Europaudvalget 2016
KOM (2016) 0864
Offentligt
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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}
EN
EN
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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
240
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A
NNEXES
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.
241
Annex I: Procedural information
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Comments made by RSB in first Opinion
Modifications made in reaction to
of 16 September 2016
comments RSB
Issues cross cutting to other impact assessments
This IA and the IA on the revision of the
An explicit vision of the EU electricity
renewables directive need a coherent analysis market has been incorporated in section
of renewable electricity support schemes.
1.1.1.4. This vision includes a section on the
They need to reconcile different expectations connection with the share of RES E and
of what the market will deliver in terms of the prosumers.
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
The IA should clarify and explain the content A dedicated section was included in Annex
and assumptions of the baseline scenario in
IV clarifying all points raised concerning the
relation to the other parallel initiatives
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
A plain-language abstract has been added at
make it helpful in informing political
the beginning of the document.
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
The report should present a clear vision for
An explicit vision of the EU electricity
the EU electricity market in 2030 and beyond market has been incorporated in section
with a distinction between immediate
1.1.1.4 covering issues mentioned.
challenges and longer term developments.
This vision needs to be coherent with EU
A detailed section on in RES E in connected
policies on competition, climate and energy.
with the MDI is contained in a text box in
It also needs to be consistent with the parallel section 6.2.6.3. Another box is located in
initiatives, notably the revision of the RES
Section 2.1.3.
Directive. In particular, this applies to the
assumptions and expectations on what the
new electricity market design could deliver
Further clarifications have been added in
on its own and whether the renewable target
requires complementary market intervention. section 1.2.1 on interlinkages with RED II.
Based on a common (with other parallel
A dedicated section was introduced in Annex
initiatives) baseline scenario, the report
IV clarifying all points raised concerning the
should prioritise the issues to be addressed,
baseline, REF2016 and EUCO27.
present an appropriate sequencing and
strengthen the treatment of subsidiarity
The baseline description in 5.1.2, 5.2.2,
considerations such as for action related to
6.1.1.2 and 6.1.1.4 was improved and
energy poverty and distribution system
references were made to its more detailed
operators.
description in the Annex.
242
Annex I: Procedural information
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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
On how the models of "energy only markets"
options, the report should indicate whether
will coexist with CMs, clarifications have
and how the models of “energy only markets”
been introduced in section 2.2.2.
will coexist with capacity mechanisms and
assess the risks of an uncoordinated
Section 6.2.6 now includes a sub-section on
introduction of capacity remuneration
investments, discussing all relevant issues.
mechanisms across the EU. The impact
analysis should also report on the
effectiveness of the options to deliver the
adequate investment and price responses.
Main recommendations for improvements
The analysis of support schemes for
An explicit vision of the EU electricity
renewable electricity should be consistent
market has been incorporated in section
across this impact assessment and the one
1.1.1.4. This includes a vision on whether
outside-the- market measures to support for
covering renewable energy sources. The
reports should clarify what support schemes
RES E are needed up to 2030. The question
will be needed, and whether these are needed what type of out-of-market support
only in case the market fails to deliver the
mechanisms are needed falls within the remit
2030 EU target of at least 27% of RES in
of the RED II IA.
final energy consumption, or will be used to
promote certain types of renewable energy.
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 An explicit vision of the EU electricity
procedure envisaged for procuring support
market has been incorporated in section
for renewable energy producers and assess its 1.1.1.4. This includes a vision on whether
outside-the- market measures to support for
impact on the electricity market.
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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Annex I: Procedural information
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Comments made by RSB in first Opinion
of 16 September 2016
Modifications made in reaction to
comments RSB
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.
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 expected involvement of consumers and
prosumers in supplying electricity and
managing its demand has to be consistent
across the two impact assessments.
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
The analysis should integrate the effects of
developed in a text box in Section 6.1.4.2.
potentially more volatile electricity prices and Also the RED II IA has been adjusted.
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.
In devising the options, the report should be
See section 2.4.1 and section 5.4.4. The
proportionate to the importance of the
report clarifies the main objective of the
problems/objectives and realistic in assessing measures linked to energy poverty (i.e.
what can be achieved. For instance, options
description of the term 'energy poverty' and
linked to the issue of energy poverty (being
measurement of energy poverty), which
part of the social policy) should be built
already apply to Member States (Member
around increasing transparency and peer
States should address energy poverty where it
pressure among Member States rather than
is identified). Better monitoring of energy
the single market motive.
