developed are set out in Art. 18 (1), (2), (3) Electricity
Regulation and Art. 23 (1) Gas Regulation.
192
In line with Art. 34 ACER Regulation. The Commission prepared this evaluation with the assistance of
an independent external expert and including a public consultation. The evaluation covered the results
achieved by the Agency and its working methods.
186
Improving the institutional framework
prominent role in the EU regulatory field while focusing on the right priorities193
. Also,
according to ACER194
, both ENTSOs have achieved a good level of performance since
their establishment by the Third Package.
However, the recent developments in the European energy markets that the current
Impact Assessment reflects upon and the related proposals of the Market Design
Initiative require the adaptation of the institutional framwork. In addition, the
implementation of the Third Package has also highlighted areas with room for
improvement concerning the framework applicable to ACER and the ENTSOs.
The Agency has limited decision-making powers, as it acts primarily through
recommendations and opinions. With the integration of the European electricity markets
more and more cross-border decisions will be necessary (e.g. market coupling). Such
decisions however require a strong regulatory framework, for which a fragmented
national regulatory approach has proved to be insufficient195
. Ultimately this fragmented
regulatory oversight might constitute a barrier to the integration of the energy markets196
.
In this regard, there is consensus among market parties and stakeholders that ACER
should indeed be enabled to more efficiently deal with cross-border issues197
and to take
decisions198
.
Moreover, as European energy markets are more and more integrated, it is crucial to
ensure that ACER can function as swiftly and as efficiently as possible. As most of the
193
"Commission evaluation of the activities of the Agency for the Cooperation of Energy Regulators
under Article 34 of Regulation (EC) 713/2009" (22. 1. 2014), European Commission,
https://ec.europa.eu/energy/sites/ener/files/documents/20140122_acer_com_evaluation.pdf
194
"Energy Regulation: A Bridge to 2025 Conclusions Paper" (19 September 2014) ACER Report.
195
The existing competences of ACER for taking decisions set out in the ACER Regulation do not
include the implementation of network codes and guidelines. Many trading or grid operation methods
to be developed under network codes or guidelines require common EU-wide decisions or regional
decisions. Given that ACER does not have competence to take EU-wide or regional decisions relating
to network codes and guidelines, currently NRAs have to decide unanimously on the adoption of
identical legal acts in all national legal systems within a six-month period. This renders the
implementation of network codes and guidelines complex and inefficient.
196
"Energy Union. Key Decisions for the Realisation of a Fully Integrated Energy Market" (2016), Study
for the Committee for Industry, Research and Energy of the European Parliament: "In several regional
or EU-level projects (e.g. market coupling projects, see our case study in Annex 3) national
authorities, TSOs, regulators and energy exchanges of different Member States need to cooperate.
However, as they are primarily responsible for their own national gas and electricity system and
market they are not always sufficiently motivated to also take supranational interests into account.
[…] This leads to complex and slow decisional and implementation processes for most cross-border
projects, resulting in delayed implementations (e.g. the intra-day markets’ coupling project)." In this
context, different stakeholders argue for stronger governance at EU level. For example, EPEX Spot
states the need to accompany the electricity EU target model by appropriate governance architecture at
European level, applicable on market coupling activities, which will be crucial to ensure an efficient
day-to-day operation of such complex mechanisms.
197
"Energy Union. Key Decisions for the Realisation of a Fully Integrated Energy Market" (2016), Study
for the Committee for Industry, Research and Energy of the European Parliament.
198
For instance, the Third Package does not define a regional regulatory framework beyond the generic
reference to the need for NRAs to cooperate at regional level supported by ACER, which would be
necessary to ensure proper oversight of regional entities or functions.
187
Improving the institutional framework
regulatory decisions require the favourable opinion of the Board of Regulators, it is
equally relevant that the NRAs represented in the Board of Regulators can find
agreements swiftly and efficiently, which in the past was not always the case, leading to
delays or to a situation where the sufficient majority could not be reached, making it
impossible for ACER to fulfil its role.
As mentioned in Section 2 above, the Third Package introduced network codes as tools
for developing EU-wide technical, operational and market rules. While this process has
proved very sucessful overall, the practice of the last 5 years has highlighted the
existence of structural insufficiences. As an example, ENTSO-E plays a central role in
developing EU-wide market rules. Therefore, the rules on its independence and
transparency have to be strong and have to be accompanied by appropriate oversight
rules to ensure the transparent and efficient functioning of the organisation. The
reinforcement of these rules was also strongly requested by a high number of
stakeholders in the Commission's public consultation on the market design initiative.
Some stakeholders have mentioned that there is a possible conflict of interest in ENTSO-
E’s role – being at the same time an association called to represent the public interest
involved e.g., in network code drafting, and a lobby organisation for TSOs with own
commercial interests – and requested the adoption of measures to address this conflict199
.
The Third Package also includes elements of oversight of ENTSO-E by ACER.
However, given the strong role ENTSO-E plays as a technical expert body, in particular
in the development and implementation of network codes and guidelines, ACER's
oversight has proved to be insufficient, for example as regards ENTSO-E's statutory
documents or as regards the delivery of data to the Agency200
. Moreover, the emergence
of new entities and functions of EU-level or regional relevance through the adoption of
network codes and guidelines has further enlarged this oversight gap. This is, for
example, the case with the nominated electricity market operators ('NEMOs'), the market
coupling operator ('MCO') function, which will together be responsible for performing
cross-border day-ahead and intraday trading, a role created under the CACM Guideline,
and regional security coordinators ('RSCs') in electricity. The creation of these new
entities and functions has not been accompanied by tailored regulatory oversight.
The ACER Board of Appeal has a crucial function in safeguarding the validity of the
Agency's decisions. Even though the Board of Appeals has been called upon only in a
very limited number of times since the establishment, it has proved that its independence
is crucial. Experience shows that its functioning and financing must be reaffirmed to
ensure its full independence and efficiency.
199
For example by Eurelectric, EFET, CEDEC, Europex. This issue was also raised among the
observations of the European Court of Auditors in its report "Improving the security of energy supply
by developing the internal energy market: more efforts needed" (2015), which stated: "This is
problematic because, although the ENTSOs are European bodies with roles for the development of the
internal energy market, they also represent the interests of their individual members."
200
ACER exerts limited oversight (opinion on status, list of members and rules of procedures as per Art. 5
of the Electricity Regulation and monitoring of ENTSO-E’s tasks as per Art. 9 of the Electricity
Regulation.
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Improving the institutional framework
Like most of the EU decentralised agencies, ACER benefits from a Union subsidy set
aside specifically in the general budget of the European Union. As explained in Section
2, ACER has been tasked with additional functions since its establishment. These tasks
have been accompanied with additional staff. However, ACER is also subject to the
programmed reduction of staff in decentralised agencies by 5% over a period of 5 year
set out in the Commission's communication on "Programming of human and financial
resources for decentralised agencies 2014-2020"201
. It is clear that any additional tasks
for ACER as envisaged in the proposed initiatives will further tighten its financing and
staffing and will require further resources.
Another set of shortcomings can be tracked to insufficient participation of DSOs within
the institutional framework. Under the energy transition, a traditional top-down,
centralised electricity distribution system is being outpaced by more decentralised
generation and consumption. The integration of a significant share of variable solar and
wind generation capacity connected directly to distribution networks create new
requirements and possibilities for DSOs, who will have to deal with increased capacity
while maintaining quality of service and minimizing network costs. In addition, the
electrification of sectors such as transport and heating will introduce new loads in
distribution networks and will require a more active operation and better planning.
The problem is aggravated by the fact that specific requirements on TSO – DSO
cooperation as set forth in the different Network Codes and Guidelines, and new
challenges that TSOs and DSOs are jointly facing, will require greater coordination
between system operators.
For the time being, no provision at all is made for the formal integration of DSOs into the
EU institutional decision making. However, from a policy perspective a cohesive and
consistent participation of DSOs in the EU institutional framework is required. Future
electricity system will require a more coordinated approach of TSOs and DSOs on issues
of mutual concern. Regarding network codes, DSOs will need to display a common
approach, as many of the envisaged network codes are directly or indirectly concern
distribution grids.
As set out in the evaluation report202
, while the principles of the Third Package achieved
its main purposes, new developments in electricity markets led to significant changes in
the market functioning in the last five years. The existing rules defining the institutional
framework are not fully adapted to deal with the recent changes in electricity markets
effectively. Therefore, it is reasonable to update these rules so that they may be able to
cope with the reality of today's energy system.
201
Communication from the Commission to the European Parliament and the Council, COM(2013)519
final of 10.07.2013.
202
Evaluation Report covering the evaluation of the EU's regulatory framework for electricity market
design and consumer protection in the fields of electricity and gas and evaluation of the EU rules on
measures to safeguard security of electricity supply and infrastructure investment (Directive 2005/89).
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Improving the institutional framework
The institutional framework currently applicable to the internal energy market as set out
in the Third Package is based on the complementarity of regulation at national and EU-
wide level. In view of the developments since the adoption of the Third Package as
described in the evaluation report, the institutional framework, especially as regards
cooperation of NRAs at regional level, will need to be adapted to ensure the oversight of
entities with regional relevance. Moreover, as the European energy markets are more and
more integrated, it is crucial to ensure that ACER can function as swiftly and as
efficiently as possible. In addition, the implementation of the Third Package has
highlighted areas with room for improvement concerning the framework applicable to
ACER and the ENTSOs.
Presentation of the options
3.4.3.
Option 0: Business as usual
The business as usual (BAU) option does not foresee new, additional measures to adapt
or improve the institutional framework. Apart from the continued implementation of the
Third Package and the implementation of network codes and guidelines, this option
would leave the EU institutional framework unchanged, meaning that it would continue
to be primarily based on a close complementarity of regulation at national and EU-wide
level.
The challenges arising through the changes to and the stronger integration of the
European energy markets could not be tackled and regulatory gaps arising from the
adoption and implementation of network codes and guidelines would also remain
unaddressed. This could potentially lead to delays in their implementation and ultimately
act as a barrier to achieving the electricity EU target model.
The BAU option would maintain the limitation of ACER's decision-making powers and
would not remedy the risks arising from the fragmented national regulatory approach.
NRAs and ACER would continue to face difficulties fulfilling their tasks that have
relevance at regional and EU level.
The business as usual option would leave ACER's current internal decision-making
unchanged. This would mean that where the favourable opinion of the Board of
Regulators is necessary, this would have to be reached with two-thirds majority facing
the risk of delays or lack of agreement.
Under this option the process of developing network codes would remain unchanged.
This would allow ENTSO-E to continue playing a very strong role in setting European
market rules, going beyond of that providing technical expertise. This option would
neither improve the rules on ENTSO-E's transparency and independence nor the rules of
ACER's oversight of ENTSO-E. The progress concerning ENTSO-E's transparency
would depend on the voluntary initiative of the association. The criticisms to the
existence of conflicts of interest regarding the roles of ENTSO-E, particularly as regards
the development of network codes, would not be addressed.
Under the Option business as usual, despite having been assigned additional
responsibilities since its establishment, ACER would still be constrained by the current
regulatory framework as regards the regulatory oversight of new entities and functions
performing at regional or EU level.
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Improving the institutional framework
This Option would maintain the current framework for the functioning of ACER's Board
of Appeal. This means that its independent functioning and financing would continue to
be highly vulnerable.
The BAU also foresees no integration of DSOs into the institutional decision-making
setting as explained under the Section dealing with the shortcomings of current
legislation. It is true that in 2015, with the support of the Commission, the four European
DSO associations and ENTSO-E established a cooperation platform203
between TSOs
and DSOs at EU level. This cooperation has the objective to work on issues of mutual
DSO-TSO concern such as coordinated access to resources, regulatory stability, grid
visibility and grid data. However, this cooperation remains purely voluntary in nature
with no formal expression in the wider EU decision making setting or ACER.
In sum, European DSOs collaborate through the existing DSO associations but without
any legal status at EU institutional level. There is no formal participation in drafting or
amending of network codes and guidelines.
Option 0+: Non-regulatory approach
Under this option a "stronger enforcement" approach and voluntary collaboration as a
non-legislative measure were considered without foreseeing any new, additional
measures to adapt the institutional framework. Improved enforcement of existing
legislation would entail the continued implementation of the Third Package and the
implementation of network codes and guidelines – as described under option business as
usual – combined with stronger enforcement. However, stronger enforcement would not
provide any improvement to the current institutional framework as it is already fully
implementing the existing legal framework.
Collaboration in the current institutional framework is based on legal obligation. While
voluntary cooperation might be possible in areas not covered under the Thrid Energy
Package, it would require establishing parallel structures and additional resources without
significantly improving the functioning of the current regulatory framework. Therefore,
voluntary collaboration is not considered a valid option.
Therefore, the Option 0+ would leave the EU institutional framework unchanged,
meaning that it would continue to be based, primarily, on a close complementarity of
regulation at national and EU-wide levels. Furthermore, any improvement compared to
the current situation would have to stem from voluntary initiatives of the involved
bodies. In addition, this option could not provide the necessary solutions arising from the
changing market reality as described in this impact assessment. Therefore, this option is
discarded as not valuable in providing solutions for the described shortcomings and
overall developments.
203
ENTSO-E, CEDEC, GEODE, EDSO, EURELECTRIC (2015), "General Guidelines for reinforcing the
cooperation between TSOs and DSOs" (http://www.eurelectric.org/media/237587/1109_entso-
e_pp_tso-dso_web-2015-030-0569-01-e.pdf)
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Improving the institutional framework
Option 1: Upgrade the EU institutional framework
Option 1 foresees adapting the EU institutional framework to the new realities of the
electricity system204
and to the resulting need for additional regional cooperation and to
address the existing and anticipated regulatory gaps in the energy market, providing
thereby for flexibility by a combination of bottom-up and top-down approaches. Option 1
would adapt the institutional framework set out in the Third Package to address the
regulatory gaps materialising through the implementation of the Third Package and
resulting from the adoption and implementation of network codes and guidelines. It
would also adapt the institutional framework to the new realities of the electricity system
and to the resulting need for additional regional cooperation.
As regards ACER’s decision-making, Option 1 would largely entail reinforcing its
powers to carry out regulatory functions at EU level. In addition, in order to address the
existing regulatory gap as regards NRAs' regulatory functions at regional level, the
policy initiatives under this option would set out a flexible regional regulatory framework
to enhance the regional coordination and decision-making of NRAs. This Option would
introduce a system of coordinated regional decisions and oversight for certain topics by
NRAs of the region (e.g. ROCs and others deriving from the proposed market design
initiatives) and would give ACER a role for safeguarding the EU-interest.
Option 1, while giving ACER additional powers, would also ensure that the Agency can
swiftly and effectively reach these decisions in its Board of Regulators. To enable NRAs
to take decisions without delay in the BoR, this Option would adapt the BoR internal
voting rights. Option 1 also reflects on the necessity to ensure that all (existing and
proposed) ACER decisions are subject to appeal and that the ACER Board of Appeal can
act fully independently and effectively through adjusting its financing and internal rules.
Further, concerning ACER's competences, Option 1 entails strengthening ACER's role in
the development of network codes, particularly as regards giving the Agency more
responsibility in elaborating and submitting the final draft of the network code to the
Commission, while maintaining ENTSO-E's relevant role as a technical expert. This
Option would also involve strengthening ACER's oversight over ENTSO-E. In addition,
Option 1 would effectively distinguish ENTSO-E’s statutory mandate from defending its
member companies' interests by setting out a clear European mandate in the legislation
and ensuring more transparency in its decision-making processes.
Under this Option, ACER would receive additional competence to oversee new entities
and functions which are not currently subject to regulatory oversight at EU level. This is
the case for power exchanges operating in their cross-border functions; they play a
crucial role in coupled European electricity markets and perform functions that have
characteristics of a natural monopoly. Depending on the type of entity or function and
their geographical scope, this Option would either introduce NRAs’ coordinated regional
oversight with support and monitoring by ACER or ACER oversight with NRAs’
contribution.
204
As further detailed in Section 1 of the main body of this impact assessment.
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Improving the institutional framework
As described in this Section, Option 1 would give ACER additional tasks and powers
while acknowledging that appropriate financing and staffing is key for ACER to perform
its role. Therefore, Option 1 foresees additional sources of financing which would be
possible either by increasing the EU financing or by introducing co-financing,
complementary to the Union financing the sector ACER is supervising205
.
This Option would also include a formal place for DSOs to be represented at EU level, in
line with an increase in their formal market responsibilities and role as has been
mentioned above. The establishment of an EU DSO entity will enable the development
of new policies which can positively affect the cost efficient integration of distributed
energy resources including RES E, and which will reinforce the representation and
participation of EU DSOs at an institutional European level.
Option 1 thus envisages the establishment of an EU DSO entity for electricity with an
efficient working structure. European DSOs will provide experts based on calls for
proposals issued by the EU-DSO. European DSOs will participate in financing the EU-
DSO entity through a Supporting Board based on the existing EU DSO associations
(Eurelectric, EDSO, CEDEC, GEODE).
Tasks of the EU DSO will include:
- Drafting network codes/guidelines following the existing procedures;
- Monitor the implementation of network codes on areas which concern DSOs;
- Deliver expert opinions as requested by the Commission;
- Cooperate with ENTSO-E on issues of mutual concern, such as data
management, balancing, planning, congestion, etc.
The EU DSO entity will also work on areas such as DSO/TSO cooperation, integration
of RES, deployment of smart grids, demand response, digitalisation and cybersecurity.
Option 2: Restructure the EU institutional framework
Option 2 would significantly restructure the institutional framework, going beyond
addressing the regulatory gaps identified above and moving towards more centralised
institutional structures with additional powers and responsibilities at European level,
particularly as regards the role of ACER and ENTSO-E.
Concerning ACER's powers, Option 2 would extend ACER's decision-making powers to
all regulatory issues with cross-border trade relevance. This would result in ACER taking
205
The Commission’s aim for decentralised agencies is to eliminate EU and national budgetary
contributions and wholly finance them by the sector they supervise, see the Mission letter of
Commissioner Hill of 1 November 2014. In this sense ACER could be co-financed through the sector
it is supervising. In the light of ACER’s cruacial role in delivering on the common EU objectives and
in particular in protecting the Eurpean energy markets from fraud, the functioning of ACER could be
co-financed with contributions from market participants and/or public bodies benefitting from ACER’s
activities. This would contribute to guaranteeing ACER's full autonomy and independence.
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Improving the institutional framework
over most NRA responsibilities directly or indirectly related to cross-border and EU-level
issues. This Option would further give the ACER Director the power to become the main
decision-making instance in the Agency, as opposed to the BoR, possibly with veto
powers from the Board of Regulators on certain measures.
As regards ACER's competences, Option 2 would entail a direct oversight over ENTSO-
E and over other entities fulfilling EU level or regional functions, giving ACER the
power to take binding decisions.
In order for ACER to perform its role under Option 2, it would require a significant
reinforcement of ACER's budget and staff as this would make a strong concentration of
experts in ACER necessary. Therefore, this option would entail – as foreseen under
Option 1 – reinforcing EU funding and the possibility to introduce in addition financing
through market players and/or public bodies. As Option 2 would give ACER such strong
powers it would also entail a significant reinforcement of the structural set-up of the
Board of Appeal to ensure that the appeal mechanism can function independently and
effectively because it would potentially face a significantly higher number of appeals due
to the increasing number of direct ACER decisions foreseen under this Option.
As regards to ENTSO-E's competences, this option would require a formal separation of
ENTSO-E from its members' interest. It would strengthen the independence of ENTSO-E
by introducing a European level decision-making body who would have powers to decide
on proposals and initiatives without requiring prior TSOs' approval.
With regards to the role of DSOs, the measures included under Option 1 would apply to
Option 2 as well. The move to an EU regulator with full powers would however mean
that ACER would have to also carry out the oversight of, and entertain relations with,
DSOs in a way that is now done at Member State level.
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Improving the institutional framework
Table 2: Detailed overview of the measures proposed under the three options
ISSUE Option 0: Business as
usual
Option 1: Ugrade EU
insitutional framework to
address regulatory gaps
Option 2: Restructur
EU institutional
framework
ACER decision-
making
Limited, through
recommendations and
opinions
Most regulatory decisions
with BoR favourable
opinion
ACER Director manages
ACER and tables
proposals for BoR
favourable opinion
ACER decisions with BoR
favourable opinion, also
replacing Guideline
implementing “all NRA”
decisions at EU and regional
levels
Framework of regional NRA
decision-making with ACER
oversight (complementary
role to safeguard EU interest)
ACER decision
without BoR
involvement, mainly
by ACER Director
BoR decision-
making
2/3rds
majority for the most
of ACER decisions
Simple majority for most of
ACER decisions
2/3rds
majority for
ACER decisions in a
limited instances
Board of Appeal Independent body for all
appeal cases
Some of its costs are
envisaged in the ACER
budget
Independent body for all
appeal cases with strengthend
framework and separate
budget line in the ACER
budget
Independent body for
all appeal cases with
strengthend line of
financing and
framework
ACER Financing Community/EU-funding
(separate budget line)
Possibility for ACER to
collect fees for individual
decisions
Need for increased financing
(possibly through increased
EU-funding and possibly co-
financing by contributions by
market participants and/or
national public authorities
Need for significantly
increased financing
(possibly through
increased EU-funding
and possibly co-
financing by
contributions by
market participants
and/or national public
authorities
Network Code
development
process
Based on ACER’s
framework guideline
ENTSO-E drafts network
code (strong role and
influence), ACER provides
opinion and
recommendation to the
Commission.
Based on ACER’s framework
guideline ENTSO-E drafts
network code guided by a
standing stakeholder body
and broad general stakeholder
involvement, ACER
consolidates the network code
and submites the final
product to the Commission
Based on ACER’s
framework guideline
ENTSO-E drafts
network code with the
involvement of
standing stakeholder
body, ACER
consolidates the
network code (ACER
internal decision
without Board of
Regulators'
favourable opinion)
and submites the final
product to the
Commission
Oversight of
ENTSO-E
Limited ACER oversight
of ENTSO-E
Strenghtened ACER
oversight of ENTSO-E
Strenghtened ACER
oversight of ENTSO-
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Improving the institutional framework
E
Oversight of new
entities
None or limited regulatory
oversight (limited rules in
network codes and
guidelines)
Strenghtened regulatory
oversight by NRAs and
ACER
ACER direct
oversight
ENTSO-E’s
mission and
transparency
Lack of clear European
mission and voluntary
transparency rules
Codified clear European
mission and transparency
obligations on its decision-
making
Formal separation
from its members'
interests and creation
of a decision-making
body
DSO European DSOs
collaborate through the
existing DSO associations
but without any legal
status at EU institutional
level. There is no formal
participation in drafting or
amending of network
codes and guidelines
Establishment of an EU DSO
entity for electricity with an
efficient working structure;
European DSOs will provide
experts based on calls for
proposals issued by the EU-
DSO.
Same as Option 1,
plus an increased role
for coordination and
oversight on the part
of ACER
Source: European Commission
Comparison of the options
3.4.4.
As stated above, the goal of the proposed initiatives is to adapt the institutional
framework to the reality of integrated regional markets. In this regard, as it will be further
illustrated below, Option 0, the business as usual option, would not contribute towards
achieving this objective and in some instances it may even be detrimental, since the
institutional framework needs to be able to provide tools for the different parties (ACER,
NRAs, ENTSO-E) to address the challenges arising from the integration of the markets.
Options 1 and 2 can capture the challenges and potential opportunities, but the efficiency,
effectiveness and economic impact of these options can vary significantly.
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Improving the institutional framework
Table 3: Qualitative comparison of Options in terms of their effectiveness, efficiency
and coherence of responding to specific criteria
Criteria Option 0:
Business as usual
Option 1:
Upgrade EU institutional
framework addressing
regulatory gaps
Option 2:
Restructure EU
institutional framework
Quality 0
Progress remains limited
and primarily voluntary
+
Using expertise from
established actors
+
Efficient through limited
coordination requirements
Speed of
implemen-
tation
-
Slow, primarily
voluntary progress
0/+
Building upon established
structures
-
Delays resulting from
changed structure
Use of
established
institutional
processes
-
Efficiency of established
processses limited.
++
Can build upon established
structures
-
Requires building up new
structures/processes
Efficient
organisational
structure
0
Existence of insufficient
rules and regualtory
gaps for organisation
++
Efficient organisational
structure can be created;
using expertise from
established actors further
improving it
+
Efficient because of limited
coordination requirements
Involvement of
stakeholders
0
Process in the hands of
the main actors
+
Rules for effective,
reinforeced involvement
+
Rules for effective,
reinforced involvement
Source: European Commission.
The assumptions in this table are based on the feedback received from stakeholders in their response
to the public consultation and from additional submissions from ACER.
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Improving the institutional framework
Table 4: Qualitative estimate of the economic impact of the Options
Economic Impact
Internal
Market for
electricity
Transparency
and non-
discrimination
Administrative
impact and
implementation
costs
Option 0: Business as usual 0/+ - 0
Option 1: Upgrading EU institutional framework + + 0/-
Option 2: Restructuring EU institutional framework ++ ++ --
Source: European Commission
The assumptions in this table are based on the feedback received from stakeholders in their response to the
public consultation and from estimations concerning the resources of ACER and ENTSO-E.
In summary, Option 0 – business as usual – will fall short in providing for an institutional
framework that can underpin the integration of the internal electricity market in a timely
manner.
Option 1, addressing regulatory gaps by upgrading the EU institutional framework would
be, according to the assessment of the options above, the most appropriate measure for
establishing an EU institutional framework that reflects and complements the
increasingly integrated and regional dimension of the electricity market. This option is
favoured by most of the stakeholders206
. It represents a flexible approach combining
bottom-up initiatives and top-down steering of the regulatory oversight, respecting the
principle of subsidiarity.
Option 2, significantly restructuring the EU institutional framework, while having
advantages in terms of requiring less coordination and being as efficient as Option 1, it
has the clear disadvantage of requiring significant changes to established institutional
practices and processes and of having the greatest economic impact. Some of the
solutions proposed under Option 2, such as those involving the extension and shifting of
decision-making powers and responsibilities, would raise severe opposition from
stakeholders. That would be for example the case for ACER and the transfer of decision-
206
70% of stakeholders responding to the relevant questions of the Commission's public consultation on a
new market design were in favour of strengthening ACER's institutional role, e.g. some mentioning
that it may be efficient to enable ACER to take decisions on cross-border issues where EU network
codes/guidelines require decisions to be taken by all national regulatory authorities. Further, many
stakeholders asked for improving ENTSO-E's independence from its members' commercial interest.
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Improving the institutional framework
making powers from NRAs207
. In summary, Option 2 did not receive support from
stakeholders.
The Commission Services are of the view that Option 1 "upgrading the EU institutional
framework " is currently the most appropriate approach to achieve the main objective
pursued i.e., adapt the institutional framework and ACER's decision powers and internal
decision-making to the reality of integrated regional markets.
It is also relevant to note, that as the institutional framework for the European energy
market design initiative, the proposals discussed above in the options will be
accompanied by some further changes originating from the need to adapt ACER's
funding Regulation to the Common Approach on EU decentralised agencies208
and to
incorporate some minor improvements to streamline the institutional framework
established in the Third Package.
Further, as the Third Package establishes an identical institutional framework for
electricity and for gas209
, changes to this system will be also applied to the gas sector
where relevant and reasonable to ensure that rules and processes are identical for the two
sectors in the future.
Budgetary implications of improved ACER staffing
3.4.5.
This Section provides an estimate of budgetary implications from adjusting ACER
staffing to adequately meet new tasks and responsibilities envisaged under the preferred
option (Option 1) as well as under the highly ambitious Option 2.
As per the Agency's draft 2017 Work Programme, ACER employed on 31.12.2015 a
total of 54 Temporary Agents, of which 39 at AD level and 15 at AST level. The Agency
further employed an additional 20 Contract Agents and 6 SNE, raising the total ACER
headcount to 80.
It should be noted that the European Commission, in its latest opinion on the ACER
Work Programme210
did not agree to grant additional staff under the 2017 budget,
judging that current staff figures are adequate to meet current tasks and suggesting that
ACER shifts resources internally to meet priority objectives.
207
Most of the Member States responding to the relevant questions of the Commission's public
consultation on a new market design favored preserving the status quo as regards the institutional
framework.
208
The Common Approach on EU decentralised agencies agreed in July 2012 by the European
Parliament, the Council and the Commission defines a more coherent and efficient framework for the
functioning of agencies. Although legally non-binding, it serves as a political blueprint not only
guiding future horizontal initiatives but also in reforming existing, individual EU agencies. Most
importantly, the implementation of the Common Approach requires the adaptation of the founding acts
of existing agencies, based on case by case analysis.
209
For example, the Third Package, in the Gas Regulation established the European Network for
Transmission System Operators for Gas (Art. 5).
210
Commission Opinion on the draft Work Programme of the Agency for the Cooperation of Energy
Regulators, C(2016)3826 of 24.6.2016
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Improving the institutional framework
In line with additional tasks foreseen under Option 1 and Option 2, ACER staffing
resources should however be adapted.
The tables below show the financial implications of Option 1 and Option 2 for extra staff.
The average cost per headcount is based on the latest DG BUDGET declared average
cost211
: for a Temporary Agent, total average costs including "bailage" costs (real estate
expenses, furniture, IT, etc.), stand at EUR 134.000 per year per individual.
Table 5: ACER staff: budgetary implications under Option 1
Function (a) No. extra
staff (MIN)
(b) No. extra staff
(MAX)
Budget of (a)
(million euros)
Budget of (b)
(million euros)
Network Codes and
Regulation
7 12 0.938 1.618
Regulatory Oversight 6 10 0.804 1.340
Coordination
(Internal and
External)
2 3 0.268 0.402
DSO-related 2 3 0.268 0.402
Total + 17 + 28 2.278 3.752
Source: Own calculation based on DG BUDG figures
211
Circular note of DG BUDGET to RUF/2015/34 of 09.12.15
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Improving the institutional framework
Table 6: ACER staff: budgetary implications under Option 2
Function (a) No. extra
staff (MIN)
(b) No. extra staff
(MAX)
Budget of (a)
(million euros)
Budget of (b)
(million euros)
Network Codes and
Regulation
20 30 2.680 4.020
Regulatory Oversight 30 35 4.020 4.690
Dedicated national
desk offices
56 84 7.504 11.256
Reinforced Board of
Appeal
15 20 2.010 2.680
Coordination
(Internal and
External) &
Management
15 20 2.010 2.680
DSO-related 5 10 0.670 1.340
Total + 141 + 199 19.296 26.666
Source: Own calculation based on DG BUDG figures
These calculations are only approximate as they cannot take into account the grade level
of future recruited staff or the exact breakdown of future tasks. This is particularly true
for Option 2, which would entail a complete overhaul of the Agency and the
appropriation of full regulatory competences for 28 markets.
Subsidiarity
3.4.6.
The current institutional framework for energy in the Union is based on the
complementarity of regulation at national and EU level. The Third Package mandated the
designation by Member States of national regulatory authorities and required that they
guarantee their independence and ensure that they exercise their role and powers
impartially and transparently at national level. The Third Package also created ACER and
ENTSO-E in order to enhance the coordination of national energy regulators and
elecricity TSOs at EU level.
The implementation of the Third Package through the adoption of Commission
implementing regulations has led to the creation of new entities and functions which have
changed the regulatory landscape. Some of these entities/functions have EU-wide
relevance (e.g., the market coupling operator function in the electricity sector) whereas
others have regional relevance (e.g., the regional security coordinators in the electricity
sector, capacity allocation platforms in the gas sector).
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Improving the institutional framework
Moreover, the electricity markets have become more integrated due to increasing cross-
border electricity trade and more physical interconnections in the European electricity
grid. This, together with progressively higher shares of decentralized and variable
renewable energy sources, have rendered the national electricity systems much more
interdependent than in the past.
Whereas the institutional framework envisaged in the Third Package has undoubtedly
been successful, the unprecedented changes described above have highlighted the
existence of regulatory gaps. These gaps appear, for example, where the creation of the
entities/functions with EU-wide or regional relevance has not been accompanied with the
necessary tools to equip ACER with powers to exercise regulatory oversight over them,
despite the fact that they will be carrying out monopoly or critical functions for the
internal energy market at EU or regional level. Other gaps relate to the lack of regulation
ensuring the consistent implementation of governance principles across regions or to the
lack of clarity concerning the roles and responsibilities of national regulatory authorities,
ACER and ENTSO-E following the adoption of Commission implementing regulations.
It is therefore necessary to adapt the institutional framework in the Third Package to meet
this new reality and provide a basis for realizing the full potential of the internal energy
market. This is why the roles of NRAs, ACER, and ENTSO-E need to further evolve,
clarifying their powers and responsibilities over relevant geographical areas. In addition,
it will be necessary to adapt the institutional framework to the changes in EU energy
legislation stemming from the proposed initiatives.
Proportionality
Option 1 would be in line with the proportionality principle given that it aims at clearly
defining the roles, powers and responsibilities of the main actors (NRAs, ACER,
ENTSO-E) so that they are adapted to the new realities of the electricity markets and to
the need for more regional cooperation. More specifically:
- The improvements to the ACER framework under this option do not aim at
replacing national regulatory authorities but rather at complementing their role as
regards issues which have regional/EU-wide relevance. The scope of ACER's
responsibilities will continue to be limited to cross-border relevant issues.
- The improvements concerning the regulatory oversight at regional level aim at
addressing the regulatory gap that has arisen with the implementation of the
Third Package through the adoption of Commission implementing regulations.
- The amendments of the ENTSO-E framework under this option principally aim
at improving and clarifying its mandate to ensure its European character and to
introduce more transparency in its internal decision-making processes.
- The improvements to the process for developing Commission implementing
regulations (network codes and guidelines) aim at addressing some of the
shortcomings identified in the past years.
- The establishment of an EU DSO entity will support EU policies and RES
integration in the electricity system, will support the swift implementation of
network codes and guidelines, and enhance cooperation between TSOs and
DSOs.
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Improving the institutional framework
Stakeholders' opinions
3.4.7.
This Section provides a more detailed summary of the views expressed by stakeholders
regarding the adaptation of the institutional framework in the European Electricity
Regulatory Forum and in response to the Commission public consultation on a new
market design.
The 29th
meeting of the European Electricity Regulatory Forum of 9 October 2015
underlined, as a conclusion, "the need for analyzing and further elaborating the roles,
tasks, responsibilities and consider possible governance structures of ACER and
ENTSO-E" and stressed "the need to observe and consider possible governance
structures for other bodies, including DSOs and power exchanges, and for NEMO
cooperation."
As regards enhancing ACER's institutional role, in response to the Commission public
consultation on a new market design, 70% of all stakeholders who answered the
questions on ACER wanted to increase the powers or tasks of ACER (notably as regards
oversight of ENTSO-E). 30% supported to keep the status quo. Only a limited number of
respondents (5%) mentioned missing independence of ACER as a problem. In general,
views differed between Member States and NRAs on the one hand (rather for preserving
status quo) and other stakeholders (rather in favour of strengthening powers at
regional/EU level).
Within the development of a robust regulatory framework for the entities performing
monopoly or near-monopoly functions at EU or regional level, ACER called for the
power to exercise regulatory oversight over such entities212
. With regard to regional
cooperation, which should be promoted by the NRAs, ACER can support NRAs' actions
and should be responsible for promoting and monitoring the consistency of regional
implementation and of the activities of entities performing monopoly or near-monopoly
activities at regional level.
As regards ENTSO-E, 38% of the respondents to the public consultation on a new market
design did not have or did not express any opinion or preference regarding the possible
strengthening of ENTSO-E. Looking at the respondents having an opinion on this topic,
59 % of the respondents were in favour of not to strengthen ENTSO-E while 41% asked
for a stronger ENTSO-E.
As regards power exchanges, 63% of the respondents to the consultation answering this
specific question were of the view that there is a need for enhanced regulatory oversight
of power exchanges.
As regards the process for development of Commission implementing regulations in the
form of network codes and guidelines, some of the respondents to the consultation
mentioned the existence of a possible conflict of interest in ENTSO-E’s role – being at
the same time an association called to represent the public interest, involved e.g. in
212
ACER's position on the regulatory oversight of (new) entities performing monopoly or near-monopoly
functions at EU-wide or regional level.
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Improving the institutional framework
network code drafting, and a lobby organisation with own commercial interests – and
asked for measures to address this conflict. Some stakeholders suggested that the process
for developing network codes should be revisited in order to provide a greater a balance
of interests. Some submissions advocated for including DSOs and stakeholders in the
network code drafting process.
As regards DSOs, the establishment of an independent EU-level DSO entity has been
welcomed by stakeholders on multiple occasions. In particular, attention is drawn to the
Conclusions of the 31st
Energy Regulators Forum, whereby: "The Forum takes note of
the announcement from the Commission of the establishment of an EU‐ level DSO entity
that can serve to provide expertise in advancing the EU market. The Forum invites the
Commission, in the design of any entity, to ensure a balanced representation of DSOs
and maximum independence and neutrality". Equally, regulators (ACER and CEER)
suggested considering whether DSOs should be encouraged to establish a single body
through which they can more efficiently participate in the process of new electricity
market design.


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 4/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
207
TABLE OF CONTENTS
4. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(1);
(IMPROVED ENERGY MARKETS, NO CMS).................................................................. 209
4.1. Removing price caps...................................................................................................................209
Summary table.............................................................................................................................209
4.1.1.
Description of the baseline..........................................................................................................210
4.1.2.
Deficiencies of the current legislation .........................................................................................215
4.1.3.
Presentation of the options .........................................................................................................216
4.1.4.
Comparison of the options ..........................................................................................................216
4.1.5.
Subsidiarity...................................................................................................................................218
4.1.6.
Stakeholders' opinions.................................................................................................................218
4.1.7.
4.2. Improving locational price signals ...............................................................................................220
Summary Table ............................................................................................................................221
4.2.1.
Description of the baseline..........................................................................................................222
4.2.2.
Deficiencies of the current legislation .........................................................................................228
4.2.3.
Presentation of the options .........................................................................................................229
4.2.4.
Comparison of the options ..........................................................................................................230
4.2.5.
Subsidiarity...................................................................................................................................231
4.2.6.
Stakeholders' opinions.................................................................................................................232
4.2.7.
4.3. Minimise investment and dispatch distortions due to transmission tariff structures....................234
Summary table.............................................................................................................................235
4.3.1.
Description of the baseline..........................................................................................................236
4.3.2.
Deficiencies of the current legislation .........................................................................................238
4.3.3.
Presentation of the options .........................................................................................................239
4.3.4.
Comparison of the options ..........................................................................................................240
4.3.5.
Subsidiarity...................................................................................................................................245
4.3.6.
Stakeholders' opinions.................................................................................................................245
4.3.7.
4.4. Congestion income spending to increase cross-border capacity...................................................248
Summary table.............................................................................................................................249
4.4.1.
Description of the baseline..........................................................................................................251
4.4.2.
Deficiencies of the current legislation .........................................................................................254
4.4.3.
Presentation of new measures/options ......................................................................................255
4.4.4.
Comparison of the options ..........................................................................................................257
4.4.5.
Subsidiarity...................................................................................................................................259
4.4.6.
Stakeholders' opinions.................................................................................................................260
4.4.7.
5. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(2)
(IMPROVED ENERGY MARKETS - CMS ONLY WHEN NEEDED, BASED ON
COMMON EU-WIDE ADEQUACY ASSESSMENT ( AND OPTION 2(3) (IMPROVED
ENERGY MARKET, CMS ONLY WHEN NEEDED BASED ON COMMON EU-WIDE
ADEQUACY ASSESSMENT, PLUS CROSS-BORDER PARTICIPATION) ................. 262
5.1. Improved resource adequacy methodology ................................................................................264
Summary table.............................................................................................................................265
5.1.1.
Description of the baseline..........................................................................................................266
5.1.2.
Deficiencies of the current legislation .........................................................................................272
5.1.3.
Presentation of the options .........................................................................................................273
5.1.4.
Comparison of the options ..........................................................................................................275
5.1.5.
Subsidiarity...................................................................................................................................283
5.1.6.
208
Stakeholders' opinions.................................................................................................................283
5.1.7.
5.2. Cross-border operation of capacity mechanisms .........................................................................286
Summary table.............................................................................................................................287
5.2.1.
Description of the baseline..........................................................................................................288
5.2.2.
Deficiencies of the current legislation .........................................................................................289
5.2.3.
Presentation of the options .........................................................................................................290
5.2.4.
Comparison of the options ..........................................................................................................293
5.2.5.
Subsidiarity...................................................................................................................................296
5.2.6.
Stakeholders' opinions.................................................................................................................296
5.2.7.
209
Removing price caps
4. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(1); (IMPROVED ENERGY MARKETS, NO CMS)
4.1. Removing price caps
Summary table
4.1.1.
Objective: to ensure that prices in wholesale markets and not prevented from reflecting scarcity and the value that society places on energy.
Option 0: Business as usual Option 1: Eliminate all price caps Option 2: Create obligation to set price caps, where they exist, at VoLL
Description
Existing regulations already require harmonisation of
maximum (and minimum) clearing prices in all price
zones to a level which takes "into account an estimation
of the value of lost load".
Non-regulatory approach
Enforceability of "into account an estimation of the
value of lost load" in the CACM Guideline is not strong.
Enforcement action is unlikely to be successful or
expedient. Relying on stronger enforcement would leave
considerable more legal uncertainty to market
participants than clarifying the legal framework
directly.Voluntary cooperation not provide the market
with sufficient confidence that governments would not
step in restrict prices in the event of scarcity.
Eliminate price caps altogether for
balancing, intraday and day-ahead markets
Removes barriers for scarcity pricing
Avoids setting of VoLL (for the purpose of
removing negative effects of price caps)
Reinforced requirement to set price limits taking "into account an estimation of
the value of lost load"
Allow for technical price limits as part of market coupling, provided they do not
prevent prices rising to VoLL.
Establish requirements to minimise implicit price caps.
Pros
Simple to implement – leaves adminstration to technical
implementation of the CACM Guideline.
Measure simple to implement;
unequivocally and creates legal certainty.
Compatible with already existing requirement to set price limit, as provided for
undert the CACM regulation, provides concrete legal clarity
Cons
Difficult to enforce; no clarity on how such clearing
prices will be harmonised. Does not prevent price caps
being implemented by other means.
Can be considered as non-proportional;
could add risk to market participants and
power exchanges if there are no limits .
VoLL, whilst a useful concept, is difficult to set in practice. A multitude of
approaches exist.
Most suitable Option(s): Option 2 - this provides a proportionate response to the issue –, it would allow for technical limits as part of market coupling and this should not restrict the markets
ability to generate prices that reflect scarcity.
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Removing price caps
Description of the baseline
4.1.2.
Scarcity pricing is critical to investment in flexible generation and demand. Traditionally,
power plants have been built based on receiving a stable revenue and operating with high
levels of output for a significant proportion of time (i.e. high load factors). However,
with more variable renewable technologies entering on to the system, with generally very
low or zero marginal costs, the patterns that more conventional forms of generation
operate (e.g. gas) is changing. Investment will no longer be able to take place based on
the assumption that plants will operate at high load factors for a significant portion of
their working life; with more and more generation from renewables, with lower running
costs, these plants will operate less and less. However, they will remain critical in
providing a stable electricity system. They will need to operate to keep supply steady in
times of low renewable generation and flexibility will be key. There will be more and
more occasions when prices could reach very high levels (in times of scarcity) but for
very short periods of time. It is these peaking prices that can provide the signals and
stimulate the investment needed in flexible capacity so long as investors have the
confidence that they will be able to recoup their money based on such prices. Further,
such prices are critical in stimulating other forms of flexibility, notably in the form of
demand response – in the case where a consumer (industrial or residential) has a contract
which reflects wholesale price movements, the greater the price differences, the greater
the incentive to respond by reducing consumption and instead using energy at lower price
periods.
It is not the case, however, that all consumers will necessarily see such short-term
changes in prices. In general, consumers will be more affected by the longer-term
changes in average prices; these will more likely feed through to energy bills for reasons
explained below.
Whilst different formulas exist, unit costs in a standard fixed or variable (monthly) retail
tariff will be an average of the wholesale price over a period of time, with additional
costs added, such as network costs, taxes, etc., along with any supplier margins.
Consumers on these tariffs will be shielded from period-by-period changes in the
wholesale price, be they up or down.
Whilst the development of demand response will be enhanced by dynamic tariffs which
better reflect the wholesale price, there is no proposal for this to be obligatory. If a
consumer were to choose a tariff that mirrored the wholesale price on a 1:1 ratio,
overtime they would likely pay less as their suppliers would face lower hedging costs,
which they could then pass on to those consumers as tariff savings (lower margins). This
is illustrated in the Nordic markets, where hourly tariffs are often the cheapest on the
market for most consumers. Nevertheless, consumers whose peak consumption
consistently coincided with price peaks on the market, and who chose a dynamic tariff,
may end up paying more at the end of the billing period, reflecting their cost to the
system.
The formation of scarcity prices can be contained directly or indirectly and, in particular,
by caps on prices. These can be implemented for a number of reasons, including
technical (e.g. required as part of the operation of the programs which determine market
results), to improve the robustness of market operation (e.g. to prevent significant errors
in bidding affecting market outcomes), for competition reasons (i.e. to limit any abuse of
a dominant position), for consumer-related reasons (e.g. to limit consumer exposure to
high prices) and for financial reasons (e.g. to limit the collateral needing to be posted).
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Removing price caps
In a perfect market, supply and demand will reach an equilibrium where the wholesale
price reflects the marginal cost of supply for generators and the marginal willingness to
pay for consumers. If generation capacity is scarce, the market price should reflect the
marginal willingness to pay for increased consumption. As most consumers do not
participate directly into the wholesale market, the estimated marginal value of
consumption is based on the value of lost load (VoLL). VoLL is a projected value which
is supposed to reflect the maximum price consumers are willing to pay to be supplied
with electricity. If the wholesale price exceeds the VoLL, consumers would prefer to
reduce their consumption, i.e. be curtailed. If, however the wholesale price is lower than
the VoLL, consumers would rather pay the wholesale price and receive electricity. If
prices are prevented from reaching the VoLL through the introduction of price caps, then
short-term prices will be too low in scarcity situations. This in turn can affect investment
signals - notably, it can reduce the incentive to investment in flexible capacity (i.e. of the
type that can respond to short-term peaks in prices) and demand response.
However, currently all Member States have specific restrictions on the price to which
wholesale prices can rise. In the day-ahead market, the most common cap is EUR
3000/MWh, which is by-and-large a technical constraint rather than implemented with
the intention of keeping prices below VoLL. Some Member States have values somewhat
lower, which could introduce distortions in the price signals.
Figure 1 – Day-ahead price caps
▪ Majority: +3000 EUR/MWh
▪ GB: +3000 or +6000 GBP/MWh
▪ Greece: 150 EUR/MWh
▪ Ireland: +1000 EUR/MWh
▪ Poland: 347 EUR/MWh, +3000
EUR/MWh (x-border)
▪ Portugal/Spain: 180 EUR/MWh
Source: "Market design: Barriers to optimal investment decisions" Impact Assessment support study,
(2016) COWI
These values have limited relationship to the value of lost load and, therefore, if
maintained would prevent prices rising to the level to which society values energy. For
example, a recent study commissioned for the UK's Department of Energy and Climate
Change estimated that VoLL for Electricity in Great Britain to be GBP 10,289/MWh for
212
Removing price caps
domestic users and GBP 35,488 for SMEs on a winter peak workday (approximately
EUR 13,500/MWh and EUR 46,500/MWh at the time of writing)1
. Whilst VoLL will
change depending on the circumstances, the user and the location (it will not be the same
in all Member States), it is clearly much higher than the limits that currently exist in
many day-ahead markets. Price caps in the intraday markets show a lot less
harmonisation - see map below. Whilst the level is generally much higher - i.e. no caps in
some countries, and up to EUR 9999,99/MWh in others, and therefore are less likely to
create distortions, some Member States have price caps which will fall far below VoLL.
Figure 2 – Intraday price caps
▪ Green: No ID market
▪ Light blue: -9999,99 to +9999,99
EUR/MWh
- Stripes: DE: Discrete -
3000/+3000 EUR/MWh
▪ Dark blue: No price caps
▪ Czech: +3700 EUR/MWh
▪ Dark red:
- GB: 0/+2000 GBP/MWh
- IT: 0/+3000 EUR/MWh
- PT, ES: 0/+180 EUR/MWh
Source: "Market design: Barriers to optimal investment decisions" Impact Assessment support study,
(2016) COWI
With regards to the balancing timeframe, price caps apply to the activation (energy) part
of balancing services in several Member States. In some countries there are fixed price
caps, like +/-9999,99 EUR/MWh in Slovenia, +/-3700 EUR/MWh in Czech Republic, or
203 EUR/MWh for FRR in Lithuania. In Austria and the Nordic countries, the floor
price is equal to the day-ahead price, meaning that there is a guarantee that the payment
for energy injected for balancing is at least equal to the day ahead price. In Belgium,
1
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/224028/value_lost_load
_electricty_gb.pdf
213
Removing price caps
FRR prices are capped to zero (downward regulation) and to the fuel cost of CCGT plus
40 euros (upward regulation). Most Member States do not have price caps for capacity
(reserve) bids.
There is an important relationship between the price paid for balancing services and the
imbalance price – that is, the price determined by TSOs which producers and consumers
must pay as they use or produce too much or too little energy compared to their
contracted amount. As detailed further below, it is this real-time price which will have
the biggest impact on prices in the intraday, day-ahead and forward prices. However, it
will be heavily influenced by the price that TSOs pay for balancing services. In
particular, under the upcoming Balancing Guideline, there are restrictions on how it can
be formed based on the price paid for activation of balancing energy. The Guideline will
also require that there are no caps or floors to balancing energy prices.
Free formation of prices in the balancing market is perhaps the most important issue;
day-ahead and intraday markets effectively act as an opportunity to hedge against the
expected imbalance price - they will not buy or sell energy above this price as it will be
cheaper to be out of balance and pay the imbalance price. Therefore, the balancing price
should not mute scarcity pricing by capping prices below VoLL, else prices in the
intraday and day-ahead timeframes will not reflect scarcity, regardless of any caps put in
place.
The following diagrams illustrate the relationship between prices in each of the three
market timeframes, using the example of the imbalance price in Belgium on the 22nd
September 2015. Figure 5 shows a high imbalance price caused by scarcity due to
unplanned outages.
Figure 3 – Day-ahead spot prices as a result from the matching of orders in and the
coupling of the bidding zones in the CWE-region on the 21st
, 22nd
and 23rd
September 2015
Source: Belpex, EEX, APX
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Removing price caps
Figure 4 – Intraday prices in Belgium on 21st
, 22nd
and 23rd
September 2015
Source: Belpex
Figure 5 – Imbalance prices in Belgium on 21st
, 22nd
and 23rd
September 2015,
Source: Elia
From these, it can be seen that the market is behaving rationally - i.e. that parties are
trading in the day-ahead and intraday markets to hedge themselves. The prices are
tracking the imbalance price. If it was prevented from going above a set amount, this
would have an effect on bidding behaviour in the other two timeframes, which would
also not go above this price. As the imbalance price will change in real time, market
participants can only base their bidding in the day ahead and intraday markets based on
what they expect the price will be. Therefore, such tracking of prices across timeframes
will not happen where there are very short-term changes in the imbalance price, e.g. due
to sudden tripping of equipment.
It should be noted that there is a difference between price restrictions on the price paid
for activation of energy by TSOs in the balancing timeframe, and the imbalance price.
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Removing price caps
The former will help inform the imbalance price, but it is generally the latter that has the
most impact on behaviour in the day-ahead and intraday market.
Two issues exist relating to harmonisation of caps. Firstly, given the above, that of
harmonisation between timeframes. If caps exist in the balancing timeframe, there is little
point in having a cap higher than this in intraday or day ahead, as there will be no reason
for market parties to bid or offer energy at a higher price - i.e. because it will be cheaper
to pay the imbalance price. It is therefore important that there is consistency across
market timeframes. The second issue relates to harmonisation between markets. If there
are different price caps each side of a border, this can interfere with how energy flows in
times of system stress. Take for example Member State A with a price cap of 1000, on a
border with a Member States B whose price cap is 100. In the absence of a cap, energy
would flow to the country who valued it the most, i.e. with the higher price. However,
with these caps if there was a concurrent scarcity event which led to prices going above
100, then energy will always flow to Member State A, despite the fact that Member State
B might value energy as much or more (i.e. because the price cannot attract flows of
energy more than Member State A’s prices).
Implicit price caps can also exist. For example, in some Member States (around a third),
a shadow auction2
is triggered if prices reach 500 euros /MWh (or goes below -150 euros
/MWh). This can act as a disincentive to bid higher than EUR 500 . Other disincentives
that have been identified include: general fears about competition law – for example, the
market restricting itself out of fear of being seen to be abusing a dominant position; the
price at which strategic reserves are activated; and TSO actions based on market price.
Deficiencies of the current legislation
4.1.3.
Current European legislation contains very little reference to wholesale market prices
caps. In fact, the only reference is contained in the CACM Guideline. Specifically,
Articles 54 (covering intraday trading) and Article 41 (covering day-ahead) require
power exchanges, acting in their cross-border roles as NEMOs to propose harmonised
maximum and minimum bid prices. This needs to "take into account the value of lost
load." This proposal is due to be made to regulatory authorities by mid May 2017.
As pointed out in the Evaluation Report, normally, well-functioning wholesale markets
should provide price signals necessary to trigger the right investment. However, the
ability of markets to do so is debated today because today's electricity markets are
characterised by uncertainties as well as by a number of market and regulatory failures
which affect price signals. These include low price caps, renewable support schemes, the
lack of short term markets and lack of demand response operators.
2
Auctions run to validate that the results of the first auction are correct and not abnormal prices due to
either technical issues during the execution of the market clearing algorithms, or bidding behaviour of
market participants.
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Removing price caps
Presentation of the options
4.1.4.
Option 0: Business as usual
The option would allow for the continuation of limits on wholesale prices. This would in
principle allow for different price caps in different timeframes. However, under the terms
of the CACM Guideline it would bring harmonisation in day-ahead and intraday as there
is a requirement for a harmonised value in all bidding zones participating in market
coupling. This value would have to "take into account" the value of lost load. It would
not, however, have to represent this value and could be significantly lower. For example,
as part of the NWE market coupling project, there is a maximum clearing price of
3000euros/MWh in those bidding zones taking part in the project. This limit has been
applied to other markets, for example the German intraday auction (which takes place
after the cross-border auction) and the GB day-ahead auction (a similar process, again
after the cross-border auction, although the limit is expressed in GBP). This is most
likely due to issues of convenience and to prevent creating perverse incentives to trade in
one of the markets as opposed to another.
Option 1: Eliminate all price caps
This option would see a prohibition on all upper price restrictions in the wholesale
market, in all timeframes. It would mean that prices would be able to reach VoLL. It
would also involve a prohibition on any technical price limits imposed by power
exchanges.
Option 2: Create obligation to set price caps, where they exist, at VoLL
This option would require that, where caps exist, they shall be no lower than VoLL in all
market timeframes. This would be coupled with a requirement that Member States
establish VoLL. This option would be compatible with a technical limit imposed by
power exchanges, but would include a trigger to raise such limits in order to prevent
them constraining acurate price formation coupled with a date by which the maximum
must not be below VoLL. It would also make clear that, once at VoLL, the value need
not be harmonised.
Comparison of the options
4.1.5.
As detailed above, allowing prices to reflect scarcity, and investors having confidence
that this will be allowed to happen, is key to stimulating investment in a more flexible
system.
The options must, therefore, be assessed in this context i.e. those options which would
prevent scarcity prices forming and, in particular, reflecting the true scarcity in terms of
willingness to pay for energy, would not be compatible with the objective of creating an
energy market that is able to face future challenges and stimulate the right investments.
The 'do nothing' option would not be consistent with the set objectives – even though
harmonised maximum clearing prices would be implemented, these only have to 'take
into account' the value of lost load and there would be no way to provide confidence that
prices could indeed reach values which reflect scarcity. It would allow for price caps to
continue existing within Member States. Whilst in practice, for most Member States,
prices have not been constrained by existing caps (there have been no instances yet
where they have hit the 3000 euros mark), this is not set to remain the case forever.
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Removing price caps
Doing nothing, or relying on voluntary cooperation at the Member State level, would not
provide investors with any confidence that restrictions would be removed (or raised) in
the event they were hit and the default position is that they would remain in place. It
therefore has to be assumed that such an option would shave off the peaks in pricing.
Whilst the CACM Guideline contains a reference to VoLL, ‘take into account' is not
enforceable.
Option 1 – to eliminate any price caps - would be the option most in line with this
specific objective, in that it would allow prices to rise to any level, determined by supply
and demand fundamentals. Making a strict, EU-level prohibition may provide investors
with confidence that Member States would not intervene to keep wholesale prices low for
political reasons – e.g. because of a negative perception of the impacts of peaking prices
on consumers. This option, however, entails risks. In particular, it would prevent any
limits being used in the market coupling system or by power exchanges. This could have
technical impact on the operation of the systems used to run the markets and may
influence the amount of collateral that market parties are required to post. Market parties
are generally required to provide cash or credit to cover their potential exposure. Without
limits in the clearing price, this could become more expensive or their credit more
restrictive (e.g. on how much they can trade), as the potential exposure would be higher.
Further, it could prevent the use of any explict price-based measure to detect errors in
bidding.
Option 2 would allow for the use of limits to exist in the context of trading on the power
exchanges and only in relation to maximum and minimum clearing prices developed in
accordance with the CACM Guideline. In order to prevent such limits restricting accurate
price formation, the option would also introduce a specific requirement that they be
raised when a trigger point is reached coupled with a requirement that they be set at the
value of lost load within a certain timeframe. The option would also prohibit Member
States from introducing legal caps on the wholesale price unless this reflects a calculation
of the value of lost load.
The advantage of this approach is that it would still allow for technical limits to be
introduced by power exchanges, but would not constrain price formation and would give
investors a clear signal that Member State authorities cannot step in artificially dampen
prices. The disadvantage as compared to Option 1 is that, in order for such limits to
continue to exist and to be effective, there may need to be a time lag between the trigger
and the limit being raised. This would need to be as short as possible so not to prevent
prices from rising.
A difficulty with this option is the complexity of establishing VoLL. It will change
depending on the circumstances and the user and so one value will only ever be an
estimation.
This option would also be bundled with a requirement placed on Member States to avoid
and, where possible, eliminate any implicit price caps so not to disincentives the offering
of high prices by market participants.
The benefits of better price signals and further articulated as part of the wider option to
address uncertainty on future investments (Problem Area II, which includes policies on
locational signals, scarcity pricing and price caps, resource adequacy planning and
capacity mechanisms) in Section 6.2.2.
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Removing price caps
Subsidiarity
4.1.6.
Given that the EU energy system is highly integrated, prices in one country can have a
significant effect on prices in another. Further, if there are significant differences
between countries on the level to which wholesale prices can rise, then energy may flow
in the wrong direction during times of system stress. A coordinated and harmonised
approach is, therefore, necessary.
This topic is, to an extent, already covered under the CACM Guideline – which notably
requires the setting of harmonised maximum clearing prices which take into account the
value of lost load.
Differences in national approaches could create significant distortions in the market and
prevent the most cost-effective supply of electricity. It could also distort investment
signals, for example those countries who have a higher cap would potentially attract
more investment thnt those with a lower cap.
EU action is therefore necessary to ensure a common approach is taken which minimises
distortions in the operation of markets between Member States.
Stakeholders' opinions
4.1.7.
From the Market Design consultation, a large majority of stakeholders agreed that
scarcity pricing is an important element in the future market design. It is perceived, along
with current development of hedging products, as a way to enhance competitiveness.
While single answers point at risks of more volatile pricing and price peaks (e.g. political
acceptance, abuse of market power), others stress that those respective risks can be
avoided (e.g. by hedging against volatility).
Many submissions to the consultation highlighted the link between scarcity pricing and
incentives for investments/capacity remuneration mechanisms, as well as the crucial role
of scarcity pricing for kick-starting demand response at industrial and household level.
Key stakeholder comments included:
- "…energy prices that reflect market fundamentals, including scarcity in terms of
time and location, are an important ingredient of the electricity market design.
Undistorted prices (without regulatory intervention) should thus trigger optimal
dispatch and signal the need for investments/divestments… Price caps and other
interventions in the market hindering the appearance of scarcity prices should be
removed." Eurelectric
- "…we need to better valorize flexibility. Prices reflecting scarcity are crucial in
this context and should therefore be a key priority of the market reform… Prices
better reflecting scarcity will be more volatile and might be higher than today
during some periods of the day (assuming the end of price caps). Rather than a
challenge, this represents an opportunity as it will unlock new strategies to hedge
against risks on the wholesale market while triggering dynamic pricing offers on
the retail side." SolarPower Europe.
- "In principle, electricity prices should reflect actual scarcity so that the most
cost-efficient flexibility options on the supply and the demand side as well as the
most efficient storage solutions are employed. Prices should also reflect the
scarcity of transmission capacities within and across market borders"
EUROCHAMBERS
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Removing price caps
- "In order to provide correct price signals for new investments (both generation
and consumption), and to provide security of supply, prices which reflect actual
scarcity are an important ingredient in the future market design."
BusinessEurope
- "Citizens Advice supports efforts to move to market structures that more
accurately reflect scarcity. This is an important way of conveying price signals
reflecting the genuine value of consumption and production, at different times
and in different locations." Citizens Advice
- "…energy prices should effectively reflect both temporal scarcity and surplus in
order to adequately reward flexibility. Such an approach to energy pricing would
better facilitate the investments required to address the European energy
trilemma of sustainability, security of supplies, and competitiveness." WWF
Further, in a position paper, Wind Europe state that "[i]t is important that market prices
are undistorted and allowed to move freely without caps. Transparent market prices must
be in place in all time horizons, i.e. forward, day-ahead, intraday and real time, and also
used for settlement of remaining imbalances. This will help to incentivise and reward the
provision of flexibility services. Policy makers should be aware that price spikes are
needed to trigger the right scarcity signals on both the supply and demand side;
investment decisions based on a certain expectation of price spikes will only be made if
there is enough trust by investors that politicians will not interfere and introduce price
caps. " 3
The March 2016 Florence Forum made the following relevant conclusion:
"The Forum acknowledges the significant progress being made on the integration of
cross-border markets in the intraday and day-ahead timeframes, and considers that
market coupling should be the foundation for such markets. Nevertheless, the Forum
recognises that barriers may continue to exist to the creation of prices that reflect
scarcity and invites the Commission, as part of the energy market design initiative, to
identify measures needed to overcome such barriers. In doing so, it requests the
Commission take proper account of technical constraints that may exist."
3
https://windeurope.org/fileadmin/files/library/publications/position-papers/EWEA-Position-Paper-
Market-Design.pdf
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Improving locational price signals
4.2. Improving locational price signals
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Improving locational price signals
Summary Table
4.2.1.
Objective: The objective is to have in place a robust process for deciding on the structure of locational price signals for investment and dispatch decisions in the EU electricity
wholesale market.
Option 0 Option 1 Option 2 Option 3
Description
Business as Usual – decision on bidding
zone configuration left to the arrangements
defined under the CACM Guideline or
voluntary cooperation, which has, to date,
retained the status quo.
Move to a nodal pricing system Introduce locational signals by new means,
i.e. through transmission tariffs
Improve currently existing the CACM
Guideline procedure for reviewing bidding
zones and introducing supranational
decision-making, e.g. through ACER.
This would be coupled with a strengthened
requirement to avoid the reduction of cross-
zonal capcity in order to resolve internal
congestions.
Pros
Approach already agreed. Theoretically, nodal pricing is the most
optimal pricing system for electricity
markets and networks.
Would unlock alternative means to provide
locational signals for investment and
dispatch decisions.
This improvement will render revisions of
bidding zones a more technical decision.
It will also increase the available cross-
zonal capacity.
Cons
Risks maintenance of the status quo, and
therefore misses the opportunity to address
issues in the internal market.
Nodal pricing implies a complete,
fundamental overhaul of current grid
management and electricity trading
arrangements with very substantial
transition costs.
Incentives would be not be the result of
market signals (value of electricity) but cost
components set by regulatory intervention
of a potentially highly political nature.
Does not address the underlying difficulty
of introducing locational price zones,
namely the difficulties to arrive at decisions
that reflect congestion instead of political
borders.
Does not address a situation where the
results of the bidding zone review are sub-
optimal. I.e. this option only covers
procedural issues.
Most suitable option(s): Option 3 – this option will rely on a pre-established process but improve the decision-making so that decisions take into account cross-border impact of bidding zone
configuration. Other options – e.g. tofundementally change how locational signals are provided, would be dispropritionate.
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Improving locational price signals
Description of the baseline
4.2.2.
The internal energy market is based on the concept of bidding zones, which are defined
as "the largest geographical area within which market participants are able to exchange
energy without capacity allocation."4
They are effectively market areas within which
energy is considered to be able to flow freely and within which, therefore, there will be a
single wholesale price for any given market timeframe.
Currently, bidding zones are based on national borders, although there are some
exceptions5
.
Figure 1, Curent bidding zone configuration
Source: Ofgem, 2014
The wholesale price will be the same in one part of France as it is in another, the same in
one part of Spain as it is another part of Spain, the same in Germany as it is in
Luxembourg and Austria, and so on. The wholesale price in Italy may be different in
different parts, as it may be in Sweden and Norway.
4
Commission Regulation (EU) No 543/2013 of 14 June 2013 on submission and publication of data in
electricity markets
5
There is currently one German-Austrian-Luxembourg bidding zone, and Italy, Sweden and Norway
are split into several zones.
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Improving locational price signals
This is critical, as the wholesale price is a crucial part of determining when and where
people invest (and where there are no other revenue streams such as capacity
mechanisms, the only basis). Higher prices in one area will in theory attract investment
into that area over and above somewhere with lower prices. This locational signal in the
energy price will not exist within a bidding zone, and so will not encourage investment in
one part as compared to another and, in the case where bidding zone boundaries are
based on Member State borders, within one part of a Member State compared to another.
This is despite the fact that there may be bottlenecks within that Member State that
prevent the free flow of energy from one part to another and, hence, could create a
greater need for investment in certain geographical areas.
Further, wholesale energy prices will determine when generating plants dispatch and, to a
lesser degree (due to relative inelasticity in the demand-side) when load consumes
energy. i.e. where the price is higher than a generator's short-run marginal cost, bar any
external factors, they will run. If there are significant congestions within a bidding zone,
and the price is influenced by demand behind such congestion, generators on the other
side may still dispatch despite limited ability to transport the energy to the demand. This
can result in the so-called 'loop flow' phenomenon whereby energy will flow around the
congestions through another zone, against market price signals. These flows, as they have
not been scheduled, can have significant implications. More specifically, they can reduce
the amount of cross-border capacity made available to the market for trade and result in
costly remedial actions, for example the need to redispatch (the reduction in the amount
of power injected on one side of the congestion and, simultaneously, an equivalent
increase in the amount injected on the other side). As an example, in 2015 the total cost
for redispatching within the DE-AT-LU bidding zone was approximately 930 million
euros6
. Overall, the total welfare loss due to loop flows was estimated to be around 450
million euros in 20147
.
An improved configuration of bidding zones, one which takes account of structural
congestions within the European grid, would mitigate many of these issues, as it would
improve the locational price signals. In particular, in the short-term it would affect how
and where energy is dispatched and, for the longer-term, will improve the price signals
on where to locate new generation investments. Clearly investment in transmission
capacity is also critical, notably within a bidding zone so that energy can better flow from
one area to another. However, the bidding zone structure itself may not provide strong
signals for such investment; as Ofgem point out in its Bidding Zone Literature Review
(2014)8
, impact on investment may be muted by practical consideration, for example, due
to economies of scale, uncertainties about future generation investment, and difficulty in
centralising charges or reliability and quality of service.
6
ENTSO-E Transparency Platform, at https://transparency.entsoe.eu/
7
"Market Monitoring Report 2014" (2015) ACER – social welfare losses for both unscheduled flows
and unscheduled allocated flows.
8
https://www.ofgem.gov.uk/sites/default/files/docs/2014/10/fta_bidding_zone_configuration_literature_
review_1.pdf
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Improving locational price signals
The precise definition of bidding zones, and realising maximum benefit from it, is
complex and highly technical, and there are a number of variables which must be
considered. Therefore, a review process, to be undertaken by TSOs, has been formalised
in legislation under the CACM Guideline9
. More specifically, once a review is
launched10
, TSOs are to review the existing bidding zone configuration and alternative
bidding zone configurations, and must submit this to Member States or, where so
determined by a Member State, NRAs for a decision on whether to amend or maintain
the zones. Figure 2 below provides a summary of this process.
Figure 2, simplified flow chart of bidding zone review process under the CACM
Guideline
When undertaking a review, TSOs must consider issues relating to network security,
market efficiency, including any increase or decrease in economic efficiency of changes,
and stability and robustness of bidding zones.
A number of authors have already suggested alternative configurations, for example as
shown in figure 3.
9
In practice, work has already started on this.
10
Which can be done by ACER, NRAs, Member States or TSOs, depending on specific criteria – Article
32
Launch Review
ACER NRAs One NRA TSOs MS
TSOs: Develop methodology and assumptions NRAs
TSOs: Assess and compare, consult and submit proposal
MS (or
NRA)
MS/NRAs: Reach agreement on proposal to maintain or amend
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Improving locational price signals
Figure 3, possible alternative configuration,
Source: Supponen, Influence of National and Company Interests on European Electricity Transmission
Investments, 2011
However, as pointed out by Supponen (2011), even price zones which reflect the most
congested parts of the European grid, will not provide as efficient price signals as a
system which is based on a more granular system, such as that of nodal pricing. Nodal
pricing is a method of determining prices in which market clearing prices are calculated
for a number of locations on the transmission grid called 'nodes'. These nodes would be
determined based on the most congested points in the system. The price at each node
represents the locational value of energy, which includes the cost of the energy and the
cost of delivering it11
. This model is used in much of North America. For example, the
PJM’s system includes over 10 000 price nodes across 20 transmission control zones,
with trading available at nodes, at aggregates of several nodes, at 12 hubs consisting of
hundreds of nodes each, and at 17 import and export external interfaces. The IEA
conclude that "This nodal pricing system facilitates adjustments to dispatch in the real-
time market, efficient use of variable resources and demand-side response, and limits to
market power by individual generators"12
.
In 2014, Breuer simulated the potential price differences based on a nodal system in
Europe, comparing average across the year with times of strong wind and high load in
continental Europe.
11
Phillips, Nodal Pricing Basics, Independent Electricity Market Operator, available at
http://www.ieso.ca/imoweb/pubs/consult/mep/LMP_NodalBasics_2004jan14.pdf
12
Repowering markets
226
Improving locational price signals
Figure 4 – Nodal prices, base case (2016)
Source: Breuer, Optimised bidding area delineations and their evaluation in the European Electricity
System, Brussels, April 2014 – Nodal prices (base case) 2016
As can be seen from the above, there could be significant changes in prices in a nodal
system compared to average prices across Europe on windy days with high demand.
Such a picture serves to illustrate what the prices should be if transmission capacity were
fully taken into account. This does not cluster around the current bidding zone
configuration as shown above and suggests inaccuracy of price formation in the current
setup. It is also far from clear just from the above how this could be best grouped into a
bidding zone structure, and several possibilities exist just from this one scenario. The
complexity could be further increased when looking at alternative scenarios (e.g. high
wind/low demand, etc.).
It is therefore concluded that it is correct to rely on a technical analysis where the costs,
benefits and practical considerations (including those listed in the CACM Guideline) will
be considered – this is much more likely to result in a more optimal configuration than
the one currently seen. The issue at stake, therefore, is how to make any change based on
the outcome of the review pre-establishing under the CACM Guideline, or whether to
move to a wholly different arrangement for locational signals such as the mandatory
introduction of locational elements in transmission changes or moving to a nodal system
Cross-zonal capacity calculation
With a, theoretical, 'perfect' bidding zone configuration, the only congestion would be on
a bidding zone border. Therefore, there would be no internal constraints that would cause
reductions in cross-border capacity. However, even if and when a configuration is
implemented that better reflects structural congestion, there will still be internal
congestion. The Electricity Regulation states that:
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Improving locational price signals
"TSOs shall not limit interconnection capacity in order to solve congestion inside
their own control area, save for the abovementioned reasons and reasons of
operational security"13
There is, however, evidence that cross-zonal (interconnection) capacity is indeed being
limited in order to deal with internal issues. In its Market Monitoring Report, ACER
analysed the ratio between thermal capacity (the theoretical maximum capacity) of
interconnectors and the capacity offered for trade (with Net Available Capacity – NTC
Capacity). The results showed that the ratios varied significantly and that on a number of
borders the NTC was significantly below the thermal capacity.
Figure 5 – Ratio between available NRC and aggregated thermal capacity of
interconnectors – 2014 (%, MW),
Source: ACER/CEER Market Monitoring Report 2015.
ACER concluded that "these results indicate that on the borders on the right side of the
figure either the internal congestions are shifted to the border, or those borders are
affected by a significant amount of unscheduled flows."
Regardless of the reason, the impact of this is the reduction of cross-border trade and has
resulted in the need to curtail capacity the other side of the border. The German-Danish
border provides an example of the sorts of impacts this can have. The below graph shows
the average interconnection capacity was 250MW on DK1-DE in 2015, 15% of the
maximum capacity. An investigation for the Danish TSO energinet.dk and the relevant
13
Annex I section 1.7
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Improving locational price signals
German TSO TenneT found that a minimum capacity of 1.000 MW will bring a social
economic benefit to the region of approximately 40 million euros per annum14
.
Figure 6: Monthly average NTC as part of total transfer capacity (2009-2016).
Source: energinet.dk as reported by the Danish Energy Regulatory Authority
15
Deficiencies of the current legislation
4.2.3.
The most relevant legislation is the Electricity Regulation, which contains a detailed
Annex on congestion management. However, it does not define bidding zones. In Section
1.7 it states that "when defining appropriate network areas in and between which
congestion management is to apply, TSOs shall be guided by the principles of cost-
effectiveness and minimisation of negative impacts on the internal market in electricity."
More detail is provided under the CACM Guideline, which contains a detailed approach
to reviewing and defining prices zones (Articles 32 through 34), as detailed above.
Following TSOs' review and proposals Member States are required to "reach an
agreement on the proposal to maintain or amend the bidding zone configuration."
This approach lends itself to the maintenance of the status quo as there are likely to be
competing interests at stake. In particular, some Member States are unlikely to want to
amend bidding zones where it would create price differentials within their borders; it is
sometimes considered to be right for all consumers to pay the same price within a
Member State, and for all producers to receive the same price. The current legislation
does not, therefore, provide for the socially optimal solution to be agreed.
14
Investigation of welfare effects of increasing cross-border capacities on the DK1-DE interconnector.
Institute for Power Systems and Power Economics. RWTH Aachen University. June 2014. Study
commissioned by TenneT and Energinet.dk.
15
"STUDY ON CAPACITY REDUCTIONS ON THE GERMAN – WESTERN DANISH BORDER (DE-
DK1) (Tender for Offers)" - http://f.industry-supply.dk/2bjt3mw1t748a8fa.pdf
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Improving locational price signals
With regards to cross-zonal capacity, the current terms of the Electricity Regulation are
unclear and allow for different interpretations and application.
The Evaluation Report concludes that "the Third Package clearly lacks rules for the
development and functioning of short markets as well as rules that would enable the
development of peak prices reflecting actual scarcity in terms of time and location," and
that "given the economic importance (and distributive effects) of the decisions TSOs have
to agree on, experience has shown that voluntary cooperation between TSOs was not
able to overcome the problems that block progress in the internal electricity market (e.g.
definition of fair bidding zones, effective cross-border curtailments)"
Presentation of the options
4.2.4.
Option 0: BAU and stronger enforcement
This option would entail relying on existing legislation to improve the configuration of
bidding zones. The likelihood of seeing any meaningful change as a result of this process
is minimal. Existing provisions under the Electricity Regulation are arguably not
sufficiently clear and robust to enforce a structure which reflects systematic constraints in
the interconnected system. The provisions of the CACM Guideline do not provide for a
clear decision-making process which provided any degree of certainty that the change
will be made, but rather it is left to individual Member States to make the decisions even
though these decisions have significant cross-border impacts.
Voluntary cooperation
As highlighted above, the evidence suggests that voluntary cooperation will not result in
progress in this area, as there has been to date already significant opportunity to effect the
necessary changes voluntarily.
Option 1: Move to a nodal-pricing system
A nodal pricing system would be the most granular way of determining location-based
energy prices. In theory, this would eliminate the need for remedial actions by the TSO to
alleviate congestion as the price of energy would determine exactly where it should be
dispatched from. It would also create more accurate investment signals in new generation
and infrastructure – in the case of the former in areas with higher prices, reflecting more
scarcity.
Moving to a nodal pricing system would require a fundamental change in the way
European energy markets are structured – current arrangements for cross-border trading
(market coupling) would need to be redeveloped, implying significant IT and procedural
changes. It would also be a significant change for market participants. The cost impact of
this would, in the short-term, likely out weight the benefits.
Option 2: Introduce locational signals through other means
It is possible to introduce signals for investment and/or dispatch through other means
than a market-based energy price. The main alternative method is through transmission
tariffs – i.e. charging generators less in areas where more capacity and energy is required,
and more where it is not. This can provide effective signals. It would mean a fundamental
change to the tariffs structure as around half (15) of Member States do not apply
transmission tariffs to generation. Further, this would not necessarily affect dispatch as, if
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Improving locational price signals
charges are based on capacity, it becomes part of a generators fixed cost and will not
affect when they generate. Moving to 'energy-based' charges could add distortions into
the market as it would be very difficult to engineer this in a way which reflected the
congestion and the dynamic-nature of production. Indeed, ACER has recommended the
removal of energy based transmission charging on generators.
Option 3: Improve bidding zone review and decision-making process
As mentioned above, a review process is already detailed as part of the CACM
Guideline. There is a requirement to review both existing and possible alternative
configurations, the latter of which is triggered by specific circumstances. This option
would see a strengthening of the decision-making process as a result of the review, in
particular to ensure that the cross-border impacts of bidding zone configurations are
appropriately taken into account. This would be achieved explicitly clarifying existing
requirements for price zone borders to be based on congestion and not Member State
borders. Procedurally, more powers would be given to EU institutions to decide on price
zone configuration following the review. There could also be some amendments to the
review process itself to ensure that it can show the optimal solution.
The option would be coupled with strengthened legal provision that make clearer the
allowed derogations to the overriding rule that cross-zonal capacity must not be limited
to solve internal congestion, and make any derrogation subject to regualtory oversight.
Comparison of the options
4.2.5.
Maintaining the current system of review, and leaving the final decision-making in the
hands of national authorities, would be the simplest option and the one which would
yield the least disruption. However, as highlighted above, the process lends itself to
maintenance of the status quo as decisions will be made on an individual, rather than
collective basis. Difficulties have already arisen in the process (relating to some
ambiguities in the current legislation). The benefits of price zone boundaries, reflecting
structural congestions would not be seen, or would only partially be realised, if there is
no coordinated decision. These have been estimated to be between 300-400 million euros
per annum16
to around 800 million euros17
.
The second option (Option 1), to move to a nodal pricing system, would be the most
complex to implement. It would involve a complete redesign of the current system. It
would involve fundamentally moving away from the current market setup and would
significant changes to trading arrangements. By way of example, the current approach for
coupling national markets would likely need to change significantly, which would
involve large changes to IT and practices of traders, TSOs, power exchanges, suppliers
and generators. The costs of change would be significant. Burstedde, in an analysis of a
number of central European countries18
found that there would be overall savings in the
16
Bauer, ibid.
17
Duthaler, C. (2012): "A network and performance based zonal configuration algorithm for electricity
systems", Dissertation, EPFL, Lausanne (Switzerland)
18
Comprising of AT, CH, DE, NL, VE and FR
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Improving locational price signals
total cost of electricy supply from a nodal model, compared to a model based on bidding
zones around Member State borders, of around 940 million euros, mostly due to
redispatch costs. However, she also concluded that "the increase in overall system costs
which results from aggregating nodes into zones remains negligible in relative terms" and
that there would be savings from any move from nationally-based bidding zone
borders19
.
The assessment of a nodal model will also form part of the review of bidding zones
structures by TSOs – it is therefore considered premature to conclude that Europe should
move to such a model before this review has concluded; the process will allow a proper
assessment of the different options and a decision can be taken on the basis of this.
Option 2 would require the introduction of administered locational signals. It is very
unclear what the costs and benefits of this approach would be, given that it would depend
on the prices set. If it were done on a capacity basis it would only impact the investment
signals, and not dispatch signals. If it were done on an energy basis, then it could add
significant distortions, e.g. by changing the merit order between different plants. This
would be counter-productive and erode the benefits from the market design initiative.
Option 3 builds on the system already established in the EU, as well as processes already
developed as part of the CACM Guideline. However, by moving to a more coordinated
decision-making process, one which does not prejudice the assessment of the benefits
and the costs of potential alternatives by TSOs, the likelihood that decisions are taken
which reflect the cross-border impacts of the bidding zone structure is greatly increased.
A more appropriately defined bidding zone structure could reduce the need for remedial
actions, such as redispatch, reduce unscheduled flows in the form of loop flows, and
improve signals for investment. Even so, an improved bidding zone structure would not
eliminate internal congestion. Strengthened provisions in the Electricity Regulation to
provide very clear rules on when cross-border capacity can be limited will help alleviate
the economic impacts of this happening in order to address internal issues.
The benefits of better locational signals are further articulated as part of the wider option
to address uncertainty on future investments (Problem Area II, which includes policies on
scarcity pricing and price caps, resource adequacy planning and capacity mechanisms) in
Section 6.2.2.
Subsidiarity
4.2.6.
Networks in the EU energy market are highly meshed and therefore energy trading in one
part has a significant part on another part. There are, however, naturally bottlenecks in
the system that prevent unhindered flow of energy – termed congestion. These do not
necessarily (and, in the case of the continental and Nordic synchronous areas) follow
Member State borders.
The Third Package already contains provisions relating to congestion management,
requiring procedures to be put in place, which is further elaborated by the CACM
19
Around 280 million euros in the case of moving to 9 zones.
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Improving locational price signals
Guideline. It is important to have a harmonised approach to the management congestion
in order to manage it cost-effectively across the market and allow for maximum cross-
border trading.
Markets are split based on price zones, where the wholesale price is the same for each
given timeframe. These provide locational signals for dispatch and investment.
Whilst the Third Package has achieved much, further action is needed at the EU-level –
price zones based on Member State borders do not reflect the actual locational need for
investment or demand for energy in a particular location. More coordinated action is
therefore necessary to direct dispatch of energy and investment in infrastructure based on
where it is needed and will provide most benefit to the EU interconnected system as a
whole. This will become increasingly important with more and more variable sources of
generation coming online over the coming years.
Action is already underway reviewing the structure of price zones in the EU. However,
the decision-making is still left at the national level, which lends itself to maintenance of
the status quo, which can have negative cross-border impacts (such as unscheduled flows
of energy from one country to another as a result of inefficient price signals).
Stakeholders' opinions
4.2.7.
A large number of respondents to the Energy Market Design consultation agreed that
energy prices should not only relate to time, but also locational differences in scarcity
(e.g. by meaningful price zones or locational transmission pricing). While some
stakeholders criticised the current price zone practice for not reflecting actual scarcity
and congestions within bidding zones, leading to missing investment signals for
generation, new grid connections and to limitations of cross-border flows, others recalled
the complexity of prices zone changes and argued that large price zones would increase
liquidity.
WindEurope (formally EWEA) commented that "[w]holesale electricity prices reflecting
scarcity and physical constraints, including transmission capacity, are desirable in a
fully functional electricity market. This is already expressed in the present zonal pricing
model inside bidding zones and between bidding zones where price differentials signal
the need for transmission investments."
In their joint response to the consultation, ACER/CEER stated that "[p]rices reflecting
scarcity (both in terms of time and location) of generation resources in each bidding
zone of organised markets in the different timeframes (day-ahead, intraday and
balancing) should become a key ingredient of the future market design."
