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 - Hoofdinhoud

Council of the European Union

Brussels, 2 December 2016 (OR. en)

15135/16

Interinstitutional File: ADD 4

2016/0379 (COD) i

ENER 418 ENV 758 CLIMA 169 COMPET 637 CONSOM 301 FISC 221 IA 131 CODEC 1809

COVER NOTE

From: Secretary-General of the European Commission, signed by Mr Jordi AYET PUIGARNAU, Director

date of receipt: 1 December 2016

To: Mr Jeppe TRANHOLM-MIKKELSEN, Secretary-General of the Council of the European Union

No. Cion doc.: SWD(2016) 410 final - PART 2/5

Subject: 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

Delegations will find attached document SWD(2016) 410 final - PART 2/5.

Encl.: SWD(2016) 410 final - PART 2/5

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 i} {SWD(2016) 411 final} {SWD(2016) 412 final} {SWD(2016) 413 final} 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

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

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 tradeoffs

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

on its own and whether the renewable target Further clarifications have been added in 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

Comments made by RSB in first Opinion Modifications made in reaction to of 16 September 2016 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 covering renewable energy sources. The outside-the- market measures to support for 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 impact on the electricity market. outside-the- market measures to support for

RES E are needed. A detailed section on in RES E in connected with the MDI is contained in a text box in section 6.2.6.3. Further clarifications have been added in section 1.2.1 on interlinkages with RED II.

243

Comments made by RSB in first Opinion Modifications made in reaction to of 16 September 2016 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).

In addition, even though the report does not Text adapted in section 2.2.2 and included a present a blueprint for a capacity reference to forthcoming report by DG remuneration mechanism (as it is in the remit Competition. 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 An explicit vision of the EU electricity prosumers in supplying electricity and market has been incorporated in section managing its demand has to be consistent 1.1.1.4. across the two impact assessments. 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

244

Comments made by RSB in first Opinion Modifications made in reaction to

of 16 September 2016 comments RSB

The IA report needs to be more reader A reader friendly abstract that succinctly

friendly and helpful for decision-making. The presents the main elements of the analysis,

report should contain a 10-15 page abstract the policy trade-offs and the conclusions has

that succinctly presents the main elements of been added to the main text of the IA.

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

245

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

246

Comments made by RSB in second Modifications made in reaction to Opinion on 7 November 2016 comments RSB

fees) in the short and medium term. In the contracts, which are a frequent concern of same vein, the report should examine the consumer groups. impact of the policy on various groups of consumers 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 To improve clarity, the new Box 9 includes based on modelling, the results of the further explanations. Please also see new modelling should be critically reviewed to footnotes 345 and 384 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 feedin 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 It has been made clearer that market based RES-E support schemes (as proposed in the support schemes, such as premium schemes RED II IA) is not critically discussed. First, combined with auctions, are an underlying the report needs to emphasize that they premise of the impacts of the present would not be based on any type of feed-in initiative. (See section 1.1.1, 1.2.1, Box 7 tariff but premiums on top of market under section 6.2.6.3, Box 9 underneath revenues and these premium will be section 6.4.6 and Annex IV) auctioned. Second, the report needs to consider the fact that such auctions may not The phase-out of non-market based support necessarily be effective in reducing the schemes has already commenced under the support to renewable energy sources. This EEAG adopted in 2014 and is further is particularly relevant in a situation where reinforced by the measures proposed by the share of renewables in the electricity RED II. It is therefore assumed that nongeneration mix is expected to grow market based support schemes are fully

247

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.

248

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

249

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";

(ii) Market functioning. In the context of a weak demand and economic crisis, Europe's energy markets today area was deemed characterised by two developments: the integration of large amounts of renewables and the implementation of the EU target model. This was clearly reflected in the responses to this consultation. Overall respondents' opinions were split as to whether energy-only markets could deliver investments needed to ensure generation adequacy and security of supply. However, there is near unanimous support from respondents for the importance of the completion of the integration of day-ahead, and close to real time markets as a an important contributor to security of supply although, some respondents caution that this will not address fundamental problems with whether energy-only markets can deliver resource adequacy Similarly, there are strong calls facilitating demand side response and the development of grids in line with the ten year network development plan. Almost all responses to the consultation raised the impact of RES E on the market. For example the UK response discusses the impact that more low marginal cost pricing will have on the market, and the issue is discussed in detail in the Clingendael paper submitted in response to the consultation. Industry in particular raised the issue about the impact that RES E support schemes had on the market. While many raise the issue of any out-of-market support creating distortions, the position set out in the response of Eneco, a Dutch company is worth quoting "In general, support for specific energy sources does not undermine investments to ensure generation adequacy, it just changes the merit order. But details of support mechanisms can, specifically if a support mechanism lowers the value of flexibility". This consideration can be seen in the numbers of

2

https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E nergy%20Market.pdf

3 https://ec.europa.eu/energy/en/consultations/consultation-generation-adequacy-capacity-mechanisms

href="https://ec.europa.eu/energy/en/consultations/consultation-generation-adequacy-capacity-mechanisms-and-internal-market-electricity">and-internal-market-electricity

250

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.

(iv) Interventions to ensure security of supply. As already noted opinion is divided on whether energy only markets can deliver the investments which will be needed to ensure generation adequacy and security of supply in the future. However, there were even more varied opinions on the effectiveness of different capacity remuneration mechanisms. Given this divergence of opinion therefore there is only limited support for a European blueprint, many respondents pointing to divergent local circumstances and the need to address specific problems as

251

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 https://ec.europa.eu/energy/en/consultations/consultation-retail-energy-market

5

https://ec.europa.eu/energy/sites/ener/files/documents/Charts_Public%20Consultation%20Retail%20E nergy%20Market.pdf

252

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 selfgeneration and auto-consumption splits views evenly.

253

(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 hasslefree, 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 i 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 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 nondiscriminatory 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 crossborder 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 interdependence. 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 href="https://ec.europa.eu/energy/en/consultations/public-consultation-risk-preparedness-area-security-electricity-supply">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 The rather cautious reaction to the idea of regional plans contrasts with the overwhelming support for regional assessments of generation adequacy under the market design consultation.

10 A similar concern is reflected in the market design consultation results.

11 https://ec.europa.eu/energy/en/consultations/preparation-new-renewable-energy-directive-period-after

2020 12 https://ec.europa.eu/energy/en/consultations/public-consultation-new-energy-market-design

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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 http://data.consilium.europa.eu/doc/document/ST-9073-2015-INIT/en/pdf

263 264

Annex III: Who is affected by the initiative and how

The present initiative covers a large area of measures. The tables below provide an overview of the parties affected, separately for each of the measures resulting from the preferred policy options developed in the Annexes 1.1 through to 7.6.

Such matters are equally referred to in section 6 of the main text for the (more aggregated) main policy options developed there.

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Table 1. Persons affected by measure for Problem Area I, Option 1(a) (level playing field)

Affected party Measure

1.1. Priority access and dispatch 1.2. Regulatory exemptions from balancing responsibility 1.3. RES E access to provision of non-frequency ancillary services

Member States Need to change national legislation in so far as it contains priority dispatch; need to Need to change national legislation in so far as it contains They need to adapt national legislation to create include provisions on transparency and compensation of curtailment and redispatch exemptions from balancing responsibility conditions for non-discriminatory procurement of nonfrequency ancillary services.

National Need to oversee implementation of provisions, notably determination which generators Need to oversee implementation of provisions, notably oversight of They need to oversee implementation and monitoring regulatory continue to benefit from priority rules, and ensure correct curtailment compensation. TSOs. of provisions, notably oversight of TSOs. authorities

(NRAs)

Transmission Reduction of priority dispatch and priority access facilitates grid operation and lowers Implementation of balancing rules, notably settlement of parties in They need to change the way non-frequency ancillary

System dispatch costs. Introduction of clear compensation rules on the other hand can increase imbalance. services are contracted, procured and possibly

Operators redispatch costs where such compensation is currently insufficient. remunerated.

(TSOs)

Distribution Where DSOs curtail generation to resolve local grid constraints, they are affected No direct impact, as balancing is the role of TSOs; indirectly, DSOs very likely would also be affected, because most

System identically to TSOs. increased balancing responsibility of generators increases system RES are connected at distribution level and the DSO's

Operators transparency also to the benefit of DSOs. role in managing their network would have to change

(DSOs) in order to allow RES assets to participate to the provision of ancillary services.

Generators Generators currently subject to priority rules will be exposed to increased curtailment Balancing responsible parties, including suppliers, traders and Owners of generation assets (RES and not) would be risks and lower likelihood of dispatch (for high marginal cost generators; likelihood of generators currently subject to balancing responsibility are not affected by changes in the rules of how non-frequency dispatch actually increases for low marginal cost generators) unless they continue to directly impacted. Generators currently exempted or partly shielded ancillary services are procured. More transparent and benefit from the exemptions. Generators not subject to exemptions will be less likely to from balancing responsibility will have to increase their efforts to competitive procurement rules could enable market be curtailed and more likely to be dispatched where they are the most efficient remain in balance (e.g. through better use of weather forecasts) or entrance by new actors and technologies, such as generator available. All generators will benefit from increased transparency and legal will be exposed to financial risks. battery storage.

certainty on redispatch and curtailment compensation. Suppliers Suppliers are not directly affected. Balancing responsible parties, including suppliers, traders and Most likely not affected.

generators currently subject to balancing responsibility are not directly impacted.

Power exchanges Power exchanges could benefit from the increased market liquidity particularly for Power exchanges could benefit from the increased market liquidity Most likely not affected. short-term products which results from market-based curtailment and redispatch. particularly for short-term products which results from balancing

responsibility of RES E.

Aggregators Aggregators are likely to benefit in particular by offering market-based resources to be Aggregators are likely to benefit in particular by offering to small Aggregators are likely to benefit from a more level used by TSOs in redispatch or curtailment. generators services to fulfil their balancing responsibility. playing field and get access to additional remuneration streams.

End consumers End consumers are not directly affected. End consumers are not directly affected. End consumers are not directly affected.

266 Annex III: Who is affected by the initiative and how

Table 2. Persons affected by measure for problem Area I, Option 1(b) (Strengthening short-term markets)

Affected party Measure

2.1. Reserves sizing and procurement 2.2. Removing distortions for liquid short-term markets 2.3. Improving the coordination of Transmission System Operation

Member States Member State authorities define the country's overall Member States authorities generally play a limited direct role in the Member States authorities will be impacted if they are responsible for policy regarding energy mix and power grid investments. operation of intraday markets. They will, however be impacted if they implementing/enforcing/monitoring the requirements. This topic is likely to have are responsible for implementing/enforcing requirements. a particularly political angle, as Member States may not be willing to entrust ROCs with decision-making powers under the assumption that security of supply is a national responsibility (although based on the TFEU, it constitutes a shared responsibility between the EU and MS).

National NRAs approve the methodology for sizing and NRAs are responsible for regulatory oversight of intraday markets, NRAs of each of the regions where a ROC is established would be required to regulatory procurement of balancing reserves. They are also including as part of the implementation of the CACM Guideline, carry out the regional oversight of the concerned ROC. This would include authorities responsible for any impact on TSOs' tariffs and how crosswhere they are responsible for approving a number of methodology competences at least equivalent to those established for NRAs in the Third

(NRAs) border infrastructure is allocated. developed by TSOs and power exchanges. They will, therefore, be Energy Package. affected by changes in so far as it could alter the basis for their It may be necessary to entrust ACER with the EU-wide oversight of ROCs. It regulatory decisions. However, the direct impact on NRAs is would be necessary to set out a framework for the interaction between the anticipated to be relatively limited. regional groupings of NRAs and ACER.

Transmission TSOs analyse system's state and propose the methodology TSOs are heavily involved in the operation of intraday markets, National TSOs would be complemented by ROCs performing functions of

System for sizing and procurement of balancing reserves in their notably in determining the cross-border capacity made available to the regional relevance, whilst real time operation functions would be left solely in the

Operators control areas. market, and in using the results for operation of the system. They are hands of national TSOs.

(TSOs) Shifting responsibilities for sizing and procurement of therefore likely to be significantly impacted by any changes. ROCs could potentially be entrusted with certain decision making responsibilities balancing reserves at regional level implies a need for for a limited number of operational functions, whilst TSOs would retain their strong governance at regional level. responsibility as regards all other functions for which they are currently Existing physical constraints would still need to be taken responsible at national level. It may be necessary to entrust additional tasks to into account in the regional procurement platform. ENTSO-E related to the cooperation and coordination between ROCs.

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 Generators, as Balancing Service Providers, would have Generators will be affected by any changes in wholesale prices they Generators could benefit from a more secure power system and a more efficient additional opportunity to participate in the balancing receive for their energy on the intraday market. More efficient price market leading to increased market opportunities.

market even though significant operational impact might signals, and more potential for trading, will open up the market to increase due to the procurement frequency. Such smaller generators, particularly renewable. framework would, however, allow the participation of renewable energy sources in the balancing market potentially leading to a sharp decrease of balancing reserve cost.

Aggregators Smaller products and time units will give aggregators Increased price fluctuations will give aggregators more opportunities Limited impact on aggregators. more access to intraday markets. to operate, thereby helping to ensure that demand meets supply at any

point in time. Suppliers Regional procurement of reserves would lead to regional Suppliers will be affected insofar as they are the ones who buy power Limited impact on suppliers.

settlement of imbalances; therefore allowing for increase on the wholesale market. Any changes in intraday clearing prices will competition of suppliers across borders. 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 In case an optimisation process for the allocation of Power exchanges will be the most affected by any changes to intraday Limited impact on power exchanges. It is expected that they could benefit power exchanges transmission capacity between energy and balancing arrangements, as they are the ones who operate the platforms on which exchanges as the optimisation of market-related functions such as capacity

markets has to developed, day-ahead market coupling energy is traded in the intraday timeframe. They will therefore have to calculation would entail more liquidity in the markets that could be exchanged. algorithm currently operates by power exchanges might be adapt systems and process to meet new requirements.

267 Annex III: Who is affected by the initiative and how Affected party Measure

2.1. Reserves sizing and procurement 2.2. Removing distortions for liquid short-term markets 2.3. Improving the coordination of Transmission System Operation

impacted and solution will have to be found on sharing transmission capacity in an optimal way for the markets preceding the balancing market.

End consumers End consumers will be able to participate in balancing End consumers will be affected insofar as changes to the wholesale Regional TSO cooperation through the creation of ROCs would benefit markets via demand response aggregators allowing for price are passed on to them in their retail price. consumers through improved security of supply (by minimising the risk of wide stronger supplier's competition at regional level. 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.

268 Annex III: Who is affected by the initiative and how

Table 3. Persons affected by measure for Problem Area I, Option 1(c) (Pulling demand response and distributed resourced into the market)

Affected party Measure

3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO 3.4. Improving the institutional framework remuneration

Member States Those 17 Member States that roll out smart meters The competent ministries in each Member State who The competent ministries in each Member State who MS authorities will be in charge of national will not be affected by the new provisions on smart will be involved in the transposition of the relevant will be involved in the transposition of the relevant implementation of the revised Third Package. meters, apart from the obligation to comply with the EU legislation and monitor the implementation and EU legislation and monitor the implementation and

recommended functionalities, which may need to effectiveness of the measures under the preferred effectiveness of the measures under the preferred transpose into national legislation. Similarly for option. option. those two Member States that opted for partial rollout 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.

National Additional administrative impact may be created for As DSOs are regulated entities is expected that NRAs According to the Electricity Directive NRAs have the Their role, powers and responsibilities will be regulatory the NRAs for enforcing actions regarding the will have the main role of ensuring the effective main role in fixing or approving network tariffs or further clarified, especially as regards issues authorities consumer entitlement to request a fully functional application of measures. NRAs will be mostly their methodologies. The overall aim is to move which are relevant at regional/EU level. This

(NRAs) smart meter. This includes assessing the costs to be involved in the application of the measures and in towards more sophisticated network tariff will affect the way NRAs have cooperated at borne by the consumer, and overseeing the process designing the necessary rules for the practical methodologies. To this end, some NRAs might have regional and EU-level, including within of deployment. At the same time, improved implementation. As the measures under the preferred to modify the existing methodologies for distribution ACER, in order to enhance the collaboration consumer engagement thanks to smart metering, option are closely linked to a suitable remuneration tariffs. The introduction of smarter regulatory between NRAs and ACER.

would make it easier for NRAs to ensure proper methodology, NRAs will also probably have to frameworks will require the availability of the In the context of clarifying the respective roles functioning of the national (retail) energy markets. modify existing schemes. This will require the necessary human, technical and financial resources. of NRAs and ACER, some of the powers and Already under the existing legislation NRAs are availability of the necessary human, technical and responsibilities currently conferred to NRAs obliged to encourage demand side resources to financial resources. may be shifted to ACER. 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.

Agency for the Apart from the minor changes necessary to ensure ACER will be affected to the extent which will be ACER will be affected to the extent which will be Its role, powers and responsibilities will be cooperation of effective market monitoring in the changed market called to oversight the activities of EU DSO entity called to oversight the activities of EU DSO entity further enhanced in order to ensure that ACER energy context, ACER will not be affected by changes in and its involvement in relevant network codes or and its involvement in network codes or guidelines can continue fulfilling its role of supporting regulators unlocking demand side response.. guidelines. on network tariffs. NRAs in exercising their functions at EU level

(ACER) 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

269 Annex III: Who is affected by the initiative and how Affected party Measure

3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO 3.4. Improving the institutional framework remuneration

ACER, to ensure that it can carry out an EU- level oversight. ACER's role will be affected by the changes envisaged for the process of development of Commission implementing regulations in the form of network codes and guidelines.