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,
A dedicated section was included in Annex
including the link with the 2016 reference
IV clarifying all points raised concerning the
scenario and underlying assumptions
baseline, REF2016 and EUCO27.
Some more technical comments have been
All technical comments have been addressed.
transmitted directly to the author DG and are
expected to be incorporated into the final
version of the impact assessment report
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Annex I: Procedural information
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Comments made by RSB in first Opinion
of 16 September 2016
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
Modifications made in reaction to
comments RSB
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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Annex I: Procedural information
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Comments made by RSB in second
Modifications made in reaction to
Opinion on 7 November 2016
comments RSB
Opinion RSB on resubmission
Restoring price signals for investments is
Reference is made to the new Box 9
one crucial element of the revised market
underneath Section 6.4.6 for further
design. The report is clearer on its view that explanations, which was added following
undistorted markets deliver the right price the RSB comments.
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?
Further recommendations for improvements
Internal coherence and risks:
Text has been added to Sections 8.1 and
The analysis in the report demonstrates that 8.2.2 with regard to the reviewing of
the vision for the EU electricity market in assumptions and monitoring of
2030 and beyond relies on the
implementation.
implementation of many different policies The 2030 RES E objectives are part of the
and assumptions, and is subject to
base-line of the analyses. Trade-offs
numerous risks. The narrative of the report between government interventions in
should more clearly reflect these risks. The support of RES E are investigated in the
report should propose modalities to review REDII impact assessment. However, in the
assumptions and monitor implementation at present report, it has been rendered more
intermediate stages. The text of the report clearly what elements of the RED II
should reflect the trade-off between
initiative are important to the impacts of the
restoring the EU internal energy market in present initiative.
its pure form and government intervention See in this regard Section 1.1.1, 1.2.1, Box
to support renewable energy sources and to 7 under section 6.2.6.3, Box 9 under Section
maintain security of supply.
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 The risks of greater price variability have
Union places citizens at its core. The report been introduced in two new text boxes in
should therefore better address the risks
Section 5.1.4.3 (Box 4) of the main impact
and benefits to consumers, especially with assessment document, and in Section 3.1.5
regard to expected higher price variability. of the Annexes to the Impact Assessment.
It should discuss not just possible long run These specifically address the benefits and
benefits, but also costs (including switching risks of dynamic electricity pricing
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Comments made by RSB in second
Opinion on 7 November 2016
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
Modifications made in reaction to
comments RSB
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.
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
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Annex I: Procedural information
To improve clarity, the new Box 9 includes
further explanations. Please also see new
footnotes 345 and 384
.
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
Modifications made in reaction to
Opinion on 7 November 2016
comments RSB
substantially and the wholesale prices will phased out by 2024, whereas the impact
be depressed at least until the current
assessment looks at the situation in 2030.
support schemes for RES-E are reviewed in For more detail see Annex IV.
2024.
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
References to policy trade-offs (market
inclusion of the abstract has improved the versus government intervention) have been
presentation of relevant information,
further emphasised. See for instance the
though the issue of policy trade-offs
abstract, page 10 and 13 and Sections
(market vs. government interventions)
6.2.2.1, 6.2.6.3 and 7.5.1. Furthermore,
should be emphasized more explicitly
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 I: Procedural information
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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 consultation
1
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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Annex II: Stakeholder consultations
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The following paragraphs provide a summary of the responses available on the
Commission's website
2
. The responses and a summary thereof are also available on the
Commission's website
3
.
(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";
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
(ii)
2
3
https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E
nergy%20Market.pdf
https://ec.europa.eu/energy/en/consultations/consultation-generation-adequacy-capacity-mechanisms-
and-internal-market-electricity
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Annex II: Stakeholder consultations
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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 3
ème
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.
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
(iv)
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Annex II: Stakeholder consultations
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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-consumers
4
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 website
5
.
(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
5
https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market
https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E
nergy%20Market.pdf
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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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(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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Public consultation on a new energy market design
A wide public consultation
6
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 website
7
.