EURELECTRIC "generally favours larger bidding zones as they present more
advantages for the functioning of the market and its liquidity, however bidding zone
configuration should duly take into account the grid capacity. Zones should respect
structural bottlenecks that do not necessarily correspond to national borders."
The European Association for Storage of Energy (EASE) said that "[p]rices need to
reflect the physical limitations of the grid in order to deliver optimal locational signals
for investment, consumption and production."
Another is example is that of Norderegi, who view is that "[f]undamentally, the borders
between Bidding Zones should be based on the physical characteristics of the power
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Improving locational price signals
system. Bidding Zones should be aligned with where structural constraints occur.
Leading principle is that cross border trade must not be restricted. Moving internal
national transmission bottlenecks to national borders must not be used as a congestion
management method."
On the other hand, some stakeholders highlight risks to changes in price zone
configuration. For example, the European Energy Exchange (EEX) states that "The
development towards large, cross-border bidding zones supports the efficiency of the
power system by integrating markets. Supply and demand can be brought together more
efficiently. The prerequisite for this is grid expansion. Delayed or insufficient grid
expansion even in a national context has a negative impact on the market as a whole, as
is currently seen in the discussion of splitting the German/Austrian bidding zone. Such a
decision would be a huge step back in the creation of the internal market, splitting
Europe’s most liquid bidding zone, decreasing the possibilities of risk mitigation and
eventually causing higher energy prices for consumers."With regards to congestion
management, there have been significant concerns raised by industry about the practice
of limiting cross-border capacity to deal with internal congestion. For example,
Nordenergi have said, in a public letter to the European Commission, that the "principle
that congestion needs to be managed where it occurs must be maintained as the
governing rule in an internal market, and this principle does not allow for congestion to
be moved to national borders in the extent and in the non-transparent manner that seems
to be the case on the mentioned Nordic borders" and that "besides the continuous welfare
losses due to curtailments of cross-border capacities, there are in addition severe long-
term negative effects through inefficient investment signals to both generators,
consumers and TSOs."
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Minimise investment and dispatch distortions due to transmission tariff structures
4.3. Minimise investment and dispatch distortions due to transmission tariff
structures
235
Minimise investment and dispatch distortions due to transmission tariff structures
Summary table
4.3.1.
Objective: to minimise distortions on investment and dispatch patterns created by different transmission tariffs regimes.
Option 0: Business as usual Option 1: Restrict charges on producers
(G-charges)
Option 2: Set clearer principles for transmission
charges
Option 3: Harmonisation
transmission tariffs
Description
This option would see the status quo
maintained, and transmission tariffs set
according to the requirements under Directive
72 and the ITC regulation.
Stronger enforcement and voluntary
cooperation:
There is no stronger enforcement action to be
taken that would alone address the objective.
Voluntary cooperation would, in part, be
undertaken as part of implementation of
Option 2.
This option could see the prohibition of
transmission charges being levied on
generators based on the amount of energy
they generate (energy-based G-charges)
This option would see a requirement on ACER to
develop more concrete principles on the setting of
transmission tariffs, along with an elaboration of
exiting provisions in the electricity regulation where
appropriate.
Full harmonisation of
transmission tariffs.
Pros
Pros: Minimal change; likely to receive some
support for not taking any action in the short-
term.
Eliminating energy-based G-charges
would serve to limit distortionary effects
on dispatch of generation caused by
transmission tariffs. Social welfare
benefits of approximately EUR 8 million
per year. Would impact a minority of
Member States (6-8 depending on design).
Provides an opportunity to move in the right direction
whilst not risking taking the wrong decisions or
introducing inefficiencies because of unknowns;
consistent with a phased-approach; could eliminate
any potential distortions without the need to mandate
particular solutions; consistent with the introduction
of legally binding provisions in the future, e.g.
through implementing legislation.
Minimises distortion between
Member States on both
investment and dispatch;
creates a level-playing field.
Cons
In the longer-term, likely to be a drive to do
more and maintaining the status quo unlikely
to be attractive; risks of continued divergence
in national approaches.
Social welfare benefits relatively small –
could be outweighed by transitional costs
in the early years. Can be considered
'incomplete' as a number of other design
elements of transmission tariffs contribute
to distortionary effects.
Still leaves the door open for variation in national
approaches; will not resolve all potential issues.
Unlikely to a proportionate
response to the issues at this
stage; given the technicalities
involved, it could be more
appropriate to introduce such
measures as implementing
legislation in the future.
Most suitable option(s): Option 2 – aside from some high-level requirements, given the complexity of transmission charges, the precise modalities should be set-out as part of implementing
legislation in the future if and when appropriate. The value in Option 2 will be to set the path for the longer-term.
236
Minimise investment and dispatch distortions due to transmission tariff structures
Description of the baseline
4.3.2.
Tariffs are charged on demand and/or production in order to recover the costs associated
with building, maintaining and operating transmission and distribution infrastructure.
They can be used merely as a cost recovery tool, but also as a means to incentivise
investments and behaviours. They also have the potential to have distortionary effects. In
this annex, the focus is on the design of transmission tariffs, with distribution tariffs
discussed further in Annex 3.3. However, there are potentially important interactions,
which are touched on further below.
There are a number of decisions that regulatory authorities can take on the design of
tariffs. These are summarised below:
Figure 1 – building blocks of transmission tariffs
Source: Cambridge Economic Policy Associates Ltd for ACER.
237
Minimise investment and dispatch distortions due to transmission tariff structures
The Third Package, and more specifically the Electricity Directive and Electricity
Regulation, contain specific provisions for the charging of transmission tariffs.
Requirements under the Directive include that tariffs, or the methodologies for
calculating them, must be fixed or approved by NRAs in accordance with transparent
criteria20
and sufficiently in advance of their entry into force21
.
Article 14 of the Electricity Regulation provides further requirements, which include:
- that "[c]harges applied by network operators for access to networks shall be
transparent, take into account the need for network security and reflect actual costs
incurred insofar as they correspond to those of an efficient and structurally
comparable network operator and are applied in a non-discriminatory manner;" and
- that, "[w]here appropriate, the level of the tariffs applied to producers and/or
consumers shall provide locational signals at Community level, and take into account
the amount of network losses and congestion caused, and investment costs for
infrastructure."
More specific requirements are provided for under the inter-transmission system operator
compensation mechanism ("ITC") regulation22
. This regulation sets down limits on the
average annual transmission charges that can be applied in each Member States to
electricity producers23
. The regulation also required ACER to provide an opinion to the
Commission regarding the appropriateness of the range of charges, which it did on 15th
April 2014.
In the opinion, ACER stated that it deemed it important that charges on generators ("G-
charges") are "cost-reflective, applied appropriately and efficiently and, to the extent
possible, in a harmonised way across Europe." It recommended that: G-charges based on
energy produced (energy-based) should not be used to recover infrastructure costs;
energy-based G-charges should be set at 0 euros/MWh, except where they are used for
recovering the costs of system losses or costs relating to ancillary services. They
concluded, however, that it was unnecessary to propose restrictions on charges based on
connected capacity of the generation (what they term power-based charges) or fixed
(lump sum) charges.
However, prior to this opinion, a report by Frontier Economics for Energy Norway,
published in May 201324
, concluded that the potential for welfare loss is significant, with
effects on investment more significant than operational decisions, and strong welfare
losses result from a lack of harmonisation.
20
Art 37(1)(a)
21
Art 37(6)(a)
22
Commission Regulation (EU) No 838/210 of 23 September 2010 on laying down guidelines relating to
the inter-transmission system operator compensation mechanism and a common regulatory approach
to transmission charging, OJ L 250 24.09.2010, p5-11
23
0-2 EUR /MWh in Romania; 0-2.5 EUREUR /MWh in UK and Ireland; 0-1.2 EUR/MWh in Denmark,
Sweden and Finland; and 0-0.5 EUR/MWh in all other Member States.
24 "
Transmission tariff harmonisation supports competition", a report prepared for Energy Norway, May
2013
238
Minimise investment and dispatch distortions due to transmission tariff structures
Subsequently, and with the possibility existing to develop a 'network code25
' to
harmonise transmission tariffs, ACER commissioned a scoping study from Cambridge
Economic Policy Associates Ltd (CEPA), which was finalised in August 2015. CEPA
concluded that, whilst there are theoretical distortions introduced by different charging
regimes in different Member States, the benefits of a short-term regulatory response (e.g.
harmonising through a network code) were unlikely to outweigh the potential costs of
change. However, they also concluded that in the longer-term, there is a stronger case for
further harmonisation "principally based on the need for greater consistency and
application of "optimal" tariff structure that reflect the costs generating by market
participants' decisions."
Figure 2 – Connection and generation tariffs in various countries
Source: Cambridge Economic Policy Associates Ltd for ACER, based on analysis of ENTSO-E data.
Deficiencies of the current legislation
4.3.3.
As detailed above, a framework for transmission tariffs is provided for in the Electricity
Directive, Electricity Regulation and in the ITC Regulation26
. These all provide
significant scope for national differences without a view on how any potential negative or
distortionary impacts can be resolved. Further, the ACER recommendation has not been
implemented into the ITC Regulation.
25
A Commission Regulation developed under procedures laid down in the Electricity Regulation.
26
Commission Regulation (EU) No 838/2010 of 23 September 2010 on laying down guidelines relating
to the inter-transmission system operator compensation mechanism and a common regulatory
approach to transmission charging, OJ L 250, 24.9.2010, p. 5–11
239
Minimise investment and dispatch distortions due to transmission tariff structures
The Evaluation Report points out that "whilst the Third Package contains provision on
transmission tariffs, their level and design still differ significantly between Member
States. This has the potential to distort price signals."
Presentation of the options
4.3.4.
Option 0 – BAU
This option would involve maintaining the status quo, and the provisions relating to
tariffs in the Third Package and associated legislation would remain the same.
Option 0+: stronger enforcement and voluntary cooperation
There is no additional enforcement action to take that would address the points above.
Option 2 would entail a level of voluntary cooperation as part of its implementation – i.e.
that regulatory authorities voluntarily work towards implementation of key principles
developed by ACER in advance of further legally binding obligations.
Option 1 - Restrict charges on producers (G-charges)
This option would involve eliminating energy-based transmission charges that can be
charged on producers (except where they are used for recovering the costs of system
losses or costs relating to ancillary services), as set out in the ACER opinion. It would
have an effect in the following Member States, who apply such charges27
.
- Denmark
- Finland
- France
- Portugal
- Romania
- Spain
In implementing this option, those Member States would have a choice as to how they
then treat generators. They could either remove charges on generators all together,
meaning that all tariffs would be charged to consumers, or they could replace them with
alternative tariffs, namely ones based on the capacity or a lump-sum tariff. For the
purposes of this analysis, it is assumed that these Member States continue to levy charges
on generators.
Option 2 - Introduce more extensive and concrete principles on the setting of
transmission charges
This option would involve giving responsibility to ACER to develop guidance addressed
to national regulatory authorities, which would be developed over a time frame of 1-2
years. It would provide a basis on which NRAs could make their decisions with a view to
27
Excluding Austria and Belgium, who apply energy-based charges for ancillary services and/or losses
240
Minimise investment and dispatch distortions due to transmission tariff structures
more concrete legal measures in the future, notably though implementing legislation such
as a network code or guideline. Such principles could relate to: the definition and
implementation of cost-reflectivity; charges applied to consumers versus charges applied
to producers; the types of costs which are to be included; locational and/or time-of-use
element of charges; and principles relating to transparency and predictability. It would be
accompanied by some higher-level principles in legislation, for example requiring
regulatory authorities to minimise any distortions between transmission and distribution
tariffs - e.g. on their impact on generators.
Option 3 - Full harmonisation
This option would not only see the process and criteria harmonised but also the
components and levels of transmission charges so that the charges on load and
production and comparable in each Member States. This would include the elaboration of
a harmonised definition of cost-reflectivity, so that all Member States charge producers
and/or consumers on the same basis. Further, it would ensure that costs related to
ancillary services and losses are treated in the same way.
This option could be accompanied by a requirement that transmission charges include a
locational element reflecting, in particular, transmission constraints within a price zone.
Comparison of the options
4.3.5.
G-Charges
The option to remove energy-based transmission tariffs on generators has been assessed
quantitatively based on ECN's COMPETES model28
. COMPETES is a power
optimisation and economic dispatch model that seeks to minimise the total power system
costs of European power market whilst accounting for the technical constraints of the
generation units, transmission constraints between the countries as well as transmission
capacity expansion and generation capacity expansion for conventional technologies for
given generation intermittency (e.g., wind, solar) and RES E penetration in EU Member
States. The model also decommissions the existing conventional power plants that cannot
cover their fixed costs.
In order to provide a frame of reference, three scenarios were assessed as regards the
change on total system costs29
, TSO surplus30
, payments by consumers31
and producer
surplus32
for a reference year of 2030:
- Reference case where no tariffs are charged. Implicitly, therefore, all the
transmission costs are covered by congestion income and electricity prices
28
" Transmission Tariffs and Congestion Income Po6licies", ECN, DCision, Trinomics (Intermediate
Report)
29
Generation OPEX + Generation CAPEX + Fixed O&M + Transmission Investment
30
G-charge payments + Congestion income - Transmission CAPEX
31
Payments consumers make for their electricity use, i.e. electricity use (in MWh) x electricity price (in
Euro/MWh)
32
Short run profits - Gen CAPEX - G-charge payments
241
Minimise investment and dispatch distortions due to transmission tariff structures
charged to consumers - this was created for the purposes of assessing the options
below, as opposed to being an option itself.
- Option 0: Reflecting the current situation with different G-tariffs per country
(Euro/MWh or Euro/MW differing per country). The tariffs are taken from the
ACER internal G-charges monitoring report.
- Option 1: Implementing capacity-based tariffs only in which case energy-based
Euro/MWh tariffs of Option 0 are converted to Euro/MW capacity-based tariffs.
A figure for the total social welfare was calculated as {Change in TSO surplus + Change
in Producer surplus - Change in Consumer payments}. The results for the total and
comparison of the options are provided in table 1 and 2 respectively.
Table 1 – total values, all countries (million EUR)
System
Costs
TSO
surplus
Consumer
payments
Producer
surplus
Reference (no tariffs) 85,082.2 2,102.3 226,821.0 138,455.7
Option 0 (current
situation) 85,094.7 3,044.6 227,617.6 138,282.9
Option 1 (cap.-based
tariffs) 85,094.0 2,875.1 227,298.2 138,141.1
Table 2 – option comparison, all countries (million EUR)
System
Costs
TSO
surplus
Consumer
payments
Producer
surplus
Social
welfare
Option 0 vs
Reference 12.5 942.3 796.6 -172.8 -27.1
Option 1 vs
Reference 11.8 772.8 477.2 -314.6 -19.0
Option 1 vs
Option 0 -0.8 -169.5 -319.4 -141.8 8.1
Moving from the current system (Option 0) would result in an increase in economic
efficiency of generation dispatch and investment decisions as well as overall competition
between generators. More specifically, there would be some limited effect on dispatch
and investment decisions of generators in countries that have to replace energy-based by
capacity-based or lump sum G-charges. On the other hand, decisions of generators in
countries that currently either have no energy-based G-charges or only non-energy based
G-charges in place would not be affected. Cross-border competition between generators
is likely to induce regulatory competition between Member States and, as such, likely to
serve as an implicit upper limit to all types of G-charges, preventing larger divergence of
within the EU. However, this this does not imply that G-charges will be set to their
optimal long-run cost-reflective level i.e. the level that stimulates generators and
consumers to take investment and siting decisions that minimise overall system costs,
which is the sum of generation, network, and societal costs. Rather it is likely that the G-
charges of the largest Member States in Continental Europe become the benchmark. In
the absence of incentives for multilateral coordination of country practices regarding
transmission charges for generators (either regional or EU-wide), this option can
therefore be considered as incomplete. As can be seen from the above, the social benefits
of moving from the current system would be in the region of EUR 8 million a year – a
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Minimise investment and dispatch distortions due to transmission tariff structures
small proportion of overall system costs. This risks being outweighed by implementation
costs.
Principles for transmission charges
It is naturally more difficult to quantitatively assess the impacts of this option, as they
will by-and-large depend on the precise design of such principles and the extent to which
they are implemented prior to any legal mandate (e.g. from implementing legislation
such as a network code). Therefore this option is assessed qualitatively.
A harmonisation of the tariff principles to better reflect the grid costs will have a positive
impact on the efficiency of dispatch and investment decisions by generators. Concerning
the latter, harmonised tariff principles will improve the investment climate for power
generation by offering a higher predictability with regard to the expected tariff
development. It will overall reduce competition distortions amongst generators, but the
impact of tariff harmonisation on the competitiveness of individual generators can be
positive or negative depending on the current situation.
As discussed above, there are a number of issues that need to be addressed in the design
of tariff structures. These include the extent to which charges are applied to generators as
compared to consumers (the Generation: Load or "G:L" split), the basis on which they
are charged, the interpretation of the principle of 'cost reflectivity,' whether there are
signals on location or time of use, etc. Whilst the discussion here has mostly been
focused on generators and the wholesale market, a significant proportion of transmission
tariffs on are charged on consumers/load – all Member States apply charges to load, with
some applying all of them (15). Therefore the design of tariff structures can have a
significant impact on consumers, both financially and economically, and on their
behaviour. There are clearly a number of complexities which will need discussion among
regulators, TSOs and stakeholders to determine the most beneficial approach.
Despite the fact that national tariff differences are only one of the drivers of current
distortions of dispatch and investment decisions between Member States, the focus on
cost reflectivity of transmission signals is key in an increasingly interconnected system in
order to prevent negative spill-over effects.
Harmonisation
Full harmonisation would involve decisions on many of the same topics as mentioned
above, but determining them in legislation immediately. It would require upfront
decisions on the 'optimal' tariff structure, something that so far has not been determined
with a clear articulation of the benefits. As mentioned above, there already exists a legal
mechanism for harmonising tariffs – Article 8 of the Electricity Regulation already
provides the ability to create implementing legislation, in the form of a network code,
something that would be developed collaboratively by TSOs, regulators, ACER and
stakeholders. Doing this as part of Market Design is very unlikely to elicit better results
than could be achieved with the detailed and ongoing participation of experts that the
development of a network code would involve. Further, flexibility would be
compromised. Given the complexity and the amount of 'unknowns' there is a significant
risk that any attempt to fully harmonise would result in issues that could only be
identified once Member States start to implement the requirements; a network code
allows for significantly more flexibility to respond to such issues if and when they arise.
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Minimise investment and dispatch distortions due to transmission tariff structures
Requirements set out in an ordinary legislative act would prove much more difficult to
adapt.
There are two sub-issues that have also been considered as part of this option: that of
harmonised charges relating to ancillary services and grid losses; and locational-
charging.
There is significant diversity in charging methodologies with regards to ancillary
services. For instance, in most Member States, all costs for balancing services are
recovered via charges on load. Only in a few Member States do generators pay grid
charges that comprise a specific contribution for the cost related to balancing services33
.
With regards to grid losses, again most European countries recover them through charges
on load, but in a few countries the related cost is partly or fully charged to generators34
.
If charges for ancillary services were to be harmonised, the impact on short-term and
long-term electricity system efficiency would depend on the level of the charges and the
charging modalities but may not be substantial. If charges for ancillary services were to
be more correctly and transparently allocated to the market parties (generation and load)
on basis of needs of the parties, market operators would contribute to minimising the
overall need for such services, particularly frequency-related services, with more flexible
demand and supply. It could, however, contribute to a higher cost-reflectiveness and
fairer cross-border competition amongst generators as the currently diverging charging
practices and cost allocation can lead to competition distortions between power
generators active in the same integrated regional market.
The impact of a harmonised charging method of grid losses via a specific tariff on the
short-term and long-term electricity system efficiency would be very limited. Only if grid
losses are calculated and charged individually to grid users would there be a higher
impact on the short and long-term system efficiency. There is, however, scope to correct
competitive distortions on generators, although this will only have an impact in those few
Member States where losses are (partly) charged to generators; in the large majority of
Member States grid losses are entirely charged to load.
33
Austria (2.81 EUR/MWh in 2015), Belgium (0.9111 EUR/MWh, which represents 50 % of the overall
reservation cost for balancing services), Bulgaria (3.65 EUR/MWh to be paid only by wind and solar
generators to cover the cost for balancing services), Finland (0.17 EUR/MWh), Ireland (0.3
EUR/MWh), Northern-Ireland (0.31 EUR/MWh), Norway (0.21 EUR/MWh – the costs for procuring
balancing services are in Norway divided equally between generation and load) and Sweden (0.087
EUR/MWh). In Great Britain, the costs incurred by the TSO (NGET) in balancing the transmission
system are recovered through Balancing Services Use of System (BSUoS) Charges, which are shared
equally between generators and suppliers. ACER, Internal Monitoring Report on Transmission charges
paid by the electricity producers, May 2016.
34
Austria (0.45 EUR/MWh in 2015), Belgium (balancing responsible parties are obliged to inject,
depending on the time, 1.25 or 1.35 % more than their offtake from the grid), Greece (average = 1.08
EUR/MWh based on zonal Generation Losses Factors), Ireland and Northern-Ireland (1.36
EUR/MWh), Norway (average = 0.57 EUR/MWh based on marginal loss rates which are different
depending on the location and the time), Romania (0.23 EUR/MWh) and Sweden (0.40 EUR/MWh) -
ACER, Internal Monitoring Report on Transmission charges paid by the electricity producers, (May
2016).
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Minimise investment and dispatch distortions due to transmission tariff structures
With regard to providing appropriate locational signals for investment and dispatch of
generation through tariffs, clearly this can only be achieved where generators are charged
tariffs (so in 12 Member States) and, with regards to the latter, only where there is
energy-based charging (8 Member States). Administratively setting tariffs to affect
dispatch could add significant distortions into the energy market and requiring this is not
an option that is explored further. As to investment signals, i.e. making it more expensive
to locate in areas of less need, and less expensive in areas of higher need, proponents
would argue that it gives economic signals about where to site new generation capacity
and use existing capacity, and that it reflects the costs to the transmission network that
generators cause. However, opponents believe that locational charging is designed to
reflect a generating mix predicated on generation close to centres of demand and not
designed to encourage a fundamental shift to more mixed and geographically spread
energy supply. Any concrete impact of location-based charging on economic efficiency
will largely depend on the level of the fee and its form, and it is not clear that this would
override other factors influencing siting (regulatory, planning, meteorological, etc.).
Further, it is potentially complex to implement and could add uncertainty to generators. If
price zones are formed based on structural congestion, part of an objective of Market
Design (see Annex 4.2) this could anyway remove the need to introduce locational
signals by other means – i.e. as the energy price would provide such signals. This is not
to say that the approach is not succeeding in those countries that already employ it (e.g.
GB, Sweden) or that it is definitely unsuitable for the future, but rather that the first step
should be to implement appropriate defined price zones and that further, detailed
consideration is needed at the regulatory level on whether and how to implement such an
approach. It is, therefore, not considered an appropriate response to design or mandate its
introduction as part of this legislative package.
Summary
Given the number of design features and complexities regarding transmission tariffs, and
the potentially small benefits associated with harmonising the less-complex aspects
individually, it is concluded that the most appropriate option is to leave any full
harmonisation to future implementing legislation as part of a network code or, if
appropriate, through an amendment to existing implementing legislation35
. This will
minimise disruption and implementation costs, allow the precise package to be worked
up over time and with full involvement of experts, and also allow for the interactions
between distribution tariffs and transmission tariffs, and their impacts on consumers and
generators at both connection-levels, to be more fully reflected. Further, it will allow
time to determine the most beneficial approach and tackle the most significant issues
holistically. The development of principles to guide NRAs when designing tariffs
regimes (Option 2) would provide the first step in this process, and facilitate early
decisions and implementation prior to any legally binding instrument. As the topic falls
within the regulators' field of competence, this would be appropriately led by ACER.
Further, augmentation of the high-level principles in the Electricity Regulation is
necessary to reflect evolution of the market since they were originally introduced, for
35
E.g. changes to G-charges could be effected by amending the ITC regulation.
245
Minimise investment and dispatch distortions due to transmission tariff structures
example to avoid any discrimination between distribution-connected and transmission-
connected generation when setting or approving tariffs.
Subsidiarity
4.3.6.
Charges applied to generators in relation to their connection to, and use of, networks can
be significant. Differences in these charges can therefore have an effect on decision-
making, whether it is on investment locations or on dispatch of energy, and can therefore
add distortions into the market. Given the highly integrated nature of EU electricity
markets, this can add distortions between Member States.
EU-level action is therefore warranted, in order to ensure the minimum degree of
harmonisation needed to avoid distortion in investment and generation is achieved. The
Third Package already lays down a number of rules relating to these changes (notably
Article 14 of the Electricity Regulation), and also requires NRAs to take an active role
(under the Electricity Directive). Further provisions relating to transmission tariffs are
contained in the inter-transmission system operator completion mechanism (ITC)
Regulation, aimed at the issues mentioned above.
Whilst much has been achieved, there is still scope for improvement, particularly given
the importance of minimising distortions to the benefit of consumers. EU-action is
needed to addresses this as it needs to be coordinated across the EU.
Stakeholders' opinions
4.3.7.
Stakeholder feedback suggests there is a case for change, particularly in the medium to
long-term. In 2015, ACER ran an exercise looking at potential harmonisation of tariffs
through the development of a network codes. This included stakeholder questionnaires
(run by Cambridge Economic Policy Associated – CEPA). In their report, CEPA
highlighted a number of points:
- The majority of stakeholders (79 responses) across European countries consider
that the current electricity transmission tariff structures do impact on the efficient
functioning of the European electricity market;
- Around 80% of respondents agreed that generators’ operational and investment
decisions are affected by transmission tariff structures;
- The majority of respondents also considered differences in current transmission
tariff structures across Europe to be a source, or a potential source, of regulatory
and market failure in the IEM. Differences in transmission tariff structures across
European countries were identified by stakeholders as a problem today and
potentially in the future, citing distortions to operational (as well as investment
decisions) as a source of regulatory or market failure;
- Over 60% of respondents also agreed or strongly agreed that differences in
transmission tariff structures across European countries could hamper cross-
border electricity trade and/or electricity market integration. Energy-based tariffs
were cited as a particular issue;
- Around 70% of respondents believed that there are benefits that can be achieved
through harmonisation of transmission tariff structures. Only 7% of all
respondents rejected the idea that harmonisation of transmission tariffs would be
beneficial for the IEM;
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Minimise investment and dispatch distortions due to transmission tariff structures
Further, Eurelectric, in their market design publication36
, state that "[r]egarding
transmission tariffs applied to generators, their structure and methodologies to compute
the costs need to be harmonised. Furthermore, their levels should be set as low as
possible, in particular the power based charges (€/MW) which act as a fixed cost for
generation and therefore distort investment decisions."
36
"Electricity market design: Fit for the low carbon transition," Eurelectric (2016)
247
Minimise investment and dispatch distortions due to transmission tariff structures
248
Congestion income spending to increase cross-border capacity
4.4. Congestion income spending to increase cross-border capacity
249
Congestion income spending to increase cross-border capacity
Summary table
4.4.1.
Objective: The objective of any change should be to increase the amount of money spent on investments that maintain or increase available interconnection capacity
Option 0: Business as usual Option 1 Option 2 Option 3
Description
This option would see the current situation
maintained, i.e. that congestion income can be
used for (a) guaranteeing the actual availability of
allocated capacity or (b) maintaining or increasing
interconnection capacities through network
investments; and, where they cannot be efficiently
used for these purposes, taken into account in the
calculation of tariffs.
Stronger enforcement: current rules do not allow
for stronger enforcement.
Voluntary cooperation: would offer no certainty
that the allocation of income would change.
Further prescription on the use of
congestion income, subjecting its use
on anything other than (a)
guaranteeing the actual availability of
allocated capacity or (b) maintaining
or increasing interconnection
capacities (i.e. allowing it to be offset
against tariffs) to harmonised rules.
Require that any income not used for (a)
guaranteeing availability or (b) maintaining or
increasing interconnection capacities flows
into the Energy part of CEF-E or its
successor, to be spent on relieving the biggest
bottlenecks in the European electricity system,
as evidenced by mature PCIs.
Transfer the responsibility of using the
revenues resulting from congestion and
not spent on either (a) guaranteeing
availability or (b) maintaining
capacities to the European Commission.
De facto all revenues are allocated to
CEF-E or successor funds to manage
investments which increase
interconnection capacity.
Pros
Minimal disruption to the market; consumers can
benefit from tariff reductions – unclear whether
benefits of better channelling income towards
interconnection would provide more benefits to
consumers, given that it may offset (at least in
part) money spent on interconnection from other
sources.
More guarantee that income will be
spent on projects that increase or
maintain interconnection capacity and
relieve the most significant
bottlenecks; could provide around 35%
extra spend; approach reflects the EU-
wider benefits of electricity exchange
through interconnectors; can be linked
to the PCI process.
Guarantees that income will be spent on
projects that increase or maintain
interconnection capacity and relieve the most
important bottlenecks; could provide up to
35% extra spend; approach reflects the EU-
wider benefits of electricity exchange through
interconnectors; firm link with the PCI
process.
Best guarantee that income will be
spent on the biggest bottlenecks in the
European electricity system, ensuring
the best deal for European consumers in
the longer run; approach reflects the
EU-wider benefits of electricity
exchange through interconnectors; to be
linked to the PCI process.
250
Congestion income spending to increase cross-border capacity
Cons
Missing a potentially significant source of income
which could be spent on interconnection and
removing the biggest bottlenecks in the EU.
Restricts regulators in their tariff
approval process and of TSOs on
congestion income spending.
Additional reporting arrangements will
be necessary.
Requires stronger role of ACER.
Restricts regulators in their tariff approval
process and of TSOs on congestion income
spending.
Could mean that congestion income
accumulated from one border is spent on a
different border or different Member States.
Additional reporting arrangements will be
necessary.
Requires stronger role of ACER.
Could prove complicated to set up such
an arrangement; could mean that
congestion income accumulated from
one border is spent on a different border
or different Member States.
Requires a decision to apportion
generated income to where needs are
highest in European system. Will face
national resistance.
Will require additional reporting
arrangements to be put in place.
Requires stronger role of ACER.
Most suitable option(s): Option 2 – provides additional funding towards project which benefit the EU internal market as a whole, while still allowing for national decision making in the first
instance. Considered the most proportionate response.
251
Congestion income spending to increase cross-border capacity
Description of the baseline
4.4.2.
Congestion37
income arises across an interconnection due to price differences on each
side of it. Such effects happen between price areas (i.e. bidding zones), as opposed to
between Member States. The higher the price difference, the greater the income
generated. Conversely, the greater the levels of interconnection, the more arbitrage
opportunities and, therefore, the lower the price differences each side. Congestion
income per MW is therefore lower.
The issue of optimising interconnection capacity from a private versus social cost-benefit
perspective has been analysed, among others, by De Jong and Hakvoort (2006; see also
De Jong, 2009).38
They show that, under certain assumptions (two-node network with
perfect competition and linear supply and demand curves), the capacity that maximises
social benefits is twice the capacity that maximises private benefits. This relationship
changes a bit, however, when investment costs are also taken into account. In that case,
De Jong and Hakvoort show that the interconnection capacity that maximises social
value exceeds the capacity that maximises private profits by even more than a factor of
two.
37
The term ‘congestion’ means a situation in which an interconnection linking national transmission
networks cannot accommodate all physical flows resulting from international trade requested by
market participants, because of a lack of capacity of the interconnectors and/or the national
transmission systems concerned.
38
De Jong, H., and R. Hakvoort (2006), Interconnection Investment in Europe – Optimizing capacity
from a private or a public perspective ?, in : Proceedings of Energex 2006, the 11th international
energy conference and exhibition, 12-15 June 2006, Stavanger, Norway, pp. 1-8. De Jong, H. (2009),
Towards a single European electricity market – A structural approach to regulatory mode decision-
making, Ph.D.-thesis, Technical University Delft, the Netherlands.
252
Congestion income spending to increase cross-border capacity
Figure 1 - Optimum interconnection capacity from a social versus private benefit
perspective
Source: De Jong (2009), p. 261 (see also De Jong & Hakvoort, 2006))
Congestion income from interconnection capacity is a major source of revenues for
TSOs' investment in network expansion. Therefore, in theory, TSOs will invest in new
interconnection capacity as long as the congestion income outweighs the investment and
operational costs (including a reasonable rate of return) and the potential decrease of
congestion income on existing cross zonal interconnectors in the case that the new
interconnector serves as a substitute to existing interconnectors. From a social point of
view, this may result in underinvestment in interconnection capacity and, hence, in a sub-
optimal level of cross-border transmission capacity.
Partly to address this, Article 16 of the Electricity Regulation seeks to restrict how
congestion income can be used39
. Specifically, it only allows it to be used to:
1. guarantee the availability of allocated interconnection capacity;
2. maintaining or increasing interconnection capacities through network
investments, in particular in new interconnectors;
3. to be offset against network tariffs; or
4. held on account until it can be spent on one of the above.
39
In the case of new interconnectors, exemptions can be given to these requirements subject to a number
of conditions being fulfilled.
253
Congestion income spending to increase cross-border capacity
According to data from ENTSO-E, the total amount of TSO net revenues from
congestion management on interconnections was EUR 2.3 billion in 2014 and EUR 2.6
billion in 2015. Figure 2 presents the spending of congestion revenues in 2014-15
aggregated for all members of ENTSO-E, both in million EUR and as a % of total annual
revenues. These revenues amounted to, on average, EUR 2.275 million per annum in
2014-2015. Figure 2 shows that out of this amount, on average, EUR 374 million was
spent on capacity guarantees (16%), EUR 817 million on capacity investments (36%),
EUR 804 million on reducing transmission tariffs (35%) and EUR 280 million saved on
an account (12%). This implies that, on average, about half of the congestion revenues in
2014-15 were used to guarantee, maintain or increase interconnection capacity and,
hence, that – in principle – there is room for increasing this share by alternative Options.
It should be noted, however, that changing the rules on spending of congestion income
may not by itself be sufficient to stimulate investment in relieving the biggest bottlenecks
in the EU. There are a number of reasons why investment in interconnection capacity
might not be forthcoming: they are complex projects with a number of socio-economic
impacts, and often face barriers relating to, for example, planning; the decisions are
complex, and often require the involvement of two or more parties; additional
investments may be needed in national networks in order to accommodate new capacity.
Further, TSOs are able to cover the investment and operational costs of interconnectors –
which are approved by their NRAs – not only from congestion revenues but also, or even
exclusively, from regulated transmission tariffs. Therefore, there is theoretically already a
source of funding for such projects, although in practice the regulated tariff system may
be considered too restrictive for socially optimal investments in interconnection capacity,
for instance because certain costs may not be approved to be part of the regulated cost
base, or because the allowed rate of return may be considered too low to cover the risks,
uncertainties or other challenges involved.
254
Congestion income spending to increase cross-border capacity
Figure 2- Spending of congestion revenues in 2014-15 (in million EUR and as % of
total annual revenues for all countries)
Source: ENTSO-E (2014-15)
Deficiencies of the current legislation
4.4.3.
Current legislation is not providing for sufficient investments in bottlenecks within the
European electricity system. Whilst, as highlighted above, this is unlikely to be due, at
least solely, to how congestion income is spent, there is clearly scope for significantly
255
Congestion income spending to increase cross-border capacity
more funding to be directed toward this ends from congestion income. As demonstrated
from the above figures, the amount spent on increasing or maintaining interconnection
capacity is less than half of the available funds. Further, despite existing bottlenecks and
interconnection levels well below the optimum ones, the legislation offers incentives to
NRAs to retain congestions, as the income they generate can be used to lower national
tariffs. There are also significant deficiencies in transparency with regards to the
spending of congestion income. Whilst current legislation contains obligations relating to
transparency, this is ineffective in practice and it proves difficult to assess how the
provisions of Article 16 are being applied. For example, it is unclear:
- how the TSOs decide on the use of congestion revenues for either guaranteeing,
maintaining or increasing interconnection capacity;
- whether and how the NRAs check (i) that TSOs have used congestion revenues
efficiently for either guaranteeing, maintaining or increasing interconnection
capacity, and (ii) that the rest of the revenues cannot be efficiently used for these
purposes;
- on which criteria the NRA decides on the maximum amount used as income to be
taken into account when approving or fixing network tariffs;
- how the congestion revenues are used during the period they are put on a separate
account;
- the projects towards which the funds are being allocated, including the split
between investments towards capacity maintenance and capacity increases.
The Evaluation Report points out that "another problem is the lack of adequate and
efficient investment in electricity infrastructure to support the development of cross-
border trade. ACER's recent monitoring report and other reports on the EU regulatory
framework stress that the incentives to build new interconnections are still not optimal.
In the current regulatory framework, TSOs earn money from so-called congestion rents.
If TSOs reduce congestion between two countries, their revenues will therefore decrease.
The Third Package has identified this dilemma and addressed through obliging TSOs to
use congestion rents either for investments in new interconnection or to lower network
tariffs. Experience with this rule has, however, shown that most TSOs prefer to use
congestion rents to lower their tariff to investing into new interconnectors."
Presentation of new measures/options
4.4.4.
Option 0 – Do nothing.
This would maintain the status quo, i.e. rules on spending covered by Article 16 of the
Electricity Regulation. The methodology currently being developed under the Capacity
Allocation and Congestion Management regulation (CACM) would provide the main
rules on how the income is allocated between TSOs on each border.
Option 0+: Non-regulatory approach
Stronger enforcement of existing rules will not allow an improvement of the current
situation.
Voluntary cooperation will provide no certainty that there will be a change in the current
allocation of congestion income. Given there are already rules in place, a change to these
rules is needed to address the issue.
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Congestion income spending to increase cross-border capacity
Option 1 – Harmonised use of congestion income
The first option would maintain all the options for the use of congestion income as
already provided for in the regulation, but be more prescriptive about when it can be
taken into account in the calculation/reduction of network tariffs. More specifically, it
would require that its use on anything other than (a) guaranteeing the actual availability
of allocated capacity or (b) maintaining or increasing interconnection capacities be
subject to harmonised rules developed by ACER.
These rules would clearly define the situation when, and when not, the alternative options
could be pursued. Indicatively, the possibility to decrease the network tariff through
congestion income would be allowed only when there is clear and justified evidence,
according to the ACER rules, that there are no cost-effective projects that would be more
beneficial for social welfare than tariff reduction. Rules would also detail how
long/which revenues could be kept in internal accounts until they can be effectively spent
for the above purposes.
This option would be combined with more transparency and additional rules for
publication and monitoring of this spending.
Option 2 – Harmonised use of congestion income with basic CEF option
The second option would, similarly, restrict spending to (a) guaranteeing availability or
(b) maintaining or increasing interconnection capacities. If the income cannot be
effectively used on (a) or (b), it would flow into the Connecting Europe Facility for
Energy (CEF-E) or its successor, and be spent on relieving the biggest bottlenecks in the
European electricity system, as evidenced by mature PCIs. Unlike Option 1, there would
be no option to use the income when calculating tariffs until such time that all the biggest
bottlenecks have been removed (which practically will not happen in the foreseeable
future).
This option would, similarly to Option 1, include harmonised compliance rules to be set
out and monitored by ACER, and combined with more transparency.
Under this option, it is possible that congestion revenues that would normally be used to
lower the national network tariff accrued in one Member State will be spent in another
Member State allowing spending on those projects that would bring the greatest benefits
to the EU as a whole.
Option 3 – Harmonised use of congestion income with full CEF option
The third option is an extension of the second. TSOs would, at the national level, be
permitted to use income for (a) guaranteeing the actual availability of allocated capacity
or (b) maintaining interconnection capacities. However, they would not be permitted to
use it to increase interconnection capacity, and neither could it be used against tariffs.
Instead, all income not spent on (a) and (b) above would be directed to the European
Commission, de facto to the CEF-E or successor funds, to manage interconnection
capacity. This way, the revenues that, up to now can be used by TSOs/NRAs for
increasing capacity or lowering network tariffs, would be spent on the biggest
bottlenecks in the European electricity system as evidenced by mature PCIs. Again, as
with Option 2, if and when all these are removed, income could then be taken into
account when calculating tariffs.
257
Congestion income spending to increase cross-border capacity
This option would, similarly to Option 1, include harmonised compliance rules to be set
out and monitored by ACER, and combined with more transparency.
Again, under this option it is possible that congestion revenues accrued in one Member
State will be spent in another Member State allowing spending on those projects that
would bring the greatest benefits to the EU as a whole.
Comparison of the options
4.4.5.
The options have been compared against the following criteria:
- Effectivity. Effectivity implies that, as much as possible, congestion income is
used to maximise the amount of cross-border capacity available to market
participants. The criterion assesses whether and to what extent the Options
achieve this objective;
- Efficiency. Efficient use of congestion income means that the procedure for the
spending of congestion income provides a simple and straightforward approach to
guaranteeing that congestion income is used for maintaining or increasing the
interconnection capacity;
- Transparency. The spending of congestion income should be transparent and
auditable;
- Robustness. The spending rules should be set in such a way to avoid influence
over the rules beyond what it envisaged;
- Predictability. The spending rules should allow a forecast of the financial
outcome and allow for reasonable financial planning by the TSOs involved;
- Proportionality. Congestion income policy options should be commensurate with
the problem i.e. not going beyond what is necessary to achieve the objectives,
limited to those aspects that Member States cannot achieve satisfactorily on their
own, and minimise costs for all actors involved in relation to the objective to be
achieved;
- Smoothness of transition. The current congestion income spending should not be
changed in a radical way in the short-term in order to limit the financial impact on
all system participants.
Effectivity
With respect to the effectivity of the policy options, all three positively contribute in
more or less the same manner. Currently, congestion income may be taken into account
by the regulatory authorities when approving the methodology for calculating network
tariffs and/or fixing network tariffs. In all three options this type of usage will be strongly
restricted or forbidden causing a larger share of the congestion income to be allocated to
maintaining and/or increasing cross-border capacity. However, for the actual construction
of these links, there may be additional barriers like the licensing procedures for the new
corridors, so the availability of more financial resources may not in all cases guarantee
interconnection expansion.
Efficiency
Currently, TSOs and NRAs have the possibility to allocate the congestion revenues in the
most economically efficient manner. However, due to flexibility at the national-level it
258
Congestion income spending to increase cross-border capacity
cannot be guaranteed that congestion income will always be spent on maintaining and/or
increasing the available interconnection capacity. In each of the three options the level of
freedom for TSOs and NRAs to decide otherwise will be significantly reduced.
Since in Option 2 congestion income for investments are managed at a European level,
whereas the operational measures to guarantee or maintain the interconnection capacity
are dealt with nationally, this Option might be less effective than the other two.
Furthermore, there is some possibility that Member States prefer to withhold funds from
being transferred to a European institution by previous spending on operational
measures.
Transparency
There are currently reporting obligations for the TSO on the spending of congestion
income. It is nonetheless not entirely clear, which criteria are applied for allocating
congestion income to operational measures, investments in capacity expansion or
inclusion in the transmission tariffs. It is expected that each of the three options will
increase the transparency of the allocation and spending of congestion income.
Robustness
The present methodology for spending congestion income is monitored by the NRAs
whereas the revenues themselves are ring fenced. There is not much room to spend the
income for other purposes than that envisaged. Each of the three Options further narrows
down the discretion of TSOs and NRAs. In each Option a larger share of congestion
income will be used for investments, since decision making is either more heavily
regulated or transferred to the European level.
Predictability
Currently, it is not clear how congestion income will be spent. It does not only depend on
the operational costs needed to guarantee the cross-border capacity, but also to the
discretion of the TSOs (and the approval of the NRAs) in deciding how to spend the
income. Each of the three Options contributes to a better predictability. However, the
first option leaves more freedom to Member States to decide on new investments than the
other two options, under which the income is added to the CEF-E funds, which are only
used for PCI investment projects. In the latter case the predictability of the manner of
spending is very good.
With respect to spending congestion income on operational matters, clearer rules will
contribute to higher transparency on the amount of funds needed for it. This will
materialise in all three options.
Proportionality
If the objective of the policy options is to enhance the actual availability of the
interconnection capacity by relieving the financial constraint, each option that effectively
increases the financing of investments can be considered as proportional. With respect to
the implementation differences between the three options, it is debatable which measure
is more (or less) proportional than the other: adding detailing regulation (as in Option 1)
259
Congestion income spending to increase cross-border capacity
or shifting decision making power from the national to the European level (as in Options
2 and 3).
Smoothness of transition
The smoothness of transition is assessed with respect to the amount of change involved
when implementing each Option with reference to the current situation. The
implementation of additional regulation does not significantly change the present powers
of TSOs and NRAs, which is why Option 1 is positive with respect to smoothness of
transition.
For Options 2 and 3 decision making on new investments and operational measures for
maintaining the interconnection capacity shifts to the European level, which will have a
larger impact. It is possible that there will be objections to such a change, especially the
third option where more congestion income is managed on this level.
Summary
Overall, do nothing is not considered an appropriate response, as it does not address the
deficiencies in the current legislation. Changing the current arrangements will not only
increase the incentives on TSOs, but also on Member States and NRAs – i.e. there is a
sum of money that must be spent on interconnection in some form. Whilst tariffs can
always be used to fund such developments, there are counter-incentives, i.e. to keep
tariffs lower by limiting development to that which is strictly necessary as opposed to
being of longer-term benefit and of benefit to the EU internal market as a whole.
Option 1 is the least change, and the most flexible. However, due to this flexibility it is
also the option which could see the least amount of money redirected from being used
when calculating tariffs or from internal accounts towards projects that increase
interconnection capacity. Option 3 would be a significant change and takes away all
national-level decision-making on new investment using congestion income. This may be
less proportionate than allowing some national autonomy, at least in the first instance if it
achieves broadly the same ends. Option 2 would see the same financial potential for new
network investments that increase interconnection capacity – i.e. up to EUR 1.14 billion
per annum. It is therefore considered the most proportionate response to achieve the ends
sought.
Subsidiarity
4.4.6.
The use of congestion income by TSOs has already been addressed at EU-level as part of
the Third Package. The issue is very much one of a cross-border nature, as the majority
of congestion income is raised on infrastructure that crosses Member State borders. A
common approach across the EU is necessary to ensure a level-playing field between
Member States and leaving the issue at national, or bi-lateral, level risks inconsistent
application.
35% of congestion income was used on average over 2014 and 2015 to reduce tariffs,
despite the increase of cross-border trade in electricity between most EU Member States
and the growing need to strengthen the physical connection of electricity markets. Also,
maintaining grid stability becomes more challenging as increasing shares of variable
renewables enter the energy mix; higher interconnection levels could decrease the
260
Congestion income spending to increase cross-border capacity
necessity for redispatch and lead to lower network tariffs. These issues, given their cross-
border impacts, can only be dealt with at an EU-level.
Given that the most common use of congestion income does not seem to address the
current needs of grid development and maintenance, further EU action is necessary to
ensure that there is an increase of the proportion of congestion income spent on
maintaining or increasing interconnection.
Stakeholders' opinions
4.4.7.
Whilst there was not a specific question in the energy market design consultation on
congestion income, and many respondents did not comment on the issue, some did
express views. For example, comments included:
"… It should be a common European interest to reduce or remove permanent
bottlenecks between countries within the EU. Primarily it should be done by using the
congestion incomes for investments instead of simply managing the congested
transmission lines. There is no need for separate capacity pricing for the energy only
markets."
"At the moment, income from congestion management shall be used to mitigate the
bottleneck or decrease the end user tariffs. However clear mechanism for setting up
the financing of the new projects shall be in place (including needed change in
accounting standards and income tax rules). With the new investment the respective
bottleneck is dismissed and there is no further income from congestion management.
This makes the return on investment impossible."
"According to the Communication it is essential to achieve the previously established
target value of 10% for the interconnection of electricity networks, and its increase to
15%. To this end, the current effective EU regulation provides adequate support. At
the same time, according to the Commission’s concept the utilisation of fees currently
charged for congestion management should be regulated in a manner which would
facilitate the development of the electricity system. We would be in a position to
support this concept if there is guarantee that once the target value has been
achieved by a Member State the revenues could still be used for other purposes as
well (e.g. tariff cuts)."
"…funds [for cross-border redispatching] could come from congestion rents which
are not possible to be attached to a border anymore in a flow-based world. This
common TSO income should be spent commonly on costly coordinated actions."
261
Congestion income spending to increase cross-border capacity
262
Congestion income spending to increase cross-border capacity
5. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA II, OPTION 2(2) (IMPROVED
ENERGY MARKETS - CMS ONLY WHEN NEEDED, BASED ON COMMON EU-WIDE
ADEQUACY ASSESSMENT ( AND OPTION 2(3) (IMPROVED ENERGY MARKET, CMS ONLY
WHEN NEEDED BASED ON COMMON EU-WIDE ADEQUACY ASSESSMENT, PLUS CROSS-
BORDER PARTICIPATION)
263
Congestion income spending to increase cross-border capacity
264
Improved resource adequacy methodology
5.1. Improved resource adequacy methodology
265
Improved resource adequacy methodology
Summary table
5.1.1.
Objective: Pan-European resource adequacy assessments
Option 0 Option 1 Option 2 Option 3
Description
Do nothing.
National decision makers would continue to
rely on purely national resource adequacy
assessments which might inadequately take
account of cross-border interdependencies.
Due to different national methodologies,
national assessments are difficult to
compare.
Binding EU rules requiring TSOs to
harmonise their methodologies for
calculating resource adequacy +
requiring Member States to exclusively
rely on them when arguing for CMs.
Binding EU rules requiring ENTSO-E to
provide for a single methodology for
calculating resource adequacy +
requiring Member States to exclusively
rely on them when arguing for CMs.
Binding EU rules requiring ENTSO-E to carry
out a single resource adequacy assessment for
the EU + requiring Member States to
exclusively rely on it when arguing for CMs.
Pros
Stronger enforcement:
Commission would continue to face
difficulties to validate the assumptions
underlying national methodologies including
ensuing claims for Capacity Mechanisms
(CMs).
National resource adequacy assessments
would become more comparable.
In addition to benefits in Option 1, it
would make it easier to embark on the
single methodology.
In addition to benefits in Options 1 & 2, it
would make sure that the national puzzles neatly
add up to a European picture allowing for
national/ regional/ European assessments.
Results are more consistent and comparable as
one entity (ENTSO-E) is running the same
model for each country.
Cons
Even in the presence of harmonised
methodologies national assessment
would not be able to provide a regional
or EU picture.
Even in the presence of a single
methodology, national assessments
would not be able to provide a regional
or EU picture.
National TSOs might be overcautious
and not take appropriately cross-border
interdependencies into account.
Difficult to coordinate the work as the
EU has 30+ TSOs.
It would potentially reduce the 'buy-in' from
national TSOs who might still be needed for
validating the results of ENTSO-E's work.
Most suitable option(s): Option 3 - this approach assesses best the capacity needs for resource adequacy and hence allows the Commission to effectively judge whether the proposed
introduction of resource adequacy measures in single Member States is justified.
266
Improved resource adequacy methodology
Description of the baseline
5.1.2.
Based on perceived or real resource adequacy concerns40
, several Member States have
recently introduced resource adequacy measures. These measures often take the form of
either dedicated generation assets kept in reserve or a system of market wide payments to
generators for availability when needed (Capacity mechanisms or 'CM's).
Figure 1: CMs in the EU
Source: ACER 2015 Monitoring report
National resource adequacy assessments
To determine whether these concerns require the introduction of a CM, Member States41
first need to carry out an assessment of the adequacy situation. Indeed, all Member States
that are part of DG COMP's Sector Inquiry on Capacity Mechanisms measure the
security of supply situation in their country by carrying out an adequacy assessment in
which one or more methodologies are applied that give an indication of the potential of
the generation fleet to meet demand in the system at all times and under varying
scenarios.
40
The sector inquiry has shown that a clear majority of public authorities expect reliability problems in
the future even though today such problems have been extremely rare in the past five years. In nine out
of ten Member States, no such problems have occurred at all. The only exception is Italy, where such
issues have arisen on the islands of Sardinia and Sicily which are not well connected to the grid on the
mainland. Although the Member States do not experience reliability issues at present, many Member
States are of the opinion that reliability problems are expected to arise in the coming five years.
41
In most countries, TSOs are the responsible bodies for monitoring and reporting on long-term resource
adequacy. Other responsible institutions are NRAs or governments In the UK, the medium and long
term resource adequacy assessments are carried out by the NRA and government respectively. In
Estonia, the long term monitoring is managed by the government.
Strategic reserve
(since 2004 ) - gradual phase-
out 2020 and considering a
permanent market system
after 2020
New Capacity Mechanism
under assessment by COMP
(Capacity payments from 2006
to 2014)
Capacity payment (since 2008) –
Tendering for capacity
considered but no plans
No CM (energy only market)
CM operational
Reliability option
(first auction end 2016, first
delivery contracted capacity is
expected in 2021)
Strategic reserve
(from 2016 on, for 2 years,
with possible extension for 2
years)
CM proposed/under consideration
Capacity requirements
(certification started 1 April
2015)
Capacity auction
(since 2014 - first delivery in
2018/19)
Capacity payment
(since 2007)
considering reliably options
Capacity Payment (Since 2010
partially suspended between
May 2011 and December 2014)
Strategic reserve (since 2007)
Debate pending
Strategic reserves for DK2
region from 2016-2018 (and
potentially from 2019-2020)
Strategic reserve
(since 1 November 2014)
267
Improved resource adequacy methodology
The methodologies are however rarely comparable across Member States. Methods vary
significantly, for instance when it comes to the question whether to take into account
generation from other countries, but also regarding the scenarios and underlying
assumptions42
.
The Council of European Energy Regulators (CEER)43
performed a survey over
European countries showing that security of supply is dealt with at national level through
quite different approaches:
- Assessing resource adequacy requires the definition of one or more scenarios that
can affect generation and demand projections. These scenarios are elaborated
according to different assumptions about load (typically high vs. low demand
scenario), and type and amount of future installed capacity (e.g. conservative or
baseline vs. high RES penetration scenario). Regarding the scenarios44
used in the
different Member States, the methodologies differ greatly depending on the
targeted timeframe45
and the majority of them do not seem to be consistent
throughout most of the national resource adequacy assessments.
- Regarding load forecast, Member States base their projections on historical load
curves, with assumptions on the evolution of specific parameters. The most
exploited parameters are economic growth, temperature, policy, demography and
energy efficiency. The extent to which types of consumers are grouped to
appraise carefully different consumption patterns can be very different46
.
Moreover demand response is largely not included as a separate factor in load
forecast methodologies, even though it may appear that it is indirectly included in
the projections through the effects it has had on the historical load curves47
.
42
JRC (2016), "Generation adequacy methodologies review"
43
CEER (2014), "Assessment of electricity generation adequacy in European countries"
44
In at least 6 countries (including Sweden, Romania, Malta, Finland and Norway) resource adequacy is
assessed against a single pre-defined baseline scenario. For the other cases (UK, France, the
Netherlands, Estonia, Hungary, Lithuania, Belgium, Spain, Ireland and Italy), several possible
scenarios are considered on the basis of different assumptions about load as well as type and amount of
future installed capacity, such as a conservative scenario, a baseline scenario a RES penetration
scenario, for example.
45
In at least 9 countries (France, Estonia, Malta, Hungary Lithuania, Belgium, Spain, Ireland and Italy)
the scenarios are compounded taking as a reference the short, medium and long-term horizons. In the
Netherlands and Finland, the long term is not considered, while in Sweden and Norway only the short-
term is taken into account. In Denmark, only the long-term scenario is considered. In the Czech
Republic and Switzerland, the only scenario considered is the very long term, while in Spain the latter
scenario completes the short, medium and long-term analyses. Finally, in Romania, no short-term
analysis is performed (only mid and long-term scenarios are considered).
46
In 10 national resource adequacy reports (the UK, France, Norway, Malta, Czech Republic, Hungary,
Lithuania, Ireland, Austria and Italy) more than one category of consumers (e.g. residential, industrial,
commercial, agriculture, etc.) serve as a basis for the forecasts; while in 4 reports (the Netherlands,
Estonia, Belgium and Sweden), load only is forecasted at an aggregate level.
47
Only 3 countries include demand response as a separate factor in their load forecast methodology i.e.
the UK, France and Spain. In Norway and Finland, the contribution from demand response is not
included as separate factor, but peak load estimation is based on actual load curves which include the
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Improved resource adequacy methodology
- Regarding generation forecast, the most important inputs are the information
received by those intending to build new generation and rules on how to consider
existing infrastructure. All Member States take projected investments into
account, sometimes with very heterogeneous sources and assumptions48
. In
addition, there are also various ways generation from variable output (i.e.
intermittent RES) is modelled49
; from no consideration at all, to precise hourly
estimations based on sophisticated data. It is commonly agreed that there is a
need to improve methodologies to better address how variable output impacts
adequacy.
- With an increasing proportion of variable renewable resources, electricity systems
have become more complex. To address this increased complexity, some Member
States have replaced relatively simple, ‘deterministic’ assessment metrics50
–
which simply compare the sum of all nameplate generation capacities with the
peak demand in a single one-off moment – by more complex ‘probabilistic’51
models, which are able to take into account a wide range of variables and their
behaviour under multiple scenarios. This includes not only state of the art weather
forecasts, but also factors in less predictable capacity sources such as the
contribution from demand response, interconnectors or renewable energy sources.
effect of demand response. Sweden does not consider demand response, and do not assume that
consumers respond to peak load in their analysis.
48
For instance, decommissioning (and mothballing) of investments is not systematically taken into
account. Most collected data come from generators, partly directly via the TSOs.
49
Some countries (Estonia, Romania, Malta and Denmark) still go with the approach of unavailable
capacity while there are also others like the Netherlands, Norway, Spain and Sweden, which take a
certain percentage as available generation. On the contrary, France and the UK go up to detailed
modelling based on climate data, hub heights (for offshore wind farms) and detailed coordinates for
the generation sites.
50
One of the simplest measures to determine the level of resource adequacy is the capacity margin. This
deterministic methodology simply expresses the relation between peak demand in the electricity
system and the total available supply, usually as a percentage. In only two of the eleven Member States
analysed in the sector inquiry, this relatively simple capacity margin is calculated. For instance in
2016, France had 104,480 MW of production installed capacity whereas peak demand during winter
2015/2016 was 84,700 MW; from that, one could say that France has approximately a 23% capacity
margin (RTE figures). Of course, no form of generation can always output its full nameplate capacity
with 100% reliability. Therefore, each source of input needs to apply a de-rating factor in order to
reflect its likeliness to be technically available to generate at times of peak demand (e.g. in Ofgem's
electricity capacity assessment, a combined cycled gas plant is assumed to be available 85% of the
time). In 2014, CEER found that 6 Member States were using de-rated capacity margins: Estonia,
Malta, Hungary, Belgium, Spain and Sweden.
51
Around half of the Member States of the sector inquiry carry out a 'probabilistic' calculation that can
be either expressed in LOLP, LOLE or EENS: (i) Loss of load probability (LOLP) quantifies the
probability of a given level of unmet demand at any particular point in time; (ii) Loss of load
expectation (LOLE) sets out the expected number of hours or days in a year during which some
customer disconnection is expected. For instance, French TSO RTE expects some customer
disconnection to happen during 1h45 over winter 2016-2017; (iii) Expected energy non served (EENS)
measures the total shortfall in capacity that occurs at the time when there are disconnections. EENS
makes it possible to monetise where VoLL has also been calculated.
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Improved resource adequacy methodology
Nonetheless, these adequacy methodologies52
still differ (deterministic vs.
stochastic).
- Despite on-going developments, some assessments are still considering isolated
systems and/or developing ways to include interconnectors53
. Others use non-
harmonised methodologies to consider cross-border capacity, with no cross-
border coordination foreseen. The availability of interconnection capacity is
mostly based on historical data (export and import flows during various periods
of time) and to lesser extent, on estimated data (e.g. market component such as
future prices estimations). Generation and load data correlations at supranational
levels are rarely considered54
, and for country-wide modelling, the "copperplate
approach" prevails55
.
- It should be noted that monitoring and assessing resource adequacy is a very
complex process which requires defining robust concepts, criteria and procedures
in order to give a reference tool to decision-making bodies if problem are
encountered. In almost all EU countries, the body responsible for ultimately
ensuring resource adequacy is the national government. However, monitoring
responsibilities are usually shared among the TSO, the NRA and the government.
These responsibilities can evolve depending on the timeframe considered. For the
medium and long-term timeframes, TSOs are the responsible bodies for
monitoring and reporting in most Member States. Other responsible institutions
are NRAs or governments56
. In most cases, the assessment is carried out yearly.
52
Half of the national studies are based on a 'probabilistic' approach (the UK, France, the Netherlands,
Finland, Romania, the Czech Republic, Lithuania, Belgium, Ireland, Italy) while six of them are based
on a deterministic approach (Estonia, Malta, Hungary, Belgium, Spain and Sweden). Denmark uses a
deterministic approach, but takes into account the outage percentage of power plants which is based on
both historical observations and Monte Carlo simulations.
53
The extent to which current resource adequacy reports take the benefits of interconnectors into account
varies a lot: 4 reports still model an isolated system (Norway, Estonia, Romania, and Sweden); 2
reports use both interconnected and isolated modelling (France and Belgium); 3 report methodologies
are being modified to include an interconnection modelling; 9 reports simulate an interconnected
system (UK, the Netherlands, Czech republic, Lithuania, Finland, Belgium and Ireland, while France
and Italy use both methods).
54
It is not obvious that national resource adequacy reports generally take interactions between generation
and demand profiles into account. Moreover, it seems that most reports do not consider correlated
data, which could be done (for example with the use of a common correlated climate database at
regional level, or a common methodology for load sensitivity to temperatures). One direct
consequence is that most reports do not intend to identify the impact on security of supply of potential
simultaneous severe conditions in different electricity systems.
55
In the process of assessing resource adequacy, transmission and distribution networks can be modelled
in a very different manner, from a highly realistic description of the technical parameters which
constrain the power flows in the system, to a simplified modelling where these networks are
considered as a copperplate grid. Some systems are said not to be subject to structural internal
congestions (including France and Romania).
56
In the UK, the medium and long term resource adequacy assessments are carried out by the NRA and
government respectively. In Estonia, the long term monitoring is managed by the government.
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Improved resource adequacy methodology
Table 1: Deterministic vs probabilistic approaches to adequacy assessments
Source: European Commission based on replies to sector inquiry, see below for a description of capacity
margin, LOLP, LOLE, and EENS
ENTSO-E carries out an EU-wide resource adequacy assessments
In addition to resource adequacy assessments carried out by Member States, there are
also EU level rules foreseen by the Third Package (the Electricity Regulation) requiring
ENTSO-E to carry out a medium and long-term resource adequacy assessment (so-
called, Scenario Outlook and Adequacy Forecast or SO&AF) in order to provide
stakeholders and decision makers with a tool to base their investments and policy
decisions.
ENTSO-E is currently moving from a deterministic approach to a probabilistic approach
(sequential Monte-Carlo). This evolution will be done progressively and is expected to be
completely implemented by 2018. The first steps of the new methodology were carried
out in the latest published report so-called SO&AF 2015.
The ENTSO-E SO&AF 2015 presents the following characteristics/ limitations57
:
- ENTSO-E uses a deterministic assessment which calculates for each country
deterministic security of supply indicators (namely 'remaining capacity' and
'adequacy reference margin') only at particular points in time (the 3rd
Wednesday
of each month on the 19th
hour in the pan-European assessment or at national
peak load time in the national assessments). The report presents results for the
mid-term and long-term timeframes (5-year and 10 years ahead, respectively)58
.
- Regarding load forecast, there is no explicit modelling of demand-side response
in the SO&AF 2015 but is expected to be taken into account from 2017 onwards.
57
JRC Science for Policy Report (2016), "Generation adequacy methodologies review"
58
Since 2011, ENTSO-E performs a SO&AF annually, with a time horizon of 15 years until SO&AF
2014 and 10 years in SO&AF 2015.
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Improved resource adequacy methodology
- Regarding generation forecast, the analysis is based on two different scenarios for
generation (conservative and best estimate). The conservative scenario considers
only new capacity if it is considered as certain and for the decommissioning, it
considers the official notifications but also additional criteria as for example,
technical lifetime of generators (additional criteria which are not considered in the
best estimate scenario). RES (wind and solar PV) are taken into account for the
first time in the SO&AF 2015 assessment by estimating their load factor (with a
Pan-European Climate database of 14 climatic years).
- Regarding interconnection, the ENTSO-E SO&AF 2015 assessment only
considers import and export capacities for each country. There is no explicit
modelling of flow-based market coupling.
Voluntary initiatives to carry out regional resource adequacy assessments
Some Member States have voluntarily decided to cooperate and deliver a regional
resource adequacy assessment. This is the case of the seven TSOs in the Pentalateral
Energy Forum59
('PLEF') who have decided to move away from country specific point in
time assessments to an integrated chronological probabilistic assessment. The new
methodology is based on harmonised and detailed input data to capture the main
contingencies60
susceptible of threatening security of supply. This voluntary approach
developed by the PLEF TSOs is currently used as a test-lab for upgrading the ENTSO-E
methodology.
59
An inter-governmental initiative designed to promote collaboration on cross-border exchange of
electricity in Austria, Belgium, France, Germany, Luxembourg, the Netherlands, Switzerland.
60
These contingencies include outdoor temperatures (which result in load variations, principally due to
the use of heating in winter), unscheduled outages of nuclear and fossil-fired generation units, amount
of water resources, and wind and photovoltaic power production.
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Improved resource adequacy methodology
Table 2: PLEF vs ENTSO-E approaches to adequacy assessments
PLEF
ENTSO-E
Current Targeted
Approach Probabilistic Deterministic Probabilistic
Scale
Regional (at least direct
neighbours, up to
second degree
neighbours)
National – simplified
regional
Pan European
Network representation
Current (NTC
61
) and
targeted (PTDF
62
)
None on small scale,
maximum flows on
regional scale
First, NTC
Later, possibly flow-
based
Security of supply
indicators
Loss of load (energy
duration, probability,
frequency,…), capacity
margin
Capacity margin Loss of load
Uncertainty
considerations
Monte Carlo simulations Additional margins Monte Carlo simulations
Source: Artelys (2016), "METIS Study S4: Stakes of a common approach for generation and system
adequacy"
Deficiencies of the current legislation
5.1.3.
As highlighted in Section 7.3.2 of the Evaluation, resource adequacy is not addressed in
the Third Package. The Commission's current tool to assess whether government
interventions in support of resource adequacy are legitimate is State aid scrutiny. The
EEAG require among others a proof that the measure is necessary. However, the
framework does not allow the Commission to effectively judge whether there is a
resource adequacy problem in the first place.
To date, the need for CMs are based on national adequacy assessments and Member
States rely on them when arguying for CMs. However, national assessments are
undertaken in different ways across Europe. These assumptions may substantially differ
depending on the underlying assumptions made and the extent to which foreign
capacities as well as demand side flexibility are taken into account in calculations. For
example, the Council of European Energy Regulators (CEER) recommends to "take into
account the potential benefit provided by interconnectors in national resource adequacy
analyses in a coordinated and consistent way across Member States"63
. In addition,
CEER is of the opinion that "these different procedures pose difficulties (especially for
neighbouring countries) as it is a challenge to understand the different procedures and
processes from one country to another"64
.
61
Interconnectors are usually modelled as commercial flows with no network physical constraints, but
constrained by maximum net transfer capacities (NTC). In practice NTC values can vary quite often,
due to outages, maintenance and temperature affecting lines' physical properties.
62
Power Transfer Distribution Factor
63
CEER (2014), Recommendations for the assessment of electricity generation adequacy
64
CEER report on “Assessment of generation adequacy in European countries” (published in 2014)
http://www.assoelettrica.it/wp-content/uploads/2014/10/Ceer_GenerationAdequacyAssessment.pdf
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Improved resource adequacy methodology
Art. 8 of the Electricity Regulation gives to ENTSO-E the responsibility for carrying out
a European resource adequacy outlook. It requires amongst others that the European
resource adequacy outlook should build on national resource adequacy outlooks prepared
by each individual TSO. Consequently the ENTSO-E assessment is rather a compilation
of national assessments than a genuine calculation based on raw data input. Also the
applied methodology needs a review in particular with regards to the input data and the
calculation method used. For example, the European Electricity Coordination Group
recommends that "The improvements in the existing ENTSO-E methodology should focus
on the consistent treatment of variable RES generation and interconnectors"65
.. In their
current form and granularity they are not suitable to assess whether certain Member
States are likely to face resource adequacy problems in the mid to long-term.
Further to the difference in approach, CEER highlights that "there are also differences
between the System Outlook & Adequacy Forecast (SO&AF) undertaken by ENTSO-E
and the national assessments that occur due to different quality of data and a more
sophisticated approach in some countries"66
.
All in all, neither national assessments nor ENTSO-E's European resource adequacy
outlook, in their current form a) appropriately inform investors, governments and the
wider public of the likely development of system margins and b) allow the Commission
to effectively judge whether the proposed introduction of resource adequacy measures in
single Member State is justified.
Presentation of the options
5.1.4.
Option 0 - BAU
National decision makers would continue to rely on purely national resource adequacy
assessments which inadequately take account of cross-border interdependencies. In
addition, due to different national methodologies, national assessments are difficult to
compare.
The Commission would continue to face difficulties to validate the assumptions
underlying national methodologies including ensuing claims for CMs.
Option 0+ stronger enforcement
As the current legislation foresees that national resource adequacy plans are the basis for
ENTSO-E to draw up its resource adequacy assessments, stronger enforcement is not a
viable option.
Some Member States (e.g. PLEF) have voluntarily decided to cooperate and deliver a
regional resource adequacy assessment. However, the PLEF geographically covers only
65
Report of the European Electricity Coordination Group on The Need and Importance of Generation
Adequacy Assessments in the European Union, Final Report, October 2013
66
CEER report on “Assessment of generation adequacy in European countries” (published in 2014)
http://www.assoelettrica.it/wp-content/uploads/2014/10/Ceer_GenerationAdequacyAssessment.pdf
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Improved resource adequacy methodology
part of the EU electricity market and hence its role cannot go beyond that of a test-lab for
upgrading the ENTSO-E methodology. Indeed, without a common methodology for all
EU Member States, the Commission would continue to face difficulties to effectively
judge whether the proposed introduction of resource adequacy measures in single
Member States is justified.
Option 1 – Binding EU rules requiring TSOs to harmonise their methodologies for
calculating resource adequacy + requiring Member States to exclusively rely on them
when arguing for CMs
Option 1 would require TSOs to harmonise their methodologies for calculating resource
adequacy and require Member States to exclusively rely on them when arguing for CMs.
TSOs would have to cooperate to upgrade their methodologies based on probabilistic
calculations, with appropriate coverage of interdependencies, availability of RES and
demand side flexibility and availability of cross-border infrastructure in times of stress.
In this option, Member States would be responsible for carrying out the assessment.
Option 2 - Binding EU rules requiring ENTSO-E to provide for a single methodology for
calculating resource adequacy + requiring Member States to exclusively rely on them
when arguing for CMs
Option 2 would require ENTSO-E to provide for a single methodology for calculating
resource adequacy and require Member States to exclusively rely on them when arguing
for CMs. The ENTSO-E methodology should be upgraded based on propabilistic
calculations67
and should appropriately take into account foreign generation, RES and
demand response.
In this option, Member States would be responsible for carrying out the assessment based
on the ENTSO-E methodology & coordination.
Option 3 - Binding EU rules requiring ENTSO-E to carry out a single resource adequacy
assessment for the EU + requiring Member States to exclusively rely on it when arguing
for CMs
Option 3 would require ENTSO-E to carry out an EU-wide resource adequacy
assessment and Member States to exclusively rely on it when arguing for CMs. In other
words, this would mean that, ENTSO-E would be required to not only provide for the
methodology (similar to Option 2) but also carry out the assessment. The ENTSO-E
assessment should have the following characteristics:
i. It should cover all Member States
ii. It should have a granularity of Member State/ bidding zone level to enable the
analysis of national/ local adequacy concerns;
67
The PLEF approach could serve as a pioneer for applying the advanced methodology for a wider
perimeter.
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Improved resource adequacy methodology
iii. It should apply probabilistic calculations that consider dynamic characteristics of
system elements (e.g. start-up and shut-down times, ramp up and ramp-down
rates…)68
iv. It should calculate resource adequacy indicators for all countries (LOLE, EENS,
etc.)
v. It should appropriately take into account foreign generation, interconnection
capacity, RES69
, storage and demand response
vi. The assessment should be carried out every year
vii. Time span of 5-10 years
It should be noted that under this option each Member State would be allowed to carry
out their national resource adequacy assessment if they wish to but they would not be
able to rely on these results when arguing for CMs.
Comparison of the options
5.1.5.
Contribution to policy objectives
Under Option 0, proposed CMs would be based on national resource adequacy
assessments and projections. National assessments may substantially differ depending on
the underlying assumptions made and the extent to which foreign capacities as well as
demand side flexibility and variable renewable generation70
are taken into account in
calculations. Some countries even use deterministic methodologies that are obsolete (they
do not consider the stochastic nature of forced outages and variable renewable
generation). In addition, these national assessments are often not in line with the current
EU-wide assessment carried out by ENTSO-E. All in all, this approach reinforces the
national focus of most mechanisms and prevents a common view on the adequacy
situation. Remaining in the status quo may therefore lead to significant capacity
overinvestments. In consequence, it creates more uncertainty in neighbouring countries
as each Member State takes individual actions in putting in place CMs.
In Option 1, proposed CMs would still be based on national resource adequacy
assessments but these would adopt harmonised methodologies including input data. The
assessments would thus become more comparable across Member States. However, even
though this approach is an improvement compared to Option 0, it seems likely that
Option 1 would still lead to significant capacity overinvestments. Although this option
provides a minimum harmonization, the implementation time will take longer as some
Member States current methodologies are far from the target one. An entity or body
needs to assure that the harmonized methodology is properly implemented and check the
consistency of the results across countries. This option can produce significant delays.
68
This means considering flexibility issues, temporal constraints and a realistic evaluation of the
expected role of interconnectors.
69
National but also foreign RES should be considered as the IEM and the interconnection capacity are
the basis for a more and better integration of RES allowing a higher capacity factor for RES. The same
can apply to storage.
70
Some countries still assume zero capacity value for wind and PV. Countries that do not assume a zero
value differ on the methodology to estimate the capacity value of RES.
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Improved resource adequacy methodology
Option 2 would make it easier to embark on a single methodology. Moreover, this
approach is likely to result in less over-investment in power infrastructure. However, it
would be difficult to coordinate the work of the 30+ TSOs in Europe. In addition,
national TSOs might be overcautious and not take appropriately into account cross-
border interdependencies. Even in the presence of a single methodology, national
assessments would not be able to provide an effective regional or EU picture.71
Indeed,
national interests could still play a role in the manner in which the assessments are done.
There is a risk that Member States would deviate from the single methodology when
implementing it which means that an enforcement and monitoring mechanism should be
provided for.
Option 3 would most likely be the best option to reach the set objectives as it would
make sure that the national puzzles neatly add up to a European picture allowing for
national/ regional/ European assessments. A major advantage is that ENTSO-E has
already been carrying out an EU-level resource adequacy assessment based on the Union
legislation. By requiring ENTSO-E to carry out the assessment, Option 3 appears to be
appropriate to overcome the main obstacles that prevent Option 1 and 2 from being
effective. Indeed, there would be less room for Member States to deviate in the
implementation of the single methodology. This would favour neutrality as it would
avoid national interests playing a role in the manner in which the assessments are done.
Efficiencies would arise from a reduced need for coordination between Member States
and a reduced need for oversight during the implementation of the methodology by the
Member States. As a drawback, Option 3 would potentially reduce the 'buy-in' from
national TSOs who might still be needed for validating the results of ENTSO-E's work.
All in all, this option would best assess the capacity needs for resource adequacy and
hence allow the Commission to effectively judge whether the proposed introduction of
resource adequacy measures in single Member States is justified.
Key economic impacts
An expert study carried out using METIS72
assesses the benefits of cooperation for
resource adequacy. The study highlights that significant capacity savings can be obtained
from a European approach to security of supply with respect to a country-level resource
adequacy assessment. The reasons for these savings is that Member States have different
needs in terms of capacity with peak demands that are not necessarily simultaneous.
Therefore, they can benefit from cooperation in the production dispatch and in
investments.
71
For example the extent to which Member States can rely on each other for contributions to their own
security of supply depends, among other things, on the likelihood of scarcity situations occurring
simultaneously in those Member States. Even if Member States calculate their resource adequacy
assessment based on a single methodology it cannot be ensured that they arrive at exactly at the same
outcomes except if all Member States share all data sets generated by the other and if they carry out
exactly the same computational steps using those data sets.
72
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016).
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Improved resource adequacy methodology
The model jointly optimises peak capacities for two reference cases for EuCO2773
–
without cooperation (capacities are optimised for each country individually, as if
countries could not benefit from the capacities of their neighbours) vs. with cooperation
(capacities are optimised jointly for all countries, taking into account interconnection
capacities (NTCs).
In both options, capacity dimensioning has the following characteristics: (i) removal of
peak fleets (CCGT, OCGT and oil) to avoid excessive overcapacity); (ii) Other units are
kept (including nuclear, coal and lignite), which creates overcapacity for CZ, SK and
BG; (ii) Optimisation of gas and peak fleats (modeled as OCGT) with VOLL = 15k
EUR/MWh and peak annual price = 60k EUR/MW/year.
The difference in installed capacity between the two cases reveals how much savings
could be made from cooperation in investments.
Results show that almost 80 GW of capacity savings (see figures 2 and 3) across th EU,
which represents 31% of the installed gas capacities, can be saved with cooperation in
investments. This represents a gain of EUR 4.8 billion per year of investments.
It should be noted that this figure does not assess at which stage Member States are
currently (i.e. whether some Member States already benefit from the capacities of their
neighbours), as the benefits have already been reaped by some. It should also be noted
that this figure does not include savings on production dispatch, which could lead to
much higher monetary benefits.
73
The scope of the model comprises EU28 + (CH, NO, BA, MK, ME, RS) and 50 years of weather data.
278
Improved resource adequacy methodology
Figure 2 – Capacity savings for METIS EuCO27 in GW
Source: METIS
279
Improved resource adequacy methodology
Figure 3 – Capacity savings for METIS EuCO27 in % of demand
Source: METIS
The main reasons for these capacity savings are twofold: (i) variability of peak demand
across Europe and (ii) variability of weather conditions (and consequently of RES
generation profiles) across Europe.
- Variability of power demand profiles across Europe: Energy end use practices are
different and the deployment of equipement using electricity (for instance
electrical heating) varies across Member States. In particular, the sensitivity of
Member States national demand with regards to temperature varies from one
country to the other. Moreover, low temperature events do not occur at the same
time in all Member States74
. As a consequence, the aggregated European demand
peak is lower than the sum of all national demand peaks (which do not occur at
the same time). A European electric system with cooperation in capacity
dimensioning would therefore face a lower capacity need – defined by the
aggregated European demand peak – than a set of isolated national systems,
74
For instance, extreme temperature conditions are often not correlated between Western Europe and
Northern Europe (Norway, Sweden, Finland and Estonia).
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Improved resource adequacy methodology
which would require a global generation capacity as high as the sum of national
peak demand.
Figure 4 – illustration of cooperation in variability of peak demand across Europe
(based on ENTSO-E v3 scenario)
Source: METIS
- Variability of RES generation profiles: Despite geographical correlations at the
regional scale, different climatic regimes produce different weather conditions
across Europe, which often compensate one another. This influences the RES
generation profiles. Indeed, aggregating European RES generation profiles leads
to higher load factors for RES than single country RES load factors.
Figure 5 – illustration of cooperation in variability of RES generation across Europe
(based on ENTSO-E v3 scenario i.e. high RES scenario)
Source: METIS
Impact for businesses and public authorities
The administrative costs75
are expected to be marginal compared to the economic
benefits that would be reaped. ENTSO-E currently employs two FTEs to carry out its
resource adequacy assessment and has a working group of 10 FTEs from national TSOs.
In addition, we assume approximately 100 FTEs working on national resource adequacy
75
The economic costs linked to resource adequacy assessments are based on own estimations, resulting
from discussions with stakeholders and experts.
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Improved resource adequacy methodology
assessments in TSOs across Europe (Option 0). Option 1 is assumed to require require
20-25 additional FTEs for coordinating the harmonisation of national assessments. It is
likely that Option 2 would be slightly less human intensive – only 15-20 additional FTEs
would be needed. Under Option 3, it is assumed that the same amount of FTEs would be
needed as in Option 2 but these would be employed by ENTSO-E. In monetary terms,
this can be translated into 2-3 million euros annually in terms of personnel costs for
Option 3. In addition, IT costs are equally likely to be small. For Option 3, IT costs are
assumed to be in the range from 2-3 million euros per year as ENTSO-E would need
more calculatory power that has IT implications. For options 1 and 2, they are likely to
be lower than for Option 3 as TSOs across Europe have already developed their own IT
systems. All in all, the estimated administrative costs of ENTSO-E providing for a single
methodology and carrying out the assessment (Option 3) would range from 4 to 6
million euros per year. This is marginal compared to the estimated benefits presented
above.
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Improved resource adequacy methodology
Table 3: Comparison of the Options in terms of their effectiveness, efficiency and
coherence of responding to specific criteria
Option 0: No
further action
Option 1:
Harmonisation of
national
assessments
Option 2: ENTSO-
E provides for
single
methodology,
Member States
carry out the
assessment
Option 3: ENTSO-
E provides for
single methodology
and carries out the
assessment
Quality of the
methodology
--
No progress or
uncertain progress
as it depends on
Member State
independent
initiatives
0
Progress remains
limited as only
harmonisation
++
Efficient as there is
a single
methodology
++
Coherence as
ENTSO-E runs the
same model for all
Member States and
the pan-European
assessments. Input
and output data are
more coherent.
Use of
established
institutional
processes
-
Unclear which
processes to be
used
+
Can build upon
established
processes
0/+
Can partially build
upon established
processes
-
Requires building
up new processes
(ENTSO-E to carry
out the assessment)
Efficient
organisational
structure
-
Each Member State
carries out its own
assessment
-
Each Member State
carries out its own
assessment
0/-
Each Member State
carries out its own
assessment based
on ENTSO-E
methodology
++
Efficient as
ENTSO-E carries
out the assessment
for all Member
States
Capacity
savings
--
Low capacity
savings
-
Higher capacity
savings due to
different treatment
of cross-border
capacity
+
Higher capacity
savings as single
methodology
++
Highest capacity
savings as single
methodology and
calculation
The assumptions are based on the Market Design Initiative consultations and other
meetings with stakeholders
In summary:
- Option 0, "No further action": will likely lead to significant over-investments and
hence will fall short in providing the adequate level of security of supply for
Europe for any given provision cost level.
- Option 1, "Harmonisation of national assessments": is likely to be more efficient
than Option 0, but cannot be expected to fully meet the specific objectives.
- Option 2, "ENTSO-E providing for a single methodology but Member States
carrying out the assessments": is likely to lead to less overinvestment.
Nonetheless, national interests could still play a role in the way in which the
assessments are done.
- Option 3, "ENTSO-E providing for a single methodology and carrying out the
assessments": seems, according to the assessment of the options, to be the most
appropriate measure for assessing generation adequacy assessment.
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Improved resource adequacy methodology
Subsidiarity
5.1.6.
The subsidiarity principle is fulfilled given that the generation adequacy challenges the
EU power system is facing cannot be optimally addressed based on national adequacy
assessments as is currently the case, as foreign contribution to national demand might not
be sufficiently taken into account. This can be the case because national assessments
apply different assumptions, calculatory approaches and data input. This is why it would
be best suited to require ENTSO-E to carry out a single updated generation adequacy
assessment for the EU based on a revamped methodology and high quality and granular
data input from TSOs including requiring Member States to exclusively rely on it when
arguing for CMs.
