kom (2016) 0863 - Ingen titel

Europaudvalget 2016
KOM (2016) 0863
Offentligt

EUROPEAN

COMMISSION

Brussels, 30.11.2016

SWD(2016) 410 final

PART 2/5

COMMISSION STAFF WORKING DOCUMENT

IMPACT ASSESSMENT

Accompanying the document

Proposal for a Directive of the European Parliament and of the Council on common

rules for the internal market in electricity (recast)

Proposal for a Regulation of the European Parliament and of the Council on the

electricity market (recast)

Proposal for a Regulation of the European Parliament and of the Council establishing

a European Union Agency for the Cooperation of Energy Regulators (recast)

Proposal for a Regulation of the European Parliament and of the Council on risk

preparedness in the electricity sector

{COM(2016) 861 final}

{SWD(2016) 411 final}

{SWD(2016) 412 final}

{SWD(2016) 413 final}

kom (2016) 0863 - Ingen titel

TABLE OF CONTENTS

ANNEXES ................................................................................................................................ 241

Annex I: Procedural information .................................................................................................. 241

Annex II: Stakeholder consultations ............................................................................................. 249

Annex III: Who is affected by the initiative and how.................................................................... 264

Annex IV: Analytical models used in preparing the impact assessment. ..................................... 281

Annex V: Evidence and external expertise used........................................................................... 315

Annex VI: Evaluation..................................................................................................................... 321

Annex VII: Overview of electricity network codes and guidelines ............................................... 323

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

...................................................................................................................................................... 325

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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.

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Comments made by RSB in first Opinion

Modifications made in reaction to

of 16 September 2016

comments RSB

Issues cross cutting to other impact assessments

This IA and the IA on the revision of the

An explicit vision of the EU electricity

renewables directive need a coherent analysis market has been incorporated in section

of renewable electricity support schemes.

1.1.1.4. This vision includes a section on the

They need to reconcile different expectations connection with the share of RES E and

of what the market will deliver in terms of the prosumers.

share of renewable electricity and of the

participation of prosumers. Given uncertainty

on these issues, both IAs should incorporate

the same range of possible outcomes in their

analysis

The IA should clarify and explain the content A dedicated section was included in Annex

and assumptions of the baseline scenario in

IV clarifying all points raised concerning the

relation to the other parallel initiatives

baseline, REF2016 and EUCO27.

The baseline description in 5.1.2, 5.2.2,

6.1.1.2 and 6.1.1.4 was improved and

references were made to its more detailed

description in the Annex.

Issues specific to the present impact assessment

The IA report is too long and complex to

A plain-language abstract has been added at

make it helpful in informing political

the beginning of the document.

decisions. The Board recommends that this

report begin with a concise, plain-language

abstract of approximately 10-15 pages. This

abstract should summarise the key elements

of the IA and identify the main policy trade-

offs

The report should present a clear vision for

An explicit vision of the EU electricity

the EU electricity market in 2030 and beyond market has been incorporated in section

with a distinction between immediate

1.1.1.4 covering issues mentioned.

challenges and longer term developments.

This vision needs to be coherent with EU

A detailed section on in RES E in connected

policies on competition, climate and energy.

with the MDI is contained in a text box in

It also needs to be consistent with the parallel section 6.2.6.3. Another box is located in

initiatives, notably the revision of the RES

Section 2.1.3.

Directive. In particular, this applies to the

assumptions and expectations on what the

new electricity market design could deliver

Further clarifications have been added in

on its own and whether the renewable target

requires complementary market intervention. section 1.2.1 on interlinkages with RED II.

Based on a common (with other parallel

A dedicated section was introduced in Annex

initiatives) baseline scenario, the report

IV clarifying all points raised concerning the

should prioritise the issues to be addressed,

baseline, REF2016 and EUCO27.

present an appropriate sequencing and

strengthen the treatment of subsidiarity

The baseline description in 5.1.2, 5.2.2,

considerations such as for action related to

6.1.1.2 and 6.1.1.4 was improved and

energy poverty and distribution system

references were made to its more detailed

operators.

description in the Annex.

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Comments made by RSB in first Opinion

of 16 September 2016

Modifications made in reaction to

comments RSB

A dedicated section on sequencing was

introduced as section 7.5.3

Regarding the treatment of subsidiarity for

actions related to energy poverty, please see

sections 5.4.4; and 5.4.5. The report assesses

the options with regards to subsidiarity. It

argues that measures in Option 1 are

proportionate and in line with the subsidiarity

principle while measures in Option 2 entail

significant costs and may be better carried out

by national authorities.

When assessing the impacts of the different

On how the models of "energy only markets"

options, the report should indicate whether

will coexist with CMs, clarifications have

and how the models of “energy only markets”

been introduced in section 2.2.2.

will coexist with capacity mechanisms and

assess the risks of an uncoordinated

Section 6.2.6 now includes a sub-section on

introduction of capacity remuneration

investments, discussing all relevant issues.

mechanisms across the EU. The impact

analysis should also report on the

effectiveness of the options to deliver the

adequate investment and price responses.