(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
7
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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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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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 3
rd
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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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 website
8
.
(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
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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
-
-
-
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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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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 2020
11
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 website
12
.
Targeted consultations
A High Level Conference on electricity market design took place on 8 October 2015 in
Florence.
9
10
11
12
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.
A similar concern is reflected in the market design consultation results.
https://ec.europa.eu/energy/en/consultations/preparation-new-renewable-energy-directive-period-after-
2020
https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design
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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
Forum
13
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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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
15
http://data.consilium.europa.eu/doc/document/ST-9073-2015-INIT/en/pdf
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
1.1. Priority access and dispatch
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 oversee implementation of provisions, notably determination which generators
continue to benefit from priority rules, and ensure correct curtailment compensation.
Measure
1.2. Regulatory exemptions from balancing responsibility
Need to change national legislation in so far as it contains
exemptions from balancing responsibility
Need to oversee implementation of provisions, notably oversight of
TSOs.
1.3. RES E access to provision of non-frequency
ancillary services
They need to adapt national legislation to create
conditions for non-discriminatory procurement of non-
frequency ancillary services.
They need to oversee implementation and monitoring
of provisions, notably oversight of TSOs.
National
regulatory
authorities
(NRAs)
Transmission
System
Operators
(TSOs)
Distribution
System
Operators
(DSOs)
Generators
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.
Where DSOs curtail generation to resolve local grid constraints, they are affected
identically to TSOs.
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.
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.
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.
Most likely not affected.
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.
Suppliers
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.
Suppliers are not directly affected.
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.
Balancing responsible parties, including suppliers, traders and
generators currently subject to balancing responsibility are not
directly impacted.
Power exchanges could benefit from the increased market liquidity
particularly for short-term products which results from balancing
responsibility of RES E.
Aggregators are likely to benefit in particular by offering to small
generators services to fulfil their balancing responsibility.
End consumers are not directly 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.
Aggregators are likely to benefit in particular by offering market-based resources to be
used by TSOs in redispatch or curtailment.
End consumers are not directly affected.
Most likely not affected.
Aggregators
End consumers
Aggregators are likely to benefit from a more level
playing field and get access to additional remuneration
streams.
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
2.1. Reserves sizing and procurement
Member States
Member State authorities define the country's overall
policy regarding energy mix and power grid investments.
Measure
2.2. Removing distortions for liquid short-term markets
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.
2.3. Improving the coordination of Transmission System Operation
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).
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.
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.
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.
Transmission
System
Operators
(TSOs)
Generators
Aggregators
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.
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.
Smaller products and time units will give aggregators
more access to intraday markets.
Regional procurement of reserves would lead to regional
settlement of imbalances; therefore allowing for increase
competition of suppliers across borders.
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
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.
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.
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.
Suppliers
Power
exchanges
Increased price fluctuations will give aggregators more opportunities
to operate, thereby helping to ensure that demand meets supply at any
point in time.
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.
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 aggregators.
Limited impact on suppliers.
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
2.1. Reserves sizing and procurement
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 will be able to participate in balancing
markets via demand response aggregators allowing for
stronger supplier's competition at regional level.
Measure
2.2. Removing distortions for liquid short-term markets
2.3. Improving the coordination of Transmission System Operation
End consumers
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
3.1. Unlocking demand side response
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.
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.
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..
Measure
3.2. Distribution networks
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.
3.3. Distribution network tariffs and DSO
remuneration
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.
3.4. Improving the institutional framework
MS authorities will be in charge of national
implementation of the revised Third Package.
National
regulatory
authorities
(NRAs)
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)
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
3.1. Unlocking demand side response
Measure
3.2. Distribution networks
3.3. Distribution network tariffs
remuneration
and DSO
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.
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.
Transmission
System
Operators
(TSOs)
European
network
of
transmission
system operators
(ENTSOs)
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.
ENTSO-E will not be affected by changes in
unlocking demand response.
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.
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.
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.
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.
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
3.1. Unlocking demand side response
indirectly benefit from a better uptake of demand
response as the reduction in peaks it will reduce the
need to invest in distribution networks.
Measure
3.2. Distribution networks
3.3. Distribution network tariffs
remuneration
and DSO
3.4. Improving the institutional framework
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.