Requiring ENTSO-E to carry out a single generation adequacy assessment for the EU
would also be in line with the proportionality principle given that the total capacity
requirements for ensuring the same level of security of supply will be lower than in the
case of national adequacy assessments. This will strengthen the internal market by
making sure that resources are deployed and utilised efficiently across the EU.
Stakeholders' opinions
5.1.7.
Replies to the public consultation on the Market Design Initiative
A majority of stakeholders (34%) is in favour of sticking to an "energy-only" market,
possibly with a strategic reserve. Many generators and some governments disagree and
are in favour of market-wide CMs (in total 22% of stakeholders replies). Many
stakeholders (31%) share the view that properly designed energy markets would make
capacity mechanisms redundant (21% disagree).
There is almost a consensus amongst stakeholders on the need for a more aligned method
for generation adequacy assessment (73% in favour, 2% against). A majority of
answering stakeholders (47% of all stakeholders) supports the idea that any legitimate
claim to introduce CMs should be based on a common assessment. When it comes to
geographical scope of the harmonized assessment a vast majority of stakeholders (86%)
call for regional or EU-wide adequacy assessment while only a minority (20%) favour a
national approach.
Most of the stakeholders including Member States agree that a regional/European
framework for CMs are preferable. Member States, however, might want to keep a large
degree of freedom when proposing a CM. They might claim that beyond a revamped
regional/ EU generation adequacy assessment there is legitimacy for a national
assessment based on which they can claim the necessity of their CM.
Sensibilities
The CEER claims that "security of supply is no longer exclusively a national
consideration, but it is to be addressed as a regional and pan-European issue" and that
"generation adequacy needs to be addressed and coordinated at regional and European
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Improved resource adequacy methodology
level in order to maximise the benefit of the internal market for energy". As a conclusion
to their survey, the CEER published recommendations76
that emphasize the need for the
implementation of a single harmonised methodology. The PLEF has already used such a
common approach in a recent security of supply study77
. In addition, ENTSO-E's target
methodology is announced to be "fully in line with the methodology developed by the
TSOs of the PLEF"78
.
EFET79
is of the opinion that "the current 'national approach' potentially leads to an
over procurement of capacity as Member States do not appropriately take into account
what capacity is available outside of their borders. As a medium step, regional
assessments based on clusters of countries that are highly interconnected can be
efficient, as they will effectively pool resources over a wider area. The ENTSO-E SO&AF
reports are a first step in the direction of a European approach to adequacy assessment.
However, the reports so far only consolidate the analysis of individual TSOs for their
respective control area/country. Market participants still expect a truly European
adequacy assessment from ENTSO-E, and national regulators should support the
requests of ACER and the European Commission in that regard."
On the ENTSO-E methodology, Wind Europe80
is of the opinion that "most national
adequacy assessments focus on the contribution of firm generation units, with little or no
consideration for the contribution of other energy sources such as demand-side response,
storage, imports/exports or renewables." It recommends that "developing a holistic
approach that systematically and realistically include renewables, demand response,
storage and interconnections' contribution to adequacy."
76
Recommendations for the assessment of electricity generation adequacy, CEER
77
Pentalateral Energy Forum [PLEF] – Support Group 2, Generation Adequacy Assessment
78
Energy Community Workshop: "Towards Sustainable Development of Energy Community", RES
integration: the ENTSO-E perspective
79
EFET answer to the public consultation on the market design initiative
80
Wind Europe, "Assessing resource adequacy in an integrated EU power system" (May 2016)
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Cross-border operation of capacity mechanisms
5.2. Cross-border operation of capacity mechanisms
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Cross-border operation of capacity mechanisms
Summary table
5.2.1.
Objective: Framework for cross-border participation in capacity mechanisms
Option 0 Option 1 Option 2
Description
Do nothing.
No European framework laying out the details of an effective cross-
border participation in capacity mechanisms. Member States are likely to
continue taking separate approaches to cross-border participation,
including setting up individual arrangements with neighbouring markets.
Harmonised EU framework setting out procedures including
roles and responsibilities for the involved parties (e.g. resource
providers, regulators, TSOs) with a view to creating an effective
cross-border participation scheme.
Option 1 + EU framework harmonising
the main features of the capacity
mechanisms per category of mechanism
(e.g. for market-wide capacity
mechanisms, reserves, …).
Pros
Stronger enforcement
The Commission's Guidance on state interventions81
and the EEAG
require among others that such mechanisms are open and allow for the
participation of resources from across the borders. There is no reason to
believe that the EEAG framework is not enforced. To date, however,
there are not many practical examples of such cross-border schemes.
It would reduce complexity and the administrative impact for
market participants operating in more than one Member
States/bidding zone.
It would remove the need for each Member State to design a
separate individual solution – and potentially reduce the need for
bilateral negotiations between TSOs and regulators.
It would preserve the properties of market coupling and ensure
that the distortions of uncoordinated national mechanisms are
corrected and internal market able to deliver the benefits to
consumers.
In addition to benefits in Option 1, it
would facilitate the effective
participation of foreign capacity as it
would simplify the design challenge and
would probably increase overall
efficiency by simplifying the range of
rules market participants, regulators and
system operators have to understand.
Cons
As the conclusion of individual cross-border arrangements depend on the
involved parties' willingness to cooperate it is likely that this option will
cement the current fragmentation of capacity mechanisms. Arranging
cross-border participation on individual basis is likely to involve high
transaction costs for all stakeholders (TSOs, regulators, ressource
providers).
It would be a cost for TSOs and regulators which would have to
agree on the rules and enforce them across the borders. These
costs would be lower than in Option 0 though.
In addition to the drawback of Option 1,
it would limit the choice of instruments.
Most suitable Option(s): Options 1 and 2
81
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf
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Cross-border operation of capacity mechanisms
Description of the baseline
5.2.2.
DG COMP's sector enquiry on Capacity Mechanisms found that cross-border
participation is not yet enabled in the majority of CMs, and with different Member States
developing different solutions for their already different national capacity mechanisms
there is an emerging risk of increasing fragmentation in the market.
The exclusion of foreign capacity from CMs reduces the efficiency of the internal market
and increases costs for consumers. The most damage is done if Member States make no
assessment of the possibility of imports when setting the amount of capacity to contract
through a CM (in a volume-based model) or setting the price required to bring forward
the required volume (in a price-based mechanism). In this approach (no cross-border
participation), there would be greater distortion of the signals for where new capacity
should be built, and an increase in overall system costs due to overcapacity. In addition,
CMs would fail to adequately reward investment in interconnection that allows access to
capacity located in neighbouring markets. The potential unnecessary costs of this
overcapacity has been estimated at up to 7.5 billion euros per year in the period 2015-
203082
.
Some Member States have attempted to address the problem by taking account of
expected imports (at times of scarcity) when setting the volume to contract in their
capacity mechanism (defined as implicit participation) This reduces the risk of
domestic overprocurement and recognises the value to security of supply of connections
with the internal energy market. However, implicit participation does not remunerate
foreign capacity for the contribution it makes to security of supply in the CM zone. If
only domestic capacity recieves capacity payments, there will be a greater incentive for
domestic investment than investment in foreign capacity or interconnectors resulting in
less than optimal investment in foreign capacity and in interconnector capacity.
The best approach to this would be explicit participation which means that the
contribution of imports to the CM zone must not only be identified, but the providers of
this foreign capacity need to be remunerated for the security of supply benefits that they
deliver to the CM zone.
This approach has been formalised in the Commission's Guidance on state interventions83
and the EEAG which require among others explicit participation of foreign capacity in
the CM (EEAG 232).
However, putting in place a functioning explicit cross-border CM requires multiple
arrangements involving several parties (e.g. resource providers, TSOs, regulators). This
is a difficult exercise requiring willingness and cooperation from all parties which cannot
82
See Booz & co, 2013, 'Study on the benefits of an integrated European Energy market'
83
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf
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Cross-border operation of capacity mechanisms
be taken for granted. This could explain why, to date, there are not many practical
examples of such cross-border schemes.
Member States who have implemented an explicit cross-border scheme have taken
different approaches. Portugal, Spain and Sweden appear to take no account of imports
when setting the amount of capacity to support domestically through their CMs. In
Belgium, Denmark, France and Italy, expected imports are reflected in reduced domestic
demand in the CMs. The only Member States that have allowed the direct participation of
cross-border capacity in CMs are Belgium, Germany and Ireland.
Foreign plants were allowed to participate in the Belgian tender for new capacity,
provided that they would subsequently become part of the Belgian bidding zone even if
geographically located in another Member State.
In the Irish tender, foreign capacity could participate if it could demonstrate its
contribution to Irish security of supply – no foreign capacity was selected in the tender.
In the existing Irish capacity payments model, foreign capacity can benefit from capacity
payments. However, the method for enabling this participation involves levies and
premiums on electricity prices and is not therefore compatible with market coupling rules
which require electricity prices, not capacity premiums/taxes, to provide the signal for
imports and exports84
.
None of the strategic reserves are open to generators located outside of the Member State
operating the reserve mechanism; except for the German network reserve which contracts
capacity outside of Germany provided that it can contribute to alleviating security of
supply problems in Southern Germany through re-dispatch abroad.
Despite the current lack of foreign participation, many Member States are trying to
develop cross-border participation in their mechanisms. France carried out last year a
consultation which outlined different options for the participation of interconnectors or
foreign capacity in the decentralised obligation scheme. Ireland published a consultation
in December85
on options for cross-border participation in its planned mechanism. Italy is
apparently considering future foreign participation in its capacity mechanism. Since
December 2015 the British capacity mechanism has included interconnectors with
Britain, which can participate as price takers in capacity auctions.
Deficiencies of the current legislation
5.2.3.
The Commission's current tool to assess whether government interventions in support of
generation adequacy are legitimate is State aid scrutiny. The EEAG require among others
a proof that the measure is necessary, technological neutral and allows for explicit cross-
border participation. Beyond the requirements of the Commission's guidance on state
intervention and the EEAG, there is no European framework laying out the details of an
effective cross-border participation in capacity mechanisms.
84
Note however that the Irish capacity mechanism does operate across the UK and Irish border because
of joint market arrangements and a single bidding zone covering Ireland and Northern Ireland.
85
https://www.semcommittee.com/overview?article=f254d505-16bc-4a66-b940-bf2cc7b614ae
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Cross-border operation of capacity mechanisms
This could explain why few Member States have developed cross-border schemes with
explicit participation, which means that (at best) they only implicitly take into account
foreign capacities. If Member States limit participation in a national mechanism only to
capacity providers located within their borders, and make overly conservative
assumptions about their level of imports they should expect, this will lead to distorted
locational investment signals and over-capacity in areas with capacity mechanisms.
These distortions can benefit incumbent market participants which will further reduce
competition in the long run.
Member States wanting to comply with the EEAG requirements have to individually
arrange, for each of their borders separately, the necessary cross-border arrangements
involving a multitude of parties including regulators, resource providers and TSOs.
Arranging cross-border participation on individual basis is likely to involve high
transaction costs for all stakeholders. This is also a difficult exercise requiring
willingness and cooperation from all parties which cannot be taken for granted.
When developing solutions for explicit participation of interconnectors and foreign
capacity to their CM, Member States need to address a number of policy considerations.
For example, an explicit participation model needs to identify:
- Whether there should be any restriction on the amount of capacity that can
participate from each connected bidding zone;
- What type of capacity product (obligations and penalties) should apply to foreign
capacity providers; and
- Which foreign capacity providers are eligible to participate (DSR, generation,
storage).
It is therefore not surprising that 85% of market participant respondents and 75% of
public body respondents to the sector inquiry questionnaire felt that rules should be
developed at EU level to limit as much as possible any distortive impact of CMs on cross
national integration of energy markets.
The fact that cross-border participation is not yet enabled in the majority of CMs as
highlighted on p.30 of the Evaluation, and with different Member States developing
different solutions for their already different national CMs, there is an emerging risk of
increasing fragmentation in the market.
Presentation of the options
5.2.4.
Option 0 - BAU
The Commission's Guidance on state interventions86
and the EEAG require among others
that such mechanisms are open and allow for the participation of resources from across
the borders.
86
http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf
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Cross-border operation of capacity mechanisms
The EEAG include the following requirements related to cross-border participation in a
generation adequacy measure:
i. Should take the contribution of interconnection into account (226);
ii. Should be open to interconnectors if they offer equivalent technical performance
to other capacity providers (232)
iii. Where physically possible, operators located in other members states should be
eligible to participate (232);
iv. Should not reduce incentives to invest in interconnection, nor undermine market
coupling (233).
As explained above, the EEAG requires among others explicit participation of foreign
capacity in the capacity mechanism (EEAG 232). However, Option 0 does not provide
for a European framework setting out harmonised rules of an effective cross-border
participation scheme.
Option 0+
Despite the EEAG requirements for Member States to individually arrange, for each of
their borders separately, the necessary cross-border arrangements, few Member States
have voluntraily collaborated to develop an effective cross-border scheme. This is a
difficult exercise requiring willingness and cooperation from all parties which cannot be
taken for granted.
Option 1 - Harmonised EU framework setting out procedures including roles and
responsibilities for the involved parties (e.g. resource providers, regulators, TSOs) with a
view to creating an effective cross-border participation scheme
Under this option there would be a requirement for Member States to allow for explicit
participation of foreign capacity in national CMs.
There would also be a harmonised EU framework setting out procedures including roles
and responsibilities for the involved parties (e.g. resource providers, regulators, TSOs)
with a view to creating an effective cross-border participation scheme. The framework
would:
a) Define the appropriate share of foreign participation (de-rating of resources);
b) Allocation of 'entry tickets' to foreign resource providers87
;
87
The contribution foreign capacity makes to a neighbour's security of supply is provided partly by the
foreign generators or demand response providers that deliver electricity, and partly by the transmission
(interconnection) allowing power to flow across borders. Depending on the border, there can be a
relative scarcity of either interconnection or foreign capacity. To ensure the right investment
incentives, the revenues from the mechanisms paid to the interconnection and/or the foreign capacity
should reflect the relative contribution each makes to security of supply in the zone operating the CM.
Where interconnection is relatively scarce but there is ample foreign capacity in a neighbouring zone,
the interconnectors should thus receive the majority of CM. This would reinforce incentives to invest
in additional interconnection, which is the limiting factor in in this case. Conversely, where there is
ample interconnection but scarcity of foreign capacity, the foreign capacity should receive most of the
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Cross-border operation of capacity mechanisms
c) Same remuneration principles for domestic and foreign resource providers;
d) No booking (or setting aside) of cross-border capacities for cross-border
participation;
e) Contribution of foreign capacity in parallel scarcity situations88
to be addressed
by de-rating factors;
f) No delivery obligation (only availability);
g) No adjustment of cross-border schedules;
h) No limitation of the participation of a capacity resource to a single CM where the
resource can contribute to security of supply in more than one CM zone.
More details regarding the harmonised EU framework
De-rating of resources: De-rating of interconnectors and/or foreign capacity refers to an evaluation of the
expected actual contribution of a capacity provider on average, over the long-term, at times when it is
required. This issue is critical as conservative assumptions will lead to overcapacity, and overly generous
assumptions will potentially lead to unmet demand (and potentially reduced confidence in the value of
interconnection).
Entry-tickets to foreign resource providers: Foreign capacity providers would have to acquire specific
"interconnection tickets" to allow them to explicitly participate in the CM. Foreign capacity bids to get
access to the capacity market via the interconnection, up to the level of available interconnection capacity.
The interconnection receives revenues from "interconnection tickets" auctioning. Foreign capacities
receive revenues at "local CM" clearing price. This would allow a priori a market-based split of value and
the right incentive for investments.
Same remuneration principles for domestic and foreign resource providers: In principle, if the
allocation process for capacity contracts allows interconnector or foreign capacity to compete directly with
domestic capacity, the obligation and penalties faced by the interconnector or foreign capacity providers
should be the same as the obligations and penalties faced by the domestic capacity providers.
No booking of cross-border capacity for cross-border participation: One of the basic features of
capacity mechanisms is that the participating resources (mainly generators) receive a payment for their
availably in times of expected system stress. Whether a participating resource actually generates electricity
depends on short-term market price signals (effectively intra-day and balancing market prices). This
mechanism makes sure that power flows to the area in Europe that needs it most. For example, if short-
term prices in Belgium turn out to be 2.000 EUR/MWh while prices around Belgium are only 250
EUR/MWh the market coupling algorithm (and successive intra-day exchanges) will make sure that all
available transmission capacities on the Belgian border will be used to flow power into the country. The
limiting factor to supply Belgium in times of stress is (most likely) not the availability of generating assets
in Europe but the relative scarcity of transmission capacities towards Belgium. Setting aside transmission
capacities for the purposes of cross-border participation will therefore not improve the security of power
supplies in Belgium but will only interfere with the efficient functioning of power markets. Participation of
resources from across the border should therefore not be link to the effective delivery of electricity from
capacity remuneration. In this case, foreign capacity is the limiting factor that should receive
additional incentives.
88
The extent to which an interconnector can reliably provide imports to the countries it connects depends
not just on the line's technical availability but also on the potential for concurrent scarcity in the
connected markets. If zone A only has a winter peak demand problem and connected zone B only has
a summer peak demand problem, each may expect 100% imports from the other at times of local
scarcity. However, if countries A and B are neighbours with similar demand profiles and some similar
generation types, there may be some periods of concurrent scarcity where neither can expect imports
from the other.
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Cross-border operation of capacity mechanisms
that resource. Paying for capacity (availability) across the borders can still make sense as this provides
incentives to keep resources available to produce if market prices signal so.
Contribution of foreign capacity in parallel scarcity situations to be addressed by de-rating factors:
In practice, it is extremely unlikely that scarcity events will be perfectly correlated between two
neighbouring countries. So, to avoid a situation where overall less contribution by imports to security of
supply is assumed than is truly the case, a statistical judgement – de-rating of the interconnectors on each
border to reflect expected long-run average import capacity at times of scarcity – is needed for each
capacity mechanism. The amount of capacity demanded domestically should be reduced by this amount,
and this capacity is then available for allocation to foreign capacity providers.
No delivery obligation (only availability): An availability cross-border product allows the internal market
to function unimpeded and avoids creating distortions to merit order dispatch that might be created with
delivery obligations. Moreover, an availability product provides an additional incentive for Member States
to correct regulatory failures and ensure their electricity prices reflect scarcity – which has further benefits
for market functioning as such prices provide a signal for investment in flexible capacity and enable
demand response. Lastly, establishing a relatively simple availability product – along with other common
rules – makes cross-border participation much more readily implementable.
No adjustment of cross-border schedules: Because of the potential for delivery obligations to create
distortions in neighbouring markets and the fact that anyway such obligations can only incentivise actions
which are likely to have a very limited effect on cross-border flows, delivery obligations are not
appropriate for interconnectors or foreign capacity.
No limitation of the participation of a capacity resource to a single CM where the resource can
contribute to security of supply in more than one CM zone: Without this requirement explicit
participation is likely to lead to overcapacity which would be a worse outcome than implicit participation.
Option 2: – Option 1 + EU framework harmonises the main features of the capacity
mechanisms per category of mechanism (e.g. for market-wide capacity mechanisms,
reserves, …)
In addition to Option 1, the EU framework would harmonise the main features of the
capacity mechanisms per category of mechanism (e.g. for market-wide capacity
mechanism, reserves, etc.), such as the properties of capacity product to be offered, the
duration of the obligation, etc.
Comparison of the options
5.2.5.
Contribution to policy objectives
Option 0 already requires explicit participation of foreign capacity in the CM under the
EEAG rules. However, the EEAG framework does not set out harmonised rules of an
effective cross-border participation scheme. This explains why few Member States have
developed cross-border schemes with explicit participation, which means that (at best)
they only implicitly take into account foreign capacities. If Member States limit
participation in a national mechanism only to capacity providers located within their
borders, and make overly conservative assumptions about their level of imports they
should expect, this will lead to distorted locational investment signals and over-capacity
in areas with capacity mechanisms, and an increase in overall system costs. As the
conclusion of individual cross-border arrangements depend on the involved parties'
willingness to cooperate it is likely that this option will cement the current fragmentation
of capacity mechanisms. Arranging cross-border participation on individual basis for
each of a Member States borders is likely to involve high transaction costs for all
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Cross-border operation of capacity mechanisms
stakeholders (TSOs, regulators, ressource providers). This is also a difficult exercise
requiring willingness and cooperation from all parties which cannot be taken for granted.
Option 1 would facilitate explicit cross-border participation as already required by
EEAG by providing an EU framework with roles and responsibilities of the involved
parties. This option would remove the need for each Member State to design a separate
individual solution – and potentially reduce the need for bilateral negotiations between
TSOs. It would also reduce complexity and the administrative impact for market
participants operating in more than one zone. Hence, it is likely that an increased number
of Member States would implement an effective cross-border scheme. Explicit
participation would lower overall system costs as it corrects investment signals and
enables a choice between local generation and alternatives. On one hand, the capacity in
a CM zone will bid lower into the domestic CM as a result of access to revenues from
electricity and capacity in neighbouring zones. On the other hand, this will lead to more
investment in capacity in a non-CM zone, and in transmission to neighbouring CM
zones, if capacity in a non-CM zone has access to neighbouring capacity and energy
prices. All in all, with the design options of an EU framework chosen above, Option 1 is
likely to better preserve operational market efficiencies (e.g. market coupling) and ensure
that the investment distortions of uncoordinated national mechanisms are corrected and
the internal market able to deliver the benefits to consumers.
Option 2 would facilitate the effective participation of foreign capacity as it would
simplify the design challenge and would probably increase overall efficiency by
simplifying the range of rules market participants, regulators and system operators have
to understand. At the same time there is a risk that it would limit the choice of
instruments and potentially the ability to answer a wider range of problems that capacity
mechanisms could address.
Key economic impacts
The economic impacts of the different options are analysed in the core document
"Section 6 - Problem Area II".
Impact for businesses and public authorities
Although the cost of designing cross-border participation in CM depends to some extent
on the design of the CMs, an expert study89
estimated that such cost corresponds roughly
to 10%90
of the overal cost of the design of a CM91
. In addition, they estimate costs
associated with the operation of a cross-border scheme i.e. additional costs if cross-
border participation is facilitated to amount to 6-30 FTEs92
for TSOs and regulators
combined. TSOs and regulators have to check pre-qualification and registration
89
Thema (2016), Framework for cross-border participation in capacity mechanisms (First interim
report)
90
Costs in the design phase are one-time costs.
91
The same expert study also found that the overall cost of of the design are fairly small compared to the
overall cost of the CM (remuneration of the participation ressources).
92
FTEs in other phases refer to (annually) recurring costs.
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Cross-border operation of capacity mechanisms
(eligibility phase) and ensure compliance i.e. monitoring, control, penalties (control/
compliance phase).93
Market participants participating in a cross-border scheme would
potentially have additional costs of 0-3 FTEs.
The expert study found that providing for a common framework for cross-border
participation (Option 1) would actually reduce the cost of cross-border participation
when compared with Option 0. This is because in Option 0 cross-border arrangements
have to be set up and operated based on indivdual arrangements which involve costs that
can be saved if these arrangements follow a template. For TSOs and NRAs, the study
estimates the cost saving for Option 1 to be 30% of eligibility costs and compliance costs
compared to Option 0.
In analogy to Option 1 we would expect that providing for a common template for
capacity mechanisms (Option 2) would actually reduce the design cost of CMs when
compared with Option 0 and Option 1. This is because in Option 0 and Option 1 CMs are
designed individually which involve costs that can be saved if the CM design follows a
template. For TSOs and NRAs, the study estimates the cost savings to be 50% of
eligibility costs and compliance costs compared to Option 0.
93
There is a difference between a generator model for cross-border participation and an interconnector
model in relation to the costs. This difference can be explained by the number of participants and
jurisdictions. The more participants and countries participate, the greater the potential for increased
costs.
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Table 1: Comparison of the Options in terms of their effectiveness, efficiency and
coherence of responding to specific criteria
Option 0:
do nothing (EEAG)
Option 1:
EU framework for
cross-border
participation
Option 2: EU
framework for cross-
border participation +
blueprint
Investment distortions
due to uncoordinated
CMs
-
More chance of
distorted locational
signals and over-
capacity in zones with
CM
+
Less chance of
investment distortions
due to effective cross-
border scheme
+
Less chance of
investment distortions
due to effective cross-
border scheme
Overall system costs
-
Higher overall system
costs
+
Lower overall system
costs due to reduction in
CM auction price
+
Lower overall system
costs due to reduction in
CM auction price
Speed of
implementation
-
Individual XB
arrangements for each
border
+
Harmonised XB
arrangements across the
EU
+
Harmonised XB
arrangements across the
EU
Complexity and
administrative impact
--
High administrative
impact for market
participants operating in
more than one zone
+
Reduced complexity
and administrative
impact due to
harmonised rules
+
Reduced complexity
and administrative
impact due to
harmonised rules
The assumptions are based on the Market Design Initiative consultations and other meetings with
stakeholders
Subsidiarity
5.2.6.
The subsidiarity principle is fulfilled given that the EU is best placed to provide for a
harmonised EU framework with a view to creating an effective cross-border participation
scheme. Member States currently take separate approaches to cross-border participation
including often not allowing for foreign participation or only implicitly taking into
account foreign contribution to own security of supply. As cross-border participation in
CMs requires neighbouring TSOs' and NRA's full cooperation, individual Member States
might not be able to deliver a workable system or only provide suboptimal solutions.
Providing for a framework on cross-border participation in capacity mechanisms would
be also in line with the proportionality principle given that it aims at preserving the
properties of market coupling and ensuring that the distortions of uncoordinated national
mechanisms are corrected and the internal market is able to deliver the benefits to
consumers. At the same time, it removes the need for each Member State to design a
separate individual solution – and potentially reducing the need for bilateral negotiations
between TSOs and NRAs.
Stakeholders' opinions
5.2.7.
Public consultation on the Market Design Initiative
Stakeholders clearly support a common EU framework for cross-border participation
in capacity mechanisms (52% in favour, 10% against). Most of the stakeholders
including Member States agree that a regional/European framework for CMs are
preferable. Similarly, Member States might instinctively want to rely more on national
assets and favour them over cross-border assets. It is often claimed that in times of
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Cross-border operation of capacity mechanisms
simultaneous stress, governments might choose to 'close borders' putting other Member
States who might actually be in bigger need in trouble.
Sensibilities
EFET94
is of the opinion that "Member States with a CM need to explicitly take into
account the contribution of foreign capacities. This will likely require advanced TSO-
TSO cooperation, and will require more complex arrangement at EU or regional level.
EFET therefore supports the establishment of EU rules in this domain. One note of
caution though: in no case should the cross-border participation to national CMs result
in any reservation of cross-border transmission capacity or alteration of cross-border
flows from the market outcomes".
Wind Europe95
"acknowledges the need for a common set of indicators and criteria for
cross-border participation, as this is a necessary condition for the existence of capacity
markets where needed." […] In addition, they "call for a strong involvement of the
Commission to ensure that such a common European framework for cross-border
participation does not serve as a pretext for introducing potentially unneccesary CMs."
ACER and CEER96
"fully endorse that explicit participation of foreign capacity
providers into national CMs through a market-based mechanism should be allowed. In
this respect, […] a few important prerequisites need to be fulfilled to make explicit cross-
border participation possible and beneficial: a) TSOs are incentivised to make a
sufficient and appropriate amount of cross-border capacities available for cross-border
trade throughout the year(s); b) TSOs are not allowed to adjust, limit or reserve these
cross-border transmission capacities at any point in time, including in case of shortage
situation; and c) TSOs agree ex ante on the treatment of local/ foreign adequacy
providers in case of a widespread shortage situation (i.e. when a shortage situation
affects at least two countries simultaneously)."
94
EFET response to the public consultation on the Market Design Initiative, 2015
95
WindEurope response to the public consultation on the Market Design Initiative, 2015
96
ACER-CEER response to European Commission Capacity Mechanism Sector Inquiry, July 2016


EN EN
EUROPEAN
COMMISSION
Brussels, 30.11.2016
SWD(2016) 410 final
PART 5/5
COMMISSION STAFF WORKING DOCUMENT
IMPACT ASSESSMENT
Accompanying the document
Proposal for a Directive of the European Parliament and of the Council on common
rules for the internal market in electricity (recast)
Proposal for a Regulation of the European Parliament and of the Council on the
electricity market (recast)
Proposal for a Regulation of the European Parliament and of the Council establishing
a European Union Agency for the Cooperation of Energy Regulators (recast)
Proposal for a Regulation of the European Parliament and of the Council on risk
preparedness in the electricity sector
{COM(2016) 861 final}
{SWD(2016) 411 final}
{SWD(2016) 412 final}
{SWD(2016) 413 final}
Europaudvalget 2016
KOM (2016) 0863
Offentligt
303
TABLE OF CONTENTS
6. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA III: A NEW LEGAL
FRAMEWORK FOR PREVENTING AND MANAGING CRISES SITUATIONS......... 305
Summary table.............................................................................................................................305
6.1.1.
Description of the baseline..........................................................................................................309
6.1.2.
Deficiencies of the current legislation .........................................................................................310
6.1.3.
Presentation of the options .........................................................................................................314
6.1.4.
Comparison of the options ..........................................................................................................326
6.1.5.
Subsidiarity...................................................................................................................................335
6.1.6.
Stakeholders' Opinions ................................................................................................................336
6.1.7.
7. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA 4: THE SLOW
DEPLOYMENT OF NEW SERVICES, LOW LEVELS OF SERVICE AND POOR RETAIL
MARKET PERFORMANCE ................................................................................................. 339
7.1. Addressing energy poverty .........................................................................................................341
Summary table.............................................................................................................................342
7.1.1.
Description of the baseline..........................................................................................................344
7.1.2.
Deficiencies of the current legislation .........................................................................................356
7.1.3.
Presentation of the options.........................................................................................................358
7.1.4.
Comparison of the options ..........................................................................................................370
7.1.5.
Subsidiarity...................................................................................................................................395
7.1.6.
Stakeholders' Opinions ................................................................................................................396
7.1.7.
7.2. Phasing out regulated prices.......................................................................................................401
Summary table.............................................................................................................................402
7.2.1.
Description of the baseline..........................................................................................................403
7.2.2.
Deficiencies of the current legislation .........................................................................................404
7.2.3.
Presentation of the options .........................................................................................................407
7.2.4.
Comparison of the options ..........................................................................................................409
7.2.5.
Subsidiarity...................................................................................................................................448
7.2.6.
Stakeholders' opinions.................................................................................................................448
7.2.7.
7.3. Creating a level playing field for access to data ...........................................................................453
Summary table.............................................................................................................................454
7.3.1.
Description of the baseline..........................................................................................................455
7.3.2.
Deficiencies of the current legislation .........................................................................................457
7.3.3.
Presentation of the options .........................................................................................................457
7.3.4.
Comparison of the options ..........................................................................................................458
7.3.5.
Subsidiarity...................................................................................................................................461
7.3.6.
Stakeholders' opinions.................................................................................................................461
7.3.7.
7.4. Facilitating supplier switching.....................................................................................................467
Summary table.............................................................................................................................468
7.4.1.
Description of the baseline..........................................................................................................469
7.4.2.
Deficiencies of the current legislation .........................................................................................478
7.4.3.
Presentation of the options .........................................................................................................478
7.4.4.
Comparison of the options ..........................................................................................................479
7.4.5.
Subsidiarity...................................................................................................................................484
7.4.6.
Stakeholders' opinions.................................................................................................................485
7.4.7.
7.5. Comparison tools........................................................................................................................489
Summary table.............................................................................................................................490
7.5.1.
304
Description of the baseline..........................................................................................................491
7.5.2.
Deficiencies of the current legislation .........................................................................................496
7.5.3.
Presentation of the options .........................................................................................................497
7.5.4.
Comparison of the options ..........................................................................................................500
7.5.5.
Subsidiarity...................................................................................................................................509
7.5.6.
Stakeholders' opinions.................................................................................................................510
7.5.7.
7.6. Improving billing information .....................................................................................................515
Summary table.............................................................................................................................516
7.6.1.
Description of the baseline..........................................................................................................517
7.6.2.
Deficiencies of the current legislation .........................................................................................530
7.6.3.
Presentation of the options .........................................................................................................534
7.6.4.
Comparison of the options ..........................................................................................................535
7.6.5.
Subsidiarity...................................................................................................................................545
7.6.6.
Stakeholder's opinions.................................................................................................................547
7.6.7.
8. DESCRIPTION OF RELEVANT EUROPEAN R&D PROJECTS ............................... 553
305
Addressing energy poverty
6. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA III: A NEW LEGAL FRAMEWORK FOR PREVENTING AND MANAGING CRISES SITUATIONS
Summary table
6.1.1.
Objective: Ensure a common and coordinated approach to electricity crisis prevention and management across Member States, whilst avoiding undue government
intervention
Option 0: Do nothing Option 0+: Non-
regulatory
approach
Option 1: Common minimum
EU rules for prevention and
crisis management
Option 2: Common minimum EU rules plus regional
cooperation, building on Option 1
Option 3: Full harmonisation
and full decision-making at
regional level, building on
Option 2
Assessments
Rare/extreme risks and
short-term risks related to
security of supply are
assessed from a national
perspective.
Risk identification &
assessment methods differ
across Member States.
- This option was
disregarded as no
means for
enhanced
implementing of
existing acquis
nor for enhanced
voluntary
cooperation were
identified
- Member States to identify and
assess rare/extreme risks based on
common risk types.
-
ENTSO-E to identify cross-border electricity crisis scenarios
caused by rare/extreme risks, in a regional context. Resulting
crisis scenarios to be discussed in the Electricity
Coordination Group.
Common methodology to be followed for short-term risk
assessments (ENTSO-E Seasonal Outlooks and week-ahead
assessments of the RSCs).
All rare/extreme risks
undermining security of supply
assessed at the EU level, which
would be prevailing over
national assessment.
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Addressing energy poverty
Plans
Member States take
measures to prevent and
prepare for electricity crisis
situations focusing on
national approach, and
without sufficiently taking
into account cross-border
impacts.
No common approach to
risk prevention &
preparation (e.g., no
common rules on how to
tackle cybersecurity risks).
a)
- - Member States to develop
mandatory national Risk
Preparedness Plans setting out
who does what to prevent and
manage electricity crisis
situations.
-
- Plans to be submitted to the
Commission and other Member
States for consultation.
-
- Plans need to respect common
minimum requirements. As
regards cybersecurity, specific
guidance would be developed.
Mandatory Risk Preparedness Plans including a national and
a regional part. The regional part should address cross-border
issues (such as joint crisis simulations, and joint
arrangements for how to deal with situations of simultaneous
crisis) and needs to be agreed by Member States within a
region.
Plans to be consulted with other Member States in the
relevant region and submitted for prior consultation and
recommendations by the Electricity Coordination Group.
Member States to designate a 'competent authority' as
responsible body for coordination and cross-border
cooperation in crisis situations.
Development of a network code/guideline addressing specific
rules to be followed for the cybersecurity.
Extension of planning & cooperation obligations to Energy
Community partners
Mandatory Regional Risk
Preparedness Plans, subject to
binding opinions from the
European Commission.
Detailed templates for the plans
to be followed.
A dedicated body would be
created to deal with
cybersecurity in the energy
sector.
Crisis
management
Each Member State takes
measures in reaction to
crisis situations based on its
own national rules and
technical TSO rules.
No co-ordination of actions
and measures beyond the
technical (system operation)
level. In particular, there are
no rules on how to
coordinate actions in
simultaneous crisis
situations between adjacent
markets.
No systematic information-
sharing (beyond the
technical level).
Minimum common rules on crisis
prevention and management
(including the management of
simultaneous electricity crisis)
requiring Member States to:
(i) not to unduly interference with
markets;
(ii) to offer assistance to others
where needed, subject to financial
compensation, and to;
(iii) inform neighbouring Member
States and the Commission, as of
the moment that there are serious
indications of an upcoming crisis
and during a crisis.
Minimum obligation as set out in Option 1.
Cooperation and assistance in crisis between Member States,
in particular simultaneous crisis situations, should be agreed
ex-ante; also agreements needed regarding financial
compensation. This also inclues agreements on where to shed
load, when an to whom. Details of the cooperation and
assistance agreements and resulting compensation should be
described in the Risk Preparedness Plans.
Crisis is managed according to
the regional plans, including
regional load-shedding plans,
rules on customer
categorisation, a harmonized
definition of 'protected
customers' and a detailed
'emergency rulebook' set forth
at the EU level.
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Addressing energy poverty
Montoring
Monitoring of security of
supply predominatly at the
national level.
ECG as a voluntary
information exchange
platform.
- - Systematic discussion of ENTSO-
E Seasonal Outlooks in ECG and
follow up of their results by
Member States concerned.
Systematic monitoring of security of supply in Europe, on the
basis of a fixed set of indicators and regular outlooks and
reports produced by ENTSO-E, via the Electricity
Coordination Group.
Systematic reporting on electricity crisis events and
development of best practices via the Electricity Coordination
Group.
A European Standard (e.g. for
EENS and LOLE) on Security
of Supply could be developed
to allow performance
monitoring of Member States.
Pros
Minimum requirements for plans
would ensure a minimum level of
preparedness across EU taking
into account cyber security.
EU wide minimum common
principles would ensure
predictability in the triggers and
actions taken by Member States.
Common methodology for assessments would allow
comparability and ensure compatibility of SoS measures
across Member States. Role of ENTSO-E and RSCs in
assessment can take into account cross-border risks.
Risk Preparedness Plans consisting of a national and regional
part would ensure sufficient coordination while respecting
national differences and competences. Minimum level of
harmonization for cybersecurity throughout the EU.
Designation of competent authority would lead to clear
responsibilities and coordination in crsis.
Common principles for crisis management and agreements
regarding assistance and remuneration in simultaneous
scarcity situations would provide a base for mutual trust and
cooperation and prevent unjustified intervention into market
operation.
Enhanced role of ECG would provide adequate platform for
discussion and exchange between Member States and
regions.
Regional plans would ensure
full coherence of actions taken
in a crisis.
308
Addressing energy poverty
Cons
Lack of cooperation in risk
preparedness and managing
crisis may distort internal
market and put at risk the
security of supply of
neighbouring countries.
Risk assessment and preparedness
plans on national level do not take
into account cross-border risks
and crisis which make the plans
less efficient and effective.
Minimum principles of crisis
management might not
sufficiently adress simultaneous
scarcity situations.
The coordination in the regional context requires
administrative resources.
Cybersecurity here only covers electricity, whereas the
provisions should cover all energy sub-sectors including oil,
gas and nuclear.
Regional risk preparedness
plans and a detailed templates
would have difficulties to fit in
all national specificities.
Detailed emergency rulebook
might create overlaps with
existing Network Codes and
Guidelines.
Most suitable option(s): Option 2, as it provides for sufficient regional coordination in preparation and managing crsis while respecting national differences and competences.
309
Addressing energy poverty
Description of the baseline
6.1.2.
In the area of risk prevention and management of crisis situations the current legislation
is scattered over different legal acts.
Regarding risk assessment and preparedness, currently Article 4 of the Electricity
Directive obliges Member States to ensure the monitoring of security of supply issues.
Such monitoring should, in particular, cover the balance of supply and demand, the
quality and level of maintenance of the networks, as well as the measures to cover peak
demand and to deal with shortfalls of one or more suppliers. This also includes the
obligation to publish every two years, by 31 July, a report outlining the findings resulting
from the monitoring, as well as any measures taken or envisaged to address them.
Member States should submit the report to the Commission.
Additionally, ENTSO-E has the obligation to carry out seasonal outlooks (6 month –
summer & winter outlooks) as required by Article 8 of the Electricity Regulation. The
assessments, which follow a probabilistic generation adequacy methodology, explore the
main risks identified within a seasonal period and highlighting the possibilities for
neighbouring countries to contribute to the generation/demand balance in critical
situations.
In terms of coordination and exchange of information among Member States, the
Commission created in 2012 the Electricity Coordination Group1
in the aftermath of
Fukushima crisis. The Group is a platform for the exchange of information and
coordination of electricity policy measures having a cross-border impact. It also should
facilitate the exchange of information and cooperation on security of electricity supply
including the coordination of action in case of an emergency within the Union.
The legislation on crisis management is set by Directive 2005/89/EC (SoS Directive),
Article 42 of the Electricity Directive and, as regards technical issues, the network codes,
in particular by the Network Code on Emergency and Restoration ('NC ER') which is
currently in comitology for approval. In addition, also the CACM Guideline and the
Guideline on System Operation (SO Guideline) set out operational procedures during
crisis situations, in particular on system operation to be implemented by TSOs.
The Electricity Directive contemplates in its Article 42 the possibility for Member
States to take temporary safeguard measures in the event of a sudden crisis and where the
physical safety or security of persons, apparatus or installation or system integrity is
threatened. Member States are obligated to notify those measures without delay to the
other Member States and the Commission. Any safeguard measures taken by Member
States must "cause the least possible disturbance in the functioning of the internal market
and must not be wider in scope than is strictly necessary [...]." In taking safeguard
measures “Member States shall not discriminate between cross-border contracts and
national contracts" according to Article 4(3) of the SoS Directive.
1
Commission Decision of 15 November 2012 setting up the Electricity Coordination Group. OJ C353,
17.11.2012, p.2.
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Addressing energy poverty
Table 2: Specific provisions in network codes and guidelines governing crisis
prevention and management at the technical level
The Network Code on Emergency and Restoration ('NC ER') requires in preparation for emergency
situations that the relevant Regional Security Coordinators (RSCs) ensure consistency of individual TSO
System Defence Plans2
. This includes inter-TSO information exchange, identification of threats within the
capacity calculation region and identification of incompatibilities of planned measures. During emergency
"each TSO shall provide through interconnectors any possible assistance" to its neighbours and to prepare
automatic load-shedding plans to ensure stable system frequency3
. Concerning suspension of (cross-
border) market activities, TSOs can suspend the provision of cross-zonal capacity and the submission of
balancing bids under the following circumstances4
: (a) blackout state or imminent risk of a blackout state
after market mechanisms are exhausted; (b) continuing market activities decreases effectiveness of
restoration towards normal/alert state; (c) communication tools of TSO to facilitate market are not
available. It also addresses recovery and settlement of costs related to emergency measures between TSOs
and market participants, subject to assessment through NRAs5
.
The Regulation on Capacity Allocation and Congestion Management (CACM) addresses the firmness
of cross-zonal allocated capacity in case of 'force majeure' or emergency situations. It defines 'force
majeure' as unusual event which has happened, is objectively verifiable, is beyond the control of a TSO and
makes it impossible for the TSOs to fulfil its obligations as set out by the CACM Guideline. According to
Article 72, the event of 'force majeure' allows TSOs to curtail allocated cross-zonal capacity in
coordination with other concerned TSOs. TSOs are further obliged to notify market participants which are
concerned by curtailment, provide compensation and limit both consequences and duration of force
majeure.
The Guideline on System Operation (SO Guideline) defines the operational system states of 'normal',
'alert', 'emergency' and 'restoration' in its Article 18. This provides a framework for 'remedial actions' which
are used by the TSOs to manage operational security violations (Art. 20 – 23) and as an example include
manually controlled load-shedding (Art. 22, paragraph 1(j)). TSOs shall prepare and coordinate their
remedial actions among each other and their RSCs (Art. 21, paragraph 1(b)) and prefer remedial actions
which make available the largest cross-zonal capacity (Art 21, paragraph 2(d)). Moreover, they are obliged
to jointly develop a procedure for sharing costs of remedial actions (Article 76, paragraph 1(b)(v)).
Source: EU legislation
Finally, on cybersecurity, NIS Directive provides the horizontal framework to boost the
overall level of network and information security across the EU. It imposes a set of
obligations on Member States as well as on essential service providers - including the
electricity, oil and gas subsectors.
Deficiencies of the current legislation
6.1.3.
The evaluation of Directive 2005/89/EC (SoS Directive) has revealed the existence of
numerous deficiencies in the current legal framework6
. In first place, the evaluation
concludes in the ineffectiveness of the SoS Directive in achieving the objectives pursued,
notably contributing to a better security of supply in Europe. Whilst some of its
provisions have been overtaken by subsequent legislation (notably the Third Package and
2
See Article 6 of NC ER.
3
See Articles 14 & 15 of NC ER.
4
See Article 35 of NC ER.
5
See Article 8 and 39 of NC ER.
6
See Evaluation of the EU rules on measures to safeguard security of electricity supply and
infrastructure investment (Directive 2005/89/EC).
311
Addressing energy poverty
the TEN-E Regulation), there are still regulatory gaps notably when it comes to
preventing and managing crisis situations.
The evaluation also reveals that the SoS Directive intervention is no longer relevant
today as it does not match the current needs on security of supply. As electricity
systems are increasingly interlinked, purely national approaches to preventing and
managing crisis situations can no longer be considered appropriate. It also concludes that
its added value has been very limited as it created a general framework but left it by
and large to Member States to define their own security of supply standard. Whilst
electricity markets are increasingly intertwined within Europe, there is still no common
European framework governing the prevention and mitigation of electricity crisis
situations. National authorities tend to decide, one-sidedly, on the degree of security they
deem desirable, on how to assess risks (including emerging ones, such as cyber-security)
and on what measures to take to prevent or mitigate them.
The existing regulatory gap on preventing and managing crisis situations is described in
detail below.
The existing obligations for the Member States on monitoring security of supply (Article
4 of the Electricity Directive and Article 7 of the SoS Directive) focus mainly on
generation adequacy and do not address the preparation for or dealing with crisis
situations. In practice, the reports submitted under Article 4 of the Electricity Directive
are a mere compilation of information on supply and demand figures showing the
evolution in a certain time horizon, while the lists of measures described cover mainly
infrastructure projects on generation and cross-border interconnections.
There is no legal obligation for Member States to carry out a risk assessment or to
draw up a risk preparedness plan7
. All Member States set an explicit or implicit
obligation to carry out an assessment of electricity security of supply risks; however, not
all Member States describe the types of risks covered under the assessment8
. The analysis
shows that the risks to be assessed vary considerably9
. Furthermore each Member State
has designed its own "risk preparedness" or "emergency plan" to deal with stress
situations, which has resulted in different national practices across Europe which tend to
differ in nature, scope and content and rarely take into account cross-border effects.
Diverging perception of risks could lead to different levels of preparedness.
7
Only ten Member States set clear obligations to draw up risk preparedness plans, whilst eighteen other
Member States do not have such an obligation, but take risk preparedness considerations into account
in reports, plans or measures (source: Risk Preparedness Study).
In addition, Directive 2008/114/EC on the identification and designation of European critical
infrastructures defines the obligation that each identified European Critical Infrastructure needs an
operator security plan (Art. 5) which will be also reflected in the coming System Operation Guideline
(Art. 26). However, these plans focus only on each identified asset and not the electricity system as
whole.
8
Only nine Member States have direct obligations to carry out a risk assessment; other Member States
are implicitly looking at risks when monitoring the security of electricity supply (source: Risk
Preparedness Study).
9
23 Member States define risks to be addressed which vary considerably (source: Risk Preparedness
Study).
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Addressing energy poverty
The evidence shows that national plans do not look at the impacts beyond the national
borders or simultaneous crisis situations. There is close cooperation on the level of
TSOs which is not matched by a cooperation of national authorities10
.
Uncoordinated national measures to ensure the supply in emergency situations may not
be efficient or could have negative effects on neighbouring countries. The lack of
cooperation on the level of national authorities could also lead to diverging actions on
TSO and governmental level (e.g. decision on governmental level on export bans) which
could have detrimental effect on security of electricity supply.
Regarding transparency and information exchange, implementation of Article 42 of the
Electricity Directive shows that up to now the Commission was only notified of such
measures in few cases (e.g. Poland in 201511
), and only ex-post, where there was no
possibility ex-ante to assess their suitability. The current wording of Article 42 is of
rather general nature and does not lead to sufficient cross-border coordination
beforehand.
The Electricity Coordination Group has limited powers beyond the exchange of
information. There is no explicit obligation to convoke the group in case of a crisis or
when at least two Member States are in emergency. It is purely a consultative body
without powers to issue recommendations for example on the measures that Member
States could put in place during an emergency.
On managing crisis situations, currently Member States predominantly resort to
national measures without sufficient account being taken of their impact on their
neighbours or synergies stemming from a coordinated approach. There are hardly any
cross-border procedures on how Member States should act in crisis situations. However,
with increasingly integrated markets, measures taken by one Member State are highly
probable to affect its neighbours. The cross-border impact is particularly serious and
immediate in case of an actual physical shortage in real time12
.
10
There are examples of existing regional co-operation is some regions involving national authorities,
e.g. among the Nordic countries in the framework of NordBER (Nordic Contingency Planning and
Crisis Management Forum) or Pentalateral Energy Forum, however, currently this co-operation is
mainly restricted to the exchange of best practice.
11
Poland activated a crisis protocol mid-August 2015 allowing TSO to restrict power supplies to large
industrial consumers (load restrictions did not apply however to households and some sensitive
institutions such as hospitals). However, Poland notified the adoption of these measures under Article
42 one month after (mid-September).
12
Physical shortage arises when it has not been possible to fulfil the given demand, neither by market
transactions in day-ahead and intraday markets nor by balancing activities of the TSO. In this case,
load shedding will be carried out by each TSO to remedy its deficit. After market closure there is no
ambiguity regarding the deficit’s allocation across affected countries – each TSO knows exactly the
magnitude of its control area’s deficit and consequently its 'scheduled curtailment'. For exporting
Member States who strive to protect their customers from disconnection, two scenarios may arise: (i)
closing down interconnectors to stop exports altogether or (ii) carry out less-than-scheduled load
shedding in order to reduce export flows. In both cases the national action can have an impact on
cross-border power flows, affecting the neighbours' supply.
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Addressing energy poverty
In case of a simultaneous scarcity situation in two or more Member States, stopping or
limiting exports to overcome national physical shortage before domestic demand has
been curtailed would directly translate into aggravating supplies to customers in the
neighbouring Member State. The management of interconnectors and the possible spill
over effects of Member States' national actions become particularly relevant when a
concurrent physical energy shortage remains over several days (e.g. due to a heat
wave/cold spell causing a sustained demand spike or when a large number of generation
units is put out of operation). This case of energy shortage is especially exposed to the
risk of intervention with system operation or premature non-market measures by Member
States.
The network codes, i.e. the draft NC ER, the CACM Guideline and the SO Guideline
are an important step in the harmonisation of technical procedures and interoperatibility
of rules in the EU. However, a general legislative framework setting out how Member
States should act and co-operate with each other to prevent and manage electricity crisis
situations is still missing. There is still no framework clarifying roles and
responsibilities, aligning national rules, and prescribing co-operation between Member
States to resolve political issues relating to crisis management. As a result, large-scale
electricity crisis situations, as well as situations of a simultaneous crisis, cannot
effectively be resolved (for instance, there is no framework for how to deal with crisis
situations caused by extreme weather conditions, or a fuel shortage; there are no rules on
which consumers should be protected most, how to communicate and intervene at a
political level etc).
Article 4(3) of the SoS Directive does not define clear Dos and Don'ts at the Member
State level even though electricity crisis situations, especially in situations of
simultaneous scarcity, which require political decision and clear rules, roles and
responsibilities. In such situations, the market should be allowed to function as long as
possible and deliver power flows to countries with higher scarcity. Exporting Member
States should not introduce exports bans without restricting national consumers in a
proportionate manner as this would 'export' the scarcity across the borders. The treatment
of interconnection capacity and consequently the way possible load-shedding measures
could be shared across countries is not sufficiently defined. A few Member States
explicitly foresee (potentially unproportioned) export bans in their national legislation13
and a recent case of export bans in South-Eastern Europe has proven this risk in reality.
On cybersecurity, the fragmented approach of the NIS directive could be problematic
for the energy sector, as energy infrastructure is arguably one of the most critical
infrastructures that other sectors - like banking, health and mobility, depend upon to
deliver essential services. Currently, the energy sector consists of both legacy and next
generation technologies. New grid technologies are introducing millions of novel,
intelligent components to the energy sector that communicate in much more advanced
ways (two-way communications, dynamic optimization, and wired and wireless
communications) than in the past. These new components will operate in conjunction
13
One Member State specifically includes a legal provision on export bans in its legislation; eleven more
Member States include forms of export restrictions in national law, TSO regulations or multilateral
agreements (Source: Risk Preparedness Study).
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Addressing energy poverty
with legacy equipment that may be several decades old, and provide little to no
cybersecurity controls. In addition, with alternative energy sources such as solar power
and wind, there is increased interconnection across organizations and systems. With the
increase in the use of digital devices and more advanced communications, the overall risk
has increased. For example, as substations are modernized, the new equipment is digital,
rather than analogue. These new devices include commercially available operating
systems, protocols, and applications rather than proprietary solutions. This increased
digital functionality provides a larger incident surface for any potential adversary, such as
nation-states, terrorists, malicious contractors, and disgruntled employees. This new
technology increases the complexity of addressing cyber risks. Many of the
commercially available solutions have known vulnerabilities that could be exploited
when the solutions are installed in control system components. Potential impacts from a
cyber-event include: billing errors, brownouts/blackouts, personal injury or loss of life,
operational strain during a disaster recovery situation, or physical damage to power
equipment. The current legislative framework does not prepare for these impacts.
Presentation of the options
6.1.4.
Options to reinforce coordination between Member States for preventing and
managing crisis situations (Problem Area III)
Table 3: Overview of the Options for Problem Area III
Option 0: Baseline scenario
Option 0+: Improved implementation of current legislation without regulatory action at EU level
Option 1: Common minimum rules to be implemented by Member States
Option 2: Common minimum rules to be implemented by Member States plus regional cooperation
Option 3: Full harmonisation and full decision-making at regional level
Option 0: Baseline scenario
Under the baseline scenario, Member States would continue identifying and addressing
rare/extreme risks and possible crisis situations based on a national approach, in
accordance with their own national rules and requirements. As a consequence, neither
risks originating across borders, nor possible synergies in preparation for crisis are
sufficiently taken into account.
The recently adopted network codes and guidelines (i.e. The Network Code on
Emergency and Restoration, the Regulation on Capacity Calculation and Congestion
Management and the Guideline on System Operation) bring a certain degree of
harmonisation on how to deal with electricity systems in different states (normal state,
alert state, emergency state, black-out and restoration). This ensures more clarity as
regards how TSOs should act in crisis siuations, and as to how they should co-operate
with one another.
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The innovative tools14
developed for TSOs in the area of the system security in the last
years, will also contribute to improve monitoring, prediction and managing secure
interconnected power systems preventing, in particular, cascading failures15
.
However, the TSOs cooperation would be limited to technical-level decisions, and would
be hampered in practice by the absence of a proper framework for national rules and
decisions on how to prepare for and handle electricity crisis situations, in particular in
situations of siumultaneous scarcity. Such political decisions continue to be taken at a
purely national level, in an intransparent manner, without taking account of other
Member States' interests, both in a preparatory phase, and when crisis situations kick in.
Monitoring results would be published bi-annualy without any requirement to coordinate
among each other or develop any risk preparedness plan. Furthermore Member States
would not be obliged to exchange information when a possible crisis approaches. A
current mandate of the Electricity Coordination Group would also not be sufficient to
act as information exchange platform in crisis situations. This could lead to inefficiencies
when preventing and managing a crisis situation or have negative effects on
neighbouring countries.
On cybersecurity, the NIS Directive, aiming at a high common level of network and
information security across the Union, provides the horizontal framework to boost the
overall level of network and information security across the EU on a cross-sectoral and
generic level. However, as the NIS Directive is defining only very generic and high-level
obligations, there is room for a more sectoral approach defining concrete modalities to
ensure a minimum of coordination among Member States and resilience of the
interconnected European electricity grid. Energy infrastructure is arguably one of the
most critical infrastructures that other sectors - like banking, health and mobility- which
depend upon to deliver essential electricity services. Thus it is essential to tackle the
potential risks of a major blackout taking into account coordinated attacks to more than
one Member State and the interconnectivity and the system complexity of the energy
sector.
14
ITESLA project (which was financed under FP7) developed methods and tools for the coordinated
operational planning of power transmission systems, to cope with increased uncertainties and
variability of power flows, with fast fluctuations in the power system as a result of the increased share
of resources connected through power electronics, and with increasing cross-border flows. The project
shows that the reliance on risk-based approaches for corrective actions can avoid costly preventive
measures such as re-dispatching or reduced the overall risk of failure.
15
In addition the AFTER project (which was financed under FP7) also developed tools for TSOs to
increase their capabilities in creating, monitoring and managing secure interconnected electrical power
system infrastructures, being able to survive major failures and to efficiently restore service supply
after major disruptions (http://www.after-project.eu/).
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Table 4: R&D Results
The technical base to produce accurate prediction of rapid fluctuations and prevent cascading failures has
been developed in ITESLA through a framework for the exchange dynamic models of power system
elements. It showed that the reliance on risk-based approaches for corrective actions can avoid costly
preventive measures such as re-dispatching or reduced while the overall risk of failure is decreased. This
requires more and more formalised data exchange among TSO's to support the new methods and tools.
AFTER has developed a framework for electrical power systems vulnerability identification, defence and
restoration. It uses a large set of data (big data) coming from on-line monitoring systems available at
TSOs’ control centres. A fundamental outcome of the tool consists in risk-based ranking list of
contingencies, which can help operators decide where to deploy possible control actions.
SESAME, developed a comprehensive decision support system to help the main public actors in the power
system, TSOs and Regulators, on their decision making in relation to network planning and investment,
policies and legislation, to address and minimize the impacts (physical, security of supply, and economic)
of power outages in the power system itself, and on all affected energy users, based on the identification,
analysis and resolution of power system vulnerabilities.
Source: European Commission (DG ENER)
Table 5: Innovative Tools for Electrical System Security within Large Areas
(ITESLA)
Project FP7-ITESLA
Innovative Tools for Electrical System Security within Large Areas
Addressing mainly: Co-optimisation of interconnection capacity, Regional operational centres
The project developed methods and tools for the coordinated operational planning of power transmission
systems, to cope with increased uncertainties and variability of power flows, with fast fluctuations in the
power system as a result of the increased share of resources connected through power electronics, and with
increasing cross-border flows. The project aims at enhancing cross-border capacity and flexibility while
ensuring a high level of operational security.
Fact Sheet: http://cordis.europa.eu/project/rcn/101320_en.html
Web Site: http://www.itesla-project.eu/
Important project outcomes include
- A platform of tools and methods to assist the cooperation of transmission system operators in dealing
with operational planning from two days ahead to real time, particularly to ensure security of the
system. These tools support the optimisation of security measures, in particular to consider corrective
actions, which only need to be implemented in rare cases that a fault occurs, in addition to preventive
actions which are implemented ahead of time to guarantee security in case of faults. The tools provide
risk-based support for the coordination and optimisation of measures that transmission operators need
to take to ensure system security. The platform also supports "defence and restoration plans" to deal
with exceptional situation where the service is degraded, e.g. after storms, or to restore the service
after a black-out. The platform has been made publicly available as open-source software.
- A clarification of the data and data exchanges that are necessary to enable the implementation of these
coordination aspects.
- A framework to exchange dynamic models of power system elements including grids, generators and
loads, and a library of such models covering a wide range of resources. These models are essential to
produce accurate prediction of the rapid fluctuations that take place in the power grid after faults, and
to prevent cascading failures.
- The tools and models allow reducing the amount of necessary preventive measures. The reliance on
risk-based approaches can avoid or minimise costly preventive measures such as re-dispatching while
the overall risk of failure is decreased.
- A set of recommendations to policymakers, regulators, transmission operators and their associations
(jointly with the UMBRELLA project). These foster the harmonisation of legal, regulatory and
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operational framework to allow the exploitation of the newly developed methods and tools. They also
identify the need for increased formalised data exchange among TSO's to support the new methods
and tools.
Source: European Commission (DG ENER)
Option 0+: Non-regulatory approach
As current legislative framework established by the SoS Directive set general principles
rather than requires Member States to take concrete measures, better implementation and
enforcement actions will be of no avail.
In fact, as the progress report of 2010 shows16
, the SoS Directive has been implemented
across Europe, but such implementation did not result in better co-ordinated or clearer
national policies regarding risk preparedness.
The recently adopted network codes and guidelines offer some improvements at the
technical level, but do not address the main problems identified.
In addition, today voluntary cooperation in prevention and crisis management is scarce
across Europe and where it takes place at all, it is often limited to cooperation at the level
of TSOs. It is true that certain Member States collaborate on a voluntary basis in order to
addresss certain of the problems identified (e.g. Nord-BER, PLEF). However, these
initiatives have different levels of ambition and effectiveness, and they geografically
cover only part of the EU electricity market. Therefore, voluntary cooperation will not be
an effective tool to solve the problems identified timely and in the whole EU.
Option 1: Common minimum rules to be implemented by Member States
Assessments and plans
Under Option 1 Member States would be obliged to develop national Risk Preparedness
Plans ('Plan') with the aim to prevent or better manage the electricity crisis. The Plan
should respect minimum common requirements and include a risk assessment of the
most relevant crisis scenarios originated by rare/extreme risks. For that purpose, at least
the following types of risks could be considered: a) rare/extreme natural hazards17
, b)
16
Report on the progress concerning measures to safeguard security of electricity supply and
infrastructure investment COM (2010) 330 final.
17
Extreme weather events are likely to affect the power supply in various ways: (i) thermal generation is
threatened by lack of cooling water (as shown e.g. in summer 2015 at the French nuclear power
stations Bugey, St. Alban and Golfech); (ii) heat waves cause high demand of air conditioning (which
e.g. resulted in price peaks in Spain in late July 2015 when occurring in parallel with low wind
output); (iii) heat waves affect grid performance in various ways, e.g. moisture accumulating in
transformers (which e.g. lead to blackouts in France on June 30th
2015) or line overheating (leading to
declaration of emergency state by the Czech grid operator CEPS on July 25th
in 2006) (source: S&P
Global, Platts: European Power Daily, Vol. 18, Issue 123).
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accidental hazards which go beyond N-1, c) consequential hazards such as fuel
shortage18
, d) malicious attacks (terrorist attacks, cyberattacks).
The Plans would need to respect a set of minimum requirements, namely how Member
States would prepare for crisis situations and how they should deal with the identified
crisis scenarios. Preparatory measures could include, e.g. training for all staff involved in
crisis management and regular simulations of crisis. Risk preparedness plans should
further include how to prevent and manage cyber-attack situations which would be one of
the risks to be covered by the plans. This will be combined with a soft guidance on
cybersecurity in the energy sector based on NIS Directive.
Plans should be adopted by relevant governments / ministries, following an inclusive
process, and (at least some parts of the Plans) should be rendered public. Plans should be
updated on a regular basis (e.g., every three years, unless major incidents or market
developments require an earlier update). For the purpose of consultation, Plans should be
submitted to other Member States and the Commission.
The main benefit this option would bring is better preparedness, due to the fact that a
common approach is followed across Europe, thus excluding the risk that some Member
States 'under-prepare'. In addition, better preparedness, transparency and clear rules on
crisis management are likely to reduce the chances of premature market intervention.
Crisis management
To ensure transparency and information exchange, Member States would be obliged to
inform immediately in situations of "early warning" or "crisis" their neighbours and
the European Commission to provide them with all the necessary information, in
particular on the actions they intend to take.
"Early warning" could be defined as the state where there is concrete, serious and
reliable information that an event may occur which is likely to result in significant
deterioration of the supply situation and is likely to lead to a crisis level. While "crisis"
could be defined as the event of significant deterioration of electricity supply over a time
span lasting long enough to give room for political action and when all relevant market
measures have been implemented but the supply is insufficient to meet the remaining
demand19
.
18
One example proving that such risks should be taken into account is the shortage of anthracite coal in
Ukraine in June 2016. Due to the political situation in Ukraine affected the rail transport of coal. As
several Ukrainian nuclear power units are offline for maintenance in parallel, the responsible ministry
called for limiting power consumption. (Source: S&P Global, Platts: European Power Daily, Vol. 18,
Issue 123).
19
In most of the cases the declaration of "crisis" by the national authorities will coincide with the
"emergency state" of the transmission system as severe technical problems could lead to the
"exceptional situation". But in very extreme or rare cases where situations demand political decisions
and are not solely limited to system operation in real time (e.g. fuel supply scarcity, energy shortage
for longer time periods) the government could decide to declare emergency - without necessary being
in "emergency state"- with the aim to take safeguard measures (non-market based measures).
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Under this option, the Commission could also set out legal principles governing crisis
management. This will replace the current Article 42 of the Electricity Directive, which
allows Member States to take 'safeguard measures' in situations of a sudden crisis and
when security of persons or equipment is threatened. When dealing with emergency
Member States should respect three basic rules:
- 'Market comes first': Non-market measures should be introduced only once market
measures cannot tackle the situation. Measures should not unduly distort functioning of
the market. They should be introduced only temporary and on the basis of an objective
trigger described in the Plans. In particular, market rules on cross-border trade need to be
respected20
.
- 'Duty to offer assistance': In case crisis arises, Member States should react in a spirit of
good cooperation and solidarity21
. Practical arrangements regarding cooperation and
solidarity measures shall be established in advance by Member States and be reflected in
the risk preparedness plans.
- 'Transparency and information exchange': Member States should ensure transparency
of the actions taken from the moment that there are serious indications of a crisis and
during a crisis. This should be ensured through the regional part of the risk preparedness
plans and through informing neighbours and the Commission in case of declaration of
'early warning' or 'crisis'.
By imposing obligations to co-operate and lend assistance, Member States are also less
likely to 'over-protect' themselves against possible crisis situations, which in turn will
contribute to more security of supply at a lesser cost.
Monitoring
In order to anticipate and mitigate potential upcoming crisis, under Option 1 Member
States would be obliged to take into account the results of the ENTSO-E seasonal
assessments (winter & summer outlooks). Member States should take measures
accordingly, if there are serious indications that they could be in a predefined crisis
situation (i.e. in an 'early warning' situation), as well as in a situation of crisis.
Option 2: Common minimum rules to be implemented by Member States plus
regional co-operation
Assessments and plans
Option 2 would be built on Option 1 adding rules and tools facilitating cross-border
cooperation in a regional and Union wide context.
20
Rules on cross-border capacity allocation are set out in the CACM Guideline. Its Article 72 allows
TSOs to curtail allocated cross-zonal capacity in the event of 'force majeure'.
21
At TSO level, providing cross-border assistance through the available interconnectors is provided for
in Article 12 of the draft Network Code on Emergency and Restoration.
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Under Option 2 Member States should also develop their Risk Preparedness Plans.
However, the identification of the crisis scenarios and the risk assessment would be
carried out by ENTSO-E. This approach would ensure that the risks originating across
the borders, including scenarios of a possible simultaneous crisis, are taken into account.
ENTSO-E would be required to develop a methodology for the identification of risk
scenarios. Such methodology would need to include at least following elements:
- consider all relevant national and regional circumstances;
- the interaction and correlation of risks across the borders;
- running simulations of simultaneous crisis scenarios;
- ranking of risks according to their impact and probability.
To take account of all regional specificities ENTSO-E could delegate all or part of its
tasks to the ROCs. The crisis scenarios identified by ENTSO-E would be discussed in the
Electricity Coordination Group. The regional approach in the identification of the crisis
scenarios ensures a common strategy to minimise impacts of possible crisis, focus in
particular on correlated risks and on risks that could affect simultaneously several
Member States. This would significantly improve level of preparedness at national,
regional and EU level, as the cross-border considerations are duly taken into account
since the beginning.
Table 6: Best practice examples of Member State cooperation
Nordic Contingency and Crisis Management Forum (NordBER)
The Nordic (including Iceland) TSOs, regulators and energy authorities founded a Nordic cooperation
body (NordBER) in order to improve crises management and preparedness. The cooperation focuses on the
exchange of information and experiences on contingency planning and emergency exercises. Moreover, it
requires a common contingency planning for the overall Nordic power sector as a supplement to the
national emergency work and as an extension of operation and planning cooperation between the TSOs.
Pentalateral Energy Forum
The Pentalateral Energy Forum is the framework for regional cooperation of relevant ministries, NRAs,
TSOs and market parties in Central-Western Europe (BENELUX-DE-FR-AT-CH). Its Support Group 2
gives guidance on regional cooperation in the field of security of supply and acts as "development center
for new ideas" with the goal to reach specific recommendations.
Source: https://nordber.org/ and http://www.benelux.int/nl/kernthemas/energie/pentalateral-energy-forum/
The Risk Preparedness Plans under this option would contain two parts – a part
reflecting national measures and a part reflecting measures to be pre-agreed in a regional
context. The latter part includes particular preparatory measures such as simulations of
simultaneous crisis situations in neighbouring Member States ("stress tests" organised by
ENTSO-E in a regional context); procedures for cooperation with other Member States in
different crisis scenarios, and rules for how to deal with simultanous crisis situations. In
this context the Member States should, among others, agree in advance in which
situations, what load and to whom will be curtailed in simultaneous crisis situations. In
order to facilitate the extent of offered assistance, in particular in cases where no other
agreement has been made for assistance in simultaneous crisis, it might be necessary to
allign principles for priorization and the share of customers which is prioritized highly in
order to avoid overprotection at the cost of neighbouring Member States.
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The draft Plans should be consulted with other Member States in each region and
submitted for prior consultation to the Electricity Coordination Group. Through
regionally co-ordinated plans, Member States would be able to ensure that increased TSO
cooperation is matched by a more structured co-operation between Member States22
. The
regions for such cooperation should therefore be the same as the TSO regions developed
for the RSCs. To ensure cooperation further, the obligation on coordinated planning
should be extended to Energy Community Partners.
To facilitate the cross-border cooperation and to overcome the current situation of
unclear roles and responsibilities, Member States should designate one 'competent
authority', which would be the responsible body for coordination and cross-border
cooperation in a crisis situation. The Competent Authority should belong either to the
national administration or to the NRA.
In order to also adress specific rules to be followed to ensure cybersecurity a network
code or guideline should be developed.The network code/guidelines should take into
account at least the following elements: a) methodology to identify operators of essential
services for the energy sector; b) risk classification scheme; c) minimum cyber-security
prerequisites to ensure that the identified operators of essential services for the energy
sector follow minimum rules to protect and respond to impacts on operational network
security taking the identified risks into account. A harmonized procedure for incident
reporting for the energy sector shall be part of the minimum prerequisites.
Crisis management
As described in Option 1, all measures taken by Member States to prepare to or deal with
'crisis' should be based on a common framework and the principles of 'market comes
first', 'duty to offer assistance' and 'transparency and information exchange'.
The 'duty to offer assistance' should especially address simultaneous scarcity situations
which would be set to further rise in the near future given the increasing interconnectivity
of the European electricity systems and markets (see Graphs 1 and 2). In situations of
concurrent energy shortage over several days23
, Member States should agree in advance,
when and what loads would be curtailed in crisis situations with a cross-border impact24
.
Solidarity measures in simultaneous scarcity, including coordinated demand restrictions
22
For cases of crisis, in particular simultaneous scarcity, also ENTSO-E sees a need for "not only on a
technical level but political cooperation" and plans which "should cover extreme crisis situations
beyond the measures provided by e.g. network codes and RSCs services" (s. ENTSO-E
recommendations to the regulatory framework on risk preparedness (WS5) (2016), ENTSO-E,
document in the process of publication).
23
Unlike sudden power outages, an energy shortage could be (i) anticipated e.g. several days in advance
and (ii) last over a period of several days. Therefore, decision making on customer disconnection, rota
plans etc. is likely to not only affect TSOs, but also involve Member States. A good example of a rota
plan is the "Electricity Supply Emergency Code" of the UK:
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/396424/revised_esec_ja
nuary_2015.pdf
24
One example of a load shedding plan prioritizing regions is the Belgian "Plan de délestage en cas de
pénurie d'électricité" http://economie.fgov.be/fr/penurie_electricite/plan-delestage/#.VpTd2v7luUk
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in various markets, could be subject to financial compensation ex-post, following
agreements between Member States according to the principles set out in Article 39 of
NC ER (avoiding market distortion, incentivizing balanced positions). In order to avoid
'exporting' energy scarcity to neighbouring markets Member States should also allow for
domestic load shedding to be carried out by their TSOs according to schedules. Any rules
on protected customers should not lead to unjustified over-protection of a too high share
of national customers25
.
25
As already existing in many Member States today, Member States can introduce rules on customer
categorization to prioritize customers in case of load shedding. Such rules on protected customers
should take into account national and local specifics, but respect harmonized principles.
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Graph 1: Distribution of system stress hours by Member States over fifty years of
historical demand data
Stress hours are defined as hours of extremely high demand. The graph shows the 150 hours per Member
State of the highest demand in the historical period of fifty years (1960-2010). The intensity of the colour
indicates the intensity of demand (red means super peaks of demand). Rows indicate Member States.
Columns indicate the respective historical years.
Source: METIS
Graph 2: Distribution of prices at VoLL in the context of a well-integrated market
by Member States over fifty years of historical demand data
As result of better integration of the markets the stress hours would decrease and be concentrated in periods
affecting simultaneously several Member States.
During these stress hours the price becomes equal to VoLL.
Source: METIS
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Table 7: Best practice example of TSO agreements of Nordel
The Nordic TSOs pre-agreed on certain procedures to be taken in crisis situations (s. Apendix 9 of Nordel
System Operation Agreement 3 (5)). In Power Shortages, it demands information of the other TSOs as
quickly as possible and forbids that prearranged trading between players can be changed. In Critical Power
Shortages and after all manual balancing reserve (i.e. available generation capacity) has been exhausted, it
sets out a procedure for load shedding without a commercial agreement. After the subsystem with the
greatest physical deficit has started load shedding and two or more subsistems have an equally large deficit,
load shedding is distributed thereafter between those subsystems26
.
Source: Nordel System Operation Agreement 1 (5), Appendix 9
Monitoring
Building on Option 1, ENTSO-E would carry out seasonal assessments, which would
need to be further improved via the introduction of a common methodology, to be
developed by ENTSO-E on the basis of criteria set out in EU legislation. This could be a
probabilistic methodology that should take into account uncertainties of input variables
(e.g. probability of transmission capacity outage, of severe weather conditions, of
unplanned outage of power plants, variability of demand, etc.). The methodology would
also indicate the probability of a critical situation actually occuring and of low level of
cross-border capacity. This methodology should be used not only for seasonal outlooks
but also for weekly risk assessments by RSCs.
This option also contemplates the reinforcement of tasks and powers of the Electricity
Coordination Group with a view to ensure transparency and wide discussion between
Member States in the preventive phase and after declaration of early warning/crisis. In
particular, the Group would be the forum for the discussion of the draft plans and the
measures that Members States foresee to implement based on the results of the seasonal
outlooks. The Group could also play a role in the assessment of measures adopted by
Member States in early warning/crisis. More generally, the Group could be given
concrete tasks to discuss policies in the area of security of supply, for instance, through
regular discussions on the basis of ENTSO-E adequacy outlooks. It could issue
recommendations and develop best practice. The reinforced role would enhance the
coordination of measures and ensure more uniformity and coherent plans. Overall, the
reinforcement of tasks and powers of the Electricity Coordination Group would
contribute to enhance cooperation and to build trust and confidence among Member
States.
In addition to the obligation to notify immediately the declaration of early warning or
crisis and provide Member States concerned and the Commisison with all relevant
information, under Option 2 Member States would be obligated to carry out an ex-post
evaluation. The evaluation should be submitted to the Commission at the latest six
weeks after the lifting of early warning or crisis. The assessments should be presented by
the Member States concerned at the Electricity Coordination Group.
26
That agreements similar to the Nordic TSOs could be a best practice also for the system of continental
Europe as it mentioned by the Dutch TSO TenneT to the public consultation. It recommends to have
common rules and definitions and defining allowed measures on different levels of criticality, as
security of electricity supply is becoming an issue of reginal rather than national importance.
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To allow for a precise monitoring of how well Member States' systems perform in the
area of security of supply, security of supply indicators would be introduced. ENTSO-E
would calculate for all Member States the following security of supply indicators:
expected energy non served (EENS) expressed in GWh/year and loss of load expectation
(LOLE) expressed in hours/year. ENTSO-E would conduct the security of supply
performance measurements based on the indicators on annual basis, at the occasion of the
adequacy assessment outlook. The introduction of security of supply indicators to assess
how well Member States perform in the area of security of supply would enhance
comparability and mutual trust in neighbours.
Option 3: Full harmonisation and full decision-making at regional level
Assessments and plans
Built on Option 2, under Option 3 the assessment of rare and extreme risks would be
carried out at EU level, which would prevail over national assessments.
The risk preparedness plans would be developed on regional level27
. In each region the
Member States would need to agree on one risk preparedness plan which would address
the most relevant risks in each region. The list of measures to mitigate the risks should be
developed on and co-ordinated at the regional level by the ROCs. This would allow a
harmonised response to potential crisis situation in each region.
Even though the regional plans would ensure full coherence of actions ahead and in
particular in a crisis, it would be difficult that all national specificities could be addressed
through regional plans.
On cybersecurity Option 3 would go one step further and nominate a dedicated body
(agency) to deal with cybersecurity in the energy sector. This would guarantee full
harmonisation on risk preparedness, communication, coordination and a coordinated
cross-border reaction on cyber-incidents.
Crisis management
Regarding crisis management, under Option 3 crisis would have to be managed
according to the regional plans agreed among Member States. The Commission would
determine the key elements of the regional plans such as: commonly agreed regional
load-shedding plans, rules on customer categorisation, a harmonised definition of
'protected customers' (high priority grid users) at regional level or specific rules on crisis
information exchanges in the region. Under Option 3, the Commission would also create
a detailed 'emergency rulebook' with an exhaustive list of measures that can be taken
by Member States and TSOs in crisis situations.
27
The results of the public consultation showed that only few stakeholders were in favour of regional or
EU wide plans. Some stakeholders mentioned the possibility to have plans on all three levels (national,
regional and EU), e.g. see the answers of Latvian government, EDSO, GEODE, Europex.
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Monitoring
The seasonal outlooks carried out by the ENTSO-E and ROCs would include a proposal
of ROCs for each reagion of measures to mitigate the risks identified. Member States
would be obligated to implement them.
In order to also harmonize monitoring practices on a European level and ensure full
consistency, a European standard (e.g. for EENS and LOLE) on Security of Supply could
be developed and fixed (e.g. determined value to be fulfilled by all Member States)
which could be used to monitor the Member State performance.
Comparison of the options
6.1.5.
Option 1 (Common minimum rules to be implemented by Member States)
Contribution to the policy objectives
Under this option, Member States would be required to draw up risk preparedness plans,
built on common elements, and to respect certain common minimum rules when
managing crisis situations.
The main benefit this option would bring is better preparedness, due to the fact that a
common approach is followed across Europe, thus excluding the risk that some Member
States 'under-prepare'. In addition, better preparedness, transparency and clear rules on
crisis management are likely to reduce the chances of premature market intervention.
By imposing obligations to co-operate and lend assistance, Member States are also less
likely to 'over-protect' themselves against possible crisis situations, which in turn will
contribute to more security of supply at a lesser cost.
Economic Impacts
Overall, the policy tools proposed under this option should have positive effects. Putting
in place a more common approach to crisis prevention and management would not entail
additional costs for businesses and consumers. It would, by contrast, bring clear benefits
to them.
First, a more common approach would help better prevent blackout situations, which are
extremely costly. The immense costs of large-scale blackouts provide an indication of
potential benefits of improved preparation and prevention28
.
28
Previous blackouts in Europe had severe consequences. For example, the blackout in Italy in
September 2003 resulted in a power disruption for several hours affecting about 55 million people in
Italy and neighbouring countries and causing around 1.2 billion euros worth of damage. (source: The
costs of blackouts in Europe (2016), EC CORDIS: http://cordis.europa.eu/news/rcn/132674_en.html).
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Table 8: Overview over most severe blackouts in Europe
Country & year
Number of end-
consumers
interrupted
Duration,
energy not
served
Estimated costs to
whole society
Sweden/Denmark,
2003
0.86 million
(Sweden);
2.4 million
(Denmark)
2.1 hours,
18 GWh
EUR 145 –
180 million
France, 1999 1.4 - 3.5 million
2 days–2 weeks,
400 GWh
EUR 11.5 billion
Italy/Switzerland,
2003
55 million 18 hours
Sweden, 2005 0.7 million
1 day – 5 weeks,
11 GWh
EUR 400 million
Central Europe, 2006 45 million
Less than
2 hours
Source: SESAME: Securing the European Electricity Supply Against Malicious and Accidental Threats
A more common approach to emergency handling, with an obligation for Member States
to help each other, would help to avoid or limit the effects of potential blackouts. A more
common approach, with clear obligations to e.g., follow up on the results of seasonal
outlooks, would also reduce the costs of remedial actions TSOs have to face today29
.
This, in turn, should have a positive effect on costs overall.
In addition, improving transparency and information exchange would facilitate
coordination, leading to a more efficient and less costly measures.
By ensuring that electricity markets operate as long as possible also in stress situations,
cost-efficient measures to prevent and resolve crisis are prioritized.
The overall impact of the Commission Recommendations on cybersecurity for the energy
sector can be very broad, given the voluntary nature of this approach. If fully followed by
all Member States, the same impacts as in Option 2 should be considered. If only
partially considered by Member States, the average administrative cost would be rather
low.
Who should be affected and how
Option 1 is expected to have a positive effect on society at large and electricity
consumers in particular, since it helps prevent crisis situations and avoid unnecessary cut-
offs. Given the nature of the measures proposed, no major other impact on market
participants and consumers is expected.
29
The example of the Summer Outlook 2016 for Poland involves the following remedial actions to
prevent emergency situations: (i) switching measures of the respective TSOs PSE and 50Hertz, as well
as (ii) rescheduling of DC loop flows involving DE, DK, SE, PL, (iii) bilateral re-dispatch between DE
and PL and (iv) multilateral re-dispatch additionally involving e.g. AT, CH. Out of those, (i) and (ii)
are non-costly measures whereas re-dispatch induces significant costs.
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Addressing energy poverty
On cybersecurity, given the voluntary approach of this option, several stakeholders
(TSOs, DSOs, generators, suppliers and aggregators) could be affected. However, the
impact is estimated limited as the costs of cybersecurity for regulated entities merely
need to get considered and taken into account by the regulatory authority. Thus, the
TSOs and DSOs affected could recover their costs via grid tariffs. In that case, the pass
through of costs would have an impact on consumers that could see a slightly increased
in the final prices of electricity.
Impact on business and public administration
The preparation of risk preparedness plans as well as the increased transparency and
information exchange in crisis management imply a certain administrative effort30
.
However, the impact in terms of administrative impact would remain low, as currently
Member States already assess risks relating to security of supply, and all have plans in
place for dealing with electricity crisis situations31
.
In addition, it is foreseen to withdraw the current legal obligation for Member States to
draw up reports monitoring security of supply32
, as such reporting obligation will no
longer be necessary where national plans reflect a common approach and are made
transparent. This would reduce administrative impacts.
Option 2 (Common minimum rules to be implemented by Member States plus
regional co-operation)
Contribution to the policy objectives
Option 2 build on Option 1, but adds the dimension of regional (and some) EU-level co-
operation. In particular, it requires Member States to pre-agree on certain aspects of the
Risk Preparedness Plans (notably on how to deal with situations of a simultaneous
electricity crisis). It also calls for a more systematic assessment of rare/ extreme risks at
the regional level. Given the interlinked nature of EU's electricity systems, enhanced
regional co-operation brings clear benefits when it comes to preventing and managing
crisis situations.
The regional approach in the identification of the crisis scenarios ensures a common
strategy to minimise impacts of possible crisis, focus in particular on correlated risks and
on risks that could affect simultaneously several Member States. This would significantly
improve level of preparedness at national, regional and EU level, as the cross-border
considerations are duly taken into account since the beginning. The regional coordination
of plans would build trust between Member States which is crucial in times of crisis. The
30
Administrative costs are defined as the costs incurred by enterprises, the voluntary sector, public
authorities and citizens in meeting legal obligations to provide information on their action or
production, either to public authorities or to private parties.
31
All twenty-eight Member States have a general obligation to monitor the security of electricity supply
from which implicitly follows the obligation to assess electricity supply risks, while nine countries
have a direct legal obligation to carry out an assessment of these risks. (Source: Risk Preparedness
Study).