Main recommendations for improvements

The analysis of support schemes for

An explicit vision of the EU electricity

renewable electricity should be consistent

market has been incorporated in section

across this impact assessment and the one

1.1.1.4. This includes a vision on whether

outside-the- market measures to support for

covering renewable energy sources. The

RES E are needed up to 2030. The question

reports should clarify what support schemes

will be needed, and whether these are needed what type of out-of-market support

mechanisms are needed falls within the remit

only in case the market fails to deliver the

of the RED II IA.

2030 EU target of at least 27% of RES in

final energy consumption, or will be used to

A dedicated section was included in Annex

promote certain types of renewable energy.

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.

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Comments made by RSB in first Opinion

of 16 September 2016

Modifications made in reaction to

comments RSB

The clarification in Annex IV as regards the

baseline explains how, the impact

assessments for the MDI and RES E are fully

compatible, including as regards to the

tendering procedure (see section on current

market arrangements in Annex IV).

Text adapted in section 2.2.2 and included a

reference to forthcoming report by DG

Competition.

In addition, even though the report does not

present a blueprint for a capacity

remuneration mechanism (as it is in the remit

of the state-aid guidelines/EU competition

policy), it should analyse possible detrimental

effects of such mechanisms being introduced

in the EU in an uncoordinated fashion. In

particular, the IA should examine distortions

to investment incentives and price setting

mechanisms.

The expected involvement of consumers and

prosumers in supplying electricity and

managing its demand has to be consistent

across the two impact assessments.

An explicit vision of the EU electricity

market has been incorporated in section

1.1.1.4.

This includes a vision on prosumers and the

risk of disconnection, which is further

The analysis should integrate the effects of

developed in a text box in Section 6.1.4.2.

potentially more volatile electricity prices and Also the RED II IA has been adjusted.

high fixed network costs on prosumer

involvement and on the long-term risk that

these might disconnect from the network as

local storage technology evolves.

In devising the options, the report should be

See section 2.4.1 and section 5.4.4. The

proportionate to the importance of the

report clarifies the main objective of the

problems/objectives and realistic in assessing measures linked to energy poverty (i.e.

what can be achieved. For instance, options

description of the term 'energy poverty' and

linked to the issue of energy poverty (being

measurement of energy poverty), which

part of the social policy) should be built

already apply to Member States (Member

around increasing transparency and peer

States should address energy poverty where it

pressure among Member States rather than

is identified). Better monitoring of energy

the single market motive.

poverty across the EU will, on one hand, help

Member States to be more alert about the

number of households falling into energy

poverty, and on the other hand, peer pressure

encourages Member States to put in place

measures to reduce energy poverty.

The baseline scenario should be clarified,

A dedicated section was included in Annex

including the link with the 2016 reference

IV clarifying all points raised concerning the

scenario and underlying assumptions

baseline, REF2016 and EUCO27.

Some more technical comments have been

All technical comments have been addressed.

transmitted directly to the author DG and are

expected to be incorporated into the final

version of the impact assessment report

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Comments made by RSB in first Opinion

of 16 September 2016

The IA report needs to be more reader-

friendly and helpful for decision-making. The

report should contain a 10-15 page abstract

that succinctly presents the main elements of

the analysis, the policy trade-offs and the

conclusions. The main text should be

streamlined to contain the crucial elements of

the analysis in the main part of the report

Modifications made in reaction to

comments RSB

A reader friendly abstract that succinctly

presents the main elements of the analysis,

the policy trade-offs and the conclusions has

been added to the main text of the IA.

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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

explanations, which was added following

that undistorted markets deliver the right

the RSB comments.

price signals for investment. The report

should more convincingly explain how

adequate pricing could be achieved in the

presence of national capacity markets and

subsidies for renewables which might

exacerbate excess capacity in the market.

The report should assess the risk of

persistent low electricity wholesale prices

and associated consequences for the

effectiveness of the initiative. What would

be the effects for investment, demand

response, elimination of subsidies, and

consumer benefits?

Further recommendations for improvements

Internal coherence and risks:

Text has been added to Sections 8.1 and

The analysis in the report demonstrates

8.2.2 with regard to the reviewing of

that the vision for the EU electricity

assumptions and monitoring of

market in 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 present report, it has been rendered more

at intermediate stages. The text of the

clearly what elements of the RED II

report should reflect the trade-off between initiative are important to the impacts of

restoring the EU internal energy market in the 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

maintain security of supply.

Section 6.4.6 and Annex IV.

It is noted that improving market

functioning reduces the need for

government intervention with regard to

both RES E (See Section 1.1.1.4, Box 7

below section 6.2.6.3 and section 7.5.1)

and resource adequacy (See section 6.2.2.1,

Section 6.2.6.3 and Section 7.5.1).