Transmission A greater roll-out of smart meters allows TSOs to TSOs will be involved as more coordination with TSOs will not be affected by changes in distribution Some of the transparency obligations imposed

System better calculate settlements and balancing penalties DSOs will be required. TSOs will have to allocate the tariffs. on ENTSO-E as well as some of the

Operators as the consumption figures can be based on real necessary human and technical resources in order to governance rules applying to this association

(TSOs) consumption data and not only on profiles. achieve such coordination. will indirectly affect TSOs.

TSOs are affected by opening markets for Some of the proposed rules (e.g. co-financing aggregated loads and demand response. Those of ACER by contributions from market effects are dealt with in the Impact Assessment on participants) might directly impact on TSOs. 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.

European ENTSO-E will not be affected by changes in ENTSO-E will have to cooperate with the EU DSO ENTSO-E will not be affected by changes in ENTSO-E's mandate will be mainly clarified, network of unlocking demand response. entity on issues which are relevant to both distribution tariffs. whilst ensuring that its added value of transmission transmission and distribution networks. providing technical expertise is preserved. system operators Transparency of ENTSO-E will be further

(ENTSOs) improved.

The role of ENTSO-E will be affected by the changes envisaged for the process of development of Commission implementing regulations in the form of network codes and guidelines.

Distribution In most Member States, DSOs are responsible for DSOs will be directly affected by the possible It is expected that the envisaged measures under the DSOs will be able to participate more actively

System organising the installation of smart meters. The measures under the preferred option as they will have preferred option will positively affect DSOs as they as a result of the changes envisaged for the

Operators additional costs to be determined by the NRAs can to have in place the necessary human and technical aim to a more efficient utilisation of the distribution process of development of Commission

(DSOs) however be charged to the users. resources in order to implement the envisaged system and the incentivisation of DSOs towards more implementing regulations in the form of

DSOs also benefit from access to real time data measures. Additional personnel or infrastructure optimal development and operation of their grids. network codes and guidelines. coming from smart metering. It supports them in might be necessary. However, DSOs will use More advanced tariff schemes may require the their work on monitoring and controlling the flexibility solutions in order to increase efficiencies, availability and monitoring of detailed data (financial network, improving its reliability and power quality, only where benefits will outweigh additional costs. and technical) and the achievement of specific and its overall effectiveness, particularly in the targets. Any additional administrative costs should be presence of distributed generation. This ultimately offset by the expected benefits. 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

270 Annex III: Who is affected by the initiative and how Affected party Measure

3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO 3.4. Improving the institutional framework remuneration

indirectly benefit from a better uptake of demand response as the reduction in peaks it will reduce the need to invest in distribution networks.

Generators Demand response is designed to reduce peak Generators will not be affected by the measures under The envisaged measures aim to the overall reduction Generators will be able to participate more demand and thereby effectively replace marginal the preferred option. of network costs through the incentivisation of DSOs actively as a result of the changes envisaged power plants and reduce electricity prices at the to raise efficiencies, which will have an overall for the process of development of Commission wholesale market. As such generators are likely to positive impact to system users. The envisaged implementing regulations in the form of face reduced turnover from lower peak prices and measures also aim to a fair allocation of costs among network codes and guidelines.

from operating reserve capacities. different system users. Therefore, to the extent to Generators are not likely to be effected by an which the envisaged measures will incite changes in accelerated smart meter roll out. existing tariffs, generators or other system users may be affected from any new tariffs which will result to reallocation of costs.

Suppliers Smart meters can have a direct impact on suppliers, Suppliers will not be affected as the envisaged It is not expected that the envisaged measures will Suppliers will be able to participate more as they enable consumers to easily switch. measures will not affect their normal business. affect the suppliers. actively as a result of the changes envisaged Furthermore, there is one Member State where for the process of development of Commission suppliers are responsible for the roll-out. Moreover, implementing regulations in the form of smart metering allows suppliers to offer dynamic network codes and guidelines.

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.

Power exchanges No impact expected No impact expected No impact expected Power exchanges will be subject to an enhanced regulatory oversight at EU level exercised by ACER and NRAs.

Power exchanges will be able to participate more actively as a result of the changes envisaged for the process of development of Commission implementing regulations in the

271 Annex III: Who is affected by the initiative and how Affected party Measure

3.1. Unlocking demand side response 3.2. Distribution networks 3.3. Distribution network tariffs and DSO 3.4. Improving the institutional framework remuneration

form of network codes and guidelines.

Aggregators (and Aggregators are likely to benefit from an accelerated Aggregators will be positively affected as DSOs will Insofar as distribution tariffs incentivise grid users to Aggregators and other new market entrants other new roll out of smart meters as this technology facilitates request their services in order to use flexibility for use the network more efficiently, aggregators will not will be able to participate more actively as a market entrants) market access for demand service providers and managing congestion in their networks. be called upon as much to help to manage network result of the changes envisaged for the process

aggregators. Equally all measures aimed at removing congestion.. of development of Commission implementing market barriers and increasing competition in the regulations in the form of network codes and retail market will immediately facilitate market guidelines access for aggregators and new energy service providers and hence opens new business opportunities for them.

End consumers End consumers will get the right to request smart Use of flexibility from DSOs will result to lower The envisaged measures aim to the overall reduction Consumers will be able to benefit from meters and have access to dynamic electricity network costs. This reduction will be reflected in of network costs through the incentivisation of DSOs enhanced transparency and in general from pricing contracts which clearly gives puts them in a distribution tariffs and the final electricity bill of the to raise efficiencies, which will have an overall well-functioning energy markets.

position to become active market participants. consumer. positive impact to system users. The measures also Furthermore, provision of accurate and reliable data aim to a fair allocation of costs among different flows due to smart metering would enable easier and system users. Therefore, to the extent to which the quicker switch between suppliers, access to choices, envisaged measures will incite changes in existing smart home solutions and innovative automation tariffs, consumers or other system users may be services, and can also lead to energy savings. affected from any new tariffs which will result to Consumers will equally benefit from more reallocation of costs. 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.

272 Annex III: Who is affected by the initiative and how

Table 4. Persons affected by measure Problem Area II, Option 1 (Improved energy market without CMs)

Affected party Measure 4.1. Removing price caps 4.2. Improving locational price signals 4.3. Minimise investment and dispatch 4.4. Congestion income spending to increase crossdistortions due to transmission tariff border capacity structures

Member States Member States authorities will be impacted if they Member States authorities will be impacted if they are Member States authorities will be impacted if Member States authorities will be impacted if they are are responsible for responsible for implementing/enforcing/monitoring the they are responsible for responsible for implementing/enforcing/monitoring the implementing/enforcing/monitoring the requirements. This topic is likely to have a particularly implementing/enforcing/monitoring the requirements.

requirements. political angle, as splitting price zones within a Member requirements. State will result in different wholesale electricity in that

Member State depending on location (although not necessarily retail prices).

National NRAs will be impacted if they are responsible for Member States authorities will be impacted if they are NRAs play a significant role in monitoring, NRAs are currently responsible for reviewing the use regulatory implementing/enforcing/monitoring the responsible for implementing/enforcing/monitoring the authorising, etc. tariffs and connection of congestion income, and for authorising it to be spent authorities requirements. requirements. charges. Any change would impact on how on the reduction of tariffs. They will be affected by

(NRAs) they do this. Option 2 and 3 as they no longer need to authorise it to be spent on the reduction of tariffs. Option 1 could require them to make a more them to make a more thorough assessment.

ACER will be affected by changes to monitoring and transparency requirements and the requirement on them to develop harmonised rules.

Transmission There will be limited impact on TSOs. TSOs will be affected as it will likely mean they hold Changes would have limited impact on TSOs It will change how transmission system operators are

System and operate networks over more than one price zone. It themselves, as proposals are not generally able to use congestion income. Options 1-3 could lead

Operators will also change those transmission lines that looking at how TSOs are remunerated, but to more investment activity of the TSO.

(TSOs) accumulate revenue from congestion. rather how the money is collected.

Generators Increased price variability will impact the revenue Different price zones will change the prices that Changes would most affect generators – If Option 1, 2 and 3 lead to more investment in generators will see from the energy market – they generators receive depending on their location. lower connection charges or tariffs (where networks, this would impact generators by delivering will likely see higher prices for short periods of they are applied to generators) would have a more cross-border competition and present further time, which will incentivise flexible generation. positive impact on their revenues. trading opportunities to sell energy by an increases in the liquidity of cross-border markets.

273 Annex III: Who is affected by the initiative and how Affected party Measure

4.1. Removing price caps 4.2. Improving locational price signals 4.3. Minimise investment and dispatch 4.4. Congestion income spending to increase crossdistortions due to transmission tariff border capacity

structures

Suppliers Increased price variability will impact the price Different price zones will change the prices that Limited impact on suppliers. If Option 1, 2 and 3 lead to more investment in paid by suppliers - – they will likely see higher suppliers pay depending on their location. networks, this would impact generators by delivering prices for short periods of time. more cross-border competition and present further trading opportunities to buy energy by an increase in the liquidity of cross-border markets.

Power Power exchanges will be required to implement the Different price zone will change the practices of power Limited impact on power exchanges. If Option 1, 2 and 3 lead to more investment in exchanges requirements, which could require changes to exchanges – currently they operate based on MS-level networks, this would impact power exchanges if it

systems and practices. markets (in general) – they would need to differential leads to greater cross-border trade on their platforms. markets based on different price boundaries.

End End consumers will be affected insofar as changes Different price zones could affect end-consumers End consumers could be affected if more End consumers may be affected by any reduction in the consumers to the wholesale price are passed on to them in their depending on their location. However, possibilities exist tariffs were charged on load, as opposed to amount that can be offset against tariffs. However, this

retail price. However, more variable prices will not to retail MS-level retail prices, production. However, overall the impact is may be outweighed by the positive effect of more necessarily be felt by end-consumers as they may likely to be similar as the overall cost basis cross-border capacity being available, and the benefit be hedged (particularly household) against this would not changing. this has on competition and energy prices. volatility in their retail contracts.

274 Annex III: Who is affected by the initiative and how

Table 5. Persons affected by measures of Problem Area II, Option 2 (Improved energy market, CMs based on an EU-wide adequacy assessment) and

Option 3 (Improved energy market, CMs based on an EU-wide adequacy assessment, plus cross-border participation

Affected party Measure

5.1. Improved generation adequacy methodology 5.2. Cross-border operation of capacity mechanisms

Member States Member States would be better informed about the likely development of security of supply indicators Each Member State would not need to design a separate individual solution – and this would potentially and would have to exclusively rely on the EU-wide generation adequacy assessment carried out by reduce the need for bilateral negotiations between TSOs.

ENTSO-E when arguing for CMs.

National regulatory NRAs/ ACER would be required to approve the methodology used by ENTSO-E for the generation NRAs/ ACER would be required to set the obligations and penalties for non-availability for both authorities (NRAs) adequacy methodology and potentially endorse the assessment. participating generation/ demand resources and cross-border transmission infrastructure.

Transmission System TSOs would be obliged to provide national raw data to ENTSO-E which will be used in the EU-wide ENTSO-E would be required to establish an appropriate methodology for calculating suitable capacity

Operators (TSOs) generation adequacy assessment. values up to which cross-border participation would be possible.

Based on the ENTSO-E methodology, TSOs would be required to calculate the capacity values for each of their borders. They might potentially be penalized for non-availability of transmission infrastructure. TSOs would be required to check effective availability of participating resources. ENTSO-E may also be required to establish common rules for crediting foreign capacity resources for the purpose of participation in CMs reflecting the likely availability of resources in each country/zone.

Generators ENTSO-E would also have to provide for an updated methodology with probabilistic calculations, Foreign capacity providers would participate directly into a national capacity auction, with availability appropriate coverage of interdependencies, availability of RES and demand side flexibility and rather than delivery obligations imposed on the foreign capacity providers and the cross-border availability of cross-border infrastructure. infrastructure.

Foreign capacity providers/ interconnectors would be remunerated for the security of supply benefits that they deliver to the CM zone and would receive penalties for non-availability.

Suppliers ENTSO-E would be required to carry out an EU-wide or regional system adequacy assessment based Limited impact on suppliers on national raw data provided by TSOs (as opposed to a compilation of national assessments).

Aggregators With the updated methodology provided by ENTSO-E, intermittent RES generators/ demand-side Just like generators they shall be able to participate in cross-border CMs. flexibility would be less likely to be excluded from contributing to generation adequacy.

Power exchanges Limited impact on suppliers Limited impact on power exchanges

End consumers Limited impact on aggregators Explicit cross-border participation in CMs would preserve the properties of market coupling and ensure that the distortions of uncoordinated national mechanisms are corrected and the internal market is able to deliver the benefits to consumers.

275 Annex III: Who is affected by the initiative and how

Table 6. Persons affected by measures for Problem Area III

Affected party Measure

Member States Member States (i.e. responsible ministries) would bear the main responsibility of preparing Risk Preparedness Plans and coordinating relevant parts with other

Member States from their region, including ex-ante agreements on assistance during (simultaneous) crisis and financial compensation. Member States would designate a ministry or the NRA as 'competent authority' as responsible body for preparing the Risk Preparedness Plan and for cross-border coordination in crisis. As members of an empowered Electricity Coordination Group they would consult and coordinate Plans. The above described responsibilities might involve an increased administrative impact. However, most of the tasks are already carried out in a purely national context and there might also be benefits from exploiting synergies of improved cooperation. In addition, existing national reporting obligations would be reduced (e.g. repealing the obligation of Article 4 of Electricity Directive "Monitoring security of supply").

National regulatory NRAs could possibly fulfil certain tasks as part of the Risk Preparedness Plan of their Member State. authorities (NRAs) Furthermore they might be appointed as 'competent authority' by Member States. In this case, they would be responsible for preparing the Risk Preparedness Plan

and for cross-border coordination during crisis, possibly requiring additional resources. Transmission System ENTSO-E would be responsible for identification of crisis scenarios and risk assessment in a regional context. A common methodology for short-term assessments Operators (TSOs) (ENTSO-E Seasonal Outlooks and the week-ahead assessments of the RSCs) should be developed by ENTSO-E.

This might require additional resources within ENTSO-E and within the RSCs, in case that ENTSO-E delegates all or part of these tasks to them. However, additional costs would be limited as some of these tasks are already carried out today. Giving these bodies a clear mandate, it would however significantly improve cross-border coordination.

Generators Generation companies and other market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management and the prevention of unjustified market intervention.

Suppliers Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management and the prevention of unjustified market intervention.

Aggregators Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management and the prevention of unjustified market intervention.

Power exchanges Market operators would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management and the prevention of unjustified market intervention.

End consumers As described above the impacts of blackouts on industry and society proved to be severe. Consequently, end consumers benefit extensively from improved risk preparedness as it would help to prevent future blackouts more effectively.

276 Annex III: Who is affected by the initiative and how

Table 7.a Persons affected by measure for Problem Area IV

Affected party Measure

7.1. Monitoring energy poverty 7.2. Options for phasing out regulated prices 7.3. Creating a level playing field for access to data

Member States Option 1 leads to an improved framework to measure energy poverty. Those Member States still practicing some form of price regulation will The competent ministries and authorities who will be

Member States will have a better understanding of energy poverty as a have to make the necessary legislative and market changes in order to involved in the transposition of the relevant EU legislation result of a clearer conceptual framework (through the common ensure a smooth and effective phase out. and will monitor the implementation and effectiveness of understanding of energy poverty) and better information on the level of the measures under the preferred option. energy poverty (measuring energy poverty). Ultimately, this will contribute to better identification and targeted public policies to alleviate energy poverty.

National regulatory NRAs will need to monitor and report to the European Commission and In most countries with price regulation, NRAs are the bodies The envisaged measures will partly affect the NRAs as most authorities (NRAs) ACER the number of disconnections. According to ACER Market responsible for setting the level of regulated prices for a defined probably will have a role in the implementation of the

Monitoring Report, only 16 Member States met this requirement. regulatory period. In few cases NRAs are only giving their opinion on measures at national level. Other authorities such as data regulated prices set by the government. Phasing-out regulated prices protection authorities may be involved in the would remove these responsibilities of the NRAs therefore reducing implementation of the envisaged measures at national level. administrative costs and resource needs. However new tasks for the NRAs will have to monitor the data handling procedures as NRAs might be defined by Member States in the follow-up of the price part of the retail market functioning. The involvement of deregulation process such as monitoring the level of market prices with NRAs is expected to be higher in Member States where the possibility to intervene ex post in the price setting in case of market smart metering systems are deployed.

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.

Transmission The preferred option would not directly affect TSOs. The preferred option would not directly affect TSOs. TSOs might be affected in terms of costs in cases where

System Operators Member States will decide that they are responsible for the

(TSOs) operation of the data-hub. However, the envisaged measures do not impose an obligation to Member States regarding the data management model and the party responsible for acting as a data-hub. The measures under the preferred option will benefit TSOs and other operators as the will allow them, under specific terms, to have access to aggregated information which will be useful for network planning and operation.