32
Article 4 of the Electricity Directive; Article 7 of the Electricity SoS Directive.
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Addressing energy poverty
harmonised approach via Network Codes/Guidelines would also ensure a minimum level
of harmonization for cybersecurity in the energy sector throughout the EU.
The agreement at regional level of some aspects of the risk preparedness plan would
ensure that coordination and cooperation is agreed in advance. This is particularly
relevant as regards situations of simultaneous crisis.
The regional approach for the ENTSO-E's seasonal outlooks would ensure a more
granular and in-depth assessment of possible cross-border situations. This could give a
better indication of the impacts of possible crisis situations and the possible solutions that
cooperation could bring.
The introduction of security of supply indicators to assess how well Member States
perform in the area of security of supply would enhance comparability and mutual trust
in neighbours.
The reinforced role of the Electricity Coordination Group would ensure transparency
and wide discussion in prevention and managing crisis. It would also facilitate the
exchange of information in situations of early warning and crisis and the ex-post
evaluation. In addition, it would enhance the coordination of measures and ensure more
uniformity and coherent plans. Overall, the reinforcement of tasks and powers of ECG
would contribute to enhance cooperation and to build trust and confidence among
Member States.
Economic Impacts
This option would lead to better preparedness for crisis situations at a lesser cost through
enhanced regional coordination. The results of METIS simulations33
show that well
integrated markets and regional coordination during periods of extreme weather
conditions (i.e. very low temperature34
) are crucial in addressing the hours of system
stress hours (i.e. hours of extreme electricity demand), and minimizing the probability of
loss of load (interruption of electricity supply).
Most importantly, while a national level approach to security of supply disregards the
contribution of neighboring countries in resolving a crisis situation, a regional approach
to security of supply results in a better utilization of power plants and more likely
avoidance of loss of load. This is due to the combined effect of the following three
factors: (i) the variability of renewable production is partly smoothed out when one
considers large geographical scales, (ii) the demands of different countries tend to peak at
different times, and (iii) the power supply mix of different countries can be quite
different, leading to synergies in their utilization.
33
"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",
Artelys (2016).
34
Even though periods with very low temperature occur rarely (9C difference between the 50 year worst
case and the 1% centile) countries can face high demand peaks (e.g. Nordic countries and France)
mainly due to the high consumption for the electric heating. As example, the additional demand for the
50 years peak compared to the annual peak demand is 23% for France, 18% for Sweden and 17.3% for
Finland.
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Addressing energy poverty
The following table compares the security of supply indicator "expected energy non-
served" (EENS) assessed by METIS for the three levels of coordination (national,
regional, European)35
. It highlights an overestimation of the loss of load, when it is
measured in a scenario of non-coordinated approach, which does not take into account
the potential mutual assistance between countries.
Table 9 - Global expected energy non-served as part of global demand within the
three approaches
Level EENS (% of annual load) – ENTSO-E V136 scenario
National level 0,36 %
Regional level 0,02 %
European level 0,01 %
Source: METIS
The EENS for the three levels of coordination are represented on the figure below. When
the security of supply is assessed at the national level, many countries of central Europe
seem to present substantial levels of loss of load. However, since these countries are
interconnected, a regional assessment of security of supply (taking into account power
exchanges within this region) significantly decreases the loss of load levels.
Figure 1 - EENS (%) estimation by country for scenario ENTSO-E 2030 v1 with
CCGT/OCGT current generation capacities. From left to right: EENS estimated at
European, regional and national levels
Source: METIS
35
"METIS Study S04: Stakes of a common approach for generation and system adequacy", Artelys
(2016).
36
ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario
where no common European decision regarding how to reach the CO2-emission reductions has been
reached. Each country has its own policy and methodology for CO2, RES and system adequacy.
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Addressing energy poverty
METIS simulations also show that thanks to regional cooperation the stress situations
would decrease and concentrate in a limited number of hours that may occur
simultaneously. Therefore, it highlights the need for specific rules on how Member States
should proceed in these particular circumstances, as proposed in this Option 2.
As the overall cost of the system would decrease thanks to enhanced coordination this
could have a positive impact on prices for consumers.
On the contrary, a lack of coordination on how to prevent and manage crisis situations
would imply significant opportunity costs. A recent study also evidenced that the
integration of the European electricity market could deliver significant benefits of 12.5 to
40 billion euro until 2030. However, this amount would be reduced by 3 to 7.5 billion
euro when Member States pursue security of electricity supply objectives following
going alone approaches37
.
Overall, the costs to develop and to follow a Network Code or Guidelines on cyber-
security would be limited. Additionally, given the administrative nature of the Option,
the impact could be estimated limited as it mostly requires harmonising existing practices
available in most of Member States. In addition, some obligations specific for the energy
sector would reinforce existing provisions on the NIS Directive such as the identification
of operations of essential services and the reporting obligation of cyber-incidents.
Security does in general not present a separate budget line; that is why it is very hard to
estimate how much is already spent on cybersecurity expenditures. Some of the costs
might also be hidden in other budget lines, like in human resources, securing buildings,
etc. Thus there is very few evidence on cybersecurity expenses in the energy sector. As
example, according to a US survey in a small sample of 21 utilities and energy
companies, they spent an average of $45.8 million a year on computer security to prevent
69% of known cyber strikes against their systems in 201138.
On the contrary, the
damages of cybersecurity breaches could be huge. Even though the range of costs varies
on the incident, a recent study reveals a wide spectrum of costs ranging from $156,000
(very low end estimate) to $5.5 million per single event39
. Additional costs may arise
through losses in stock value. Overall, the costs of a blackout following a cyber-incident
are the same as for a physical incident. Therefore, the overall impact of rules on
cybersecurity would be limited while the benefits of preventing cyber-incidents could be
high.
Who should be affected and how
As in the case for Option 1, Option 2 is expected to have a positive effect on society at
large and electricity consumers in particular, since it helps prevent crisis situations and
37
"Benefits of an Integrated European Energy Market (2013)", BOOZ&CO.
38
Insurance as a risk management instrument for energy infrastructure security and resilience (2013),
U.S. Department of Energy: http://www.bloomberg.com/news/articles/2012-02-01/cyber-attack-on-u-
s-power-grid-seen-leaving-millions-in-dark-for-months.
39
Insurance as a risk management instrument for energy infrastructure security and resilience" (2013),
U.S. Department of Energy: http://www.bloomberg.com/news/articles/2012-02-01/cyber-attack-on-u-
s-power-grid-seen-leaving-millions-in-dark-for-months.
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Addressing energy poverty
avoid unnecessary cut-offs. Given that, under Option 2, Member States would be
required to effectively cooperate, and tools would be in place to monitor security of
supply via the Electricity Coordination Group, such crisis prevention and management
would be even more effective.
The measures would also have a positive effect on the business community, as there
would be much more transparency and comparability as regards how Member States
prepare for and intend to manage crisis situations. This will increase legal certainty for
investors, power generators, power exchanges but also for TSOs when managing short-
term crisis situations.
Among the stakeholders the most affected would be the competent authorities (e.g.
Ministry, NRA) as actors responsible for the preparation of the risk preparedness plans
(see below, assessment of impacts on public authorities).
Other actors, such as TSOs, could be also affected, given in particular the possibility for
the Competent Authorities to delegate certain tasks (e.g. carry out the risk assessment).
However, as the tasks delegated would be closely linked to the tasks attributed by law to
the TSOs (e.g. ensuring the ability of the system to meet demand), the impact of the
specific tasks delegated would be limited.
ENTSO-E could be affected as well as it has to identify the cross-border scenarios and
improved the seasonal outlooks with more robust regional analysis. Given the possibility
for ENTSO-E to delegate certain tasks to the ROCs, the national TSOs as members of the
ROCs could be also affected. However, the impact would remain limited given the
current experience of TSOs on risk analysis and the existing cooperation among the
TSOs.
Impact on business and public authorities
The assessment of this option shows a limited increase in administrative impact, although
it would be to some extent higher than Option 1, given that national authorities would be
required to pre-agree part of their risk preparedness plans in a regional context.
However, existing experiences show that a more regional approach to risk assessment
and risk preparedness is technically and legally feasible. Further, since the regional parts
of the plans would in practice be prepared by regional co-ordination centres between
TSOs, the overall impact on Member States' administrations in terms of 'extra burdens'
would be limited, and be clearly offset by the advantages such co-operation would bring
in practice.40
40
The Nordic TSOs, regulators and energy authorities cooperate through NordBER, the Nordic
Contingency and Crisis Management Forum. This includes information exchange and joint working
groups and contingency planning for the overall Nordic power sector as a supplement to the national
emergency work and TSO cooperation (www.nordber.org).
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Addressing energy poverty
In addition, more regional cooperation would also allow Member States to create
synergies, to learn from each other, and jointly develop best practices. This should,
overtime, lead to a reduction in administrative impacts.
Finally, European actors such as the Commission and ENTSO-E would provide guidance
and facilitate the process of risk preparation and management. This would also help
reduce impacts on Member States.
It should be noted, that under Option 2 (as is the case for Option 1) no new body or new
reporting obligation is being created, and that existing obligations are being streamlined.
Thus, the Electricity Coordination Group is an existing body meeting regularly, for the
future it is foreseen to make this group more effective by giving it concrete tasks.
Further, national reporting obligations would be reduced (e.g. repealing the obligation of
Article 4 of Electricity Directive) and EU-level reporting would take place within the
context of existing reports and existing reporting obligations (e.g. ACER annual report
Monitoring the Internal Electricity and Natural Gas Markets).
Option 3 (Full harmonisation and full decision-making at regional level)
Contribution to the policy objectives
The measures of this Option pursue the maximum level of harmonisation at EU level
with the clear aim to increase the level of preparedness ahead of a crisis and the
mitigation of the impact in the case of an unexpected event occurs.
The starting point for this option is the preparation of risk preparedness plans at
regional level. Even though the regional plans would ensure full coherence of actions
ahead and in particular in a crisis, it would be difficult that all national specificities could
be addressed through regional plans.
The creation of a new EU agency dedicated to cybersecurity in the energy sector would
ensure full harmonisation on risk preparedness, communication and coordination across
Europe. Additionally, the agency would facility a quick and coordinated cross-border
reaction on cyber-incidents.
Economic Impacts
The regional coordination through the regional plans would have a positive impact in
term of cost as the number of plans would be necessary less than twenty-eight plans and
limited to the number of regions. In addition, the coordination at European level would
decrease slightly the loss of load level compared to the regional coordination (EENS
0,01% compared to 0,02%).
On the contrary, on cybersecurity, the creation of a dedicated agency at EU level would
have important economic implications as this agency would be a new body that does not
exist yet and which is also not foreseen in the NIS Directive. The costs of creating this
new agency are not only limited to the creation of a new agency itself, but the costs
would also have to include the roll-out of a whole security infrastructure. For example,
the estimated costs of putting in place the necessary security infrastructure and related
services to establish a comparable national body - cross-sectorial governmental
Computer Emergency Response Team (CERT) with the similar duties and
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Addressing energy poverty
responsibilities at national level as the planned pan-European sector-specific agency -
would be approximately 2.5 million EUR41
per national body. This means that the costs
for the security infrastructure would be manifold for a pan-European body. In terms of
human resources, for the proper functioning of the new agency with minimum scope and
tasks at EU level, it is estimated a staff of 168 full time equivalents (considering 6 full
time equivalents per Member State sent to the EU agency). The representation from all
Member States in the agency is essential in order to ensure trust and confidence on the
institution. However, the availability of network and information security experts who
are also well-versed in the energy sector is limited.
Who should be affected and how
The obligation of regional plans would have important implications for the competent
authorities as the coordination and agreement of common issues (e.g. load shedding plan,
harmonised definition of protected customers) would be a lengthy and complex process.
On cybersecurity, the creation of the new agency at EU level would mobilize highly
qualified human resources with skills in both energy and information and communication
technologies (ICT). This could have a potential impact on national administrations and
energy companies as long as some of the experts in the field could be recruited by the
new institution. However, the impact would be limited as the representation for all
Member States should be guaranteed. Therefore, a small number of experts (around 6)
per country could be recruited.
Impact on business and public authorities
Overall Option 3 would imply significantly administrative impact in the preparation of
the regional plans. It would require important efforts to gather information related to
national and regional circumstances and contribute to the joint task of assessing the risks
and identifying the measures to be included in the plans. In any case, it would seem
difficult to coordinate within a region the national specificities and risks originate mostly
in one Member State.
The creation of a new agency on cybersecurity would imply significant administrative
impacts in the preparation and set-up of the agency, as well as in the communication
structure with already existing cross-sectorial bodies of Member States
(CERTs/CSIRTs).
Conclusion
From the point of view of impacts, particularly costs and administrative impact, Option 1
could in principle appear as preferred option. However, the performance in terms of
effectiveness and efficiency is limited compared to Option 2 and 3. Additionally, impacts
associated with Option 3 are neither proportionate nor fully justified by the effectiveness
of the solutions, which makes Option 3 perform poorly in terms of efficiency compared
to Option 2.
41
SWD(2013) 32 final.
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Overall, the more harmonized approach to security of supply through minimum rules
pursued by Option 1 would not solve all the problems identified, in particular, the
uncoordinated planning and preparation ahead of a crisis. As regards Option 1, the main
drawback of this approach is that each Member State would be drafting and adoption the
national risk preparedness plans under its own responsibility. Given the urgency to
enhance the level of protection against cyber threats and vulnerabilities, it must be
concluded that Option 1 regarding cybersecurity is not recommended, because it is not
viable for reaching the policy objectives, given that the effectiveness would depend on
whether the voluntary approach would actually deliver a sufficient level of security.
Option 2 addresses many of the shortcomings of Option 1 providing a more effective
package of solutions. In particular, the regionally coordinated plans ensure the regional
identification of risks and the consistency of the measures for prevention and managing
crisis situations. For cybersecurity this option creates a harmonised level of preparedness
in the energy sector and ensures that all players have the same understanding of risks and
that all operators of essential services follow the same selection criteria for the energy
sector throughout Europe.
Overall, Option 3 represents a highly intrusive approach that tries to address possible
risks by resorting to a full harmonisation of principles and the prescription of concrete
solutions. The assessment of impacts in Option 3 shows that the estimated impact on cost
is likely to be high and looking at the performance in terms of effectiveness, it makes
Option 3 a disproportionate and not very efficient option.
In the light of the previous assessment, the preferred option would be Option 2. This
option is the best in terms of effectiveness and, given its economic impacts, has been
demonstrated to be the most efficient as well as consistent with other policy areas.
Subsidiarity
6.1.6.
The necessity of EU action is based on the evidence that national approaches not only
lead to sub-optimal measures, they also make the impacts of a crisis more acute.
Additionally, the risk of a blackout is not confined to national boundaries and could
directly or indirectly affect several Member States. Therefore, national actions in terms
of preparedness and mitigation cannot only be defined nationally, given the potential
impact on the level of security of supply of a neighbouring Member State and/or on the
availability of measures to tackle scarcity situation.
The increasing interconnection of the EU electricity markets requires a coordination of
measures. In the absence of such coordination, security of supply measures (including
measures on cybersecurity) implemented at national level only are likely to jeopardize
other Member States' or the security of supply at EU level. Situations like the cold spell
of 2012 showed that coordination of action and solidarity are of vital importance. An
action in one country can provoke risks of blackouts in neighbouring countries (e.g.
electricity export limitations imposed by Bulgaria in February 2012 had an impact in the
electricity and gas sectors in Greece). By contrary, coordination may offer a wider range
of solutions.
So far, the potential for more efficient and less costly measures thanks to the regional
coordination has not being fully exploited, which is detrimental to EU consumers.
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However, the regional approach to security of supply also requires paying special
attention to the divergences that between regions could appear. Therefore such
coordinated approach requires action at the EU level. Action at EU level could be also
needed under certain situations where the security of supply in the EU, cannot be
sufficiently achieved by the Member States alone and can therefore, by reason of the
scale or efforts of the action, be better achieved at Union level.
The EU action is framed under Article 194 of Treaty of the Functioning of the Energy
Union (TFEU) which recognizes that certain level of coordination, transparency and
cooperation of the EU Member states' policies on security of supply is necessary in order
to ensure the functioning of the energy market and the security of supply in the Union.
Stakeholders' Opinions
6.1.7.
The results of the Public Consultation on Risk Preparedness in the area of Security of
Electricity Supply showed that the majority of respondents (companies, associations and
Governments) take the view that the current legal framework (the SoS Directive) is not
sufficient to address the interdependencies of an integrated European electricity market.
Assessments and Plans
A majority of stakeholders is in favour of requiring Member States to draw up risk
preparedness plans (see as example the answers from the Dutch and Latvian
Governments, GEODE, CEDEC, EDF UK, TenneT, Eurelectric and Europex).
Stakeholders also see a need for regional coordination of the assessment and preparation
for rare/extreme risks (see for example the anwers of the Estonian, Finish, French, Dutch,
Swedish Governments as well as ENTSO-E and Eurelectric). However, there is no
agreement on how to 'define' regions for planning and cooperation. Most stakeholders
suggest to use existing (voluntary) systems for regional cooperation as a staring point
(e.g. the Finish Government) and emphasize the role of the existing RSCs (e.g. the Czech
Government). Also the European Parliament42
takes the view that it makes sense to step
up cooperation within and between regions under the coordination of ACER and with
cooperation of ENTSO-E, particularly as regards evaluating cross-border impacts.
Stakeholders further make the case for a common methodology for assessing risks to
ensure comparability of results (e.g. EDF). This could be achieved through common
high-level templates (e.g. answers from the Finish, Dutch, Norwegian Governments and
the German Association of Local Utilities). There is general acknowledgement of the
importance of preventing risks related to cyber-attacks.
Many stakeholders stress the need for a definition/clarification on roles and
responsibilities as well as operational procedures to be followed (e.g. who to contact in
times of crisis). Stakeholders see the added value of designating one 'competent
authority' per Member States, however there is no agreement on who this should be.
42
See: Towards a New Energy Market Design (June 2016), Werner Langen, European Parliament,
paragraph 68.
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Some argue that the choice should be left with the Member States (see for example the
answers from the Norwegian Government or the German Association of Local Utilities)
while others prefer a strong mandate of the TSOs (e.g. TenneT).
Crisis management
Stakeholders, in particular from the industry also request more transparency to reduce the
scope for measures that unnecessarily distort markets. A majority of stakeholders sees a
need for clear provisions on the suspension of market activities, "protected customers"
and cost compensation (e.g. EDF).
Even though stakeholders point out that the draft Network Codes and current practice
should be taken into account, they see a need for political discussion on regional level
and the definition of clear principles for crisis management as e.g. curtailment in
simultaneous scarcity situations requires political decision (e.g. ENTSO-E43
). The need
to develop a more common approach to managing crisis situations within the EU while
taking into account the existing regional solutions is also seen by the Dutch Presidency of
the European Council44
and the Florence Forum45
.
Monitoring
In order to ensure adequate oversight, most stakeholders are in favour of a system of peer
reviews to be conducted in a regional context or in the frame of the Electricity
Coordination Group which could provide the interlinkage between technical and
political/economical aspects. Monitoring could be further enhanced through more
common and transparent approach to standards. Some stakeholders wish a stronger role
for ACER/ENTSO-E and a rather facilitating role for the Commission (e.g. CEER,
ENTSO-E)
43
See for example ENTSO-E's presentation on Capacity Mechanisms (TOP 2.4) from the Florence
Forum in June 2016, ENTSO-E (available: https://ec.europa.eu/energy/en/events/meeting-european-
electricity-regulatory-forum-florence).
44
See Note to the Permanent Representatives Committee/Council: Messages from the Presidency on
electricity market design and regional cooperation, paragraph 7.
45
See Conclusions from Florence Forum, March 2016, paragraph 10.
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Addressing energy poverty
7. DETAILED MEASURES ASSESSED UNDER PROBLEM AREA 4: THE SLOW DEPLOYMENT
OF NEW SERVICES, LOW LEVELS OF SERVICE AND POOR RETAIL MARKET PERFORMANCE
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7.1. Addressing energy poverty
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Addressing energy poverty
Summary table
7.1.1.
Objective: Better understanding of energy poverty and disconnection protection to all consumers
Option: 0 Option: 0+ Option 1 Option 2
BAU: sharing of good practices. BAU: sharing of good practices
and increasing the efforts to
correctly implement the legislation.
Voluntary collaboration across
Member States to agree on scope
and measurement of energy
poverty.
Setting an EU framework to monitor energy
poverty.
Setting a uniform EU framework to
monitor energy poverty, preventative
measures to avoid disconnections and
disconnection winter moratorium for
vulnerable consumers.
Energy poverty - EU Observatory of Energy poverty
(funded until 2030).
- Option 0+: EU Observatory of Energy
Poverty (funded until 2030).
- Generic description of the term energy
poverty in the legislation. Transparency in
relation to the meaning of energy poverty
and the number of households in a situation
of energy poverty
- Member States to measure energy poverty.
Better implementation of the current
provisions.
- Option 0+: EU Observatory of Energy
Poverty (funded until 2030).
- Specific definition of energy poverty
based on a share of income spent on
energy.
- Member States to measure energy
poverty using required energy.
Better implementation and transparency
as in Option 1.
Disconnection
safeguards
- NRAs to monitor and report
figures on disconnections.
- NRAs to monitor and report figures on
disconnections.
- NRAs to monitor and report figures on
disconnections.
- A minimum notification period before a
disconnection.
- All customers to receive information on
the sources of support and be offered the
possibility to delay payments or
restructure their debts, prior to
disconnection.
- Winter moratorium46
of disconnections
for vulnerable consumers.
46
An all season moratorium may be suitable to some MS but not necessarily to all. In addition, evidence on Excess Summer Death is less developed than for Excess Winter Deaths which
makes it difficult to quantify the cost/benefits. Finally, stakeholders have noted that while in winter, heating is necessary, particularly if affected by bad health. Other cost effective
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Addressing energy poverty
Pros - Continuous knowledge exchange. - Stronger enforcement of current
legislation and continuous
knowledge exchange.
- Clarity on the concept and measuring of
energy poverty across the EU.
- Standardised energy poverty concept and
metric which enables monitoring of
energy poverty at EU level.
- Equip Member States with the tools to
reduce disconnections.
Cons - Existing shortcomings of the legislation
are not addressed: lack of clarity of the
concept of energy poverty and the
number of energy poor households
persist.
- Energy poverty remains a vague concept
leaving space for Member States to
continue inefficient practices such as
regulated prices.
- Indirect measure that could be viewed as
positive but insufficient by key
stakeholders.
- Insufficient to address the
shortcomings of the current
legislation with regard to energy
poverty and targeted protection.
- New legislative proposal necessary.
- Administrative costs.
-
- New legislative proposal necessary.
- Higher administrative costs.
- Potential conflict with principle of
subsidiarity.
- Specific definition of energy poverty
may not be suitable for all Member
States.
- Safeguards against disconnection may
result in higher costs for companies
which may be passed to consumers.
- Safeguards against disconnection may
also result in market distortions where
new suppliers avoid entering markets
where risks of disconnections are
significant and the suppliers active in
such markets raise margins for all
consumers in order to recoup losses from
unpaid bills.
- Moratorium of disconnection may
conflict with freedom of contract.
Most suitable option(s): Option 1 is recommended as the most balanced package of measures in terms of the cost of measures and the associated benefits. Option 1 will result in a clear
framework that will allow the EU and Member States to measure and monitor the level of energy poverty across the EU. The impact assessment found that the propose disconnection
safeguards in Option 2 come at a cost. There is potential to develop these measures at the EU level. However, Member States may be better suited to design these schemes to ensure that
synergies between national social services and disconnection safeguards can be achieved. Please note that Option 1 and Option 2 also include the measures described in Option 0+.
solutions can be found for heatwave (drink water; staying indoors). We are aware that in some MS the housing stock is not prepared for heatwaves and houses are overheated. However,
this may be better assessed at Member State level.
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Description of the baseline
7.1.2.
Energy has a fundamental role to ensure adequate households' standards of living.
Energy services are crucial to ensure warm homes, water and meals, lighting,
refrigeration and the operation of other appliances. European households are, however,
increasingly unable to meet their basic energy needs due to energy prices increasing
faster than household income and inefficient housing and household appliances leading
to higher energy bills47
.
An affordable connection to energy supply facilitates modern daily life by providing
essential services and enabling social interactions. Lack of access to an energy supply
impinges on the rights of energy consumers and negatively affects living conditions and
health48
. This is well recognised in legislation49
and reflected in the overall objectives of
the European Internal Energy Market (IEM).
Under the existing provisions in the Electricity and Gas Directive, Member States have to
address energy poverty where identified. The evaluation of the provisions found
important shortcomings stemming from the opaqueness of the term energy poverty,
particularly in relation to consumer vulnerability, and the lack of transparency with
regards to the number of households suffering from energy poverty across Member
States.
The aim of this Section is to describe the two policy areas impacted by the proposed
options: energy poverty and disconnection safeguards.
Energy poverty: drivers of energy poverty and number of households in energy poverty
Energy poverty is often defined as the situation in which individuals or households are
not able to adequately heat their homes or meet other required energy services at an
affordable cost50
.
Energy poverty is usually discussed in the context of general poverty. Yet, households
face widely varying costs to achieve the same level of warmth for reasons other than
income, such as, energy efficiency of the dwelling or household's ability to interact with
the market. In addition, an adequate level of energy is essential for citizens to function
and actively participate in society51
.
47
Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies and
measures. (2015). Insight_E.
48
COM (2015) "A framework Strategy for a Resilient Energy Union with a Forward-looking Climate
Change Policy"
49
Directive 2009/72/EC Point 45 states that “Member States should ensure that household
customers...enjoy the right to be supplied with electricity of a specified quality at clearly comparable,
transparent and reasonable prices.”
50
Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies and
measures. (2015). Insight_E.
51
Fuel Poverty: The problem and its measurement. 2001. John Hills. Available at:
http://sticerd.lse.ac.uk/dps/case/cr/CASEreport69.pdf. Working Paper on Energy Poverty. 2016.
Vulnerable Consumer Working Group. The Vulnerable Consumer Working Group (VCWG) provides
345
Addressing energy poverty
Insight_E identifies high energy bills, low income and poor energy efficiency as the main
drivers of energy poverty52
.
Figure 1: Drivers of energy poverty
Source: Insight_E (2015)
Looking at the drivers, it is likely that energy poverty impacts low-income households
with higher energy needs. Eurostat publishes the number of households who felt unable
to keep warm during winter. This indicator is widely used in the literature as a proxy
indicator of energy poverty. In 2014, around 10% of the EU population was not able to
keep their home adequately warm53
(see Figure below).
advice to the European Commission on the topics of consumer vulnerability and energy poverty.
Industry, consumer associations, regulators and Member States representatives are members of the
group.
52
Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies and
measures. (2015). Insight_E.
53
The indicator is measured as part of the Eurostat Survey on Income and Living Conditions (EU-SILC).
ENERGY
POVERTY
ENERGY
AFFORDABILITY
ENERGY
USE
PATTERNS
HOUSING
PATTERNS
HIGH
ENERGY
BILLS
POOR
ENERGY
EFFICIENCY
LOW
INCOME
Indicators:
- Energy consumption
(type)*
- Type of heating
system & share of
central heating*
Indicators:
- Tenure system*
- Housing
characteristics*
Indicators:
- Income
- Energy prices*
- Energy
consumption
(level)
* : exogenous
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Addressing energy poverty
Figure 2: Percentage of all households and households in poverty that consider they
are unable to keep warm
Source: Eurostat – SILC indicators (Inability to keep home adequately warm - Code: ilc_mdes01)
Evidence suggests that energy poverty is increasing in Europe. In recent years, energy
prices have risen faster than household disposable income54
, which has been particularly
problematic for low-income households, who depending on their individual
circumstances, may have had to under-heat their homes, reduce consumption on other
essential goods and services or get into debt to meet their energy needs55
.
Data from Member States on household energy consumption shows that the poorest
households have seen their share of disposable income spent on gas, electricity and other
fuels used for domestic use56
increased more than middle-income households. The Figure
below presents the EU share of household expenditure on domestic energy between 2000
and 2014.
54
Source: Eurostat (Electricity prices for domestic consumers; Gas prices for domestic consumers;
disposable income of households per capita; period 2010 – 2014).
55
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
56
Domestic use refers to heating, lighting and powering appliances.
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Addressing energy poverty
Figure 3: EU average - share of households' budget spent on domestic energy
services
Source: National Statistical Authorities of EU Member States; VCWG (2016)
In 2014, expenditure on energy services for the poorest households in the EU increased
by 50%, reaching almost 9% of their total budget.
Preliminary analysis for the upcoming Energy Price and Cost Report indicates that in
most of the EU Member States the share of energy in total expenditure grew faster in the
lowest income quintile than in the third quintile, implying that increasing energy costs
impacted poorer households more significantly than those on middle income. For
instance, the EU average spending for households in the lowest income quintile on
electricity and gas increased by 24% in real terms. As a comparison, middle income
households saw their domestic energy expenditure increase by 18% in real terms.
The lack of affordability of domestic energy services, which can be understood as a
proxy for energy poverty, can have serious consequences on households' well-being.
The Marmot Review highlighted the strong relationship between colder homes, Excess
Winter Deaths (EWDs) and increased incidence of other health problems. The review
found that 22% of EWDs in the UK could be attributed to cold housing. Healy57
found
that countries with the poorest housing (Portugal, Greece, Ireland, the UK) show the
highest excess winter mortality.
The Figure below presents EWD58
for the EU Member States in 2014. The Figure shows
that deaths in winter are significantly higher than during the rest of the year, particular
for some Member States.
57
Excess winter mortality in Europe: a cross country analysis identifying key risk factors. (2003). Healy.
58
Excess Winter Deaths = winter death (December – March)- 0.5Non-winter deaths (August –
November, April – July / (average of non-winter deaths)
6%
9%
5%
6%
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Poorest households Middle income households
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Addressing energy poverty
Figure 4: Excess Winter Deaths – 2014
Source: EU Buildings Database (BPIE)
In addition to the negative impacts on health, energy poverty can result in high level of
indebtedness or even disconnection. At the EU level, energy poverty risks excluding
some consumers from the energy transition, preventing them from enjoying the benefits
of the IEM.
The issue of energy poverty or lack of affordability of domestic energy services is likely
to remain relevant. In a scenario where energy prices follow GDP growth while wages,
especially for low-income workers remain flat, the gap between household income and
energy prices will widen and energy poverty is likely to increase. There are two main
channels through which wages for low-skilled workers may be supressed:
- Automation: routine tasks which are usually carried out by low-skilled workers
can be automated as technology allows. As the cost of technology falls, low-
skilled wages may be supressed to compete with capital59
.
- Skill-bias innovation: modern economics rely on a more educated workforce. As
demand for skilled individuals increases, it decreases the demand for unskilled
workers and their wages60
These effects combined are likely to supress wages, making affordability of energy
services more difficult for low-income households and, as a result, increase the number
of households in energy poverty.
Disconnection safeguards: protecting energy poor and vulnerable consumers
59
Unemployment and Innovation, No 20670, NBER Working Papers. 2014. Stiglitz.
60
"Skills, Tasks and Technologies: Implications for employment and earnings", No 16082, NBER
Working Papers. 2010. Acemoglu and Autor.
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Addressing energy poverty
The evaluation identified that given the rising levels of energy poverty. Member States
may have been discouraged to phase out regulated prices. Regulated prices, however,
have negative implications on consumers, hindering competition and innovation61
.
The evaluation recommended that any future legislative change could look into
reinforcing EU assistance on energy poverty proposing appropriate tools for addressing
energy poverty which support Member States' efforts to phase-out regulated prices62
.
Article 3 of the Electricity Directive63
and Gas Directive 64
markets reinforces the role of
consumer protection and the additional need for protection of vulnerable consumers
through particular measures, referring to the prohibition of electricity (and gas) in critical
times as one option.
Disconnections in electricity or gas supply to residential households typically arise out of
non-payment and can become especially problematic for households struggling to keep
up with their bills. In addition, there may be a disproportionately negative impact on
households with children or elderly residents in terms of health, education, etc.
In what follows, we provide an overview of the number of households being
disconnected and the main disconnection safeguards applied by Member States.
Overview of electricity and gas disconnections in the EU
Disconnection rates vary significantly across Member States. Figure 5 indicates that the
higher the disconnection level, as can be expected, the higher the arrears on utility bills65
,
which increases when the income falls below 60% of the median income. Similar
disconnection levels (Malta, Denmark, France, and Austria) exhibit similar levels of
arrears on utility bills. However, there are some exceptions: UK, Lithuania, Belgium and
Luxembourg have relatively high arrears and low disconnection rates.
61
A detail description of the negative impacts of regulated prices and the Member States currently
applying some kind of price regulation mechanism is included in Annex on Price Regulation
62
All energy consumers explicitly have a number of rights including a right to an electricity connection,
choice of and ability to switch supplier, clear contract information and right of withdrawal, and
accurate information and billing on energy consumption, vulnerable customers should receive specific
protection measures to ensure adequate protection.
63
“Member States shall take appropriate measures to protect final customers, and shall, in particular,
ensure that there are adequate safeguards to protect vulnerable customers. In this context, each
Member State shall define the concept of vulnerable customers which may refer to energy poverty and,
inter alia, to the prohibition of disconnection of electricity to such customers in critical times. Member
States shall ensure that rights and obligations linked to vulnerable customers are applied. In
particular, they shall take measures to protect final customers in remote areas.”
64
Directive 2009/73/EC of the European Parliament and the Council of 13 July 2009 concerning
common rules for the internal market in natural gas and repealing Directive 2003/55/EC (OJ L 211,
14.8.2009, p. 94).
65
Eurostat EU-SILC 2014
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Addressing energy poverty
Figure 5: Share of customers with electricity disconnections, gas disconnection, and
share of population in arrears on utility bills
Source: Insight_E (Forthcoming); Data: Eurostat; CEER National Indicators Database 2015
The rate of electricity disconnections, where the data is available, is highest across the
southern European Member States that have arguably been hardest hit by recessionary
effects of the recent economic downturn66
. In fact, in those Member States, households
exhibit the highest shares of debt on utility bills.
In terms of gas disconnections, where the data was reported, Portugal, Italy, Greece and
Hungary exhibit the highest levels of gas disconnections followed by France, Spain,
Poland, Austria, Germany and Slovakia.
Disconnection safeguards: a classification of measures
Disconnection safeguards represent one of the measures that Member States implement
to protect energy consumers. These measures ensure consumers have a continuous
supply of energy. Such safeguards can be applied to the entire customer base or to
specific groups, such as vulnerable consumers.
Disconnection safeguards can be grouped into four key measures, which can take the
form of direct protection measures, such as disconnection prohibitions, and / or other
66
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
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complementary associated measures such as debt management, and customer
engagement. See Table below67
.
Table 1: Summary of disconnection safeguards
Measure Description
Disconnection
prohibition
Moratorium on disconnecting the energy supply (either electricity, gas or both) for
all customers, a specific target group or time period (e.g., Winter)
Debt management Debt management can include a negotiated a payment plan, delayed payment
responsibility or a financial grant to assist with costs.
Customer
engagement
Customer engagement typically involves communication between the energy
supplier and the customer, where either the customer contacts the energy supplier for
assistance or the energy supplier is required to engage with the customer before
commencing the actual disconnection.
Source: Insight_E (Forthcoming)
Member States use a combination of these measures to prevent consumers from
disconnection. A summary of those is reported in Table 2.
67
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
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Table 2: Disconnection protection safeguards by Member States
E electricity G gas L legislated V voluntary
Source: CEER National Indicators Database 2015, INSIGHT_E Country Reports 2015
Focus AT BE BG CY CZ DE DK EE ES FI FR GR HR HU IE IT LT LV LU MT NL PL PT RO SE SK SI UK
All consumers EG
Vulnerable consumers/low
income/socio-demographic
E E EG EG EG EG EG EG E
Consumers with (or at risk
of) medical conditions
E EG E EG EG EG EG E E
Services (such as public
lighting, hospitals and
transport)
EG E
Unemployed consumers
EG EG EG
Under bill dispute
settlement
E E EG EG EG E
All consumers
EG EG E EG
Vulnerable consumers/low
income/socio-demographic
EG EG EG EG EG EG EG E EG
Consumers with (or at risk
of) medical conditions
EG EG EG
Debt management
LV LV L L LV LV L V L L L L L L L L L L
Prepaid meters
LV L LV L L L L L
Customer engagement
LV LV LV L LV L L LV LV L L L LV L V
Elec Discon per 1000
customers
9.1 1.5 55.1 7.5 10.0 23.0 10.0 32.6 6.3 3.6 40.0 1.8 3.0 10.0 20.0 56.1 14.0 0.0
Prepaid meters per 1000
customers
1.4 46.0 0.0 0.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 15.1 0.0 0.0 12.0
Disconnection
prohibition
Complementary
measures
Measures
year-round
measures
Seasonal
measures
(Winter
or
certain
days
of
the
week)
Statistics
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Addressing energy poverty
Disconnection safeguards - disconnection prohibition
Disconnection prohibitions are non-financial measures where moratoriums on
disconnections are declared, often for specific customer groups or for specific time
periods. These include measures that forbid disconnection to all customers or a target
group, or measures that allow disconnection only after certain stringent steps have been
taken. Prohibition can apply at particular times of the year (e.g., Winter), target particular
socio-demographic characteristics (e.g., either defined through the official definition for
“vulnerable consumer” or target households with elderly or children), where this would
have a negative impact on health, to customers in a legitimate complaint process, or to a
situation where a country is going through a national economic crisis68
.
Nineteen states have either year-round or seasonal disconnection prohibition.
Disconnection prohibition is legislated exclusively all year-round for specific customer
groups in seven Member States (Cyprus, Denmark, Spain, Luxembourg, Poland,
Portugal, Sweden), two Member States offer seasonal disconnection prohibition only
(Belgium, UK) and eleven Member States offer both year-round and seasonal
disconnection prohibition to varying customer groups (Estonia, Finland, France, Greece,
Hungary, Ireland, Italy, Lithuania, Netherlands, Romania and Slovenia).
Only four Member States provide blanket coverage for consumers in relation to
disconnection protection, but only on a seasonal basis (Belgium, Estonia, Italy, and the
Netherlands). Other widely protected consumers are those with (or at risk of) medical
conditions (in ten Member States - Cyprus, Estonia, Spain, Finland, Greece, Hungary,
Ireland, the Netherlands, Sweden, Slovenia), and customers currently under dispute
settlements (in six Member States - Italy, Luxembourg, the Netherlands, Poland,
Portugal, Sweden).
Disconnection safeguards - debt management
Debt management can include non-financial arrangements such as counselling or
assistance with budgeting as well as financial arrangements including a negotiated
payment plan, delayed payment responsibility or a financial grant to assist with costs. In
some instances, this is a measure that regulators or energy suppliers are required to offer,
whereas in other Member States, this can be offered either voluntarily through a
government agency, an energy supplier, or other consultation bodies.
The use of debt management measures is legislated in 17 Member States (Austria,
Belgium, Cyprus, Czech Republic, Germany, Spain, France, Hungary, Ireland, Italy,
Luxembourg, Malta, the Netherlands, Poland, Sweden Slovenia, and UK), while four
Member States (Austria, Belgium, Germany, Spain) also implement additional voluntary
measures, whereas Greece implements only voluntary measures for debt management.
68
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
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Addressing energy poverty
Disconnection safeguards - customer engagement
Customer engagement typically involves communication between the energy supplier
and the customer, where either the customer contacts the energy supplier for assistance or
the energy supplier is required to engage with the customer before commencing the
actual disconnection.
Energy consumers have a right to clear and transparent billing information and a single
point of contact, whose role is to ensure that consumers receive all the information that
they need regarding their rights.
Some form of customer engagement is implemented in 15 Member States (Austria,
Belgium, Germany, Denmark, Spain, France, Ireland, Italy, Luxembourg, Poland,
Portugal, Romania, Sweden, Slovakia, and UK). Limited information is available on how
the various energy companies choose to engage with customers, but a review of the
regulators showed that the legislation usually ensures that consumers are notified about
their bills or an impending disconnection usually in the form of a letter69
.
Finally, 22 Member States combine the use of debt management and some form of
customer engagement including: Austria, Belgium, Cyprus, Czech Republic, Germany,
Denmark, Spain, France, Greece, Hungary, Ireland, Italy, Luxembourg, Malta, the
Netherlands, Poland, Portugal, Romania, Sweden, Slovakia, Slovenia and UK.
On the other hand six Member States do not have debt management or customer
engagement safeguards either in their legislation or voluntarily and include Bulgaria,
Estonia, Finland, Croatia, Lithuania and Latvia.
Disconnection notification periods and procedures for disconnection and reconnection
across Member States
Even if the time frames differ among Member States, the practice for disconnecting and
reconnecting customers to electricity and gas provision is similar. The general practice in
most Member States consists of at least one (or more) written notices of unpaid bills,
followed by disconnection. Both the days between the unpaid bill and the final notice of
disconnection, and between the latter and the disconnection are usually legislated70
.
The number of days before disconnection varies among Member States (Figure 6). The
disconnection period is the highest in Belgium with a lengthy disconnection process71
,
followed by the UK. Both Belgium and the UK have the lowest share of customers
disconnected from electricity. The explanation for such low disconnection levels might
be in the fact that those two states have the highest requirements in terms of days before
disconnection is legally possible, but could also be linked to the fairly high share of
69
CEER National Indicators Database 2015
70
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
71
Upon defaulting on payments, a customer is given at least 30 day notice of cancellation of the contract,
followed by a 60 day grace period to find another supplier. If the customer defaults on payments with
the second supplier, this process is repeated. Thereafter, the supplier can apply to the local council for
permission to disconnect the customer, especially if they refuse the installation of a prepaid meter.
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Addressing energy poverty
prepaid meters and strong use of complementary measures. Denmark does not have a
specific number of days legislated, but rather specifies that at least two notifications must
be sent out72
.
Certain Member States (e.g., Sweden and Luxembourg) contact the social services in
between the final notice period and the disconnection of a consumer. Other Member
States have longer disconnection times where a smart meter is in place (e.g., in Italy
before the disconnection takes place, the maximum power supply is reduced to 15% for
15 days73
).
Figure 6: Working days before electricity disconnection, in ascending order for
notification period (2014)
Source: Insight_E (Forthcoming)
Reconnection happens in most Member States only upon receipt of payment of the entire
outstanding debt to the service provider or when an alternative repayment plan has been
negotiated. In some Member States, the customer is reconnected if the unpaid bill is
disputed. In those cases, the service provider cannot disconnect the customer again until
the dispute is settled.
72
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
73
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
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Addressing energy poverty
Deficiencies of the current legislation
7.1.3.
This Section summarises Section 7.1.1 and Annex III of the Commission evaluation of
the provisions on consumer vulnerability and energy poverty in the 2009 Electricity and
Gas Directives. The full evaluation is included in a separate document.
The legislators' original objectives of these provisions were:
1. To ensure protection of vulnerable consumers by having Member States define
the concept of vulnerable consumers and implement measures to protect them.
2. To mitigate the problem of energy poverty by having Member States address
energy poverty, where identified, as an issue.
These provisions were put in place to facilitate the decision by Member States to proceed
with electricity and gas market liberalisation, as it was recognised by the legislators that
actions to protect vulnerable consumers were needed in the context of liberalising the
European energy market.
The evaluation assesses the legislation against five criteria. The Table below provides a
summary of this assessment.
Table 3: Evaluation of the provisions on consumer vulnerability and energy poverty
Criterion
Legislation
meets
criterion
Assessment
Achievements Shortcomings
Effectiveness Partially Member States define
vulnerable consumer and
adopt measures to protect
them.
Uneven protection of vulnerable
consumers.
Lack of data on the scale and drivers of
energy poverty
Growing energy poverty levels across
the EU
Lack of assistance by Member States to
address energy poverty.
NRA lack data to fulfil monitoring role.
Some Member States still quote energy
poverty as a reason for maintaining
price regulation and not going ahead
with full energy market liberalisation
Efficiency Completely Low costs compared with
potential benefits.
Relevance Completely Consumer vulnerability will
remain relevant as some
drivers of vulnerability are
permanent.
Energy poverty likely to grow in the
future if no policy adopted.
Coherence Partially No inconsistencies with or
elements working against
objectives of the provisions.
Lack of an agreed description of the
term energy poverty and caveats in the
obligations stand in contrast to the call
for action in the Directive.
EU-added
value
Completely Member States have taken
action as a result of EU
intervention.
Source: Evaluation of the provisions on consumer vulnerability and energy poverty
The evaluation concluded that the provisions in the Electricity and Gas Directive related
to consumer vulnerability and energy poverty were mostly effective.
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Addressing energy poverty
EU action successfully encouraged Member States to define the concept of vulnerable
consumers in their legislation and to adopt measures to protect vulnerable consumers.
The provisions have also brought the issue of energy poverty to the attention of Member
States.
However, the evaluation also identified certain shortcomings. With respect to energy
poverty, the evaluation shows that even though most Member States have correctly
implemented the provisions on consumer vulnerability, the incidence of energy poverty
has continued to rise across the EU. In addition, even though Member States have to
address energy poverty where identified, the Electricity and Gas Directives do not
include any reference to the meaning of energy poverty nor do they explain in which
circumstances energy poverty can be identified as an issue.
At the same time current legislation does not enable comparable data on energy poverty
to be sourced from Member States to deliver a full picture of energy poverty in the EU,
in terms of scale, drivers and potential future evolution. In addition, while the provisions
on vulnerable consumers and energy poverty were put in place to facilitate the decision
by Member States to proceed with electricity and gas market liberalisation, 17 Member
States still maintain electricity and/or gas price regulation, often quoting increase in
energy poverty as a risk associated with deregulating energy prices.
While research indicates that energy poverty and consumer vulnerability are two distinct
issues74
, the provisions in the Electricity and Gas Directives refer to energy poverty as a
type of consumer vulnerability. The evaluation argues that this may have led to an
incorrect expectation that a single set of policy tools could address both problems
simultaneously.
The evaluation also identifies shortcomings in the effectiveness of the provisions
referring to the role of National Regulatory Authorities (NRAs) in monitoring electricity
and gas disconnections.
The evaluation found that the provisions were efficient and relevant. While efficiency
was difficult to quantify due to lack of data, it is likely that the benefits derived from
defining consumer vulnerability at the Member State level and implementing measures to
protect them outweighed the costs of setting up such policies. In terms of relevance,
evidence suggests that the problem of energy poverty is growing and it is likely to
continue without policy intervention. European Commission75
research suggests that
consumer vulnerability in the energy market will continue to be a relevant policy issue in
the future as a substantial share of those characterised as vulnerable consumers have
permanent characteristics that make them vulnerable.
74
"Energy poverty and vulnerable consumers in the energy sector across the EU: analysis of policies
and measures". (2015). Insight_E.
75
European Commission (2016). Available at:
http://ec.europa.eu/consumers/consumer_evidence/market_studies/vulnerability/index_en.htm-
summit/2015/files/ener_le_vulnerability_study_european_consumer_summit_2015_en.pdf.
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Addressing energy poverty
Regarding coherence, there were no inconsistencies or elements in the legislation
working against the objectives of the provisions on vulnerable and energy poor
consumers. Nevertheless the misidentification of consumer vulnerability and energy
poverty as the same issue in the Electricity and Gas Directives means that the expected
combined impacts are not occurring and energy poverty grows while Member States take
action to protect vulnerable consumers.
In relation to EU-added value, while it is true that some Member States had been
already protecting their vulnerable energy consumers prior to EU intervention, others
have been obliged to take action as a result of EU intervention.
Overall, the evaluation concluded that the provisions have mostly met their objectives.
However, the legislation did not give sufficient attention to the issue of energy poverty.
As the Electricity and Gas Directives define energy poverty as a type of consumer
vulnerability, the effectiveness of the provisions was reduced. This categorisation leads
to a simplistic expectation that a single set of policy measures from Member States
would automatically address both problems simultaneously. However, evidence suggests
that energy poverty has been rising over the years, despite the protection available for
vulnerable consumers. In parallel, Member States have maintained regulated prices,
which had a negative effect on the internal energy market.
The Options presented in this impact assessment attempt to address this situation.
Presentation of the options.
7.1.4.
This Section presents the policy options in detail. Each Option includes a table with the
description of the specific measures. An assessment of the costs and benefits for each of
the measures is presented in the following Section.
Business as Usual (BaU): sharing of good practices.
The BaU includes measures that are currently implemented or in the pipeline. These
measures will be undertaken without legislative change and aim at improving
knowledge-exchange.
Table 4: BaU
Measures Pros Cons
Energy
poverty
Promoting
good practices
Continuous
Knowledge
exchange.
Existing shortcomings of the legislation are not
addressed: lack of clarity of the concept of energy
poverty and the number of energy poor households
persist.
Energy poverty remains a vague concept leaving space
for Member States to continue inefficient practices such
as regulated prices.
Indirect measure that could be viewed as positive but
insufficient by key stakeholders.
The Commission has already secured funding to set up an Observatory of Energy
Poverty. However, the BaU scenario assumes the funding for the Observatory will not be
extended beyond 2019 and therefore no additional cost will be incurred in the appraised
period.
The Commission will continue promoting the exchange of good practices which are
likely to contribute to enhance transparency and knowledge dissemination. However, this
option may be insufficient to address the partial effectiveness of the current provisions as
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Addressing energy poverty
identified in the evaluation as the current legislation does not require Member States to
measure energy poverty and hence to address it.
Option 0+: sharing of good practices and monitoring the correct implementation of the
legislation.
There is scope to address some of the problems identified in the evaluation without new
legislation. This option seeks non-legislative measures such as voluntary collaboration
across Member States as a tool to address these problems. With the help of the EU
Observatory of Energy poverty, this option includes voluntary collaboration across
Member States to agree on the scope of energy poverty as well as the way of measuring.
Measures to ensure the monitoring of disconnections across Member States are also
included.
The evaluation identified that National Regulatory Authorities (NRAs) have not reported
to ACER data on the number of disconnections. As described in the evaluation, ACER
reported that only 16 NRAs were able to report data on disconnections. This is despite
the legal obligation stated in the Electricity Directive Article 37 Duties and powers of the
regulatory authority under paragraphs (j)76
and (e)77
.
In addition, the Observatory delivers the exchange of good practices and better statistical
understanding of the drivers of energy poverty. Option 0+ assumes the Observatory
continues its operation at least until 2030 (the end of the assessment period for the Impact
Assessment).
Table 5: Option 0+
Measures Pros Cons
Energy
poverty
EU Observatory of Energy
Poverty.
NRAs to monitor and report
data on disconnections.
Voluntary collaboration across
Member States to agree on
scope and measurement of
energy poverty.
Stronger enforcement of
current legislation and
continuous knowledge
exchange.
Insufficient to address the
shortcomings of the current
legislation with regard to energy
poverty and targeted protection.
This option does not address all the shortcomings identified in the evaluation, such as the
need to measure energy poverty and the lack of adequate tools to protect vulnerable and
energy poor consumers. Furthermore, voluntary collaboration may not be a suitable
measure. The Commission already undertakes actions involving Member States, such as
the publication of guidelines and working paper in the context of the Vulnerable
76
Monitoring the level and effectiveness of market opening and competition at wholesale and retail
levels, including on electricity exchanges, prices for household customers including prepayment
systems, switching rates, disconnection rates, charges for and the execution of maintenance services,
and complaints by household customers, as well as any distortion or restriction of competition,
including providing any relevant information, and bringing any relevant cases to the relevant
competition authorities;
77
Reporting annually on its activity and the fulfilment of its duties to the relevant authorities of the
Member States, the Agency and the Commission. Such reports shall cover the steps taken and the
results obtained as regards each of the tasks listed in this Article;
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Addressing energy poverty
Consumer Working Group, with have had a limited impact on Member States. Thus,
legislative action, beyond Option0+, is required.
Option 1: Setting an EU framework to monitor energy poverty.
This option includes obligations on Member States that will need to be implemented
through new EU legislation. The measures included in this option are designed to address
the shortcomings identified in the evaluation:
- clarifying the concept of energy poverty,
- improving transparency with regard to the number of households in energy poverty.
Table 6: Option 1
Measures Pros Cons
Energy
poverty
- Generic, adaptable
description of the term
energy poverty in the
legislation.
- Member States to measure
energy poverty.
- Shared understanding of what energy
poverty entails while flexible enough to
cater for Member States' differences.
- Transparency when measuring and
monitoring energy poverty.
- Synergies with the Observatory.
- New legislation will
be necessary.
- Administrative
impact on Member
States.
Option 1 includes a number of legislative changes that represent new obligations for
Member States. In what follows, we provide a detailed description of these new
obligations.
Energy poverty - a description of the term energy poverty
Option 1 adds a description of the term energy poverty in the EU legislation. The
objective of this measure is to clarify the term energy poverty.
A number of European institutions have called on the European Commission to propose
an EU-wide definition of energy poverty, calling for a common description of the term
energy poverty.
- EESC (2011; 1)78
: "… energy poverty should be tackled at all tiers of
government, and that the EU should adopt a common general definition of energy
poverty, which could then be adapted by Member States".
- Committee of the Regions (2014;15)79
"…recognition of the problem at the
political level on the one hand, and to ensure legal certainty for measures to
combat energy poverty on the other; such a definition should be flexible in view
of the diverse circumstances of the Member States and their regions…”.
78
European Economic and Social Committee (EESC) (2011) Opinion of the European Economic and
Social Committee on ‘Energy poverty in the context of liberalisation and the economic crisis’
(exploratory opinion). Official Journal of the European Union, C 44/53.
79
Committee of the Regions (CoR) (2014) Opinion of the Committee of the Regions - Affordable Energy
for All. Official Journal of the European Union, C 174/15.
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Addressing energy poverty
- European Parliament (2016)80
" Calls on the Commission to develop with
stakeholders a common definition of energy poverty which should aim at
assessing at least the following elements: material scope, difficulty for a
household to gain access to essential energy, affordability and share of total
household cost, impact on basic household needs such as heating, cooling,
cooking, lighting and transport".
- European Parliament (2016)81
"Calls for the development of a strong EU
framework to fight energy poverty, including a broad, common but non-
quantitative definition of energy poverty, focusing on the idea that access to
affordable energy is a basic social right"
Thomson et al82
summarise the arguments in favour and against of an EU-wide definition
of energy poverty.
Table 7: Arguments in favour and against an EU-wide definition of energy poverty
In favour Against
Policy synergy. Not all Member States are
addressing this problem and those that are, act on
their own, without seeking synergies with others,
which makes it harder to identify, assess and deal
with energy poverty at the European level.
Limited evidence. Need to compile comparable
household data on energy consumption and income
to produce reliable statistics.
Recognition. A common EU-level definition of
energy poverty may give the problem better
visibility at the Member State level.
Comparability. A shared pan-EU definition would
need to be relatively broad in order to accommodate
the diversity of contexts found at the Member State-
level, in terms of climate conditions, socioeconomic
factors, energy markets and more.
Clarification. Adopting even a general description
of fuel or energy poverty at the EU-level would
help to resolve the considerable terminological
confusion that presently exists, and may pave the
way for more detailed national definitions.
Path dependency. An incorrect definition may lead
Member States to a wrong path from which it may
be difficult to depart as a result of path dependency.
Source: Thomson et al (2016)
The Vulnerable Consumers Working Group (VCWG)83
looked into several definitions
used to describe energy poverty which have been put forward by Member States,
European institutions and research projects. Most of the definitions shared common
themes:
- domestic energy services refer to services such as heating, lighting, cooking and
powering electrical appliances;
- the term affordable is used to refer to households receiving adequate energy
services without getting into debt; and
80
European Parliament. Committee on Employment and Social Affairs. Draft report on meeting the
antipoverty target in the light of increasing household costs. (2015/2223(INI)). Rapporteur: Tamás
Meszerics.
81
European Parliament. Committee on Industry, Research and Energy. Draft report on Delivering a
New Deal for Energy Consumers. (2015/2323(INI)). Rapporteur: Theresa Griffin.
82
Fuel poverty in the European Union: a concept in need of definition? 2016. Thomson et al.
83
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
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Addressing energy poverty
- the term adequate usually means the amount of energy needed to ensure basic
comfort and health.
VCWG concluded that a prescriptive definition of energy poverty for the EU28 would be
too restrictive, given the diverse realities across Member States. Yet, the group agreed
that a generic definition represents a positive step forwards to tackle the problem of
energy poverty. The VCWG argues that, if such as EU-wide definition were to be
identified, it should be simple, focus on the problem of affordability and allow sufficient
flexibility to be relevant across Member States84
. Such a definition can refer to elements
such as households with a low-income; inability to afford; and adequate domestic energy
services. Within the generic definition Member States can adapt it to suit national
circumstances (e.g. by adopting their own numerical threshold for low income).
Energy poverty - Measuring energy poverty
Option 1 requires Member States to measure energy poverty. To measure energy poverty,
Member States will need to construct a metric which should make reference to household
income and household domestic energy expenditure.
Measuring energy poverty allows Member States to understand the depth of the problem
and assess the impact of the policies to tackle it85
.
Most researchers used Eurostat Survey on Income and Living Conditions (EU-SILC) to
produce proxy indicators of energy poverty at Member State level such as the perceived
inability to keep homes adequately warm86
. However, this indicator has some well-
known limitations87 88
:
- subjectivity due to self-reporting;
- limited understanding of the intensity of the issue due to the binary character of
the metric;
- assumption that participants in a survey view such judgments like 'adequacy of
warmth' in a similar way; and
- difficult to compare across Member States.
In Member States that have or are considering energy poverty metrics, most experiences
concern expenditure-based metrics rather than consensual-based metrics. The advantage
of an expenditure based metric is that it is quantifiable and objective. These indicators
measure energy poverty as a result of two of the main drivers of energy poverty:
domestic energy expenditure and household income. Nonetheless, these indicators also
suffer from some limitations89
:
84
A few Member States already have a definition of energy poverty. These definitions are presented in
Sub-Annex 1.
85
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
86
This kind of indicators is referred in the academic literature as consensual-based indicators.
87
Selecting Indicators to Measure Energy Poverty. 2016. Trinomics.
88
"Quantifying the prevalence of fuel poverty across the European Union". 2013. Thomson and Snell.
89
"Selecting Indicators to Measure Energy Poverty". 2016. Trinomics.
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Addressing energy poverty
- cannot assess whether consumers reduce expenditure because of budget
constraints or due to other factors. Thus, it does not take account of the issue of
self-disconnection i.e. households who do not consume adequate amount of
energy to avoid falling into arrears or debt;
- it does not reflect consumers’ motivation for expenditure levels; and
- sensitive to methodological decisions such as definition of income or the
definition of the threshold.
Member States will have the freedom to define the metric according to their
circumstances. A European Commission study reviewed 178 indicators of energy poverty
and proposed a final set of four indicators, three of them expenditure based metrics. The
study confirmed that all the final recommended indicators can be produced using data
already collected by Member States90
.
These measures build upon the existing provisions on energy poverty in the Electricity
and Gas Directive. They offer the necessary clarity to the term energy poverty, as well as,
the transparency with regards to the number of household in energy poverty. Since
currently available data can be used to measure energy poverty, the administrative costs
are limited. Likewise, the actions proposed do not condition Member States primary
competence on social policy, hence, respecting the principle of subsidiary.
90
Trinomics 2016. Available at:
https://ec.europa.eu/energy/sites/ener/files/documents/Selecting%20Indicators%20to%20Measure%20
Energy%20Poverty.pdf
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Addressing energy poverty
Option 2: Setting a uniform EU framework to monitor energy poverty, preventative
measures to avoid disconnections and disconnection winter moratorium for vulnerable
consumers.
Table 8: Option 2
Measures Pros Cons
Energy poverty - Specific, harmonised definition
of energy poverty.
- Require Member States to
measure energy poverty using
required energy.
- Improve comparability
of energy poverty as a
result of a harmonised
concept of energy
poverty.
- Measuring energy
poverty using required
energy.
- New legislation will be
necessary.
- A prescriptive
definition of energy
poverty may not be
adequate for all Member
States.
- High administrative
cost to measure energy
poverty using required
energy.
Safeguards
against
disconnection
- A minimum notification period
before a disconnection.
All customers to receive
information on the sources of
support and be offered the
possibility to delay payments or
restructure their debts, prior to
disconnection.
- Winter moratorium of
disconnections for vulnerable
consumers.
- Equips Member States
with the tools to prevent
and reduce the number of
disconnections.
- - Gives customers more
time to make
arrangements to pay their
bills, i.e. avoids
unnecessary
disconnections and costs
of disconnecting and
reconnecting.
- - Customers are given
information. about
outreach points.
- Customers are given an
opportunity to better
handle their energy debts
- The most vulnerable
customers will benefit
from a guaranteed energy
supply through the
coldest months of the
year.
- New legislation will be
necessary.
- Administrative impact
on Member States.
- Administrative impact
on energy companies
- Safeguards against
disconnection may
result in higher costs for
companies which may
be passed to consumers.
- Safeguards against
disconnection may also
result in market
distortions as suppliers
seek to avoid entering
markets where there are
likely to be significant
risks of disconnections
and the suppliers active
in such markets raise
margins for all
consumers in order to
recoup losses from
unpaid bills.
- Moratorium of
disconnection may
conflict with freedom of
contract.
Option 2 represents additional obligations for Member States. In what follows, we
describe these new obligations.
Energy poverty - EU definition of energy poverty
Option 2 adds a specific definition of energy poverty in the EU legislation. Energy
poverty will refer to those households which after meeting their required energy needs
fall below the poverty line or other income related threshold. This measure will clarify
the term energy poverty (as in Option 1) and improve the comparability and monitoring
of energy poverty within the EU.
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Addressing energy poverty
A definition using a relative income threshold, such as the Low Income High Cost91
, is
suited to measure energy poverty in the EU. Since the poverty threshold is a relative
metric (e.g. below 40% of the median income) this type of metric takes account of the
distribution of income in each Member State. However, it might well be that in some
Member States a significant number of households live below the poverty line. In those
cases, a different metric of energy poverty using a lower income threshold may be more
suitable.
Some stakeholders will be in favour of such as measure since it addresses the need for a
common definition. However, as it was described in Option 1, the EESC (2011: 1) and
Committee or the Regions (2014;15) request the Commission a 'common general
definition' ; 'flexible in view of the diverse circumstances of the Member States and
regions'. The VCWG92
also stated that 'a prescriptive definition of energy poverty for the
EU28 would be too restrictive, given the diverse realities across Member States'.
Similar arguments were put forward in Thomson et al93
with regard to comparability. The
authors argue that a shared pan-EU definition would need to be relatively broad in order
to accommodate the diversity of contexts found at the Member State level in terms of
climate conditions, socioeconomic factors or energy markets. This is in contradiction
with a more prescriptive definition of energy poverty at the EU level.
Energy poverty - measuring energy poverty
Option 2 requires Member States to measure energy poverty using 'required energy'.
Metrics using 'required' rather than 'actual' expenditure calculate the amount of energy
necessary to meet certain standards such as a specific indoor temperature during a
number of hours per day.
The main advantage of this type of measurement94
is that it refers to an adequate level of
energy service. As such, it computes the amount of energy for a specific heating regime
rather than measuring actual expenditure, which may not be adequate for low-income
households that may under-consume due to budget constraints.
In order to be able to compute required energy, the following information is needed95
:
- heating system and fuels used;
- dwelling characteristics;
- regional and daily climate variations; and
- number of days per year a household stays in their home.
91 "
Low income High Costs (LIHC) indicator" (Hills, 2011): A household i) income is below the poverty
line (taking into account energy costs); and ii) their energy costs are higher than is typical for their
household type.
92
Working Paper on Energy Poverty. 2016. Vulnerable Consumer Working Group.
93
"Fuel poverty in the European Union: a concept in need of definition?" 2016. Thomson et al.
94
The UK, which has considerable experience in this field, measures energy poverty or fuel poverty
using required energy.
95
Selecting Indicators to Measure Energy Poverty. 2016. Trinomics.
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Addressing energy poverty
This data, especially the variables related to dwelling characteristics, are rarely available.
To collect it, Member States are likely to need to run a Housing Condition Survey96
which ideally should be linked to the Household Budget Survey.
Safeguards against disconnection - minimum notification period of 40 working days
Evidence suggests that stronger guidelines dictating adequate disconnection times and
procedures could be an effective way to prevent disconnections. For instance, in Belgium
and UK, the two countries with the highest disconnection time requirements,
disconnection levels are at the lowest97
.
This measure requires Member States to give all customers at least two months
(approximately 40 working days) notice before a disconnection from the first unpaid bill.
In Member States, legislated working days before disconnecting a customer vary
between a week and 200 days, with an average of approximately 40 days (See Table
below).
Table 9: Statistics on disconnection notices (legal requirements) in Member States
MIN MAX Average Standard
deviation
Working days to final disconnection notice98
3 45 18.15 12.87
Working days to actually disconnect a final household
customer from the grid because of non-payment
7 200 36.81 36.79
Source: Insight_E (Forthcoming); Data: Eurostat; CEER National Indicators Database 2015
Longer disconnection period may stop some disconnections as customers have more time
to engage or to seek help. The direct monetary benefit comes in the form of avoided
disconnection and reconnection costs to society. Other non-direct monetary benefits to
the utility are those of retaining the customer, and avoiding lost income, due to allowing
the consumer time to pay back arrears.
It is possible to calculate the amount of time before which it is not cost effective to
disconnect a household from electricity and gas provision. This is done by comparing the
cost of disconnection and reconnection with the average monthly household expenditure
for gas and electricity.
Figure 7 shows the number of days it is cost-effective not to disconnect a household for
those Member States with available data to perform the necessary calculations.
96
The Housing Condition Survey measures the physical characteristics of the dwelling such as height of
the ceilings, materials of the wall, or the size of the windows to calculate the energy performance of
the building.
97
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E.
98
Denmark does not stipulate a number of days but rather that a minimum of two notices be sent
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Addressing energy poverty
Figure 7: Number of days from which it is cost-effective to disconnect a household
Source: Insight_E (Forthcoming)
Interestingly for both electricity and gas it is not cost effective to disconnect within a
certain time starting from the unpaid bill for any of the considered countries. For
electricity, in Germany and Italy, it is cost-effective to disconnect only after
approximately 2 months from the unpaid bill, while in Ireland and the UK at least one
month is needed to justify disconnection. That value is approximately 15 working days
for France and Spain, having less costly connection and reconnection procedures. For
gas, as the cost of connection and reconnection is higher, those values are larger. In
Germany and Spain three or more months of unpaid bills would justify a disconnection,
for Italy and France more than one month99
.
It is to be noted that these numbers merely compare the cost of connecting and
disconnecting a household with household energy bills. Including other social and health
benefits would increase the amount of days before a disconnection is cost effective.
Those costs are difficult to quantify. Nonetheless, a number of articles and research
projects provide evidence of a link between warmer homes and improvements in
health100101102103 104 105
. More information on the benefits of a longer notification period is
provided in the next Section.
99
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E
100
Chilled to Death: The human cost of cold homes. (2015). Association for the Conservation of Energy,
Available at: http://www.ukace.org/wp-content/uploads/2015/03/ACE-and-EBR-fact-file-2015-03-
Chilled-to-death.pdf
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Addressing energy poverty
Setting a minimum notification period of 40 working days will lead to 18 Member States
having to increase their disconnection notice requirements (See Table below). Five of
those would have to increase the notice by 10 working days or less. Hungary, Latvia,
Spain, Finland, Romania, Greece, Croatia, the Netherlands, UK and Belgium would not
be impacted by this regulation. In addition, Member States with robust social security
schemes disconnection safeguards would not have any substantial impact as early
intervention typically assists vulnerable consumers and the energy poor with avoiding
disconnections, nota bene via direct financial support.
The extension of the disconnection notice period is associated with additional costs for
the suppliers in the form of bills which can be left unpaid by some of the customers. The
measure also has potential market distortion effects as suppliers seek to avoid entering
markets where there are likely to be significant risks of disconnections and the suppliers
active in such markets raise margins for all consumers in order to recoup losses from
unpaid bills.
Table 10: Additional working days with a two month disconnection notice106
Member State Additional number of days
Cyprus 33
Czech Republic 33
Bulgaria 30
Ireland 30
Malta 26
Estonia 25
Lithuania 25
Portugal 25
Slovakia 25
Austria 20
Slovenia 20
Sweden 15
Germany 10
Italy 10
Luxembourg 10
Poland 10
France 5
Source Insight_E (Forthcoming); Data: Eurostat; CEER National Indicators Database 2015
Safeguards against disconnection – prior to disconnection notice, consumers should
receive: (i) information on the sources of support and (ii) be offered the possibility to
delay payments or restructure their debt.
101
"Fuel Poor & Health. Evidence work and evidence gaps". DECC. Presented at Health, cold homes and
fuel poverty Seminar at the University of Ulster. (2015). Cole, E. Available at:
http://nhfshare.heartforum.org.uk/HealthyPlaces/ESRCFuelPoverty/Cole.pdf
102
Towards an identification of European indoor environments’ impact on health and performance -
homes and schools. (2014). Grün & Urlaub.
103
Excess winter mortality: a cross-country analysis identifying key risk factors. Journal of Epidemiology
& Community Health 2003. Healy.
104
Estimating the health impacts of Northern Ireland’s Warm Homes Scheme 2000-2008. (2008). Liddell.
105
The Health Impacts of Cold Homes and Fuel Poverty (London: Friends of the Earth). (2011). Marmot
Review Team.
106
Denmark does not stipulate a number of days but rather that a minimum of two notices be sent
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Addressing energy poverty
Customer engagement
Customer engagement typically involves communication between the energy supplier
and the customer, where either the customer contacts the energy supplier for assistance or
the energy supplier is required to engage with the customer before commencing the
actual disconnection. This communication can take the form of a letter, registered letter,
e-mail, phone call, text message or house call. The use of these measures varies across
Member States and while a comprehensive review of how this is undertaken is not
available, it is clear that some variation of consumer engagement occurs nonetheless.
Debt management
Debt management can include non-financial arrangements such as counselling or
assistance with budgeting as well as financial arrangements including a negotiated
payment plan, delayed payment responsibility or a financial grant to assist with costs.
Safeguards against disconnection - winter moratorium of disconnections for vulnerable
consumers.
This measure stops disconnection from energy provision (electricity and gas), for
vulnerable consumers, during the winter months. Already, 10 Member States provide
seasonal disconnection prohibitions at particular times.
Of those Member States, eight define clearly the winter period during which
disconnections are banned (See Figure 8).
Figure 8: Winter period with ban on disconnection in Member States
Sep Oct Nov Dec Jan Feb Mar Apr May
BELGIUM
ESTONIA
FINLAND
FRANCE
HUNGARY
IRELAND
NETHERLANDS
UK
Source: Insight_E (Forthcoming)
On the other hand, other countries define the winter as ‘cold season’ or depending on
temperatures (e.g. Lithuania prohibit disconnections when the highest daily air
temperature is lower than minus 15 °C or higher than plus 30 °C).
This measure, unlike the others, will specifically target vulnerable consumers. Hence, the
coverage of the measure depends on the definition of consumer vulnerability in energy
markets in each of the Member States.
With regard to the disconnection safeguards discussed in this Section, it needs to be
noted that Member States may be better suited to design these schemes to ensure that
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Addressing energy poverty
synergies between national social services and disconnection safeguards can be achieved.
These synergies may also result in public sector savings which may be significant given
the substantial costs of some of these measures, see Table 22 and Table 23.
Comparison of the options
7.1.5.
This Section quantifies the costs and benefits for the BaU and each of the policy options.
The tables below summarise the main results of the Cost Benefit Analysis (CBA). The
methodology, assumptions and calculations are subsequently explained.
Table 11: BaU: costs and benefits
Costs Benefits
Description Quantification Description Quantification
Promoting good
practices.
Exchange of good
practices and
collaboration
across Member
States
EUR 0. Continuous
Knowledge
exchange.
N.A. only
qualitative.
Table 12: Option 0+: costs and benefits
Costs Benefits
Description Quantification Description Quantification
EU Observatory of
Energy Poverty.
Running the EU
Observatory of
energy poverty.
EUR100,000 per
year .
Knowledge
exchange.
N.A. only
qualitative.
NRAs to monitor
and report figures on
disconnections.
Better
implementation of
current legislation
Electricity
Directive Article
37 (j) and (e).
No additional cost. Improved
information on
number of
disconnections.
N.A. only
qualitative.
Table 13: Policy Option 1: costs and benefits
Costs Benefits
Description Quantification Description Quantification
Energy poverty
Generic
adaptable
description of
the term energy
poverty in the
legislation.
Enumerate the
main
characteristics
that define
energy poverty.
No additional
cost.
Transparency, clarification
and policy synergies.
N.A. only
qualitative.
Member States
to measure
energy poverty.
Produce a metric
to measure
energy poverty.
Administrative
cost.
Understanding the extent of
the problem. Improved
transparency.
N.A. only
qualitative.
Note: Policy Option 1 includes the measures described in option 0+.
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Addressing energy poverty
Table 14: Policy Option 2: costs and benefits
Costs Benefits
Description Quantification Description Quantification
Energy poverty
Specific
definition of
energy poverty
Produce a
specific
harmonised
definition of
energy poverty.
No additional
cost.
Transparency, clarification
and policy synergies.
N.A. only
qualitative.
Member States to
measure energy
poverty using
required energy
Collecting
detailed housing
stock data.
Administrative
cost.
Understanding the extent of
the problem. Improved
transparency.
N.A. only
qualitative.
Disconnection safeguards
A minimum
notification
period before a
disconnection.
All customers
will receive a
disconnection
notice at a
minimum of at
least two
months (or 40
working days)
before
disconnection
from the first
bill unpaid.
Cost of unpaid
bills.
General benefits from
avoiding disconnection in
the form of improvements
in households' health and
well-being; cross-
departmental savings; and
avoiding cost of
disconnection and
reconnection. Gives
customers more time to
make arrangements to pay
their bills.
N.A. only
qualitative.
All customers to
receive
information on
the sources of
support and be
offered the
possibility to
delay payments
or restructure
their debts, prior
to disconnection.
Prior to issuing
a disconnection
notice, all
consumers
should: receive:
(i) information
on the sources
of support, and;
(ii) be offered
the possibility to
delay payments
or restructure
their debt.
Consumer
information cost
varies depending
on the type of
intervention
which may
include
registered letters;
phone calls; text
message; or
emails.
Debt
management cost
depends on the
type of
intervention.
General benefits from
avoiding disconnection.
Gives customers more time
to make arrangements to
pay their bills, i.e. avoids
unnecessary disconnections
and costs of disconnecting
and reconnecting.
Customers are given
information about outreach
points.
Customers are given an
opportunity to better handle
their energy debts
N.A. only
qualitative.
Winter
moratorium of
disconnections
for vulnerable
consumers.
In case of non-
payment
vulnerable
consumers will
not be
disconnected
from the
electricity and
gas grid during
Winter.
The cost of
unpaid bills.
General benefits from
avoiding disconnection.
The most vulnerable
customers will benefit from
a guaranteed energy supply
through the coldest months
of the year.
N.A. only
qualitative.
Note: Policy Option 2 includes the measures described in option 0+.
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Addressing energy poverty
Methodology
The methodology follows the Better Regulation Guidelines. In this Section, we present
the steps taken for the calculation of the costs and benefits.
Introduction - Costs and Benefits Analysis (CBA)
This impact assessment takes account of societal costs and benefits when assessing the
impact of the policies. In addition, the net impact on total welfare and the net impacts on
specific groups (i.e. winners and losers) are relevant as these provisions are likely to
benefit more those in lower income or vulnerable economic conditions.
The cost of the measures occurs immediately following the adoption of the policies into
national legislation and are borne by public authorities (i.e. measuring energy poverty)
and energy providers (e.g. disconnection safeguards). Benefits, on the other hand, tend to
emerge over a longer time frame and are more difficult to quantify.
As far it has been possible, costs and benefits are based on market prices. However, this
has not always been possible, particularly when quantifying the benefits.
In the case of disconnection safeguards, the costs of this measure represent the mirror
image of the benefits for those households who are not disconnected as a result of the
safeguards. Even though this is a symmetrical change in private welfare and therefore it
cancels out at the aggregate level, there is an impact in terms of transfer of welfare
between those who are not in risk of disconnection (wealthier households) and those in
risk of disconnection (poorest households). It can be argued that this transfer has a
positive impact on efficiency if we assume poorest household have a higher marginal
utility for each additional euro received than wealthier households. This approach has
been followed in some Impact Assessments107
using empirical evidence from the
academic literature108
. Due to lack of data, however, these effects have not been
quantified.
The discount rate used equals 4%. The time period starts when the measures are
implemented at Member State level and ends in 2030. We assume measures are
implemented in 2020109
. In reality, the starting period may be subject to change
depending on which year the measures are approved in each Member State. This will
advance or delay the costs and benefits impacting the overall net benefit of the policies.
107
UK Treasury 'Green Book Appraisal and Evaluation in Central Government (2003). Annex 5
Distributional Impacts. Available at:
https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/220541/green_book_co
mplete.pdf
108
Cowell and Gardiner (1999); Pearce and Ulph (1995)
109
We assume the legislation proposed in the Winter Package will be approved by the co-legislator in
2017 and Member States will require three years for implementing the new measures.
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Addressing energy poverty
As stated in the Better Regulation guidelines, CBA has important limitations. The main
limitations refer to:
- the assumption that income can be a proxy for happiness or satisfaction,
- the fact that it willingly ignores distributional effects; and
- its lack of objectivity when it comes to the selection of certain parameters (e.g.
the inter-temporal discount rate), which can tilt the balance in favour of certain
regulatory options over others.
The overall goal of the intervention is to achieve the benefits at the overall lowest cost.
The policy options will contribute to advancement in social welfare in terms of economic
efficiency, consumer protection and life satisfaction.
Quantifying the costs
Producing a description of energy poverty (policy Option 1); and a specific definition of
energy poverty (policy Option 2) will be undertaken by the European Commission at no
additional cost.
Business as Usual – calculating the costs
Exchange of good practices
The European Commission continues fostering the exchange of good practices across
Member States through its network of stakeholders such as the Vulnerable Consumers
Workings Group. No additional cost is estimated.
Option 0+ – calculating the costs
The cost of the EU Observatory of Energy Poverty
The European Commission has published a contract service to build and maintain the EU
Observatory of Energy Poverty. The current budget equals EUR 800,000 for a 40 month
contract. The continuation of the work after the contract is estimated at EUR 100,000 per
year110
.
The cost of NRAs monitoring and reporting figures on disconnections
The current energy legislation requires national regulators to monitor disconnections.
However, not all Member States report figures on disconnections111
. Full implementation
of the current legislation represents no extra cost as there is no additional obligation.
Policy Option 1 – calculating the costs
The cost of Member States to measuring energy poverty making reference to household
income and household energy expenditure
110
"Selecting Indicators to Measure Energy Poverty". (2016). Trinomics.
111
ACER Market Monitoring Report (2014)
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Measuring energy poverty will result on a new information obligation for Member States.
This is a direct cost related to compliance i.e. the need to divert resources to address the
direct consequences of the policy options which creates an administrative cost112
to
comply with the new information obligation.
The administrative costs consist of two different cost components: the business-as-usual
costs and administrative impacts. The administrative impacts stem from the part of the
process which is done solely because of a new legal obligation.
To compute these costs we follow the Better Regulation Guidelines which state that the
effort of assessment should remain proportionate to the scale of the administrative costs
imposed by the legislation and must be determined according to the principle of
proportionate analysis.
To calculate the administrative cost we use the Standard Cost Model. The main objective
of the model is to assess the cost of information obligations imposed by EU legislation.
The following Table presents the steps that will need to be followed to measure energy
poverty.
112
Administrative costs are defined as the costs incurred by enterprises, the voluntary sector, public
authorities and citizens in meeting legal obligations to provide information on their action or
production, either to public authorities or to private parties.
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Table 15: Steps to measuring energy poverty
Activity
Identification of
information
obligations
Measuring energy poverty making reference to household income and household
energy expenditure.
Data requirements: household income and household energy expenditure. Source:
Household Budget Survey and/or Survey of Income and Living Conditions.
Identification of
required actions
Familiarising with the information obligation: senior managers will need to assess the
information needed and allocate tasks within the Civil Service to measure energy
poverty.
Training employees about the information obligation: civil servants will need training
on the necessary data to measure energy poverty. The amount of training necessary is
likely to be limited since the information needed (i.e. household income and
household energy expenditure) is already collected by Member States.
Retrieving relevant information from existing data: civil servants will need to retrieve
household income and household energy expenditure data either from the Household
Budget Survey and/or Survey on Income and Living Condition.
Producing new data: civil servants will need to use household income and household
energy expenditure to produce an indicator of energy poverty. For those Member
States with no official metric to measure energy poverty, it is likely that the Civil
Service will produce different metrics and recommend one for adoption. The work
required to produce the most common indicators of energy poverty is not particularly
burdensome113
.
Holding meetings: senior civil servants will hold several meetings to decide which
metric should be used to measure energy poverty. Ultimately a decision will need to
be made at the Government level before the metric is reported to the European
Commission.
Inspecting and checking: civil servants will need to perform quality control activities
on the data to ensure the robustness of the results.
Submitting the information: civil servants will need to submit the information to the
European Commission. It is likely that in some cases civil servants may need to
allocate additional time for discussion with European Commission officials for
clarification.
Identification of
target group
Public Authorities
Identification of
frequency of
required actions
Once a year
Identification of
relevant cost
parameters
No particular relevant cost such as external costs (e.g. using consultancies or gathering
new data) has been identified.
Assessment of
the number of
entities concerned
28 Member States
The administrative impact will decrease after the first year since Member States will be
familiar with the new obligation and have agreed on the internal procedures to measure
113
"Selecting Indicators to Measure Energy Poverty". (2016). Trinomics.
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energy poverty. Hence, we have computed the administrative impact for year 1 and the
administrative impact for the subsequent years separately.
An estimation of the time and frequency of the tasks was gathered from information
provided by Member States.
France, the UK and Ireland already measure energy poverty. Hence, this obligation will
not constitute an additional cost for these Member States.
To quantify the administrative impact we used the Standard Cost Model. The model does
not include information for Croatia. The cost of measuring energy poverty in Croatia was
calculated using information on labour cost from Slovenia. Even though this is not ideal,
we prefer this approach to avoid any under-estimation of the cost of the obligation. At the
EU level, the relative small size of Croatia means that the EU wide cost will not be
significantly affected by this assumption. The final cost is shown in the Table below.
Table 16: Cost of measuring energy poverty making reference to household income
and household energy expenditure (EUR)
First year Following years
Standard Cost Model EUR 454,129 EUR 255,277
Estimated cost in France, UK,
Ireland
(-EUR57,137) (-EUR32,444)
Estimated cost in Croatia EUR 10383 EUR 5788
Final cost EUR 407,375 EUR 228,621
Source: European Commission's calculation
For completeness, we include the results of the Standard Cost Model in the tables below.
These results include the cost of measuring energy poverty in all Member States but
Croatia.
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Addressing energy poverty
Table 17: Administrative costs of measuring energy poverty in year 1
Obligation Action Target
Group
Staff type Hourly
rate
Man
hours
Activity cost
(EUR)
Measuring energy
poverty
Familiarizing with the information obligation 28 MS Legislators, senior officials and
managers
41.5 65 75,530
Training employees about the information
obligations
28 MS Professionals 32.1 33 29,660
Retrieving relevant information from existing data 28 MS Professionals 32.1 50 44,491
Adjusting existing data 28 MS Professionals 32.1 25 22,470
Producing new data 28 MS Professionals 32.1 143 128,079
Holding meetings 28 MS Legislators, senior officials and
managers
41.5 52 60,424
Inspecting and checking 28 MS Professionals 32.1 31 27,638
Copying 28 MS Professionals 32.1 50 44,940
Submitting the information 28 MS Professionals 32.1 23 20,897
Total 454,129
Source: European Commission's calculation
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Table 18: Administrative costs of measuring energy poverty in following years
Obligation Action Target
Group
Staff type Hourly
rate
Man
hours
Activity cost
(EUR)
Measuring energy
poverty
Familiarizing with the information obligation 28 MS Legislators, senior officials and
managers
41.5 27 31,374
Training employees about the information
obligations
28 MS Professionals 32.1 29 26,065
Retrieving relevant information from existing data 28 MS Professionals 32.1 33 29,660
Adjusting existing data 28 MS Professionals 32.1 12.5 11,235
Producing new data 28 MS Professionals 32.1 45 40,446
Holding meetings 28 MS Legislators, senior officials and
managers
41.5 26 30,212
Inspecting and checking 28 MS Professionals 32.1 33 29,660
Copying 28 MS Professionals 32.1 45 40,446
Submitting the information 28 MS Professionals 32.1 18 16,178
Total 255,277
Source: European Commission's calculation
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Addressing energy poverty
Option 2 – calculating the costs
The cost of Member States measuring energy poverty using required energy
The UK measures energy poverty using required energy rather than actual expenditure.