Impact analysis:

The vision of an energy The risks of greater price variability have

Union places citizens at its core. The

been introduced in two new text boxes in

report should therefore better address the Section 5.1.4.3 (Box 4) of the main impact

risks and benefits to consumers, especially assessment document, and in Section 3.1.5

with regard to expected higher price

of the Annexes to the Impact Assessment.

variability. It should discuss not just

These specifically address the benefits and

possible long run benefits, but also costs

risks of dynamic electricity pricing

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Comments made by RSB in second

Modifications made in reaction to

Opinion on 7 November 2016

comments RSB

(including switching fees) in the short and contracts, which are a frequent concern of

medium term. In the same vein, the report consumer groups.

should examine the 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 based on modelling, the results of the

modelling should be critically reviewed to

avoid false expectations, in view of many

assumptions taken. For instance, the

modelling results in the average level of

wholesale

prices at 74€/MWh already in

2020 and 103€/MWh in 2030). The

attainment of these price levels is hard to

imagine in reality, given that currently that

level is around 34€ and more renewable

capacity is being deployed into the system,

still benefitting from the current support

schemes for RES-E (based mostly on feed-

in tariffs). Lower than modelled wholesale

prices could seriously undermine the

investment outcome, the assumed

increased engagement of consumers and

demand response

–

the cornerstones of the

EU Energy Union.

Similarly, the effectiveness of the revised

RES-E support schemes (as proposed in

the RED II IA) is not critically discussed.

First, the report needs to emphasize that

they would not be based on any type of

feed-in tariff but premiums on top of

market revenues and these premium will

be auctioned. Second, the report needs to

consider the fact that such auctions may

not necessarily be effective in reducing the

support to renewable energy sources. This

is particularly relevant in a situation where

the share of renewables in the electricity

generation mix is expected to grow

To improve clarity, the new Box 9 includes

further explanations. Please also see new

footnotes 345 and 384

It has been made clearer that market based

support schemes, such as premium schemes

combined with auctions, are an underlying

premise of the impacts of the present

initiative. (See section 1.1.1, 1.2.1, Box 7

under section 6.2.6.3, Box 9 underneath

section 6.4.6 and Annex IV)

The phase-out of non-market based support

schemes has already commenced under the

EEAG adopted in 2014 and is further

reinforced by the measures proposed by

RED II. It is therefore assumed that non-

market based support schemes are fully

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Comments made by RSB in second

Modifications made in reaction to

Opinion on 7 November 2016

comments RSB

substantially and the wholesale prices will phased out by 2024, whereas the impact

be depressed at least until the current

assessment looks at the situation in 2030.

support schemes for RES-E are reviewed For more detail see Annex IV.

in 2024.

The cost effectiveness of the RES E

support schemes as such is the subject of

the RED II impact assessment.

Procedure and presentation

While the report is still very long, the

References to policy trade-offs (market

inclusion of the abstract has improved the versus government intervention) have been

presentation of relevant information,

further emphasised. See for instance the

though the issue of policy trade-offs

abstract, page 10 and 13 and Sections

(market vs. government interventions)

6.2.2.1, 6.2.6.3 and 7.5.1. Furthermore,

should be emphasized more explicitly

Options 2 and 3 under problem area II

expressly seek to address the compatibility

of government intervention in a market

context.

An overview of evidence and external expertise used is provided in a separate annex.

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Annex 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

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.

https://ec.europa.eu/energy/sites/ener/files/documents/20130207_generation_adequacy_consultation_d

ocument.pdf

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The following paragraphs provide a summary of the responses available on the

Commission's website

. The responses and a summary thereof are also available on the

Commission's website

(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

–

particular there is a conflict between the market driven approach to liberalisation

and to EU ETS and the various sectoral targets in renewables, energy efficiency

etc."

The Netherlands (Ministry of Economic Affairs)

responded "the absence of a

credible carbon policy and a lack of proper market functioning cannot be

underestimated";

Market functioning.

In the context of a weak demand and economic crisis, Europe's

energy markets today area was deemed characterised by two developments: the

integration of large amounts of renewables and the implementation of the EU target

model. This was clearly reflected in the responses to this consultation. Overall

respondents' opinions were split as to whether energy-only markets could deliver

investments needed to ensure generation adequacy and security of supply.

However, there is near unanimous support from respondents for the importance of

the completion of the integration of day-ahead, and close to real time markets as a

an important contributor to security of supply although, some respondents caution

that this will not address fundamental problems with whether energy-only markets

can deliver resource adequacy Similarly, there are strong calls facilitating demand

side response and the development of grids in line with the ten year network

development plan. Almost all responses to the consultation raised the impact of

RES E on the market. For example the UK response discusses the impact that more

low marginal cost pricing will have on the market, and the issue is discussed in

detail in the Clingendael paper submitted in response to the consultation. Industry

in particular raised the issue about the impact that RES E support schemes had on

the market. While many raise the issue of any out-of-market support creating

distortions, the position set out in the response of Eneco, a Dutch company is worth

quoting

"In general, support for specific energy sources does not undermine

investments to ensure generation adequacy, it just changes the merit order. But

details of support mechanisms can, specifically if a support mechanism lowers the

value of flexibility".