Distribution System The preferred option would not directly affect DSOs. The preferred option would not directly affect DSOs. In the large majority of Member States DSOs will be

Operators (DSOs) 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.

277 Annex III: Who is affected by the initiative and how Affected party Measure

7.1. Monitoring energy poverty 7.2. Options for phasing out regulated prices 7.3. Creating a level playing field for access to data

Generators The preferred option would not directly affect generators. In countries where artificially low regulated end-user prices are backed Generators will not be affected under the preferred option. up by generation deliveries at non cost-reflective level agreed by longterm

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.

Suppliers The preferred option would not directly affect suppliers. Alternative (non-regulated) suppliers would benefit from the The availability of consumption data under non

However, should the improved monitoring of energy poverty lead to deregulation of prices by increased possibilities to compete on the price discriminatory terms and interoperability of data formats increased action to tackle the problem by Member States, then the costs of and therefore to gain more market share. This is particularly true for will have positive effects on suppliers and other retailers. these measures may be borne by suppliers. Depending on each Member countries where regulated prices set at non cost-reflective levels The aim of the measures under the preferred option is to States, these costs may then be recovered as network charges, passed on to prevent alternative suppliers from contesting the regulated offer. For bring down the administrative costs for the various retail consumers or taken against energy providers overall benefits. the regulated suppliers (usually former incumbents) the removal of service providers including suppliers. Preventative measures, such as debt management or providing additional price regulation would lead to increased operational costs related to the information on where to find support, represent an additional cost to implementation of the transition from the regulated offer to market energy retailers in those Member States where these measures are not yet based offer for its customer base. Moreover, regulated suppliers are in place. A moratorium of disconnection will reduce energy retailers' likely to lose significant market shares if customers will switch to revenue as energy will be supplied free of charge. However, such costs will competitive offers of alternative suppliers. to some extent be mitigated by lower numbers of bad debtors in the long run.

Power exchanges The preferred option would not directly affect power exchanges. The preferred option would not directly affect power exchanges. -

However, power exchanges could benefit from increased liquidity due to better functioning competition on retail and wholesale markets following price deregulation.

Aggregators The preferred option would not directly affect aggregators. Removing price regulation would stimulate the development of energy In the preferred option aggregators and other retail service services which create market opportunities for aggregators. providers will have equal access to data as suppliers in a transparent and non-discriminatory way. This will allow aggregators to develop new services for consumers and will facilitate their entrance in the market.

Consumers Consumers in a situation of energy poverty or at risk of energy poverty will Phase-out of regulated prices for end customers would stimulate The envisaged measures under the preferred option aim to be positively impacted by the preferred option. A clearer understanding competition on retail markets which translates for customers into more support the development of a competitive retail market. It is and measuring of energy poverty will have positive impacts on Member choice and better offers in terms of price and service quality. Customers expected that the measures will bring developments which States efforts to tackle energy poverty.. would be able to better manage their own energy consumption by using will affect positively consumers through the availability of energy services and technologies such as demand response, selfwider choice of services, focusing on demand response and generation, and self-consumption. However, notably in countries where energy efficiency.

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.

278 Annex III: Who is affected by the initiative and how

Table 7.b Persons affected by measures for Problem Area IV

Affected party Measure

7.4. Facilitating supplier switching 7.5. Comparison Tools 7.6. Improving Billing Information

Member States The preferred option may need to be transposed into national The preferred option will need to be transposed into national law, resulting in The preferred option will need to be transposed into national law, resulting in administrative impacts. administrative impacts. law, resulting in modest implementation costs.

Some Member States (e.g. BE, IT) have eliminated exit fees However, some 13 Member States already have at least one independent CT run by a already, the latter reporting increased consumer trust as a government or government-funded body. As these are free of conflicts of interest, we result. Others with a relatively high preponderance of exit fees can assume they are likely to meet the accreditation criteria. (NL, IE, SI) are likely to be more reserved, particularly in light of the fact that they may have relatively competitive markets already.

National The preferred option would likely lead to additional The preferred option would likely lead to additional stakeholder engagement and The preferred option would likely lead to additional regulatory stakeholder engagement and enforcement actions, resulting in enforcement actions, resulting in increased administrative impacts. However, this stakeholder engagement and enforcement actions, resulting authorities increased administrative impacts to NRAs. would not necessarily be a role for the NRAs as an independent body might be assigned in increased administrative impacts to NRAs.

(NRAs) However, any clarification and simplification of EU legal the task (e.g. GB where an independent auditor audits the CT). However, improved billing clarity would make it easier for provisions may lead to greater ease of enforcement, and However, any strengthening of EU legal provisions should lead to a reduction in the NRAs to ensure the proper functioning of national (retail) commensurate savings. number of consumer complaints. energy markets they are charged with.

In addition, improved consumer engagement would make it In addition, improved consumer engagement would make it easier for NRAs to ensure easier for NRAs to ensure the proper functioning of national the proper functioning of national (retail) energy markets. (retail) energy markets they are charged with.

Transmission Not affected. Not affected. Not affected.

System

Operators

(TSOs)

Distribution Any change in consumer switching behaviour resulting from Insofar as the measures lead to increased switching, this will result in increased Not affected.

System the preferred option would be reflected in switching administrative costs to DSOs. However, these costs will be passed through to

Operators operations, and their associated administrative impacts. consumers through network charges.

(DSOs) However, as DSOs are regulated monopolies, these costs (or savings, if switching decreases) will eventually be passed through to end consumers.

Suppliers Most suppliers are unlikely to welcome measures to further Industry associations (EURELECTRIC and Eurogas) have publicly supported Most suppliers are unlikely to welcome EU legislation restrict switching-related fees, as these limit their ability to consumer access to neutral and reliable comparison tools. In particular, increased addressing the content or format of energy bills, as this limit tailor tariffs to different consumers. reliability and impartiality in comparison tools may encourage new market entrants, their ability to tailor bills to different consumers.

Some may also financially benefit from the increased thereby improving the likelihood of a level playing field. Some may also benefit from the low awareness amongst 'stickiness' switching-related fees create amongst their However, some suppliers are unlikely to welcome measures to certify comparison tools their consumer base of information that may be contained in consumer base. as this may have an impact on how and where their offers are published, and their bills, such as switching information, consumer rights, and In addition, any change in consumer switching behaviour ability to tailor tariffs to different consumers (in terms of cost, etc.). consumption levels. resulting from the policy options would be reflected in Some may also lose out financially if they are no longer able to influence the ranking of switching operations, and the associated administrative search results to promote certain offers; this applies both to energy suppliers and to CT impacts to suppliers. providers. Insofar as the measures lead to increased switching, this will result in increased administrative costs to suppliers.

Comparison tool Not affected. More stringent requirements in terms of reliability and impartiality may increase their Not affected. providers 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.

279 Annex III: Who is affected by the initiative and how Affected party Measure

7.4. Facilitating supplier switching 7.5. Comparison Tools 7.6. Improving Billing Information

End consumers Some end consumers would benefit from contract exit fees The preferred option would benefit many consumers, as the offers displayed would be Some end consumers would benefit from contract exit fees if

(permitted in the preferred option) if such fees mean that more representative of the best ones (e.g. those offering the best value for money and such fees mean that suppliers are able to offer them lower suppliers are able to offer them lower prices or better levels of the best service levels) available on the market. Asymmetric access to information prices or better levels of service. service. would be reduced. Consumers would have greater trust in their ability to select the best However, all consumers are likely to benefit from a However, all consumers are likely to benefit from a complete offer through improvements in levels of service, and they would be better protected. complete ban on other switching-related fees, as well as ban on other switching-related fees (as per the preferred They will be better able to make informed choices, and to benefit from the internal greater transparency around any switching-related fees they option), as well as greater transparency around any switchingmarket. may be charged. related fees they may be charged. More generally, the majority of consumers would benefit More generally, the majority of consumers would benefit from further restricting the use of switching-related charges. from further restricting the use of switching-related charges. Such charges are a financial barrier to accessing better deals, Such charges are a financial barrier to accessing better deals, disproportionately affect decision making, foster uncertainty disproportionately affect decision making, foster uncertainty on the benefits of switching, and reduce retail-level on the benefits of switching, and reduce retail-level competition. competition.

280 Annex III: Who is affected by the initiative and how

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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 http://ec.europa.eu/dgs/energy/tenders/doc/2014/2014s_152_272370_specifications.pdf

17 Once operational, the envisaged link is expect to be the following:

https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis

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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 intertemporal non-linear optimisation; non-linear cost supply functions are assumed for all resources used by power plants for operation and investment, including for fuel prices

(relating fuel prices non-linearly with available supply volumes) and for plant development sites (relating site-specific costs non-linearly with potential sites by

Member State); the non-linear cost-potential relationships are relevant for RES E power possibilities but also for nuclear and CCS.

The simulation of plant dispatching considers typical load profile days and system reliability constraints such as ramping and capacity reserve requirements. Flow-based optimisation across interconnections is simulated by considering a system with a single bus by country and with linearized DC interconnections. Capacity expansion decisions depend on inter-temporal system-wide economics assuming no uncertainties and perfect foresight.

The optimisation of system expansion and operation and the balancing of demand and supply are performed simultaneously across the EU internal market assuming flow-based allocation of interconnecting capacities. The outcome of the optimisation is influenced by policy interventions and constraints, such as the carbon prices (which vary endogenously

19 http://www.e3mlab.National Technical University of Athens.gr/e3mlab/ .

20 https://ec.europa.eu/energy/sites/ener/files/documents/sec_2011_1569_2.pdf '.

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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 phaseout, 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 wellfunctioning 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 intracountry 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 uptime, 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 coordinatedsynchronized 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.

289

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

290

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;

292

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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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. Hydroreservoirs 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; nondispatchable 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:

𝑆𝐵 −𝐑𝐀𝐓𝐄

𝒎

𝒑 ∙� 𝐒𝐔𝐏𝐏

𝑝 = 𝑀𝐶 𝑝 + 𝐶𝐸𝐼𝐿 𝑚 ∗ e 𝐃𝐄𝐌𝐃

−1�

𝒎

P is the plant identifier, 𝑀 the merit order type, 𝑀𝐶 the Marginal cost, 𝑆𝑈𝑃𝑃 the total supply (capacity) of merit order type, 𝐷𝐸𝑀𝐷 the hourly demand specific to merit order type, 𝐶𝐸𝐼𝐿 the price ceiling for merit order type, 𝑅𝐴𝑇𝐸 the (inverse) rate of mark-up and

𝑆𝐵 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 midload 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 postcalculation 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 costeffective 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 costeffective 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 .

295

• - 

  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)

Share in % diff % diff 2000 2015 2030 total for 2015- 2030-

2030 (%) 2010 2015

Electricity consumption (in TWh) 3,029.0 3,271.8 3,525.6 8% 8%

Final energy demand 2,530.7 2,802.4 3,081.3 11% 10%

Industry 1,061.1 1,001.4 1,054.8 30% -6% 5%

Households 713.8 833.6 899.7 26% 17% 8%

Tertiary 683.5 899.3 982.2 28% 32% 9%

Transport 72.3 68.2 144.6 4% -6% 112%

Energy branch 281.7 262.6 231.2 7% -7% -12%

Transmission and distribution losses 216.2 206.7 213.1 6% -4% 3%

Net Installed Power Capacity (in GW e ) 683.5 965.6 1,131.0 41% 17%

Nuclear energy 139.6 120.8 109.9 10% -13% -9%

Renewable energy 129.0 366.7 652.2 58% 184% 78%

Hydro (pumping excluded) 115.8 127.5 133.3 12% 10% 5%

Wind on-shore 12.7 130.6 246.1 22% - 88%

Wind off-shore 0.1 11.0 37.9 3% - 246%

Solar 0.2 97.4 233.8 21% - 140%

Biomass-waste fired 12.7 27.9 53.1 5% 121% 90%

Other renewables 0.8 1.1 2.1 0% 32% 86%

Thermal power 414.9 478.1 368.9 33% 15% -23%

Solids fired 194.5 176.6 99.4 9% -9% -44%

Oil fired 83.3 53.1 15.3 1% -36% -71%

Gas fired 123.8 219.6 200.1 18% 77% -9% Net Electricity generation by plant

type (in TWh) 2,844.0 3,090.0 3,396.7 9% 10%

Nuclear energy 893.9 825.7 738.4 22% -8% -11%

Renewable energy 374.5 736.2 1,372.8 40% 97% 86%

Hydro (pumping excluded) 351.6 357.7 375.1 11% 2% 5%

Wind on-shore 22.2 241.4 564.4 17% - 134%

Wind off-shore - 32.8 127.3 4% - 288%

Solar 0.1 103.8 303.6 9% - 193%

Biomass-waste fired 42.9 130.6 238.1 7% 204% 82%

Other renewables 5.0 7.1 9.7 0% 42% 37%

Thermal power 1,575.6 1,528.0 1,285.6 38% -3% -16%

Solids fired 866.3 780.3 448.6 13% -10% -43%

Oil fired 178.4 30.2 14.6 0% -83% -52%

Gas fired 483.4 580.4 576.8 17% 20% -1% Source: PRIMES

Baseline: Current Market Arrangements ('CMA')

The Market Design Initiative addresses four different Problem Areas. The first two, addressing market functioning and investments, share a common baseline which is highly dependent on the context (e.g. based on REF2016 or EUCO27). The other two Problem Areas, concerning risk preparedness and retail markets, are more independent of the overall context, as in each case the envisaged baseline and options can apply in either context (moreover the assessment tends to be mainly qualitative). Therefore the discussion on the baseline is meaningful mainly for the first two Problem Areas.

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Similar to the other 2016 Energy Union initiatives, EUCO27 was chosen as the starting point (i.e. context) of the baseline for the Market Design Initiative (so-called "Current

Market Arrangements" – CMA). The EUCO27 scenario is the most relevant to the objectives of the initiative, as it provides information on the investments needed and the power generation mix in a scenario in line with the EU's 2030 objectives.

As all analysis focuses on the power sector, all assumptions exogenous to the power sector were taken from the EUCO27 scenario. This also applied for the energy mix, the power generation capacities for each period, the fuel and carbon prices, electricity demand, technology costs etc. The main obstacle in further using the EUCO27 as a baseline for this impact assessment was that it assumes a perfectly competitive and wellfunctioning 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 marketcoupling 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 The same applies for CHP, when the main use of those plants is the production of heat/steam.

27 The CMs would not affect the merit order in problem area I, as the analysis assumes bidding based on marginal costs (not scarcity pricing, which is introduced in problem area II).

28 Once operational, the envisaged link is expect to be the following:

https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis

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The two versions of EUCO27 are in general quite close from an EU energy system perspective. Two differences can be found in 2030, one in the RES E shares and the other in CO2 prices, slightly affecting power generation capacities and production.

RES E overall share is in both cases 27%, with a differentiation in the sectoral contribution: in the preliminary version the share of RES E is at 48.4%, while being

47.3% in the final EUCO27 version. This was mainly driven by differences in off-shore wind deployment. There is more switching from coal to gas in the final version. This is translated to 2 p.p. increase of gas in the share of power gas generation, while solids decreased by 0.5 p.p. and RES E by 1.3 p.p.. The 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 Actually reserve procurement was not modelled for other non-EU28 Member States, as well as for Malta, Cyprus and Luxembourg.

30 "METIS Technical Note T04: Methodology for the integration of PRIMES scenarios into METIS",

Artelys (2016)

300

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.

301

• 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

BE DK FI FR IE NO SE UK

OCGT added capacity 5 2 4 6 1 4 3 19 (GW)

Source: METIS, Artelys Crystal Super Grid

METIS policy scenarios for the options of Problem Area I

This section provides information on the market design options that were modelled and assessed using METIS. Each scenario was run using the full capabilities of METIS. In fact certain aspects of METIS were further developed in order to be possible to better assess a number of the measures covered in the impact assessment.

Each scenario was intended to match the setup of one assessed option. For this purpose the options were first decomposed into a number of "fields", reflecting existing market distortions or design features that were addressed within each option. Following subsequent analysis, these fields were then narrowed down to the twelve presented in

Table 3 below. For each of these fields, two or three sub-options were considered across the different scenarios. The sub-options considered (entitled "a"/"'b"/"c") are identified on the right had columns of Table 3, while their description is provided in Table 4.

For all fields, sub-option "a" reflects current practices and existing market distortions, as well as the possible evolution of markets in the near future in the absence of new policies. The identification and methodology for the quantification of current practices

was supported by a study performed specifically for this purpose 33 .

32 - Regarding grid development and the interconnectors between countries, they are based on the ENTSO- E TYNDP, following the respective timelines. After the end of the TYNDP, expansions are based on known plans and the development of RES E.

33 "Electricity Market Functioning: Current Distortions, and How to Model their Removal", COWI

(2016).