Social and physical surveys are carried out in each constituent country to gather all the
necessary information to estimate and monitor energy poverty.
The European Commission requested the assistance of the Scottish Government to gather
the necessary information to understand the activities and estimate the costs of measuring
energy poverty using required energy. The estimated cost for using this approach at the
EU level is based on the cost of an analogous exercise to measure energy poverty in
Scotland.
The main tool to gather all the data to estimate the level of energy poverty in Scotland is
the Scottish House Condition Survey114
(SHCS). The objective of the survey is much
broader than measuring energy poverty. The survey includes a range of additional topics,
as well as information on several characteristics of the household. Each year a Technical
Report115
is published to summarise the survey methodology and delivery of the survey
work.
The SHCS includes a sample of more than 3,000 paired households and dwellings. The
Table below breaks down the different components of the SHCS. Member States already
undertake social surveys116
, making the physical survey the main additional cost of this
measure.
Table 19: SHCS – cost structure
SHCS – Activities Description of activities SHCS – Share
of total cost
Survey management Project management, recruitment, briefing and training, etc. 15%
Fieldwork costs
- Social surveys
- Physical survey
45 minutes social interview and 60 minutes physical survey,
and work to secure interviews. 24%
33%
Processes and final
output
Data processing, sampling, selection, questionnaire
development, validation, clean datasets, and survey reports.
24%
Estimating energy
poverty
Energy poverty modelling using information collected in the
surveys
4%
Source: European Commission's calculation
The methodology to calculate cost of gathering data to measure energy poverty using
required energy at EU level is as follows:
114
The Scottish House Condition Survey run as a standalone survey every 5 years, in 1991, 1996, and
2002. In 2004 it became an annual survey, running separately until 2011. From 2012, the SHCS was
merged with the Scottish Household Survey.
115
"Scottish Household Survey Technical Report". Available at:
http://www.gov.scot/Topics/Statistics/SHCS/2009techrep
116
For instance, physical surveys can be run as a sub-sample of larger surveys such as the Household
Budget Survey which will significantly reduce the costs.
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Addressing energy poverty
1. Calculate the cost per interview.
2. Adjust cost per interview by Member States labour costs.
3. Multiply cost per interview in each Member States by the number of effective
interviews necessary to get a representative sample in each Member States.
Based on the information provided by the Scottish Government, we estimate the cost of
the SHCS per interview to be around EUR 268. This cost includes the activities
described in the Table above: survey management; fieldwork cost (physical survey);
processes and final output; and estimating energy poverty.
A significant component of that cost relates to labour costs. Thus, we adjust the cost per
interview by the different labour costs across the EU using information on wages
provided in the Standard Cost Model. As previously mentioned, the model does not
contain labour costs for Croatia. As before, we approximate Croatian labour costs using
the labour cost in Slovenia.
The total number of households that would need to be interviewed depends on several
statistical considerations. We use the effective sample size of the Household Budget
Surveys117
provided by Eurostat.
117
Eurostat Household Budget Surveys 2010 Achieve Sample Sizes. Quality Report. Source:
http://ec.europa.eu/eurostat/documents/54431/1966394/LC142-
15EN_HBS_2010_Quality_Report_ver2+July+2015.pdf/fc3c8aca-c456-49ed-85e4-757d4342015f
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Addressing energy poverty
Table 20: Cost per dwelling adjusted by Member States labour costs
Member State Adjustment factor
(MS' labour cost /
UK labour cost –
category:
professional)
Cost per
interview (EUR)
Sample size
required
Total cost (EUR)
BE 1.3 346 3,459 1,195,000
BG 0.1 27 1,343 36,000
CZ 0.3 82 3,182 262,000
DK 1.2 320 1,697 544,000
DE 1.1 298 37,606 11,209,000
ET 0.2 62 1,619 100,000
IE 1.1 291 2,562 746,000
EL 0.7 184 1,512 278,000
ES 0.7 193 8,743 1,688,000
FR 1.0 274 5,114 1,404,000
IT 1.0 272 8,884 2,420,000
CY 0.8 219 1,910 419,000
LV 0.2 44 1,653 73,000
LT 0.2 44 1,242 55,000
LU 1.3 356 3,068 1,092,000
HU 0.2 60 4,175 250,000
MT 0.4 116 3,157 366,000
NL 0.9 249 1,461 364,000
AT 1.0 269 2,962 796,000
PL 0.3 91 4,022 367,000
PO 0.6 156 30,228 4,708,000
RO 0.2 45 6,328 288,000
SL 0.5 138 2,658 366,000
SK 0.3 69 2,076 143,000
FI 0.9 253 2,532 640,000
SE 1.0 258 2,157 556,000
HR 0.5 138 2,464 340,000
Total Cost 30,704,000
Source: European Commission's calculation
As the housing stock changes slowly, a physical survey of the housing stock does not
need to be carried out annually. The survey can be run every two years and produce
accurate results118
. Hence, we estimate that the total annual cost of measuring energy
poverty using required energy to be approximately EUR 15.35 million.
The annual cost may increase for those Member States that have to start procurement
processes to gather this data. It is likely, however, that the cost of measuring energy
poverty using required energy is over-estimated. This is because the SHCS gathers more
information than what is explicitly required to measure energy poverty.
The cost of disconnection safeguards – 40 working days minimum notification period
The cost of a minimum notification period can be assessed as the amount of the unpaid
energy bills during the period in which disconnection is not possible. This could be either
118
Based on interview with Scottish Survey manager.
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a cost, in case the consumer never pays back the bills, or a delayed income, in case the
measure is successfully implemented and the non-paying consumer only delays in paying
the bill.
The direct monetary benefit comes in the form of avoided disconnection and
reconnection costs to society. To calculate the average amount of time spent on
disconnection and reconnection, the cost of disconnection and reconnection was divided
by the hourly wage of a technical staff using data from the Standard Cost Model. The
average time was equal to 2.4 hours. To calculate the potential savings to society, we
assume that the notification reduces the number of disconnections by 10%. We consider
10% to be a conservative assumption. The examples of UK and Belgium show that long
pre-disconnection periods contribute, among other factors, to low disconnection
numbers. In addition, in many cases disconnections are solved within few days.
Notifications are sent to all consumers, many of them, are not necessarily vulnerable or
in low-income but have simply forgotten to pay their energy bills.
After the notification, households will be disconnected and acquire a debt with their
energy supplier. In many cases, those households will be reconnected again and the debt
will be repaid either by the households or the Government. In other cases, a household
can be declared in bankruptcy and never repay the debt. For those cases, the unpaid bill
during the notification period will be a cost for the supplier. To calculate this cost, we
assume119
a high cost scenario where 30% of households will never repay their debts and
a central cost scenario for which 10% households will never repay their debt.
There are no statistics available with the number of households permanently without
electricity or gas as a result of non-payment. Anecdotal evidence, gathered through
discussions with national regulators, indicate that this number may be small. Given that
the majority of European households connected to the electricity or gas grid do receive
energy services, it is possible that before or after a household is being disconnected,
some kind of process starts by which the affected household or the public sector repay
the debt or it is condoned by the supplier.
This is highly likely in Member States with strong social security systems such those
who may have to extend their notification like Austria, Germany, Denmark, France, or
Sweden and Member States such as Ireland and Poland where pre-payment meters are
offered to households as a last resort measures to provide energy and slowly repay the
debt. For these Member States, extending the notification period may not result in any
added cost. However, to avoid any under-estimation of the cost we have added all the
Member States with notification periods lower than 40 days.
The steps taken to calculate the total net costs are the following:
- Calculate the cost of connection and disconnection in each Member State
impacted by this measure.
119
The assumed number of households unable to repay the debt was checked against regulators'
experiences.
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Addressing energy poverty
- Estimate the savings of a longer notification period which equals to the avoided
cost of connection and reconnection.
- Calculate the average household energy expenditure for 40 working days in each
Member State impacted by this measure.
- Estimate the cost of the measure assuming that 10% (central cost scenario) and
30% (high cost scenario) of households will never repay their debt.
- Calculate the net cost of the policy.
The net cost of unpaid bills for these two scenarios for those Member States with a
notification period lower than 40 working days is presented in Table 21.
Table 21: Estimated cost of extending notification period
Member State Central Cost (10%) in EUR High Cost (30%) in EUR
AT 148,160 1,027,465
BG* 184,081 624,502
CY 236,164 942,264
CZ* 405,482 1,587,838
DE 627,268 9,340,006
DK 219,079 1,216,659
EE* -5,018 96,725
FR 1,617,788 6,439,202
IE 35,596 222,339
IT -570,068 18,342,145
LT 6,046 24,428
LU* 3,194 24,311
MT 11,103 47,098
PL 945,689 4,131,371
PT 2,328,274 9,210,831
SE* 156,570 778,667
SI* 204,133 708,164
SK 109,395 484,050
Total Annual Cost 6,662,934 55,248,063
Note: * indicates Member States without available data on disconnections. For these Member States
disconnections was proxy by the average number of disconnections.
Source: European Commission's calculation
Estonia and Italy enjoy a net benefit from extending the notification period i.e. expressed
as a negative cost. In these Member States, the savings from avoiding the cost of
connection and reconnection during the notification period is higher than the total debt in
the central cost scenario where 10% of households do not repay their debt.
The results in Table 21 are nonetheless sensitive to the assumptions used with regard to
the number of disconnections avoided and the number of households who will never
repay their debt. For instance, if we assume that just 5% of households do not repay their
debt, extending the notification period results in an EU net benefit of more than EUR 5
million.
It is also important to note that publically available data on disconnection rates across all
Member States is incomplete, despite Member States’ obligation to report such data to
National Regulatory Authorities. For the purpose of the present analysis, the average
number of disconnection was applied to proxy for potential disconnection in those
Member States without available data. This assumption may not be adequate for Member
States such as Luxembourg or Sweden which may have a significantly lower number of
disconnections than the average.
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Addressing energy poverty
Overall, it is likely that the conservative assumption used in the calculation of the costs
led to conservative estimates of the cost which may over-estimate the impact of the
measures.
In addition to the above it is important to note that Member States with robust social
security schemes are unlikely to face any additional costs as a result of the extension of
the disconnection notice period as rapid intervention of social security services typically
helps households in those Member States to avoid disconnections.
The cost of disconnection safeguards - prior to disconnection notice, consumers should
receive: (i) information on the sources of support and (ii) be offered the possibility to
delay payments or restructure their debt.
To calculate the cost of these measures, we collected information on the cost of similar
schemes currently operating in Member States and estimate the cost of replicating these
schemes in the Member States where debt management or customer engagement
activities do not exist.
The steps taken to calculate the total costs are the following:
- Gather information on case studies and calculate the cost per household for debt
management and customer engagement.
- Calculate the cost per household in each Member States taking account of
different labour costs using information from the Standard Cost Model.
- Multiply the cost per household by the number of households in arrears (high cost
scenario) and the number of disconnections (central cost scenario)
Similarly to the cost of extending notification period, it is likely that in some Member
States, particularly those with strong social security system, households may never need
debt management advice or information on the sources of support.
It might well be that even though Member States such as Denmark, Finland, or the
Netherlands do not have official debt management advice or customer engagement
activities120
, households in these Member States do receive support prior to disconnection
or when facing difficulties to pay their energy bills. That will make these measures
superfluous. In those cases, Member States will not face any additional cost. However, to
avoid any under-estimation of the costs, the impact assessment includes all the Member
States without these services121
.
Using the number of households in arrears as a proxy for the number of disconnections
may also over-estimate the costs. First of all, not all households in arrears may be in a
position to require support. Arrears may well be for other reasons than financial
constraints or difficulties to make ends meet. Secondly, in some Member States,
households in arrears may receive support from local authorities or social services which
will erase the need for these measures and thus the cost.
120
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E
121
"Measures to protect vulnerable consumers in the energy sector: an assessment of disconnection
safeguards, social tariffs and financial transfers". Forthcoming publication. Insight_E
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As a result of these assumptions, we believe the costs presented here are conservative.
The cost of debt management
Step Change is a UK based charity which helps people overcome their debt
difficulties122
. In 2014, the charity served more than 300,000 people at an operating cost
of around GBP 140 per beneficiary which equates to around EUR 172123
. A similar
scheme operates in Germany at the local level124
. The cost of the Germany scheme was
on average EUR 167 per households. The estimations are based on the cost from the UK
based programme since it is run nationally. Nonetheless, the UK and German program
have similar cost per households.
Assuming the same efficiency in other Member States but different labour costs, the cost
of replicating Step Change activities in other Member States is shown in Table 22. The
same Table also shows the cost of extending the services to all households in arrears with
utility bills (as potential households in need of assistance with managing utility bills –
high cost scenario) and the cost of providing the service to those households who are
actually disconnected125
– central cost scenario.
When estimating the costs of debt management it is important to note that debt
management assistance have positive long-term impacts on households. This means that
a substantial share of households benefiting from debt management assistance can be
expected to manage their payments more effectively after the initial intervention. Thus,
the annual cost of this intervention can be expected to decrease annually reflecting the
success rate of the measure.
For instance, from the more of 1,200 households receiving support in Germany, 90% of
the beneficiaries felt their future energy needs would be secured and therefore were not
in need to reapply to receive assistance. In addition 80% of the disconnection threats
were averted which generates savings in the form of avoided disconnection and
reconnection costs.
The 90% success rate in the German example may not be easy to replicate in other
Member States. As a conservative assumption we assume a success rate of 25%. Hence,
the annual cost of the measure will decrease by 25% year-on-year.
It is also important to note that this type of services, despite being of a considerable cost
per customer provide an added-value to the energy suppliers. For example, Step Change
is partly funded by the energy suppliers as they enjoy the benefits of having an
122
Step Change: http://www.stepchange.org/
123
2014 average exchange rate of GBP 0.806 for one euro.
124
Information on the scheme can be found at:
https://www.verbraucherzentrale.nrw/mediabig/238730A.pd and
https://www.verbraucherzentrale.nrw/mediabig/237456A.pdf
125
Information on the total number of disconnections was not available for all Member States. For those
Member States for which this information was not available, we applied the average disconnection
rate.
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Addressing energy poverty
intermediary that provides support to customer on arrears or in risk of disconnection for
non-payment.
The cost of customer engagement
Irish suppliers have established an Energy Engage Code which provides guidelines on
the approach suppliers should take with customers in arrears and those with possible
disconnection. According to the Code, suppliers should communicate with customers
having difficulties in paying their bills and advise them on possible debt management
plans. The cost of this option involves communication costs including letter, phone calls
and SMS messages. Information on the estimated cost of customer engagement provided
by one of the main Irish suppliers is presented below:
- Written communication: EUR 1.5
- Phone calls: EUR 5
- Mobile Text: 8 euro cents
It is likely that this measure may have positive long-term impacts reducing the number of
beneficiaries and the cost of the scheme. However, we did not find any evidence of the
possible success rate. To avoid any under-estimation of the cost we assume the number
of beneficiaries remains constant over time.
This amounts to an estimated cost of customer engagement of around EUR 6.6 per
customer. The same approach as per debt management was used to calculate the cost of
extending similar schemes to other Member States. We first adjust the cost of customer
engagement per customer for each Member State using Eurostat Purchasing Power Parity
Index. The cost per customer was multiplied by the total number of households in arrears
– high cost scenario and total number of disconnections – central cost scenario.
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Addressing energy poverty
Table 22: Cost of debt management and customer engagement
Member State
Estimated cost of debt
management (EUR) Member State
Estimated cost of customer
engagement (EUR)
Central Cost High cost Central Cost High Cost
BG 114,408 6,770,270 BG 21,056 1,245,997
DK 7,665,949 73,559,897 CY 121,107 97,921
EE 65,607 3,882,393 CZ 9,217 545,417
FI 708,564 41,930,412 EE 7,045 416,885
HR 1,016,791 22,934,923 FI 25,786 1,525,929
LT 95,899 5,634,449 GR 900,327 4,138,621
LV 22,088 1,266,903 HR 52,140 1,176,085
PT 33,574,204 91,806,810 HU 410,753 1,139,442
RO 293,008 17,339,207 LT 11,309 664,469
SK 121,024 7,161,768 LV 3,129 179,479
MT 12,187 100,663
NL 9,876,748
SI 116,888 164,857
Total Annual Cost 43,677,542 272,287,031 Total Annual Cost 1,690,944 21,272,514
Note: the number of reported disconnections in the Netherlands was nil. CEER database
Source: European Commission's calculation
The cost of disconnection safeguards - winter moratorium of disconnections for
vulnerable consumers.
A winter disconnection moratorium for vulnerable consumers may result in a cost for the
energy supplier, consumers or the government, depending on how the measure is
financed. The cost of this measure can be estimated as the cost of the unpaid energy bill
from non-paying vulnerable consumers during winter. However, the debt per each non-
paying household might be recovered at a certain point, therefore not resulting in a cost.
The cost per non-paying household of a possible winter disconnection is reported in
Table 23. This was calculated assuming that a household does not pay the energy costs
for the full winter, assumed to be four months long which is equal to the average
legislated winter length in countries that have disconnection safeguards for the winter.
This was calculated using the average energy expenditures for the lowest income
quintile.
We also assume that a percentage of vulnerable consumers will not repay their energy
bill due to the moratorium. A high and a central cost scenario are presented in the table
below. The scenarios assume that 30% (high cost) and 10% (central cost) of the
vulnerable households will not repay their energy bills during winter. It can be argued, as
it was done previously for the other disconnection safeguards, that these assumptions are
likely to over-estimate the cost.
It might be that some Member States such as Austria, Germany or Luxembourg have
sufficient tools in place to protect vulnerable households from being disconnected
making a moratorium unnecessary. For those Member States, the costs of the moratorium
will not be realised. However, as in the other Sections of the impact assessment, we have
included all Member States without a winter moratorium for vulnerable consumers.
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Addressing energy poverty
As previously discussed, anecdotal evidence suggests that the number of households
permanently cut-off from electricity and gas services because of non-payment may be
significantly lower.
The number of vulnerable consumers was not available for some of the impacted
Member States. In these cases, referred in the table below with an asterisk, the number of
vulnerable consumers the number of households unable to keep their homes adequately
warm was used as a proxy. This is likely to over-estimate the number of vulnerable
households, particularly in those Member States with an explicit definition of consumer
vulnerability in energy markets. Further information on the definition of consumer
vulnerability in energy markets can be found in the evaluation.
It needs to be added that the inability of a vulnerable household to pay its energy bill may
also be linked to the type of tariff. It might well be that vulnerable households are not in
the most advantageous tariff. In those cases, switching to a more competitive offer
reduces energy costs and may avoid disconnection. These interactions were not taken
into account in this impact assessment. However, it can be assumed that the preventative
measures undertaken prior to disconnection such as customer engagement and debt
management may assist vulnerable consumers to reduce their energy cost by switching to
a more economic tariff.
Finally, there might be scope for reducing the costs of winter moratorium of
disconnections if it is designed taking into account Member States national social
services. However, as social policy is a primary competence of Member States, an EU
winter moratorium on disconnections may go beyond the limits of subsidiarity (see
Section 7.1.6 Subsidiarity).
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Addressing energy poverty
Table 23: Cost of winter moratorium for vulnerable consumers
Mem
ber
state
Vulnerabl
e
consumers
Electricity Gas
Central cost case
(10% disconnect
and never pays
back) in EUR
High cost case
(30% disconnect
and never pays
back) in EUR
Central cost case
(10% disconnect
and never pays
back) in EUR
High cost case
(30% disconnect
and never pays
back) in EUR
AT* 118,357 2,092,547 6,277,640 733,812 2,201,435
BG* 1,048,035 9,643,610 28,930,829 229,965 689,895
CZ* 267,191 4,559,591 13,678,772 2,807,494 8,422,483
DE* 1,978,803 33,507,728 100,523,184 15,962,343 47,887,029
LU* 1,374 26,642 79,926 20,210 60,630
LV* 215,001 1,743,136 5,229,408 607,682 1,823,046
MT 24,416 242,927 728,782 36,852 110,557
PT 61,129 941,387 2,824,160 707,059 2,121,176
SK* 117,990 1,172,983 3,518,950 1,333,957 4,001,872
Total Annual Cost 53,930,551 161,791,651 22,439,374 67,318,123
Note: Vulnerable consumers for AT, BG, CZ, DE, LU, LV and SK set as the number of households feeling
unable to keep warm during winter. It was not possible to calculate the cost for Croatia due to lack of data
on household energy expenditure
Source: European Commission's calculation
Summary Table
The annual cost and the total net present cost for the period 2020 and 2030 of the policy
options presented in the impact assessment are summarised in the Table below.
Table 24: Total Cost
Annual cost in EUR Net present cost for the period
2020 – 2030 in EUR
BAU: sharing of good practices. 0 0
Option 0+: sharing of good
practices and increasing the
efforts to correctly implement the
legislation.
100,000 911,090
Policy Option 1: Setting an EU framework to monitor energy poverty
Central cost scenario 407,375 (first year)
228,621 (following years)
2,261,696
Policy Option 2: Setting a uniform EU framework to monitor energy poverty, preventative measures
to avoid disconnections and disconnection winter moratorium for vulnerable consumers.
Central cost scenario 159,105,345 1,194,481,728
High cost scenario 587,348,869 3,820,183,393
Source: European Commission's calculation
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Addressing energy poverty
Quantifying the Benefits
In this Section we describe the benefits derived from implementing the policies.
Overall benefits
Tackling energy poverty can have positive effects on individual's health and well-being,
savings for the health sector, as well as provide economy-wide gains on productivity
levels. Although it is difficult to quantify the specific impact of the policies presented in
this impact assessment towards these overall benefits, it is likely that applying these
policies will contribute to reap these benefits.
For instance, it is likely that on individual's health, there have been various studies
linking cold homes with respiratory illnesses and excessive winter mortality. The World
Health Organisation estimated that 30% of Excess Winter Deaths (EWD) can be directly
related to cold homes126
. The 2009 Annual Report of the Chief Medical Officers127
estimated that for every £1 spent on ensuring homes are kept warm, the public health
sector saves £0.42.
A recent study concluded that home environment is key to ensure citizens are healthy and
productive128
. Remaining connected to an energy supply better enables households to
maintain healthy homes in terms of indoor temperature and humidity levels. Lack of
energy supply has been linked to an increase of respiratory illnesses, circulatory diseases,
mental health and allergies, which, left unchecked, lead to absence from work and loss of
productivity estimated to total 9.8 billion EURO annually in Europe129130131
. Policies
proposes in the revision of the EED and the EPBD which contribute to better energy
efficiency in the domestic sector will also contribute to realise benefits of better health
and productivity.
The UK Healthy Homes Barometer 2016 estimates that minor illnesses, such as coughs,
colds, flus and illnesses can be attributed to 27 million lost working days, which affect
morale and productivity. The direct cost to the economy in the UK due to these absences
is estimated at £1.8 billion in 2013.
Ensuring energy provision can also have a positive impact on educational attainment,
lower missed school days and life chances for children132
.
126
"Indoor cold and mortality. In Environmental Burden of Disease Associated with Inadequate
Housing", (Bonn: World Health Organisation (Regional office for Europe)). (2011). Rudge, J.
127
2009 Annual Report of the Chief Medical Officer (London: Department of Health). 2010. Donaldson,
L.
128
"Healthy Homes Barometer". (2016). Wegener and Fedkenheuer,
129
"Towards an identification of European indoor environments’ impact on health and performance -
homes and schools". (2014). Grün & Urlaub,
130
"The Health Impacts of Cold Homes and Fuel Poverty" (London: Friends of the Earth). (2011).
Marmot Review Team.
131
"Estimating the health impacts of Northern Ireland’s Warm Homes Scheme" 2000-2008. (2008).
Liddell.
132
Evaluating the co-benefits of low-income energy-efficiency programmes. 2013. Heffner & Campbell.
391
Addressing energy poverty
Identifying energy poverty will also assist Member States in assessing the level of energy
poverty. Such identification will support Member States to better target public policies to
those households in need of assistance. In addition, disconnection safeguards will further
help Member States to reduce the number of disconnections, benefiting in particular low-
income households who are more likely to face energy poverty. With such measures in
place, Member States may feel more confident to phase out regulated prices.
The removal of regulated prices which will bring efficiency improvements, resulting on:
- more competition in the energy markets with positive impacts on consumer and
innovation;
- the removal of market distortions which alter the allocation of resources.
- additional citizen's satisfaction due to the positive impacts of competition on
innovation in the form of enhanced service provision and quality;
- a positive impact on the internal energy market. Companies wishing to engage in
cross-border trade will not be discouraged by regulated prices, which prevent
competition when set below cost,; and
- improved public finances since regulated prices are an ineffective measure of
protection as they are applied to all households, including those who can afford to
pay a higher price. Phasing out regulated prices will unlock resources which can
be used for targeted protection.
Better information on the level of energy poverty and measures to reduce the number of
disconnections will have a positive impact on consumer protection and the health and
well-being of European citizens. Art. 38 of the Charter of Fundamental Rights of the EU
requires EU policies to ensure a high level of consumer protection. The Treaty
establishes that 'consumer protection requirements shall be taken into account in defining
and implementing other Union policies and activities' (TFEU, art. 12), and that '… the
Union shall contribute to protecting the health, safety and economic interests of
consumers, as well as to promoting their right to information, education and to organise
themselves in order to safeguard their interests.' (TFEU, Art. 169)
Policy Option 1 – assessing the benefits
The benefits of a generic description of the term energy poverty in the legislation
Three main benefits have been identified as a result of a shared understanding of energy
poverty across the EU: recognition, clarification and policy synergy133
.
In terms of recognition, an EU description of energy poverty may help Member States to
identify the problem. This is relevant as the majority of Member States have not defined
the phenomenon of energy poverty despite the evidence which suggest that household
across Europe are struggling to access adequate energy services134
,
As for clarification, a major regulatory impediment to addressing energy poverty is the
unclear understanding of the term. This is particularly relevant as in many cases the term
133
"Fuel poverty in the European Union: a concept in need of definition?" 2016. Thomson et al.
134
"Quantifying the prevalence of fuel poverty across the European Union". (2013). Thomson and Snell.
392
Addressing energy poverty
energy poverty is mixed or used interchangeably with the broader term of consumer
vulnerability or general poverty135
. Adopting a generic description of energy poverty
would help to resolve the terminological confusion that presently exists, and may pave
the way for more detailed national definitions. Above all a generic common
understanding of energy poverty in the EU, which focuses on the drivers of energy
poverty, is a necessary prerequisite towards achieving reliable and comparable data on
the current and future evolution of the nature and scale of the issue.
In terms of policy synergy, there is potential for achieving synergies at the EU and
Member State level. Having a shared concept could also assist Member State cooperation
and knowledge exchange in this area.
The benefits of measuring energy poverty by referring to household income and
household energy expenditure
Measuring energy poverty will assist Member States to assess whether energy poverty is
getting better or worse over time. It will also help Member States to identify the people
affected so that they can be targeted by appropriate interventions. Hence, measuring
energy poverty will help policy makers to assess the impact of their policies136
.
In summary, measuring energy poverty will enable Member States to:
- measure the level of energy poverty at a particular moment of time
- identify trends and changes on the levels of energy poverty,
- understand the extent, depth and persistence of the problem,
- identify the kinds of people affected; and
- support policy design and delivery to tackle the problem
These offer the necessary clarity to the term energy poverty, as well as, the transparency
with regards to the number of household in energy poverty while respecting the
principles of subsidiarity.
Option 2– assessing the benefits
The benefits of a specific EU definition of energy poverty
A specific, harmonised EU definition of energy poverty such as the one explained
previously will bring benefits similar to those associated with a general definition of
energy poverty. In addition, being a more specific definition, we expect the benefits in
relation to clarification to be higher.
However, here it is important to remember the risks that a specific definition of energy
poverty at the EU level may bring in terms of currently limited comparable evidence,
comparability and relevance, and path dependency137
.
135
"Working Paper on Energy Poverty".(2016). Vulnerable Consumer Working Group.
136
Fuel Poverty: The problem and its measurement. (2001). John Hills. Available at:
http://sticerd.lse.ac.uk/dps/case/cr/CASEreport69.pdf
137
"Fuel poverty in the European Union: a concept in need of definition? " (2016). Thomson et al.
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Addressing energy poverty
As discussed before, a specific EU definition of energy poverty may be in conflict with
the diversity of contexts at the Member States in terms of climate conditions,
socioeconomic factors or energy markets. If the definition were to be inadequate for a
Member State, it would take considerable amount of time to change the EU legislation
and amend this situation.
The benefits of Member to measure energy poverty using required energy
Measuring an adequate level of energy services is the main advantage of using required
rather than actual expenditure. This is the approach taken in the UK and it is regarded as
most appropriate by several experts138
. It requires, nonetheless, agreeing on what is
adequate. In some cases, the term adequate refers to a specific heating regime139
.
Having defined what is adequate, the required energy approach calculates the amount of
energy needed to meet that heating regime. Energy poverty is later computed comparing
the required energy expenditure against household income. Hence, required energy
expenditure solves the main weakness of the actual expenditure approach. When using
actual expenditure, we are not able to distinguish between those households that do not
consume sufficient energy because of financial constraints from those that do not need
much energy to meet their energy needs because they live in a high energy efficient
dwelling.
The benefits of disconnection safeguards - minimum notification period
Longer disconnection periods will provide customers with additional time to engage with
suppliers and/or seek help. There is a direct monetary benefit in the form of avoided
disconnections and reconnection costs. In addition to these benefits, any avoided
disconnection stemming from this measure will bring benefits such as health
improvements and cross-department savings in social and health budgets, and
improvements in equality.
Suppliers will also benefit from lower disconnection rates as they will retain such
customers, thereby avoiding lost income, allowing the customer to pay back arrears, and
avoiding some of the costs related to new customer acquisition.
The benefits of disconnection safeguards - prior to disconnection notice, consumers
should receive: (i) information on the sources of support and (ii) be offered the
possibility to delay payments or restructure their debt.
Providing additional information to consumers and the possibility to delay payments or
restructure their debt may result in a number of disconnections being averted. Hence, the
benefits are similar as in the case of extended notification period In addition, households
will be better informed, and can improve their energy management and potentially avoid
future debt. As described in the case of minimum notification period, suppliers will also
138
"Selecting Indicators to Measure Energy Poverty". (2016). Trinomics.
139
For instance in the case of Scotland, the current definition of fuel poverty makes reference to a heating
regime for standard occupants between 21°C and 18°C for 9 hours during weekdays and 16 hours else
and for any occupant aged 60 or more or long-term sick and disabled between 23°C and 18°C 16 hours
per day. Source: http://www.gov.scot/resource/0039/00398798.pdf
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Addressing energy poverty
benefit from lower disconnections. Investment in consumer engagement and debt
management services will support a number of jobs in services such as debt counselling.
The benefits of winter moratorium of disconnections for vulnerable consumers.
Similar to the other measures which reduce disconnections, a winter moratorium will
bring benefits in the form of health benefits to vulnerable consumers, cross-departmental
savings in social and health budgets, and avoided disconnection and reconnection costs.
Sensitivity analysis
This impact assessment suffers from important shortcomings to quantify the benefits.
The policy options bring multiple benefits in terms of better public policy with regard to
energy poverty, improvements in individuals' well-being and public sector saving from
fewer disconnections. However, we were not able to quantify the value of these benefits
from market prices.
Sensitivity analysis allows us to calculate the amount of benefits that would be necessary
to justify the costs from these policies.
One of the key benefits of the options presented stem from improvements in individual
health which can be particularly effective at addressing Excess Winter Deaths (EWD).
EWD refers to deaths which would not have occurred if dwellings had been properly
heated. The cost to society of EWD can be estimated as forgone GDP i.e. each excess
winter death translates in forgone monetary value approximated by GDP per capita. This
is a rather crude measure with some disadvantages (e.g. different values for different
countries) but it can be interpreted as an estimation of the loss to society.
To perform the sensitivity analysis, the following steps are taken:
- Aggregate the cost of policy Option 1 and 2 for the high and central cost scenario.
- Multiply the number of EWD140
by the GDP per capital141
- Calculate the reduction in EWD that equals the cost of the policies.
The results of the calculation are presented below.
Table 25: Sensitivity analysis
Benefits from reduction in Excess
Winter Deaths equal to the cost of the
policies
Policy Option 1: Setting an EU framework to monitor energy
poverty
Policy Option 1 – first year 0.004%
Policy Option 1 – following years 0.002%
Policy Option 2: Setting an EU uniform framework to monitor
energy poverty and reduce disconnections for vulnerable
140
The number of EWD is calculated following an approach similar to Johnson and Griffinths (2003).
The number of deaths is equal to the deaths between the months of December and March minus the
average number of deaths for other months. Data source: Eurostat. Mortality Statistics.
141
Eurostat. GDP per capital in euros at current prices.
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Addressing energy poverty
consumers.
Policy Option 2 – central cost scenario 1.5%
Policy Option 2 – high cost scenario 5.6%
Source: European Commission's calculation. Note: Policy Option 1 and 2 include the measures described
in option 0+.
The Table shows that a minimal reduction in EWD is sufficient to justify the cost arising
from policy Option 1. On the other hand, a reduction of 1.5% and 5.6% is necessary for
the cost of policy Option 2 to be equal to possible benefits. The differences between the
low and high cost scenario are explained by the assumptions used to calculate the cost,
and in particular, to the number of households that after being disconnected or because of
the moratorium will never repay their debt.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the
preceding pages, accrue overwhelmingly to energy poor households. Depending on how individual
Member States choose to finance their new obligations to measure energy poverty levels (costs outlined in
detail in Tables 15 to 17), the marginally increased burdens resulting from the implementation of these
measures are socialized amongst other ratepayers or taxpayers. The measures can therefore be considered
progressive in nature i.e. they tend to redistribute surplus from relatively high-income ratepayers/taxpayers
to increase the welfare of lower-income ratepayers
Subsidiarity
7.1.6.
In this Section we assess the options presented in the impact assessment against the
subsidiarity principle as stated in Article 5 of the Treaty of the EU.
The subsidiarity principle is upheld because the objectives of the policy options, which
have been defined to address the shortcoming of the current legislation as identified in
the evaluation, cannot be achieved sufficiently by Member States.
The evaluation of the current provision of the Electricity and Gas Directive defined
energy poverty as a subset of consumer vulnerability. This categorisation leads to a
simplistic expectation that a single set of policy measures from Member States would
automatically address both problems simultaneously. However, evidence suggests that
energy poverty has been rising over the years, despite the protection available for
vulnerable consumers. In this context, Member States have been reluctant to phase out
regulated prices, pointing towards the protection of vulnerable and energy poor
households as one of the main reasons. As a consequence, national regulation has had
negative spill-over effects, weakening the internal energy market.
The measures proposed in Option 1 build upon the existing provisions on energy poverty
in the Electricity and Gas Directive. They offer the necessary clarity to the term energy
poverty, as well as, the transparency with regards to the number of household in energy
poverty. Since currently available data can be used to measure energy poverty, the
administrative costs are limited. Likewise, the actions proposed do not condition Member
States primary competence on social policy, hence, respecting the principle of subsidiary.
In addition, the protection of vulnerable and energy poor consumers has been quoted as
one of the reasons for maintaining regulated prices. This type of intervention, particularly
when prices are regulated below costs, has negative implications on the functioning of
the internal energy market. Article 114 and 194 pf the Treaty pf the Functioning of the
European Union states that in order to achieve the objectives in Article 26, the EU
legislators shall adopt the measures for the approximation of the provisions laid down by
396
Addressing energy poverty
law, regulation or administrative action in Member States which have as their object the
establishment and functioning of the internal market. Article 194 states that the Union
policy shall aim to ensure the functioning of the energy market.
It can be argued that Article 169 on Consumer Protection provides further justification
for action at the EU level. The options described in this IA include disconnection
safeguards either as preventative measures prior to disconnection or as a prohibition of
disconnection for vulnerable consumers.
The options presented in this Annex bring a double dividend: on the one hand they
contribute to the protection of consumers – as explained in the introduction there is a link
between energy poverty and excess winter deaths – and on the other hand, these
measures support the completion of the internal energy market.
It needs to be noted that, as we explained in Option 2, Member States may be better
suited to design schemes to protect households from disconnection in order to ensure that
synergies between national social services and disconnection safeguards are achieved.
In addition, a prohibition on disconnections for vulnerable consumers may restrict the
principle of freedom of contract, in particular for the ten Member States that do not have
such a measure in place. However, action at EU level may be the most effective way to
ensure a common level of protection for vulnerable consumers. Furthermore, in terms of
proportionality, Member States should carefully specify the group of vulnerable
consumers who cannot be disconnected to avoid going beyond what is necessary to
achieve the consumer protection objective.
Stakeholders' Opinions
7.1.7.
The options described in this impact assessment have benefited from the continued
dialogue between the European Commission services and civil society through the
Vulnerable Consumer Working Group (VCWG).
The VCWG was reconvened after the 2015 Citizens' Energy Forum. The group has met
five times since then:
- 3 June 2015
- 21 October 2015
- 9 December 2015
- 26 January 2016
- 24 May 2016
The VCWG meetings are attended by key stakeholders from industry, consumer
associations, academics, regulators and representatives of Member States. A full list of
the members of the group who have attended at least one of the last five meetings is
provided below:
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Addressing energy poverty
Table 26: Members of the Vulnerable Consumer Working Group
Organisation Member State
Ministry of Economics Latvia
Ministry of Economy Poland
Ministry of Employment and the Economy, Energy
Department
Finland
Ministry of National Development Hungary
Bulgarian Permanent Representation to the EU Bulgaria
Hungarian Permanent Representation to the EU Hungary
Czech Permanent Representation to the EU Czech Republic
FPS Economy - DG Energy Belgium
ERO - Energy Regulatory Office of the Czech
Republic
Czech Republic
E-control Austrian Energy Regulator Austria
OFGEM United Kingdom
NEON European Organisation
Citizens advice United Kingdom
Danish Consumer Council Denmark
DECO Portugal
The Swedish Consumer Energy Markets Bureau Sweden
RWADE Belgium
University of Leicester United Kingdom
University of Stuttgart Germany
European Disability Forum European Organisation
Fondazione Consumo Sostenibile Italy
GEODE European Organisation
HISPACOOP Spain
Housing Europe Belgium
International Union of Tenants European Organisation
EURELECTRIC European Organisation
EUROGAS European Organisation
ADEME France
AEEGSI Italy
AISFOR Italy
CEDEC European Organisation
DGEC France
EAPN European organisation
EFIEES European Organisation
ENGIE France
FdSS France
In the meetings of the VCWG142
, the group discussed the topic of energy poverty. These
discussions were captured in the Working Paper on Energy Poverty143
. The group
conclusions were as follows (emphasis added):
- Measuring energy poverty is important to understand the depth of the problem
and also assess the impact of the policies which have been put in place to tackle
142
The minutes, agenda and presentations of the meetings can be found online at:
https://ec.europa.eu/energy/en/events/citizens-energy-forum-london
143
VCWG (2016) Working Paper on Energy Poverty. Available at:
https://ec.europa.eu/energy/sites/ener/files/documents/Working%20Paper%20on%20Energy%20Pover
ty.pdf
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Addressing energy poverty
it. Metrics which account for the relationship between household income and
household energy needs or expenditure capture well the problem of affordability.
- Better information on housing stock, which can be efficiently gathered as part of
the regular Household Budget Survey, will help Member States to measure
energy poverty and design energy efficiency policies which benefit the energy
poor.
- Tackling energy poverty requires a combination of policies, dealing with the
causes and the symptoms of energy poverty. Good examples include targeted
short-term (financial support) and long-term measures (energy efficiency) in
addition to consumer protection and reasonable safeguards against
disconnections.
- A common understanding of the concept of energy poverty will help Member
States, civil society and industry to start a dialogue about the depth of energy
poverty and how to tackle it. The VCWG considers that a common understanding
of energy poverty in the form of a generic definition represents a positive step
forwards to tackle the problem of energy poverty. Such a definition should be
simple, focus on the problem of affordability, and allow sufficient flexibility to be
relevant across Member States. The VCWG proposes that such a definition can
refer to elements such as low-income; inability to afford; and adequate domestic
energy services
The options described in this impact assessment draws from the conclusions of this
paper. In particular, key elements of Option 1 are supported by the VCWG Working
Paper on Energy Poverty.
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Addressing energy poverty
Sub-Annex 1
Table 27: Energy poverty definitions
Member
State
Definition
France
Energy Poverty: A person who encounters in his/her accommodation particular difficulties to
have enough energy supply to satisfy his/her elementary needs, this being due to the
inadequacy of resources or housing conditions.
Ireland
Energy poverty is a situation whereby a household is unable to attain an acceptable level of
energy services (including heating, lighting, etc.) in the home due to an inability to meet
these requirements at an affordable cost.
Cyprus
Energy poverty may relate to the situation of customers who may be in a difficult position
because of their low income as indicated by their tax statements in conjunction with their
professional status, marital status and specific health conditions and therefore, are unable to
respond to the costs for the reasonable needs of the supply of electricity, as these costs
represent a significant proportion of their disposable income.
Slovakia
Energy poverty under the law No. 250/2012 Coll. Of Laws is a status when average monthly
expenditures of household on consumption of electricity, gas, heating and hot water
production represent a substantial share of average monthly income of the household”
England
Energy poverty: A household i) income is below the poverty line (taking into account energy
costs); and ii) their energy costs are higher than is typical for their household type.
Scotland
Fuel poverty: A household, in order to maintain a satisfactory heating regime, it would be
required to spend more than 10% of its income (including Housing Benefit or Income
Support for Mortgage Interest) on all household fuel use.
Wales
Fuel poverty is defined as having to spend more than 10% of income (including housing
benefit) on all household fuel use to maintain a satisfactory heating regime. Where
expenditure on all household fuel exceeds 20% of income, households are defined as being
in severe fuel poverty.
Northern
Ireland
A household is in fuel poverty if, in order to maintain an acceptable level of temperature
throughout the home, the occupants would have to spend more than 10% of their income on
all household fuel use.
Source: Insight_E 2015
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Addressing energy poverty
401
Phasing out regulated prices
7.2. Phasing out regulated prices
402
Phasing out regulated prices
Summary table
7.2.1.
Objective: Removing market distortions by achieving the phase-out of supply price regulation for all customers144
.
Option: 0 Option 1 Option 2a Option 2b
Making use of existing acquis to continue
bilateral consultations and enforcement
actions to restrict price regulation to
proportionate situations justified by general
economic interest, accompanied by EU
guidance on the interpretation of the current
acquis.
Requiring Member States to progressively
phase out price regulation for households by a
deadline specified in new EU legislation,
starting with prices below costs, while allowing
transitional, targeted price regulation for
vulnerable customers (e. g. in the form of social
tariffs).
Requiring Member States to
progressively phase out price
regulation, starting with prices below
costs, for households above a certain
consumption threshold to be defined in
new EU legislation or by Member
States.
Requiring Member States to progressively phase
out below cost price regulation for households by
a deadline specified in new EU legislation.
Pros:
- Allows a case-by-case assessment of the
proportionality of price regulation, taking into
account social and economic particularities in
Member States
Pros:
- Removes the distortive effect of price
regulation after the target date.
- Ensures regulatory predictability and
transparency for supply activities across the
EU.
Pros:
- Limits the distortive effect of price
regulation.
- Would reduce the scope of price
regulation therefore limiting its
distortive impact on the market.
Pros:
- Limits the distortive effect of price regulation
and tackles tariff deficits where existent.
Cons:
- Leads to different national regimes
following case-by-case assessments. This
would maintain a fragmented regulatory
framework across the EU which translates
into administrative costs for entering new
markets.
Cons:
- Difficult to take into account social and
economic particularities in Member States in
setting up a common deadline for price
deregulation.
Cons:
- Difficult to take into account social
and economic particularities in
Member States in defining a common
consumption threshold above which
prices should be deregulated..
Cons:
- Defining cost coverage at EU level is
economically and legally challenging.
- Implementation implies considerable regulatory
and administrative impact.
- Price regulation even if above cost risks holding
back investments in product innovation and
service quality.
Most suitable option(s): Option 1 - Setting an end date for all price intervention would ensure the complete removal of market distortions related to end-user price regulation and help create a
level playing field for supply activities across the EU while allowing targeted protection for vulnerable customers and/or energy poor.
144
For the purpose of this annex of the impact assessment, households or household customers shall include customers in a comparable situation (e. g. SMEs, hospitals etc.)
403
Phasing out regulated prices
Description of the baseline
7.2.2.
A regulated supply price is considered as a price subject to regulation or control by
public authorities (e.g. governments, NRAs), as opposed to being determined exclusively
by supply and demand. This definition includes many different forms of price regulation,
such as setting or approving prices, standardisation of prices or combinations thereof.
The existing acquis only allows price regulation if strict conditions are met.
Regulated prices are unlawful under current Gas and Electricity Directives as interpreted
by the Court of Justice, unless they meet specific conditions. Accordingly, the Court of
Justice has ruled145
that supply prices must be determined solely by supply and demand
as opposed to State intervention as from 1 July 2007. The Court based its interpretation
on the provision146
stating that Member States must ensure that all customers are free to
buy electricity/natural gas from the supplier of their choice as from 1 July 2007 (Article
33 of the Electricity Directive and Article 37 of the Gas Directive interpreted in light of
the very purpose and the general scheme of the directive, which is designed progressively
to achieve a total liberalisation of the market in the context of which, in particular, all
suppliers may freely deliver their products to all consumers).
Article 3(1) of Gas and Electricity Directives requires Member States to ensure, on the
basis of their institutional organisation and with due regard to the principle of
subsidiarity, that natural electricity/gas undertakings are operated in accordance with the
principles of that directive with a view to achieving, inter alia, a competitive market.
However, Gas and Electricity Directives are also designed to ensure that, in the context
of that liberalisation, high standards of public service are maintained and the final
consumer is protected.
In order to meet those latter objectives, Article 3(1) of Gas and Electricity Directives
states that it applies without prejudice to Article 3(2), which expressly permits Member
States to impose public service obligations on undertakings operating in the electricity
and gas sectors, which may in particular concern the price of supply.
In this context the conditions allowing price regulation in the form of public service
obligation imposed on undertakings are to i) be adopted in the general economic interest,
ii) be clearly defined, transparent, non-discriminatory and verifiable, guarantee equality
of access for EU companies to national customers and iii) meet a requirement for
proportionality (which refers in particular to limitation in time and as regards the scope
of beneficiaries).
145
Case C-265/08, Federutility and others v Autorità per l’energia elettrica e il gas
146
The Court judgement was based on Article 23(1)(c) of Directive 2003/55 of the Second Energy
Package which provides that Member States must ensure that all customers are free to buy natural gas
from the supplier of their choice as from 1 July 2007; however a similar provision is contained in the
Second Package Electricity Directive and the relevant provisions has remained unchanged in the Third
Package Directives.
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Phasing out regulated prices
Price regulation for non-households has been systematically challenged via infringements
while price regulation for households has not been yet subject to infringement
procedures. Deregulating household prices may be politically unpopular in Member
States where regulation is justified by social policy objectives and/or lack of competition.
This policy choice has meant addressing through infringements the more important
market distortion created by the regulation of prices for larger and potentially most active
consumers who use most of the energy sold on the European market (more than 70% of
total electricity consumption and close to 60% of the total gas consumption)147
. In
addition, the Commission has opted initially for an informal approach via bilateral
consultations with Member States to discuss reasonable and sustainable alternatives to
price regulation and accompanying support for vulnerable consumers. However,
infringement actions against price regulation for households are not excluded in the
follow-up to informal consultations.
Electricity and gas price regulation refers to the ‘energy’ component of the end-user
price, excluding costs of transport/distribution, taxes, other levies and VAT. This
component is the element which should be determined by market demand and supply in a
fully liberalised energy market. By contrast, the other elements that influence the end-use
electricity price are subject to other regulation and legislation including network
regulation, taxes and levies/support schemes for energy efficiency and renewable energy
sources.
Deficiencies of the current legislation
7.2.3.
Despite the current acquis, some form of price regulation exists in 17 Member States, as
shown in the table below.
This is problematic because evidence presented in Section 5 of the present Annex
demonstrates that regulation of electricity and gas prices limits customer choice, reduces
customer satisfaction and restricts competition. This is particularly true for markets
where supply prices are set below costs (i.e. without taking into consideration wholesale
market prices and other supply costs).
Artificially low regulated prices (even without pushing them below costs) limit market
entry and innovation, prompt customers to disengage from the switching process and
consequently hinder competition in retail markets. In addition, they may increase investor
uncertainty and impact the long-term security of supply.
Furthermore, regulated prices (even when set above costs) can act as a pricing focal point
which competing suppliers are able to cluster around and – at least in markets featuring
strong customer inertia – can also considerably dilute competition.
147
In 2014, non-residential customers consumed 1.921.153 out of the total 2.706.310 Gigawatt-hour
electricity consumption and 1.506.185 Gigawatt-hour out of the total 2.578.779 Gigawatt-hour of gas
consumption – Eurostat data, 2014.
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Phasing out regulated prices
As shown in the Evaluation of the EU's regulatory framework for electricity market
design and consumer protection in the fields of electricity and gas, market-based energy
prices that are able to take into account the rapid changes of demand and response and
cross-border trade are even more crucial than in 2009. The evaluation concludes that
progress towards lifting regulated prices blocking competition and consumers' choice
should continue (Evaluation Section 7.1.1).
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Phasing out regulated prices
Table 1: Energy price regulation in EU Member States – February 2016148
Member State Electricity Gas
Austria
Belgium
Bulgaria X X
Croatia X X
Cyprusi
X
Czech Republic
Denmarkii
X X
Estonia
Finland
France X X
Germany
UK (Great Britain)
UK (Northern Ireland) X X
Greeceiii
X
Hungary X X
Ireland
Italyiv
X X
Latviav
X
Lithuaniavi
X X
Luxembourg
Maltavii
X
Netherlands
Polandviii
X X
Portugalix
X X
Romaniax
X X
Slovakia X X
Slovenia
Spainxi
X X
Sweden
Source: European Commission Data.
i
Price regulation economically justified due to natural monopoly.
ii
Denmark is implementing measures aimed at progressively removing regulated prices. This follows from
changes in the energy law introduced in January 2013.
iii
Discussions with Greece on the phase-out of regulated prices are conducted as part of the Economic
Adjustment Programme and lead to the phase-out of electricity regulated prices for households and small
enterprises as of 30 June 2013. The only exceptions are end-user prices for vulnerable customers. As
regards gas, a major reform of the Greek gas retail market is envisaged that seeks to abolish the regional
monopolies of the EPAs for gas supply and to progressively extend eligibility to all retail customers.
iv
Italy has introduced since 2013 market based reference prices for small customers including SMEs that
according to the Italian NRA should be considered de facto non-regulated.
v
Latvia has removed regulated prices for electricity for households other than vulnerable in January 2015.
As a first step towards price deregulation, a revised Energy Law, adopted on 18 September 2014,
introduced a category of vulnerable customers (underprivileged social groups and families with 3 or more
children) and set a fixed price for electricity for these customers. Regarding gas, the liberalization is
expected to be completed by 2017, subject to interconnections projects being realized in order to make the
transition from isolated market to an interconnected one.
vi
Lithuania has removed electricity regulated prices in the beginning of 2015.
vii
Malta regulates electricity prices for all customer segments. However, it has extensive exemptions
notably from market opening and customer eligibility provisions of the Third package.
viii
Discussions with Poland are ongoing regarding draft measures communicated to Commission's services
implementing the judgement delivered on 10 September 2015 concerning gas price regulation (36/14
Commission v. Poland). The draft measures foresee deregulation of gas prices for households by 2023.
148
Based on current state of play of the conformity checks.
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Phasing out regulated prices
ix
Portugal has agreed a roadmap for phasing out regulated prices as a result of the infringement
proceedings initiated by the Commission. In August 2012, the government announced the complete
elimination of regulated tariffs with a transitory tariff in place for three years.
x
Romania has agreed an electricity and gas price deregulation calendar as part of the Economic
Adjustment Programme.
ix
In Spain, on 27 December 2013, the new Electricity Act modified the last resort tariff for electricity and
introduced the PVCP (Precio Voluntario Pequeño Consumidor or Voluntary price for small customers) for
electricity households. The energy component of this price reflects the spot market during the period, only
the profit margin of the suppliers being regulated.
Presentation of the options
7.2.4.
Option 0: Making use of existing acquis to continue bilateral consultations and
enforcement actions to restrict price regulation to proportionate situations justified by
manifest public interest
This option consists in a new round of bilateral meetings with the Member States as
regards households, relying on the existing acquis. Due to the political sensitivity
attached to price regulation for households, but also taking into account that national
price regulation regimes are characterised by a variety of rules and justifications thereof,
voluntary collaboration between Member States based on assistance by the Commission
services has not been considered as an adequate tool for achieving price deregulation, a
bilateral approach being preferred. Bilateral meetings can be followed by EU Pilots and
infringement procedures to restrict price regulation to time-limited situations justified by
the public interest.
In this context, the Commission services will:
- offer Member States assistance on practical implementation of deregulation
including on accompanying good practice in protecting the energy poor through
social policy;
- monitor Member States' adherence to adopted phase-out roadmaps and the
implementation of the principle of cost-reflectiveness of their regulated prices;
and
- initiate enforcement where Member States refuse to phase-out regulated prices on
a voluntary basis.
While enforcement action under this option may be effective, as repeatedly backed by
favourable judgements of the European Court of Justice, infringement actions by the
Commission against price regulation for households remain politically sensitive.
Option 1: Requiring Member States to progressively phase out price regulation for
households by a deadline specified in new EU legislation, starting with prices below
costs, while allowing transitional, targeted price regulation for vulnerable customers (e.
g. in the form of social tariffs).
The legislative measures would include:
- introducing binding deadlines (e. g. 3-4 years from the entry into force of the
legislation) in the Electricity and Gas Directives for price-setting for households
to be free of regulatory intervention and instead subject only to supply and
demand.
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Phasing out regulated prices
- allowing regulated prices (e. g. in the form of social tariffs) targeted at specific
groups of vulnerable customers, notably the energy poor. This would also
contribute to ensuring universal access to affordable energy services as required
under UN-backed Sustainability Development goals.
These measures would be accompanied by:
- bilateral consultations, as appropriate, to support Member States in defining and
implementing the roadmaps and in identifying vulnerable groups for special
protection.
- technical advice, guidance and sharing of good practices on energy efficiency,
alternative financial support measures (e. g. energy cheques) or income support
through the welfare system to complement or progressively substitute the need for
social tariffs.
This option might accelerate liberalization processes in Member States by establishing a
clear target date for price deregulation while allowing regulated prices as targeted,
transitional support to vulnerable customers. However, it would not fully take into
account social and economic particularities in Member States in setting up a common
deadline for price deregulation.
Option 2a: Requiring Member States to progressively phase out price regulation, starting
with prices below costs, for households below a certain consumption threshold to be
defined in new EU legislation or by Member States, with support from Commission
services.
If the consumption threshold is defined below current levels used by Member States to
apply price regulation, this option would reduce the scope of price regulation therefore
limiting its impact on the market.
The main challenge of this option concerns the calculation of the right thresholds.
Allowing regulated prices up to certain rather low energy consumption thresholds may
miss out some poorer customers who may consume rather more energy per household, as
they may spend more time in their homes (due to unemployment, invalidity, home work),
live in poorly insulated dwellings or require to be connected to medical equipment. As a
consequence they may exceed the defined thresholds. On the other hand and contrary to
the desired effect, ordinary customers of sufficient wealth but low consumption e.g. due
to a lifestyle with a relatively limited use of appliances may profit from such thresholds.
The same might apply to secondary homes inhabited only temporarily by wealthier
customers.
Maintaining regulated prices for large parts of consumption through high thresholds
prevents the development of market-based demand response and other flexibility options,
as price-based incentives cannot be created through price regulation schemes as
effectively as by the market. This option could thus limit the achievement of the full
effects of the Market Design initiative, particularly its elements aimed at end-customers.
Option 2b: Requiring Member States to phase out below cost price regulation by a
deadline specified in new EU legislation.
While this option would limit the distortive effect of price regulation and tackle tariff
deficits, maintaining regulated prices, even if above cost, would prevent the development
of market-based demand response and other flexibility options, as price-based incentives
409
Phasing out regulated prices
cannot be created through price regulation schemes as effectively as by the market.
Moreover, price regulation that does not allow charging more than current costs risks
holding back investments in product innovation and service quality.
The main challenge of this option would be to define cost coverage methodologies for
price regulation at EU level. It is legally challenging as the current EU acquis establishes
as a general rule that prices should be set by market forces; moreover, this option could
produce weaker effects than current EU acquis as it would limit the requirement of
proportionality to be met by price regulation only to the cost coverage aspect (not taking
into account the limitation in time, in the scope of beneficiaries or the necessity test). It is
also economically challenging due to opaque cost structures of the companies. Moreover,
ensuring cost-reflectiveness by regulation would imply considerable regulatory and
administrative impact.
Comparison of the options
7.2.5.
Comparison of performance of energy markets with and without price regulation
The objective of this Section is to assess the performance of energy markets where prices
are established by a governmental authority (they are regulated) with that of markets
where prices are set in market conditions, by supply and demand. The assessment is
made based on the level of competition within each group of markets, according to the
conventional structure-conduct-performance framework, which explores a range of retail
market indicators such as market structure and concentration, consumer switching
activity and consumer experience.
In order to assess the performance of markets with and without energy price regulation
the present Section carries out a comparative analysis of energy markets across all EU
Member States, grouped in two categories: markets where energy prices are set in market
conditions and markets characterised by intervention in the price setting mechanism.
These two groups are appraised using average values for each of the elements
considered, weighted by population.
Background: Energy market liberalisation and price regulation
The EU-level liberalisation of the electricity market was initiated with the First Energy
Market Directive, which was adopted in 1996. At that time, both the United Kingdom
and the Nordic countries had already started to liberalise their markets. Two additional
legislative packages have followed since then, i.e. the Second Energy Market Directive in
2003 and the Third Package, including the Third Electricity Directive, in 2009. The
process has aimed to separate the network activities, i.e. transmission and distribution,
from generation and supply activities. The rules regarding unbundling of these activities
into separate entities have become increasingly stringent over this period to properly
ensure this separation of activities. This has mainly reflected concerns about the
competition, in particular regarding an appropriate pricing of these services as well as
fair access to the networks for new entrants.
Following the separation of the different activities in the supply chain of electricity, the
price formation of the final end-user price has also changed. The electricity price now
consists of different components relating to the different parts of the supply chain, as
shown on Figure 1.
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Phasing out regulated prices
While regulated prices are unlawful under current Gas and Electricity Directives, unless
they meet specific conditions, many Member States still apply price regulation.
At the same time it is important to note, as already explained in Section 2 of the present
Annex, that electricity and gas price regulation refers only to the ‘energy’ component of
the end-user price, excluding network charges, taxes, other levies and VAT. This
component is the element which should be determined by market demand and supply in a
fully liberalised energy market.
Figure 1: Different components of the final electricity price
Source: ECFIN
Background: Academic discussion on the merits of energy market liberalisation
A number of academic papers have presented arguments in favour of price regulation in
retail energy markets. The assumption presented is that deregulation will not lead to any
significant efficiency improvement or added value. The argument presented is that the
potential retail savings on activities such as metering, billing or customer services are
uncertain and their expected economic impact is too low to be significant for most
customers.149
In addition, it is also argued that customers are reluctant to change150
and
in some cases inability to make appropriate choices.151
However, the above mentioned arguments have been refuted by a number of authors.
Littlechild argues that domestic customers are not indifferent to choice, and retailing is
149
"Why do we need electricity retailers? Or can you get it cheaper wholesale" (2000) Paul L. Joskow;
"The future of retail energy markets" (2008) Catherine Waddams; "The big retail ‘bust’: what will it
take to get true competition?" (2000) Theresa Flaim
150
"Consumer preference not to choose: methodological and policy implications" (2007) Timothy J
Brennan
151
"Retail competition in electricity markets" (2009) Christophe Defeuilley
411
Phasing out regulated prices
precisely the activity that can lead to products that best suit customers' preferences.152
Based on the US experience with energy market liberalisation Zarnikau and
Whitworth153
, Rose154
and Joskow155
demonstrate cost-saving benefits from competition.
Moreover, introducing competition is equivalent to opening the door to innovation. The
market can create alternatives to a regulated framework. Those in favour of a regulated
retail market assume regulators will set up a pass-through tariff in which the final price of
energy will be composed of the cost of wholesale energy plus a margin to cover for the
cost of selling the energy to the final customers. However, Littlechild argues that if
customers want this option, the market will be able to deliver it. Indeed, as it is already
the case in the Nordic Member States, with the roll-out of smart meters, dynamic tariffs,
which are similar to the pass-through tariffs, will be available to customers. From this
perspective, the advantages of competition are clear.
Other arguments in favour of open retail markets refer the possibility that suppliers
introduce new billing options, improve operations of the wholesale market by raising the
number of agents involved or provide energy efficiency related services. On the other
hand, regulated prices may reduce customer engagement and, in these markets, there is a
possibility for Governments to alter electricity tariffs for political gains. More generally,
it has been argued that end-user price regulation in electricity and gas markets distorts the
functioning of the market and jeopardises both security of supply and the efforts to fight
climate change156
.
Assessment of market structure and concentration
Measures of market structure and concentration, such as the number of main suppliers
and the market share of largest suppliers, provide an indication of the degree of
competition in a market, which is a useful first step to draw a comparison between
markets with energy price regulations and those where prices are set by supply and
demand. Markets with lower market concentration where a high number of service
providers compete to gain and retain customers are under competitive pressure to deliver
better deals for consumers. This makes market structure indicators relevant for assessing
the performance of energy markets.
Evidence shows that energy markets without price regulation show a higher number of
suppliers and less market concentration. In fact, while markets without electricity price
regulation have on average 34 nationwide suppliers, markets with regulated prices have
19, as shown on Figure 2. A similar trend can be observed within the gas market, as
shown on Figure 4. While markets without gas price regulation have on average 30
suppliers, markets with regulated prices have 17.
152
"Retail competition in electricity markets—expectations, outcomes and Economics" (2009) Stephen
Littlechild
153
"Has Electric Utility Restructuring Led to Lower Electricity Prices for Residential Consumers in
Texas?" (2006) Jay Zarnikau, Whitworth
154
"The State of Retail Electricity Markets in the US" (2004) Kenneth Rose
155
"Markets for power in the United States: an interim assessment" (2005) Paul L Joskow
156
"Position paper on end-user price regulation" (2007) European Regulators’ Group for Electricity and
Gas
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Phasing out regulated prices
Among the top ten electricity markets in terms of the number of suppliers, seven do not
use any form of price regulation, including Sweden (97 nationwide suppliers), the
Netherlands (75) and Finland (45). In contrast, among the ten electricity markets with the
lowest number of suppliers, eight are characterised by regulated prices, including Cyprus
(1 nationwide supplier), Malta (1), Lithuania (3), Bulgaria (4) and Latvia (5).
Figure 2: Overall number of suppliers and number of nationwide suppliers active in
the retail electricity market for households
Source: ACER
19
34
174
390
0 100 200 300 400 500 600
WA (reg)
LV
EL
SK
RO
PT
PL
MT
LT
IT
HU
HR
FR
ES
DK
CY
BG
WA (non-reg)
UK
SI
SE
NL
LU
IE
FI
EE
DE
CZ
BE
AT
Overall number of suppliers
Nationwide suppliers
413
Phasing out regulated prices
Figure 3: Overall number of suppliers and number of nationwide suppliers active in
the retail gas market for households
Source: ACER
Market concentration, measured by the share of the main suppliers in that market, is
another key indicator of competitiveness. Main suppliers (i.e. suppliers who have a
market share above 5% of the total) in markets without price regulation have a 63%
market share in the electricity market and 56% market share in the gas market. Markets
with regulated prices see main suppliers covering 74% of the market on average in
electricity and gas markets. This data further confirms the advantage of markets without
price regulation in terms of their competitive performance.
17
35
80
300
0 100 200 300 400 500 600
WA (reg)
LV
EL
SK
RO
PT
PL
MT
LT
IT
HU
HR
FR
ES
DK
CY
BG
WA (non-reg)
UK
SI
SE
NL
LU
IE
FI
EE
DE
CZ
BE
AT
Overall number of suppliers
Nationwide suppliers
414
Phasing out regulated prices
Figure 4: Cumulative market share of main suppliers
Source: ACER
Assessment of market conduct
Effective retail competition is characterised by competition between suppliers over price
and non-price elements whereby suppliers undercut each other's' prices to the efficient
cost level, improve the quality of their services and develop innovative products which
meet the requirements of customers with a view to increasing market share and profits. In
competitive retail markets customers should have the freedom of choice by moving to an
alternative supplier, to change contracts or to choose new products. The freedom to
choose the energy supplier is key because customer switching activity puts competitive
pressure on market actors.
In the present Section all of the above described elements of retail market conduct are
analysed for both regulated and non-regulated energy price markets in order to complete
the relative performance assessment of these markets.
Price competition
Price competition is typically used as the basic indicator of market competitiveness. Price
competition among suppliers is limited to the energy component of the supply price
which remains the largest of the three price components despite the fact that this
component has generally diminished since 2008 mainly due to increases in the
taxes/levies.157
Data from the Agency for the Cooperation of Energy Regulators (ACER)158
shows that
Member States without regulated prices have on average slightly higher energy prices
157
"Energy prices and costs in Europe" (2014) European Commission
https://ec.europa.eu/energy/sites/ener/files/publication/Energy%20Prices%20and%20costs%20in%20E
urope%20_en.pdf
158
"Market Monitoring Report 2014" (2015) ACER, available at
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015.pdf
63
74
56
74
0
10
20
30
40
50
60
70
80
Non-regulated Regulated
Electricity
Gas
415
Phasing out regulated prices
than those with price regulation. This is not surprising as Member States with regulated
prices can set de facto the final price on energy services. Price regulation by State
authorities can and in some instances does result in prices set below costs, i.e. the end
consumer price does not cover the full costs of producing and delivering energy to
consumers.
Figure 5: Retail price level across EU Member States, 2014
Source: ACER
Note: Information for Latvia; Bulgaria; Bulgaria, Croatia, Cyprus; Lithuania; Malta; and Romania not available.
While lower retail prices seem to present an immediate advantage to all customers, it is
important to analyse the economic sustainability of energy prices regulated below the
actual cost and changes to consumer surplus resulting from price regulation.
Cost reflectiveness of regulated prices
Regulated prices can have negative impacts on the energy market especially if they are
set too low. First, energy prices which are set too low fail to provide the right signal to
energy customers about costs and scarcity, which risk resulting in over-consumption of a
cheap service. Second, the low level might hamper the process of market opening by
discouraging new companies from entering the market. Third, they will determine the
ability of different suppliers to make competitive offers on the wholesale market. For this
reason, if end-user prices are set too low, suppliers might not be able to recover their
costs and could face potential losses.
By contrast, if set too high, they might not reflect the production costs of the incumbent
and increase their rents, while at the same time reducing the surplus of final customers.
The result is inefficiencies in the overall energy system.
Determining the proper level of regulated prices requires full information on the cost
structure of the industry, which is becoming increasingly difficult as the electricity
markets evolve.
In fact, while ensuring cost-reflectiveness of regulated prices could be an option to
address negative effects of price regulation, the regulators' ability to set the right margin
between wholesale and retail prices is limited by imperfect information and rapidly
changing market conditions including a wholesale market which is affected by
23
18
0
5
10
15
20
25
30
35
AT
BE
CZ
EE
FI
DE
GB
IE
LU
NL
SI
SE
WA
(non-reg)
DK
FR
HU
IT
PL
PT
SK
ES
EL
WA
(reg)
Retail
price
level
(€/kWh)
416
Phasing out regulated prices
commodity prices, cost of capital and the price of CO2 allowances, to quote just a few.
These barriers constitute a significant disadvantage characterising any kind of price
regulation, even that which is set "above costs", as there is a high risk that the margins set
by the regulators will not be sufficient for new service providers to enter the market. The
effect of such miscalculation of the most optimum price level would be less market
players and less competition and therefore less innovation and a lower general level of
services.
Issue of tariff deficits
Electricity tariff deficits have emerged as an issue for public finances. A tariff deficit
implies that a deficit or debt is built up in the electricity sector, often in the regulated
segments of transmission or distribution system operators, but in some cases also in the
competitive segments, e.g. in incumbent utilities.
A deficit is accumulated due to the fact that the regulated tariffs which should cover the
system's operating costs are either set too low or not allowed to increase at a pace that
cover rising production or service costs. As these deficits accumulate due to government
regulation of tariff or price levels, they have been recognised as contingent liabilities of
the State in a few Member States. In these cases, the debt stemming from low energy
prices need to be repaid through general taxation from present or future taxpayers.
The results of a study carried out by the Directorate General for Economic and Financial
Affairs on the issue of electricity tariff deficits indicates that 11 Member States had
accumulated electricity tariff deficits as of 2012159
. Within that group, 10 Member States
continue to regulate their electricity prices, as shown in Figure 7.
Figure 6: Electricity tariff deficit – comparison between Member States
Source: DG ECFIN, European Commission
159
"Electricity Tariff Deficits. Temporary or permanent problem in the EU?" (2014) European
Commission
417
Phasing out regulated prices
Cumulated tariff debts are substantial in some Member States. In Spain and Portugal,
where electricity prices are regulated, the tariff debt represented 3% and 2.2-2.6% of the
GDP respectively.
Link between wholesale and retail prices
While regulated price markets show an advantage over unregulated price markets in
terms of the final price for the consumer, research carried out by the European Parliament
shows that the relationship between wholesale and retail prices for households is weaker
in countries with price regulation.160
Whilst retail household prices appear to be
positively related to wholesale prices for both groups of countries, the link for countries
with price regulation is less pronounced based on the estimated coefficients. This
indicates that regulated prices may weaken the link between wholesale prices and retail
prices, or at least tend to delay it. While this could delay or prevent the increase of
household prices when wholesale prices are high, it may also imply that households
cannot fully benefit from a decrease in wholesale prices.
Ensuring an effective link between wholesale and retail energy prices is key for
delivering the benefits of the wholesale energy market competition to energy consumers.
To give a sense of perspective, the European Commission 2014 report on the "Progress
towards completing the Internal Energy Market" found that wholesale electricity prices
in the EU declined by one-third and wholesale gas prices remained stable between 2008
and 2012.161
Protection of vulnerable consumers and the energy poor
Continuous price regulation in some Member States is justified on the grounds of
protection of vulnerable consumers and the energy poor. In this context, it is argued that
energy price regulation is necessary to protect customers from the market power of
energy monopolies. This is because an unregulated monopoly could charge customers a
price much higher than its production cost. Similar arguments have been put forward
with respect to vulnerable customers.
However, evidence shows that blanket energy price regulation is not an optimal
protection measure for vulnerable consumers from the point of view of efficient
allocation of public resources. The above is based on the assumption that deficits
associated with energy prices regulated below-costs are financed from the State budget.
In fact, under regulated energy price environments public resources are often used to
support all households, regardless of their income or vulnerability. The efficiency of such
approach is questionable as even the distribution of benefits associated with low
regulated energy prices results in higher income groups receiving higher public support
than lower income groups, as evidenced in Figure 7 below, which shows that top earners
in most Member States consume more electricity than the lowest income groups. Higher
energy consumption among top income groups occurs despite the assumed higher
160
"The impact of oil price on EU energy prices" (2014) European Parliament
161
"Communication on progress towards completing the Internal Energy Market" European Commission
COM(2014) 634 final
418
Phasing out regulated prices
efficiency of dwellings inhabited by these income groups and higher energy efficiency of
appliances typically used.
Figure 7: Electricity consumption per income group
Source: DG ENER
It can be argued that if resources previously allocated to finance below-cost price
regulation are used for targeted support of vulnerable consumers, a higher impact can be
achieved in terms of the protection of vulnerable consumers. This conclusion is
supported by evidence presented in Figure 8 which shows that consumers in unregulated
price markets feel more able to maintain an adequate level of heat during winter. This
data also shows that energy price regulation is not an effective means of addressing
energy poverty.
419
Phasing out regulated prices
Figure 8: Percentage of population unable to keep their homes warm during winter,
2014
Source: DG ENER
Non-price competition/innovation
Although low prices are the most commonly thought of way for firms to attract
consumers, suppliers may also seek to distinguish their products by other means. These
may include quality of service, convenience, an environmentally sustainable product, or
any other non-price aspect that adds value for consumer and brings innovation to the
retail energy market. The diversity of products available in a market is therefore also a
good indication of the health of competition.
Conversely, when prices are kept artificially low customer surplus may be reduced as
some customers are able and willing to pay higher prices for better and more innovative
energy services. In that context regulated prices might deprive those customers from
accessing more offers and more innovative and complex services such as certified green
energy offers, loyalty programmes, access to new technologies such as smart metering
and mobile apps, or non-financial benefits such as free maintenance of water boilers or
home insurance which are delivered by some retailers within the energy market.
In fact, data displayed in Figure 9 shows that customers in markets where prices are not
regulated have access to more diverse services and a wider choice of offers. Dual fuel
offers are available in 75% of the markets without price regulation and only in 44% in
those with regulated prices. Certified green energy offers are available in 92% of the
markets without price regulation and in 67% of the markets with regulated prices. Only
50% of markets with regulated prices offer energy pricing alternatives, while this option
is available in 92% of markets without price regulation.
420
Phasing out regulated prices
Figure 9: Share of Member States with dual-fuel, certified green and variety of
energy pricing tariffs
Source: ACER
Markets without price regulation are also characterised by retail energy markets
delivering more financial and non-financial benefits and a greater availability of
information and communication technologies in association with energy contracts, as
showed in Figure 10.
421
Phasing out regulated prices
Figure 10: Retail market innovation
number
of
electricity
only
offers
dual-
fuel
availabl
e
certified
green
energy
offers
available
availabilit
y of non-
price
financial
benefits
availability
of non-
financial
benefits
ICT
offer
Variety of
energy
pricing
alternative
s available
to
consumers
Austria 53 Yes Yes Yes Yes Yes Yes
Belgium 20 Yes Yes Yes No Yes Yes
Bulgaria 1 N/A N/A No
Croatia 4 N/A N/A Yes
Czech
Republic
69 Yes Yes Yes
Cyprus 1 N/A N/A No
Denmark 83 No Yes Yes No Yes Yes
Estonia 40 Yes No Yes
Finland 401 No Yes Yes Yes Yes Yes
France 22 Yes Yes Yes
Germany 404 No Yes Yes No Yes Yes
Great Britain 69 Yes Yes Yes Yes Yes Yes
Greece 7 No No Yes
Hungary 4 No No No
Ireland 9 Yes Yes Yes Yes Yes Yes
Italy 23 Yes Yes Yes Yes Yes Yes
Luxembourg 18 Yes Yes Yes
Latvia 1 N/A N/A No
Lithuania 1 N/A N/A No
Malta 1 N/A N/A No
Netherlands 86 Yes Yes Yes No Yes Yes
Poland 133 No Yes Yes
Portugal 34 Yes Yes Yes
Romania 1 N/A N/A No
Slovakia 23 No No No
Slovenia 5 Yes Yes No
Spain 54 Yes Yes Yes Yes Yes
Sweden 378 No Yes Yes Yes Yes Yes
Source: ACER/CEER, VaasaETT
Data presented above further confirms that markets where prices are set according to
supply and demand perform better in terms of bringing innovation to the retail energy
market– deliver greater choice and more innovative services and offers, than markets
where energy prices are regulated.
Customer switching activity
Customer switching activity puts competitive pressure on suppliers and therefore is an
important indicator of competition within the market.
ACER data presented in Figure 11 and 12 shows that markets with no price regulation
show higher customer activity both in terms of external switching (movement between
suppliers) and internal switching (movement between alternative products from the same
supplier) than markets with regulated prices.
422
Phasing out regulated prices
On the other hand, electricity switching rates in markets with price regulation are
significantly lower. In Malta, Cyprus, Bulgaria, Latvia, Lithuania and Romania switching
rates remained at zero, mainly due to the lack of retail competition or very weak
competition and limited choice available to customers.
Figure 11: Customer external switching rates
Source: ACER
Customers in regulated price markets also display lower internal switching rates – a
phenomenon which can be explained by more restricted choice of offers in those
markets. In fact, Figure 12 shows that 75% of customers in markets with price regulation
have never switched contracts, in comparison to 32,5% in markets with no price
regulation.
Figure 12: Proportion of customers who have never switched contract (internal
switching)
Source: ACER
Low switching rates in markets with price regulation represent a lost opportunity
for savings for many customers. In fact in most markets customers can derive
8%
6%
0%
2%
4%
6%
8%
10%
12%
14%
16%
AT
BE
CZ
EE
FI
DE
GB
IE
LU
NL
SI
SE
WA
(non-reg)
DK
FR
HU
IT
PL
PT
SK
ES
EL
WA
(reg)
Rate
of
switching
(%)
423
Phasing out regulated prices
substantial benefits from switching, as illustrated in Figure 13. In markets
without price regulation customers can save on average 23% of their energy bill by
switching from the incumbent. Potential savings in markets with price regulation
amount to 12% on average.
Figure 13: Savings on incumbent
Source: ACER
Assessment of customer experience
Customer experience is key to appraising the comparative performance of different types
of markets. Variables which compose customer experience and are analysed in this
Section include comparability of offers, trust in retails to respect the rules and regulations
protecting customers, the degree to which customer expectations are met and customer
satisfaction with the choice.
The above variables are measured by the Consumers, Health, Agriculture and Food
Executive Agency (CHAFEA) as part of the Market Monitoring Survey. The report
surveys 42 markets in the 28 Member States of the EU, as well as Norway and Iceland,
with the general aim to assess customer experiences and the perceived conditions of the
customer markets in all EU Member States. The assessment is measured through a
"Market Performance Indicator" (MPI) which is a composite index indicating how well a
given market performs, according to customers.
The overall MPI score for the market for “electricity services” across the EU is 75.3
points, based on a maximum possible score of 100 points. Electricity services market
scored 3.3 points lower than the services markets average. This makes it a low
performing services market, ranking 26th of the 29 services markets. The overall MPI
score for the market for “gas services” at EU28 level is 78.1, which is lower than the
services markets average score by 0.5 points. This makes it a middle to high performing
services market, ranking 14th of the 29 services markets.
In comparison to the services markets average, the “electricity services” market has a
higher proportion of complaints and higher detriment score, measuring customers
experiencing problems with the products or services they purchased. The electricity
services market also performs worse than average in terms of the comparability of offers,
customers' trust in suppliers, the capacity to meet customers' expectations, and the ability
23%
12%
-10%
-5%
0%
5%
10%
15%
20%
25%
30%
35%
40%
AT
BE
CZ
DE
EE
FI
IE
LU
NL
SE
SI
UK
WA
(non-reg)
BG
CY
DK
ES
FR
HR
HU
IT
LT
MT
PL
PT
RO
SK
EL
LV
WA
(reg)
Savings on incumbent (%)
424
Phasing out regulated prices
of the market to deliver sufficient choice. It is also characterised by a lower than average
switching activity.
At the same time, there is a 34.1 point difference in MPI between the top ranked country
and the lowest ranked country, indicating that there are considerable country differences
to be taken into account when evaluating the electricity services market. The market
scores higher in the EU15 and lower in the EU13 compared to the EU28, while
performing especially well in the Western and Northern regions.
In comparison to the services markets average, the “gas services” market scores above
the average for the problems, detriment and expectations components. However, the
comparability and choice components are lower. The “gas services” market also has a
lower than average switching proportion.
Figure 14: Market Performance Indicator for electricity markets with and without
price regulation
Source: EC, DG JUST162
The MPI scores for 2015 indicate a clear advantage of markets without price regulation
over those with regulated prices in terms of customer satisfaction. As shown in Figure
14, markets without price regulation scored on average 80 points, while those with price
regulation scored 72. The advantage of markets without price regulation over those with
regulated prices was equally spread across all five components analysed, as shown in
Figure 15.
162
"Monitoring Customer Markets in the European Union 2013 – Part III (Electricity)"(2013) European
Commission
80
72
68
70
72
74
76
78
80
82
WA (non-reg) WA (reg)
WA (non-reg)
WA (reg)
425
Phasing out regulated prices
Figure 15: Market Performance Indicator for electricity markets per component for
electricity markets with and without price regulation
Source: EC, DG JUST
The 2013 edition of EU market surveys provides an insight into general customer
satisfaction with the electricity market, as shown in Figure 15. Markets without price
regulation scored 7.6 and 7.8 on average for customer satisfaction with the offers on the
market and with the variety of suppliers, while markets with price regulation scored 6.8
and 5.8 points respectively. This data confirms a clear advantage of markets without
price regulation from the customer point of view.
Figure 16: Customer satisfaction with the electricity market
Source: European Commission (2013)
Conclusion of the assessment
In this Section we have methodically screened the performance of markets with and
without price regulation based on a number of competitiveness indicators and market
surveys which measure market competitiveness and customer satisfaction with the
1,4
1,5
2,0
1,7
1,4
1,2
1,3
1,9
1,6
1,2
0,0
0,5
1,0
1,5
2,0
2,5
compare trust prob_det expect choice
WA (non-reg)
WA (reg)
426
Phasing out regulated prices
electricity and gas markets. The analysis indicates that electricity and gas markets where
prices are set by supply and demand are able to deliver better and more diverse services
to the customers. In fact, despite slightly higher prices in markets without price
regulation, customers in these markets show a higher level of satisfaction as they have a
wider choice and access to better quality services which are more reflective of their
preferences.
The analysis nonetheless suffers from clear limitations such as selection bias. It might
well be that the Member States in the category of non-regulated prices have lower market
concentration, higher switching rates or better customer experience for reasons different
than price regulation. However, despite the methodological weaknesses of the analysis,
the results are comparable with the results of research carried out by ACER in its Market
Monitoring Report.
In fact, in order to achieve a full picture of energy market competitiveness which is not
dependent on a single indicator ACER produced a single composite index (‘ACER Retail
Competition Index – ARCI’) which provides a comprehensive picture of the relative
competition performance of the retail electricity and gas household markets in each
Member State. The indicator combines several elements, including market concentration,
entry/exit activity, switching, consumer satisfaction and mark-ups (see Table 2 below).
As such the indicator covers all of the individual components used to analyse the
performance of markets with and without electricity and gas price regulation.
Table 2: Competition indicators included and the assessment framework for the
composite index
Indicator Scope Low score = 0 High score =10 Weight
Concentration ratio, CR3 National Market share of
three largest
suppliers 100%
Market share of three
largest suppliers 30%
or less
10
Number of suppliers with market
share > 5%
National Low number of
suppliers
High number of
suppliers
10
Ability to compare prices easily National Difficult to compare
prices
Easy to compare
prices
10
Average net entry (2012-2014) National Net entry zero Net entry of five or
more nationwide
suppliers
10
Switching rates (supplier + tariff
switching) over 2010-2014
National Annual switching
rate zero
Annual switching rate
20% or more
10
Non-switchers National None have switched All have <1/3 not
switched
10
Number of offers per supplier Capital
city
One offer per
supplier
Five or more offers
per supplier
10
Does the market meet expectations National Market does not
meet expectations
Market fully meets
expectations
10
Average mark-up (2012–2014)
adjusted for proportion of
consumers on non-regulated prices
National High mark-up Low mark-up 10
Source: ACER
According to the index, the most competitive markets for households are electricity
markets in Sweden, Finland, the Netherlands, Norway and Great Britain and gas markets
in Great Britain, the Netherlands, Slovenia, the Czech Republic and Spain. The index
shows weak retail market competition in electricity household markets in Latvia,
Bulgaria and Cyprus and gas household markets in Lithuania, Greece and Latvia.