This consideration can be seen in the numbers of 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

(ii)

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

nergy%20Market.pdf

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

and-internal-market-electricity

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their response

"Allerdigs ist ein Umstieg von der Festvergutuetung unter der

garantierten Abnahme des EE-Stroms auf ein System der Marktintergration

notwendig, in dem die Erneueuerbaren ihre Einspeisung an dem Marktpreissignal

orientieren…".

(iii)

Assessing security of supply.

There is widespread recognition of a need for

improved assessment of generation and security of supply in the internal market

given the impact of both RES E and market integration. Proposal have been made

suggesting a need for more scenario analysis based on different weather conditions,

different timespans for the assessment (long-term, short-term), more detailed

assessment of flexibility and more coordination between TSOs and more sensitivity

analysis. In this regard the existing ENTSO-E generation adequacy assessment is

not felt to meet future needs, without suggesting that ENTSO-E is not carrying out

its current role properly. There is particularly strong support for more regional

generation adequacy assessments combined with a common methodology for

undertaking such assessments. For example France in its response states

"Il

pourrait notamment être utile de renforcer la cohérence à l’échelle régionale des

différentes méthodes d’analyse et des scénarios produits

au niveau national,

souvent interdépendants. Ces analyses régionales viendraient ensuite alimenter un

exercice réalisé à l’échelle de l’Union".

Support for binding standards is less strong

among respondents. Many of those who, in principle, would welcome common

standards point to the difficulties in establishing such standards while MS retain

responsibility for Security of Supply (and hence determining standards). Others

(such as the Oeko institute) consider that more harmonised activities of Member

states are essential in the internal market. There was limited support for a revision

of the Security of Supply directive, which was perceived to fulfil its limited role.

Again France states that

"Il apparaît préférable de privilégier l’élaboration rapide

de ces codes et achever ainsi la mise en oeuvre des dispositions du 3

ème

paquet

avant d’envisager des mesures nouvelles au travers de la refonte de cette

directive."

However some stated that since the Directive was adopted before the

Third Package, the situation after the Third Package is different and therefore the

level of cooperation prescribed by the Directive does not correspond to today's

situation. Summarising, there was widespread support for a reassessment of how

generation adequacy and security of supply are assessed, and a recognition for the

need for actions to be coordinated. The question which stands out is what are the

best tools to do this. Here the electricity coordination group ('ECG') (explicitly

mentioned by several respondents) can play a critical role. The Commission will

continue to examine what are the best tools available to achieve the widely

supported aim of improved generation adequacy assessment.

Interventions to ensure security of supply.

As already noted opinion is divided on

whether energy only markets can deliver the investments which will be needed to

ensure generation adequacy and security of supply in the future. However, there

were even more varied opinions on the effectiveness of different capacity

remuneration mechanisms. Given this divergence of opinion therefore there is only

limited support for a European blueprint, many respondents pointing to divergent

local circumstances and the need to address specific problems as 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

(iv)

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aid assessments, and notwithstanding caution about overly detailed assessment at

EU level its detailed comments on the individual criteria in the consultation paper

were broadly supportive. FR states

"Il est toutefois utile et légitime que la

Commission européenne suive de près l’impact des choix des Etats membres sur le

marché intérieur"

but also cautions that

"Il semble prématuré à ce stade de définir

des critères détaillés de compatibilité avec le marché intérieur".

DE states that the

Commission

"im Bedarfsfall eintreten, der die Koordinierung zwischen den MS zu

einer stärker gemeinsamen …Gewährleistung der Versorgungssicherheit

erleichtert.".

Consultation on the retail energy market

A public consultation dedicated to electricity retail markets and end-consumers

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

(v)

Retail competition.

Respondents to this public consultation felt that market-based

customer prices are an important factor in helping residential customers and SMEs

better control their energy consumption and costs (129 out of 237 respondents

considered that it was a very important factor while other 66 qualified it as

important for the achievement of the said objective). Moreover, out of 121

respondents who considered that the level of competition in retail energy markets

is too little, 45 recognised regulation of customer prices as one of the underlying

drivers.

81% of the respondents agreed that allowing other parties to have access to

consumption data in an appropriate and secure manner, subject to the consumer's

explicit agreement, is a key enabler for the development of new energy services for

consumers.

As regards whether it is sufficiently easy without facing disproportionate

permitting and grid connection procedures for a consumer to install and connect

renewable energy generation and micro-CHP pursuant to the provisions of the RES

and Energy performance in buildings Directives the views are split.

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(vi)

Consumer issues.

222 out of 237 respondents to the retail market public

consultation believed that transparent contracts and bills were either important or

very important for helping residential consumers and SMEs to better control their

energy consumption and costs.