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Table 3: Overview of MDI impact assessment Problem Area I scenarios as modelled by METIS (read in conjunction with Table 4)

MDI options

Action Field 0 1(a) 1(b) 1(c) 2

1 DR deployment a b b c c

2 RES E priority dispatch a b b b b

3 Biomass reserve procurement a b b b b

4 Coal/lignite unit commitment at intraday a b b b b

5 Balance responsibility a b b b b

6 Intraday coupling a a b b b

7 Time granularity for reserve sizing a a b b b

8 Reserve procurement methodology a a b b b

9 Joint/separate upward/downward reserve a a b b b

10 Use of NTC a a b b c

11 Reserve dimensioning and risk sharing a a b b c

12 PV, Wind and RoR reserve procurement a a a b b

Source: METIS

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Table 4: Overview of the sub-options for each measure modelled in METIS

Measure Topic Description of the options

Three levels of DR deployment (sub-options a, b and c, with increasing economic potential, based on COWI BAU and PO2

scenarios 34 ) were considered.

In sub-option "a" DR can considered only for countries where DR

1 DR deployment has currently access to the market and only for industrial resources based on BAU potentials. In sub-option "b" DR by industrial

resources appears in all countries based on BAU potentials. In suboption "c" all DR resources participate based on the potential of the PO2 scenario, adjusted to better match EUCO27 projections and the activation limits of DR potential.

Two options were considered:

• a. 

  Penalty factor for PV and Wind curtailment, priority

dispatch for Biomass

• b. 

  No penalty factor or priority dispatch for PV, Wind and

Biomass

2 RES E priority For sub-option "a", modelling RES E priority dispatch for wind and dispatch PV was performed via a penalty factor and not by explicit priority

dispatch. The reason was that there were a number of hours for certain Member States that if an explicit priority dispatch was enforced for all RES E, their power system collapsed (solution was infeasible). In reality this would most likely be addressed by the TSOs via the curtailment of RES E.

Two options for participation of biomass in reserve procurement:

3 Biomass reserve a. Biomass does not participate in FCR or FRR procurement b. Participation of Biomass (the absence of priority dispatch is

a prerequisite)

Two options for coal and lignite unit commitment: a. The day-ahead unit commitment decision (i.e. which plants

Coal/lignite unit are turned on or off) for coal and lignite power plants cannot 4 commitment at be refined during intraday, i.e. coal and lignite plants are

intraday treated as must-runs in intraday once scheduled in dayahead.

• b. 

  Coal and Lignite can re-optimise their commitment in intraday (subject to their technical constraints).

By making RES E producers financially responsible for the imbalances they are encouraged to improve their generation

forecasts. Two options were considered:

5 Balance a. H-2 forecasts were used for Wind and PV generation for responsibility reserve dimensioning and generation of imbalances.

• b. 

  H-1 forecasts were used for demand and PV, while 30 min forecasts were used for Wind, leading to lower imbalances and lower reserve requirements.

34 "Impact Assessment support Study on downstream flexibility, demand response and smart metering",

COWI (2016)

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Measure Topic Description of the options

Auctions for interconnections capacity can either be explicit,

captured in METIS as if assuming the flows are fixed in H-4, or

implicit, in which case flows can be updated in H-1. Two options

were considered:

6 Intraday coupling a. Auctions were mostly explicit, except in specific areas

based on current practices.

• b. 

  Auctions were implicit for all interconnections.

In any case, the reserve procured at day-ahead remained fixed during

intraday.

Two options were considered for aFRR reserve sizing: a. Fixed reserve size computed as 0.1% and 99.9% centiles of imbalance distribution over the year. While some Member States have different reserve sizes depending on demand

7 Time granularity for reserve sizing variation, this option assumes that the reserve size is

constant over the year for all Member States. b. Variable reserve size depending on the hour of the day and

wind energy generation. Size is computed with 0.1% and 99.9% centiles of imbalance conditional distribution

Reserve can be procured either day-ahead (which was modelled in METIS as a joint optimization of power and reserve hourly

Reserve procurement at day-ahead) or on a fixed basis per year (in which case 8 procurement the mean annual value of optimal reserve procurement is used). The

methodology options were:

• a. 

  Current practices
• b. 

  Day-ahead procurement

  Joint/separate Two options were considered for upwards and downwards reserve: 9 upward/downward a. Joint procurement according to current practices

reserve b. Being two separate products which can be procured independently

To model the process of interconnection allocation, three options were considered: a. National TSOs need to have a high security margin. For the scope of METIS, EUCO27 NTCs were reduced by 5%.

10 Use of NTC b. Collaboration between TSOs reduces the need for security margins. EuCo NTC values were used.

• c. 

  The introduction of a supranational entities will result in a further reduction of the security margins, leading to an increase by 5% of the EuCO NTCs.

To assess whether risk sharing can reduce the needs for national reserves, three options were considered. Reserve was sized using a probabilistic approach:

Reserve a. At national level 11 dimensioning and b. At regional level

risk sharing c. At EU level In order to ensure Member States can face similar security of supply

risks when less reserves can be procured (Options b. and c.), part of the interconnections' capacity was reserved for mutual assistance between Member States.

PV, Wind and RoR Two options: 12 reserve a. PV, Wind and Hydro RoR do not participate in FCR or FRR

procurement b. Participation of PV, Wind and Hydro RoR in FCR or FRR

Source: METIS

305

A more detailed description of the scenarios, how each option/measure was modelled and what were the identified relevant current practices, can be found in an explanatory

technical report 35 .

It is important to highlight that the scenarios under Problem Area I do not consider explicitly the possible existence of capacity mechanisms nor support schemes for RES E, focusing strictly on the wholesale market operation over the various time frames (dayahead, intraday, balancing). Nevertheless, certain assumptions (like priority dispatch for biomass) would make economic sense only in the case of existing economic subsidies.

Figure 6: Regions used for cooperation in reserve sizing and procurement

Source: METIS

35 "METIS Technical Note T05: METIS market module configuration for Study S12: Focus on day-ahead,

intraday and balancing markets", Artelys and THEMA Consulting (2016).

306

Figure 7: DR deployment in METIS for options a, b and c and current practices in DR participation in balancing markets

Source: METIS

PRIMES/IEM policy scenarios for the options of Problem Area II

PRIMES/IEM scenarios were setup very similarly to the METIS scenarios. As can be deduced from the description of the model, PRIMES/IEM puts more emphasis on the simulation of the bidding behaviour of market participants and the modelling of the grid, thus making it a better tool to capture the additional measures considered in Option 1 of Problem Area II (on top of Option 1(c) of Problem Area I), i.e. the removal of low price caps and the addition of locational price signals.

The consideration of market participant bidding behaviour and internal grid congestion, made it necessary to re-run the baseline (Option 0) also of Problem Area I under these new assumptions, in order to be used as the baseline of Problem Area II, with one caveat: similar to METIS, PRIMES/IEM cannot model CMs. On one hand this implies an underestimation of the benefits of the energy only market (Option 1) related to the more efficient operation of the system. On the other hand the modelled baseline could not be used for the comparison with Options 2 and 3. The approach followed to resolve this issue is described in the next section.

In order to enrich the analysis, and provide more comparability with the analysis performed for Problem Area I, it was decided to run also Options 1(a) (level playing field) and Option 1(b) (strengthening short-term markets) of Problem Area I. For the better understanding of the reader, the construction of these options is presented in a similar manner as for the METIS scenarios, highlighting that Option 0 corresponds to the

307

baseline and Option 1(c) to Option 1 of Problem Area II. Options 1(a) (level playing field) and 1(b) (strengthening short-term markets) do not correspond to any specific option of Problem Area II, but are presented for completeness. The identification and methodology for the quantification of current practices was supported by the same study used for the METIS modelling.

Table 5: Overview of MDI impact assessment Problem Area II scenarios as modelled by PRIMES/IEM (read in conjunction with Table 4)

Action Field MDI options 0 1(a) 1(b) 1

1 DR deployment a b b c 2 RES E priority dispatch a b c d 3 Day-ahead and intraday liquidity a b c c 4 Intraday coupling a b c c 5 Reserve dimensioning a b c c 6 Reserve procurement methodology a a b b 7 Use of NTC and bidding zones assumption a a b b 8 Price Caps a b b b

Source: PRIMES/IEM

Table 6: Overview of the sub-options for each measure modelled in METIS

Measure Topic Description of the options

Three levels of DR deployment (sub-options a, b and c, with increasing economic potential, based on COWI BAU and PO2 scenarios) were

1 DR deployment considered. Assumptions were similar to METIS. As load shifting and load reductions could be captured in PRIMES/IEM, DR was modelled also for the day-ahead (not only for balancing / reserves as in METIS).

Four sub-options were considered: a. Priority dispatch for must take CHP, RES E, biomass and small-scale RES E

• b. 

  As in (a), but biomass bids at marginal costs. c. As in (b), with no priority dispatch of RES E except small scale. RES E bidding at marginal costs minus FIT (wherever

2 RES E priority applicable). dispatch d. As in (c) but with no priority of small-scale RES E thanks to

aggregators. Note that removal of priority dispatch is assumed to imply balance responsibility and capability to participate in intraday and offer balancing services. Thus for sub-option (d) all resources participate in intraday, offer balancing services and have balancing responsibilities.

Three options were considered: a. Low liquidity. DAM covers part of the load, with many bilateral contracts nominated. ID illiquid in certain countries, in

3 Day-ahead and intraday liquidity which case TSO has significant RR.

• b. 

  Improved liquidity. DAM covers the large majority of the load, no nominations. ID illiquid in certain countries, in which case TSO has significant RR.

308

Measure Topic Description of the options

• c. 

  Liquid markets. DAM covers the whole load. Liquid and

harmonised ID markets.

Three options were considered: a. Very limited participation of flows over interconnectors (as available capacity for intraday is restricted to the minimum –

4 Intraday coupling defined by country) b. Limited participation of flows over interconnectors

• c. 

  Entire physical capacity of interconnectors allocated to IDM and flow-based allocation of capacities, after taking into account remaining capacity of interconnectors.

Reserve was sized exogenously (own calculations). Three options were considered:

5 Reserve

• a. 

  High reserve requirements (national)

dimensioning b. High reserve requirements (national) but slightly reduced than in Option 0

• c. 

  EU-wide reserve requirements (nonetheless taking into account areas systematically congested)

The options were: Reserve a. Current practices 6 procurement b. Day-ahead procurement(which was modelled in PRIMES/IEM

methodology as a joint optimization of power and reserve day-ahead procurement)

Two options were considered:

Use of NTC and a. Restrictive ATC (NTC – bilateral contracts – TSO reserves) – 7 bidding zones defined by country. National Bidding Zones (NTC values are

assumption given on existing border basis) b. Entire physical capacity of interconnectors allocated to DAM

and flow-based allocation of capacities

Two options: 8 Price Caps a. Reflecting current practices

• b. 

  Equal to VoLL, being the same for all Member States.

Source: PRIMES/IEM

PRIMES/OM policy scenarios for the options of Problem Area II

As already discussed in the previous section, the technical difficulty to model simultaneously specific wholesale market measures (removal of low price caps, locational signals for investments) with the issues on the coordination of CMs led to a two-step approach:

• - 

  Initially PRIMES/IEM was used to model Option 0 and Option 1 of Problem Area II. This was sufficient to show the benefit of Option 1.

• - 

  Subsequently PRIMES/OM was used to model Options 1 to 3 of Problem Area II, but not Option 0, this time the focus being on CMs. Comparison was performed among these three Options.

Due to the limitations of PRIMES/OM, all the detailed measures and assumptions under Option 1 could not be captured. Concerning bidding behaviour, the same approach as in PRIMES/IEM was followed. Table 7 presents a short comparison of the main results related to power generation for 2030 for the three models (PRIMES, PRIMES/IEM and PRIMES/OM).

309

Table 7: Comparison of results for PRIMES EUCO27, PRIMES/IEM Option 1(b) and PRIMES/OM Option 1 for 2030.

PRIMES PRIMES/IEM

EUCO27 Option 1(b) PRIMES/OM Option 1

Net Installed Power Capacity (in MW e ) 1,131,045 1,094,290 Nuclear energy 109,905 109,905 Hydro (pumping excluded) 133,335 133,335 Wind on-shore 246,064 246,064

Wind off-shore 37,949 as in 37,949

Solar 233,813 EUCO27 233,813

Biomass-waste fired 53,073 53,073 Other renewables 2,079 2,066 Solids fired 99,396 80,844 Oil fired 15,304 15,930

Gas fired 200,127 181,312

Net generation by plant type (in GWh) 3,396,680 3,339,769 3,378,950

Nuclear energy 738,363 678,318 737,365 Hydro (pumping excluded) 375,138 364,089 375,020 Wind on-shore 564,407 552,893 564,539 Wind off-shore 127,334 126,953 127,388 Solar 303,625 266,644 299,070 Biomass-waste fired 238,108 231,813 200,828 Other renewables 9,732 9,732 9,268 Solids fired 448,640 368,460 469,182 Oil fired 14,572 28,816 36 11,754

Gas fired 576,760 712,051 584,537

Source: PRIMES

Apart from the differences in the installed capacities for solids and gas plants, explained in more detail in Section 6.2.6.3, the main difference is the increased generation of gas plants in detriment of solids and nuclear in PRIMES/IEM, most likely due to the better capturing of the flexibility needs of the system.

With Option 1 described above, Options 2 and 3 assume on top the inclusion of CMs for specific countries. Both Options assume CMs only in the case of Member States foreseeing adequacy problems in their markets. Therefore certain Member States needed to be chosen indicatively for this role. For the scope of this assessment, four countries were assumed to be in the need of a CM: France, Ireland, Italy and UK. This assumption was not based on a resource adequacy analysis, but on the CMs examined under DG COMP's Sector Inquiry, focusing specifically on countries with market-wide CMs.

When a country was assumed to have a CM in place, it was assumed that generators no longer followed scarcity pricing bidding behaviour, but shifted to marginal cost bidding.

36 As the reported technology categories of PRIMES do not entirely match PRIMES/IEM, for

PRIMES/IEM the reported figure in the table for oil fired generation includes peak units, steam turbines (both oil and gas) as well as CHP with oil as main fuel.

310

Therefore in Options 2 and 3 a hybrid market was considered for EU28, with 24 Member States having an energy only market (with scarcity pricing behaviour), while 4 Member States having and energy market (with marginal pricing behaviour) supplemented with a capacity mechanism.

Finally the only difference between Options 2 and 3, is that in Option 3 the CM is assumed to include rules foreseeing explicit participation of cross-border capacities. Cross-border capacities were assumed to participate to a CM up to a certain upper bound. The main idea for this calculation of this upper bound was similar to the concept of unforced available capacity, which is used in CMs for the generation capacities. Note though that using this concept for calculating unforced available capacity (or de-rated capacity) of interconnectors during system stress times is more complex because the probability of non-delivery is not due only to technical factors but it is mainly due to congestion factors, which can considerably vary depending on power trade circumstances during system stress times. To do this calculation it was necessary to dispose simulation results of the operation of the multi-country system. Alternatively, the calculation could be based on statistical data on system operation in past years. In both cases, the simulation requires calculation of power flows over the interconnection system.

Data collection and data gaps

The modelling performed for the impact assessment had significant data requirements. For example METIS requires about twenty different types of data (such as installed capacities, variable costs, availabilities, load factors and such). Depending on the type of simulation, over 25 million individual data points can be required for each single test case, mostly coming from hourly data (such as hourly national demands). For the NTUA models an ever larger set of data was required (multiple times larger), as PRIMES covers the whole European energy sector and all existing or emerging technologies, from household appliances to industrial processes and means of transport. The respective data were collected from public and commercial databases, as well as DG ENER EMOS database.

Moreover, in order to assess the impact of various measures and regulations aimed at improving the market functioning, one needs to compare the market outcome in the distorted situation, i.e. under current practices, with the market outcome after the implementation of new legislative measures. These distortions should be based on the current situation and practices and form the baseline for the impact assessment.

For this purpose the Commission requested assistance in the form of a study providing the necessary inputs, i.e. facts and data for the modelling of the impacts of removal of current market distortions. Although a significant amount of data was collected, a large number of desired data sets was either unavailable or undisclosed. This unavailability of data sometimes applied only for specific Member States for certain series, creating

311

difficulties in using the collected data for the rest of the Member States. In these cases

proxies need to be defined that could fill in the data gaps 37 .

Modelling limitations

Every model is a simplification of reality. Thus, a model itself is not able to capture all features and facets of the real world. While one may be tempted to include as many features and options as possible, one has to be careful in order to avoid over-complication of models. This can very quickly result in overfitting (i.e. modelling relationships and cause and effects that do in this way not apply to reality, but yielding a better fit), and transparency issues (i.e. understanding in the end not the model results, or drawing wrong conclusions). It is therefore essential to find the right balance between complexity and transparency, taking the strengths and weakness of each modelling approach into account.

For these reasons, considering the limitations of each modelling approach, a number of compromises were made. There was an effort these compromises to retain the complexity of the modelling at the lowest possible level, in order to allo interpretability of results. The aforementioned study on market distortions also contributed in identifying the best modelling approaches to capture all major distortions.

One should also expect that the different models used, although all of them focus on the power sector, can produce different results due to the varying methodological approaches followed. As long as these differences are well-founded on the underlying methodology and scope of each model, while being based on the same underlying assumptions and input data, they can be considered as complementary, as they give a better overview of the impacts of the various policy options and help producing a more robust assessment.

37 "Electricity Market Functioning: Current Distortions, and How to Model their Removal", COWI

(2016).