427
Phasing out regulated prices
The results of the ACER analysis, presented also in Figure 14, indicate that the level of
competition in markets with regulated prices for households is much lower than in
countries that do not regulate electricity and gas prices, with the exceptions of the gas
markets in Spain and Denmark. Therefore the ACER indicator confirms the overall
findings of the analysis of the performance of markets with and without price regulation
carried out in the present Section.
Figure 17: ACER Retail Competition Index (ARCI) for electricity and gas
household markets – 2014
Source: ACER
428
Phasing out regulated prices
Comparison of options for price deregulation
Table 3: General comparison of the options
0. Non legislative:
Making use of
existing acquis to
continue bilateral
consultations and
enforcement actions,
accompanied by EU
guidance
1. Legislative
obligation:
No price
regulation but
social tariffs
allowed
2a Legislative
obligation:
Price regulation
allowed below
certain
consumption
threshold
2b. Legislative
obligation:
Cost covering
price regulation
allowed without
limitation as to the
amount of energy
consumed
Time
limitation
End date to be set by
each Member State in
compliance with EU
acquis to be assessed
on case-by-case basis.
End date set in
EU legislation
for all price
regulation
(except social
tariffs)
End date set in EU
legislation for
price regulation
above a certain
consumption
threshold.
No end date for
price regulation
below the defined
threshold.
End date set in EU
legislation for price
regulation below
costs
No end date for
price regulation
below the defined
threshold.
Limitation as
to the scope of
beneficiaries
Scope of
beneficiaries to be
defined by each
Member State in
compliance with EU
acquis to be assessed
on case-by-case basis.
No beneficiaries
of price
regulation.
Social tariffs
allowed as
transitional
measure
Beneficiaries of
price regulation
limited to
households below
a certain
consumption
threshold
No limitation as
regards the scope of
beneficiaries (all
households).
Methodology
for setting the
price
Methodology to be
defined by each
Member State in
compliance with EU
acquis to be assessed
on case-by-case basis.
No provisions as
regards
methodology
(cost coverage
etc.) necessary
as all price
regulation is to
be phased out.
Methodology to
be defined by each
Member State in
compliance with
EU acquis to be
assessed on case-
by-case basis.
Principles ensuring
cost coverage (e. g.
at least positive
mark-ups or costs
of an efficient
supplier plus a
reasonable profit
margin) to be
defined in EU
legislation while
concrete
methodologies
would be
developed at
national level.
Level of
harmonisation
Allows a case-by-
case assessment of
the price regulation
regimes as well as of
the eventual
exemptions.
Harmonised end
date for blanket
price regulation.
Allows a case-
by-case
assessment of
the exemptions
to price
deregulation
(targeted price
regulation for
vulnerable
consumers).
Harmonised end
date for blanket
price regulation.
Harmonised
exemptions to
price deregulation
(based on a
consumption
threshold).
Harmonised end
date for blanket
price regulation.
Harmonised
exemptions to price
deregulation (based
on a price
threshold).
429
Phasing out regulated prices
Option 0
Option 0 consists of making use of the existing acquis to continue bilateral consultations
and enforcement actions to restrict price regulation to proportionate situations justified by
general economic interest.
Costs
The main costs of this option are those of adapting price regulation regimes in Member
States following a case by case assessment by the Commission services via bilateral
consultations followed by infringement actions where appropriate based on the current
EU acquis. This option would result in different national regimes of price intervention (in
terms of applicability in time, to the scope of beneficiaries and definition of price
regulation) or a complete removal thereof, assessed on a case-by-case basis in terms of
compliance with the EU acquis including as regards proportionality of the measure for
achieving the pursued general interest objectives. It is therefore difficult to estimate the
costs associated with the implementation of each regime.
The resulting diversity of regimes would create/maintain uncertain prospects for
businesses which discourages cross-border supply activities.
The lack of a level playing field across the EU in terms of price setting procedures
translates into administrative costs for entering and conducting business in new markets.
Member States with no price regulation will not be affected by the implementation of this
option. Therefore no economic impacts are to be expected.
Benefits
While overall the competition on retail markets would improve compared to the existing
situation due to the limitation or complete removal of price regulation in Member States,
market distortions would continue to exist impacting national markets as well as cross-
border competition.
Consumers' benefits linked to price deregulation (more consumer choice for suppliers
and energy service providers, better services and resulting increased consumer
satisfaction) would vary according to the national price intervention regime/the lack
thereof.
Option 1
Option 1 consists of requiring Member States to progressively phase out price regulation
for households by a deadline specified in new EU legislation, while having the right to
allow transitional, targeted price regulation for vulnerable customers (e. g. in the form of
social tariffs).
Social tariffs are a form of regulated prices, usually below market level, available to
specific groups of vulnerable customers, notably the energy poor, to ensure that these
customers have access to energy at affordable prices.
A social tariff can apply to electricity and/or gas (or any other fuel). The illustrative
analysis of costs and benefits for this option will focus on electricity.
430
Phasing out regulated prices
Costs
The main cost components of this option are associated with the potential introduction of
a targeted price regulation for vulnerable consumers, such as through the social tariff.
Member States already applying social tariffs (BE, BG, CY, FR, DE, GR, PT, RO, ES,
UK) would not be affected by the implementation of this option.
The estimation of cost and benefits of Option 1 is made in comparison to the free market
option (with no regulated prices of any kind or social tariff) for Member States which
currently do not use "social tariffs" as a form of protection of vulnerable consumers.
The estimations provided are for illustrative purposes only. The final amount of targeted
electricity and/or gas, number of households and level of subsidies can be varied
depending on the preferences of the Member State implementing the measure.
Table 4 below shows the average annual electricity consumption and average annual
expenditure on electricity which are the two variables used to estimate the cost of
introducing social tariffs.
Table 4: Average annual household electricity consumption and expenditure, 2014
Member State
Average annual electricity
consumption
Average annual expenditure on
electricity
kWh/HH EURO/HH
BG 3836 275
CY 4935 920
DK 4288 439
ES 3855 687
FR 5204 499
GR 3953 471
HR 3712 374
HU 2522 233
IT 2494 375
LT 2025 180
LV 2099 180
MT 4266 553
PL 2010 221
PT 2935 377
RO 1590 144
SK 2682 330
Source: INSIGHT_E
The cost of implementing a social tariff depends on the scope of beneficiaries, the
difference between the market-based price of energy and the advantageous price set for
the beneficiaries of social tariffs as well as on the amount of energy consumption to be
covered by the social tariff.
For the purpose of this analysis, the beneficiaries of the social tariff are defined as the
share of the population unable to keep warm (according to EU-SILC 2014). The level of
the social tariff is defined as 20% less than the regular electricity price (which is shown
as the average 2014 nominal price without taxes and levies). There would be no cap on
431
Phasing out regulated prices
the amount of energy consumption covered by the social tariffs for the defined
beneficiaries.
However, in reality Member States would be able to decide on all of the above elements
according to their national circumstances. This means that Member States would be able
to decide on a more restraint or larger group of beneficiaries, a specific discount level
defining the price level under social tariffs and/or set a cap on energy consumption
beyond which market prices apply.
Within Option 1 various sub-options can be explored with respect to financing the
implementation of the social tariffs, such as:
A- financing only by non-vulnerable households,
B- financing by all households and
C- financing by all electricity customers (including industry, commercial sectors,
and all households including vulnerable households).
However, it is important to bear in mind that a levy only on industrial customers would
not be desirable as this would make industry less competitive. The final tariff would still
vary for vulnerable (eligible households) and other household customers as the base price
for the regular tariff and the social tariff remains the same in each instance. Of course,
the social tariffs can also be financed in part or in whole through the government budgets
and this option could be explored in addition (i.e. financial transfers).
The table and figures below show the costs or savings (net benefits) of the introduction of
a tariff, with savings arising for households receiving the social tariff and costs for those
paying for the tariff measure. Costs and benefits are calculated for each of the above
defined sub-options for financing: A, B and C.
As shown in the summary table below, the costs to finance the social tariff will see an
increase in the electricity bills from 1-14% depending on electricity prices, share of
vulnerable consumers and average electricity consumption in each Member State. The
increase in the electricity bills as result of the implementation of the measure is expected
to be highest in BG, GR, CY and PT if the financing is done via all non-vulnerable
households or all households. Financing the measure across all electricity consumers
allows alleviating the increase in energy bills thus limiting the impact on individual
customers.
432
Phasing out regulated prices
Table 6: Comparison of differences in tariffs to vulnerable and non-vulnerable
households for Option 1 according to different financing models
A - Financing across all non-
vulnerable households
B - Financing across all
households
C - Financing across all
electricity consumers
Non-vulnerable
Households
(regular tariff)
Vulnerable
Households
(social
tariff)
Non-vulnerable
Households
(regular tariff)
Vulnerable
Households
(social
tariff)
Non-vulnerable
Households
(regular tariff)
Vulnerable
Households
(social
tariff)
BG 14% -20% 8% -10% 3% -16%
CY 8% -20% 6% -13% 2% -18%
DK 1% -20% 1% -19% 0% -20%
ES 2% -20% 2% -17% 1% -19%
FR 1% -20% 1% -19% 0% -19%
GR 10% -20% 7% -12% 2% -17%
HR 2% -20% 2% -18% 1% -19%
HU 3% -20% 2% -17% 1% -19%
IT 4% -20% 4% -16% 1% -19%
LT 7% -20% 5% -13% 2% -18%
LV 4% -20% 3% -16% 1% -19%
MT 6% -20% 4% -14% 1% -18%
PL 2% -20% 2% -18% 0% -19%
PT 8% -20% 6% -13% 1% -18%
RO 3% -20% 2% -17% 1% -19%
Source: INSIGHT_E
Figure 17 and 18 further explore the nominal costs and benefits per vulnerable and non-
vulnerable household.
Figure 17: Comparison of annual costs per non-vulnerable household to finance
social tariffs implemented under Option 1(EUR per household per annum)
Source: INSIGHT_E
433
Phasing out regulated prices
Figure 18: Comparison of annual savings per vulnerable household benefiting from
social tariffs implemented under Option 1(EUR per household per annum)
Source: INSIGHT_E
Other costs related to the implementation of this option would be those associated with
the adoption and implementation of deregulation roadmaps in Member States applying
price regulation.
Benefits
This option delivers benefits linked to price deregulation in the form of a more
competitive retail energy market and the associated wider consumer choice of suppliers
and energy service providers and access to a larger variety of products, services and
offers, thus increasing consumer satisfaction, as demonstrated earlier in the present
Section, under subheading 5a.
At the same time the option to provide transitional and targeted price regulation to clearly
defined vulnerable consumer groups would provide the means for achieving the objective
of consumer protection during the period of market adjustment. After the period of
adjustment, transitional price regulation for targeted groups could be replaced by social
policy measures.
Moreover, suppliers would benefit from a level playing field across the EU in terms of a
regulatory environment which would encourage cross-border competition. For suppliers
in Member States applying price regulation, implementation of this option would lead to
a decrease in total costs due to the removal of compliance costs related to setting and
submitting for approval/applying regulated prices as set by the national authorities.
Allowing regulated prices (e. g. in the form of social tariffs) targeted at specific groups of
vulnerable consumers, notably the energy poor, would also contribute to ensuring
434
Phasing out regulated prices
universal access to affordable energy services as required under UN-backed
Sustainability Development goals.
Summary of costs and benefits for Option 1
The table below summarises the costs and benefits associated with the implementation of
Option 1. It reveals that costs of the measure would vary depending on the chosen
financing model, leading to an increase in the electricity tariff of non-eligible customers
by 1-15%. Vulnerable households eligible for social tariff save on average 20% on their
annual electricity bills.
Table 7: Option 1 - Cost and Benefits
Costs Benefits
Measure Description Quantification Description Quantification
Targeted price
regulation for
vulnerable
customers in the
form of social
tariffs.
Social tariffs in place
for a targeted
customer group
(usually less than 20%
of the population)
accompanying the
transition towards
market base prices.
Depending on
the financing
model (the
current
examples are
cost-neutral to
government),
those on the
regular tariff
will see an
increase in their
electricity tariff
by 1-15%.
Allowing price
regulation exclusively
for clearly defined
vulnerable customer
groups would ensure
that it is a targeted and
transitional measure.
Benefits linked to
price deregulation:
wider consumer
choice, innovation in
the retail energy
market linked to
increased competition,
better quality of
services, increased
consumer satisfaction.
Vulnerable
households save
20% on their
annual electricity
bills.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the
preceding pages, accrue overwhelmingly to households who would qualify for targeted social tariffs and/or
other targeted social support measures i.e. vulnerable and/or energy poor consumers. The biggest losers
from the measures in the preferred option are high-volume, often higher-income consumers who have in
the past benefitted from retail prices that have been set at artificially low levels (see Table 6 and Figures 17
and 18, above). The measures can therefore be considered progressive in nature i.e. they tend to
redistribute surplus from relatively high-income ratepayers to increase the welfare of lower-income
ratepayers.
435
Phasing out regulated prices
Nevertheless, it is also important to remember that in Member States where costs of social tariffs are
covered through a tax or a levy on the electricity bill, the social tariff regime places a disproportionately
high burden on low-income consumers who are just above the threshold for qualifying for a social tariff. In
contrast, direct financial support that is financed through income taxation would avoid this and place a
higher burden on those with broader shoulders. For this reason, when it comes to the most effective means
of fighting energy poverty, well-targeted social policy measures and investments in energy efficiency,
rather than social tariffs, are essential
Option 2a
Option 2a consists of requiring Member States to progressively phase out price
regulation for households above a certain consumption threshold to be defined in new EU
legislation or by Member States, with support from Commission services.
Costs
The main costs associated with the implementation of this option are linked to the
financing of the subsidised energy amount for all beneficiaries of the measure (all
households).
For the purpose of this analysis we assumed that all Member States applying price
regulation in the energy markets would deliver 30% of consumption of electricity for all
households at a reduced rate of 20% less than the average regular price163
. This level was
selected based on the current implementation of various social tariff schemes across
Member States, which point towards a reduction in the overall annual bill of 10-30%.
However this scheme applies to all households rather than vulnerable households only.
These values are for illustrative purposes only and the final amount can be varied
depending on the preferences of the Member States implementing the measure.
Under Option 2a the electricity consumption is subsidised for all households for the first
30% and the costs are evenly spread across all consumers.
The impacts on the final consumer bill are presented per Member State in the graphs
below – there is very little impact on the final bill of the households due to the fact that
the discount is available to all households and is also financed by all households.
However, the average final bill would be lower for households consuming less electricity
than the average and higher for households consuming more than the average. Therefore,
this option might incentivise households to lower their energy consumption but it could
also penalise lower income households which use more electricity than the average due
to poor building insulation, lower energy efficient appliances or higher than average
people per household.
163
Eurostat, 2014, Average prices excluding all taxes and levies - based on average consumption
436
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Figure 19: Option 2a cross-country comparison of average annual electricity costs
per household before and after the introduction of a subsidised amount of electricity
0
100
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€
Kw/h
Bulgaria
before policy
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Cyprus
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437
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0
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Denmark
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Spain
before policy
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measure
438
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0
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€
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€
Kw/h
Greece
before policy
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measure
439
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0
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€
Kw/h
Croatia
before policy
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measure
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0 1000 2000 3000 4000 5000 6000
€
Kw/h
Hungary
before policy
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measure
440
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0
100
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0 1000 2000 3000 4000 5000 6000
€
Kw/h
Italy
before policy
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after policy
measure
0
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0 1000 2000 3000 4000 5000 6000
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Kw/h
Lithuania
before policy
measure
after policy
measure
441
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0
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€
Kw/h
Latvia
before policy
measure
after policy
measure
0
100
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€
Kw/h
Malta
before policy
measure
after policy
measure
442
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0
100
200
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500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Poland
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Portugal
before policy
measure
after policy
measure
443
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Benefits
In comparison to Option 1 the benefits linked to price deregulation under Option 2a can
be expected to be fewer as a greater share of the retail market is covered by regulated
prices under Option 2a.
However, in comparison to the current situation, if the consumption threshold beyond
which prices are de-regulated was lowered across Member States currently applying
price regulation, the net effect of the measure would be beneficial in terms of introducing
more competition in the retail energy markets.
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Romania
before policy
measure
after policy
measure
0
100
200
300
400
500
0 1000 2000 3000 4000 5000 6000
€
Kw/h
Slovakia
before policy
measure
after policy
measure
444
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Comparison between Option 1 and Option 2a
Option 1 specifically targets the support measures for vulnerable consumers, such that
the discounted rate for purchasing electricity is only available to vulnerable consumers.
Option 1 also allows greater benefits from the energy market opening in terms of more
competition, more consumer choice, better quality of services and more innovation. On
the contrary, under Option 2a a lower amount of energy will be subsidised but the
subsidy/support will be delivered to all households, regardless of their situation. This
means lower support for vulnerable consumers under Option 2a, as shown in Table 8
which indicates the total amounts of electricity subsidised for vulnerable consumers
under Option 1 and 2a. At the same time Option 2a delivers lower degree of market
opening and therefore lower competition within the market and fewer benefits associated
with market competition.
Table 8: Comparison of residential TWh subsidised in comparison to total
residential TWh consumed
Option 1 Option 2a
Share of
vulnerable
households
Total HH
consumption
Total
electricity
subsidised
for
vulnerable
consumers
Total
electricity
subsidised
-
vulnerable
households
Total electricity
subsidised non-
vulnerable
households
Total
electricity
subsidised for
all households
TWh TWh TWh TWh TWh
BG 41% 10.6 4.3 1,3 1,9 3.2
CY 28% 1.4 0.4 0,1 0,3 0.4
DK 3% 10.1 0.3 0,1 2,9 3.0
ES 11% 70.7 7.8 2,4 18,8 21.2
FR 6% 149.4 8.8 2,6 42,2 44.8
GR 33% 17.2 5.6 1,7 3,5 5.2
HR 10% 5.6 0.5 0,2 1,5 1.7
HU 12% 10.4 1.2 0,4 2,8 3.1
IT 18% 64.3 11.6 3,5 15,8 19.3
LT 27% 2.7 0.7 0,2 0,6 0.8
LV 17% 1.7 0.3 0,1 0,4 0.5
MT 22% 0.6 0.1 0,0 0,1 0.2
PL 9% 28.0 2.5 0,8 7,6 8.4
PT 28% 11.9 3.4 1,0 2,6 3.6
RO 12% 11.9 1.5 0,4 3,1 3.6
SK 6% 4.9 0.3 0,1 1,4 1.5
EU-16 Totals 13% 401,5 49,4 14,8 120,4 135,2
Source: INSIGHT_E
While the total subsidised energy is much higher in the case of Option 2a, the amount of
energy subsidised for vulnerable customers is lower which indicated a lack of targeting
of the measure.
As regards administrative costs for implementing the measures, the blanket approach
(lack of identification of a targeted group of beneficiaries) used in Option 2a does not
require resources for the identification of vulnerable households. However, these
445
Phasing out regulated prices
administrative costs linked to the identification of vulnerable consumers can be expected
to be minimal as authorities responsible for identifying socially vulnerable groups are
already operating in all Member States.
Finally, a comparison of costs between these two options needs to take into account that,
in the case of Option 1, costs associated with the implementation of social tariffs would
be limited in time due to the temporary nature of the measure, while in the case of Option
2a there is no foreseen end-date for subsidising a specific amount of energy consumption.
Option 2b
Option 2b consists of requiring Member States to progressively phase out below-cost
price regulation for households by a deadline specified in new EU legislation
Costs
This option allows price regulation defined at levels that cover the costs incurred by the
energy undertakings, therefore no subsidisation is necessary. This option does not
involve financing of any new measure therefore a quantitative estimation of costs cannot
be performed.
Main costs would be linked to the adoption and implementation of roadmaps foreseeing
gradual achievement of cost-reflectiveness of price regulation in the Member States
concerned. The main and key challenge for the implementation of this option would be to
define methodologies for defining cost coverage of energy prices at EU level in a context
where cost structures of market actors are opaque. Moreover, ensuring cost-reflectiveness
by regulation would imply considerable regulatory and administrative impact.
Benefits
The main benefits of this option would be to limit the distortive effect of price regulation
and tackle tariff deficits.
However it is necessary to point to the potential risks associated with energy prices being
regulated below costs, such as the accumulation of tariff deficits.
In a study164
carried out at the request of the European Parliament, a hypothetical case
study shows that in a country where the retail market price for electricity is 0.20 euro per
kWh for domestic customers and the regulated tariff is set at 0.18 euro per kWh, the tariff
deficit would be 0.02 euro per kWh. If there are 15 million domestic customers with an
average annual electricity consumption of 3 000 kWh, of whom 80 per cent are supplied
at the regulated tariff, the result would be a total tariff deficit of 720 million euro per
164
"Cost of Non-Europe in the Single Market for Energy" (2013) Institute for European Environmental
Policy at the request of the European Parliament, available at:
http://www.europarl.europa.eu/RegData/etudes/etudes/join/2013/504466/IPOL-
JOIN_ET(2013)504466(SUM01)_EN.pdf
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year. One may compare the size of the country in this hypothetical illustrative case (15
million domestic customers) with a country of the size of Spain or Poland.
Figure 20: Tariff deficit
Source: European Parliament165
Regulated end-user prices reflecting actual costs would ensure remuneration for the
suppliers/generators providing them some economic incentives for investment in new
and existing generation capacities and in demand reduction measures.
This option could be implemented by progressively increasing the level of regulated
prices in countries where they are not cost covering with the objective of achieving cost
covering and contestable end user prices. Provided that the level of regulated prices will
ensure cost coverage incurred by the suppliers subject to price regulation plus a
reasonable profit margin, such measure would stimulate the competition on the retail
market by encouraging new entries and allowing existing non-regulated suppliers to gain
more market share by proposing better offers to customers. Such incentives would
however be limited, directly dependent on the profit margin allowed through the chosen
methodology.
It can be expected that benefits linked to enhanced competition on the retail market
resulting from the implementation of this option would be more limited compared to
Option 1 or 2a mainly due to the lack of limitation of allowed price regulation (as regards
the scope of beneficiaries or the regulated amount of energy) which would result in a
more important market distortion.
One example of above costs price regulation is through a cost-of-service regulation166
,
under which a company is allowed to charge end customers its total incurred costs
165
"The Cost of Non-Europe in the Single Market for Energy" (2013) European Parliament
166
"Regulation of the Power Sector" (2013) Ignacio J. Pérez-Arriaga
447
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(investment costs plus operation costs), where the investments costs include a fair return
on investment.
This example was studied by Pérez-Arriaga167
who identified that the main advantage of
this type of regulation is that it ensures that customers do not overpay and investors are
not undercompensated at any given time. However there are also important risks and
disadvantages linked to such approach, as shown in the table below.
Cost-of-service regulation
Pros Cons/risks
Ensures a fair price at any given time (customers do
not overpay and investors are not
undercompensated)
Ensures regulatory stability
Guarantees cost recovery (via suitable
remuneration), providing a favourable investment
climate, reducing capital costs
Guarantees high levels of security of supply for
electricity customers.
Possible cost inflation due to :
- Information asymmetries: utilities have much
more precise cost and demand data than the
regulator, who needs them in the tariff review
process. Information may therefore be manipulated
by regulated companies to bring in higher revenues
that cannot subsequently be recorded as earnings,
but which can be earmarked for certain cost items
(such as higher salaries or a larger headcount).
- Lack of incentives for efficient management:
keeping costs as low as possible (for a given
amount and quality of service) calls for some effort
from company managers. Under the traditional
system of regulation, managers have no incentive to
make this effort since, if costs grow, revenues are in
principle automatically adjusted to absorb the
difference.
- Regulator capture: utilities usually have a wealth
of resources that can be deployed to influence
regulator decisions in their favour. This undue
influence on regulatory decisions, called ‘‘regulator
capture’’, may be exerted in a variety of ways,
including all forms of lobbying, communication
campaigns, regulator hire by the regulated utilities
and vice versa (so-called revolving doors).
Source: "Regulation of the Power Sector" (2013) Ignacio J. Pérez-Arriaga
It becomes clear that, while this type of price regulation might appear as keeping end
customer prices under control while allowing a fair remuneration for energy utilities, it is
not exempted from risks of abuse by utilities. Therefore, the objective of protecting
customers from possible abuse by utilities in setting the price which is sometimes
invoked as justification for maintaining some form of price regulation does not seem to
be fully ensured by implementing this option.
167
"Regulation of the Power Sector" (2013) Ignacio J. Pérez-Arriaga
448
Phasing out regulated prices
Subsidiarity
7.2.6.
Different national approaches to opening of the market for electricity and gas supply to
households prevent the emergence of a genuine internal energy market for household
customers. More specifically, we observe a wide range of criteria for defining the
beneficiaries of price regulation (consumption threshold, in some cases combined with
vulnerability criteria).
Under the EU acquis (Art. 14 TFEU, Protocol on SGEI), the Commission has assumed
the role of the guardian of both free competition and general interest. The interpretation
of the Treaty by the Court of Justice has in some cases allowed a restriction on
competition if necessary for the accomplishment of special tasks. Moreover, the adopted
and proposed legislation in the field of regulated public services shows how both free
competition and restrictions on competition can have a place if required for the
accomplishment of special tasks.
The balance between both aspects is subject to the principle of proportionality, implying
that the restriction on competition should be no greater than is required to accomplish the
special tasks. In defining the proportionality principle, EU legislation can specify the
scope of beneficiaries for price regulation (consumption threshold) or the cost coverage
condition.
EU action obliging Member States to progressively adopt less restrictive measures to
achieve the objectives of general interest justifying price regulation is necessary in order
to minimize the negative effect of regulated prices which represent an important barrier
to retail competition, including cross-border. The added value of EU action with respect
to the deregulation of end-user electricity and gas prices has been highlighted by the
European Parliamentary Research Service in a study on "The Cost of Non-Europe in the
Single Market for Energy"168
which considers the possibilities for gains and/or the
realisation of a 'public good' through common action at EU level in specific policy areas
and sectors. This study identifies regulated end-user prices among the areas that are
expected to benefit most from deeper EU integration, where the EU added value is
potentially significant.
Stakeholders' opinions
7.2.7.
Public consultation
The outcome of a public consultation carried out by the European Commission from 22
January 2014 to 17 April 2014 has confirmed that market-based customer prices are an
important factor in helping residential customers and SMEs better control their energy
consumption and costs (129 out of 237 respondents considered that it was a very
important factor while other 66 qualified it as important for the achievement of the said
objective).
168
http://www.europarl.europa.eu/RegData/etudes/etudes/join/2013/504466/IPOL-
JOIN_ET(2013)504466(SUM01)_EN.pdf
449
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Moreover, out of 121 respondents who considered that the level of competition in retail
energy markets is too little, 45 recognised regulation of customer prices as one of the
underlying drivers.
National Regulatory Authorities
ACER identifies price regulation as one of the barriers to entering retail energy markets,
in particular in Member States where regulated prices are set below cost levels, which
hampers the development of a competitive retail market. It shows that even in other
Member States where end-user prices are set with reference to wholesale prices, which is
the preferred approach, they may negatively impact the customers’ propensity to switch.
Therefore, ACER recommends that, where justified, regulated prices should be set at
levels which avoid stifling the development of a competitive retail market. They must be
consistent with the provisions of the Third Package, and should be removed as soon as a
sufficient level of retail competition is achieved.
The body representing the EU's national regulatory authorities in Brussels, CEER (
The
Council of European Energy Regulators), identifies as well regulated end-user prices
among the barriers to entry for energy suppliers into retail gas and electricity markets
across the EU. It shows that in the situation where regulated prices are set below cost, or
with a too limited margin to cover the risk of activity, they discourage investments and
the emergence of newcomers.
In their reply to the question “Do you consider regulated end-user prices as a significant
barrier to entry for energy suppliers in your MS and have you taken initiatives to remove
it?” included in a questionnaire169
addressed by CEER to NRAs in 2016, NRAs from
countries with price regulation considered them as a significant barrier to entry for
alternative suppliers. All Member States, where NRAs consider regulated prices as a
significant barrier, are planning to remove them, at least for non-household customers.
In general, NRAs emphasised the need to “facilitate the phasing out of regulated end
user prices, as soon as practicable, whilst ensuring that customers are properly
protected where competition is not yet effective”, as expressed in the conclusions of the
ACER / CEER Bridge to 2025.
As part of a roadmap for phasing-out regulated prices, most of the concerned NRAs state
that regulated prices should first be aligned with supply costs. They also point out the
role of the NRA to define the appropriate methodology and to control end-user prices
evolution.
Some NRAs suggest that the final decision for end-user prices withdrawal should depend
on the level of competition in the market, which could be assessed by the NRA, like the
169
"Benchmarking report on removing barriers to entry for energy suppliers in EU retail energy markets"
(2016) CEER, available at
http://www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Custom
ers/Tab6/C15-RMF-70-03_BR_barriers_to_entry_for_suppliers_1-Apr-2016.pdf
450
Phasing out regulated prices
number of market participants and their market share, the transparency of structure and
rules of market functioning, a non-discriminatory treatment on the market.
Eventually, some NRAs note the need to protect vulnerable and low income household
customers.
Suppliers
EUROGAS170
supports the distinction between regulated end-user prices and social
tariffs. It states that specific, time-limited and appropriate regulated end-user prices may
be necessary in circumstances where market forces are not yet in place (in pre-
competitive markets notably to ensure headroom for new entrants and to protect
customers from market abuse). They should then be generally widely available for
customers in those Member States, irrespective of their economic position and should not
be set below market price or below cost, to minimise distortions and barriers to entry.
Social tariffs where they exist can and should also be organized without market
distortions. Member States should not be able to use energy poverty definitions in such a
way as to block market development.
In their contribution to the discussions within the workshop on the issue of electricity and
gas price (de)regulation organised by the European Commission in the context of the on-
going work on the future Electricity Market Design on 3 June 2016, EURELECTRIC
agreed that regulated prices represent a barrier to entry to new suppliers and that they
discourage competition on services.
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Customers, the Parliament's Committee on Industry, Research and
Energy (ITRE): " Considers that phasing out regulated energy prices for customers
should take into account the real level of market competition in the Energy Union
Strategy context, which should ensure that customers have access to safe energy prices"
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Customers, the Parliament's Committee on the Internal Market and
Customer Protection (IMCO) " Urges the Commission to take concrete action to better
link wholesale and retail energy markets, so as to better reflect falling wholesale costs in
retail prices and to achieve a gradual phasing-out of regulated prices, and to promote
responsible customer behaviour, by encouraging Member States to seek other means to
prevent energy poverty; recalls that prices set by the market benefit customers; ".
Consumer Groups
In their contribution to the discussions within the workshop on the issue of electricity and
gas price (de)regulation organised by the European Commission in the context of the on-
going work on the future Electricity Market Design, BEUC has argued that price
170
Eurogas press release available at: http://www.eurogas.org/uploads/media/2015-June_-
_15PP282__Eurogas_Position_Paper_on_Vulnerable_Customers.pdf
451
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regulation should be a transitional tool before a certain level of competition is achieved
on the retail market. In any case, it stated that prices should be fixed at contestable levels
to allow alternative suppliers to compete. Moreover, an adequate market design should
be the prerequisite for price deregulation.
452
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453
Creating a level playing field for access to data
7.3. Creating a level playing field for access to data
454
Creating a level playing field for access to data
Summary table
7.3.1.
Objective: Creating a level playing field for access to data.
Option: 0 Option 1 Option 2
BAU
Member States are primarily
responsible on deciding roles and
responsibilities in data handling.
- Define responsibilities in data handling based on appropriate definitions in the
EU legislation.
- Define criteria and set principles in order to ensure the impartiality and non-
discriminatory behaviour of entities involved in data handling, as well as timely
and transparent access to data.
- Ensure that Member States implement a standardised data format at national
level...
- Impose a specific EU data management model (e.g. an
independent central data hub)
- Define specific procedures and roles for the operation of
such model.
Pro
Existing framework gives more
flexibility to Member States and NRAs
to accommodate local conditions in
their national measures.
Pro
The above measures can be applied independently of the data management model
that each Member State has chosen.
The measures will increase transparency, guarantee non-discriminatory access and
improve competition, while ensuring data protection.
Pro
Possible simplification of models across EU and easier
enforcement of standardized rules.
Con
The current EU framework is too
general when it comes to
responsibilities and principles. It is not
fit for developments which result from
the deployment of smart metering
systems.
Con Con
High adaptation costs for Member States who have already
decided and implementing specific data management models.
Such a measure would disproportionally affect those Member
States that have chosen a different model without necessarily
improving performance.
A specific model would not necessarily fit to all Member
States, where solutions which take into account local
conditions may prove to be more cost-efficient and effective.
Most suitable option(s): Option 1 is the preferred option as it will improve current framework and set principles for transparent and non-discriminatory data access from eligible market
parties. This option is expected to have a high net benefit for service providers and consumers and increase competition in the retail market.
455
Creating a level playing field for access to data
Description of the baseline
7.3.2.
Legal Framework
Annex I (paragraph 1(h)) of the Electricity Directive set some basic requirements
regarding data access from consumers and suppliers, and for the party responsible for
data management. It also provides that data should be shared by explicit agreement and
free of charge.
Article 41 of the Electricity Directive provides that Member States shall be responsible
for setting responsibilities of TSOs, DSOs, suppliers, customers and other market
participants with respect to contractual arrangements, commitments to customers, data
exchange and settlement rules, data ownership and metering responsibility.
Assessment of current situation
Access to consumption data will support the deployment of distributed energy resources
and the development of new flexibility services. This is true not only in relation to
flexibility that system operators may use when planning and operating their networks,
but also to flexibility that will be used in the wholesale markets for achieving wider
system benefits.
Currently different models for the management of data have been developed or are under
development across the EU (e.g. data handled by DSO, TSO, or an Independent Data
Hub). The activity of handling metering data is closely linked to the traditional metering
activity. In the majority of Member States DSOs are responsible for installing and
operating the smart metering infrastructure and they are also responsible for collecting
consumption data and consequently being involved in the handling process of these data.
From a European policy perspective it is important to ensure the impartiality of the entity
which handles data and to ensure uniform rules under which data can be shared.
Table 2 presents the responsible entity in each Member State for the metering activity
(market regulated/non-regulated), and the responsible entity for the roll-out of smart
metering infrastructure, as well as for access to data171
.
171
"Benchmarking smart metering deployment in the EU-27 with a focus on electricity". COM(2014) 356
final
456
Creating a level playing field for access to data
Table 2: Data handling model in Member States with smart metering systems
(implemented or planned)
Source: COM(2014) 356 final
According to the above data in the majority of Member States the DSO is the responsible
party for metering activity and smart meters, as well as for data access. However,
regarding data access more recent information indicates that some Member States such as
Finland and Sweden are planning a central data hub under the responsibility of the TSO.
In general it is observed, that in countries with a high number of DSOs (e.g. SE, FI) it
seems to be more effective to introduce a central hub which will collect information from
several DSOs and provide access to these data to third parties. In such cases it is expected
that transparency and efficiency in the market will increase, while data will be easily
available to retailers and consumers.
However, different data handling models do not exclude responsibility and involvement
of DSOs, in most of the cases they are responsible for smart meters and participate in the
data handling process. This means that even if they are not assuming a central role in data
handling (e.g. the case of France or Italy), they will collect consumption data and
communicate these data to a central hub.
457
Creating a level playing field for access to data
Requirements of Article 1(h) of Annex I have been subject to formal actions against
several Member States.
Deficiencies of the current legislation
7.3.3.
The Evaluation illustrates how one of the main objectives of the Electricity Directive was
to improve competition through better regulation, unbundling and reducing asymmetric
information. In general, unbundling measures contribute to the contestability of the retail
market and thus facilitate market entry by third party suppliers.
The implementation of smart metering systems in 17 Member States will generate more
granular consumption data and new business opportunities in the retail market. Data
management models for handling those data are accompanied by procedures which
facilitate the retail market and improve processes such as switching, billing, settlements
etc.
The existing provisions of the Electricity Directive provide a general framework under
which each Member State can decide its data management model and procedures of data
handling. This framework however needs to be enhanced and updated in terms for
instance of eligible market parties who should be allowed to access consumers' data,
authorization of parties which handle data, simple procedures and interoperable data
format. Indeed, Section 7.3.6 and Annex IX of the Evaluation show that the current
legislation was not designed to address currently known challenges in managing large,
commercially valuable consumption data flows.
Presentation of the options
7.3.4.
Under Option 0 (BAU) Member States are responsible to develop their own data
handling model in line with rules of the Third Package and the related data protection
legislation. Member States are responsible for developing their own data handling
models in line with rules of the Third Package and the related data protection legislation.
A stronger enforcement and/or voluntary cooperation (Option 0+) has not been
considered as the existing EU framework provide only minimum requirements which
need to be updated in line with the developments in the retail market and the introduction
of smart metering systems, while voluntary cooperation would only deliver a set of best
practices that Member States could share, but it would not be adequate for setting the
necessary principle for a transparent and non-discriminatory exchange of data.
Under Option 1 Member States will continue to be responsible for the development of
the data management model; however, more explicit requirements will be introduced
regarding responsibilities in data handling based on appropriate definitions and
principles. Also, criteria and measures will be introduced to ensure the impartiality and
non-discriminatory behaviour of entities involved in data handling, as well as timely and
transparent access to data. Member States will also have to implement a standardised
data format in order to simplify retail market procedures and enhance competition.
Measures under this option will also ensure data protection in line with the requirements
of Regulation (EU) 2016/679 on the protection of personal data and Recommendation
2014/724/EU on the Data Protection Impact Assessment Template for smart grids and
smart metering systems.
Under Option 2 each Member State will have to implement a specific data management
model and procedures described in EU legislation.
458
Creating a level playing field for access to data
Comparison of the options
7.3.5.
a. The extent to which they would achieve the objectives (effectiveness);
The main objective is to ensure that data handling models support equal data access and
facilitate retail market competition.
Option 0 would mean no further measures from the existing framework set in the
Electricity Directive. Member States would be practically completely responsible for
setting the general framework and the detailed regulation on data management models,
access rules and principles, roles and responsibilities of market actors etc.
Data access is highly important for supporting new services and for facilitating
competition, especially where smart metering systems exist. Option 0 would not
guarantee that national frameworks will accommodate all necessary elements in order for
instance to allow data access to a minimum of service providers besides suppliers.
Moreover, the current framework does not include any measures in order to avoid
privileged access to information from service providers which are affiliated to operators
which collect and store data (e.g. DSOs).
Option 1 seeks to address deficiencies of Option 0 by enhancing the existing framework
and set minimum requirements in terms of eligible market parties which should have
access to data, specific principles, and ensuring consumers' privacy. Moreover, this
option will set some minimum safeguards in order to avoid privileged access to data of
commercial value. The level of effectiveness of this option will depend on the specific
implementation in each Member State and the detailed national rules, as measures under
this option will set the basic EU framework.
Option 2 is considered to be less effective compared with the other two options as it will
entail full harmonisation of data management models and rules across EU Member
States. As in many Member States (e.g. UK, IT, FR, FI, NL, AT etc.) the data
management models have been already implemented or planned, the imposition of a
different model (e.g. independent data hub), would entail a restructuring of the existing
models.
The above policy options were developed in the context of the Digital Single Market172
and the Energy Union which include the strong and efficient protection of fundamental
rights in a developing digital environment. One of the objectives should be to ensure
widespread access and use of digital technologies while at the same time guaranteeing a
high level of the right to private life and to the protection of personal data as enshrined in
Articles 7 and 8 of the Charter of Fundamental Rights of the EU.
172
In the context of the Digital Single Market the Commission will propose a European free flow of data
initiative with the aim to promote free movement of data in the European Union. The initiative will
tackle restrictions to data location and access to encourage innovation. The Commission will also
launch a European Cloud initiative, covering certification, switching of cloud service providers and a
research cloud (https://ec.europa.eu/digital-single-market/en/economy-society-digital-single-market).
459
Creating a level playing field for access to data
The policy options proposed (from compliance with data protection legislation and the
Third Package - Option 0; to further introduction of specific requirements on data
handling responsibilities based on principles of transparency and non-discrimination -
Option 1; and implementation of a specific data management model to be described in
EU legislation - Option 2) seek to ensure the impartiality of the entity which handles data
and to ensure uniform rules under which data can be shared. Access to a consumer's
metering or billing details can only happen when authorised by that consumer and under
the condition that the personal data protection and privacy are guaranteed.
The policy options are fully aligned and further substantiate the fundamental rights to
privacy and protection of personal data of Articles 7 and 8 of the Charter of Fundamental
Rights of the EU, as well as with the General Data Protection Regulation (EU Regulation
2016/679 modifying Directive 95/46/EC) and with Commission Recommendation
2014/724/EC on the Data Protection Impact Assessment Template for Smart Grid and
Smart Metering Environments.
b. Key economic impacts and benefit/cost ratio, cost-effectiveness (efficiency) &
Economic impacts
Option 1 is expected to yield higher net benefits in comparison with option 0, as it will
set principles for an open and more competitive retail market. Moreover, specific
procedures of the market such as switching are expected to improve with stricter
requirements on the data format.
An overall positive effect on the energy market can be expected. Active and well-aware
consumers are more likely to make informed decisions, from choosing their energy
supplier to consumption decisions. More consumers might switch their supplier, which
will foster competition in the retail market. Active consumers might also consider third
party services such as applications to reduce or optimise their energy consumption, which
would amplify the market for third party activities. Different initiatives and business
models could simplify the interaction between consumers and third parties, and therewith
further increase the market potential of third party services173
.
Moreover, direct feedback for example on real time consumption data and energy prices,
could have a substantial impact on energy savings. Evidence from Ireland and the UK
show that energy savings can reach up to 2.5% and 8.8% in peak hours174
.
173
Like for instance the Green Button initiative in US where consumers can easily give access to their
consumption data to third parties who automatically receive a standardized data-package for that
consumer; the initiative positively affected the overall business case of third parties ("Green Button:
One Year Later" (2012) IEE Edison Foundation). Another example of such initiative is the Midata
initiative in UK (http://www.gocompare.com/money/midata/) which concerns energy and other
sectors; as energy firms are increasingly taking on board the need to provide customers with
downloadable data to better understand their gas and electricity usage, Midata initiative aims to further
encourage this practice across all energy suppliers and to make it easier to upload this data to
comparison sites.
174
Intelligent Energy Europe (2012): "European Smart Metering Landscape Report 2012"; Ofgem
(2011): "Energy Demand Research Project: Final Analysis" (study conducted by AECOM for
Ofgem).
460
Creating a level playing field for access to data
A main benefit of ensuring interoperability between different data systems is the easy
access to new markets for commercial actors such as energy suppliers or aggregators.
Ensuring for instance uniform formats for consumption data reduces entry barriers for
commercial actors seeking to establish in other Member States. This could enhance
competition in the supplier and aggregator market. Ensuring interoperability would imply
agreeing to a common standard at national level, which would induce some costs such as
administrative costs for defining and concurring on the new format, especially to data
administrators (DSOs or data hubs) who will have to adapt their system to a new
common format. Depending on the case such costs might be significant, as a number of
existing data handling systems and the involved entities would have to adjust to the new
standards (suppliers, DSOs, third parties, data administrators). However, it is expected
that on an aggregated level these costs will not exceed benefits.
The implementation of Option 2 would entail high administrative costs. Determining a
mandatory data handling model will imply administrative costs of defining and designing
such a model, and more importantly high sunk costs for existing data handling models
and additional costs for establishing a new one, both in terms of personnel costs and IT
infrastructure. Designing and building a new data handling model is a complex procedure
and may well take several years of planning and implementation. In Denmark, the central
data hub took more than 4 years to design and develop in its simple form, and 7 years in
its enhanced form, and is estimated to a cost of approximately 165 million euros, where
approximately 65 million euros accrued to the data hub administrator (the TSO), and
around 100 million euros accrued to DSOs and energy suppliers. Therefore, the costs of
redesigning already implemented data handling models across the EU are therefore likely
to be substantial.
c. Simplification and/or administrative impact for companies and consumers
Option 2 for data management would result in high administrative costs affecting
existing structures as well as possibly energy companies and consumers.
d. Impacts on public administrations
Impacts on public administration are summarized in Section 7 below.
e. Trade-offs and synergies associated with each option with other foreseen measures
Options 1 and 2 for data management are clearly also associated with demand response
and smart metering. Smart meters will provide granular data which should be accessible
from service providers for settlement or support of services. A well-functioning data
management model is therefore crucial for the provision of demand response services.
f. Likely uncertainty in the key findings and conclusions
There is a medium risk associated with the uncertainty of the assessment of costs and
benefits of the presented options. However, it is considered that this risk cannot influence
the decision on the preferred option as there is a high differentiation among the presented
options in terms of qualitative and quantitative characteristics.
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Creating a level playing field for access to data
g. Which Option is preferred and why
Option 1 is the preferred option as it will improve current framework and set principles
for transparent and non-discriminatory data access from eligible market parties. This
option is expected to have a high net benefit for service providers and consumers and
increase competition in the retail market.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the
preceding pages, accrue evenly to all consumers. The measures can therefore be considered neutral in
nature i.e. they do not redistribute surplus between higher- and lower-income ratepayers.
Subsidiarity
7.3.6.
The EU has a shared competence with Member States in the field of energy pursuant to
Article 4(1) of the Treaty on the Functioning of the European Union (TFEU). In line with
Article 194 of the TFEU, the EU is competent to establish measures to ensure the
functioning of the energy market, ensure security of supply and promote energy
efficiency.
Uncoordinated, fragmented national policies in the electricity sector may have direct
negative effects on neighbouring Member States, and distort the internal market. EU
action therefore has significant added value by ensuring a coherent approach in all
Member States.
An effective EU framework for data management which puts in place rules and
principles will give to electricity consumers more choices, better access to information
and will facilitate competition in the electricity market. Moreover, through effective data
management models and efficient procedures consumers will have access to more energy
service providers and actively participate in the electricity market. Active participation of
consumers and facilitation of demand response and energy efficiency service will
contribute to the completion of the internal energy market and support security of supply.
Envisaged measures do not aim to alter the structure of existing or planned national data
management models, but to set requirements which will enhance fundamental consumer
rights and support a competitive internal energy market.
Stakeholders' opinions
7.3.7.
3.2.7.1. Results of the consultation on the new Energy Market Design
According to the results of the public consultation on a new Energy Market Design175
the
respondents view active distribution system operation, neutral market facilitation and
data hub management as possible functions for DSOs. Some stakeholders pointed at a
potential conflict of interests for DSOs in their new role in case they are also active in the
supply business and emphasized that the neutrality of DSOs should be ensured. A large
number of the stakeholders stressed the importance of data protection and privacy, and
175
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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Creating a level playing field for access to data
consumer's ownership of data. Furthermore, a high number of respondents stressed the
need of specific rules regarding access to data.
Governance rules for DSOs and Models of data handling
Question: "How should governance rules for distribution system operators and access to
metering data be adapted (data handling and ensuring data privacy etc.) in light of
market and technological developments? Are additional provisions on management of
and access by the relevant parties (end-customers, distribution system operators,
transmission system operators, suppliers, third party service providers and regulators) to
the metering data required?"
Summary of findings:
The majority of stakeholders consider access to data by consumers and relevant third
parties under specific rules as an important element for the development of an open and
competitive retail market. Moreover, it is crucial to ensure data privacy and ownership of
data by consumers.
Regarding the data handling models, regulators and the majority of stakeholders from the
electricity industry believe that DSOs should act as neutral market facilitator. Some
stakeholders from the electricity industry suggest that the DSOs should undertake the
role of the data hub, providing an effective way to govern the data generated by smart
meters. On the other hand, IFIEC and few other stakeholders do not see favourably the
role of DSOs as market facilitator, the involvement of a third party is perceived to better
support neutrality and a level playing field.
National governments are divided on the best suitable model for data access and data
handling, around half of them advocate as the most favourable solution central data hubs.
Most of the Member States consider that the role of DSO and the model for data handling
should be best decided at national level.
Member States:
Given the central role of DSOs in metering and handling of data, Member States point
out the necessity for neutrality and independence of the DSO vis-à-vis other energy
stakeholders, while they consider that coordination between DSOs and TSOs should be
enhanced. Data need to be accessible in real-time or close to real-time for consumers and
relevant third parties, while data security and privacy is one of the most important aspects
for the acceptance of smart meters and the successful roll-out.
Some Member States promote central data hubs to collect and handle data (e.g. Denmark,
Estonia, Finland, Germany, Slovakia, and Sweden).
Some Member States (Czech Republic, France, Netherlands, and Slovakia) believe that
due to different local conditions in terms of available technologies and national
regulatory frameworks, detailed arrangements regarding data handling should be defined
at member State level through national legislation, and no further legislation is required
at EU level regarding the role of DSOs and the responsibilities for data handling.
On the other hand the Danish government considers that EU regulation should more
specifically define a minimum level of privacy and issues such as consumers' control
over their own data and non-discriminatory access to data by market players, while
harmonising the roles of market players and the kind of data they have access to. The
463
Creating a level playing field for access to data
Finnish government also calls for a clarification of the role of DSOs in the operation of
storage facilities and questions whether there is a need to revise unbundling rules.
Regulators:
Regulators stress the importance of neutrality in the role of the DSOs as market
facilitators. To achieve this will require to:
- Set out exactly what a neutral market facilitator entails;
- When a DSO should be involved in an activity and when it should not;
- NRAs to provide careful governance, with a focus on driving a convergent
approach across Europe.
Regulators consider that consumers must be guaranteed the ownership and control of
their data. The DSOs, or other data handlers, must ensure the protection of consumers’
data.
Electricity consumers:
The majority of stakeholders (BEUC, CEFIC, CEPI) agree that consumers should have
access to real time information, historical information, accurate billing and easy switch of
provider. Some of them (CEFIC, EURACOAL) believe that the DSOs should play a
central role in providing end-users with the necessary information. All electricity
consumer stakeholders agree that data protection must be assured.
IFIEC considers that DSOs should not play the role of market facilitator, the involvement
of a third party is perceived to better support neutrality and a level playing field.
Moreover, coordination of TSOs and DSOs and potentially extended role of DSOs with
respect to congestion management, forecasting, balancing, etc. would require a separate
regulatory framework. However, IFIEC express concerns that some smaller DSOs might
be overstrained by this. Extended roles for DSO should be in the interest of consumers
and only be implemented when it is economically efficient.
EUROCHAMBERS believes that due to different regional and local conditions a one
size fits all approach for governance rules for distribution system operators is not
appropriate. The EU could support Member States by developing guidelines (e.g. on grid
infrastructures and incentive systems).
Energy industry:
Most stakeholders (CEDEC, EDSO, ESMIG, ETP, EUROBAT, EWEA, GEODE)
believe that the role of DSOs should focus on active grid management and neutral market
facilitation. Some respondents state that the current regulatory framework prevents DSOs
from taking on some roles, such as procurer of system flexibility services and to procure
balancing services from third parties, and such barriers should be eliminated.
All stakeholders agree that the provision of data management services should be carried
out in a neutral and non-discriminatory manner with all appropriate protections for data
security, data privacy and the right of the consumers to control third party access to their
data. On this regard, GEODE highlights the need to have a clear distinction between
personal data (which belongs to the customer) and non-personal data which should be
provided to any relevant party who requests it, on a non-discriminatory basis.
According to Eurelectric, EWEA, ETP and GEODE, DSOs operating as data hub could
provide an effective way to govern the data generated by smart meters.
464
Creating a level playing field for access to data
Eureletric believes that the need for guaranteeing security of information and preventing
cyber-attacks could also be better ensured when there is only one entity in charge of
managing information flow. Mindful of the different unbundling situations in place in the
EU, DSOs should be responsible for data handling up to the metering point in a fully
unbundled context. Moreover, regulatory authorities should make sure that data
management beyond the meter takes place in a condition that ensures customer privacy
and it should be up to the consumers whether to receive their data through an
intermediary (a market party) or retrieve it from a web platform linked to the data hub.
Costs connected with data management should be recovered via network tariffs.
According to RGI, for privacy reasons most data should remain in the meter itself. Data
should be stored in and regulated by a public server in an aggregated and formatted way
only dealing with the strictly necessary information. TSOs should have access to relevant
data, reflecting the actual energy portfolio and installed capacity per source at any given
time.
Also SEDC envisages that DSOs should be neutral market facilitators where unbundling
is fully implemented. However, in this scenario DSOs should not be active in markets
such as for demand response, as this would undermine their neutrality.
In relation to a possible EU intervention on the topic, GEODE suggests that Commission
should lay down generic principles rather than specific provisions, taking into account
that different Member States implement different models on the treatment of smart
metering data.
3.2.7.2. Public consultation on the Retail Energy Market
According to the results of the 2014 public consultation on the Retail Energy Market176
the majority of the respondents consider that DSOs should carry out tasks such as data
management, balancing of the local grid, including distributed generation and demand
response, and connection of new generation/capacity (e.g. solar panels).
81% of the respondents agreed that allowing other parties to have access to consumption
data in an appropriate and secure manner, subject to the consumer's explicit agreement, is
a key enabler for the development of new energy services for consumers.
3.2.7.3. Electricity Regulatory Forum - European Parliament
Relevant conclusions of the 31st
EU Electricity Regulatory Forum:
- "The Forum supports the cooperation of TSOs and DSOs on data management,
considering it an important step in finding common solutions to system operation
and system planning. It acknowledges the need to identify at EU-level a set of
common principles, roles, responsibilities and tasks concerning data
management, which will enable the development of new services and the active
participation of consumers in the future energy system while ensuring data
protection and leaving room for implementation at national level."
176
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
465
Creating a level playing field for access to data
European Parliament resolution of 26 May 2016 on delivering a new deal for energy
consumers (2015/2323(INI)):
"29. Believes that consumers should have easy and timely access to their consumption
data and related costs, to help them make informed decisions; notes that only 16
Member States have committed to a large-scale roll-out of smart meters by 2020;
believes that where smart meters are rolled out Member States should ensure a solid
legal framework to guarantee an end to unjustified back-billing and a rollout that is
efficient and affordable for all consumers, particularly for energy-poor consumers;
insists that the benefits from smart meters should be shared on a fair basis between grid
operators and users;"
"33. Underlines that the collection, processing and storage of citizens’ energy-related
data should be managed by entities managing data access in a non-discriminatory
manner and should comply with the existing EU privacy and data protection framework
which lays down that consumers should always remain in control of their personal data
and that these should only be provided to third parties with the consumers’ explicit
consent; considers, in addition, that citizens should be able to exercise their rights to
correct and erase personal data;"
466
Creating a level playing field for access to data
467
Facilitating supplier switching
7.4. Facilitating supplier switching
468
Facilitating supplier switching
Summary table
7.4.1.
Objective: Facilitating supplier switching by limiting the scope of switching and exit fees, and making them more visible and easier to understand in the event that they are used.
Option 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Stronger enforcement, following the
clarification of certain concrete requirements
in the current legislation through an
interpretative note.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers, apart from: 1) exit fees
for fixed-term supply contracts; 2) fees
associated with energy efficiency or other
bundled energy services or investments. For
both exceptions, exit fees must be cost-
reflective.
Legislation to define and outlaw all fees to
EU household consumers associated with
switching suppliers.
Pros:
- Evidence may suggest a degree of non-
enforcement of existing legislation by
national authorities.
- No new legislative intervention necessary.
Pros:
- Non-enforcement may be due to complex
existing legislation.
- No new legislative intervention necessary.
Pros:
- Considerably reduces the prevalence of fees
associated with switching suppliers, and
hence financial/psychological barriers to
switching.
Pros:
- Completely eliminates one
financial/psychological barrier to switching.
- Simple measure removes doubt amongst
consumers.
- The clearest, most enforceable requirement
without exceptions.
Cons:
- Continued ambiguity in existing legislation
may impede enforcement.
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
Cons:
- The vast majority of switching-related fees
faced by consumers are permitted under
current EU legislation.
- Certain Member States might ignore the
interpretative note.
Cons:
- Marginally reduces the range of contracts
available to consumers, thereby limiting
innovation.
- An element of interpretation remains around
exceptions to the ban on fees associated with
switching suppliers.
Cons:
- Would further restrict innovation and
consumer choice, notably regarding financing
options for beneficial investments in energy
equipment as part of innovative supply
products e.g. self-generation, energy
efficiency, etc.
- Impedes the EU's decarbonisation
objectives, albeit marginally.
Most suitable option(s): Option 1 is the preferred option, as it represents the most favourable balance between probable benefits and costs.
469
Facilitating supplier switching
Description of the baseline
7.4.2.
The evidence presented in this annex draws extensively on survey data, as well as data
from a mystery shopping exercise. The aim of the mystery shopping exercise was to
replicate, as closely as possible, real consumers’ experiences across 10 Member States177
selected to cover North, West, South and East Europe countries. A total of 4,000
evaluations were completed between 11 December 2014 and 18 March 2015178
. Whilst
data from the mystery shopping exercise is non-exhaustive, the methodology enables the
controlled sampling of a very large topic area179
, as well as providing insights that would
not be apparent in a desktop evaluation of legislation and contractual terms. Using a
behavioural research approach rather than a traditional survey allowed us to identify what
people actually do, rather than what they say they do.
Switching rates180
for energy – a proxy for consumer engagement in the market – vary
considerably between Member States (0-15%), with electricity and gas comparing
unfavourably with many other consumer sectors such as vehicle insurance and mobile
telephony.
Figure 1: Switching provider by market - EU28
Source: Market Monitoring Survey, 2015
177
The Czech Republic, France, Germany, Italy, Lithuania, Poland, Slovenia, Spain, Sweden and the UK.
178
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
179
For example, there were over 400 electricity and gas supply offers in Berlin alone in 2014 (source:
ACER Database), making a comprehensive examination of all supply offers in the EU28
impracticable.
180
The percentage of consumers changing suppliers in any given year.
7%
8%
9%
9%
9%
9%
10%
10%
10%
13%
14%
15%
16%
16%
11%
+2.2*
+0.6
+1.0*
+2.3*
-0.6
+1.3*
+1.3*
+1.6*
+2.4*
+1.6*
+2.2*
+3.1*
+3.8*
+2.6*
+1.8*
-0.3
+0.2
+1.2*
-0.8*
-0.3
-0.4
-0.2
-0.7*
-0.4
+0.1
-0.7
+0.1
-0.4
-1.4*
-0.3*
-1.2*
+0.4
-0.9*
-2.2*
-0.6
-0.3
+0.1
-0.5
-0.2
-0.1
-0.2
0.0
-0.5
+1.0*
-0.4*
-0.6
+0.3
+0.2
+0.2
+1.8*
+0.2
-3.6*
+0.6
+1.3*
+0.5
-0.5*
Mortgages
Home insurance
Gas services
TV-subscriptions
Bank accounts
Private life insurance
Loans, credit and credit cards
Fixed telephone services
Electricity services
Internet provision
Investment products, private pensions and securities
Mobile telephone services
Commercial sport services
Vehicle insurance
Switching markets
Yes
Switching provider by market - EU28
Have you switched your <provider>? Diff
2015-
2013
Diff
2013-
2012
Diff
2012-
2011
Diff
2011-
2010
470
Facilitating supplier switching
Figure 2: Factors preventing electricity and gas consumers from switching – 2014 (1
– not at all important)
Source: ACER Questionnaire, February–April 2015
Consumer associations and NRAs report that insufficient monetary gain is the prime
obstacle to switching (Figure 2 above). An ACER questionnaire suggests that the
perceived minimum annual savings required by electricity consumers to switch in
Belgium, Germany, Italy, Latvia, Poland and Slovenia lie in the range of 0–100 euros,
whilst in the United Kingdom, the Netherlands, Portugal and Sweden, this was estimated
be 100–200 euros. The switching trigger ranges were the same for gas consumers, with
the exception of Italy, where switching trigger is estimated to be in the range of 100–200
euros.
Given that the difference in price between most offers in the market lie within
comparable ranges to switching triggers (Figure 3 below), switching suppliers is a
marginal decision for many household consumers. This highlights the importance of the
broad variety of fees that consumers may be charged when they switch, as these diminish
the (perceived) financial gains of moving to a cheaper tariff in what is already a marginal
decision for many consumers.
471
Facilitating supplier switching
Figure 3: Dispersion in the energy component of retail prices for households in
capitals – December 2014
Source: ACER Retail Database (November–December 2014) and ACER calculations
Whilst the data indicates that switching is free for most EU consumers, a minority still
face switching-related charges. First of all, exit (termination) fees may apply when
leaving a fixed-term or fixed-price contract early181
. The legitimacy of such fees are
acknowledged in EU legislation (see Section 7.4.3 below), and they are often put in place
to recoup the costs of equipment, discounts and/or other incentives provided at the
beginning of the contract. A mystery shopping exercise in ten Member States revealed
that whilst 77% of electricity suppliers stated that consumers would face no charges for
switching, 17% were warned that they may be charged an exit fee (Table 1), a figure
181
As sometimes occurs in Member States including NL and UK.
472
Facilitating supplier switching
corroborated by ACER data suggesting that exit fees are still common in at least 11
Member States for electricity and 3 Member States for gas (Figure 4).
Table 1: Electricity providers’ response when asked if there are any charges when
switching electricity provider
CZ DE ES FR UK IT LT PL SE SI Total
You will not be charged
for the change
60% 94% 83% 89% 59% 86% 80% 67% 66% 80% 77%
A fee for cancelling your
current energy deal (e.g.
exit fee for fixed rates)
40% 5% 11% 5% 38% 1% 0% 28% 32% 14% 17%
Another extra charge 0% 0% 7% 4% 3% 11% 8% 4% 2% 2% 4%
No response 0% 1% 0% 1% 0% 1% 12% 1% 0% 4% 2%
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
Figure 4: Existence of exit fees imposed by suppliers when switching offers - 2014
Aside from exit fees, however, the same mystery shopping exercise revealed that 4% of
mystery shoppers were told they may be charged other fees related to switching,
including administrative costs, start-up costs for a new or short-term service, or security
deposits (Box 1 below). This finding is notable because EU legislation ensures that
consumers "are not charged for changing supplier"182
. As checks by the Commission
182
This reading was recently supported by the body representing the EU's national regulatory authorities
– the Council of European Energy Regulators – who write: "The 3rd Energy Package Directives
473
Facilitating supplier switching
indicate that this legislation has been correctly transposed into Member State law, the
finding suggests either legal failures in the EU legislative text that prevent it from
fulfilling its intention and/or non-enforcement by national authorities.
Box 1: Examples of “extra charges” when switching mentioned by electricity
providers (when being contacted by phone)
- Administration cost (EUR 35) – France
- A service fee (EUR 27.90) – France
- A fee for starting up the service (EUR 27.16) – France
- An administration cost added on the first electricity bill (EUR 27.59) – Italy
- An activation fee – Italy, Poland
- An extra charge of EUR 20.54 on the first bill; no explanation was provided for this charge – Italy
- A security deposit (EUR 70) – Italy
- A deposit (EUR 77) – Italy
- A fee for contracts of less than one year – Spain
- A yearly charge of 300 SEK/year (or 25 SEK/month) for each new contract – Sweden
Source: "Second Consumer Market Study on the functioning of retail electricity markets
for consumers in the EU" (2016) European Commission
In total, therefore, the results from these ten representative Member States suggest that
around one fifth of electricity consumers in the EU would face some sort of fee
associated with switching suppliers. As for the magnitude of switching-related charges,
Figure 5 below indicates that average exit fees fall between 5 and 90 euros, depending on
the capital city sampled. Electricity and gas consumers on fixed-price and fixed-term
contracts in Amsterdam were the most affected by exit fees, and these could significantly
reduce their saving potential from 16% (without exit fees) to 6% (with first-year exit fees
included) with respect to the average incumbent standard offer for electricity consumers,
and from 13% to 6% with respect to the average gas standard incumbent price. Exit fees
could also considerably reduce potential savings for electricity consumers in Ljubljana,
Dublin, Copenhagen, London and Warsaw.
clearly state that switching should be completely free for the customer." "Position on early termination
fees" (2016) CEER, Ref: C16-CEM-90-06.
474
Facilitating supplier switching
Figure 5: Potential effect of exit fees on annual savings to be made from switching
away from the incumbent in Europe - 2014 (% and euros)183
Source: ACER.
While the possibility of charging exit fees may provide suppliers with more flexibility in
the tariffs they are able to offer, they make comparisons more difficult for consumers and
reduce the incentive for switching. Furthermore, behavioural economic theory suggests
that all fees associated with switching can disproportionately discourage consumer action
because of a decision making bias called 'loss aversion' – a tendency to strongly prefer
avoiding losses (one-time switching fees) to acquiring gains (the long-term savings of
moving to a cheaper tariff)184
. This means the reduced incentives presented in Figure 5
will appear much more significant in the eyes of most household consumers – twice as
large if findings from benchmark behavioural studies carry over into this real-world
183
Calculated on the basis of offer data for capital cities from the ACER Retail Database and the
information from the consumer organisations. For those countries where standard offers are variable
and where consumers typically incur exit fees while on fixed-term, fixed-price contracts, the above
figure should be considered illustrative. ‘Net’ savings equal the difference between the incumbent
price and the lowest offer, minus average exit fees typically imposed on fixed-term offers (i.e. savings
for consumers after exit fees have been paid for). ‘Gross’ savings equal the difference between the
incumbent price and the lowest offer. The data presented include information from the questionnaire
(i.e. an assessment of the existence and the level of exit fees in Member States and the information
collected on the basis of offer data in the ACER database to show the potential effect of exit fees in
those MSs where these exist. The exit fees shown in the above figure are the averages of all exit fees
incurred by consumers breaking away from contracts in the first year, and might be higher than those
incurred when breaking away in the 2nd or 3rd year. In the case of electricity offers in Oslo and
Warsaw, exit fees are estimated at 5% of the final standard offer.
184
"Choices, Values and Frames" (1984) Kahneman, D., and A. Tversky, American Psychologist, 39,
341-350.
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Facilitating supplier switching
context185
. As a result, three Member States (Belgium, France and Italy) have outlawed
altogether contract exit fees for household consumers in the energy sector.
Box 2: Switching energy suppliers in Belgium
As from 13 September 2012, the Belgian Electricity Act was amended (see Article 18, Section 2 and 3 of
the Electricity Act) and suppliers were no longer permitted to charge households and SMEs (non-
residential users with a maximum annual usage of 100,000 kWh in natural gas and 50,000 kWh in
electricity) a fee for the early termination of a contract, provided that a one-month notice period is
observed.
The abolition of early termination, or exit fees seems to have had a positive impact on the market with
regard to the number of users switching to a different electricity and gas provider. Switching jumped
markedly in all Belgian regions for bot electricity and gas around the time of the legislative change. This
has led NEON – the Europe-wide network of energy ombudsmen and mediation services – to suggest that
the ban on switching fees may have been to credit for this.
The Belgian Ombudsman also found that the number of complaints with regard to switching providers has
significantly fallen since the amendment of the act on 25 August 2012, from 14% (1,854 complaints) in
2014 to 8% in 2012 (1,250 complaints), 3% in 2013 (347 complaints) and 3.5% in 2014 (318 complaints).
Source: NEON, The National energy Ombudsman Network
One final factor to take into account is a high level of uncertainty amongst consumers
over whether they could be charged for switching – a fact that may be discouraging many
from looking into the possibility of switching because of the perceived complexity of it.
Whereas the evidence suggests only around 20% of consumers in the EU would actually
face some sort of fee associated with switching suppliers, 39% of consumers surveyed186
did not know whether or not they would be charged. This does not include 17% that
responded with certainty that they could be charged a fee for switching.
185
“Loss Aversion in Riskless Choice: A Reference-Dependent Model” (1991) Tversky, A., and D.
Kahneman, Quarterly Journal of Economics, 106 (4), 1039–1061.
186
29,119 interviews were conducted across 30 countries (EU28, Iceland and Norway). "Second
Consumer Market Study on the functioning of retail electricity markets for consumers in the EU"
(2016) European Commission.
2011 2012 2013 2014
Brussel - elektriciteit 4,1% 8,3% 14,3% 9,6%
Vlaanderen - elektriciteit 8,2% 16,5% 15,4% 11,9%
Wallonië - elektriciteit 8,6% 11,6% 13,6% 12,7%
Brussel - aardgas 4,7% 9,3% 18,3% 10,5%
Vlaanderen - aardgas 9,2% 18,9% 18,7% 13,9%
Wallonië - aardgas 11,0% 15,0% 21,2% 15,9%
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Facilitating supplier switching
Figure 6: Knowledge of switching rules – no charge when changing electricity
company, by country187
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
A lack of information relevant to switching in bills is one explanation for this. Whereas
customers in the majority of Member States are currently provided with information on
the consumption period, actual and/or estimated consumption, and a breakdown of the
price, there is a greater diversity of national practices with regards to other information,
including switching information, and the duration of the contract188
.
Another explanation is incomplete information from suppliers themselves. Table 2 below
shows that mystery shoppers in ten representative Member States were often unable to
find any information on switching rules whatsoever on electricity companies’ websites.
187
Question: "The following are statements regarding consumer rights in the energy sector. Please
indicate whether each statement is true or false: "If you decide to change your electricity company,
you will not be charged for the change“".
188
For more details, see the Thematic Evaluation on Metering and Billing.
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Facilitating supplier switching
Table 2: Switching rules found on electricity companies’ websites189
SI DE UK FR PL CZ IT LT SE ES Total
50 100 75 75 100 50 75 50 50 75 700
You will not be charged for the change 82% 57% 21% 52% 50% 36% 45% 30% 10% 24% 42%
The new provider must make the change within
three weeks (or less), provided you respect the
terms and conditions of the original contract
10% 13% 26% 13% 6% 8% 1% 10% 12% 3% 10%
Within six weeks (or less) after you switch, you
should receive the final closure account from
your previous provider
10% 11% 24% 4% 7% 2% 0% 2% 2% 4% 7%
It might be that you'll incur a fee for cancelling
your current energy deal
10% 5% 17% 0% 6% 8% 1% 0% 16% 5% 7%
None of the above 14% 38% 42% 43% 47% 52% 54% 66% 66% 69% 49%
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
High uncertainty levels indicate that the current prevalence of switching-related charges
may be having a much broader impact on switching rates than would be expected if only
consumers directly affected by such charges were considered. Whereas only 3% of
survey respondents stated that one of the main reasons they had not tried to switch was
that they would incur an exit fee from their electricity company, 16% stated that the
savings would not justify the trouble linked to changing electricity companies, 14% that
it is difficult to compare offers, and 12% that they perceive switching as being too
complicated – each a response that could have been influenced by the uncertain prospect
of switching-related charges.
Figure 7: Main reasons for not trying to switch electricity company190
Q32. What are the main reasons for not trying to switch your electricity company? (up to three responses)
%, EU28, Base: Those who have not switched electricity company in the last three years (Q27 code 2)
Question not a ed in Cyprus, Latvia and Cypru
42%
24%
23%
16%
14%
12%
12%
7%
5%
5%
4%
3%
2%
1%
6%
You are satisfied with your current electricity company
No difference between providers to make switching worthwhile
You never thought about the issue
Savings don't justify the trouble of changing provider
It is difficult to compare offers of different electricity companies
Switching is complicated
You dislike/distrust alternative electricity companies
There is no alternative local electricity company
You cannot find information on how to switch
You did not know that you can switch
Due to the length of the switching process
You will incur exit fees from your current electricity company
Other electricity companies are not as environmentally-friendly
In debt with current electricity company, so you you can't switch
Other reason specified
Main reasons for not trying to switch electricity company
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
Given the persistently low levels of switching and consumer engagement in the energy
sector (Figure 1), there may therefore be scope to further restrict the use of fees charged
to consumers for changing suppliers. This would remove a key monetary barrier to
greater consumer engagement. It would make it easier for consumers to control their bills
and harder for suppliers to lock consumers into disadvantageous contracts. Such action
189
Question: "Which of the following statements about the switching process were found on the website?
(multiple answers allowed)".
190
Question: "What are the main reasons for not trying to switch your electricity company? (up to three
responses)".
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Facilitating supplier switching
would therefore be consistent with other provisions in the Electricity and Gas Directives
which state: “Member States shall ensure that the eligible customer is in fact easily able
to switch to a new supplier”.
Without intervention, switching-related fees in the range of 5 to 90 euros would likely
continue to affect an estimated 20% of electricity consumers in the EU, with uncertainty
over their applicability influencing the decision-making of well over half of all EU
electricity consumers. A lack of action to limit these fees would amount to ignoring a key
barrier to consumer engagement.
Although there is less evidence on switching-related fees in the gas sector, Figures 4 and
5 suggest they are prevalent in fewer Member States, and that their magnitude is similar.
Deficiencies of the current legislation
7.4.3.
The consumer protection provisions in the Electricity and Gas Directives regulate
switching fees. Largely unchanged since their 2001/2003 introduction, these provisions
state that “customers are not to be charged for changing supplier”.
The following text regarding contract exit fees was added in 2007: contracts must specify
“whether withdrawal from the contract without charge is permitted”. It weakened the
initial provision by affirming the permissibility of certain switching-related charges
without explicitly addressing whether the legislation addressed all switching-related
charges in categorically exhaustive manner.
As addressed in Section 7.1.1 and Annex IV of the Evaluation, the current framework
therefore remains both complex and open to interpretation with regard to the nature and
scope of certain key obligations.
Presentation of the options
7.4.4.
Option 0: Stronger enforcement
Stronger enforcement to tackle the switching fees currently imposed contrary to EU legal
requirements.
Option 0+: Clarifying certain concrete requirements in the current legislation through an
interpretative note, coupled with stronger enforcement
This option involves making it explicit that the existing Third Package provision stating
that consumers "are not charged for changing supplier" applies to contract switching fees.
This would seek to remove any legal uncertainty and improve Member State compliance.
Option 1: Legislation to outlaw the use of switching fees and to limit the use of exit fees
in electricity and gas supply contracts in the EU
In concrete terms, the preferred measures will include the following:
i. Define switching fees and contract exit fees in the legislation.
ii. Ban all switching fees, and ban exit fees in open-ended supply contracts and
fixed term contracts that have come to the end of the agreed term.
iii. For fixed-term contracts, permit exit fees if the contract has not ended, but
ensure the cost-reflectiveness and proportionality of these fees to avoid undue
consumer detriment. Clarify that consumers should always have the possibility to
exit the contract, if they are prepared to pay the exit fee.
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Facilitating supplier switching
iv. Define exceptions to accommodate certain on-bill repayment of upfront
investments in, inter alia, energy efficiency financed by suppliers or energy
service providers.
v. Introduce transparency provisions so that fees are presented in an easily
understandable manner (e.g. amortisation schedule) in contracts and pre-
contractual information.
vi. Clarify that commercial and industrial supply contracts would not be affected.
Option 2: Legislation to categorically outlaw the use of all switching and exit fees in
electricity and gas supply contracts to EU household consumers
In concrete terms, the preferred measures will include the following:
i. Define switching fees and contract exit fees in the legislation.
ii. Ban all fees defined in i).
Comparison of the options
7.4.5.
This section compares the costs and benefits of each of the Options presented above in a
semi-quantitative manner.
In general, the costs of implementing each of the above measures can be estimated to a
reasonably certain degree using tools such as the standard cost model for estimating
administrative costs. However, no data or methodology exists to accurately quantify all
the benefits of the measures in terms of direct benefits to consumer (consumer surplus) or
general competition. As such, this Section aims to illustrate the possible direct benefit to
consumers assuming certain conditions. It also highlights important qualitative evidence
from stakeholders that policymakers should also incorporate into their analysis of costs
and benefits.
Option 0: Stronger enforcement
An estimated 4% of EU consumers face switching-related charges that may be illegal
under EU law. Stronger enforcement would see these increasingly phased out. Whilst we
cannot measure the economic benefits of this option, we can estimate its benefit to
consumers given some simple assumptions.
If we assume that:
- One in fifty of the households currently affected by illegal electricity
switching fees make a switch as a direct result of an enforcement drive191
;
- Gas household consumers see no benefits192
;
191
This is a highly uncertain figure, affected by several variables that have not been studied in depth,
including the speed and effectiveness of EU enforcement action, and public awareness of consumer
rights.
192
This is a conservative estimate. Whilst the evidence suggests they may be less prevalent, and Figure
Figures X and Y indicate they are certainly present.
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Facilitating supplier switching
- The annual financial benefit of switching for these households amounts to 82
euros, which is the average difference in price between the incumbent's
standard offer and the cheapest offer in the capital city in the EU193
;
- The financial advantage of switching as a result of these measures persists for
four years194
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms195
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 0 would result in an increase in consumer surplus of between 13.7 million
euros and 48.4 million euros annually (depending on the year of implementation), and
415 million euros in total for the period 2020-2030.
In spite of these considerations, it is unlikely that Option 0 would most effectively
address the problem of poor consumer engagement. First, a great degree of uncertainty
surrounds the estimation above associated with the speed and effectiveness of EU
enforcement action.
In addition, the effectiveness of Option 0 is significantly limited by the fact that the
provisions of the Electricity and Gas Directives state that consumer supply contracts
must specify "whether withdrawal from the contract without charge is permitted". A
further 17% of consumers will therefore continue to be directly affected by contract exit
fees that are legal under current legislation.
There are no implementation costs associated with Option 0.
Option 0+: Clarifying certain concrete requirements in the current legislation through an
interpretative note, coupled with stronger enforcement
This option would make it easier for suppliers and national authorities to interpret current
switching rules and to determine whether certain fees are compatible or incompatible
with the Third Package. Consumers would also have access to more and clearer
information regarding the legal situation surrounding such fees and could become better
aware of the types of fees used in their contracts. This option would make it easier for
suppliers and national authorities to interpret current switching rules and to determine
whether certain fees are compatible or incompatible with the Third Package. Consumers
would also have access to more and clearer information regarding the legal situation
surrounding such fees and could become more aware of the types of fees used in their
contracts.
193
The weighted average was not used because the large potential savings available to DE consumers
skewed this figure to over EUR 150. "Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documentsreality,
/Acts_of_the_Agency/Publication/ACER_Market_Monitoring_Report_2015, p.59.
194
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
195
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we
have no reliable data to quantify these differences in this specific context.
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Facilitating supplier switching
Whilst the economic benefits of this measure cannot be estimated, we can expect its
benefits to consumers to be similar to Option 0 (415 million euros in total for the
period 2020-2030) or higher, reflecting the greater legal certainty engendered by the EU
guidance issued compared with Option 0.
However, as with Option 0, a further 17% of consumers are directly affected by contract
exit fees that are legal under current legislation.
It is unlikely that voluntary cooperation between Member States would address this
problem, as it is domestic in nature with no common gains to be had through supra-
national coordination.
There are no implementation costs associated with Option 0+.
Several stakeholders support the principle of better implementation of the existing
switching fee provisions in the Electricity and Gas Directives, including the European
Parliament's ITRE Committee and NRAs. Others, such as consumer groups and
ombudsmen, argue that there should be no fees associated with switching.
Option 1: Legislation to outlaw the use of switching fees and to limit the use of exit fees
in electricity and gas supply contracts in the EU
This option may considerably reduce the prevalence of both switching and exit fees for
the category of consumers most likely to be confused by such fees – household
consumers.
If we assume that:
- One in one-hundred of the 17% of households currently affected by exit fees
in their electricity supply contracts make a switch as a direct result of this
intervention196
;
- The annual financial benefit of switching for these households amounts to 82
euros, which is the average difference in price between the incumbent's
standard offer and the cheapest offer in the capital city in the EU197
;
- Gas household consumers see no benefits198
;
- The financial advantage of switching as a result of these measures persists for
four years199
;
196
This is a highly uncertain figure as we have no clear and comprehensive picture as to: i) the proportion
of consumers who may be charged exit fees even though they are on indefinite contracts; ii) the
proportion of consumers whose exit fees would be considered disproportionate, and therefore not
permitted under this option; iii) the extent to which consumers benefitting from this measure would be
aware of it; iv) how those aware of the legislative change would respond to the increased financial
incentive to switch.
197
The weighted average was not used because the large potential savings available to DE consumers
skewed this figure to over EUR 150. "Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documentsreality,
/Acts_of_the_Agency/Publication/ACER_Market_Monitoring_Report_2015, p.59.
198
This is a conservative estimate. Whilst the evidence suggests they may be less prevalent, Figures 4 and
5 indicate they are certainly present.
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Facilitating supplier switching
- All EU households within each Member State are able to benefit from these
changes equally in relative terms200
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in an increase in consumer surplus of between 29 million
euros and 102.8 million euros annually (depending on the year of implementation), and
881 million euros in total for the period 2020-2030 on top of any gains brought by
improved enforcement (estimated at 415 million euros for options 1 and 2).
Whilst these consumer benefits are subject to great uncertainty due to the unknown
extent to which they would increase consumer switching, Belgium's experience (See
Box) would seem to indicate that restricting contract exit fees has a significant potential
to increase consumer engagement – in the short-term at least.
In terms of implementation costs, Option 1 would most notably limit innovation and
consumer choice around certain elements of consumer supply contracts, most notably by
preventing exit fees from being charged in indefinite contracts. Whilst unquantifiable,
these implementation costs would likely be limited. Consumers wishing to benefit from
lower prices in exchange for greater consumer loyalty could still opt for fixed-term
contracts.
In addition, Option 1 would permit the on-bill repayment of upfront investments in
energy efficiency. Such financing through, for instance, energy performance
contracting201
will play an important part in meeting the EU's ambitious energy
efficiency targets, and is a priority under Commission plans.
Apart from consumer groups and ombudsmen, most stakeholders would seem to
support this option, including suppliers and NRAs. This is because it incrementally
builds upon the existing provisions of the Electricity and Gas Directives, helping to
achieve the legislators' intention more effectively.
This option would best clarify the legal situation and be the most enforceable measure.
Given the very significant effect on switching rates similar measures have had in
Belgium (See Box 2), this measure would also lead to a sizeable increase in consumer
engagement in many Member States in which contract exit fees are common.
199
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
200
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we
have no reliable data to quantify these differences in this specific context.
201
"Energy performance contracting" means a contractual arrangement between the beneficiary and the
provider of an energy efficiency improvement measure, verified and monitored during the whole term
of the contract, where investments (work, supply or service) in that measure are paid for in relation to
a contractually agreed level of energy efficiency improvement or other agreed energy performance
criterion, such as financial savings.
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Facilitating supplier switching
If we assume that:
- One in four of the estimated 3% of household consumers who report that they
have not tried to switch because they would be charged a fee actually make a
switch as a result of a complete ban on such fees202
;
- The annual financial benefit of switching for these households amounts to 41
euros, which is half of the average difference in price between the
incumbent's standard offer and the cheapest offer in the capital city in the
EU203
;
- Gas household consumers see no benefits204
;
- The financial advantage of switching as a result of these measures persists for
four years205
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms206
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 2 would result in an increase in consumer surplus of between 64 million
euros and 227 million euros annually (depending on the year of implementation), and
1.9 billion euros in total for the period 2020-2030 on top of any gains brought by
improved enforcement (estimated at 415 million euros for options 1 and 2).
Whereas the implementation costs of Option 2 are unquantifiable, they may be
significant. This is because Option 2 would strongly restrict the range of contracts
available to consumers, which may impede competition, as well as the provision of a
legitimate class of products.
If implemented poorly, Option 2 could also impede the development of innovative
financing options for beneficial investments in energy assets for households. Such
products may require certain forms of termination fees in order to allow companies to
recoup upfront investment costs provided as part of an integrated energy service product
e.g. solar panels or energy efficiency upgrades. This option could therefore be in
significant tension with other EU policy priorities, including its energy efficiency,
renewable deployment, and self-consumption policies. For example, one of the objectives
of the EED was to identify and remove regulatory and non-regulatory barriers to the use
of energy performance contracting and other third-party financing arrangements for
energy savings.
202
See Figure 7. This estimate is based on survey responses, and has been discounted to conservatively
reflect possible unreliability in what consumers report.