When asked to identify key factors influencing switching rates, 89 respondents out

of 237 stated that consumers were not aware of their switching rights, 110 stated

that prices and tariffs were too difficult to compare due to a lack of tools and/or due

to contractual conditions, and 128 cited insufficient benefits from switching.

178 out of 237 agreed that ensuring the availability of web-based price comparison

tools would increase consumers' interest in comparing offers and switching to a

different energy supplier. 40 were neutral and 4 disagreed.

Only 32 out of 237 respondents agreed with the statement: "There is no need to

encourage switching". 98 disagreed and 90 were neutral.

(vii)

DSOs and network tariffs.

The majority of the respondents consider that DSOs

should carry out tasks such as data management, balancing of the local grid,

including distributed generation and demand response, and connection of new

generation/capacity (e.g. solar panels). The majority of stakeholders thought these

activities should be carried out under good regulatory oversight, with sufficient

independence from supply activities, while a clear definition of the role of DSOs

(and TSOs), but also of the relationship with suppliers and consumers, is required.

Regarding distribution network tariffs, 34% of the respondents consider that

European wide principles for setting distribution network tariffs are needed, while

another 34% is neutral and 26% disagree. Time-differentiated tariffs are supported

by ca 61% of the respondents, while the majority of stakeholders consider that cost

breakdown (78%) and methodology (84%) of distribution network tariffs should

be transparent.

The majority of stakeholders also consider that self-generators/auto-consumers

should contribute to the network costs even if they use the network in a limited

way. To this end, ca. 50% of the respondents consider that the further deployment

of self-generation with auto-consumption requires a common approach as far as the

contribution to network costs is concerned.

Regarding self- consumption, self- consumers should contribute to network costs

even if they use the network in a limited way and further deployment would require

a common approach. Moreover, however the responders think that to this end a

common approach with simplified related administrative procedures is required.

Granting of financial incentives by Member States to promote self-generation and

auto-consumption splits views evenly.

(viii)

Demand response.

Over 50% of the responders think that residential consumers

lack sufficient information to use energy efficiently and make use of advances in

innovation that have enabled a broad range of distributed generation and demand

response for industrial and commercial consumers. While the views are split in

respect to the ESCOs role to facilitate the favourable contractual arrangements and

other related services and as regards the access to respective choices of energy

efficiency services consumers have. Similarly, responders' views diverge when

assessing whether there should be done more to support the establishment of

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ESCOs that are active in the field of energy efficiency. In particular, 44% of the

answers indicate that indeed there is more room to support ESCOs establishment

and 28% of the answers received point out that are satisfied with the related service.

Moving on, the overwhelming majority industrial consumers are satisfied by their

access to demand response and balancing services while on the same question the

views coming from SMEs and commercial suppliers are split. Further, 24 of the

residential consumers have access to demand response and balancing services

while this percentage is 35% for the commercial sector and SMES and reached the

66% for industrial customers. As to the entity of the demand response service

provider, over than 70% of the responders believe that this service should be

provided by the suppliers, though 50% thinks that aggregators are also fit to provide

the service while a minority would allocate this task to the DSOs.

Most responders view that they should be able to be participating in aggregation

programmes irrespective of their load size in primary balance markets. The best

way of making this happen is through aggregators and developing products taken

into account consumers flexibility characteristics and size. In addition, responders'

tend to agree that related demand response products should be hassle-free,

applicable to all consumers' profiles. People also disagree with the claim that very

specific data management tasks with regards to various distribution network actors

should be defined at European level.

Suppliers are perceived as having the most access to dynamic pricing and/or time

differentiated tariffs. They should first and aggregators, as a second choice, offer

demand response services and dynamic pricing to residential consumers, SMEs.

Unclear benefits, regulatory barriers and then unclear legal framework are

identified as the greatest barriers to limited dynamic pricing in a country. Some

respondents indicated that strengthening of infrastructure will allow greater retail

market competition

Responses agree that consumers should have a right to a smart meter installed at

their own request and at their expense also in regions without general rollout.

However, there is a slight tendency against having the choice of a smart meter with

functionalities of their own choice even if a different type is rolled out in their area.

In respect to smart appliances and energy management systems, responders

consider them as important to make the field of demand response accessible to a

broad range of consumers and that they can work as facilitators to this end. The

views also favour the display of consumption and consumption patterns by the

smart appliances and do not consider this as a detriment to the consumers' comfort.

Public consultation on a new energy market design

A wide public consultation

on a new energy market design (COM(2015)340 was

conducted from 15 July 2015 to 9 October 2015. It was open to EU and Member States'

authorities, energy market participants and their associations, SMEs, energy consumers,

NGOs, other relevant stakeholders and citizens. This public consultation aimed at

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obtaining stakeholder's views on the issues that may need to be addressed in a redesign of

the European electricity market.