312

Tool Main Modelling Limitations

Concerned Leading to a possible overestimation of Leading to a possible underestimation of

benefits benefits With an unclear effect

The baseline assumes current practices for a number The detrimental effects of capacity mechanisms or Modelling of the day-ahead and reserve procurement is of market design related measures and policies, not support schemes for RES E to the efficiency of the based on the so-called co-optimization of energy and considering their possible evolution and the expansion electricity market operation over the various time reserves. This approach was the one implemented for of existing initiatives. frames, as well as the external costs to the power simplicity and transparency. At the same time though it As the situation is very unclear how these will system (in relation to the energy market), were not does lead to the optimal scheduling of units. This on one advance in the coming years, and since modelling considered. hand underestimates the costs of the baseline (in the case requires a specific assumption for each of these Still these are touched in Problem Area II and the of METIS), but at the same time possibly over-estimates measures, it was decided for these cases (e.g. DR RED II impact assessment, as well as strong the benefits of the policy options. participation in the markets) to reflect a more indication on the impacts of RES E subsidies can be Still overall the specific choice should not be considered pessimistic view, where only few advancements are deduced by the effect of the removal of priority pivotal. Well-designed markets should lead to the same

METIS & made. In this respect the costs of the baseline are quite dispatch for biomass plants. efficient operation of the power system. Liquid intraday PRIMES/IEM likely overestimated. The softer approach used for the modelling of and balancing markets should optimize operation and

priority dispatch of variable RES E (wind, solar) resolve possible infeasibility issues resulting from the DA underestimates the relevant cost of the baseline schedule. scenario. Similarly for the balancing responsibility, where H-2 forecasts for RES E are used, even when balance responsibility is not assumed to apply to them. METIS did not model CHP and small scale RES E separately, which would further enhance the impacts of priority dispatch, currently assessed only for biomass.

The yearly dimensioning and procurement of reserves The issue of the limited liquidity currently observed Continuous intraday trading was modelled as consecutive overestimates the cost of current practices, not even in intraday and balancing markets is not captured in hourly implicit auctions. considering their possible evolution, based on which the modelling. Thus METIS assumed that markets are very likely to be brought even closer to real time in would be liquid in 2030, which may very well be the coming years. indeed the case without any policy action. Note

METIS This is partially compensated by assuming that though that in certain Member States these markets dimensioning is performed based on the more accurate may not even exist today,

probabilistic approach (despite currently performed in many Member States based on the deterministic one). Also by the fact that in all sub-options dimensioning of mFRR and FCR does not vary (thus no benefits are reported for this).

METIS Even in the baseline, interconnector capacity is The assumed effect of the measures on the interconnector

313 Annex IV: Analytical models used in preparing the impact assessment.

Tool Main Modelling Limitations

Concerned Leading to a possible overestimation of Leading to a possible underestimation of

benefits benefits With an unclear effect

assumed to be allocated and used relatively capacities (i.e. the increase of NTC capacities) for the efficiently. various options was performed in a stylized manner. It was Moreover the absence of network modelling implied based on very rough estimations due to the significant lack that all relevant (and in many cases significant) costs of relevant data. were not considered, especially related to internal congestion (within Member States). DR was modelled as if participating only in Stylized modelling approach concerning costs of DR. balancing markets and reserves, but not in day-ahead / intraday. Benefits from load shifting or load reductions were not assessed due to the lack of sufficient detailed

METIS data. A standard load profile was used for demand, based on ENTSO-E's TYNDP 2016 assumptions. A dynamic profile for demand and storage would better capture the reactions of demand to market prices (and the associated benefits). Competition issues, effects of nominations and block-bids, as well as possible strategic behaviour of

METIS the market participants were not considered. On the contrary, perfect competition was assumed based on marginal pricing.

Assumed bidding behaviour on behalf of market Modelling required a significant amount of inputs and participants was not considered very aggressive, with exogenous assumptions, e.g. on market behaviour etc., the electricity price rarely reaching the price caps. with data not necessarily available (generally, not just

PRIMES/IEM publicly).Moreover significant amount of data (e.g.

• & 

  PRIMES/OM detailed data on RR, nominations, technical details on the transmission grid) were missing, so had to be estimated by

  the modellers. Thus results are quite dependant on these inputs. Still every effort was made to confirm assumptions based on currently observed market operation data.

  The fact that the baseline does not capture the The selection of the countries assumed to have a CM may

PRIMES/OM possible overcapacity in the power markets, e.g. due be influencing the results (in an uncertain direction). Each to existing CMs or RES E support schemes or due to combination of countries could possibly lead to different

unrealised forecasts of the market participants, takes results.

314 Annex IV: Analytical models used in preparing the impact assessment.

Tool Main Modelling Limitations

Concerned Leading to a possible overestimation of Leading to a possible underestimation of

benefits benefits With an unclear effect

away part of the benefits that would be realised from well-functioning markets (and CMs). For this reason a sensitivity was performed assuming the existence of CMs for all countries, and then performing the comparison of Options 2 and 3 in this context.

315 Annex IV: Analytical models used in preparing the impact assessment.

316

Annex V: Evidence and external expertise used

The present impact assessment is based on a large body of material, all of which is referenced in the footnotes. A number of studies have however been conducted mainly or specifically for this impact assessment. These are listed and described further in the table below.

The Commission (DG Competition) has also been conducting a sector inquiry into national capacity mechanisms and organised Working Groups with Member States with a view to help them implement the provisions in the EEAG related to capacity mechanisms

and to share experience in the design of capacity mechanisms 38 .

38 http://ec.europa.eu/competition/sectors/energy/state_aid_to_secure_electricity_supply_en.html

317

Study Study serve to study/substantiate impact of Contractor Published

Assessing elements for upgrading the market (all options under Problem Area I) with a focus on the more efficient operation of the power system:

METIS - Removing Market Distortions

Study 12: Assessing Market Design - Allocating interconnection capacity Modelling tool DG ENER/METIS 39

Options in 2030. across time frames Consortium

To be published

• - 

  Procurement and Sizing of Balancing Reserves

Impacts of the participation of Distributed Generation in the market

METIS Assessing the benefits from a coordinated

Study 04: Stakes of a common approach approach in Generation and System Adequacy Modelling tool DG ENER/METIS To be published for generation and system adequacy. Analysis Consortium

METIS Effect of weather related uncertainty to

Study 16: Weather-driven revenue revenues. Capacity savings due to cooperation. Modelling tool DG ENER/METIS

uncertainty for power producers and ways to CM coordination/cross-border participation. Consortium To be published

mitigate it .

METIS

Technical Note T04: Methodology for the Technical note providing details on the

integration of PRIMES scenarios into methodological approach followed with METIS. METIS Consortium To be published

METIS.

METIS To be published

Technical Note T05: METIS market module Technical note providing details on the METIS Consortium / Thema

39 Once operational, the envisaged link is expected to be the following: https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis. Same applies for all METIS studies.

318 Annex V: Evidence and external expertise used

Study Study serve to study/substantiate impact of Contractor Published

configuration for Study S12 - Focus on daymethodological approach followed with METIS. Consulting ahead, intraday and balancing markets.

• A. 

  Assessing elements for upgrading the market (main options under Problem Area I) with a focus on the revenues for the market players, including:

"Methodology and results of modelling the - Scarcity pricing

EU electricity market using the - Bidding Zones NTUA To be published

PRIMES/IEM and PRIMES/OM models" B. Assessing investment incentives and the need for coordination of CMs:

• - 

  Profitability of power generation investments

Coordination of CMs

Electricity Market Functioning: Current Impact removing market distortions:

Distortions, and How to Model Their - Identifying market distortions COWI / Thema / NTUA To be published

Removal Providing data input and support for the modelling

Framework for cross-border participation in

capacity mechanisms CM cross-border arrangements COWI/Thema/NTUA To be published

Transmission tariffs and Congestion income Options for locational signals/regulatory

policies framework IC construction Trinomics To be published

319 Annex V: Evidence and external expertise used

Study Study serve to study/substantiate impact of Contractor Published

Integration of electricity balancing markets Main study supporting Balancing Guidelines and regional procurement of balancing IA. For MDI: regional sizing and procurement COWI/Artelys To be published

reserves balancing reserves 40

Impact Assessment support Study on Costs and benefits of measures to remove

downstream flexibility, demand response market barriers to demand response and make COWI / ECOFYS / THEMA / and smart metering dynamic price tariffs more accessible VITO

To be published

Study on future European electricity system https://ec.europa.eu/energy/sites/ener/files/documents/

operation Future model TSO collaboration Ecorys, DNV-GL,ECN 15- 3071%20DNV%20GL%20report%20Options%20for

%20future%20System%20Operation.pdf System adequacy assessment Methodology for system adequacy assessments JRC To be published

Identification of Appropriate Generation

and System Adequacy Standards for the System adequacy standards practises and https://ec.europa.eu/energy/sites/ener/files/documents/

Internal Electricity Market methods Mercados, E-bridge, ref4e Generation%20adequacy%20Final%20Report_for%2 0publication.pdf

Impact assessment support study on: Cost and benefits of different options

“Policies for DSOs, Distribution Tariffs and concerning DSO roles, distribution network Copenhagen Economics, and VVA To be published

Data Handling” tariffs, data handling models

Second Consumer Market Study on the Billing information; contract exit fees; price

functioning of retail electricity markets for comparison tools; disclosure and guarantees of Ipsos, London Economics, and consumers in the EU origin Deloitte

To be published

National policies on security of electricity Review of current national rules and practices https://ec.europa.eu/energy/sites/ener/files/documents/

supply relating to risk preparedness in the area of VVA Consulting & Spark DG%20ENER%20Risk%20preparedness%20final%2 security of electricity supply 0report%20May2016.pdf

Measures to protect vulnerable consumers Removing market distortions by phasing-out in the energy sector: an assessment of regulated prices

disconnection safeguards, social tariffs and Appraisal of disconnection safeguards across INSIGHT_E To be published

financial transfers the EU.

40 Examines in more detail issues that are going to be examined also on METIS Study S12.

320 Annex V: Evidence and external expertise used

Study Study serve to study/substantiate impact of Contractor Published

Energy poverty and vulnerable consumers https://ec.europa.eu/energy/sites/ener/files/documents/

in the energy sector across the EU: analysis Review of measures to protect energy poor and of policies and measures vulnerable consumers

INSIGHT_E INSIGHT_E_Energy%20Poverty%20- %20Main%20Report_FINAL.pdf

Selecting indicators to measure energy Review, appraisal and computation of indicators Trinomics, University College https://ec.europa.eu/energy/sites/ener/files/documents/

poverty to measure energy poverty London, and 7Seven Selecting%20Indicators%20to%20Measure%20Energ y%20Poverty.pdf

Fuel poverty in the European Union: a Critical assessment of the pros and cons of an Harriet Thomson, Carolyn Snell http://extra.shu.ac.uk/ppp-online/wpconcept

in need of definition? energy poverty definition at the EU level and Christine Liddell content/uploads/2016/04/fuel-poverty-europeanunion.pdf

The role of DSOs in a Smart Grid Assessment of the future role of DSOs in

environment specific activities ECN & Ecorys

https://ec.europa.eu/energy/sites/ener/files/documents/ 20140423_dso_smartgrid.pdf

Study on the effective integration of Assessment of distributed energy resources and https://ec.europa.eu/energy/sites/ener/files/documents/

Distributed Energy Resources for providing their effectiveness in providing flexibility to the PwC, Sweco, Ecofys, Tractebel 5469759000%20Effective%20integration%20of%20 flexibility to the electricity system energy system DER%20Final%20ver%202_6%20April%202015.pdf

From Distribution Networks to Smart Assessment of the DSO role in the context of

Distribution Systems: Rethinking the four regulatory areas including remuneration, THINK http://www.eui.eu/projects/think/documents/thinktopi

Regulation of European Electricity DSOs network tariff structure and DSO activities c/topic12digital.pdf

Options on handling Smart Grids Data Description of different data handling options https://ec.europa.eu/energy/sites/ener/files/documents/ for smart grids EC Smart Grids Task Force xpert_group3_first_year_report.pdf

Description of the flexibility context, Regulatory Recommendations for the commercial and regulatory arrangements, https://ec.europa.eu/energy/sites/ener/files/documents/

Deployment of Flexibility incentives for the development of flexibility, EC Smart Grids Task Force EG3%20Final%20-%20January%202015.pdf

policy recommendations Identifying energy efficiency improvements Analysis of different options for improving https://ec.europa.eu/energy/sites/ener/files/documents/ and saving potential in energy networks and efficiency in energy networks according to Tractebel, Ecofys GRIDEE_4NT_364174_000_01_TOTALDOC%20- demand response Article 15 of the EED %2018-1-2016.pdf

Study on tariff design for distribution Benchmarking of different distribution tariff https://ec.europa.eu/energy/sites/ener/files/documents/

systems structures and levels for electricity and gas AF Mercados, refE, Indra 20150313%20Tariff%20report%20fina_revREF- across EU E.PDF

321 Annex V: Evidence and external expertise used

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322

Annex VI: Evaluation

The evaluation is presented as a self-standing document.

323

This page was deliberately left empty

324

Annex VII: Overview of electricity network codes and guidelines

This annex provides an overview of electricity network codes and guidelines adopted or envisaged under Articles 6, 8 and 18 of the Electricity Regulation as well as a brief description to the present initiative, if any.

325

Electricity network codes State of play Brief description of contents Link to MD and guidelines adopted or I envisaged under Articles

6, 8 and 18 of the Electricity Regulation

Commission Regulation Adopted on 24 July Legal implementation of day-ahead Linked to short-term establishing a Guideline on 2015 and intraday market coupling, flowmarkets capacity allocation and based capacity calculation For more details, see congestion management Annex 2.2

Commission Regulation Adopted on 14 April Defines the necessary technical No direct link with MD establishing a Network code on 2016 capabilities of generators in order to requirements for grid connection contribute to system safety and to of generators create a level playing field.

Commission Regulation Adopted on 26 August Technical connection rules for No direct link with MD establishing a Network Code on 2016 HVDC lines, e.g. used for High Voltage Direct Current connections of offshore wind farms Connections and DC-connected Power Park Modules

Commission Regulation Adopted on 17 August Defines the necessary technical Link to demand response establishing a Network code on 2016 specifications of demand units and to measures on demand connection connected to a grid and DSOs in ancillary services For

order to contribute to system safety more details, see Annex and to create a level playing field. 3.1

Commission Regulation Adopted on 26 Creation of hedging opportunities for Link to short-term establishing a Guideline on September 2016 the electricity market; important to markets, scarcity pricing Forward Capacity Allocation facilitate cross-border trade; capacity and locational signals.

to be allocated through auctions on a See Annexes 2.2, 4.1, central booking platform; 4.2 harmonisation of capacity products

Commission Regulation Text voted favourably Rules to react to system incidents Linked to TSO establishing a Guideline on by MS on 4 May (TSO interaction when the system cooperation in the electricity transmission System goes beyond acceptable operational planning and operation of Operation Target date for ranges) transmission systems.

launching scrutiny: Creation of a framework for TSO For more details, see December 2016 cooperation in the preparation of Annex 2.3 system operation (i.e. planning ahead of real time). Guidance for how TSOs should create a framework for keeping system frequency within safe operational ranges

Draft Commission Regulation Target for vote in First step to the development of Linked to procurement establishing a Guideline on comitology: by end common merit order lists for the rules and sizing of Electricity Balancing 2016 activation of balancing energy and balancing reserves. ('Balancing Guideline') the start of a harmonisation of For more details, see

balancing products. Annex 2.1 Draft Commission Regulation Target for vote in Defines requirements of the plans to Linked to security of establishing a Network code on comitology: first quarter be adopted by TSOs concerning supply measures. Emergency and Restoration 2017 procedures to be followed when For more details, see

blackouts happen Annex 6

326

Annex VIII: Summary tables of options for detailed measures assessed under each main option

The tables provided here reflect the in-depth assessment made of the options for detailed measures described in the Annexes to the impact assessment Chapter 1.1 through to 7.6

The manner in which they correspond to the main options assessed in the present document is set out in Table 6, Table 7, Table 8 and Table 9 in the present document

327

Measures assessed under Problem Area 1, Option 1(a): level playing field amongst participants and resources

Priority access and dispatch

Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.

Option 0 Option 1 Option 2 Option 3

Do nothing. Abolish priority dispatch and priority Priority dispatch and/or priority access only for emerging Abolish priority dispatch and introduce clear This would maintain access technologies and/or for very small plants: curtailment and re-dispatch rules to replace rules allowing priority This option would generally require full This option would entail maintaining priority dispatch priority access.

n dispatch and priority merit order dispatch for all technologies, and/or priority access only for small plants or emerging This option can be combined with Option 2,

tio access for RES, including RES E, indigenous fuels such as technologies. This could be limited to emerging RES E maintaining priority dispatch/access only for indigenous fuels and coal, and CHP. It would ensure optimum technologies, or also include emerging conventional emerging technologies and/or for very small

cr ip use of the available network in case of technologies, such as CCS or very small CHP. plants

D es

CHP. network congestion.