203
We conservatively assume that the savings to consumers available in this option are significantly
reduced because the cheapest option available in the market – the benchmark price used in the other
options – is usually a fixed term contract, which may require the consumer to accept a contract exit or
termination fee in return for consumer loyalty. As this option entails banning all exit fees, it is unlikely
that suppliers would be able to offer consumers the same level of financial savings in such contracts.
204
This is a conservative estimate. Whilst the evidence suggests they may be less prevalent,
Figure 4 and Figure indicate they are certainly present.
205
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
206
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we
have no reliable data to quantify these differences in this specific context.
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Facilitating supplier switching
Whereas several stakeholders support an outright ban on switching fees – notably
consumer groups and energy ombudsmen – NRAs believe the decision on whether or not
to completely ban them should be taken at the national level. ACER and electricity
suppliers support the legitimacy of termination fees for fixed term contracts.
Conclusion
The analysis indicated that each of the Options above is likely to result in a net benefit.
However, Option 1 is the preferred option, as it represents the most favourable balance
between probable benefits and costs. Whereas the potential benefits of Option 2 are
greater, so are the potential implementation costs in terms of both reduced competition
and tension with the EU's sustainable energy policies.
Subsidiarity
7.4.6.
Consumers are not taking full advantage of competition on energy markets due, in part,
to obstacles to switching. Well designed and implemented consumer policies with a
European dimension can enable consumers to make informed choices that reward
competition, and support the goal of sustainable and resource-efficient growth, whilst
taking account of the needs of all consumers. Increasing confidence and ensuring that
unfair trading practices do not bring a competitive advantage will also have a positive
impact in terms of stimulating growth.
As a result of current EU provisions, national legal regimes remain fragmented as regards
switching-related fees. Further restricting such fees would diminish an important barrier
to customer mobility. The possibility of easy and free-of-charge switching would exert
more competitive pressure on energy suppliers to improve quality and reduce prices.
The options here envisage clarifying the legislation and further limiting the use of exit
fees across different kinds of consumer contracts (fixed-term, indefinite, supply contracts
bundled with energy services) and to different degrees.
The legal basis for the legislative options proposed (Options 1 and 2) is therefore likely
to be Article 114 TFEU. This allows for the adoption of "measures for the approximation
of the provisions laid down by law, regulation or administrative action in Member States
which have as their object the establishment and functioning of the internal market". In
doing this, in accordance with Article 169 TFEU, the Commission will aim at ensuring a
high level of consumer protection.
Without EU action, the identified problems related to the lack of an EU-wide market will
continue to lead to consumer detriment.
Option 0+
The guidance option does not significantly change the legal status quo. Member State
authorities would continue, to have a significant degree of discretion in deciding if a
termination/switching fee is allowed or not.
From a subsidiarity perspective, this option allows member States to decide on the extent
to which they wish creating an environment where customers are encouraged to switch
more freely, as this – in theory, at least – may not always result in lower overall prices
depending on the national situation.
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Facilitating supplier switching
From the perspective of proportionality, however, this option would not achieve the
objective of the Article of the Treaty taken as their legal basis – the establishment and
functioning of the internal market.
Option 1
The principles of subsidiarity and proportionality are best met through this Option, as it
is not overly prescriptive and will concretely reduce levels of consumer detriment that
are, at present, not addressed at a national level by Member State authorities.
This option aims primarily at clarifying and not strengthening existing legislation. As
switching and exit fees are already addressed in EU provisions, the subsidiarity and
proportionality principles have clearly been assessed previously and deemed as met.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the
preceding pages, accrue predominantly to consumers who are engaged in the market – those who compare
offers and are likely to change suppliers if they find a better deal. Whilst facilitating switch will also
increase consumer engagement levels, and whilst the increased competition engendered by easier switching
will lead to more competitive offers on the market, disengaged consumers, including consumers who may
be vulnerable, will not reap as many direct benefits from this policy intervention
Option 2
Banning exit fees in EU legislation would help to create a level playing field for
consumers within Member States and between Member States. At this point, however, it
would be disproportionate to impose a complete ban on exit fees as it would have a
limiting effect on innovation and choice. It would limit the range and number of offers
available to consumers, for example, fixed-term, fixed-price contracts that offer a lower
cost per kWh.
Stakeholders' opinions
7.4.7.
Public Consultation
222 out of 237 respondents to the Commission's Consultation on the Retail Energy
Market207
believed that transparent contracts and bills were either important or very
important for helping residential consumers and SMEs to better control their energy
consumption and costs.
When asked to identify key factors influencing switching rates, 89 respondents out of
237 stated that consumers were not aware of their switching rights, 110 stated that prices
and tariffs were too difficult to compare due to a lack of tools and/or due to contractual
conditions, and 128 cited insufficient benefits from switching.
Only 32 out of 237 respondents agreed with the statement: "There is no need to
encourage switching". 98 disagreed and 90 were neutral.
207
Held from 22 to 17 April 2014. https://ec.europa.eu/energy/en/consultations/consultation-retail-
energy-market
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Facilitating supplier switching
National Regulatory Authorities
ACER identifies exit fees as a potential barrier to switching, since they tend to increase
the threshold for consumers to switch due to the perceived diminished potential savings
available. However, ACER highlights that exit fees in fully competitive retail markets are
applied to cover the costs incurred by suppliers due to early contract termination. ACER
argues that offers which include exit fees should be made fully transparent (including on
price comparison tools) and that exit fees need to be objectively justified.
The body representing the EU's national regulatory authorities in Brussels, CEER208
,
supports the distinction between exit fees, which it deems to be a contractual matter, and
all other switching-related fees. CEER has stated that it should not be possible for energy
suppliers to charge an exit fee to customers who respect the end date of their fixed term
energy contract. It also deems that other switching-related fees are not permissible under
EU law. However, it argues that any decision on whether to abolish exit fees needs to be
taken at the national level, as creating an environment where customers are encouraged
to switch more freely may not always result in lower overall prices.
Ombudsmen
According to NEON, the National Energy Ombudsmen Network, EU regulations and
directives already provide that supplier switching should be easy and quick, without extra
charges. However, mistrust in the market, indecision and the perceived lack of benefits
remain the main obstacles to more switching. As it is the case in France and Belgium,
NEON believes that consumers should be allowed the right to change supplier whenever
they want, without paying termination or exit fees.
Consumer Groups
BEUC has argued for greater transparency on exit fees, stating that a summary of the key
contractual conditions, including conditions for switching, should be provided to
consumers in concise and simple language alongside with the contract209
. BEUC has also
stated that it is: "concerned about the application of termination fees representing a lock
in situation of the consumer and an anti-competitive measure as these fees often prevent
consumers from changing the supplier. Switching should not be subject to any
termination fee or penalty"210
.
BEUC, EURELECTRIC and Eurogas recently released joint statement on improved
comparability of energy offers211
. In it, they call for the following key information is
provided to customers by suppliers in one place in a short, easily understandable,
prominent and accessible manner:
- Product name and main features including, where relevant, information on
environmental impact, clear description of promotions (e.g. temporary discounts) and
additional services (e.g. maintenance, insurance, etc.)
208
The Council of European Energy Regulators.
209
http://www.beuc.eu/publications/beuc-x-2015-
102_mst_beuc_response_to_public_consultation_on_a_new_energy_market_design.pdf
210
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
211
http://www.eurelectric.org/media/263669/joint_statement_-
_improved_comparability_of_energy_offers_-2016-030-0116-01-e.pdf
487
Facilitating supplier switching
- Total Price (fixed/variable) - which includes all cost components - and conditions for
price changes
- Contract duration, notice period (renewal/withdrawal - where relevant) and
conditions for termination, including, where relevant, fees and penalties
- Payment frequency and method options (e.g. cash/ cheque/ direct debit/ standing
order/ prepayment)
- Supplier’s contact details (e.g. customer service’s address, telephone number and/or
email, including, where relevant, identification of any intermediary)
Suppliers
In their contribution to the discussions within the Citizens' Energy Forum in 2016,
EURELECTRIC and its members welcomed the intention of the Commission and
NRAs to work towards removing barriers to switching supplier. EURELECTRIC
believes that all barriers should be considered, including non-commercial barriers, i.e.
technical and regulatory. In terms of commercial barriers, a distinction should be drawn
between fixed term contracts and variable contracts. Many customers are on variable
tariffs with no end date and these do not have exit fees. In contrast, according to
EURELECTRIC, exit fees need to be allowed to for fixed term deals – provided they’re
proportionate to the costs incurred by the supplier – as they help cover the costs suppliers
face when customers leave early, much like for broadband or mobile phone contracts.
Such contracts can be cheaper because suppliers have more certainty about how many
customers they have and how much energy to buy in advance. If exit fees were banned
for such contracts, the prices of fixed term deals would be likely to go up to the detriment
of customers. EURELECTRIC believes that in any case where exit fees do apply to fixed
term contracts, they must be clearly communicated to customers up-front.
BEUC, EURELECTRIC and Eurogas also recently released joint statement on
improved comparability of energy offers, which can be read above. It notably includes
the recommendation that termination fees be provided along with other key information
on the offer "in one place in a short, easily understandable, prominent and accessible
manner".
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Parliament's Committee on Industry, Research and
Energy (ITRE): "Insists that the provisions on switching, as set out in the Third
Package, should be fully implemented by Member States, and that national legislation
must guarantee consumers the right to change suppliers in a quick, easy and free-of-
charge way, and that their ability to switch should not be hindered by termination fees or
penalties". Furthermore, ITRE calls for better information to consumers about their
rights, and for further measures to make switching between providers easier.
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Parliament's Committee on the Internal Market and
Consumer Protection (IMCO) called for: "the full implementation of the third energy
package, including the right to change suppliers free of charge and better information to
consumers about their rights, and for further measures to make switching between
providers easier and faster, including a shortened switching period and effective and
secure data portability in order to prevent the lock-in of consumers".
The Committee of the Regions
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Committee of the Regions suggests that information
488
Facilitating supplier switching
campaigns for switching suppliers should be launched by energy regulators, local
authorities and consumer organisations. The Committee also encourages the EU to adopt
an ambitious regulation on reducing the transfer time for customers switching from one
provider to another, and making the transfer procedure automatic.
489
Comparison tools
7.5. Comparison tools
490
Comparison tools
Summary table
7.5.1.
Objective: Facilitating supplier switching by improving consumer access to reliable comparison tools.
Option 0+ Option 1 Option 2
Cross-sectorial Commission guidance addressing the applicability of the Unfair
Commercial Practices Directive to comparison tools
Legislation to ensure every Member State has at
least one 'certified' comparison tool that complies
with pre-specified criteria on reliability and
impartiality
Legislation to ensure every Member State appoints an
independent body to provide a comparison tool that
serves the consumer interest
Pros:
- Facilitates coherent enforcement of existing legislation.
- Light intervention and administrative impact.
- Cross-sectorial consumer legislation already requires comparison tools to be
transparent towards consumers in their functioning so as not to mislead
consumers (e.g. ensure that advertising and sponsored results are properly
identifiable etc.).
- Cross-sectorial approach addresses shortcomings in commercial comparison
tools of all varieties.
- Cross-sectorial approach minimizes proliferation of sector-specific
legislation.
Pros:
- Fills gaps in existing legislation vis-à-vis energy
comparison tools.
- Limited intervention in the market, in most cases.
- Allows certifying all existing energy comparison
tools regardless of ownership.
- Proactively increases levels of consumer trust.
- Ensures EU wide access.
- The certified comparison websites can become
market benchmarks, foster best practices among
competitors
Pros:
- NRAs able to censure suppliers by removing their
offers from the comparison tool.
- No obligation on private sector.
- Reduces risks of favouritism in certification
process.
- Proactively increases levels of consumer trust.
Cons:
- Does not apply to non-profit comparison tools.
- Does not proactively increase levels of consumer trust.
- The existing legislation does not oblige comparison tools to be fully impartial,
comprehensive, effective or useful to the consumer.
Cons:
- Existing legislation already requires commercial
comparison tools to abide by certain of the criteria
addressed by certification.
- Requires resources for verification and/or
certification.
- Significant public intervention necessary if no
comparison tools in a given Member State meet
standards.
Cons:
- To be effective, Member States must provide
sufficient resources for the development of such tools
to match the quality of offerings from the private
sector.
- Well-performing for-profit tools could be side-lined
by less effective ones run by national authorities.
Most suitable option(s): Option 1 is the preferred option because it strikes the best balance between consumer welfare and administrative impact. It also gives Member States control over
whether they feel a certification scheme or a publicly-run comparison tool best ensures consumer engagement in their markets.
491
Comparison tools
Description of the baseline
7.5.2.
Online comparison tools – websites that compare different energy offers – play an
important role in helping consumers to make an informed decision about switching
suppliers. Comparison tools (CTs) have become increasingly widespread, and can now
be found in almost every MEMBER STATE (Table 1).
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Comparison tools
Table 1: Estimated number of energy comparison tools in Member States212
Member
State
Number
of energy
CTs
Of which
Govt.
Operated
Comment
* denotes estimate based on weighted average of figures from NRAs who reported data, or desktop
research
AT 2* 1
BE 11 3 Accreditation under review.
BG 0 0
CZ 2* 0*
DE 10 0 German consumer organisations under the umbrella of a market
watchdog have conducted a survey about CT's in February 2016 and
provided a test report and ranking, which can be found here.
DK 2 2
EE 0 0
EL 3* 0*
ES 7 1 The NRA is legally entitled to run a CT. All suppliers are obliged to
send the commercial offers to the CT. The NRA CT would meet
accreditation standards.
The consumer organization also has a CT, but only for its affiliates.
The NRA has no powers to monitor the functioning of private CTs.
It can be estimated than very few of them would meet accreditation
standards, perhaps between 0 and 3, depending on the requirements
for the accreditation.
FI 4 1 No specific accreditation standards are applied. The CT
(www.sahkonhinta.fi) operated by the NRA, however, is free of
charge, neutral, easy to access and comprehensive (all suppliers are
obliged to report their public offers there). One of the commercial
CTs uses the price data that is published by the NRA.
FR 8 2
HU 3 0 There are several running service provider businesses concentrating
exclusively on businesses. In addition Hungary is considering
implementing a comparison tool - taking into account the level of
price competition - would primarily focus on businesses and would
be run by the Hungarian NRA.
HR 1* 0*
IE 2* 0 Accreditation scheme in place
IT 9 2
LV 0 0
LT 0 0 ACER reports no price comparison tools in this Member State.
LU 1 1
212
Excluding CY and MT. Source: CEER, "Study on the coverage, functioning and consumer use of
comparison tools and third-party verification schemes for such tools", (2014) European Commission,
http://ec.europa.eu/consumers/consumer_evidence/market_studies/comparison_tools/index_en.htm.
493
Comparison tools
Member
State
Number
of energy
CTs
Of which
Govt.
Operated
Comment
* denotes estimate based on weighted average of figures from NRAs who reported data, or desktop
research
NL 14 0 No accreditation scheme. ACM developed a ‘guidance’ document
for all companies offering electricity and/or gas contracts, including
price comparison websites. The guideline is based on general
consumer law and sector specific energy legislation. The goal of the
guideline is to ensure that consumers are offered energy products
that are tailored made to their situation, contains information they
can easily understand, and compare with other offers. ACM can
intervene whenever a price comparison website does not comply
with the aforementioned legislation.
PL 1 1 Offers available on CT, are updated by NRA on the basis of
information from suppliers. Suppliers are obliged to send NRA new
offers immediately after deciding on the introducing their offer into
the market (but not later than 2 days before the offer starts).
However data concerning distribution is entered by particular DSO
on the basis of distribution tariffs and their changes.
PT 2 1
RO 0 0
SE 4 1 The regulated CT is under supervision and checked regularly. The
other CTs are not regulated, supervised nor does the regulator
control the prices or how the prices are published. There is no
specific legislation for these CTs.
SI 1* 1
SK 1* 0*
UK 34 1 33 comparison tools make up over 90% of the market in GB, with
the remaining proportion of the market made up of 100’s of smaller
switching services.
Total 122* 18*
Source: CEER and DG ENER research
A recent study found that 64% of consumers who had compared the tariffs of different
electricity companies said they had used a comparison tool to do so, compared to 38%
who had visited company websites, and 8% who had contacted companies by phone213
.
It also showed that comparison tools significantly increased the number of cheaper offers
consumers were able to identify compared with contacting individual providers
directly214
. Overall, 23% of consumers surveyed in the EU have used a comparison tool
to compare energy offers in the last 12 months215
.
213
Non-exclusive figures i.e. respondents could choose more than one means of comparison.
214
From twice to twenty times, depending on the Member State. "Second Consumer Market Study on the
functioning of retail electricity markets for consumers in the EU" (2016) European Commission.
215
However, this figure varies widely across the EU with up to 45% of UK consumers using comparison
tools to compare energy offers compared to only 2% of consumers from Luxembourg. "Study on the
494
Comparison tools
Comparison tools are likely to become even more important as the retail market for
energy matures. Between 2012 and 2014, ‘choice’ for consumers in European capitals
widened, with a greater variety of offers being available. However, the ability of
consumers to compare prices can be hampered by the complexity of pricing and the
range of energy products, as well as by an increasing number of offers and their bundling
with additional charge free or payable services216
.
In a retail market characterized by persistently low levels of consumer engagement,
comparison tools are an effective means of reducing search costs for consumers, and
presenting them with accurate market information in a manner that is clear and
comprehensive.
However, the majority of comparison tools are operated for profit, leading to situations
where their impartiality and the consumer interest may not be ensured. Most comparison
tools do not charge consumers for access to their sites and therefore the bulk of their
products are obtained via commercial relationships with the vendors they list. They get
paid via subscription fees, click-through fees, or commission fees. Some comparison
sites list sellers at no cost and get their revenue from sponsored links or sponsored ads. A
lesser used model is where some Comparison Tools charge consumers to obtain access to
its information, while firms do not pay any fees (Figure 1).
coverage, functioning and consumer use of comparison tools and third-party verification schemes for
such tools" (2013) European Commission,,
http://ec.europa.eu/consumers/consumer_evidence/market_studies/comparison_tools/index_en.htm
216
"Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015 p.40, 100.
495
Comparison tools
Figure 1: Business models of EU comparison tools (including non-energy)
Source: "Study on the coverage, functioning and consumer use of comparison tools and third-party
verification schemes for such tools" (2013) European Commission, pp. 99, 102
Recent reports of unscrupulous practices have damaged consumer trust in both
comparison tools and the switching process more generally (Box 1). Indeed, a third of
respondents to a recent EU survey somewhat or strongly agreed that they did not trust
price comparison websites because they were not independent and impartial and thus
questioned the independence of such tools. Perhaps for this reason, the same study found:
"Comparison tools did not appear keen to divulge details on how they generated
income"217
.
Identified issues include:
i) the default presentation of deals by some websites;
ii) the misleading language used to provide consumers with a choice of which
presentation to pick;
iii) the lack of transparency about commission arrangements; and
iv) inadequate arrangements for regulatory oversight.
217
Less than half of Comparison Tools were willing to disclose details on their supplier relationship,
description of business model or the sourcing of their price and product data. "Study on the coverage,
functioning and consumer use of comparison tools and third-party verification schemes for such tools"
(2013) European Commission, pp. xix, 191.
496
Comparison tools
Box 1: UK House of Commons report into energy comparison tools218
The UK has the largest number of energy comparison websites of any Member State, with 34 such tools
controlling a 90% share of the market. In 2015, the House of Commons Energy and Climate Change
Committee published a report criticising energy comparison tools for "hiding the best deals from
consumers by concealing tariffs from suppliers that do not pay the website a commission." The report
concluded that "all deals should be made available by default to the consumer" and strongly objected to
"any attempt to lure consumers into choosing particular deals by the use of misleading language." In
addition it highlighted "the lack of transparency about commission arrangements between the websites and
suppliers" as a shortcoming in the UK energy comparison tool market.
Source: UK House of Commons, Energy and Climate Change Committee
The existing consumer acquis could be made to work better (see Section below), and is
an ex-post safety net that is enforced on a case-by-case basis by relevant national courts
and authorities. There may therefore be benefit in putting in place a specific ex-ante
quality assurance mechanism to guarantee a high level of quality information and
transparency to consumers, to spread the uptake of best practices, and to boost consumer
confidence in these tools. In addition, while comparison tools are indeed widespread,
there is the need to ensure a more universal coverage of reliable comparison tools
throughout the internal market.
Deficiencies of the current legislation
7.5.3.
Section 7.3.5 and Annex V of the Evaluation show that the relevance of the existing
legislation is challenged by the fact that it is not adapted to reflect new ways of
consumer-market interaction, such as through comparison tools.
The 2005 Unfair Commercial Practices Directive219
(UCPD) addresses comparison tools
in so far as it requires them to provide enough information to ensure that consumers are
not misled. As such, comparison tools qualifying as traders under the UCPD must ensure
that they carry out comparisons in a transparent way. They must not provide false or
deceiving statements, nor must they omit information about products if this causes the
average consumer to take a decision they might not have taken otherwise. The UCPD
particularly requires all traders to clearly distinguish a natural search result from
advertising.
Indeed, the full implementation of the UCPD would help address two of the issues with
energy comparison tools identified in the Section above, namely: The misleading
language used to provide consumers with a choice of which presentation to pick; and the
lack of transparency about commission arrangements.
In spite of this legislation, however, there may be scope for further EU action to address
this area.
218
In one such case, some comparison websites were found to be hiding the best deals from consumers by
concealing tariffs from suppliers that did not pay these websites a commission. “Protecting
consumers: Making energy price comparison websites transparent” (2015) UK House of Commons,
Energy and Climate Change Committee,
http://www.publications.parliament.uk/pa/cm201415/cmselect/cmenergy/899/899.pdf.
219
Articles 6 and 7, in particular.
497
Comparison tools
Firstly, because the UCPD is a cross-sectorial and principle-based piece of legislation, its
provisions may not address all of the problems we observe in comparison tools. For
example, whilst the UCPD states that comparison tools should not mislead consumers, it
does not oblige them to be effective, impartial or useful to the consumer, nor does it
require comparison tools to cover an entire market. A comparison tool that only
displayed biased rankings would be in compliance with the UCPD as long as it clearly
stated that this was the case.
Secondly, Member States may have difficulties in interpreting the provisions of the
UCPD – as well as the 13 other pieces of legislation and official guidance that may apply
(Box 2) – and relating this body of legislation to energy comparison tools in particular.
Clearer provisions could therefore improve implementation.
Box 2: List of applicable legislation and official guidance documents
- Directive 2005/29/EC (Unfair Commercial Practices Directive)
- SEC(2009) 1666 (Guidance on Unfair Commercial Practices Directive)
- Directive 2011/83/EU (Consumer Rights Directive)
- Guidance Document concerning Directive 2011/83/EU (Guidance on Consumer Rights Directive)
- Directive 2006/114/EC (Misleading and Comparative Advertising Directive)
- Directive 2000/31/EC (E-Commerce Directive)
- Directive 98/6/EC (Price Indication Directive)
- Council Directive 93/13/EEC (Unfair Contract Terms Directive)
- Directive 2002/22/EC (Citizens' Rights Directive)
- Directive 2014/92/EU (Payment Accounts Directive)
- Regulation (EC) No 1008/2008 (Air Services Regulation)
- Directive 2009/72/EC (Electricity Directive)
- Directive 2009/73/EC (Gas Directive)
- Directive 2008/48/EC (Consumer Credit Directive)
- Directive 2007/64/EC (Payment Services Directive)
- Directive 2002/65/EC (Distance Marketing of Consumer Financial Services Directive)
Finally, whereas the UCPD and most other applicable consumer protection legislation
only applies to commercial comparison tools, there is also a need to ensure the quality of
comparison tools operated by national authorities and non-profit organizations.
As for the Third Package, consumer bills and pre-contractual information formed the
basis of consumer comparability at the time of its drafting, as consumers would manually
measure up individual offers against their current supply contract. The legislation
therefore addressed these points in order to promote consumer interests. Since then, the
use of online websites for comparison as well as marketing purposes has risen
significantly across the EU, challenging the relevance of the sector-specific energy
acquis, which does not address comparison tools at all.
Presentation of the options
7.5.4.
Option 0+ (Non-regulatory approach): Cross-sectorial Commission guidance addressing
the applicability of the Unfair Commercial Practices Directive to commercially operated
comparison tools
The Unfair Commercial Practices Directive expressly prohibits activities that materially
distort the consumer’s economic behaviour to the point where their ability to make an
informed decision is impaired. This has implications for the following issues relevant to
energy comparison tools, inter alia:
498
Comparison tools
- Identification of advertising and sponsored results;
- Criteria for ranking;
- The disclosure of relationship with suppliers (assessed on a case-by-case basis);
- Displaying the same information for all products.
Building on the principles of reliability and impartiality endorsed by the Multi-
Stakeholder Dialogue on Comparison Tools, the Commission has therefore very recently
published updated guidance on how to apply the Directive to comparison tools in all
sectors220
.
In addition, various other cross-sectorial consumer protection Directives require the
disclosure of price and product data sourcing221
. Stronger enforcement of the existing
acquis therefore has significant potential to address the shortcomings addressed above.
Accordingly, a 2013 Commission study on comparison tools found that the
"[e]nforcement of existing legal instruments appears to be first a priority"222
.
14 different EU legal instruments and guidance documents may currently apply to
comparison tools, depending on their ownership characteristics and which consumer
sector they operate in. This means that both consumers and comparison tool operators are
unlikely to be fully familiar with their respective rights and obligations. Further
consolidated guidance can be considered here, too.
Option 1: Legislation to ensure every Member State has at least one 'certified'
comparison tool that complies with pre-specified criteria on reliability and impartiality
Under this option, a designated national authority would certify energy comparison tool
websites that meet certain criteria for reliability with some form of 'trustmark' as part of a
voluntary scheme.
These criteria would include: impartiality; quality and accuracy of information; type of
information/characteristics to be compared; transparency on the criteria used for
comparisons; transparency on ranking methodologies; transparency on funding; and
(near) complete coverage of the market. As these criteria would be based on
recommendations contained in the Council of European Energy Regulator’s ‘Guidelines
of Good Practice on Price Comparison Tools’, they would be a product of the expert
opinion of EU NRAs, as well as an extensive public consultation process223
.This sector-
specific approach would plug gaps in the existing legislation, and was recently also taken
to improve comparison tools in the banking sector with the 2014 Payment Account
Directive.
220
See updated Guidance on the UCPD, http://ec.europa.eu/consumers/consumer_rights/unfair-
trade/comparison-tools/index_en.htm.
221
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, pp. 289.
222
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, pp. 287.
223
"Guidelines of Good Practice on Price Comparison Tools",(2012) CEER, Ref: C12-CEM-54-03,
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf.
499
Comparison tools
Box 3: Fourteen CEER recommendations for comparison tools
Independence: Comparison Tools in the energy sector should be independent from energy supply
companies (1), National Regulatory Authorities (NRAs) should maintain a role by assisting self-regulation,
establishing accreditation/regulation or by creating Comparison Tools (2).
Transparency: Comparison Tools should disclose the way they operate, their funding and their
owners/shareholders (3).
Exhaustiveness: All prices and products available for the totality of customers should be shown as a first
step. If not possible, the Comparison Tool should clearly state this before showing results. After the initial
search, the option to filter results should be offered to the customer (4)
Clarity and Comprehensibility: Costs should always be presented in a way that is clearly understood by the
majority of customers, such as total cost on a yearly basis or unit kWh-price including amount and duration
of discounts and whether prices are an estimation based on historic or estimated consumption (5).
Fundamental characteristics of all products, for example fixed price products, floating price products or
regulated end user prices, should be presented on the first page of the result screen. This differentiation
should be easily visible to the customer. Explanations of the different types of offers should be available to
help the customer understand their options (6). The price Comparison Tool should offer information on
additional products and services, if the customer wishes to use that information to help choose the best
offer for them (7).
Correctness and Accuracy: Price information used in the comparison should be updated as often as
necessary to correctly reflect prices available on the market (8).
User Friendliness: The user should be offered help through default consumption patterns or, preferably, a
tool that calculates the approximate consumption, based on the amount of the last bill or on the basis of
other information available to the user (9).
Accessibility: To ensure an inclusive service at least one additional communication channel (other than the
Internet) for getting a price comparison should be provided free of charge or at minimal cost (10). Online
Comparison Tools should be implemented in line with the Web Accessibility Guidelines (WCAG) and
should ensure that there are no barriers to overcome to access the comparison (11).
Customer Empowerment: Where the Comparison Tool is run by an NRA/public body they should promote
the service to customers. Where the NRA/public body is regulating/accrediting/actively monitoring
privately run Comparison Tools they should consider establishing a marker or logo (12). Comparison Tool
providers should provide background information on market functioning and market issues if the customer
wants this information or provide links to useful independent sources of information (13). Information
provided to customers should be clearly written and presented using consistent or standardised terms and
language (14).
The main administrative costs would fall upon national competent authorities who would
be charged with developing accreditation systems, monitoring compliance, and imposing
sanctions. However, the legislation would allow costs to be charged to website operators
seeking accreditation under this scheme. Such costs may be covered by, for example,
increased sales at the level of an accredited (and thus trustworthy) comparison tool.
In Member States where comparison tools are not widely used, it may be difficult to find
one that meets the criteria for certification. The legislation would therefore allow a public
authority such as the NRA to establish a comparison tool conforming to the certification
criteria.
However in more mature markets, existing providers are likely to be willing and able to
fulfil accreditation requirements in order to gain further recognition in the market and
strengthen their reputation with consumers.
500
Comparison tools
Option 2: Legislation to ensure every Member State appoints an independent body to
provide a comparison tool that serves the consumer interest
Examples of such independent bodies could include NRAs, consumer authorities, or
independent consumer groups. The establishment and funding of such comparison tools
would be left to the discretion of the Member State, however the comparison tool must
conform to the same certification criteria put forward in Option 1 to ensure its reliability.
Comparison of the options
7.5.5.
This Section compares the costs and benefits of each of the Options presented above in a
semi-quantitative manner.
In general, the costs of implementing each of the above measures can be estimated to a
reasonably certain degree using tools such as the standard cost model for estimating
administrative costs224
. However, no data or methodology exists to accurately quantify all
the benefits of the measures in terms of direct benefits to consumer (consumer surplus) or
general competition. As such, this Section draws on behavioural experiments from a
controlled environment to evaluate the impact of some policy options on consumer
decision-making. Where appropriate, it aims to illustrate the possible direct benefit to
consumers assuming certain conditions. It also highlights important qualitative evidence
from stakeholders that policymakers should also incorporate into their analysis of costs
and benefits.
Option 0+: Cross-sectorial Commission guidance addressing the applicability of the
Unfair Commercial Practices Directive to commercially operated comparison tools
The cross-sectorial approach addresses shortcomings in commercial comparison tools of
all varieties, and minimizes the proliferation of sector-specific legislation. It helps
national authorities and comparison tool operators understand the relevant EU legislation,
addressing any possible cases of non-compliance. It also leads to a lighter administrative
impact in the Member States.
In spite of these considerations, it is unlikely that Option 0+ would most effectively
address the problem of poor consumer engagement.
Whereas stronger enforcement of the existing acquis has significant potential to address
the shortcomings identified above, the existing acquis does not oblige comparison tools
to be fully impartial, nor does it oblige existing comparison tools to cover (almost) the
whole market in a given Member State. It does not apply to non-profit comparison tools,
and better enforcement alone would not be as effective in boosting consumer confidence
as a proactive accreditation scheme. Moreover, this option would not ensure that all EU
consumers have access to a certified comparison tool – an aspect that is highly desirable
given the important role comparison tools play in engaging energy consumers and the
current disparity in the coverage of energy by comparison tools in various Member States
(Table 1).
224
http://ec.europa.eu/smart-regulation/guidelines/tool_53_en.htm
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Comparison tools
It is unlikely that voluntary cooperation between Member States would address this
problem, as it is domestic in nature with no common gains to be had through supra-
national coordination.
Accordingly, NRAs, ombudsmen, consumer groups, and even industry associations
representing electricity and gas suppliers all support firmer action than Option 0+
proposes. Indeed, the only major stakeholder that partially supports the soft-law approach
embodied in Option 0+ appears to be the European Parliament's Committee on the
Internal Market and Consumer Protection. But even here, the Committee also calls for
EU-wide access to an energy comparison tool – something that cannot be ensure without
legislative changes.
There are no implementation costs associated with Option 0+.
Option 1: Legislation to ensure every Member State has at least one 'certified'
comparison tool that complies with pre-specified criteria on reliability and impartiality
The economic benefits of Option 1 will primarily be indirect, and come in terms of
greater competition (lower prices, higher standards of service and a broader variety of
products on the market). Comparison tools reduce the cost of comparing the market for
consumers and help to lower information asymmetries225
. Indeed, a behavioural
experiment showed that comparison tools increased the number of cheaper offers
consumers were able to identify by between two and twenty times (depending on the
Member State) compared with contacting individual providers directly. Given that
insufficient financial gain is the main consideration for not switching, this option should
therefore help to reduce consumer 'stickiness' and create a more level playing field for
suppliers.
225
Comparison tool users surveyed for a recent EU study reported that they used these tools because they
offered them a quick way to compare prices (mentioned by 69%) and allowed them to find the
cheapest price (68%). Vast majorities of consumers agreed that price comparison websites are the
quickest way to compare prices (in total, 90% agreed), are easy to use (87%), and are useful to find out
information about specific products/prices (84%). "Study on the coverage, functioning and consumer
use of comparison tools and third-party verification schemes for such tools" (2013) European
Commission,
502
Comparison tools
Figure 2: Number of cheaper offers found (mean) – Contacting providers vs. using
comparison tools
12.7
9.2
7.0 6.8 6.1 4.5 4.2 3.9 3.6 3.2
32.5
20.7
49.7
46.3
27.6
36.6
12.3
29.9
12.7
7.7
SE
SI
DE
PL
Total
CZ
IT
UK
ES
FR
Online and phone enquiries
Comparison tools
Mean number of chepaeroffers found
Q17a-d & Q18a-b.Total number of offers found; Total number of cheaper offers
Base: all mystery shoppers (except Lithuania)
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
In addition, Option 1 will directly result in greater consumer surplus. Consumer
protection will be strengthened as suppliers and companies managing comparison tools
will be required to improve levels of transparency. For example, tools will not be
restricted to displaying the offers that are of greatest financial interest to either party.
Customer mobility through transparent publication of all offers will be improved, as will
customer trust through certification.
For this reason, the vast majority of consumers prefer comparison tools with third party
verification. In a behavioural test carried out within the recent study on price comparison
tools 78% of respondents chose an energy comparison tool that included third party
verification over 22% that chose tools with no verification226
.
226
12,000 respondents from 15 Member States: CZ, DE, DK, FR, GR, HR, HU, IT, LV, NL, PL, UK,
RO, SE, SI. The experiment tested (a) consumer choice of a comparison tool at the initial online search
stage using a mock search engine; (b) consumer choice of a comparison tool from a short list; and, (c)
consumer choice of a product or service on an individual comparison tool. The experiment was framed
for the electricity sector and travel sector (hotels). "Study on the coverage, functioning and consumer
use of comparison tools and third-party verification schemes for such tools" (2013) European
Commission, p. 205.
503
Comparison tools
Figure 3: POTP price spread and annual savings available from switching from the
incumbent standard offer
Source: ACER Retail Database (November–December 2014) and ACER calculations
Whilst the economic benefits of Option 1 in terms of increased competition cannot be
quantified227
, one dimension of consumer surplus – the direct financial benefits to
227
EU retail markets differ on too many dimensions to make a comparative approach reliable. And too
many factors affect key retail indicators to make the results of a longitudinal study into comparison
tools reliable.
504
Comparison tools
consumers of easier and more effective switching as a result of this measure – can be
estimated using the following assumptions.
If we assume that:
- The 14 Member States that already have accreditation schemes or at least one
government-operated comparison tool (AT, BE, DK, ES, FI, FR, IE, IT, LU,
PL, PT, SE, SI, UK) would see no additional benefits from this intervention
because they already fulfil its requirements228
;
- The average switching rates for electricity and gas in each of the other
Member States (BG, CZ, DE, EE, EL, HR, HU, LT, LV, NL, RO, SK)229
increased by 0.1% as a result of the intervention230
;
- The annual financial benefit of switching in these Member States amounts to the
difference in price between the incumbent's standard offer and the cheapest offer
in the capital city (Figure 3 above).231
;
- The financial advantage of switching as a result of these measures persists for
four years232
;
- Apart from increasing the switching rate, there were no other benefits of this
intervention in term of improving the ability of switching customers to
identify a better offer233
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms234
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in an increase in consumer surplus of between 27.8 million
euros and 98.3 million euros annually (depending on the year of implementation), and
843 million euros in total for the period 2020-2030. The main implementation costs
would fall upon national competent authorities who would be charged with developing
228
This is a conservative assumption, as it may be that the certification criteria put in place by Option 1
could improve the functioning of some existing certification schemes and government-run comparison
tools.
229
CY and MT were not included in this analysis.
230
Reflecting the increased consumer confidence in comparison tools, which greatly reduce the costs of
comparing the market. 27% of consumers surveyed strongly agreed, and 48% somewhat agreed, that
they trusted comparison tools more when they were affiliated with a third-party verification scheme.
And when respondents in a behavioural experiment were offered the choice between energy
comparison tools that carried no verification and ones that did, the sites that carried verification
schemes were selected 3.5 times more often than the ones that did not. "Study on the coverage,
functioning and consumer use of comparison tools and third-party verification schemes for such tools"
(2013) European Commission, pp. 191, 205.
231
This proxy correlates well with the results of a mystery shopping exercise in which respondents were
asked to report the actual annual savings they would benefit from if they moved to the cheapest
electricity tariff they were able to find. "Second Consumer Market Study on the functioning of retail
electricity markets for consumers in the EU" (2016) European Commission.
232
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
233
A conservative assumption in light of Figure 2.
234
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we
have no reliable data to quantify these differences in this specific context.
505
Comparison tools
accreditation systems or comparison websites, monitoring compliance, and imposing
sanctions.
Box 4: The costs of Elpriskollen.se - the Swedish NRA's comparison tool235
Initial investment (2008): 1,000,000 SEK (EUR 107,000)
IT system upgrade (2014): 280,000 SEK (EUR 29,400)
Website upgrade (2015): 600,000 SEK (EUR 63,600)
Annual running costs:
License: 28,000 SEK (EUR 2,996)
Servers and storage: 72,000 SEK (EUR 7704)
Application support and CGI: 150,000 SEK (EUR 16,050)
1 to 1.7 fulltime positions, depending on the year: EUR 66,768 - EUR 113,506
This equates to c. EUR 110,000 in start-up costs and EUR 105,143 - EUR 151,881 in running costs,
factoring in the annualized costs of periodic website and IT system upgrades.
Box 5: The costs of operating Ofgem's confidence code for comparison tools236
The UK currently has 12 websites that are accredited by a full-time, 3-person team at Ofgem. This small
team deals with ad hoc stakeholder engagements associated with the day-to-day operation of the
confidence code, as well as performing continuous internal audits of accredited websites throughout the
year.
In addition, each accredited website undergoes an external audit every year by an external consultant (19
hours per site), and every new site registered undergoes a substantial external audit (70 hours per site).
This equates to around EUR 214,335 in annual running costs, assuming one new site is accredited each
year
Assuming:
- All Member States currently without any comparison tools (EE, BG, LV, LT, and
RO) set up a state-run comparison tool to fulfil their obligations under Option 1;
- The costs of each of these comparison websites for electricity and gas is 50%
higher than the cost of the Swedish NRA's electricity price comparison website,
which deals with electricity alone (Box 4)237
;
235
Labour costs assume 2,080 work hours per man-year at EUR 32.10 for professionals, as per the
standard cost model.
236
Labour costs assume 2,080 work hours per man-year at EUR 41.50 for managers, EUR 32.10 for
professionals and EUR 23.50 for technicians or associate professionals, as per the standard cost model.
Calculations assume that Ofgem's confidence code team consists of one of each of the aforementioned
categories, and that external consultants charge at the rate of managers.
506
Comparison tools
- All other Member States that would have to make changes under this option (CZ,
DE, EL, HR, HU, NL, SK) set up an accreditation scheme to fulfil their
obligations;
- The costs of the UK's accreditation scheme for energy comparison tools (Box 5)
can help us estimate the cost of accreditation schemes in these Member States;
- The costs of administering accreditation schemes is directly proportional to the
size of the market in terms of households238
;
- The cost of voluntary accreditation schemes to comparison tools is zero239
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in start-up costs of 802,500 euros running costs of between
1 million euros and 1.63 million euros annually (depending on the year of
implementation), and a total cost of between 13.3 euros and 16.5 million euros for the
period 2020-2030.
As regards stakeholder views, Option 1 would likely enjoy broad support amongst all
stakeholder groups. Whilst many stakeholders support the principle that comparison tools
should be independent and accurate without explicitly addressing the means of achieving
this, some – notably including industry groups and the European Parliament's ITRE
Committee, and the Committee of the Regions – explicitly call for certification.
Option 2: Legislation to ensure every Member State appoints an independent body to
provide a comparison tool that serves the consumer interest
As with Option 1, Option 2 would likely result in indirect and unquantifiable economic
benefits in terms of greater competition. It would also result in greater consumer
surplus.
It would ensure EU-wide access to comparison tools free from any commercial interest
that could affect their impartiality. It would also have the additional benefits that national
authorities would be able to censure suppliers by removing their offers from the
comparison tool, there would be no obligation on the private sector, and no risk of claims
of favouritism in a certification process.
When asked which organizations would be the most appropriate to run comparison tools,
51% of comparison tool users thought that they should be run by consumer organisations.
13% selected a national authority or regulator as the most suitable organisation, and 8%
preferred to entrust this task to a private organisation240
. Given these results, one might
expect Option 2 to lead to greater levels of consumer trust than Option 1.
237
This is a conservative estimate given the significant labour cost differences between SE and these
Member States that would make setting up and operating a comparison website cheaper in other
Member States.
238
A conservative estimate, given that the UK appears to have a disproportionately large number of
comparison tools for the size of its market (Table 1).
239
As the scheme is voluntary, comparison tools can be expected to only to make the changes necessary
to qualify for accreditation if they judged this would be in their long-term financial interest anyway.
240
"Study on the coverage, functioning and consumer use of comparison tools and third-party verification
schemes for such tools" (2013) European Commission, p. 203.
507
Comparison tools
Figure 4: Most appropriate organisation to run comparison tools (by country)241
"Study on the coverage, functioning and consumer use of comparison tools and third-
party verification schemes for such tools" (2013) European Commission
If we assume that:
- The average switching rates for electricity and gas in each of the 13 Member
States at least one government-operated comparison tool (BG, CZ, DE, EE,
EL, HR, HU, IE LT, LV, NL, RO, SK)242
increased by 0.13% as a result of
the intervention – 30% more than option one243
;
- The annual financial benefit of switching in these Member States amounts to
the difference in price between the incumbent's standard offer and the
cheapest offer in the capital city (Figure 3 above)244
;
- The financial advantage of switching as a result of these measures persists for
four years245
;
- Apart from increasing the switching rate, there were no other benefits of this
intervention in term of improving the ability of switching customers to
identify a better offer246
;
- All EU households within each Member State are able to benefit from these
changes equally in relative terms247
;
- A discount rate of 4% for the consumer benefits year on year;
241
Question: "Comparison tools can be run by different types of organisations. Among the following
organisations, which one do you think is the most appropriate?" '.
242
CY and MT were not included in this analysis.
243
Reflecting Figure 4. However, this estimate is highly uncertain in light of the fact that it assumes that
Member States would provide sufficient resources for the development of publicly run comparison
tools to match the quality of offerings from the private sector.
244
This proxy correlates well with the results of a mystery shopping exercise in which respondents were
asked to report the actual annual savings they would benefit from if they moved to the cheapest
electricity tariff they were able to find. "Second Consumer Market Study on the functioning of retail
electricity markets for consumers in the EU" (2016) European Commission.
245
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
246
A conservative assumption in light of Figure 2.
247
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we
have no reliable data to quantify these differences in this specific context.
508
Comparison tools
then Option 2 would result in an increase in consumer surplus of between 56 million
euros and 128 million euros annually (depending on the year of implementation), and
1.1 billion euro in total for the period 2020-2030. However, there is a greater degree
of uncertainty in these figures when compared with the workings for Options 1, in light
of possible variance in the effectiveness of such publicly-run comparison tools.
The main implementation costs would fall upon national authorities who would be
charged with developing and managing energy comparison websites248
. Privately-run
comparison sites may also lose market share to comparison tools run by a government-
funded body, although these impacts are impossible to estimate.
Assuming:
- All 13 Member States without a state-run comparison tool (BG, CZ, DE, EE,
EL, HR, HU, IE LT, LV, NL, RO, SK) set one up to fulfil their obligations
under Option 2;
- The costs of each of these comparison websites for electricity and gas is 50%
higher than the cost of the Swedish NRA's electricity price comparison
website, which deals with electricity alone (Box 5)249
;
- A discount rate of 4% year on year;
then Option 2 would result in start-up costs of 2.09 million euros, running costs of
between EUR 1.36 million and EUR 2.96 million euros annually (depending on the
year of implementation), and a total cost of between 20.6 million euros and 28.9
million euros for the period 2020-2030.
As regards stakeholder views, Option 2 may not enjoy broad support amongst all
stakeholder groups and Member States. Whilst all stakeholders emphasize the
independence of comparison tools, and some explicitly support certification (Option 1),
none have voiced their exclusive support for a publicly run and funded energy
comparison tools.
Conclusion
Option 1 is the preferred option. By proportionately updating the existing acquis,
establishing a mechanism to proactively build consumer trust, and ensuring all EU
consumers have access to a comparison tool, it strikes the best balance between
consumer welfare and administrative impact. It also gives Member States control over
whether they feel a certification scheme or a publicly-run comparison tool best ensures
consumer engagement in their markets.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the
preceding pages, accrue predominantly to consumers who are engaged in the market, and in particular
those who compare offers using the Internet. Whilst reliable comparison tools will also increase consumer
248
The costs to suppliers in terms of notifying such sites of their is not considered significant.
249
This is a conservative estimate given the significant labour cost differences between SE and these
Member States that would make setting up and operating a comparison website cheaper in other
Member States.
509
Comparison tools
engagement levels, and whilst the increased competition engendered by comparison tools will lead to more
competitive offers on the market, disengaged consumers and consumers who do not use the Internet,
including consumers who may be vulnerable, will not reap as many direct benefits from this policy
intervention.
Subsidiarity
7.5.6.
Consumers are not taking full advantage of competition on energy markets due, in part,
to obstacles to switching. Well designed and implemented consumer policies with a
European dimension can enable consumers to make informed choices that reward
competition, and support the goal of sustainable and resource-efficient growth, whilst
taking account of the needs of all consumers. Increasing confidence and ensuring that
unfair trading practices do not bring a competitive advantage will also have a positive
impact in terms of stimulating growth.
Comparison websites are an effective means of reducing search costs for consumers and
presenting them with accurate price and market information. Although they have become
increasingly important in recent years, the majority of comparison websites are operated
for profit, leading to situations where their impartiality and the consumer interest may not
be ensured. Recent reports of unscrupulous practices have damaged consumer trust in
comparison websites, suggesting the need to boost consumer confidence in such tools.
The options here revolve around improving the accessibility and reliability of comparison
websites, both commercial and not-for-profit, through improved legislative guidance,
certification schemes and/or differing obligations on Member States to ensure the
availability of such websites. Similar legislative provisions on comparison tools already
exist in other sectorial legislation (i.e. financial sector with the 2014 Payment Accounts
Directive250
).
The legal basis for the legislative options proposed (Options 1 and 2) is therefore likely
to be Article 114 TFEU. This allows for the adoption of "measures for the approximation
of the provisions laid down by law, regulation or administrative action in Member States
which have as their object the establishment and functioning of the internal market". In
doing this, in accordance with Article 169 TFEU, the Commission will aim at ensuring a
high level of consumer protection.
Without EU action, the identified problems related to the lack of an EU-wide market will
continue to lead to consumer detriment.
Option 0+
These options would fulfil the subsidiarity principle as they do not involve legislative
change and the subsidiarity of the existing legislation has been assessed previously.
However, consumer protection will continue to be compromised as consumers will not
have the assurance of comparison tool independence or of full transparency of all offers
250
Directive 2014/92/EU of the European Parliament and of the Council of 23 July 2014 on the
comparability of fees related to payment accounts, payment account switching and access to payment
accounts with basic features. Text with EEA relevance.
510
Comparison tools
available on the market. This is because of shortcomings inherent in the existing
legislation.
Option 0+ would therefore not meet the proportionality principle as it would not achieve
the objective of the Article of the Treaty taken as their legal basis – the establishment and
functioning of the internal market.
Option 1
The principles of subsidiarity and proportionality would be best met through this Option
as it would concretely improve the functioning of the internal market and reduce levels of
consumer detriment, whilst leaving national authorities broad flexibility to tailor
measures to the characteristics of their markets and their available resources.
Option 2
The principles of subsidiarity and proportionality may not be respected in this Option as
it may be excessive in terms of the implied impact on certain Member State authorities
who would need to establish an independent body to provide a comparison tool service.
Moreover, it is not clear that customer mobility or consumer protection would improve
with the introduction of such a body in all Member States as the reliability and user-
friendliness of at least some private sector comparison tools may already be of a high
standard.
Stakeholders' opinions
7.5.7.
Public Consultation
When asked to identify key factors influencing switching rates, 110 out of 237
respondents to the Commission's Consultation on the Retail Energy Market251
stated that
prices and tariffs were too difficult to compare due to a lack of tools and/or due to
contractual conditions.
178 out of 237 agreed that ensuring the availability of web-based price comparison tools
would increase consumers' interest in comparing offers and switching to a different
energy supplier. 40 were neutral and 4 disagreed.
Only 32 out of 237 respondents agreed with the statement: "There is no need to
encourage switching". 98 disagreed and 90 were neutral.
National Regulatory Authorities
ACER has argued that having reliable web comparison tools in place (allowing
comprehensive and easy ways to compare suppliers) can facilitate consumer choice and
consumer engagement by addressing the perceived complexity of the switching process.
It has therefore recommended that: "To improve consumer switching behaviour and
awareness further, National Regulatory Authorities (NRAs) could become more actively
involved in ensuring that the prerequisites for switching, such as transparent and
251
Held from 22 to 17 April 2014. https://ec.europa.eu/energy/en/consultations/consultation-retail-
energy-market
511
Comparison tools
reliable online price comparison tools and transparent energy invoices, are properly
implemented."
CEER252
sees price comparison tools as a crucial instrument to provide information to
electricity and gas customers. There are a range of routes to setting standards for
comparison tools. NRAs or another public body may establish their own comparison
tools or they may regulate private comparison tools. Alternatively, self-regulation by
comparison tools providers may be appropriate. Whatever the route, CEER's position is
that it is important that comparison tools are independent from energy supply companies,
that they are accurate and that they ideally present the full range of offers available.
In 2012, following an extensive consultation process, CEER published 14
recommendations covering the following aspects of comparison tools in the energy
sector: Independence; transparency; exhaustiveness; clarity and comprehensibility;
correctness and accuracy; user-friendliness; accessibility; and empowering customers253
.
Ombudsmen
According to NEON, the National Energy Ombudsmen Network, regulators are best
placed to define the criteria of transparency and reliability of price comparisons tools and
to assess them. NEON insisted on referring to the 2012 CEER Guidelines of Good
Practice on Price Comparison Tools and the 15 recommendations they contain254
.
Bodies in charge of providing information to consumers (single point of contact) and
organisations in charge of alternative dispute resolution (or an independent ombudsman),
as well as consumer associations (i.e. impartial bodies with no advertising or consumer
champion role, thanks to their independence from suppliers) are according to NEON best
placed to develop neutral and reliable tools. This may also be the case of private
companies, as long as they do not favour certain suppliers that would fund them or with
which they have special agreements. For all tools implemented, an annual auditing of the
regulator would be necessary: the list of approved comparison tools and a summary of
the auditing may be published and accessible online.
If the regulator sets up a price comparison tool, another authority should be responsible
for carrying out auditing, even from another Member State (peer review).
Consumer Groups
BEUC believes it is essential that the consumer gets clear and independent information
on different offers. Regardless of who is running the comparison website, it must be
ensured that the information consumers get is impartial, up to date, accurate and provided
in a user friendly way and free of charge. The comparison tool should also enable
consumers to compare their current contract with new offers in an easy way.
252
The Council of European Energy Regulators.
253
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf
254
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf
512
Comparison tools
At the same time, BEUC strongly believes there should be at least one independent
comparison tool for electricity and gas services in every Member State. In order to secure
the success of such a comparison tool, it is paramount to secure also a legal basis for
collection of price data. In addition, whilst comparison tools are increasingly used by
consumers, the proliferation of comparison tools and the influence they can have on
consumers’ decisions have given rise to concerns about their trustworthiness.
According to BEUC, if the transparency and reliability of comparison tools is not
guaranteed, if the full scale and high quality of the information they provide is not
ensured or if they do not comply with existing legislation, comparison tools can become
a source of consumer detriment and risk misleading and thereby undermining consumers’
trust in the market255
.
According to Citizens' Advice (UK) comparison tools can be operated by a regulator, a
consumer body or a private business that is appropriately regulated. The focus should
rather be on the establishment of key principles to the effect that the sites display
information in a way that is accurate, consistent, transparent, comprehensive and
unbiased. The tool must have all tariff data available from all suppliers in the market and
include information about termination fees, etc. The comparison should be based on the
customer's actual usage.
Suppliers
In their contribution to the discussions within the Citizens' Energy Forum in 2016,
EURELECTRIC considered that it is the task of regulators to make sure that
comparison tools are neutral, do not limit innovation and do not favour any specific
supplier, either directly (for example, if they collect different fees from different
suppliers) or indirectly (for example, if their IT systems are not able to process all offers).
EURELECTRIC and its members have repeatedly argued in favour of certifying
comparison tool with e.g. a trust mark from the regulator, and stressed their full support
for the Commission’s initiatives to work with NRAs to develop transparency and
reliability criteria for comparison tools where these do not exist yet.
Eurogas also welcomed the role that price comparison websites can play in national
energy markets, and argued that consumers should have access to such price comparison
services. For Eurogas, both price comparison websites operated by commercial entities as
well as non-commercial bodies operated by the NRA can provide "independent" services
to consumers. In order to ensure that this is the case, Eurogas supports an accreditation
system for such websites. According to Eurogas, experience in Member-States such as
the UK and the Netherlands suggests that price comparison websites develop over time,
with private companies establishing comparison services.
Whatever approach is adopted, Eurogas states that the funding of these sites should be
transparent. Regulation should be proportionate and would benefit from referring to the
255
http://www.beuc.eu/publications/beuc-x-2015-068_mst_building_a_consumer-
centric_energy_union.pdf
513
Comparison tools
2012 CEER Guidelines of Good Practice on Price Comparison Tools256
. Moreover, for
recommendations and best practices on price comparison tools, reference should be made
to the 2012 Report of the CEF Working Group on Transparency in EU Retail Energy
Markets257
.
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Parliament's Committee on Industry, Research and
Energy (ITRE): "Recommends developing guidelines for price comparison tools to
ensure that consumers can access independent, up-to-date and understandable
comparison tools; believes Member States should consider developing accreditation
schemes covering all price comparison tools, in line with CEER guidelines."
In addition, ITRE: "Recommends the creation of new platforms to serve as independent
[comparison tools] to provide greater clarity to consumers on billing; recommends that
such independent platforms provide consumers with information on the percentage share
of energy sources used and the different taxes, levies and add-ons contained in energy
tariffs in a comparable way to empower the consumer to easily seek more suitable offers
in terms of price, quality and sustainability; suggests that this role could be assumed by
existing bodies such as national energy departments, regulators or consumer
organisations; recommends the development of at least one such independent price
comparison tool per Member State."
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Parliament's Committee on the Internal Market and
Consumer Protection (IMCO) called on the Commission: "to ensure the
implementation of the Unfair Commercial Practices Directive and for better cooperation
between national authorities of Member States investigating such practices". It also
welcomed "the Commission’s intention to consider incorporating laws specifically
concerning energy into the Annex to the Regulation on Consumer Protection
Cooperation", although this measure was not eventually pursued by the Commission.
IMCO also called for: "European Union guidelines on independent, up-to-date and easy-
to-use price comparison tools, in particular to improve transparency, reliability, and
competition between all market players and to make it accessible and easier for
consumers to compare offers including types of contracts, prices and types of energy
sources." It finally supported: "access for all consumers to at least one price comparison
tool for energy services."
The Committee of the Regions
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Committee of the Regions supports the idea of
ensuring that each consumer has access to at least one independent and verified
256
http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b3/C12-CEM-54-03_GGP-PCT_09Jul2012.pdf
257
https://ec.europa.eu/energy/sites/ener/files/documents/2012111314_citizen_forum_meeting_working_gr
oup_report.pdf
514
Comparison tools
comparison tool. According to the Committee, these comparators must be clear,
comprehensive, trustworthy and independent, easy to use and free of charge. They should
allow existing contracts to be compared with offers available on the market. Whereas
suppliers tend to diversify their offers by including services in energy supply contracts,
comparison tools must make it possible to compare the different "packages" on offer,
while at the same time enabling the "supply" element of the various packages to be
compared on its own.
515
Improving billing information
7.6. Improving billing information
516
Improving billing information
Summary table
7.6.1.
Objective: Ensuring that all consumer bills prominently display a minimum set of information that is essential to actively participating in the market.
Option: 0 Option 0+ Option 1 Option 2
BAU/Stronger enforcement Commission recommendation on billing
information
More detailed legal requirements on the key
information to be included in bills
A fully standardized 'comparability box' in bills
Pros:
- 77% of energy consumers agree or strongly
agree that bills are "easy and clear to
understand".
- Allows 'natural experiments' and other
innovation on the design of billing information to
be developed by Member State.
- Recent (2014) transposition of the EED means
premature to address information on energy
consumption and costs.
Pros:
- Low administrative impact
- Gives Member State significant
flexibility to adapt their requirements to
national conditions.
- Allows best practices to further
develop.
Pros:
- Ensures that the minimum baseline of
existing practices is clarified and raised.
- Allows best practices to further develop,
albeit less than Option 0.
- Improves comparability and portability of
information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
- Bill design left free to innovation.
Pros:
- Highest legal clarity and comparability of
offers and bills.
- A level playing field for all consumers and
suppliers across the EU.
- Very little leeway for suppliers to differently
interpret the legislation with regards to the
presentation of information.
- Ensures consumers can easily find the
information elements needed to facilitate
switching.
Cons:
- Poor consumer awareness of market-relevant
information can be expected to continue.
- Does not respond to stakeholder feedback on
need to ensure minimum standards.
Cons:
- A recommendation is unenforceable
and may be ignored by Member
State/utilities.
- Poor consumer awareness of market-
relevant information can be expected to
continue.
- Does not respond to stakeholder
feedback on need to ensure minimum
standards.
Cons:
- Limits innovation around certain bill
elements.
- Remaining leeway in interpreting legal
articles may lead to implementation and
enforcement difficulties.
Cons:
- Challenging to devise standard presentation
which can accommodate differences between
national markets.
- Highest administrative impact.
- Prescriptive approach prevents beneficial
innovation.
- Difficult to adapt bills to evolving
technologies and consumer preferences.
Most suitable option(s): Option 1 is the preferred option as it likely to leads to significant economic benefits and increased consumer surplus without significant administrative costs or the
risk of overly-prescriptive legislation at the EU level.
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Improving billing information
Description of the baseline
7.6.2.
The evidence presented in this Annex draws extensively on survey data, as well as data
from a mystery shopping exercise. The aim of the mystery shopping exercise was to
replicate, as closely as possible, real consumers’ experiences across 10 Member States258
selected to cover North, West, South and East Europe countries. A total of 4,000
evaluations were completed between 11 December 2014 and 18 March 2015259
. Whilst
data from the mystery shopping exercise is non-exhaustive, the methodology enables the
controlled sampling of a very large topic area260
, as well as providing insights that would
not be apparent in a desktop evaluation of legislation and bills. Using a behavioural
research approach rather than a traditional survey allowed us to identify what people
actually do, rather than what they say they do.
Energy bills and annual statements be they paper or digital, are the most likely regular
communications from suppliers to be noticed and read by consumers. They are therefore
an important means through which consumers get information on their interaction with
the market. As well as data on consumption and costs, they can also convey a host of
other material which helps consumers to compare their current deal with other offers –
the name and duration of their contract, for example.
The Electricity and Gas Directives contain the following key provisions related to
metering and billing:
- Article 3 Billing and promotional material
- 3(3) Access to comparable and transparent supply options (Electricity
only)
- 3(5)/3(6) Access to consumption data
- 3(9) Disclosure of the overall fuel mix and environmental impact of the
supplier (Electricity only)
- Annex I Consumer protection
- 1.c) The transparency of applicable prices and tariffs
- 1.d) Consumer payment methods
- 1.i) Frequency of information on consumption and costs
- 2. Intelligent metering systems (smart meter roll-out)
In addition, The Energy Efficiency Directive contains the following key provisions:
- Article10 Billing information (in conjunction with Annex VII)
- 10(1) Consumption based billing (information) requirement in general
(incl. as regards minimum frequency)
- 10(2) Requirements on consumption information from smart meters
- 10(3) General information and billing requirements pertinent to costs,
consumption and payment
258
The Czech Republic, France, Germany, Italy, Lithuania, Poland, Slovenia, Spain, Sweden and the UK.
259
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
260
For example, there were over 400 electricity and gas supply offers in Berlin alone in 2014 (source:
ACER Database), making a comprehensive examination of all supply offers in the EU28
impracticable.
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Improving billing information
- Article 11 Cost of metering and billing information
- 11(1) Metering and billing generally free of charges
Whereas the EU acquis contains a relatively small number of general measures on energy
billing, all Member States have legislation with further billing requirements. For
example, UK electricity and gas suppliers must follow over 70 pages of rules on the
information in bills as part of their current licensing requirements. In recognition of the
likelihood of being overly prescriptive at present, the UK NRA is undertaking a pilot
project to improve billing in the interest of consumers.
Box 1: Select requirements for UK domestic energy bills261
The following information must be grouped together, in a box, distinct from other information and
included on page one of the Bill:
- The standardised title “Could you pay less?”
- Information on cheaper tariffs offered by the supplier and the savings available if the consumer were
to switch.
- A Personal Projection* for the consumer's current tariff.
- A signpost to further tariff information.
- A standardised switching reminder “Remember – it might be worth thinking about switching your
tariff or supplier”.
The following information must be grouped together and included on page two of the Bill, in a box,
distinct from other information, in the following order:
- The standardised title “About Your Tariff”.
- The name of the customer's fuel, current tariff, payment method, any applicable tariff end date, exit
fees and the customer's personalised usage in the last 12 months.
The following information must be provided anywhere on a bill:
- The standardised title “About Your TCR”**.
- The TCR for the customer's current tariff.
- A signpost to where to find independent advice on switching supplier.
* The Personal Projection is a standardised methodology that uses a consumer's actual or estimated
consumption to estimate their projected cost for a particular tariff for the next year.
** The TCR or 'Tariff Comparison Rate' is used to assist consumers to make an initial comparison of
alternative tariffs. It is similar in nature to the Annual Percentage Rate used to describe savings, loan and
credit agreements.
261
"The Retail Market Review – Final domestic proposals Consultation on policy effect and draft licence
conditions", (2013) Ofgem, pp. 71-108, 130-163
https://www.ofgem.gov.uk/sites/default/files/docs/2013/03/the-retail-market-review---final-domestic-
proposals.pdf. See also Gas and Electricity Markets Authority, 'Standard conditions of electricity
supply licence'
https://epr.ofgem.gov.uk//Content/Documents/Electricity%20Supply%20Standard%20Licence%20Co
nditions%20Consolidated%20-%20Current%20Version.pdf
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Improving billing information
Table 1 below presents an overview of billing practices and regulation per country. There
is a large variation in how countries choose to approach the subject, in particular with
regards to the extent to which the content of bills is specifically defined in national
legislation. Three broad approaches can be identified:
- Highly prescriptive (HP) approaches relying on legal instruments or resolutions,
which request a large amount of detail and/or give very specific instructions on
what information to provide in electricity bills.
- Legislation which specifies the main information (MI) that must be included in
bills, which is subsequently reinforced by guidance from the regulator (in terms
of mandatory information and format, or best practice guidance).
- Legislation that specifies the main information, but leaves electricity providers
broad freedom (BF) to communicate this within their own format.
In the following table, billing practices in each country are described, noting what are
considered to be a highly prescriptive approach (HP), an approach enforcing
communication of main information (MI) and, finally, an approach that allows broad
freedom (BF).
Table 1: Billing practices and regulation per country262
Austria (MI) Article 81 of EIWOG specifies which information should be presented on the electricity
bill. This provision is further detailed by ordinances from the regulator, in which
suggestions are given as to how to present the mandatory information, including the energy
sources breakdown and the price components. The contents of the documents (e.g.
electricity bill, contract, etc.) are detailed not only in the Electricity Act, but also in the
Renewable Energy Act, the System Charges Order, the Electricity Duty Act, as well as in
individual Federal states legislation. The ‘DAVID-VO’ Ordinance (Articles 1-5) specifies
the information that electricity suppliers must give to customers.
Belgium (HP) Law April, 29th 1999 ‘Loi relative à l'organisation du marché de l'électricite’ details the
mandatory information to be present in a consumer’s bill. The information to be presented
in the bill is highly regulated, with 10 mandatory headings and many mandatory sub-
headings which detail the information to be provided.
Bulgaria (BF) The Bulgarian Consumer Protection Act (Art. 4, Par. 1) outlines a minimum set of
requirements for information to be provided to the customer such as: (1) information on the
composition, (2) the supplier’s contact details, (3) the trader’s complaint handling process,
and 4) arrangements for payment.
Croatia (MI) Articles 49 and 63 of the Act on Electricity Market (Official Gazette, no. 22/13, 95/15 and
102/15) regulate billing. In Croatia, regulations specify that the supplier needs to deliver an
electricity bill that contains the following elements: the share of the price that is freely
negotiated, the share that is regulated and fees and other charges prescribed by special
regulations.
Cyprus (MI) Article 91 (1)(d)(iv) and Article 93 (1)(j) of the Electricity Law 206(Ι)/2015 regulate how
the consumption of electricity should be communicated to consumers. The tariffs of the
main energy provider are regulated by the Cyprus Energy Regulatory Authority (CERA)
and they can be found on the website of the Electricity Authority of Cyprus (EAC).
Czech
Republic
(DF)
Bills for electricity, gas, heat supply and related services are governed by Act nr. 458/2000
Coll. in articles 11(a) and 98a. Electricity suppliers are to publish the conditions and price
of electricity supply for households and residential customers in a way that can be accessed
remotely. If increasing the prices for the supply of electricity, the supplier is obliged to
notify the consumer in advance. In the case of electricity and gas, outstanding charges are
262
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
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Improving billing information
billed at least once a year.
Denmark
(MI)
Regulation of billing information is implemented in Executive Order no.486 of 2007 on
electricity billing. However, the Danish Energy Regulatory Authority has presented an
executive order which gives consumers the possibility to receive a simplified bill. The
purpose of this order is to give consumers a better understanding of the price elements and
an incentive to be active on the energy market. This order was implemented in Danish law
in October 2015.
Estonia (MI) Electricity Market Act §75 stipulates the following: “the seller shall submit an invoice for
the electricity consumed to the customer once a month, unless agreed otherwise with the
customer”. It is mandatory for suppliers to include information not just on consumption but
also on emissions and waste (nuclear and oil shale) as well as dispute resolution options.
Finland (MI) Part III, Ch. 9, 69 § of the Electricity Market Act (588/2013) outlines the legal
requirements with regards to billing imposed by the electricity provider. In the bill, the
provider is to include details on how the price is broken down, information on the
contract’s duration and which dispute-solving tools consumers have at their disposal.
France (HP) Article 4 of the Regulation 18 April 2012 covers electricity or natural gas bills, their
payment modalities and reimbursement of overpayment (i.e. bill based on an estimation of
the consumption). The bill must include information on over 16 different headings. The
website ‘Energie info’, made available by the National Energy Ombudsman, illustrates and
explains this mandatory content to consumers.
Germany
(MI)
The right to receive clear information on one’s energy contract before signing, and to be
informed in advance if any changes are made to the contract, are provided for within
German law (article 41 EnWG). The EnWG (Section IV art. 40) specifies the content that
should be provided to consumers on their electricity bills. The German Institute for
Transparency on Energy (DIFET) produces certificates for those suppliers that provide
consumer-friendly bills.
Greece (BF) The new Code of Electricity Supply regulates the tariffs of electricity suppliers.
Specifically, this code describes what must be included in the bill and how the bill must be
broken down into three different elements: (1) regulated charges; (2) competitive charges
or supply charges; and (2) other charges.
Hungary (HP) Law 2013. évi CLXXXVIII. törvény az egységes közszolgáltatói számlaképről regulates the
content of bills. The law gives actual examples of the minimal information necessary on
each bill and also gives examples as to which elements may be changed or added without
infraction. The law also imposes such details as fonts and font sizes and provides in its
annexes a detailed example of the respective bill in its actual detail. Additionally to the
law, the electricity suppliers also regularly provide a dedicated Section on how to read the
electricity bill.
Ireland (MI) Statutory instruments S.I. No. 426/2014 Part 4, Art. 6, Art. 7 and S.I. No. 463/2011, Art. 9,
regulate the communication of charges and consumption information to electricity
consumers in Ireland. Under Irish law, suppliers must also inform customers of upcoming
price changes at least one month before a price change comes into effect.
Italy (MI) D.Lgs 93/11 Art. 43(2); L 125/07 Art. 1(6) and Art. 1(5) legislate the communication of
charges and consumption information. Consumers should be informed of the components
relating to supply cost (servizi di vendita), network cost (servizi di rete), general system
charges (oneri generali di sistema), and taxes (VAT and other consumption taxes). The
regulator has set up several tools in order to help the consumer understand his bill, most
notably a dedicated webpage ”Your Bill Explained” (la bolletta spiegata) and a consumer
help-desk (lo Sportello per il Consumatore).
Latvia (MI) According to Art. 31 3° of Electricity Market Law, the Public Utilities Commission (PUC)
shall determine what kind of information and to what extent electricity supplier shall
include in their bills and informative materials that are issued to the consumer. The
regulations of the PUC determines that a bill shall include at least the electricity amount in
kWh supplied in billing period, the amount charged for consumed electricity in euros and
the average electricity price in euro per kWh during the billing period and fees for
electricity distribution system services, other additional services and the mandatory
procurements components and total fees for the billing period for consumers and other end-
users to whom shall be issued invoices regarding electricity service supply.
Lithuania
(BF)
Law on Energy of the Republic of Lithuania No. IX-884 and Law on Electricity of the
Republic of Lithuania No VIII-1881. Article 31 regulate the communication of charges and
consumption information to electricity consumers in Lithuania, as well as contractual
conditions and changes to contracts. The consumer is entitled to receive information on
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Improving billing information
conditions of service and electricity prices and tariffs, reports on prices, contract terms,
conclusion and termination conditions.
Luxembourg
(BF)
Article 2(5) of the Law of 1 August 2007 regulates the communication of charges and
consumption information to electricity consumers in Luxembourg, as well as contractual
terms. With respect to billing, the law states that electricity providers must transmit to
residential customers transparent information on tariffs and prices.
Malta (MI) Electricity Market Regulations (S.L. 545.16), Art. 8(3) regulates billing. Bills issued by
Enemalta Corporation, Malta’s electricity supplier, must include contact details of its
subcontractor, ARMS Ltd, which is the company responsible for meter reading, billing,
debt collections and customer care services. Households should receive bills calculated on
actual consumption at least every six months. For households with a smart meter, these
bills based on actual readings are more frequent. All bills show a breakdown of the price
calculation, the total electricity consumption for that period as well as the average daily
energy consumption, relevant tariffs and CO2 emissions.
Netherlands
(MI)
The Electricity Act, article 95, details the mandatory information to be provided on an
energy bill and some associations provide recommendations for data presentation. The
breakdown of an energy bill concerns supply costs (“leveringskosten”), network costs and
metering costs, and then taxes (“Belasting”). While using green energy, some taxes are
refunded (“Belastingvermindering”).
Poland (MI) The Energy Law, Art. 5. 6a - 6c. regulates the communication of charges and consumption
information to electricity consumers in Poland. Electricity suppliers are to inform
consumers about the fuel supply mix used in the previous calendar year and about a place
where information is available about the impact of the production of energy on the
environment (at a minimum in terms of carbon dioxide emissions and radioactive waste
created). Electricity suppliers must also inform consumers about the amount consumed in
the previous year and the place where information is available about the average electricity
consumption for each connection group of recipients, energy efficiency improvement
measures and the technical characteristics of energy-efficient appliances.
Portugal (BF) Art. 54 d) and Art.55 c) and d) of Decree Law of 15 February 2006 regulate the
communication of charges and consumption information to electricity consumers in
Portugal. Under the law, consumers are entitled full and adequate information to enable
their participation in the electricity market, access information in a transparent and non-
discriminatory manner on applicable prices and tariffs, as well as complete and adequate
information in order to promote energy efficiency and the rational use of resources.
Romania (HP) Law 123/2012 (modified in 2014) ART.62 (1) h9
) and art. 145 (4) p) and Law 123/2012
(modified in 2014) ART. 66 (1),(2) regulate the content of bills. The Energy Authority
ANRE has made available to the consumer an explanatory sample of the components that
have to be included in the bill. This model has been adopted by electricity suppliers, who
can also opt to display the same document at their websites, in order to inform consumers
about the contents of their bill.
Slovakia (MI) The supplier of electricity and gas is, according to the § 17 article 14 of the Law 251/2012,
obliged to inform the customer on the invoice or attached material about the particular
components of the energy supply including the unit price. Information about the
composition of the price component has to include the unit price especially for electricity
purchase including the commercial activity of the supplier, distribution, losses during
distribution, system services, system operation and taxes.
Slovenia (MI) Beside standard items that must be included in every invoice issued in Slovenia that are
stipulated by the Value Added Tax Act (invoice date, number, invoice issuer’s contact
details, amounts billed, VAT rate,…), consumers also have to receive certain information
in their electricity bills, stipulated within Article 42 of the Energy Act, including the
proportion of energy source that supplier used in preceding year in a way comparison
between different suppliers can be made, the reference source where publicly available data
on environmental impacts, expressed in CO2 emissions and amounts of radioactive waste
resulting from the electricity production in the preceding year, and consumers’ rights
related to dispute resolution.
Spain (HP) Law 24/2013 establishes the type of information that should be included in an electricity
bill. This format is mandatory for the suppliers of last resort. The details of the information
are formally listed in the resolution N.5655 of 23 May 2014 of the Ministry for the
Industry, Energy and Tourism. The resolution illustrates in its annex a template to be
followed when producing electricity bills, showing in explanatory graphs and in detailed
tables the mandatory information and its granularity.
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Improving billing information
Sweden (BF) The Electricity Act chapter 8, §14-16 specifies that an electricity supplier’s billing shall be
clear. It shall contain information on the measured consumption and current electricity
prices that the billing shall be based on. The Swedish Energy Markets Inspectorate
specifies in detail what shall be contained in electricity bills. The electricity cost consists of
two parts: (1) a payment to the grid operator to stay connected and (2) payment for the
actual electricity consumption and the electricity cost.
UK (MI) The consumers’ right to accurate consumption information is captured in Condition 31A of
the Standard Licence which makes it incumbent on suppliers to provide customers with
electricity consumption information in each bill (or, within the space of 30 days from a
notice of increase in charges in cases where the latter is issued). In addition, suppliers must
send an annual statement to all customers in a pre-defined format. Schedule 2ZB to the
Electricity Act stipulates that licence-exempt suppliers must also provide consumption data
to customers on an annual basis. Under Condition 12 of the Standard Licence, suppliers
must take meter readings at least once every two years. Condition 21B of the Standard
Licence allows customers to read their own meters as often as they choose. Suppliers are to
reflect that reading in the subsequent bill. The structure of the bill is not fixed by any
legislation.
In addition to EU and national legislative requirements, suppliers communicate and
present information in different ways as a part of their non-price competition with other
suppliers. For example, information may be presented in a certain format for branding
purposes, or to target different customers with different kinds and levels of information
to increase consumer satisfaction.
As a result of these three different factors – EU legislation, national legislation and
commercial competition – there is therefore currently a broad divergence in Member
States with regards to the individual elements in electricity and gas consumer bills and
the total amount of information in these bills.
Figure 1 below from ACER summarizes the information provided to household
customers on their bills. It includes general billing requirements put forward in Article 3
and Annex I of the Electricity and Gas Directives (for example, information on the single
point of contact), as well as items not covered by EU law (price comparison tools).
Whereas customers in the majority of Member States are currently provided with
information on the consumption period, actual and/or estimated consumption, and a
breakdown of the price, there is a greater diversity of national practices with regards to
other potentially beneficial information, such as switching information, information
about price comparison tools, and the duration of the contract.
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Improving billing information
Figure 1: Information on household customer bills in Member States – 2014
Source: CEER Database, National Indicators (2014-2015)
The results of a mystery shopping exercise on the information in energy bills covering
ten representative Member States263
provide a more detailed impression of the
differences in billing practices within the EU. Mystery shoppers were instructed to
analyse one of their own monthly, bi-monthly or quarterly electricity bills for a number
of information elements identified as best practices by the Citizens' Energy Forum's
Working Group on Billing264
(Table 2) as well as a number of information elements
addressed (although not always required) by the current Electricity Directive (Table 3)265
.
The exercise was carried out between 11 December 2014 and 18 March 2015.
263
The Czech Republic, France, Germany, Italy, Lithuania, Poland, Slovenia, Spain, Sweden and the UK.
264
"Implementation of EC Good Practice Guidance for Billing", (2010) CEER, http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b1/E10-CEM-36-03_EC%20billing%20guidance_8-Sept-2010.pdf.
265
https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-billing_energy_data.pdf
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Improving billing information
Table 2: Information included on an electricity bill in a sample of ten Member States - I266
Country
Item Item in "billing" evaluation
sheet
% who
found item
on their bill
(total)
CZ DE ES FR IT LT267
PL SE SI UK
Supplier's name Provider’s name 99% 96% 100% 100% 100% 100% 88% 100% 100% 100% 100%
Contact details (including
their helpline and emergency number)
Telephone number of customer
service/helpline
96% 92% 100% 100% 100% 100% 80% 93% 100% 100% 97%
Postal address of provider 94% 92% 100% 97% 100% 100% 60% 100% 96% 100% 83%
Email address of provider 69% 92% 95% 80% 27% 37% 40% 75% 84% 96% 60%
Emergency number (e.g. to call
in the event of an electrical
emergency or power outage)
59% 68% 8% 97% 87% 93% 28% 35% 64% 40% 87%
The duration of the contract Duration of the contract (e.g. 24
months)
22% 8% 50% 27% 17% 10% 0% 5% 40% 4% 50%
The deadline for informing the supplier about
switching to another supplier
The period of notice to
terminate your electricity
contract (e.g. 30 days before the
intended termination date)
19% 4% 50% 0% 57% 0% 12% 0% 28% 0% 27%
The tariff name Tariff name/plan (e.g. 'Day &
Night Fix')
80% 84% 65% 57% 87% 93% 60% 93% 80% 76% 100%
(A reference to) a clear price breakdown for the
tariff (the base price plus all other charges and
A detailed price breakdown for
your tariff (e.g. division of total
79% 92% 65% 100% 83% 93% 8% 88% 92% 96% 73%
266
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the EU" (2016) European Commission.
267
Lithuania stands out as the country where mystery shoppers were the least likely to find each of the items on their bill. Mystery shoppers in Lithuania (note: all shoppers were
clients of Lesto) reported that they do not receive an electricity bill; they declare usage themselves online (via www.manoelektra.lt - a site dedicated to Lesto customers) or by
means of a paper bill book.
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Improving billing information
Country
Item Item in "billing" evaluation
sheet
% who
found item
on their bill
(total)
CZ DE ES FR IT LT267
PL SE SI UK
taxes) price in base price, network
charge, etc.)
The base price of one energy unit (in kilowatt
hours or kWh) for the selected tariff
Base price per kWh of your
tariff
82% 68% 65% 87% 93% 83% 68% 83% 92% 88% 93%
The switching code Switching code/meter
identification (EAN or MPAN
code; a unique code for your
electricity meter)
73% 96% 58% 87% 87% 67% 44% 78% 76% 72% 67%
The amount to be paid, for which billing period,
by when and how
Amount to be paid 97% 100% 100% 97% 97% 100% 72% 100% 100% 100% 97%
Billing period (e.g. 15
November – 14 December
2014)
95% 96% 90% 100% 97% 100% 80% 93% 100% 100% 97%
Payment method (e.g. direct
deposit, cheque, bank transfer)
84% 88% 100% 87% 87% 87% 64% 65% 92% 64% 100%
Clear information on how this amount has been
calculated: is it based on an actual meter reading
or estimated only?
% of shoppers stating that it not
clear how the billing amount
was calculated
5% 4% 18% 3% 0% 0% 8% 3% 4% 4% 3%
For calculations based on actual consumption:
meter readings and consumption during the
billing period (measured in kilowatt hours or
kWh)
Details about consumption
during billing period (in kWh)
89% 95% 67% 96% 100% 100% 73% 95% 87% 91% 95%
Value of the meter reading at
the end of the billing period
89% 90% 93% 96% 86% 88% 73% 95% 87% 82% 95%
Value of the meter reading at
the beginning of the billing
period
88% 95% 93% 96% 86% 88% 73% 86% 83% 91% 90%
Where does the energy come from, how is it
generated, how environment friendly is it ("the
fuel mix")
Fuel mix/energy sources (e.g.
wind power, biomass)
32% 48% 45% 20% 47% 43% 0% 18% 52% 40% 13%
Information on how to get tips on saving energy
(e.g. a link to a website)
Tips on saving energy (e.g. link
to a website)
26% 8% 48% 17% 23% 20% 36% 8% 24% 20% 57%
Information on how to obtain the bill in
alternative formats (e.g. in large print) for
Information on how to obtain
your bill in alternative format
24% 16% 8% 23% 27% 53% 28% 5% 20% 16% 50%
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Improving billing information
Country
Item Item in "billing" evaluation
sheet
% who
found item
on their bill
(total)
CZ DE ES FR IT LT267
PL SE SI UK
consumers with disabilities (e.g. paper/online, large print)
Base (note: figures in grey are based on a smaller sample): 300 25 40 30 30 30 25 40 25 25 30
527
Improving billing information
Table 3: Information included on an electricity bill in a sample of ten Member States - II268
Country
Item Item in "billing" evaluation sheet
% who found
item on their bill
(total)
CZ DE ES FR IT LT PL SE SI UK
The contribution of each energy source to the overall
fuel mix of the supplier over the preceding year
13a. Fuel mix/energy sources (e.g. wind power,
biomass)
32% 48% 45% 20% 47% 43% 0% 18% 52% 40% 13%
Information concerning the consumer's rights as regards
the means of dispute settlement available to them in the
event of a dispute
8b. National contact information point (or single point
of contact where you can obtain information about
your energy rights)
28% 44% 43% 33% 43% 30% 4% 3% 16% 12% 53%
8c. An energy mediator or third-party assistance 23% 36% 45% 23% 57% 0% 0% 3% 12% 0% 50%
Base: 300 25 40 30 30 30 25 40 25 25 30
268
Shoppers were instructed to analyse a monthly or quarterly bill. In the Czech Republic and Germany, a considerable number of shoppers reported that they only receive an annual
bill from their electricity company. In these countries, 88% (n=22) and 50% (n=20), respectively, of shoppers analysed an annual bill. "Second Consumer Market Study on the
functioning of retail electricity markets for consumers in the EU" (2016) European Commission.