As regards representativeness and quality, the Commission received 320 replies to the

consultation. About 50 % of submissions come from national or EU-wide industry

associations. 26% of answers stem from undertakings active in the energy sector (suppliers,

intermediaries, customers), 9% from network operators. 17 national governments and

several national regulatory authorities submitted also a reply. A significant number of

individual citizens and academic institutes participated in the consultation.

The first assessment of the submissions confirmed broad support of a number of key ideas

of the planned market design initiative, while views on other issues vary. The following

paragraphs provide a summary of the responses, also available on the Commission's

website

(i)

Electricity market adaptations.

A large majority of stakeholders agreed that

scarcity pricing, i.e. price formation better reflecting actual demand and supply, is

an important element in the future market design. It is perceived, along with current

development of hedging products, as a way to enhance competitiveness. While

single answers point at risks of more volatile pricing and price peaks (e.g. political

acceptance, abuse of market power), others stress that those respective risks can be

avoided (e.g. by hedging against volatility). Regulated prices are perceived as one

of the most important obstacles to efficient scarcity pricing.

A large number of stakeholders agreed that scarcity pricing should not only relate

to time, but also to locational differences in scarcity (e.g. by meaningful price zones

or locational transmission pricing). While some stakeholders criticised the current

price zone practice for not reflecting actual scarcity and congestions within bidding

zones, leading to missing investment signals for generation, new grid connections

and to limitations of cross-border flows, others recalled the complexity of prices

zone changes and argued that large price zones would increase liquidity.

Many submissions highlight the link between scarcity pricing and incentives for

investments/capacity remuneration mechanisms, as well as the crucial role of

scarcity pricing for kick-starting demand response at industrial and household

level.

Most stakeholders agree with the need to speed up the development of integrated

short-term (balancing and intraday) markets. A significant number of stakeholders

argue that there is a need for legal measures, in addition to the technical network

codes under development, to speed up the development of cross-border balancing

markets, and provide for clear legal principles on non-discriminatory participation

in these markets.

Most stakeholders support the full integration of Renewable energy sources (RES)

into the market, e.g. through full balancing obligations for renewables, phasing-out

priority dispatch and removing subsidies during negative price periods. Many

stakeholders note that the regulatory framework should enable RES to participate

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in the market, e.g. by adapting gate closure times and aligning product

specifications. A number of respondents also underline the need to support the

development of aggregators by removing obstacles for their activity to allow full

market participation of renewables.

As concerns phasing out of public support schemes for RES, stakeholders take

different positions. While some argue for phasing out support schemes as soon as

possible, others argue that they will remain an important tool until technologies

have fully matured. They point at existing fossil fuel subsidies and the need to

continue subsidizing RES and maintaining other market corrections as long as

subsidies for traditional fuels and nuclear are not removed. Certain stakeholders

underline that support could progressively take more and more the form of

investment aid (as opposed to operating aid). A large majority of stakeholders is in

favour of some form of coordination of regional support schemes. The need for an

ETS reform to allow full market integration of RES was mentioned very often.

Most stakeholders agree that diversified charges and levies are a source of market

distortions.

(ii)

Resource adequacy.

A majority of answering stakeholders is in favour an "energy-

only" market, possibly augmented with a strategic reserve. Many generators and

some governments disagree and are in favour of capacity remuneration

mechanisms. Many stakeholders share the view that properly designed energy

markets would make capacity mechanisms redundant.

There is almost a consensus amongst stakeholders on the need for a more aligned

method for resource adequacy assessment. A majority of answering stakeholders

supports the idea that any legitimate claim to introduce capacity remuneration

mechanisms should be based on a common methodology. When it comes to the

geographical scope of the harmonized assessment, a vast majority stakeholders call

for regional or EU-wide adequacy assessment, while only a minority favour a

national approach. There is also support for the idea to align adequacy standards

across Member States. Stakeholders clearly support a common EU framework for

cross-border participation in capacity mechanisms.

(iii)

Retail issues.

Many stakeholders identified a lack of dynamic pricing (more

flexible consumer prices, reflecting the actual supply and demand of electricity) as

one of the main obstacles to kick-starting demand side response, along with the

distortion of retail prices by taxes/levies and price regulation. Other factors include

market rules that discriminate consumers or aggregators who want to offer demand

response, network tariff structures that are not adapted to demand response and the

slow roll-out of smart metering. Some stakeholders underline that demand response

should be purely market driven, where the potential is greater for industrial

customers than for residential customers. Many replies point at specific regulatory

barriers to demand response, primarily with regards to the lack of a standardised

and harmonised framework for demand response (e.g. operation and settlement).

Regarding the role of DSOs, the respondents consider active system operation,

neutral market facilitation and data hub management as possible functions for

DSOs. Some stakeholders point at a potential conflict of interests for DSOs in their

new role in case they are also active in the supply business and emphasized that the

neutrality of DSOs should be ensured. A large number of the stakeholders stressed

the importance of data protection and privacy, and consumer's ownership of data.