Suppliers
Power exchanges
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.
No impact expected
Suppliers will not be affected as the envisaged
measures will not affect their normal business.
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.
It is not expected that the envisaged measures will
affect the suppliers.
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 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.
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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Affected party
3.1. Unlocking demand side response
Measure
3.2. Distribution networks
3.3. Distribution network tariffs
remuneration
and DSO
3.4. Improving the institutional framework
form of network codes and guidelines.
Aggregators (and
other
new
market entrants)
End consumers
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.
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.
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
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
4.1. Removing price caps
Measure
4.2. Improving locational price signals
4.3. Minimise investment and dispatch
distortions due to transmission tariff
structures
Member States authorities will be impacted if
they
are
responsible
for
implementing/enforcing/monitoring
the
requirements.
4.4. Congestion income spending to increase cross-
border capacity
Member States authorities will be impacted if they are
responsible for implementing/enforcing/monitoring the
requirements.
Member States
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. 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.
NRAs play a significant role in monitoring,
authorising, etc. tariffs and connection
charges. Any change would impact on how
they do this.
Transmission
System
Operators
(TSOs)
Generators
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.
Different price zones will change the prices that
generators receive depending on their location.
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.
Changes would most affect generators
lower connection charges or tariffs (where
they are applied to generators) would have a
positive impact on their revenues.
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.
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.
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.
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.
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Affected party
4.1. Removing price caps
Measure
4.2. Improving locational price signals
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.
4.3. Minimise investment and dispatch
distortions due to transmission tariff
structures
Limited impact on suppliers.
4.4. Congestion income spending to increase cross-
border capacity
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.
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.
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.
Different price zones
could
affect end-consumers
depending on their location. However, possibilities exist
to retail MS-level retail prices,
Limited impact on power exchanges.
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.
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
5.1. Improved generation adequacy methodology
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.
NRAs/ ACER would be required to approve the methodology used by ENTSO-E for the generation
adequacy methodology and potentially endorse the assessment.
Measure
5.2. Cross-border operation of capacity mechanisms
Each Member State would not need to design a separate individual solution
and this would potentially
reduce the need for bilateral negotiations between TSOs.
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.
National
regulatory
authorities (NRAs)
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.
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.
Suppliers
Aggregators
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).
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.
Limited impact on suppliers
Limited impact on aggregators
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.
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.
Limited impact on suppliers
Just like generators they shall be able to participate in cross-border CMs.
Power exchanges
End consumers
Limited impact on power exchanges
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
Member States
Measure
National
regulatory
authorities (NRAs)
Transmission System
Operators (TSOs)
Generators
Suppliers
Aggregators
Power exchanges
End consumers
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").
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.
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.
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.
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.
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.
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.
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
7.1. Monitoring energy poverty
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.
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.
Measure
7.2. Options for phasing out regulated prices
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.
7.3. Creating a level playing field for access to data
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)
Transmission
System Operators
(TSOs)
The preferred option would not directly affect TSOs.
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 preferred option would not directly affect TSOs.
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.
Distribution System
Operators (DSOs)
The preferred option would not directly affect DSOs.
The preferred option would not directly affect DSOs.
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.
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
7.1. Monitoring energy poverty
Generators
The preferred option would not directly affect generators.
Measure
7.2. Options for phasing out regulated prices
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.
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.
7.3. Creating a level playing field for access to data
Generators will not be affected under the preferred option.
Suppliers
Power exchanges
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.
The preferred option would not directly affect power exchanges.
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.
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.
Removing price regulation would stimulate the development of energy
services which create market opportunities for aggregators.
-
Aggregators
The preferred option would not directly affect aggregators.
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.
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.
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
7.4. Facilitating supplier switching
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 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.
Not affected.
7.5. Comparison Tools
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.
Measure
7.6. Improving Billing Information
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. 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.
Not affected.
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)
Distribution
System
Operators
(DSOs)
Not affected.
Suppliers
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.
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.
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.
Comparison
providers
tool
Not affected.
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.
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.
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.
Not affected.
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Affected party
7.4. Facilitating supplier switching
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.
7.5. Comparison Tools
Measure
7.6. Improving Billing Information
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.
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.
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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 Commission
16
.