Lowest political Efficient use of resources, clearly Certain emerging technologies require a minimum number As Option 1, but also resolves other causes for

resistance distinguishes market-based use of of running hours to gather experiences. Certain small lack of market transparency and discrimination

capacities and potentially subsidy-based generators are currently not active on the wholesale market. potential. It also addresses concerns that

installation of capacities, making subsidies In some cases, abolishing priority dispatch could thus bring abolishing priority dispatch and priority access

transparent. significant challenges for implementation. Maintaining also could result in negative discrimination for

os priority access for these generators further facilitates their renewable technologies.

Pr operation.

Politically, it may be criticized that Same as Option 1, but with less concerns about blocking Legal clarity to ensure full compensation and subsidized resources are not always used if potential for trying out technological developments and non-discriminatory curtailment may be there are lower operating cost alternatives. creating administrative effort for small installations. challenging to establish. Unless full Adds uncertainty to the expected revenue Especially as regards small installations, this could compensation and non-discrimination is stream, particularly for high variable cost however result in significant loss of market efficiency if ensured, priority grid access may remain generation. large shares of consumption were to be covered by small necessary also after the abolishment of priority

C ons installations. dispatch.

Most suitable: Option 3. Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to actively participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should be combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or emerging technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.

328 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Regulatory exemptions from balancing responsibility

Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances caused.

Option 0 Option 1 Option 2 Option 3

Do nothing. Full balancing responsibility for all Balancing responsibility with exemption Balancing responsibility, but possibility to This would maintain the status parties possibilities for emerging technologies delegate quo, expressly requiring financial Each entity selling electricity on the and/or small installations This would allow market parties to delegate the

n balancing responsibility only market has to be a balancing responsible This would build on the EEAG. balancing responsibility to third parties.

under the state aid guidelines party and pay for imbalances caused. This option can be combined with the other

cr ip

tio which allow for some exceptions. options.

D es

Lowest political resistance Costs get allocated to those causing This could allow shielding emerging The impact of this option would depend on the them. By creating incentives to be technologies or small installations from the scope and conditions of this delegation. A balanced, system stability is increased technical and administrative effort and delegation on the basis of private agreements, and the need for reserves and TSO financial risk related to balancing with full financial compensation to the party interventions gets reduced. Incentives to responsibility. accepting the balancing responsibility (e.g. an

os improve e.g. weather forecasts are aggregator) generally keeps incentives intact.

Pr created.

Financial risks resulting from the Shielding from balancing responsibilities The impact of this option would depend on the operation of variable power generation creates serious concerns that wrong scope and conditions of this delegation. A full and (notably wind and solar power) are incentives reduce system stability and non-compensated delegation of risks e.g. to a increased. endanger market functioning. It can regulated entity or the incumbent effectively increase reserve needs, the costs of which eliminates the necessary incentives. Delegation to are partly socialized. This is particularly the incumbent also results in further increases to relevant if those exemptions cover a market dominance. significant part of the market (e.g. a high

C ons number of small RES E generators).

Most suitable: Option 2 combined with the possibility for delegation based on freely negotiated agreements.

329 Annex VIII: Summary tables of options for detailed measures assessed under each main option

RES E access to provision of non-frequency ancillary services

Objective: transparent, non-discriminatory and market based framework for non-frequency ancillary services

Option 0 Option 1 Option 2

BAU Description Description

Different requirements, awarding procedures and Set out EU rules for a transparent, non-discriminatory and Set out broad guidelines and principles for MS for the adoption of remuneration schemes are currently used across MS. market based framework to the provision of non-frequency transparent, non-discriminatory and market based framework to the

Rules and procedures are often tailored to conventional ancillary services that allows different market players provision of non-frequency ancillary services. generators and do not always abide to transparency, /technology providers to compete on a level playing field. non-discrimination. However increased penetration of

RES displaces conventional generation and reduces the supply of these services.

Stronger enforcement Pro Pro

Provisions containing reference to transparency, non Accelerate adoption in MS of provisions that facilitate the Sets the general direction and boundaries for MS without being too discrimination are contained in the Third Package. participation of RES E to ancillary services as technical prescriptive.

However, there is nothing specific to the context of capabilities of RES E and other new technologies is available, Allows gradual phase-in of services based on local/regional needs non-frequency ancillary services. main hurdle is regulatory framework. and best practices.

Clear regulatory landscape can trigger new revenue streams and business models for generation assets. Con Con Resistance from MS and national authorities/operators due to Possibility of uneven regulatory and therefore market developments the local/regional character of non-frequency ancillary depending on how fast MS act. This creates uncertain prospects for services provided. businesses slowing down RES E penetration. Little previous experience of best practices and unclear how to monitor these services at DSO level where most RES E is connected.

Most suitable option(s): Option 2 is best suited at the current stage of development of the internal electricity market. Ancillary services are currently procured and sometimes used in very different manners in different Member States, Furthermore, new services are being developped and new market actors (e.g. batteries) are quickly developing. Setting out detailed rules required for full harmonisation would thus preclude unknown future developments in this area, which currently is subject to almost no harmonisation.

330 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Measures assessed under Problem Area 1, Option 1(b) Strengthening short-term markets

Reserves sizing and procurement

Objective: define areas wider than national borders for sizing and procurement of balancing reserves

Option 0: business as usual Option 1: national sizing and Option 2: regional sizing and procurement of Option 3: European sizing and procurement procurement of balancing reserves on balancing reserves of balancing reserves

daily basis The baseline scenario consists of a This option consists in developing a This option involves the setup of a binding This option would have a major impact on the smooth implementation of the binding regulation that would require regulation requiring TSOs to use regional current design of system operation procedures Balancing Guideline. Existing on TSOs to size their balancing reserves on platforms for the procurement of balancing and responsibilities and current operational going experiences will remain and be daily probablistic methodologies. Daily reserves. Therefore this option foresees the security principles. A supranational independent free to develop further, if so decided. calculation allows procuring lower implementation of an optimisation process for system operator ('EU ISO') would be However, sizing and procurement of balancing reserves and, together with the allocation of transmission capacity between responsible for sizing and procuring balancing balancing reserves will mainly daily procurement, enables participation energy and balancing markets, which then reserves, cooperating with national TSOs. This remain national, frequency of of renewable energy sources and demand implies procuring reserves only a day ahead of would enable TSOs to reduce the security

procurement as foreseen in the response. real time . margin on transmission lines, thus offering Balancing Guideline. This option foressees separate This option would result in a higher level of more cross-zonal transmission capacity to the procurement of all type of reserves coordination betwRReen European TSOs, but market and allowing for additional cross-zonal

n Active participation in the Balancing between upward (i.e. increasing power still relies on the concept of local exchanges and sharing of balancing capacity. tio Stakeholder Group could ensure output) and downward (i.e. reducing responsibilities of individual balancing zones stronger enforcement of the power output; offering demand and remains compatible with current

D es

cr ip Balancing Guideline. reduction) products.

operational security principles.

Optimal national sizing and procurement Regional areas for sizing and procurement of Single European balancing zone. os

Pr of balancing reserves. balancing reserves.

No cross-border optimisation of Balancing zones still based on national borders Extensive standardisation through replacement balancing reserves. but cross-border optimisation possible. of national systems, difficult and costly implementation.

C ons

Most suitable: Option 2. Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the physical topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the preferred option.

331 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Removing distortions for liquid short-term markets

Objective: to remove any barriers that exist to liquid short-term markets, specifically in the intraday timeframe, and to ensure distortions are minimised.

Option 0 Option 1 Option 2

Business as usual Fully harmonise all arrangements in local Selected harmonisation, specifically on issues relating to gate closure Local markets mostly unregulated, allowing for national markets. times and products. differences, but affected by the arrangements for crossborder intraday and day-ahead market coupling.

n

tio Stronger enforcement and volunatry cooperation

There is limited legislation to enforce and voluntary

D es cr ip

cooperation would not provide certainty to the market Simplest approach, and allows the cross-border Would minimise distortions, with very limited Targets issues that are particularly important for maximising liquidity of arrangements to affect local market arrangements. Likely to opportunity for deviation. short-term markets and allows for participation of demand response and see a degree of harmonisation over time. small scale RES.

os Pr Differences in national markets will remain that can act as a Extremely complex; even the cross-border May still be difficult to implement in some Member States with barrier. arrangements have not yet been decided and implication on how the system is managed – central dispatch systems need significant work from experts. could, in particular, be impacted by shorter gate closure time.

Additional benefit unclear.

C ons

Most suitable: Option 2 – Provides a proportionate response targeting those issues of most relevance.

332 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Improving the coordination of Transmission System Operation

Objective: Stronger coordination of Transmission System Operation at a regional level

Option 0 Option 1 Option 2 Option 3

BAU Enhance the current set up of existing RSC by Go beyond the establishment of ROCs Create a European-wide Limit the TSO coordination efforts to the creating Regional Operational Centers (ROCs), that coexist with national TSOs and Independent System Operator implementation of the new Guideline on centralising some additional functions at regional consider the creation of Regional that can take over system

n Transmission System Operation (voted at the level over relevant geographical areas and Independent System Operators that can operation at EU-wide level.

Electricity Cross Border Committee in May 2016 delineating competences between ROCs and fully take over system operation at Transmission ownership would

cr ip

tio and to be adopted by end-2016) which mandates the national TSOs. regional level. Transmission remain in the hands of national creation of Regional Security Coordinators (RSCs) ownership would remain in the hands TSOs.

D es covering the whole Europe to perform five relevant of national TSOs.

tasks at regional level as a service provider to national TSOs.

Lowest political resistance. Enlarged scope of functions assuming those tasks Improved system and market operation Seamless and efficient system where centralization at regional level could bring leading to optimal results including and market operation.

benefits optimized infrastructure development, A limited number (5 max) of well-defined regions, market facilitation and use of existing

os covering the whole EU, based on the grid topology infrastructure, secure real time

Pr that can play an effective coordination role. One operation. ROC will perform all functions for a given region.

Enhanced cooperative decsion-making with a possibility to entrust ROCs with decision making competences on a number of issues.

Suboptimal in the medium and long-term. Could find political resistance towards Politically challenging. While this Extremely challenging regionalisation. If key elements/geography are not option would ultimately lead to an politically. The implications of

clearly enshrined in legislation, it might lead to a enhanced system operation and might such an option would need to

C ons suboptimal outcome closer to Option 0. not be discarded in the future, it is not be carefully assessed. It is considered proportionate at this stage questionable whether, at least

to move directly to this option. at this stage, it would be proportionate to take this step.

Most suitable option(s): Option 1 (Option 2 and Option 3 constitute the long-term vision)

333 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Measures assessed under Problem Area 1,Option 1(c); Pulling demand response and distributed resources into the market

Unlocking demand side response

Objective: Unlock the full potential of Demand Response

Option O: BAU Option 1: Give consumers access to Option 2: as Option 1 but also fully enable Option 3: mandatory smart meter roll out and technologies that allow them to participate incentive based Demand Response full EU framework for incentive based demand in price based Demand Response schemes response

Stronger enforcement of existing Give each consumer the right to request the In addition to measures described under Option Mandatory roll out of smart meters with full legislation that requires MS to roll out installation of, or the upgrade to, a smart 1, grant consumers access to electricity markets functionalities to 80% of consumers by 2025 smart meters if a cost-benefit analysis meter with all 10 recommended through their supplier or through third parties Fully harmonised rules on demand response is positive and to ensure that demand functionalities. (e.g. independent aggregators) to trade their including rules on penalties and compensation side resources can participate Give the right to every consumer to request a flexibility. This requires the definition of EU payments. alongside supply in retail and dynamic electricity pricing contract. wide principles concerning demand response wholesale markets and flexibility services.

No new legislative intervention. This option will give every consumer the This option will allow price and incentive based This guarantees that 80% of consumers across the right and the means (fit-for-purpose smart DR as well as flexibility services to further EU have access to fully functional smart meters by meter and dynamic pricing contract) to fully develop across the EU. Common principles for 2025 and hence can fully participate in price based engage in price based DR if (s)he wishes to incentive based DR will also facilitate the DR and that market barriers for incentive based DR do so. opening of balancing markets for cross-border are removed in all MS.

trade. Roll out of smart meters will remain Roll out of smart meters on a per customer As for Option 1, access to smart meters and It ignores the fact that in 11 MS the overall costs of limited to those MS that have a basis will not allow reaping in full systemhence to price based DR will remain limited. a large-scale roll out exceed the benefits and hence positive cost/benefit analysis. wide benefits, or benefits of economies of Member States will continue to have freedom to that in those MS a full roll out is not economically In many MS market barriers for scale (reduced roll out costs) design detailed market rules that may hinder the viable under current conditions. demand response may not be fully Incentive based demand response will not full development of Demand Response. Fully harmonised rules on demand response cannot removed and DR will not deliver to develop across Europe. take into account national differences in how e.g. its potential. balancing markets are organised and may lead to

suboptimal solutions. Most suitable option(s): Option 2. Only the second option is suited to untap the potential of demand response and hence reduce overall system costs while respecting subsidiarity principles. The third option is likely to deliver the full potential of demand response but may do so at a too high cost at least in those Member States where the roll out of smart meters is not yet economically viable. Options zero and one are not likely to have a relevant impact on the development of demand response and reduction of electricity system cost.

334 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Distribution networks

Objective: Enable DSOs to locally manage challenges of energy transition in a cost-efficient and sustainable way, without distorting the market.

Option: 0 Option 1 Option 2

BAU - Allow and incentivize DSOs to acquire flexibility services from distributed - Allow DSOs to use flexibility under the conditions set in

Member States are primarily energy resources. Option 1. responsible on deciding on the detail - Establish specific conditions under which DSOs should use flexibility, and - Define specific set of tasks (allowed and not allowed) for tasks of DSOs. ensure the neutrality of DSOs when interacting with the market or consumers. DSOs across EU.

• - 

  Clarify the role of DSOs only in specific tasks such as data management, the - Enforce existing unbundling rules also to DSOs with less ownership and operation of local storage and electric vehicle charging than 100,000 customers (small DSOs).

  infrastructure. - Establish cooperation between DSOs and TSOs on specific areas, alongside the

creation of a single European DSO entity. Pro Pro Pro Current framework gives more Use of flexible resources by DSOs will support integration of RES E in distribution Stricter unbundling rules would possibly enhance competition flexibility to Member States to grids in a cost-efficient way. in distribution systems which are currently exempted from accommodate local conditions in their Measures which ensure neutrality of DSOs and will guarantee that operators do not unbundling requirements. national measures. take advantage of their monopolistic position in the market. Under certain condition, stricter unbundling rules would also

be a more robust way to minimizing DSO conflicts of interest given the broad range of changes to the electricity system, and the difficulty of anticipating how these changes could lead to market distortions.

Con Con Con

Not all Member States are integrating Effectiveness of measures may still depend on remuneration of DSOs and regulatory Uniform unbundling rules across EU would have required changes in order to support framework at national level. disproportionate effects especially for small DSOs. EU internal energy market and targets. Possible impacts in terms of ownership, financing and

effectiveness of small DSOs. A uniform set of tasks for DSOs would not accommodate local market conditions across EU and different distribution structures.

Most suitable option(s): Option 1 is the preferred option as it enhances the role of DSOs as active operators and ensures their neutrality without resulting in excess administrative costs.

335 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Remuneration of DSOs

Objective: A performance-based remuneration framework which incentivize DSOs to increase efficiencies in planning and innovative operation of their networks.

Option: O Option 1 Option 2

BAU - Put in place key EU-wide principles and guidance regarding the remuneration of - Fully harmonize remuneration methodologies for all

Member States (NRAs) are mainly DSOs, including flexibility services in the cost-base and incentivising efficient DSOs at EU level. responsible on deciding on the detailed operation and planning of grids. framework for remuneration of DSOs. - Require DSO to prepare and implement multi-annual development plans, and

coordinate with TSOs on such multi-annual development plans. - Require NRAs to periodically publish a set of common EU performance indicators

that enable the comparison of DSOs performance and the fairness of distribution tariffs.

Pro Pro Pro

Current framework gives more Performance based remuneration will incentivise DSOs to become more cost-efficient A harmonized methodology would guarantee the flexibility to Member States and NRAs and offer better quality services. implementation of specific principles. to accommodate local conditions in It would support integration of RES E and EU targets. their national measures.

Con Con Con

Current EU framework provides only Detail implementation will still have to be realized at Member State level, which may A complete harmonisation of DSO remuneration schemes some general principles, and not reduce effectiveness of measures in some cases. would not meet the specificities of different distribution specific guidance towards regulatory systems. schemes which incentivize DSOs and Therefore, such an option would possibly have raise efficiencies. disproportionate effects while not meeting subsidiarity

principle. Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective remuneration schemes and enhancing transparency requirements

336 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Distribution network tariffs

Objective: Distribution tariffs that send accurate price signals to grid users and aim to fair allocation of distribution network costs.

Option: 0 Option 1 Option 2

BAU - Impose on NRAs more detailed transparency and comparability requirements for - Harmonization of distribution tariffs across EU; fully

Member States (NRAs) are mainly distribution tariffs methodologies. harmonize distribution tariff structures at EU level for all responsible on deciding on the detailed - Put in place EU-wide principles and guidance which ensure fair, dynamic, time EU DSOs, through concrete requirements for NRAs on distribution tariffs. dependent distribution tariffs in order to facilitate the integration of distributed tariff setting.

energy resources and self-consumption. Pro Pro Pro Current framework gives more Principles regarding network tariffs will increase efficient use of the system and A harmonized methodology would guarantee the flexibility to Member States and NRAs ensure a fairer allocation of network costs. implementation of specific principles. to accommodate local conditions in their national measures.