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Furthermore, a high number of respondents stressed the need of specific rules

regarding access to data. As concerns a European approach on distribution tariffs,

the views are mixed; the usefulness of some general principles is acknowledged by

many stakeholders, while others stress that the concrete design should generally

considered to be subject to national regulation.

(iv)

Regulatory framework/electricity market governance.

Stakeholders' opinions with

regard to strengthening ACER’s powers are divided. There is clear support for

increasing ACER's legal powers by many stakeholders (e.g. oversight of ENTSO-

E activities or decision powers for swifter alignment of NRA positions). However,

the option to keep the

status quo

is also visibly present, notably in the submissions

from Member States and national energy regulators. While some stakeholders

mentioned a need for making ACER'S decisions more independent from national

interests, others highlighted rather the need for appropriate financial and human

resources for ACER to fulfil its tasks.

Stakeholders' positions with regard to strengthening ENTSO-E remain divided.

Some stakeholders mention a possible conflict of interest in ENTSO-E’s

role –

being at the same time an association called to represent the public interest,

involved e.g. in network code drafting, and a lobby organisation with own

commercial interests

–

and ask for measures to address this conflict. Some

stakeholders have suggested in this context that the process for developing network

codes should be revisited in order to provide a greater a balance of in interests.

Some submissions advocate for including DSOs and stakeholders in the network

code drafting process.

A majority of stakeholders support governance and regulatory oversight of power

exchanges, particularly in relation to their role in market capacity. Other

stakeholders are skeptical whether additional rules are needed given the existing

rules in legislation on market coupling (CACM Guideline).

Stakeholders mention also that the role of DSOs and their governance should be

clarified in an update to the 3

Package.

(v)

Regionalisation of System Operation.

As concerns the proposal to foster regional

cooperation of TSOs, a clear majority of stakeholders is in favour of closer

cooperation

between TSOs. Stakeholders mentioned different functions which

could be better operated by TSOs in a regional set-up and called for less

fragmentation in some important of the work of TSOs. Around half of those who

want stronger TSO cooperation are also in favour of regional decision-making

responsibilities (e.g. for Regional Security Coordination Centres). Views were split

on whether national security of supply responsibility is an obstacle to cross-border

cooperation and whether regional responsibility would be an option.

Public consultation on risk preparedness in the area of security of electricity supply

A public consultation on risk preparedness in the area of security of electricity supply was

organized between July 15th and October 9th 2015. This public consultation aimed at

obtaining stakeholder's views in particular on how Member States should prepare

themselves and co-operate with others, with a view to identify and manage risks relating

to security of electricity supply.

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The consulation resulted in 75 responses including public authorities (e.g. Ministries,

NRAs), international organizations (e.g. IEA), European bodies (ACER, ENTSO-E) and

most relevant stakeholders, including SMEs, industry and consumers associations,

companies and citizens. The following paragraphs provide a summary of the responses.

The responses themselves as well as a summary thereof are also available on the

Commission's website

(i)

Obligation to draw up risk preparedness plans.

A large majority of respondents

(75 %) is in favour of requiring Member States to draw up risk preparedness plans,

covering results of risk assessments, preventive measures as well as measures to be

taken in crisis situations.

There is also a large support for having common templates, which should ensure

that a common approach is followed throughout Europe. Many respondents stress

the need for common definitions, common assessment methods, and common rules

on how to ensure security of supply.

In fact, most respondents acknowledge that in an increasingly interconnected

electricity market, characterised by an increasing amount of variable supply,

security of supply should be considered a matter of common concern (countries are

increasingly dependent on one another and measures taken in one country can have

a profound effect on what happens in neighbouring states and in electricity markets

in general). They also acknowledge that the current legal framework (Directive

89/2005) does not offer the right framework for addressing this inter-dependence.

Therefore, they take the view that risk preparedness plans based on common

templates can help ensure that each Member State takes the measures needed to

ensure security of supply whilst co-operating with and taking account of the needs

of others. Stakeholders, in particular from the industry, also stress that risk

preparedness plans should help ensure more transparency and reduce the scope for

measures that unnecessarily distort markets.

Whilst acknowledging the need for a common approach, a significant number of

stakeholders also state that there should be sufficient room for tailor-made, national

responses to security of supply concerns, as there are substantial differences

between national electricity systems.

Respondents further agree that plans should be drawn up on a regular basis,

proposals range from 2 to 5 years. The degree of transparency of the plans should

depend on its content and may vary in function of it (given the fact that plans

contain possibly sensitive information). Finally, respondents also warn against

creating new administrative burdens and on this basis argue that any obligation to

make risk preparedness plans should take account of already existing assessment

and reporting obligations.

The minority of stakeholders taking the view that there should be no new legal

obligation to draw up risk preparedness plans argue that such plans are already in

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electricity-supply

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place at the national level, that national electricity systems are profoundly different

from one another and that priority should be given to the process of adopting

network codes and guidelines.

(ii)

Content of risk preparedness plans / substantive requirements plans should comply

with.