METIS was presented to the Member States' Energy Economists Group on April 5
th
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 ENER
17
.
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
17
http://ec.europa.eu/dgs/energy/tenders/doc/2014/2014s_152_272370_specifications.pdf
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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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, CO
2
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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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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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
PRIMES
18
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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PRIMES is a private model which has been developed and is maintained by
E3MLab/ICCS of National Technical University of Athens
19
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 2011
20
.
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-CO
2
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
20
http://www.e3mlab.National Technical University of Athens.gr/e3mlab/.
https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_1569_2.pdf'.
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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 detail
21
.
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
EUPHEMIA
22
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 bidding
23
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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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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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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1730780_0056.png
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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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
2014
24
. 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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-
-
-
-
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
Electricity consumption (in TWh)
Final energy demand
Industry
Households
Tertiary
Transport
Energy branch
Transmission and distribution losses
Net Installed Power Capacity (in GW
e
)
Nuclear energy
Renewable energy
Hydro (pumping excluded)
Wind on-shore
Wind off-shore
Solar
Biomass-waste fired
Other renewables
Thermal power
Solids fired
Oil fired
Gas fired
Net Electricity generation by plant
type (in TWh)
Nuclear energy
Renewable energy
Hydro (pumping excluded)
Wind on-shore
Wind off-shore
Solar
Biomass-waste fired
Other renewables
Thermal power
Solids fired
Oil fired
Gas fired
Source: PRIMES
3,029.0
2,530.7
1,061.1
713.8
683.5
72.3
281.7
216.2
683.5
139.6
129.0
115.8
12.7
0.1
0.2
12.7
0.8
414.9
194.5
83.3
123.8
2,844.0
893.9
374.5
351.6
22.2
-
0.1
42.9
5.0
1,575.6
866.3
178.4
483.4
2015
3,271.8
2,802.4
1,001.4
833.6
899.3
68.2
262.6
206.7
965.6
120.8
366.7
127.5
130.6
11.0
97.4
27.9
1.1
478.1
176.6
53.1
219.6
3,090.0
825.7
736.2
357.7
241.4
32.8
103.8
130.6
7.1
1,528.0
780.3
30.2
580.4
2030
3,525.6
3,081.3
1,054.8
899.7
982.2
144.6
231.2
213.1
1,131.0
109.9
652.2
133.3
246.1
37.9
233.8
53.1
2.1
368.9
99.4
15.3
200.1
3,396.7
738.4
1,372.8
375.1
564.4
127.3
303.6
238.1
9.7
1,285.6
448.6
14.6
576.8
Share in
total for
2030 (%)
30%
26%
28%
4%
7%
6%
10%
58%
12%
22%
3%
21%
5%
0%
33%
9%
1%
18%
% diff
2015-
2010
8%
11%
-6%
17%
32%
-6%
-7%
-4%
41%
-13%
184%
10%
-
-
-
121%
32%
15%
-9%
-36%
77%
9%
-8%
97%
2%
-
-
-
204%
42%
-3%
-10%
-83%
20%
% diff
2030-
2015
8%
10%
5%
8%
9%
112%
-12%
3%
17%
-9%
78%
5%
88%
246%
140%
90%
86%
-23%
-44%
-71%
-9%
10%
-11%
86%
5%
134%
288%
193%
82%
37%
-16%
-43%
-52%
-1%
22%
40%
11%
17%
4%
9%
7%
0%
38%
13%
0%
17%
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 CMs
25
. 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 E
26
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 options
27
. 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 website
28
.
Preliminary EUCO27
26
27
28
The same applies for CHP, when the main use of those plants is the production of heat/steam.
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).
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 CO
2
price, which was 38.5 EUR/tCO
2
in the preliminary version is 42 EUR/tCO
2
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 procurement
29
;
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 report
30
.
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 scenario
31
. For
certain EU28 countries the split between hydro lake and run-of-river of PRIMES
29
30
Actually reserve procurement was not modelled for other non-EU28 Member States, as well as for
Malta, Cyprus and Luxembourg.
"METIS
Technical Note T04: Methodology for the integration of PRIMES scenarios into METIS",
Artelys (2016)
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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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8. METIS used the same NTC values as in PRIMES EUCO27
32
. 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