Con Con Con

Current EU framework provides only Detail implementation will still have to be realized at Member State level, which A complete harmonisation of DSO structures would not meet some general principles, and not may reduce effectiveness of measures in some cases. the specificities of different distribution systems. specific guidance towards distribution Therefore, such an option would possibly have network tariffs which effectively disproportionate effects while not meeting subsidiarity allocate costs and accommodate EU principle. policies.

Most suitable option(s): Option 1 is the preferred option as it will reinforce the existing framework by providing guidance on effective distribution network tariffs and enhancing transparency requirements

337 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Improving the institutional framework

Objective: To adapt the Institutional Framework, in particular ACER's decision-making powers and internal decision-making to the reality of integrated regional markets and the proposals of the Market Design Initiative, as well as to address the existing and anticipated regulatory gaps in the energy market.

Option 0 Option 1 Option 2

Maintain status quo, taking into account that the implementation Adapting the institutional framework to the new Providing for more centralised institutional structures with

n of network codes would bring certain small scale adjustments. realities of the electricity system and to the additional powers and/or responsibilities for the involved However, the EU institutional framework would continue to be resulting need for additional regional cooperation entities.

ip tio based on the complementarity of regulation at national and EU- as well as to addressing existing and anticipated

level. regulatory gaps in the energy market.

D es

cr

Lowest political resistance. Addresses the shortcomings identified and Addresses the shortcomings identified with limited

os provides a pragmatic and flexible approach by coordination requirements for institutional actors.

Pr combining bottom-up initiatives and top-down steering of the regulatory oversight.

The implementation of the Third Package and network codes is Requires strong coordination efforts between all Significant changes to established institutional processes with not sufficient to overcome existing shortcomings of the involved institutional actors. the greatest financial impact and highest political resistance.

C ons institutional framework.

Most suitable: Option 1, as it adapts the institutional framework to the new realities of the electricity system by adopting a pragmatic approach in combining bottom-up initiatives and topdown steering of the regulatory oversight.

338 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Measures assessed under Problem Area 2, Option 2(1); Improved energy-only market without CMs)

Removing price caps

Objective: to ensure that prices in wholesale markets are not prevented from reflecting scarcity and the value that society places on energy.

Option 0: Business as usual Option 1: Eliminate all price caps Option 2: Create obligation to set price caps, where they exist, at VoLL

Existing regulations already require harmonisation of Eliminate price caps altogether for balancing, Reinforced requirement to set price limits taking "into account maximum (and minimum) clearing prices in all price zones to intraday and day-ahead markets. an estimation of the value of lost load" a level which takes "into account an estimation of the value of lost load". Removes barriers for scarcity pricing Avoids setting Allow for technical price limits as part of market coupling, of VoLL (for the purpose of removing negative provided they do not prevent prices rising to VoLL. Stronger enforcement/non-regulatory approach effects of price caps). Establish requirements to minimise implicit price caps. Enforceability of "into account an estimation of the value of lost load" in the CACM Guideline is not strong. Enforcement action is unlikely to be successful or expedient. Relying on stronger enforcement would leave considerable more legal

n uncertainty to market participants than clarifying the legal

tio framework directly. Voluntary cooperation would not provide the market with

cr ip sufficient confidence that governments would not step in

D es restrict prices in the event of scarcity

Simple to implement – leaves administration to technical Measure simple to implement; unequivocally and Compatible with already existing requirement to set price limit, implementation of the CACM Guideline. creates legal certainty. as provided for undert the CACM regulation, provides concrete legal clarity

os Pr Difficult to enforce; no clarity on how such clearing prices Can be considered as non-proportional; could add VoLL, whilst a useful concept, is difficult to set in practice. A will be harmonised. Does not prevent price caps being significant risk to market participants and power multitude of approaches exist and at least some degree of exchanges if there are no limits. harmonisation will be required.

C ons

implemented by other means.

Most suitable: Option 2 - this provides a proportionate response to the issue –, it would allow for technical limits as part of market coupling and this should not restrict the markets ability to generate prices that reflect scarcity..

339 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Improving locational price signals

Objective: The objective is to have in place a robust process for deciding on the structure of locational price signals for investment and dispatch decisions in the EU electricity wholesale market.

Option 0 Option 1 Option 2 Option 3

Business as Usual – decision on bidding Move to a nodal pricing system. Introduce locational signals by new means, Improve currently existing the CACM zone configuration left to the arrangements i.e. through transmission tariffs. Guideline procedure for reviewing bidding defined under the CACM Guideline or zones and introducing supranational voluntary cooperation, which has, to date, decision-making, e.g. through ACER.

n retained the status quo . This would be coupled with a strengthened

requirement to avoid the reduction of crosscr

ip

tio

zonal capcity in order to resolve internal

D es congestions.

Approach already agreed. Theoretically, nodal pricing is the most Would unlock alternative means to provide This improvement will render revisions of optimal pricing system for electricity locational signals for investment and bidding zones a more technical decision.

markets and networks. dispatch decisions.

os It will also increase the available cross

Pr zonal capacity.

Risks maintenance of the status quo, and Nodal pricing implies a complete, Incentives would be not be the result of Does not address a situation where the

therefore misses the opportunity to address fundamental overhaul of current grid market signals (value of electricity) but cost results of the bidding zone review are subissues

in the internal market. management and electricity trading components set by regulatory intervention optimal. I.e. this option only covers

arrangements with very substantial of a potentially highly political nature. procedural issues.

transition costs. Does not address the underlying difficulty

of introducing locational price zones,

namely the difficulties to arrive at decisions

that reflect congestion instead of political

C ons borders.

Most suitable: Option 3 – this option will rely on a pre-established process but improve the decision-making so that decisions take into account cross-border impact of bidding zone configuration. Other options – e.g. tofundamentally change how locational signals are provided, would be dispropritionate.

340 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Minimise investment and dispatch distortions due to transmission tariff structure

Objective: to minimise distortions on investment and dispatch patterns created by different transmission tariffs regimes.

Option 0: Business as usual Option 1: Restrict charges on producers (G- Option 2: Set clearer principles for transmission Option 3: Harmonisation charges) charges transmission tariffs

This option would see the status quo This option could see the prohibition of This option would see a requirement on ACER to Full harmonisation of maintained, and transmission tariffs set transmission charges being levied on develop more concrete principles on the setting of transmission tariffs. according to the requirements under generators based on the amount of energy they transmission tariffs, along with an elaboration of Directive 72 and the ITC regulation. generate (energy-based G-charges) exiting provisions in the electricity regulation where appropriate. Stronger enforcement and voluntary cooperation:

n There is no stronger enforcement action to

tio be taken that would alone address the objective. Voluntary cooperation would, in

part, be undertaken as part of

D es cr ip

implementation of Option 2. Pros: Minimal change; likely to receive Eliminating energy-based G-charges would Provides an opportunity to move in the right Minimises distortion between some support for not taking any action in the serve to limit distortionary effects on dispatch direction whilst not risking taking the wrong Member States on both short-term. of generation caused by transmission tariffs. decisions or introducing inefficiencies because of investment and dispatch; Social welfare benefits of approximately EUR unknowns; consistent with a phased-approach; creates a level-playing field. 8 million per year. Would impact a minority of could eliminate any potential distortions without the Member States (6-8 depending on design). need to mandate particular solutions; consistent

os with the introduction of legally binding provisions

Pr in the future, e.g. through implementing legislation.

In the longer-term, likely to be a drive to do Social welfare benefits relatively small – could Still leaves the door open for variation in national Unlikely to a proportionate more and maintaining the status quo unlikely be outweighed by transitional costs in the approaches; will not resolve all potential issues. response to the issues at this to be attractive; risks of continued early years. Can be considered 'incomplete' as stage; given the technicalities divergence in national approaches. a number of other design elements of involved, it could be more transmission tariffs contribute to distortionary appropriate to introduce such

C ons

effects. measures as implementing legislation in the future.

Most suitable option(s): Option 2 – aside from some high-level requirements, given the complexity of transmission charges, the precise modalities should be set-out as part of implementing legislation in the future if and when appropriate. The value in Option 2 will be to set the path for the longer-term.

341 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Congestion income spending to increase cross-border capacity

Objective: The objective of any change should be to increase the amount of money spent on investments that maintain or increase available interconnection capacity

Option 0: Business as usual Option 1 Option 2 Option 3 This option would see the current situation Further prescription on the use of Require that any income not used for (a) Transfer the responsibility of using the maintained, i.e. that congestion income can be congestion income, subjecting its use on guaranteeing availability or (b) revenues resulting from congestion and not used for (a) guaranteeing the actual availability anything other than (a) guaranteeing the maintaining or increasing interconnection spent on either (a) guaranteeing availability of allocated capacity or (b) maintaining or actual availability of allocated capacity or capacities flows into the Energy part of or (b) maintaining capacities to the increasing interconnection capacities through (b) maintaining or increasing CEF-E or its successor, to be spent on European Commission. De facto all network investments; and, where they cannot interconnection capacities (i.e. allowing it relieving the biggest bottlenecks in the revenues are allocated to CEF-E or be efficiently used for these purposes, taken to be offset against tariffs) to harmonised European electricity system, as evidenced successor funds to manage investments into account in the calculation of tariffs. rules. by mature PCIs. which increase interconnection capacity.

n Stronger enforcement: current rules do not

tio allow for stronger enforcement. Voluntary cooperation: would offer no

cr ip certainty that the allocation of income would

D es change.

Minimal disruption to the market; consumers More guarantee that income will be spent Guarantees that income will be spent on Best guarantee that income will be spent on can benefit from tariff reductions – unclear on projects that increase or maintain projects that increase or maintain the biggest bottlenecks in the European whether benefits of better channelling income interconnection capacity and relieve the interconnection capacity and relieve the electricity system, ensuring the best deal for towards interconnection would provide more most significant bottlenecks; could provide most important bottlenecks; could provide European consumers in the longer run; benefits to consumers, given that it may offset around 35% extra spend; approach reflects up to 35% extra spend; approach reflects approach reflects the EU-wider benefits of (at least in part) money spent on the EU-wider benefits of electricity the EU-wider benefits of electricity electricity exchange through interconnection from other sources. exchange through interconnectors; can be exchange through interconnectors; firm interconnectors; to be linked to the PCI linked to the PCI process. link with the PCI process. process.

os Pr

342 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Missing a potentially significant source of Restricts regulators in their tariff approval Restricts regulators in their tariff approval Could prove complicated to set up such an income which could be spent on process and of TSOs on congestion income process and of TSOs on congestion arrangement; could mean that congestion interconnection and removing the biggest spending. income spending. income accumulated from one border is bottlenecks in the EU. spent on a different border or different MS. Additional reporting arrangements will be Could mean that congestion income necessary. accumulated from one border is spent on a Requires a decision to apportion generated different border or different MS. income to where needs are highest in Requires stronger role of ACER. European system. Will face national Additional reporting arrangements will be resistance. necessary. Will require additional reporting Requires stronger role of ACER. arrangements to be put in place.

C ons Requires stronger role of ACER.

Most suitable option(s): Option 2 – provides additional funding towards project which benefit the EU internal market as a whole, while still allowing for national decision making in the first instance. Considered the most proportionate response.

343 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Measures assessed under Problem Area 2, Option 2(2) CMs based on an EU-wide resource adequacy assessment

Improved resource adequacy methodology

Objective: Pan-European resource adequacy assessments

Option 0 Option 1 Option 2 Option 3

Do nothing. Binding EU rules requiring TSOs to Binding EU rules requiring ENTSO-E to Binding EU rules requiring ENTSO-E to carry National decision makers would continue to harmonise their methodologies for provide for a single methodology for out a single resource adequacy assessment for rely on purely national resource adequacy calculating resource adequacy + calculating resource adequacy + the EU + requiring MS to exclusively rely on it

n assessments which might inadequately take requiring MS to exclusively rely on them requiring MS to exclusively rely on them when arguing for CMs. account of cross-border interdependencies. when arguing for CMs. when arguing for CMs.

Due to different national methodologies,

cr ip

tio

national assessments are difficult to

D es compare.

Stronger enforcement: National resource adequacy assessments In addition to benefits in Option 1, it In addition to benefits in Options 1 & 2, it Commission would continue to face would become more comparable. would make it easier to embark on the would make sure that the national puzzles neatly difficulties to validate the assumptions single methodology. add up to a European picture allowing for underlying national methodologies including national/ regional/ European assessments. ensuing claims for Capacity Mechanisms Results are more consistent and comparable as

os (CMs). one entity (ENTSO-E) is running the same

Pr model for each country.

Even in the presence of harmonised Even in the presence of a single It would potentially reduce the 'buy-in' from methodologies national assessment methodology, national assessments national TSOs who might still be needed for would not be able to provide a regional would not be able to provide a regional validating the results of ENTSO-E's work. or EU picture. or EU picture. National TSOs might be overcautious and not take appropriately cross-border interdependencies into account. Difficult to coordinate the work as the

C ons EU has 30+ TSOs.

Most suitable option(s): Option 3 - this approach assesses best the capacity needs for resource adequacy and hence allows the Commission to effectively judge whether the proposed introduction of resource adequacy measures in single Member States is justified.

344 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Cross-border operation of capacity mechanisms

Objective: Framework for cross-border participation in capacity mechanisms

Option 0 Option 1 Option 2

Do nothing. Harmonised EU framework setting out procedures including roles Option 1 + EU framework harmonising

No European framework laying out the details of an effective crossand responsibilities for the involved parties (e.g. resource the main features of the capacity

n border participation in capacity mechanisms. Member States are likely providers, regulators, TSOs) with a view to creating an effective mechanisms per category of

tio to continue taking separate approaches to cross-border participation, cross-border participation scheme. mechanism (e.g. for market-wide

cr ip including setting up individual arrangements with neighbouring capacity mechanisms, reserves, …). markets.

D es

Stronger enforcement It would reduce complexity and the administrative impact for In addition to benefits in Option 1, it The Commission's Guidance on state interventions 41 and the EEAG market participants operating in more than one MS/bidding zone. would facilitate the effective require among others that such mechanisms are open and allow for the It would remove the need for each MS to design a separate participation of foreign capacity as it participation of resources from across the borders. There is no reason to individual solution – and potentially reduce the need for bilateral would simplify the design challenge believe that the EEAG framework is not enforced. To date, however, negotiations between TSOs and regulators. and would probably increase overall there are not many practical examples of such cross-border schemes. It would preserve the properties of market coupling and ensure that efficiency by simplifying the range of the distortions of uncoordinated national mechanisms are corrected rules market participants, regulators

os and internal market able to deliver the benefits to consumers. and system operators have to

Pr understand.

As the conclusion of individual cross-border arrangements depend on It would be a cost for TSOs and regulators which would have to In addition to the drawback of Option the involved parties' willingness to cooperate it is likely that this option agree on the rules and enforce them across the borders. These 1, it would limit the choice of will cement the current fragmentation of capacity mechanisms. costs would be lower than in Option 0 though. instruments. Arranging cross-border participation on individual basis is likely to involve high transaction costs for all stakeholders (TSOs, regulators,

C ons ressource providers).

Most suitable Option(s): Options 1 and 2

41 http://ec.europa.eu/energy/sites/ener/files/documents/com_2013_public_intervention_swd01_en.pdf

345 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Options for measures assessed under Problem Area 3: a new legal framework for preventing and managing crises situations

Objective: Ensure a common and coordinated approach to electricity crisis prevention and management across Member States, whilst avoiding undue government intervention

Option 0: Do nothing Option 0+: Non Option 1: Common minimum EU Option 2: Common minimum EU rules plus regional Option 3: Full regulatory rules for prevention and crisis cooperation, building on Option 1 harmonisation and full approach management decision-making at regional level, building on Option 2

  This option was disregarded as no means for enhanced

implementation of the existing acquis nor for enhanced voluntary cooperation were identified

Rare/extreme risks and Member States to identify and assess ENTSO-E to identify cross-border electricity crisis All rare/extreme risks short-term risks related rare/extreme risks based on common scenarios caused by rare/extreme risks, in a regional undermining security of to security of supply are risk types. context. Resulting crisis scenarios to be discussed in the supply assessed at the EU

ts assessed from a national Electricity Coordination Group. level, which would be

en perspective. prevailing over national

ssm Common methodology to be followed for short-term risk assessment.

Risk identification & assessments (ENTSO-E Seasonal Outlooks and week

A sse assessment methods ahead assessments of the RSCs).

differ across Member States.