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Improving billing information
The results show a large variation across countries for selected items; for example,
information about the period of notice to terminate a contract was not found on bills in
Italy, Poland, Slovenia and Spain, while in Germany and France, at least half of shoppers
had found such information on their bill (50% and 57%, respectively). These variations
may reflect national differences in consumer preferences and the characteristics of local
markets, as reflected in Member State rules and discretionary billing practices by
suppliers. In addition, Table 3 illustrates the possible bad application of certain EU
requirements. Only 28% of mystery shoppers (including experts) were able to find a
contact point where they could obtain information about their energy rights, as required
under Article 3(9)(c) of the Electricity and Gas Directives269
. In addition, Article 3(9)(a)
of the Electricity Directive requires suppliers to specify the contribution of each energy
source to the overall fuel mix of the supplier over the preceding year in or with consumer
bills270
. However, more than a third (35%) of mystery shoppers in the same study
disagreed that their electricity company informed them about how the electricity they
used was produced (scores 0 to 4 on a scale to 10)271
.
As transposition checks for the directives do not indicate particular irregularities around
these articles. This points to possible interpretation issues or the bad application of the
relevant measures by national authorities.
269'
'Member States shall ensure that electricity suppliers specify in or with the bills and in promotional
materials made available to final customers… the contribution of each energy source to the overall
fuel mix of the supplier over the preceding year in a comprehensible and, at a national level, clearly
comparable manner…'
270
'Member States shall ensure that electricity suppliers specify in or with the bills and in promotional
materials made available to final customers… information concerning their rights as regards the
means of dispute settlement available to them in the event of a dispute.'
271
This was the case for a majority of respondents in nine EU-28 countries, with the highest level of
disagreement observed in Bulgaria (78%). On the other end of the scale, the proportion of respondents
who “strongly agreed” (scores 8 to 10) that their electricity company informed them about how the
electricity they used was produced varied between 5% in Bulgaria and 46% in Austria. Germany
joined Austria at the higher end of the country ranking with 45% of respondents who “strongly
agreed”.
529
Improving billing information
Figure 2: Information on household customer bills in Member States – 2014
(number of information elements)
Source: CEER Database, National Indicators (2014-2015)
To illustrate another dimension of divergence, Figure 2 above shows information load in
consumer bills in different Member States. This can have a significant impact on
consumers' ability to comprehend their bills – another issue flagged up by stakeholders
and confirmed by a Commission behavioural experiment that showed that superfluous
information in energy bills made it difficult for consumers to understand them (Figure 3).
Figure 3: Performance in bill comprehension task: standard bill vs standard bill
with additional information
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission
To summarize, there is currently a broad divergence in Member States, both with regards
to the individual elements in consumer bills and the total amount of information in these
bills. The widespread divergence in national practices reflects differences in national
legislation and marketing by suppliers, which are themselves a function of consumer
530
Improving billing information
preferences and the characteristics of local markets. To a more limited extent, the
divergence may also reflect the bad application of certain requirements of the Electricity
and Gas Directives, particularly EU requirements on information on consumer rights and
energy sources.
Deficiencies of the current legislation
7.6.3.
As addressed in more detail in Section 7.1.1 and Annex V of the Evaluation, the
Electricity and Gas Directives grant consumers the right to comparable and transparent
supply options. They also state that consumers must be properly informed of their actual
energy consumption and costs frequently enough to regulate their consumption. Building
on these general provisions, the Energy Efficiency Directive puts in place requirements
on the frequency of bills and the presentation of cost and consumption information in
bills.
One of the major objectives of the Articles in the Electricity and Gas Directives relevant
to billing was enabling easier and more effective consumer choice272
. There exist various
data that help us understand how EU consumers perceive their energy bills and the extent
to which their bills are building awareness about energy use. These data are summarised
in the remainder of this Section.
Consumer organisations responding to the latest ACER Market Monitoring Report stated
that the average electricity and gas consumer in their countries is only able to compare
prices to a limited extent. The average score was 4.8 and 5.0 on a scale from 1 to 10 for
electricity and gas respectively273
.
These mediocre figures are backed by the 2016 Electricity Study that found that one in
five consumers surveyed still disagree that the electricity bills of their electricity
company were easy and clear to understand (Figure 4) – note the disparity in individual
Member States concerning the level of understanding with Bulgaria performing worst
and Cyprus performing best). This effect was even more pronounced among mystery
shoppers from ten Member States who were quizzed with their current bills to hand.
Here, between 20 and 54% of respondents disagreed with the statement “My bill is easy
to understand” (Figure 5)274
.
272
Boost competition on retail markets and create consumer incentives to save energy were other major
objectives. See the Thematic Evaluation on Metering and billing.
273
"Market Monitoring report 2014" (2015) ACER,
http://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/ACER_Market_Mon
itoring_Report_2015.
274
"Second Consumer Market Study on the functioning of retail electricity markets for consumers in the
EU" (2016) European Commission.
531
Improving billing information
Figure 4: Agreement with statement: “bills of my electrify company are easy and
clear to understand”, by country275
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
Figure 5: Agreement with the statement: “My bill is easy to understand”276
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
The complaints data collected through the European Consumer Complaints Registration
System indicates the largest share (28%) of consumer complaints reported to the
Commission between 2011 and 2016 were related to billing (Figure 6). Whilst the
complaints classified as relating to "unjustified" or "incorrect" invoicing/billing (10% of
all electricity and gas complaints) are most likely related to billing on estimated rather
than actual consumption277
, complaints about unclear invoices or bills make up around
1% of all electricity and gas complaints in the system. The category 'other billing
complaints' relates to cases where users of the European Consumer Complaints
275
Question: "The following question deals with the quality of services offered in the electricity retail
market. Please indicate how much you agree or disagree with each of the following statements, using a
scale from 0 to 10, where 0 means that you “totally disagree” and 10 means that you “totally agree”:
Bills of [PROVIDER] are clear and easy to understand."
276
Agreement with the statement: “My bill is easy to understand.”
277
See Thematic Evaluation on Smart Metering.
20 24 23
15
28
13 14
7 8 3 8
44 40
33
35
24
13
29
23 28
30 23
4 4
3
3
3
7 3 8
12 8
10 10 8
30
12
13 12 10 10
8 12
13 18
12 20 22 33
44
17
38
10
8
7 6
7
4
23
3
12 12
20
10
20 13 13 10 4
13
13
LT
SE
UK
DE
SI
IT
Total
FR
CZ
ES
PL
Completely agree
Agree
Somewhat agree
Neither agree nor disagree
Somewhat disagree
Disagree
Completely disagree
Q14. To what extent do you agree with the following statement: y bill is easy to u dersta d ?
%, Base: all mystery shoppers
532
Improving billing information
Registration System did not encode a sub-category, or where their specific complaint
could not be categorised according to the options presented below.
Figure 6: Electricity and gas consumer complaints, 2011-2016
Source: DG JUST, European Consumer Complaints Registration System.
It therefore appears that whereas a significant percentage of EU consumers do indeed
have difficulties understanding their energy bill, problems directly related to bill clarity
have not led to a large number of consumer complaints compared with other issues such
as back-billing, unfair commercial practices, and contractual clauses. However, looking
at consumer complaints alone may be insufficient as complaint levels are influenced by
consumer awareness and expectations, both of which may be low when it comes to
energy bills.
Energy bills are the foremost means through which suppliers communicate with their
customers. As such, consumers' ability to correctly answer simple questions about their
own electricity use indirectly reveals the extent to which bills have been effective in
providing information that could facilitate effective consumer choice. Figure 7 below
shows that whereas the majority of EU consumers report that they know how much they
pay for electricity, fewer were aware of their consumption in terms of kWh, what type of
tariff they have, or their sources of electricity.
Whilst this finding may certainly reflect a lack of consumer interest in this information,
the information facilitates effective consumer choice by helping consumers identify the
best offer in the market and weigh the benefits of switching. Their omission from many
bills, as the data presented in Table 2 and Table 3 above illustrates, may therefore be
impeding the achievement of one of the stated objectives of the billing provisions in the
Electricity and Gas Directives.
Unfair Commercial
Practices
16%
Contracts and
sales
11%
Quality of service
8%
Provision of
services
7%
Price / Tariff
7%
Switching
1%
Other issues
22%
Incorrect bill
6%
Unjustified invoicing
4%
Debt collection
2%
Unclear bill
1% Non-issue of invoice
0%
Other billing complaints
15%
Billing
28%
533
Improving billing information
Figure 7: Self-reported awareness of electricity use278
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
To summarize, the analysis presented in this Section indicates that there is scope to
improve the extent to which the billing provisions in the Electricity and Gas Directives
facilitate consumer choice. To help consumers accurately assess information, the
legislation can provide some degree of standardisation to allow consumers to make
accurate comparisons between offers, which is difficult to achieve through the market
alone. Standardisation of some information can also be useful to build familiarity and
help consumers recognise or retain important information.
As Figure 8 below illustrates, the difference in price between offers in the market can be
significant, and so even marginal gains in consumers' ability to identify the best deal can
result in a significant impact on consumer savings.
278
Question: "Please indicate how much you agree or disagree with each of the following statements,
using a scale from 0 to 10, where 0 means that you “totally disagree” and 10 means that you “totally
agree”."
42%
38%
30%
32%
16%
24%
26%
32%
34%
52%
4.9
5.2
5.8
5.7
7.1
I know how the electricity that I use is produced (e.g. nuclear
generation, wind, gas, solar, petroleum, coal, etc.)
I know how the price I pay for electricity is calculated
I know the main characteristics of the tariff I am on (e.g. whether
I am on a fixed or variable price, the use of renewable energy,
etc.)
I know how much electricity I use (per month, year or any other
frequency) in kWh
I know how much I pay for electricity (per month, year or any
other frequency)
Disagree (0-4) Strongly agree (8-10) Average
EU 28
2.3.1 self-reported awareness
Q1_1 to 5. Please indicate how much you agree or disagree with each of the following statements, using a scale from 0 to 10,
where ea s that you totally disagree a d ea s that you totally agree .
%, EU28, Base: all respondents
534
Improving billing information
Figure 8: Dispersion in the energy component of retail prices for households in
capitals – December 2014
Source: ACER Retail Database (November–December 2014) and ACER calculations.
Presentation of the options
7.6.4.
Option 0: BAU with stronger enforcement
Whilst no additional legislation is proposed, the Commission actively follows up
evidence suggesting possible cases of the bad application of EU law by Member States
uncovered in the evaluation. Specifically, the following elements of the current
legislation may not be being adhered to in certain Member States:
- Article 3(9)(a) of the Electricity Directive, which requires suppliers to specify the
contribution of each energy source to the overall fuel mix of the supplier over the
preceding year in or with consumer bills;
- Article 3(9)(c) of the Electricity and Gas Directives, which requires suppliers to
include information on consumer rights in or with bills.
535
Improving billing information
Option 0+: Non-regulatory approach; Commission Recommendation on billing
information
This includes general principles such as:
- Making information which is essential for understanding the price which
consumers pay for the service prominent, clear and easy to read on the bill. One
way to achieve this is to present it in a standard "comparability box" that should
feature prominently on the bill and include all the key information that consumers
need to compare offers and switch suppliers.
- Ensuring that there is a link to a national authority competent to lead a billing
review process and information campaigns.
Option 1: More detailed legal requirements on the key information
Specifically, this includes:
- Requiring electricity and gas suppliers to 'prominently display' in every
household energy bill, both paper and electronic, eight key pieces of
information279
initially identified by the Citizens' Energy Forum Working Group
on Billing in 2009280
. Not all of these data are covered by the existing legislation,
and their inclusion would help ensure that consumers have the minimum
information necessary to interact with the market, whilst leaving Member States
freedom to tailor the presentation of this information to national markets.
- Requiring the breakdown of energy costs presented to consumers to be in line
with the new Regulation on electricity and natural gas price statistics i.e. three
components (energy costs, network charges, taxes & levies) with standard
definitions throughout the EU. This could help improve consumer awareness on
the factors affecting price changes and enable the cross-border comparison of
bills.
Option 2: A fully standardized 'comparability box' in bills
This option would be to develop a standard EU information box that would prescriptively
present all the key information that consumers need to compare offers and switch
suppliers prominently on the bill. It may also most require implementing legislation to
define the format and contents of the information box.
Comparison of the options
7.6.5.
This Section compares the costs and benefits of each of the Options presented above in a
semi-quantitative manner.
279
i) The price to pay; ii) Consumption for current billing period, including comparison with previous
year (as per EED); iii) The name of the energy supplier; iv) The contact details of the energy supplier;
v) The tariff name; vi) Contract duration; vii) The customer's switching code or unique identification
code for their supply point; viii) A contact point for alternative dispute resolution (as per current
Electricity and Gas Directives).
280
"Implementation of EC Good Practice Guidance for Billing", (2010) CEER http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b1/E10-CEM-36-03_EC%20billing%20guidance_8-Sept-2010.pdf.
536
Improving billing information
In general, the costs of implementing each of the above measures can be estimated to a
reasonably certain degree using tools such as the standard cost model for estimating
administrative costs281
. However, no data or methodology exists to accurately quantify all
the benefits of the measures in terms of direct benefits to consumer (consumer surplus) or
general competition. As such, this Section draws on behavioural experiments from a
controlled environment to evaluate the impact of some policy options on consumer
decision-making. Where appropriate, it aims to illustrate the possible direct benefit to
consumers assuming certain conditions. It also highlights important qualitative evidence
from stakeholders that policymakers should also incorporate into their analysis of costs
and benefits.
Option 0: BAU with stronger enforcement
A good case can be made for a prudent, business-as-usual approach in this policy area.
First, there appear to be implementation issues on certain bill items required under
current EU legislation.
Secondly, even though there are clear issues around billing, a recent Commission survey
showed that 77% of energy consumers either agreed or strongly agreed that their bills
were "easy and clear to understand" (Figure 5), and unclear bills led to just 1% of the
electricity and gas consumer complaints reported to the Commission (Figure 6). Even
after factoring in the unreliability of some consumer report data, the absolute size of the
problem itself does not therefore appear to be very significant.
And thirdly, national regulators and energy suppliers are implementing various ways of
improving the billing experience. A business as usual approach would allow 'natural
experiments' in this area to be developed, and the Commission to gather stronger
evidence for a more targeted intervention at a later date.
In spite of these considerations, it is unlikely that Option 0 would most effectively
address the problem of poor consumer engagement. Whilst adherence to certain
billing requirements does seem to be lacking, this only relates to one or possibly two
information items, and so even ensuring 100% compliance would therefore not result in
significant change to energy bills. Whilst consumers report satisfaction with bill clarity,
questionnaires reveal glaring shortcomings in their knowledge of basic market-relevant
information that would help them identify the best offer in the market and weigh the
benefits of switching – information that could be more effectively conveyed in bills.
Accordingly, consumer groups strongly support further legislative measures to ensure
bills inform consumer better and help them to engage with the market. Indeed, all major
stakeholder groups – except for energy suppliers and industry associations – indicate that
there may be at least some scope for further EU action to ensure bills facilitate consumer
engagement in the market.
There are no implementation costs associated with Option 0.
281
http://ec.europa.eu/smart-regulation/guidelines/tool_53_en.htm
537
Improving billing information
Option 0+: Non-regulatory approach e.g. a Commission Recommendation on billing
information
This option can be discarded because a very similar set of recommendations have
already been developed by the Commission-chaired Working Group on Billing (more
details below). Whilst the group's findings were published and presented to the Citizens'
Energy Forum in 2009, these recommendations have not been fully adhered to (Table 2),
and it is unlikely that putting them in a non-binding Commission Recommendation
would change this. It is thus unlikely that voluntary cooperation between Member States
would address this problem.
Option 1: More detailed legal requirements on the key information
To recap, this option would involve ensuring that all EU suppliers use the same
definitions of price components (energy, network charges, and taxes) when
communicating with consumers. It would also involve prominently displaying the eight
pieces of information presented in every EU energy bill. These eight items are drawn
from a guidance document on billing originally proposed by a Commission-led Working
Group in 2009282
. The importance of the information items was then reaffirmed by a
Working Group on e-Billing and Personal Data Management in 2013283
. Whilst the
former comprised of representatives from NRAs and the Commission, the latter also
included representatives from consumer groups and industry. The identification and
selection of these items is therefore based on comprehensive of stakeholder dialogue
process.
The economic benefits of Option 1 will primarily be indirect, and come in terms of
greater competition (lower prices, higher standards of service and a broader variety of
products on the market). These benefits are unquantifiable.
In addition, Option 1 will directly result in greater consumer surplus, something that
can be estimated using the following assumptions.
As a whole, EU households spend a total of 147 billion euros on electricity and 97 billion
euros on gas annually, the average annual household bill being 773 euros for electricity
and 795 euros for gas284
. According to CEER, 6.3% of electricity consumers and 5.5% of
gas consumers switched energy suppliers in 2014.
If we assume that:
282
"Implementation of EC Good Practice Guidance for Billing" (2010) CEER http://www.energy-
regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Customers/Ta
b1/E10-CEM-36-03_EC%20billing%20guidance_8-Sept-2010.pdf.
283
"Working Group Report on e-Billing and Personal Data Management", (2013) Report prepared for the
6th Citizens' Energy Forum, https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-
billing_energy_data.pdf.
284
Not including MT or CY. Based on latest data available: 2014 for BE, BG, CZ, DK, EL, HR, HU, IT,
LV, PL, RO, and SK; 2013 for DE, ES, LU, NL, UK; 2012 for EE, FI, LT, SE and SI; 2011 for FR;
2010 for AT, IE and PT. Source: Eurostat.
538
Improving billing information
- The average EU switching rates for electricity and gas remained unchanged at
6.3% and 5.5% respectively285
;
- The measures improved the ability of one out of every one-hundred customers
who switched to identify a better offer286
;
- The measures benefitted consumers using comparison tools just as much as
those comparing the market directly through suppliers287
;
- These consumers were able to save an additional 5 euros from both their
electricity and gas bills a year as a result of the measures put in place288
;
- The financial advantage of being able to identify the best deal as a result of
these measures persists for four years289
;
- All EU households are able to benefit from these changes equally in relative
terms290
;
- A discount rate of 4% for the consumer benefits year on year;
then Option 1 would result in an increase in consumer surplus of between 0.9 and 3.2
million euros annually (depending on the year of implementation), and 27.6 million
euros in total for the period 2020-2030.
285
This is a conservative assumption given that 40% more consumers would have access to their unique
switching code with every bill (a piece of information important for switching) and significantly more
consumers on fixed term contracts are likely to be aware of when their current contracts expired (24%
of household consumers report that they only compare tariffs when they needed to renew their
contracts). "Second Consumer Market Study on the functioning of retail electricity markets for
consumers in the EU" (2016) European Commission.
286
This equates to just 0.063% of electricity consumers and 0.055% of gas consumers in any given year –
again, a conservative assumption. Taken as a whole, the eight information items in Option 1 aim to
arm the consumer with all the most relevant information necessary to engage with the market,
including helping consumers identify the best offer.
287
One of the benefits of this intervention would also be to give consumers easy access to all information
relevant to using comparison tools in every bill (switching code, tariff name, consumption).
288
This figure seems proportionate given that the average 80% range of the dispersion of electricity and
gas household offers in the market is around EUR 150 (Figure 8). Assuming that those switching
would tend to be moving from a tariff at the more expensive side of this distribution to a tariff at the
cheaper side of this distribution, this amounts to saying that the greater market awareness engendered
by this intervention would enable consumers to identify an offer that was just c. 3% cheaper than the
offer they would have otherwise identified without the intervention.
289
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
290
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we
have no reliable data to quantify these differences in this specific context.
539
Improving billing information
Table 4: The prevalence of eight key information items in consumer bills
Item Item in "billing" evaluation sheet % who
found item
on their bill
(total)
i) The amount to be paid, for which billing period, by
when and how (existing EU legal requirement)
Amount to be paid 97%
Billing period (e.g. 15 November
– 14 December 2014)
95%
ii) For calculations based on actual consumption: meter
readings and consumption during the billing period
(measured in kilowatt hours or kWh) (existing EU
legal requirement)
Details about consumption during
billing period (in kWh)
89%
Value of the meter reading at the
end of the billing period
89%
Value of the meter reading at the
beginning of the billing period
88%
iii) Supplier's name Provider’s name 99%
iv) Contact details (including
their helpline and emergency number)
Telephone number of customer
service/helpline
96%
Postal address of provider 94%
Email address of provider 69%
Emergency number (e.g. to call in
the event of an electrical
emergency or power outage)
59%
v) The tariff name Tariff name/plan (e.g. 'Day &
Night Fix')
80%
vi) The duration of the contract Duration of the contract (e.g. 24
months)
22%
vii) The switching code Switching code/meter
identification (EAN or MPAN
code; a unique code for your
electricity meter)
73%
viii) Information concerning the consumer's rights as
regards the means of dispute settlement available to
them in the event of a dispute (existing EU legal
requirement)
National contact information point
(or single point of contact where
you can obtain information about
your energy rights)
28%
An energy mediator or third-party
assistance
23%
Base (note: figures in grey are based on a smaller sample): 300
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
The implementation costs of Option 1 will most likely be modest because:
- All Member States have legislation with billing requirements that are more
prescriptive than those in the EU acquis (Table 1);
- National legislation is periodically revised independently of EU requirements, and so
minor EU requirements would not lead to significant additional implementation costs
to national administrations;
- It is already an EU legal requirement to display three out of the eight pieces of
information this measure proposes should be 'prominently displayed' (information on
consumption, information on costs, and information on dispute settlement);
- Only one piece of information (the contract duration) would have to be added to
around 80% of EU bills;
- Two pieces of information (the tariff name and switching code) can already be found
in over 70% of bills;
- The remaining two pieces of information (the suppliers name and contact details) can
already be found in over 95% of bills (Table 4);
540
Improving billing information
- The requirement to use standardised definitions of energy price component would not
result in any additional information requirements, per se.
This option would therefore result in the following one-time implementation costs to the
2752 electricity and 1595 gas suppliers in the EU291
. No running costs are associated
with this option due to the computerisation of billing systems.
Table 5: Option 1 implementation costs (all one-time costs)292
Obligation Action Suppliers
concerned
Staff type Hourly
rate
(EUR)
Man
hours
Activity cost
(EUR)
Ensuring 8 key
information items
are prominently
displayed in
every energy bill
Bill design 2174293
Professionals 32.10 16 1,116,566.40
Bill design 1449294
Professionals 32.10 72 3,348,928.80
Ensuring that all
EU suppliers use
the same
definitions of
price components
in bills
Understanding
information
obligation
3434295
Professionals 32.10 4 440,925.60
Adjusting
existing data
3434 Professionals 32.10 24 2,645,553.60
Total 7,551,974.40
As regards stakeholder views, Option 1 would likely enjoy broad support amongst
stakeholders, apart from energy suppliers and the industry associations who represent
them. It responds to the input from consumer groups, the European Parliament and the
Committee of the Regions that legislative action is necessary to ensure that energy bills
meet minimum standards. It also accommodates feedback from NRAs that prescriptive or
detailed EU requirements could reduce the scope for innovation among suppliers and
could become outdated quickly.
Option 2: A fully standardized 'comparability box' in bills
To recap, this option would be to develop a standard information box that would
prescriptively present key information in all EU energy bills.
The economic benefits of Option 2 would primarily be indirect, and come in terms of
greater competition (lower prices, higher standards of service and a broader variety of
products on the market). These benefits are unquantifiable.
291
Source: CEER National Indicators Database (2015).
292
Derived from the standard cost model for estimating administrative costs.
293
This assumes that 50% of all suppliers would need to make minor changes to their bills to
accommodate one additional piece of information (contract duration). 2 man days of work. Estimate
based on the figures in Table 4
294
This assumes that 30% of all suppliers would need to make moderate changes to their bills to
accommodate three additional pieces of information (contract duration, switching code, tariff name). 9
man days of work. Estimate based on the figures in Table 4.
295
79% of consumers found a breakdown of energy costs in their bills (Table 2). This legal requirement
would only apply to suppliers providing a breakdown.
541
Improving billing information
In addition, Option 2 would directly result in greater consumer surplus, something that
can be estimated with the aid of the following behavioural experiments.
10,056 respondents completed behavioural experiments to test if bill presentation impacts
consumer awareness and decision making. The behavioural experiment included a task
on bill comprehension, in which respondents were shown a best practice bill with a
comparison box or a standard bill and tested on how well they understood key pieces of
information contained in the bill. Respondents were also tested on their ability to identify
the best offer after having seen a best practice bill or a standard bill.
The “best practice” bill drew on the Working Group Reports on Billing, and Personal
Data Management cited earlier, as well as the electricity bill model/prototype developed
following input received from working group members, which makes suggestions for
both the content and format of an electricity bill and encourages the use of a
“comparability box”.
Figure 9: Best practice comparability box design
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
The “standard bill” was developed based on the bills collected through desk research on
actual providers in Europe. It does not have a comparability box and, although it provides
consumers with the same information, the presentation of the information is not as clear
(i.e. key information on tariff characteristics are not presented in a simple box on the first
page of the bill).
542
Improving billing information
Figure 10: Excerpt of standard bill
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
In the comprehension exercise, respondents were asked eight questions about the
information provided in the bill, each of which had a single correct answer (respondents
could see the bill next to the questions they had to answer). Generally, viewing the bill in
the best practice format helped respondents pick out the correct answer when compared
to the standard bill. On average across all questions, 84% of respondents who saw the
best practice bill selected the correct answers, compared to 79% of respondents who saw
the standard bill. This result is statistically significant for all eight questions as illustrated
in the table below.
Table 6: Shares of respondents who correctly answered the bill comprehension test
questions, by basic bill type
Question
Best practice
bill
Standard bill Difference
What is the name of your tariff? 90% 86% 5 pp***
How much are you being charged in total? 90% 87% 3 pp***
How much electricity did you consume? 91% 87% 4 pp***
What is the total unit cost of energy excl. VAT? 77% 72% 6 pp***
What is the standing charge incl. taxes and charges? 82% 78% 4 pp**
What is the duration of your contract? 90% 80% 10 pp***
When does your contract expire? 90% 88% 2 pp*
How much energy did you consume last year? 60% 52% 8 pp***
Average across all questions 84% 79% 5 pp***
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
In the 'stay or switch' task, designed to test if the presentation format of consumers’ bills
impacts their propensity to switch to the cheapest tariff, best practice bills also led to
TARIFF NAME STANDARD FIX
Base unit price [insert currency symbol/amount]/kWh
Standing Charge [insert currency symbol/amount]/kWh
National levy( the Green Energy Fund) [insert currency symbol/amount]/kWh
TOTAL UNIT COST WITHOUT VAT [insert currency symbol/amount]/kWh
+ VAT at 20% [insert currency symbol/amount]/kWh
TOTAL UNIT COST incl. VAT [insert currency symbol/amount]/kWh
YOUR TARIFF INFORMATION
DATE GENERAL METER NO 7546 - reading
Previous reading* 32250kWh (a)
15 August 33570kWh (a)
14 November 34100kWh (a)
Your consumption
15 August – 14 November 2014
530 kWh
*A reviatio s: a : a tual, e : esti ate
543
Improving billing information
better performance, albeit to a limited extent. Respondents viewing the “best practice”
bill were more likely to choose the cheapest deal compared to those viewing the
“standard” bill (61% compared to 59%), this impact is small and only marginally
statistically significant overall (Table 7).
Table 7: Share of respondents who selected the cheapest deal296
Bill type
All
countries
CZ DE ES FR UK IT LT PL SE SI
Best
practice
61% 59% 64% 53% 59% 72% 52% 60% 59% 63% 59%
Standard 59% 59% 61% 51% 55% 70% 55% 58% 53% 57% 58%
Source: "Second Consumer Market Study on the functioning of retail electricity markets for consumers in
the EU" (2016) European Commission.
If we assume that:
- The average EU switching rates for electricity and gas remained unchanged at
6.3% and 5.5% respectively297
;
- The measures improved the ability of two out of every one-hundred customers
who switched to identify a better offer, reflecting the results in Table 7298
;
- The measures benefitted consumers using comparison tools just as much as
those comparing the market directly through suppliers299
;
- These consumers were able to save an additional 5 euros from both their
electricity and gas bills a year as a result of the measures put in place300
;
- The financial advantage of being able to identify the best deal as a result of
these measures persists for four years301
;
- All EU households are able to benefit from these changes equally in relative
terms302
;
296
Note: Weighted base varies by treatment: Best practice = 5,042; Standard = 5,014.
297
As with Option 1, this is a conservative assumption given that 40% more consumers would have
access to their unique switching code with every bill (a piece of information important for switching)
and significantly more consumers on fixed term contracts are likely to be aware of when their current
contracts expired (24% of household consumers report that they only compare tariffs when they
needed to renew their contracts). "Second Consumer Market Study on the functioning of retail
electricity markets for consumers in the EU" (2016) European Commission.
298
This assumes the size of improvement in decision making in the real world is as significant as the size
of the effect in the experiment. However, many consumers in the real world would not even have
access to all the information in the 'standard' bill in the behavioural experiment (see Table 2). The true
effect can therefore be expected to be greater.
299
Whilst the behavioural experiment addressed the latter mode of comparison, one of the benefits of this
intervention would also be to give consumers easy access to all information relevant to using
comparison tools in every bill (switching code, tariff name, consumption).
300
This figure seems proportionate given that the average 80% range of the dispersion of electricity and
gas household offers in the market is around EUR 150 (Figure ). Assuming that those switching would
tend to be moving from a tariff at the more expensive side of this distribution to a tariff at the cheaper
side of this distribution, this amounts to saying that the greater market awareness engendered by this
intervention would enable consumers to identify an offer that was just c. 3% cheaper than the offer
they would have otherwise identified without the intervention.
301
A conservative assumption given the implied average time between switches is upwards of 15.5 years
for electricity consumers and 18 years for gas consumers.
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Improving billing information
- A discount rate of 4% for the consumer benefits year on year;
then Option 2 would result in an increase in consumer surplus of between 1.8 and 6.5
million euros annually (depending on the year of implementation), and 55.3 million
euros in total for the period 2020-2030.
However, there is significant uncertainty as to these benefits because it may prove
difficult to devise a standard EU comparability box that can fully accommodate all
differences between national energy markets. Such as box may downplay the non-
quantitative value of energy services (green offers, or offers bundled with home
insulation services) when compared to 'plain vanilla' supply contracts. Finally, the
prescriptive approach would inhibit beneficial innovation by national regulators and
suppliers, and make it difficult to adapt bills to evolving technologies and consumer
preferences.
Indeed, the Commission-chaired Working Group on e-Billing and Personal Data
Management found that bill design "should not be imposed by regulation but rather be
developed on the basis of better understanding of consumer interests also drawing on the
results of behavioural research"303
.
The implementation costs of Option 2 will most likely be significant because:
- All Member States have legislation with billing requirements that are
relatively prescriptive, and that will need to be significantly revised (Table 1);
- All energy suppliers would need to significantly revise the design of their
household bills in order to comply with the new EU requirements.
This option would therefore result in the following one-time implementation costs to
public administrations as well as the 2752 electricity and 1595 gas suppliers in the EU304
.
No running costs are associated with this option due to the computerisation of billing
systems.
302
In reality, households will react differently depending on consumers’ needs, skills, motivations,
interests, lifestyle, and access to resources such as accurate online comparison tools. However, we
have no reliable data to quantify these differences in this specific context.
303
Working Group Report on e-Billing and Personal Data Management", (2013) Report prepared for the
6th Citizens' Energy Forum, https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-
billing_energy_data.pdf.
304
Source: CEER National Indicators Database (2015).
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Improving billing information
Table 8: Option 2 implementation costs (all one-time costs)305
Obligation Action Entities
concerned
Staff type Hourly
rate
(EUR)
Man
hours
Activity cost
(EUR)
Incorporating
comparison box
into bills
Revising
national
legislation
28306
Legislators,
senior
officials,
managers
41.50 320 371,840.00
Understanding
information
obligation
4347307
Professionals 32.10 8 1,116,309.60
Bill design 4347 Professionals 32.10 144 20,093,572.80
Total 21,581,722.40
As regards stakeholder views, Option 2 would not enjoy as much support as Option 1. In
particular, it would be resisted by NRAs as well as industry as it would significantly
reduce the scope for beneficial innovation by national authorities and suppliers, as well
as their ability to tailor information to specific national markets or consumer groups308
. In
addition, whilst consumer groups, the European Parliament and the Committee of the
Regions have pushed for greater standardisation of the format of bills, it may prove
impossible to devise a format that pleases all of these diverse stakeholders in practice.
Conclusion
Option 1 is the preferred option as it likely leads to significant economic benefits and
increased consumer surplus without significant administrative costs or the risk of overly-
prescriptive legislation at the EU level.
Subsidiarity
7.6.6.
Consumers are not taking full advantage of competition on energy markets due, in part,
to poor awareness of basic, market-relevant information that could be provided in energy
bills.
The Options envisage reinforcing legal requirements on key information to include in
consumers' bills. National legal regimes for billing remain fragmented with diverging
content and format, and do not always facilitate comparison with offers and pre-
contractual information, which would improve switching rates and effectiveness. There
is also a need to standardise the definitions of energy costs, network charges, and taxes
305
Derived from the standard cost model for estimating administrative costs.
306
All Member States. 40 man-days each.
307
All electricity and gas supply companies. 18 man-days each.
308
In a workshop on effective billing that the UK energy regulator, Ofgem, recently held, attendees
generally agreed that the level of prescribed information on bills and other communications in the UK
is too high, leading to consumers being overwhelmed with information, and that a one size fits all
approach doesn’t allow for tailored information to be provided to a consumer. See 'Memo: Effective
billing workshop', (2015) Ofgem,
https://www.ofgem.gov.uk/system/files/docs/2016/03/effective_billing_workshop_251115_.pdf.
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Improving billing information
and levies used in all EU bills in order that consumers understand what they are paying
for and are better aware of the extent to which they can control their energy costs.
Well designed and implemented consumer policies with a European dimension can
enable consumers to make informed choices that reward competition, and support the
goal of sustainable and resource-efficient growth, whilst taking account of the needs of
all consumers. Increasing confidence and ensuring that unfair trading practices do not
bring a competitive advantage will also have a positive impact in terms of stimulating
growth.
The legal basis for the legislative options proposed (Options 1 and 2) is therefore likely
to be Article 114 TFEU. This allows for the adoption of "measures for the approximation
of the provisions laid down by law, regulation or administrative action in Member States
which have as their object the establishment and functioning of the internal market". In
doing this, in accordance with Article 169 TFEU, the Commission will aim at ensuring a
high level of consumer protection.
Option 0: BAU with stronger enforcement
Business as usual/stronger enforcement does not change the status quo. Member States
would continue to have a significant degree of discretion in specifying the content of
consumers' bills.
From a subsidiarity perspective, this option allows Member States to decide on the extent
to which they wish to create an environment where customers are encouraged to switch
more freely. If the status quo continues, this may not always result in lower overall
prices, depending on the national situation.
From the perspective of proportionality, however, this option would not necessarily lead
to sufficient improvements in the market.
Option 1: More detailed legal requirements on the key information
The principles of subsidiarity and proportionality are best met through this Option as it is
not overly prescriptive and will concretely reduce levels of consumer detriment that are
currently not addressed at a national level by all Member State authorities.
This option aims primarily at reinforcing existing legislation but without being overly
prescriptive. As billing is already addressed in EU provisions, the subsidiarity and
proportionality principles have clearly been assessed previously and deemed as met.
Box 1: Impacts on different groups of consumers
The benefits of the measures contained in the preferred option (Option 1), described in detail in the
preceding pages, accrue predominantly to consumers who do not engage in the market or better control
their energy consumption because of insufficient billing information or confusing bills. This may include
certain vulnerable consumers, or those who are time poor.
Option 2: A fully standardized 'comparability box' in bills
Implementing a standardised comparability box for billing would help to create a level
playing field for consumers within Member States and between Member States. At this
point, however, it would be disproportionate to impose such a requirement as consumer
research in this area is ongoing and current findings are inconclusive.
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Improving billing information
Stakeholder's opinions
7.6.7.
Public Consultation
222 out of 237 respondents to the Commission's Consultation on the Retail Energy
Market309
believed that transparent contracts and bills were either important or very
important for helping residential consumers and SMEs to better control their energy
consumption and costs. 110 out of 237 believed that prices and tariffs that were difficult
to compare were a key factor influence switching rates. And 66 out of 133 respondents
who thought that bills did not provide sufficient information thought this was the case
because they were not sufficiently transparent and meaningful.
43% of all 332 respondents to the Commission's Consultation on the Review of Directive
2012/27/EU on Energy Efficiency310
think the EED provisions on metering and billing
are sufficient to guarantee all consumers easily accessible, sufficiently frequent, detailed
and understandable information on their own consumption of energy, versus 32% who
opposed this view, and 25% who had no view. Most comments were provided by
participants who did not think that the provisions are sufficient. Many argued that energy
bills would remain too complex to be properly understood by most customers.
Citizens' Energy Forum, February 2016
The European Commission established the Citizens' Energy Forum in 2007. The Forum
meets on an annual basis in London and is organised with the support of Ofgem, the UK
regulatory authority. The overall aim of the Forum is to explore consumers' perspective
and role in a competitive, 'smart', energy-efficient and fair energy retail market. The
London Forum brings together representatives of consumer organisations, energy
regulators, energy ombudsmen, energy industries, and national energy ministries.
The 8th Citizens' Energy Forum, organised by DG Energy in collaboration with DG
Justice, took place in London on Tuesday 23 and Wednesday 24 February. In its
conclusions, the forum: "Call[ed] for improved and comparable pre-contractual
information, including green offers, contract and billing information to increase
consumer engagement." It addition, the Forum: "Call[ed] for phasing out regulated
prices and more clarity on the costs of the components of energy bills to remove barriers
to effective competition and allow consumers to choose from more diverse offers."
European Commission Working Group on e-Billing and Personal Energy Data
Management
Including representatives from national NRAs, consumer groups and industry, this
working group concluded in December 2013 that data presented in e-bills and e-billing
information, as well as in paper bills and consumption data presented on paper, needed to
be correct, clear, concise and presented in a manner that facilitates comparison and
309
Held from 22 to 17 April 2014. https://ec.europa.eu/energy/en/consultations/consultation-retail-
energy-market
310
Held from 4 November 2015 to 29 January 2016.
https://ec.europa.eu/energy/sites/ener/files/documents/Public%20Consultation%20Report%20on%20th
e%20EED%20Review.pdf
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Improving billing information
provides all relevant information to consumers – including complaint handling and
contact points for consumer information e.g. on their energy bills and consumption.
It acknowledged that clear and accurate information on energy consumption, feedback
devices, as well as information on historical consumption can help consumers to be better
aware of their consumption.
It also suggested that information is presented to consumers in a 'tiered' manner from
basic towards more complex data, enabling consumers to look for additional, e.g. more
'technical' data, in an educational manner311
.
National Regulatory Authorities
ACER suggests that there is still a lack of information relevant to switching suppliers on
the bill in many Member States. However, it point out that too much information can also
lead to too complex bills inhibiting the beneficial role of information to consumers.
The body representing the EU's national regulatory authorities in Brussels, CEER312
,
points out that detailed requirements can reduce the scope for innovation among
suppliers and could become outdated quickly (e.g. there are more people opting for
electronic billing). To this end, it feels that minimum standards or slightly higher-level
requirements might be more appropriate. It states that understandable billing information
as well as readily comparable information are critically important for consumers and
welcomes the proposal from the European Commission to identify, in collaboration with
national regulators, minimum standards for key information in advertising and bills. It
agrees that information on consumption patterns is important for consumers.
The Czech NRA ERO states that bills are very difficult to understand, not easy to read
and overloaded. Consumers need clear and transparent information, to be able to
compare offers, contract termination information, and information for switching.
The French NRA CRE suggests that the layout of energy bills should contain two levels:
essential / minimal information and detailed information (including where relevant, meter
reading, all tariffs, taxes and levies). In a consumer centric model, the exact layout
should be the suppliers’ responsibility. The breakout pages of the bill might not be
relevant in the near future, with the development of web-only / paperless offers. Detailed
legislation on paper bills is probably irrelevant in a forward looking perspective,
considering the general trend in recurrent billing services. Paper bills should not be made
compulsory. Paperless should be promoted as interactive relations allow the supplier to
develop a higher competitive advantage.
The UK NRA Ofgem does not support prescription beyond ensuring that the key
information is presented clearly. The layout of bills should be broadly left to suppliers.
Testing and trials is the best route through which to identify the most effective way to
present information on bills. It is important to ensure that consumers have access to key
311
Working Group Report on e-Billing and Personal Data Management", (2013) Report prepared for the
6th Citizens' Energy Forum, https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-
billing_energy_data.pdf.
312
The Council of European Energy Regulators.
549
Improving billing information
information and that this is not hidden away. In GB on key communications consumers
are presented with a Tariff Information Label (TIL) that houses key information about
their tariff and consumption. This provides them with easy access to the information they
need to switch tariffs. Ofgem considers this to be a useful/effective tool for consumers.
Ofgem has received feedback from a number of sources that consumers find their bills
confusing and overly complex.
Consumer Groups
BEUC states that the current EU legislative provisions related to billing are insufficient.
Bills should be clear and concise and include the necessary information for the consumer
to compare offers and to switch supplier. BEUC welcomes the Commission’s plan to put
forward proposals to improve the information provided on the bill in order to facilitate
comparability and switching among others.
Simpler bills are welcome by consumers. EU legislation should also prescribe the
outcomes required for consumers (e.g. that consumers have the data required to switch).
As bills are often packed with a lot of information, a way to avoid the overload and
simplify the overall bill would be to provide only fundamental elements on the bill (for
example in a standardized box). The bill could then include a reference to find more
detailed but perhaps less crucial information online.
The first page of the bill should contain specific elements which are standardised. A
comparability box showing the key information for switching is needed on the first page
of the bill. The Commission should respect the consumer’s choice not to play an active
role. Clear and accurate bills require high level principles for bills at the EU level.
Consumers have a diverse range of preferences and of accessible tools so the approach to
information should be shaped by consumer research at the national level. The focus
should be on less, simpler and more meaningful is better.
The Swedish consumer group Konsumenternas highlights that issues with the bill are
often connected to lack of knowledge or understanding the difference between supply
and distribution and the respective prices/tariffs. Billing should be subject to competition.
Legal provisions on the clarity of bills are difficult to sanction by the regulator. Paper
bills are likely to decrease in number and become less relevant.
The Portuguese consumer group DECO Highlights that while we already have a
standardized information model of pre-contractual information, we don't have the same
for energy bills. It could be useful to have a comparability box in the bill, which shows
key elements (including energy used compared with previous year, contract end date etc.)
and also have information about new promotions and discounts of the same supplier.
DECO believes that some elements that are similar on all energy bills should be
standardised at EU level, namely:
1. Energy supplier identification
2. Customer/Consumer identification
3. Invoice date information
4. Invoice number information
5. Commercial supply/services identification (base product/campaign)
6. Specific offer conditions
7. Fees and taxes
8. Bundled Services
9. Payment Methods
550
Improving billing information
10. Social Tariffs/Mechanisms for vulnerable consumers
11. Information about savings/sustainability and energy poverty measures.
Citizens Advice (UK) believes that a comparability box showing the key information for
switching is needed on the first page of the bill. EU legislation should prescribe the
outcomes required for consumers (e.g. that consumers have the data required to switch).
This should be supported by actions to monitor and enforce this (e.g. with a link across to
the indicators for market monitoring, including by CEER/ACER). The format and layout
should be subject to consumer testing/consumer research. It is useful to provide
consumers with information on similar properties in the area but the ‘bill’ may not be the
best location. For instance, the information could be provided in a separate report, sent to
the household, outside of the standard billing cycle.
Germany's VZBV believes that a clear requirement to show the price per kWh including
taxes is missing in the regulation. A requirement to access the meter is missing in the
regulation as well. Although legislations exists, these are partly insufficiently
implemented from the consumer point of view (esp. in terms of understand ability).
Suppliers
EURELECTRIC states that many consumers across Europe complain that there is too
much information on their bills, making them difficult to read. At the same time,
regulation does not always allow suppliers to simplify or improve them to fit with
specific consumer needs. In a competitive market, bill design should be left to suppliers
(and other market parties) to diversify their brand and image. Suppliers also need
flexibility to take into account the needs of different groups of consumers. Beside,
EURELECTRIC thinks the main issue with bill is not about the “layout” per se but about
its “regulated content” (e.g. taxes, legal wording, consumption estimation, etc.). Only the
most critical elements could be standardised at national level if evidence suggests this is
needed. Consumers also face problems with the high volume of regulated information on
their bills. The primary purpose of a bill is to set out charges for energy and to allow the
customer to understand how their consumption affects those charges. Giving evidence of
how the lay-out of paper bills can create competitive advantage is not an easy thing to do.
The point is that different consumer/consumer groups may have different needs and
preferences as to what they’d like to see in their energy bill: level of details, format, use
of graphs/tables, etc. This is why suppliers should be given enough flexibility to
innovate. In any competitive market, differentiation is key to create competitive
advantage. EURELECTRIC does not see any evidence which would support the need for
further standardisation of elements of the energy bill at European level.
Eurogas states that EU legislation sets prescriptive requirements on billing frequency
and use of meter readings which can and should be left to suppliers in competitive
markets. Communications should also be able to adapt to changing technology, such as
the increasing use of digital media, including smartphones and tablets. Suppliers in
competitive markets are best-placed to work out how to engage customers. Graphs and
tables may be equally useful in certain situations but it should be up to the competitive
market to determine how to present information to customers in an engaging way.
Consumers face problems with the high volume of regulated information on bills. The
primary purpose of a bill is to set out charges for energy and to allow the customer to
understand how their consumption affects those charges. To facilitate the readability of
the bill, some information (such as general conditions) could be made available on the
dedicated customer area and signposted on the bill.
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Improving billing information
CEDEC argues that before including new measures in the legislation it should be
ensured that the current provisions are respected. New requirements should be
conditional on technical feasibility and cost-effectiveness. The focus on measures that are
technically feasible and cost effective must remain. Consumers find more difficult to
identify and choose the cheapest deal if price structure of electricity offers is complex. In
this sense, it would be useful to avoid too many pieces of information.
UK ENERGY highlights that all markets are different and it is the role of competition
between market participants to determine what is most effective and appropriate for
billing purposes. It believes suppliers need more flexibility to determine what
information they provide to customers and how that information is provided with what
frequency. Suppliers should have increased flexibility in the layout of the bill since this is
one of the few and key contact points to engage with customers. The primary purpose of
a bill is to set out charges for energy and to allow the customer to understand how their
consumption affects those charges. It is unclear how a standardisation of the first page
could keep pace with changing technologies and markets. Consumers increasingly want
to receive communication in alternative formats such as online or via apps. It is unclear
what benefits standardisation at European level would bring.
The European Parliament
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Parliament's Committee on Industry, Research and
Energy (ITRE): "Recommends improving the frequency of energy bills and the
transparency and clarity of both bills and contracts in order to aid interpretability and
comparison, and to include in or alongside energy bills peer-based comparisons and
information on switching; insists that clear language must be used, avoiding technical
terms; requests the Commission to identify minimum information requirements in this
respect, including best practices; stresses that both fixed charges and taxes and levies
should be clearly identified as such in the bills, allowing the customer to distinguish them
easily from the variable, consumption-related cost; recalls existing requirements for
suppliers to specify in or with bills the contribution of each energy source to the overall
fuel mix of the supplier over the preceding year in a comprehensible and clearly
comparable manner, including a reference to where information can be found on the
environmental impact in terms of CO2 emissions and radioactive waste. Recommends
that consumers should be notified in or alongside energy bills about the most suitable
and advantageous tariff for them, based on historic consumption patterns, and that it
should be possible for consumers to move to that tariff, if they so wish, in the simplest
way possible. Considers that incentives and access to quality information are key in this
respect and asks the Commission to address this in upcoming proposals."
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Parliament's Committee on the Internal Market and
Consumer Protection (IMCO) called for: "the Commission to take further action to
improve the frequency of energy bills and the associated meter readings, and their
clarity, comparability, and transparency as regards types of energy sources,
consumption, price structure and the processing of enquiries and complaints."
The Committee of the Regions
In its April 2016 opinion on the Commission's Communication on Delivering a New
Deal for Energy Consumers, the Committee of the Regions:
- calls on the European Union to examine the different components of energy bills,
in order to put together a "standard" bill incorporating a number of elements that
552
Improving billing information
are uniform, legible, clear and comparable at European level and which would
allow consumers to optimise their energy use. In this regard, the European
Committee of the Regions supports the Council of European Energy Regulators'
initiative to set out harmonised definitions of different elements that should be
included in energy bills;
- calls for standardisation to be accompanied in the final bill by information about
the free tools and services that are available for comparing supply offers, as well
as information and support for households and businesses with regard to the
protection of consumers' rights;
- calls on Member States to create tools and services that make bills easier for
households and businesses to understand, so that they can be analysed; and,
where appropriate, to provide advice and support for end-users regarding the
steps which may be necessary to rectify any irregularities identified or guide end-
users towards supply contracts that are better suited to their needs;
- recommends that bills and any information issued by suppliers to their end-users
should be sent in the format requested by the latter, i.e. via post or e-mail, without
any discrimination;
- stresses that vulnerable consumers are particularly likely to encounter difficulties
in identifying the best tariffs amongst the wide range of offers, and that they often
seek the assistance of the closest level of governance. Consequently, the
European Committee of the Regions calls upon the European Union to assist local
and regional authorities in setting up support systems in the field of energy if this
is not being done by the Member States.
553
Description of relevant European R&D projects
8. DESCRIPTION OF RELEVANT EUROPEAN R&D PROJECTS
Technological developments are both part of the drivers that affect the present initiative
and part of the solutions of the problems they affect.
Technological developments have created the opportunities for consumers to transit from
being passive consumers of electricity to prosumers that can actively manage their
consumption, storage and production of electricity and particiapte in the market. This
provides opportunities for innovative business models of service provisions, often based
on advanced technologies, based on enabling smaller consumers and distributed
generation to interact with the market and have their resources being managed. At the
same time, networks should be managed more actively in order to meet the challenges
more decentralised generation brings about.
As the transition path is also created by technological progress and the solutions to the
problems they entail are equally shaped by technology, the present annex provides for a
sample of projects, supported by the EU through its 6th
and 7th
Framework Programme
and Horizon2020, that have developed technologies and innovations that render these
developments more concrete but also provide insights as to the direction the transition
may take.
554
Description of relevant European R&D projects
Project FP7-DISCERN
Title: Distributed Intelligence for Cost-Effective and Reliable Distribution Network Operation
The project linked with six large-scale smart grids demonstration projects financed at national level. The
project developed methods to characterise outcomes and aimed to find ways to replicate solutions from one
country to another.
Fact Sheet: http://cordis.europa.eu/project/rcn/106040_en.html
Web Site: http://www.discern.eu/
Important project outcome include:
The practical testing and tuning of performance metrics (Key Performance Indicators – KPI) and
evaluation of their values based on actual measurements. The project concludes that use of the KPI
framework is a valid approach for revealing the impact of a technical solution and its function(s) on a DSO
grid, system or organisation and to set the expected set of outcomes. These can be used to analyse
cost/benefit ratios at design stage and after implementation. Cost KPIs are a valid method for assessing cost
structures for Use Cases, however as the creation of a common cost list to support impartial comparisons of
the various Use Cases was found impractical within the constraints of DISCERN, the evaluation of costs
and determination of initial investments relied on individual Use Case information, which by its nature
incorporates company specific cost drivers
Project FP7-ITESLA
Title: Innovative Tools for Electrical System Security within Large Areas
The project developed methods and tools for the coordinated operational planning of power transmission
systems, to cope with increased uncertainties and variability of power flows, with fast fluctuations in the
power system as a result of the increased share of resources connected through power electronics, and with
increasing cross-border flows. The project aims at enhancing cross-border capacity and flexibility while
ensuring a high level of operational security.
Fact Sheet: http://cordis.europa.eu/project/rcn/101320_en.html
Web Site: http://www.itesla-project.eu/
Important project outcomes include:
- a platform of tools and methods to assist the cooperation of transmission system operators in dealing
with operational planning from two days ahead to real time, particularly to ensure security of the
system. These tools support the optimisation of security measures, in particular to consider corrective
actions, which only need to be implemented in rare cases that a fault occurs, in addition to preventive
actions which are implemented ahead of time to guarantee security in case of faults. The tools provide
risk-based support for the coordination and optimisation of measures that transmission operators need
to take to ensure system security. The platform also supports "defence and restoration plans" to deal
with exceptional situation where the service is degraded, e.g. after storms, or to restore the service
after a black-out. The platform has been made publicly available as open-source software.
- A clarification of the data and data exchanges that are necessary to enable the implementation of these
coordination aspects.
- A framework to exchange dynamic models of power system elements including grids, generators and
loads, and a library of such models covering a wide range of resources. These models are essential to
produce accurate prediction of the rapid fluctuations that take place in the power grid after faults, and
to prevent cascading failures.
- The tools and models allow to reduce the amount of necessary preventive measures. The reliance on
risk-based approaches can avoid or mimimise costly preventive measures such as re-dispatching while
the overall risk of failure is decreased.
- A set of recommendations to policymakers, regulators, transmission operators and their associations
(jointly with the UMBRELLA project). These foster the harmonisation of legal, regulatory and
operational framework to allow the exploitation of the newly developed methods and tools. They also
555
Description of relevant European R&D projects
identify the need for increased formalised data exchange among TSO's to support the new methods
and tools.
Project FP7-UMBRELLA
Title: Toolbox for Common Forecasting, Risk assessment, and Operational Optimisation in Grid Security
Cooperations of Transmission System Operators (TSOs)
The project developed methods and tools for the coordinated operational planning of power transmission
systems, particularly to cope with high shares of variable renewable energy. They aimed at enhancing
cross-border capacity and flexibility while ensuring a high level of operational security.
Fact Sheet: http://cordis.europa.eu/project/rcn/101318_en.html
Web Site: http://www.e-umbrella.eu/
Important project outcomes include:
- The demonstration of probabilistic forecasting of power generation and power flows on a regional
basis. These are important to plan ahead of time, the most effective methods for relieving expected
congestions. Such forecasts will also be important for intraday trading on wholesale markets.
- Validated methods and tools for a coordinated optimisation of measures to ensure the security of the
pan-European grid. Of particular importance is the to coordination of measures for relieving expected
congestions, starting from low-cost measures such as switches to coordinated generation redispatching.
- The tools and models allow to reduce the amount of necessary preventive measures. The reliance on
risk-based approaches can avoid or mimimise costly preventive measures such as re-dispatching while
the overall risk of failure is decreased.
- a set of recommendations to policymakers, regulators, transmission operators and their associations
(jointly with the ITESLA project). These foster the harmonisation of legal, regulatory and operational
framework to allow the exploitation of the newly developed methods and tools. They also identify the
need for increased formalised data exchange among TSO's to support the new methods and tools.
Project FP7-eHIGHWAY2050
Title: Modular Development Plan of the Pan-European Transmission System 2050
The project developed new methods for the top-down long-term foresight of the power system
infrastructure in a 2050 perspective, and applied these to depict grid requirements under a number of
scenarios, and outlined a "future proof" modular development pathway to this horizon.
Fact Sheet: http://cordis.europa.eu/project/rcn/106279_en.html
Web site: http://www.e-highway2050.eu/e-highway2050/
Important project outcomes include:
- a number of basis scenarios framing possible evolution of demand, generation and delivery
infrastructure in the 2050 perspective
- a foresight of expected power system technology evolution in this time frame
- optimised grid architectures to efficiently respond to the delivery needs for each of the selected
scenarios
- a modular development plan with intermediate steps that largely fit all the future pathways
- new methods for optimal long-term planning of power systems in the presence of major uncertainties
- a well-documented proposal for the clarification of the concept of "electricity highways" in the context
of the EU energy infrastructure package. This proposal has largely been adopted in the process of
selecting the second round of "projects of common interest" and has resulted in a substantial number
of projects identified as "electricity highways" as part of a double label.
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Description of relevant European R&D projects
Project FP6 : VSYNC –
Title: Virtual Synchronous Machines (VSG's) For Frequency Stabilisation In Future Grids with a
Significant Share of Decentralized Generation.
The project developed methodologies to enable a generator to behave like a "Virtual Synchronous
Generator" (VSG) during short time intervals and contribute to the stabilisation of the grid frequency.
Cordis website: http://cordis.europa.eu/project/rcn/85687_en.html
Project website: http://www.vsync.eu/
Important project outcomes include:
- The Virtual Synchronous Generator technology can contribute to the stabilisation of the grid frequency
at distribution level. The Vsync technology could allow PV to provide balancing services replacing the
inertia of 'traditional' generators. As a result, the RES absorption capacity of the grid is increased.
- Today frequency control is handled by TSOs mainly with the help of generators connected to the
transmission network. The provision of Ancillary Services of assets connected to the distribution grid
is currently not standard practice and is not standardized. However, it is possible that these will be
required or offered in future, due to increased system needs, increasing share of decentralized
generation (also reducing the possibility to rely exclusively on large generation) and possible
connection and reinforcement cost optimization at distribution..
IEE project REServiceS –
Title: Economic grid support from variable renewables
RESERVICES addresses changes in the future European power system:, in particular the need for
development of an ancillary services market in which RES can participate.
IEE website: http://ec.europa.eu/energy/intelligent/projects/en/projects/reservices
Project website: http://www.reservices-project.eu/
Important project outcomes include:
- Ancillary services are grid support services required by the power systems (transmission or
distribution system operators TSOs or DSOs) to maintain integrity, stability and power quality or the
power system (transmission or distribution system). Ancillary services can be provided by connected
generators, controllable loads and/or network devices. Some services are set as requirements in Grid
Codes and some services are procured as needed by TSOs and DSOs to keep the frequency and
voltage of the power system within operational limits or to recover the system in case of disturbance or
failure.
- There are different procurement and remuneration practices for Ancillary services, and these practices
are evolving. There are already markets for some services. Some services are mandatory (not
necessarily paid for) and some services are subject to payments according to regulated (tariff) pricing
or tendering process and competitive pricing.
- RES (in particular PV and wind) can provide ancillary services both at DSO and TSO level, from a
technology point of view, but due to the way the markets are defined (and the way ancillary services
are managed) in practice they cannot participate.
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Description of relevant European R&D projects
Project FP6 Integral
Title: Integrated ICT-platform based Distributed Control in electricity grids with a large share of
Distributed Energy Resources and Renewable Energy Sources.
The INTEGRAL project demonstrated how Distributed Energy Resources and Demand Side Response in
the distribution grid can be controlled and coordinated, based on commonly available ICT
components, standards and platforms. The project treated the operating conditions of the grid with
DER/RES aggregations in three different operating conditions:
- Normal operating conditions of DER/RES aggregations – Stakeholders involved: consumers,
aggregators, utilities.
- Critical operating conditions of DER/RES aggregations – Stakeholders involved: consumers, DSO
- Emergency operating conditions – Stakeholders involved: DSO
Cordis website: http://cordis.europa.eu/project/rcn/86362_en.html
Project website: http://integral-eu.com/
Important project outcomes include
- The test field A of the INTEGRAL project (grid in normal operational conditions), the PowerMatching
City, demonstrated that the control of DER through an automated market based concept by means of
"agents" distributed in the grid and the Powermatcher application, satisfies the needs of consumers,
aggregators and DSO. On the Data and communication aspects, the project demonstrated the absence
of technological barriers as public networks were used for transport of private data by means of Virtual
Private Networks (VPN), a proven technology to transfer encrypted data.
- The test field B (critical operation of the grid) demonstrated that DSO or aggregators can control the
grid through controlling loads and generation of prosumers. Under critical conditions, the Demand
Side Management (DSM) system disconnects the critical loads.
- The test field C (emergency operation of the grid) demonstrates that the self-healing concept helps to
minimize the average outage time of the grid. It is a high automation levels that allows DSO reducing
the average number of interruptions, enhancing hence the service quality of the grid.
Project FP7 SuSTAINABLE
Title: Smart distribution System operaTion for mAximising the Integration of renewable generation
The SuSTAINABLE project developed and demonstrated the efficient and cost-effective management of
the grid with high penetration of RES configured as a virtual power plant through elaboration of data
related to load forecast, grid infrastructure protection and renewable energy production forecast.
Cordis website: http://cordis.europa.eu/project/rcn/106534_en.html
Project website: http://www.sustainableproject.eu/Home.aspx
Important project outcomes include:
- Concerning data management, the project demonstrated that intelligent management supported by
more reliable load and weather forecast can optimise the operation of the grid. The results show that
using the distributed flexibility provided by DRD – Dynamic Response of Demand can bring an
increase of RES penetration while, at the same time, avoiding investments in network reinforcement.
- Concerning DSO benefits, the results of the project demonstrated that the active management of the
renewable generation can lead to a decrease in the investment costs of distribution lines and
substations.
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Description of relevant European R&D projects
Project FP7 IDE4L
Title: Ideal Grid for All
The IDE4L project focuses on
- improving distribution network monitoring and controllability by introducing hierarchical
decentralized automation solution for complete real-time MV and LV grid management,
- utilizing existing distribution networks more efficiently and managing fast changing conditions by
integrating large number of distributed energy resources in distribution network through real-time
automation and market based flexibility services,
- guaranteeing continuity and quality of electricity supply by distributed real-time fault location,
isolation and supply restoration solution cooperating with microgrids, and
- improving visibility of distributed energy resources to TSOs by synthesizing dynamic information
from distribution system and to commercial aggregators by validating and purchasing flexibility
services.
Cordis website: http://cordis.europa.eu/project/rcn/109372_en.html
Project website: http://ide4l.eu/
Important project outcomes include:
- Concerning data management and interoperability, the project aims to create a single concept for
distribution network companies to implement active distribution network today based on existing
technology, solutions and future requirements.
- All data exchange and data modelling are based on international standards IEC 61850,
DLMS/COSEM and CIM to enable interoperability, modularity, reuse of existing automation
components and faster integration and configuration of new automation components.
IDE4L develops the entire system of distribution network automation, IT systems and functions for active
network management.
- Fault location, isolation and supply restoration
- Congestion management
- Interactions between distribution and transmission network companies
Project FP7 NRG4Cast
Title: Energy Forecasting
NRG4Cast project developed advanced solutions for predicting behaviour of local energy networks for the
three functions:
- Predicting energy demand on several network granularity levels (region, municipality, city, business,
household and energy service provider),
- Predicting energy network failures on interlinked local network topologies,
Detecting short-term trends in energy prices and long-term trends in national and local energy policies.
Cordis website: http://cordis.europa.eu/search/result_en?q=nrg4cast
Project website: http://www.nrg4cast.org/
Important project outcomes include:
- From the data collection point of view, the project demonstrates (as other similar projects) that the
optimization of the use of energy (and hence a higher business margin) in a distributed generation can
be achieved with the support of IT dedicated tools. DSOs as well as other actors (utilities,
municipalities, etc.) can use these tools in their activities.
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Description of relevant European R&D projects
Project FP7 EEPOS
Title: Energy management and decision support systems for Energy Positive neighbourhoods
EEPOS is a central energy management system for neighbourhoods that performs coordinated energy
management. Additionally, it actively participates in energy trading with external parties on behalf of
the neighbourhood members.
Cordis website: http://cordis.europa.eu/project/rcn/105854_en.html
Project website: http://eepos-project.eu/
Important project outcomes include:
- Regarding the right to self-produce, consume, store electricity and use flexibility, optimization of use
of energy use can be achieved at neighbourhood or district level more effectively than at household
level through ad hoc energy management systems (IT support as other similar projects).
- Consequence: Matching supply and demand automatically relieves grid unbalance providing hence
indirectly grid services.
H2020: BRIDGE project network
The BRIDGE initiative collects policy recommendations from the use cases which are currently under
demonstration in the ongoing H2020 energy projects.
Important findings for the market design initiative:
Balancing:
- barriers on access to the balancing market. It is observed that not all markets in practice allow load to
be included. This is discriminatory for the energy storage assets demonstrated in the projects and does
not allow the correct valorisation of their double operative nature.
Ancillary services:
- barriers on access to the ancillary market. Participants in the project include Energy Service companies
that provide e.g. Frequency Response, Congestion management, Reserve and Ramping Duty. It is
recommended that products for ancillary services should be consistent and standardized from
transmission and down to the local level in the distribution network. Such harmonization will increase
the availability of the services, enable cross-border exchanges and lower system costs.
Project H2020: SMARTNET
Title: Smart TSO-DSO interaction schemes, market architectures and ICT Solutions for the integration of
ancillary services from demand side management and distributed generation
The project SmartNet aims at providing architectures for optimized interaction between TSOs and DSOs in
managing the exchange of information for monitoring and for the acquisition of ancillary services (reserve
and balancing, voltage regulation, congestion management) both at national level and in a cross-border
context.
Cordis web site: http://cordis.europa.eu/project/rcn/200556_en.html
Project web Site: http://smartnet-project.eu/
Important project outcomes include:
- Validated acquisition of ancillary services from specific resources such as thermal inertia of indoor
swimming pools and batteries in telecommunication base systems. In addition the project will
demonstrate modalities to exchange monitoring signals between transmission and distribution
networks. The architectures for dataflow and control signals will be tested in full replica lab
considering various levels of responsibilities for the DSOs. These ranges from a model with extended
central dispatch where TSO contracts ancillary services directly from DER owners connected to the
DSO grid to a more decentralized model where TSO, DSO and BRPs contract ancillary services
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Description of relevant European R&D projects
connected at distribution level for their own need in a common market. The preferential architectures
and data flow models will be defined during the course of the project that is running until the end of
2018.
Project FP7: ECOgrid-EU
Title: Large scale Smart Grids demonstration of real time market-based integration of DER and DR
ECOGRID-EU is a large-scale demonstration project which included 1,900 test households, out of which
~1,200 houses were equipped with home automation equipment and 500 were manually controlled
households. The project focused on direct (resistance based) and indirect (heatpump) electricity heating
applications for households since these has the highest volume potential for demand response
Cordis web site: http://cordis.europa.eu/project/rcn/103636_en.html
Project web Site: http://www.eu-ecogrid.net/
Important project outcomes include:
- Dynamic pricing needs a short time-interval, i.e. 15 minutes or less. It shows as well that this is
technically possible: even a 5-minute period is technically possible although not cost-effective in the
project setting.
- The FP7 project ECOGRID has successfully demonstrated a "real time" power market concept with 5
min time resolution. The concept provides the customers with real time prices and the local ICT
control system in the houses make it possible to optimize the use of electricity by automated
adjustment of the consumption. The concept included both a global price signal for balancing and a
locational price signals for congestion management, although the latter wasn't fully validated. In the
basic concept of the EcoGrid EU project, control of active power is generally done by leveraging the
global real-time market price and its corresponding forecast. Based on this, price deviations for each of
the local areas can be computed in order to relief active power issues within that area. The ICT
concept consists of a new market place and local control schemes which are implemented by three
different technology vendors, thereby allowing a wider base of appliances.
- It showed as well the importance of a reliable communication and automation channel, in particular for
'legacy equipment' (i.e. already installed heat pumps or electric heating).
- An important learning was that automated control has responded much better to price signals than
manually controlled. A customer with manual control gave a 60 kW total peak load reduction while
automated or semi-automated customers gave an average peak reduction of 583 kW.
- For the households equipped with fully automated demand response, the communication interface was
the highest share of the equipment cost, but in future these costs could be virtually zero when
appliances are cloud connected anyway.
- For the demonstration area (Bornholm in Denmark) wind power curtailment (virtually) was reduced by
almost 80%, and the use of (virtual) spinning reserves has been reduced by 5.5%.
- In the replication roadmap it is shown that the Belgian market could give a EUR 2 million/year
reduction of balancing cost if 10%, of the 18% of the households that have a hot water buffer tank, is
used for demand response.
Project FP7 Grid4eu
Title: Large-Scale Demonstration of Advanced Smart GRID Solutions with wide Replication and
Scalability Potential for EUROPE
Grid4EU aims at testing in real size some innovative system concepts and technologies in order to
highlight and help to remove some of the barriers to the smart grids deployment and the achievement of the
2020 European goals. It focuses on how distribution system operators can dynamically manage electricity
supply and demand, which is crucial for integration of large amounts of renewable energy, and empowers
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Description of relevant European R&D projects
consumers to become active participants in their energy choices. It is organized around large-scale
demonstrations networks located in six different countries,
Cordis web site: http://cordis.europa.eu/project/rcn/103637_en.html
Project web Site: http://www.grid4eu.eu
Important project outcomes include:
- Demonstration of enhanced functionalities of Online Tap Change Transformers (OLTC) that will
enable higher levels of PV to be integrated in the downstream LV grid. This function consists in fine-
tuning the voltage set point according to a set of parameters and inputs that includes real-time solar
radiation, used as an indicator of the amount of PV energy being produced. This enhanced control
allows varying the voltage set point that takes into account the amount of PV energy being produced,
including reaction to real time perturbations (e.g. temporary reduction in PV production due to a
cloud).
- Demonstration of technical viability of islanding in a segment of a distribution network to alleviate e.g.
critical situations at TSO level.
- Demonstration of the "Network Energy Manager (NEM) that provides an integrated flexibility
marketplace for the TSO and DSO to specify their flexibility needs to solve their respective grid
operational constraints. These needs can be automatically computed by the NEM based on renewable
production forecasts and individual load forecasts. The NEM also provides a portal for various DER
and flexibility aggregators to offer their flexibility services to satisfy the requests. As a result, the
NEM performs a global optimisation to address needs in the most economical way while still
enforcing the technical constraints. This fully automated process notifies the aggregators of their
awarded flexibility for implementation and activation for demand response, load shifting or storage
device dispatch.
Project H2020: Futureflow
Title: Smart TSO-DSO interaction schemes, market architectures and ICT Solutions for the integration of
ancillary services from demand side management and distributed generation
FutureFlow links interconnected control areas of four transmission system operators of Central-South
Europe which today do face increasing challenges to ensure transmission system security: the growing
share of renewable electricity units has reduced drastically the capabilities of conventional, fossil-fuel
based means to ensure balancing activities and congestion relief through redispatching. Research and
innovation activities are proposed to validate the enabling conditions for consumers and distributed
generators to provide balancing and redispatching services, within an attractive business environment.
Cordis web site: http://cordis.europa.eu/project/rcn/200558_en.html
Project web Site: http://www.futureflow.eu/
Important project outcomes include:
- The project Futureflow will demonstrate in near-to-real-life conditions that balancing and
redispatching service providers are able to provide cross-border balancing and redispatching services
to control zones outside their Member State borders, including automatic frequency restoration reserve
services. Each transmission system operator connected to the regional platform is able to perform its
activities by using the offers from generators and consumers possibly located in the control area of
another transmission system operator also connected to the regional balancing and redispatching
platform.
Project FP7-AFTER
Title: A Framework for electrical power sysTems vulnerability identification, dEfense and Restoration
The AFTER project addresses the challenges posed by the need for vulnerability evaluation and contin-
gency planning of the energy grids and energy plants considering also the relevant ICT systems used in
protection and control. Project emphasis is on cascading events that can cause catastrophic outages of the
electric power systems.
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Description of relevant European R&D projects
Cordis web site: http://cordis.europa.eu/project/rcn/100196_en.html
Project web Site: http://www.after-project.eu
Important project outcomes include:
- The FP7 project AFTER has developed a framework for electrical power systems vulnerability
identification, defense and restoration. It uses a large set of data (big data) coming from on-line
monitoring systems available at TSOs’ control centres. A fundamental outcome of the tool consists in
risk-based ranking list of contingencies, which can help operators decide where to deploy possible
control actions.
Project FP7-SESAME
Title: Securing the European Electricity Supply Against Malicious and accidental threats
SESAME develops a Decision Support System (DSS) for the protection of the European power system and
applies it to two regional electricity grids, Austria and Romania.
Cordis web site: http://cordis.europa.eu/project/rcn/98988_en.html
Project web Site: https://www.sesame-project.eu/
Important project outcomes include:
- SESAME, developed a comprehensive decision support system to help the main public actors in the
power system, TSOs and Regulators, on their decision making in relation to network planning and
investment, policies and legislation, to address and minimize the impacts (physical, security of supply,
and economic) of power outages in the power system itself, and on all affected energy users, based on
the identification, analysis and resolution of power system vulnerabilities.
Project H2020: Nobelgrid
Title: New Cost Efficient Business Models for Flexible Smart Grids
NOBEL GRID will develop, deploy and evaluate advanced tools and ICT services for energy DSOs
cooperatives and medium-size retailers, enabling active consumers involvement –i.e. new demand response
schemas – and flexibility of the market – i.e. new business models for aggregators and ESCOs.
Cordis web site: http://cordis.europa.eu/project/rcn/194422_en.html
Project web Site: http://nobelgrid.eu/
Important project outcomes include:
- The H2020 project NOBEL Grid will develop, deploy and evaluate advanced tools and ICT services
for energy DSOs cooperatives and medium-size retailers, enabling active consumers and prosumers
involvement. Particularly for domestic and industrial prosumers they will develop an Energy
Monitoring and Analytics App. Demonstration and validation of the project solutions will be done in
real conditions in five different electric cooperatives and non-profit sites in five EU members’ states.
Project FP7-S3c
Title: Smart Consumer - Smart Customer – Smart Citizen
The S3C project’s overall objective is to foster the ‘smart’ energy behaviour of energy customers in Europe
by assessing and analysing technology and user-interaction solutions and best practices in scientific
literature, test cases and pilot projects. Based on these insights, the S3C consortium has developed a
practical toolkit for everyone who is involved or intends to become involved in the active engagement of
end users in smart energy projects or rollouts.
Cordis web site: http://cordis.europa.eu/project/rcn/105831_en.html
Project web Site: http://www.s3c-project.eu/
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Description of relevant European R&D projects
Important project outcomes include:
- The project suggests that energy system actors (e.g. DSOs, suppliers, ESCOs, regulators) must adapt
the way and the content of their communication with customers and citizens, taking into account the
diversity of consumer segments with different backgrounds and needs. The content of communication
must be transformed into something more visual, tangible and understandable, showing exactly the
benefits customers may experience (e.g. saved money, reduction of CO2 emission) instead of a purely
technical information.
Project FP7-metaPV
Title: Metamorphosis of Power Distribution: System Services from Photovoltaics
The goal of the demonstrator was to explore in real life how PV systems can provide grid services for
increasing the hosting capacity of existing grids. This was pursued by adding a significant amount of
controllable inverters to a confined grid where the PV penetration was high already before. The
demonstrator is split up in a low voltage (LV) and a medium voltage (MV) part. On LV, the project aimed
to convince 128 households' consumers to install PV systems of an average PV generation capacity of 4
kW, for a total of 512 kW. On MV, the target was to realise 31 installations of on average 200 kW, for a
total of 6,2 MW, located at commercial and industrial sites connected to the MV grid.
Notably, all PV inverters generate low voltage at their output; however, the so-called MV systems are
directly connected to the medium voltage grid through a transformer..
Cordis web site: http://cordis.europa.eu/project/rcn/94493_en.html
Project web Site: http://metapv.eu
Important project outcomes include:
- MetaPV demonstrated that remotely controllable inverters connecting PV-panels to the distribution
grid can offer congestion management services to the distribution grid (in the form of voltage control
obtained via reactive power modulation).
- For medium-voltage grids, the hosting capacity of the network can be increased by more than 50% at
the cost of 10% of traditional grid reinforcement. For low-voltage grids, the same is also possible as
long as the costs of sophisticated features for communication do not eat up the savings from the
substituted grid reinforcement.
In MetaPV, the household received a commercial offer for the demonstrator. This offer was attractive,
partly because the inverter was offered by the inverter manufacturer at the cost (not price). DSO paid
for additional equipment needed (like hardware for data logging and communication, batteries, etc.). In
exchange, the customers acknowledged that the installations made part of a demonstration and that
DSO had the right to control them from time to time.
- MetaPV suggests that DSO makes a multiannual investment plan that takes into account flexibility
(MetaPV suggests to do this through a cost-based analysis).
- The case of MetaPV raises the question if the DSOs have the right to use or impose functions to the
customers where the PV inverters are placed. Direct control over the inverter is only granted (in
special cases) in Austria and Germany whereas in several countries DSO can impose functions to PV
inverters.
Project FP7-INTrEPID
Title: INTelligent systems for Energy Prosumer buildings at District level
INTrEPID developed technologies that enable energy optimization of residential buildings, allowing
control of internal sub-systems within the Home Area Network and interaction with other buildings, local
producers, and electricity distributors, as well as enabling energy exchange capabilities at district level. The
project had three main objectives: A. Energy optimization, which is provided by the development of three
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Description of relevant European R&D projects
INTrEPID technological components (Indoor Home networks, Supervisory control strategies and Energy
Brokerage); B. Integration and validation of the integrated system. C. Dissemination and Exploitation.
Cordis web site: http://cordis.europa.eu/project/rcn/105992_en.html
Project web Site: http://www.fp7-intrepid.eu/ intrepid@telecomitalia.it
Important project outcomes include:
- A methodology to extract individual power consumption of home appliances with a measurement at a
single point, using non-intrusive load monitoring (NILM) has been developed. NILM algorithms
utilize machine learning to detect and extract features from the aggregated consumption data. For the
households considered in the INTrEPID project, the algorithm disaggregates the individual
consumption of major appliances, without the added cost of an individual meter per device. The tested
algorithm performs well in the experiments and delivers on its promises in simple settings, where the
models account for all of the loads. However, in the final scenario, the algorithm has to give up due to
lack of models and detailed datasets. Producing the Markov models for the algorithm proves to be the
biggest disadvantage of the algorithm. Attempts were made to construct these by manual inspection of
the dataset, which did prove to be quite successful. However, it was necessary to make assumptions
about the states of the refrigerator. For the general case this works quite well, but the possible defrost
cycle was not taken into account, and only one program in the dish washer was considered. This
indicates that exhaustive knowledge about the appliance is required, when reasoning about the number
of states and transitions.
- This project shows that direct access to the meter should be considered for other parties to be able to
develop innovative services based on NILM algorithm. It is therefore not good for innovation if all
information from the smart meter has to go via the DSO first.
- The project also demonstrates that there are further dimensions to investigate when considering the
data customer confidentiality
Project FP7- INCREASE
Title: Increasing the Penetration of Renewable Energy Sources in the Distribution Grid by Developing
Control Strategies and using Ancillary Services
INCREASE focuses on how to manage renewable energy sources in LV and MV networks, to provide
ancillary services (towards DSO, but also TSOs), in particular voltage control and the provision of reserve.
INCREASE investigates the regulatory framework, grid code structure and ancillary market mechanisms,
and propose adjustments to facilitate successful provisioning of ancillary services that are necessary for the
operation of the electricity grid, including flexible market products
Cordis web site: http://cordis.europa.eu/project/rcn/109974_en.html
Project web site: http://www.project-increase.eu/
Important project outcomes:
- The market access for aggregators is improving in some EU countries, while others are still lagging
behind. Often the regulatory frameworks are not supportive for demand response or participation of
distributed renewable generation.
- Important adjustments of market regulations can be observed in a few countries, namely the reduction
of the minimum bid sizes to allow small renewable generations to participate in tenders, and shorter
scheduling periods. However in several EU countries no suitable frameworks to enable participation of
flexibility aggregators yet exist.
Project FP7- evolvDSO
Title: Development of methodologies and tools for new and evolving DSO roles for efficient DRES
integration in distribution networks
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Description of relevant European R&D projects
With the growing relevance of distributed renewable energy sources (DRES) in the generation mix and the
increasingly pro-active demand for electricity, power systems and their mode of operation need to evolve.
evolvDSO will define future roles of distribution system operators (DSOs) and develop tools required for
these new roles on the basis of scenarios which will be driven by different DRES penetration levels,
various degrees of technological progress, and differing customer acceptance patterns.
Cordis web site: http://cordis.europa.eu/project/rcn/109548_en.html
Project web Site: http://www.evolvdso.eu/
Important project outcomes include:
- DSOs can create additional value by offering/using services to/from different stakeholders in the
interest of the entire power system and its users. A sound regulatory framework can support them in
these activities.
- Future markets and regulatory frameworks should recognize the need and should provide incentives
for possible innovative flexibility levers to be procured and activated on distribution grid level.
Different stakeholders may benefit from these flexibility levers. DSOs may need these services in
different timeframes as alternatives for grid investment (long-term ahead, procured via tender) and/or
conventional operational planning actions (short-term ahead, procured via a (flexibility) market
platform). DSOs will have to gradually increase their network monitoring capacities, as well as their
active involvement in flexibility services.
Future regulatory frameworks should set clear rules for the recognition of the costs (both CAPEX and
OPEX, over all timeframes) associated with innovative smart grid solutions, taking into account their
interaction with conventional solutions and the uncertainty on cost recovery.
- Future regulatory frameworks should continue to safeguard the availability of neutral, secure, cost-
efficient and transparent data and information management on distribution grid level for all concerned
stakeholders.
- Future electricity markets will need to take into account the location of system flexibility sources and
their impact on distribution grids.
Project FP7- DREAM
Title: Distributed Renewable resources Exploitation in electric grids through Advanced heterarchical
Management
DREAM is working on an innovative organisational and technological approach for connecting electricity
supply and demand. Heterarchical principles, in which coordination is configurable, are used to coordinate
users, producers and technical/commercial/financial operators to achieve benefits. These are expected to
well exceed the technological investments required to final users. This will be pursued also through the
introduction of a new layer in the energy market, placed at distribution level and allowing for cost-effective
dynamic aggregations of users and local exchange/sales of capabilities (e.g. ancillary services from shed-
able loads or from time-flexible use of electric power), while ensuring integration with upper level national
energy marketplaces and their international interactions..
Cordis web site: http://cordis.europa.eu/project/rcn/109909_en.html
Project web Site: http://www.dream-smartgrid.eu/
Important project outcomes include:
- The intrinsic control capability made available at distribution network level through the innovative
heterarchical paradigm of DREAM, will accommodate for improved real time local balancing of
energy demand and provision, thus limiting the request of voltage and frequency regulation capacity at
transmission and distribution control level.
- The net effect of additional local balancing capacity will be reflected into a reduction of network
reinforcement requirements, and thus will increase the allowance for safe management of renewable
and distributed energy resources at the same level of deployed reinforcements.
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Description of relevant European R&D projects
Project FP7-PlanGridEV
Title: Distribution grid planning and operational principles for electric vehicles mass roll-out while
enabling integration of renewable distributed energy sources.
The increasing number of electric vehicles (EVs) (and their batteries) on the one hand and of distributed
energy sources (DER) on the other, both connected to the low-voltage (LV) and the medium-voltage (MV)
grid, are a major challenge for Distribution System Operators (DSOs) with regard to secure and reliable
energy supply and grid operation. The project developed a planning tool for DSOs which copes with this
new challenge and facilitates the transformation of the grid towards a smart grid (with controllable loads).
With the help of the tool, investment strategies regarding the reinforcement of infrastructures can be
downsized while the service quality and efficiency can be improved at the same time (reduction of peak
loads and increased renewable energy supply). PlanGridEV developed architectures to build smart grids
that support a successful and economical rollout of charging infrastructure. In addition to paving the way
into a new way of mobility these architectures are able to activate new markets where the costumers’ (EV
users) can participate and benefit from (change from costumer to prosumer e.g. by offering battery capacity
for grid stability services).
Cordis web site: http://cordis.europa.eu/project/rcn/109374_en.html
Project web site: http://www.plangridev.eu/
Important project outcomes include
- The new planning tool for DSOs: it considers the controllability of the loads (i.e. EVs) with the
(estimated) electricity generation from renewable resources;
- Tests with controllable loads DER performed in a large variety of grid constellations have shown that
peak loads could be reduced (up to 50%) and more renewable electricity could be transported over the
grid compared to scenarios with traditional distribution grid scenarios; as a result, critical power
supply situations can be avoided, and grids, consequently, do not call for reinforcement;
- Smart grids on LV/MV level require the introduction of more information and communication
technologies (ICT) allowing the exchange of operation data and control schemes between independent
market actors. PlanGridEV outlines changes of the regulatory framework allowing for a new market
design embedded within a roadmap and tangible recommendations for (i) industry, (ii) grid operators
and service providers, (iii) policy makers, and (iv) regulators with the aim that investments in grid
intelligence can be rewarded via modified tariff systems and market borders can be broken down.