346 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Member States take Member States to develop mandatory Mandatory Risk Preparedness Plans including a national Mandatory Regional Risk measures to prevent and national Risk Preparedness Plans and a regional part. The regional part should address Preparedness Plans, subject to prepare for electricity setting out who does what to prevent cross-border issues (such as joint crisis simulations, and binding opinions from the crisis situations and manage electricity crisis situations. joint arrangements for how to deal with situations of European Commission. focusing on national simultaneous crisis) and needs to be agreed by Member approach, and without Plans to be submitted to the States within a region. Detailed templates for the sufficiently taking into Commission and other Member States plans to be followed. account cross-border for consultation. impacts. Plans to be consulted with other Member States in each A dedicated body would be

s Plans need to respect common region and submitted for prior consultation and created to deal with

an No common approach minimum requirements. As regards recommendations by the Electricity Coordination Group. cybersecurity in the energy

Pl to risk prevention & cybersecurity, specific guidance would sector.

preparation (e.g., no be developed. Member States to designate a 'competent authority' as common rules on how responsible body for coordination and cross-border to tackle cybersecurity cooperation in crisis situations. risks). Development of a network code/guideline addressing specific rules to be followed for the cybersecurity.

Extension of planning & cooperation obligations to Energy Community partners.

347 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Each Member State Minimum common rules on crisis Minimum obligation as set out in Option 1. Crisis is managed according takes measures in prevention and management (including to the regional plans, reaction to crisis the management of simultaneous Cooperation and assistance in crisis between Member including regional loadsituations based on its electricity crisis) requiring Member States, in particular simultaneous crisis situations, should shedding plans, rules on own national rules and States to: be agreed ex-ante; also agreements needed regarding customer categorisation, a technical TSO rules. financial compensation. This also includes agreements on harmonized definition of (i) not to unduly interference with where to shed load, when and to whom. Details of the 'protected customers' and a

t No co-ordination of markets; cooperation and assistance arrangements and resulting detailed 'emergency rulebook' actions and measures compensation should be described in the Risk set forth at the EU level.

emen beyond the technical (ii) to offer assistance to others where Preparedness Plans.

ag (system operation) needed, subject to financial an level. In particular, compensation, and to; m there are no rules on

how to coordinate (iii) inform neighbouring Member

C ri

sis actions in simultaneous States and the Commission, as of the crisis situations between moment that there are serious adjacent markets. indications of an upcoming crisis and during a crisis.

No systematic information-sharing (beyond the technical level). Monitoring of security Systematic discussion of ENTSO-E Systematic monitoring of security of supply in Europe, on A European Standard (e.g. for of supply predominatly Seasonal Outlooks in ECG and follow the basis of a fixed set of indicators and regular outlooks EENS and LOLE) on Security

ri ng

at the national level. up of their results by Member States and reports produced by ENTSO-E, via the Electricity of Supply could be developed concerned. Coordination Group. to allow performance

ito ECG as a voluntary monitoring of Member States. on information exchange Systematic reporting on electricity crisis events and

M platform. development of best practices via the Electricity

Coordination Group.

348 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Minimum requirements for plans Common methodology for assessments would allow Regional plans would ensure would ensure a minimum level of comparability and ensure compatibility of SoS measures full coherence of actions taken preparedness across EU taking into across Member States. Role of ENTSO-E and RSCs in in a crisis. account cyber security. assessment can take into account cross-border risks.

EU wide minimum common principles Risk Preparedness Plans consisting of a national and would ensure predictability in the regional part would ensure sufficient coordination while triggers and actions taken by Member respecting national differences and competences. States. Minimum level of harmonization for cybersecurity throughout the EU.

Designation of competent authority would lead to clear responsibilities and coordination in crsis.

Common principles for crisis management and agreements regarding assistance and remuneration in simultaneous scarcity situations would provide a base for mutual trust and cooperation and prevent unjustified intervention into market operation.

Enhanced role of ECG would provide adequate platform os for discussion and exchange between Member States and

Pr regions.

Lack of cooperation in Risk assessment and preparedness The coordination in the regional context requires Regional risk preparedness risk preparedness and plans on national level do not take into administrative resources. plans and a detailed templates managing crisis may account cross-border risks and crisis would have difficulties to fit distort internal market which make the plans less efficient and Cybersecurity here only covers electricity, whereas the in all national specificities. and put at risk the effective. provisions should cover all energy sub-sectors including security of supply of oil, gas and nuclear. Detailed emergency rulebook neighbouring countries. Minimum principles of crisis might create overlaps with management might not sufficiently existing Network Codes and

C ons adress simultaneous scarcity situations. Guidelines.

Most suitable: Option 2, as it provides for sufficient regional coordination in preparation and managing crisis while respecting national differences and competences.

349 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Measures assessed under Problem Area 4: The slow deployment of new services, low levels of service and poor retail market performance

Addressing energy poverty

Objective: Better understanding of energy poverty and disconnection protection to all consumers

Option: 0 Option: 0+ Option 1 Option 2 BAU: sharing of good practices. BAU: sharing of good Setting an EU framework to monitor Setting a uniform EU framework to monitor energy practices and increasing the energy poverty. poverty, preventative measures to avoid disconnections efforts to correctly implement and disconnection winter moratorium for vulnerable the legislation. consumers. Voluntary collaboration across Member States to agree on scope and measurement of energy poverty.

Energy poverty EU Observatory of Energy Option 0+: EU Observatory of Energy Option 0+: EU Observatory of Energy Poverty (funded poverty (funded until 2030). Poverty (funded until 2030). until 2030).

Generic description of the term energy Specific definition of energy poverty based on a share poverty in the legislation. Transparency of income spent on energy. in relation to the meaning of energy Member States to measure energy poverty using poverty and the number of households in required energy. a situation of energy poverty Better implementation and transparency as in Option 1. Member States to measure energy poverty. Better implementation of the current provisions.

Disconnection NRAs to monitor and report NRAs to monitor and report figures on NRAs to monitor and report figures of disconnections. safeguards figures on disconnections. disconnections. A minimum notification period before a disconnection.

All customers to receive information on the sources of support and be offered the possibility to delay payments or restructure their debts, prior to disconnection. Winter moratorium of disconnections for vulnerable consumers.

Pros Continuous knowledge exchange. Stronger enforcement of Clarity on the concept and measuring of Standardised energy poverty concept and metric which current legislation and energy poverty across the EU. enables monitoring of energy poverty at EU level.

continuous knowledge Equip MS with the tools to reduce disconnections. exchange.

Cons Existing shortcomings of the Insufficient to address the New legislative proposal necessary. New legislative proposal necessary. legislation are not addressed: lack shortcomings of the current Administrative costs. Higher administrative costs.

of clarity of the concept of energy legislation with regard to Potential conflict with principle of subsidiarity. poverty and the number of energy energy poverty and targeted Specific definition of energy poverty may not be

350 Annex VIII: Summary tables of options for detailed measures assessed under each main option

poor households persist. protection. suitable for all MS. Energy poverty remains a vague Safeguards against disconnection may result in higher concept leaving space for MS to costs for companies which may be passed to continue inefficient practices such consumers. as regulated prices. Safeguards against disconnection may also result in Indirect measure that could be market distortions where new suppliers avoid entering viewed as positive but insufficient markets where risks of disconnections are significant by key stakeholders. and the suppliers active in such markets raise margins for all consumers in order to recoup losses from unpaid bills. Moratorium of disconnection may conflict with freedom of contract.

Most suitable option: Option 1 is recommended as the most balanced package of measures in terms of the cost of measures and the associated benefits. Option 1 will result in a clear framework that will allow the EU and Member States to measure and monitor the level of energy poverty across the EU. The impact assessment found that the propose disconnection safeguards in Option 2 come at a cost. There is potential to develop these measures at the EU level. However, Member States may be better suited to design these schemes to ensure that synergies between national social services and disconnection safeguards can be achieved. Please note that Option 1 and Option 2 also include the measures described in Option 0+.

5

351

Annex VIII: Summary tables of options for detailed measures assessed under each main option

Phasing out regulated prices

Objective: Removing market distortions by achieving the phase-out of supply price regulation for all customers.

Option: 0 Option 1 Option 2a Option 2b

Making use of existing acquis to continue Requiring MS to progressively phase out price Requiring MS to progressively phase Requiring MS to progressively phase out below bilateral consultations and enforcement regulation for households by a deadline out price regulation, starting with cost price regulation for households by a deadline actions to restrict price regulation to specified in new EU legislation, starting with prices below costs, for households specified in new EU legislation. proportionate situations justified by general prices below costs, while allowing transitional, above a certain consumption threshold economic interest, accompanied by EU targeted price regulation for vulnerable to be defined in new EU legislation or guidance on the interpretation of the current customers (e. g. in the form of social tariffs). by MS. acquis.

Pros: Pros: Pros: Pros:

• - 

  Allows a case-by-case assessment of the - Removes the distortive effect of price - Limits the distortive effect of price - Limits the distortive effect of price regulation proportionality of price regulation, taking into regulation after the target date. regulation. and tackles tariff deficits where existent. account social and economic particularities in - Ensures regulatory predictability and - Would reduce the scope of price

MS transparency for supply activities across the regulation therefore limiting its

EU. distortive impact on the market. Cons: Cons: Cons: Cons: - Leads to different national regimes following - Difficult to take into account social and - Difficult to take into account social - Defining cost coverage at EU level is case-by-case assessments. This would economic particularities in MS in setting up a and economic particularities in MS in economically and legally challenging. maintain a fragmented regulatory framework common deadline for price deregulation. defining a common consumption - Implementation implies considerable regulatory across the EU which translates into threshold above which prices should and administrative impact. administrative costs for entering new markets. be deregulated. - Price regulation even if above cost risks holding

back investments in product innovation and service quality.

Most suitable option(s): Option 1 - Setting an end date for all price intervention would ensure the complete removal of market distortions related to end-user price regulation and help create a level playing field for supply activities across the EU while allowing targeted protection for vulnerable customers and/or energy poor.

352 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Level playing field for access to data

Objective: Creating a level playing field for access to data.

Option: 0 Option 1 Option 2

BAU - Define responsibilities in data handling based on appropriate definitions in the - Impose a specific EU data management model (e.g. an

Member States are primarily EU legislation. independent central data hub) responsible on deciding roles and - Define criteria and set principles in order to ensure the impartiality and non- Define specific procedures and roles for the operation of responsibilities in data handling. discriminatory behaviour of entities involved in data handling, as well as timely such model.

and transparent access to data. - Ensure that Member States implement a standardised data format at national

level. Pro Pro Pro Existing framework gives more The above measures can be applied independently of the data management model Possible simplification of models across EU and easier flexibility to Member States and NRAs that each Member State has chosen. enforcement of standardized rules. to accommodate local conditions in The measures will increase transparency, guarantee non-discriminatory access and their national measures. improve competition, while ensuring data protection.

Con Con Con

The current EU framework is too High adaptation costs for Member States who have already general when it comes to decided and implementing specific data management models. responsibilities and principles. It is not Such a measure would disproportionally affect those Member fit for developments which result from States that have chosen a different model without necessarily the deployment of smart metering improving performance. systems. A specific model would not necessarily fit to all Member

States, where solutions which take into account local conditions may prove to be more cost-efficient and effective.

Most suitable option(s): Option 1 is the preferred option as it will improve current framework and set principles for transparent and non-discriminatory data access from eligible market parties. This option is expected to have a high net benefit for service providers and consumers and increase competition in the retail market.

353 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Facilitating supplier switching

Objective: Facilitating supplier switching by limiting the scope of switching and exit fees, and making them more visible and easier to understand in the event that they are used.

Option 0 Option 0+ Option 1 Option 2

BAU/Stronger enforcement Stronger enforcement, following the Legislation to define and outlaw all fees to Legislation to define and outlaw all fees to clarification of certain concrete EU household consumers associated with EU household consumers associated with requirements in the current legislation switching suppliers, apart from: 1) exit fees switching suppliers.

through an interpretative note. for fixed-term supply contracts; 2) fees associated with energy efficiency or other bundled energy services or investments. For both exceptions, exit fees must be costreflective.

Pros: Pros: Pros: Pros:

• - 

  Evidence may suggest a degree of non- Non-enforcement may be due to complex - Considerably reduces the prevalence of - Completely eliminates one enforcement of existing legislation by existing legislation. fees associated with switching suppliers, financial/psychological barrier to switching. national authorities. - No new legislative intervention necessary. and hence financial/psychological barriers - Simple measure removes doubt amongst

• - 

  No new legislative intervention necessary. to switching. consumers.

  • - 

    The clearest, most enforceable requirement without exceptions.

Cons: Cons: Cons: Cons:

• - 

  Continued ambiguity in existing - The vast majority of switching-related fees - Marginally reduces the range of contracts - Would further restrict innovation and legislation may impede enforcement. faced by consumers are permitted under available to consumers, thereby limiting consumer choice, notably regarding

• - 

  The vast majority of switching-related fees current EU legislation. innovation. financing options for beneficial investments faced by consumers are permitted under - Certain MS might ignore the interpretative - An element of interpretation remains in energy equipment as part of innovative current EU legislation. note. around exceptions to the ban on fees supply products e.g. self-generation, energy

  associated with switching suppliers. efficiency, etc. - Impedes the EU's decarbonisation objectives, albeit marginally.

Most suitable option(s): Option 1 is the preferred option, as it represents the most favourable balance between probable benefits and costs.

354 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Comparison tools

Objective: Facilitating supplier switching by improving consumer access to reliable comparison tools.

Option 0+ Option 1 Option 2

Cross-sectorial Commission guidance addressing the applicability of the Unfair Legislation to ensure every Member State has at Legislation to ensure every Member State appoints an

Commercial Practices Directive to comparison tools least one 'certified' comparison tool that complies independent body to provide a comparison tool that with pre-specified criteria on reliability and serves the consumer interest

impartiality Pros: Pros: Pros: - Facilitates coherent enforcement of existing legislation. - Fills gaps in existing legislation vis-à-vis energy - NRAs able to censure suppliers by removing their - Light intervention and administrative impact. comparison tools. offers from the comparison tool. - Cross-sectorial consumer legislation already requires comparison tools to be - Limited intervention in the market, in most cases. - No obligation on private sector. transparent towards consumers in their functioning so as not to mislead - Allows certifying all existing energy comparison - Reduces risks of favouritism in certification consumers (e.g. ensure that advertising and sponsored results are properly tools regardless of ownership. process. identifiable etc.). - Proactively increases levels of consumer trust. - Proactively increases levels of consumer trust. - Cross-sectorial approach addresses shortcomings in commercial comparison - Ensures EU wide access. tools of all varieties. - The certified comparison websites can become - Cross-sectorial approach minimizes proliferation of sector-specific market benchmarks, foster best practices among legislation. competitors Cons: Cons: Cons: - Does not apply to non-profit comparison tools. - Existing legislation already requires commercial - To be effective, Member States must provide - Does not proactively increase levels of consumer trust. comparison tools to abide by certain of the criteria sufficient resources for the development of such tools - The existing legislation does not oblige comparison tools to be fully impartial, addressed by certification. to match the quality of offerings from the private comprehensive, effective or useful to the consumer. - Requires resources for verification and/or sector.

certification. - Well-performing for-profit tools could be side-lined - Significant public intervention necessary if no by less effective ones run by national authorities. comparison tools in a given MS meet standards.

Most suitable option(s): Option 1 is the preferred option because it strikes the best balance between consumer welfare and administrative impact. It also gives Member States control over whether they feel a certification scheme or a publicly-run comparison tool best ensures consumer engagement in their markets.

355 Annex VIII: Summary tables of options for detailed measures assessed under each main option

Improving billing information

Objective: Ensuring that all consumer bills prominently display a minimum set of information that is essential to actively participating in the market.

Option: 0 Option 0+ Option 1 Option 2

BAU/Stronger enforcement Commission recommendation on billing More detailed legal requirements on the key A fully standardized 'comparability box' in bills information information to be included in bills

Pros: Pros: Pros: Pros:

• - 

  77% of energy consumers agree or strongly - Low administrative impact - Ensures that the minimum baseline of - Highest legal clarity and comparability of agree that bills are "easy and clear to - Gives MS significant flexibility to existing practices is clarified and raised. offers and bills. understand". adapt their requirements to national - Allows best practices to further develop, - A level playing field for all consumers and

• - 

  Allows 'natural experiments' and other conditions. albeit less than Option 0. suppliers across the EU. innovation on the design of billing information - Allows best practices to further - Improves comparability and portability of - Very little leeway for suppliers to differently to be developed by MS. develop. information. interpret the legislation with regards to the

• - 

  Recent (2014) transposition of the EED means - Ensures consumers can easily find the presentation of information. premature to address information on energy information elements needed to facilitate - Ensures consumers can easily find the consumption and costs. switching. information elements needed to facilitate

  • - 

    Bill design left free to innovation. switching. Cons: Cons: Cons: Cons:

• - 

  Poor consumer awareness of market-relevant - A recommendation is unenforceable - Limits innovation around certain bill - Challenging to devise standard presentation information can be expected to continue. and may be ignored by MS/utilities. elements. which can accommodate differences between - Does not respond to stakeholder feedback on - Poor consumer awareness of market- Remaining leeway in interpreting legal national markets. need to ensure minimum standards. relevant information can be expected to articles may lead to implementation and - Highest administrative impact.

  continue. enforcement difficulties. - Prescriptive approach prevents beneficial - Does not respond to stakeholder innovation. feedback on need to ensure minimum - Difficult to adapt bills to evolving technologies standards. and consumer preferences.

Most suitable option(s): Option 1 is the preferred option as it likely to leads to significant economic benefits and increased consumer surplus without significant administrative costs or the risk of overly-prescriptive legislation at the EU level.

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356 Annex VIII: Summary tables of options for detailed measures assessed under each main option

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