Many stakeholders take the view that it is too early at this stage to decide on

the exact content of risk preparedness plans. They stress the need for more analysis,

as well as in-depth discussions on the issue, in particular within the Electricity

Coordination Group. In spite of this general caveat, consultation results already

contain many useful pointers about substantive requirements plans should comply

with:

Definition of risks. Various stakeholders stress the need to develop a common

definition of what security of supply means and the various risks that should be

covered. Risk preparedness plans should be comprehensive in nature, covering

generation adequacy and grid adequacy issues, as well as issues related to more

short-term security issues (such the risk of a sudden unavailability of the grid

or a power plant as a result of a terrorist attack);

Cybersecurity. Respondents generally acknowledge the importance of

preventing risks related to cyber-attacks but there is at this stage, no agreement

on the need for further specific EU measures;

Risk assessments and standards. Whilst the public consultation did not raise a

specific question on risk assessment methods and standards (since these

questions where covered by the market design consultation), various

stakeholders make the case for a common methodology for assessing risks, to

ensure a comparability of results, and a more common and transparent approach

to the standards that are used to assess risks and define an acceptable level of

reliability (this is also confirmed by replies to the market design consultation).

Various stakeholders also take the view that risk preparedness plans should

contain the results of various assessments made as well as the indicators used

to make the assessments;

Preventive measures. Stakeholders in favour of risk preparedness plans agree

that such plans should identify both demand-side and supply-side measures

taken to prevent security of supply issues, in particular situations of scarcity.

They also agree on the need to assess the impact of existing and future

interconnections and to take account of the import capacity when designing

preventive measures. Many stakeholders point in this context to the need to

ensure that markets function in an optimal way, thus allowing for flexibility in

demand and a mix of solutions to ensure that a sufficient level of supply is

guaranteed whilst keeping distortive measures at bay. Finally, stakeholders also

stress that any assessment of import capacity should take account of the

expected situation in neighbouring Member States;

Dealing with emergency situations. A large majority of stakeholders agrees that

plans should identify actions (market and non-market based) to be taken in

emergency situations and rules on cooperation with other Member States. A

majority also believes that plans should include provisions on the suspension

of market activities, “protected customers” and cost compensation.

Additionally, some stakeholders suggest lists of specific content for the

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emergency plans. As regards the development of new EU rules, many

stakeholders state that due account should be taken of the network code on

Emergency and Restoration, which is under preparation. Most say this draft

network code should be considered as the basis, whilst acknowledging a

possible need for additional common rules. A minority of stakeholders argues

that the network code on emergency and restoration should be considered

sufficient, leaving no need for additional EU-level rules, or consider that the

issues not covered by the network code should not be addressed at the EU level;

Definition/clarification of roles and responsibilities and what operational

procedures to be followed (e.g., who to contact in times of crisis)

(iii)

Who should draw up risk preparedness plans, at what level, and with what kind of

'oversight'?

Who should be responsible for drawing up risk preparedness plans? Whilst

most stakeholders recall that national governments have the ultimate

responsibility for ensuring security of supply, many stakeholders consider that

TSOs should take a lead role in drawing up risk preparedness plans. Most

however consider that TSOs need to co-operate however with national

ministries and/or national regulatory authorities, with the latter assuming a

monitoring or supervisory role. There is a large support for a stronger DSO

involvement in the preparation of the plans as well, as well as a clarification of

the responsibilities of DSOs in crisis situations. Whilst most stakeholders see

the added value of designating one 'competent authority' per Member States,

there is no agreement on who that competent authority should be (and some

argue that this choice should be left with the Member States).

At what level should risk preparedness plans be drawn up? A large majority of

respondents take the view that plans should be made at national level; however

a large majority also stresses the need for more cross-border co-operation, at

least in a regional context. A significant group of respondents argues that plans

should be made at the regional level (for instance, as a complement to cross-

border co-operation by TSOs in the frame of the regional security coordination

initiatives) or call for plans at national and regional levels (or even 'multi-level'

plans).

Those that argue in favour of national plans highlight the fact that

responsibilities (and liabilities) for security of supply issues are national.

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).

The rather cautious reaction to the idea of regional plans contrasts with the overwhelming support for

regional assessments of generation adequacy under the market design consultation.

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

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What oversight should there be? Most stakeholders are in favour of a system of

peer reviews, to be conducted either in a regional context, or in the frame of the

Electricity Coordination Group. The latter should in any event be convened on

a regular basis to serve as a forum for exchanging best practice. Some

stakeholders are also in favour of a stronger role for ACER/ENTSO-E, in

particular as regards more technical aspects of cross-border co-operation. As

regards the Commission, stakeholders mainly see a facilitating role, but are

often not in favour of a review system where the Commission takes binding

decisions.

Aspects of the present initiative were also part of the consultation on the preparation of a

new Renewable Energy Directive

for the period after 2020

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

Targeted consultations

A High Level Conference on electricity market design took place on 8 October 2015 in

Florence.

The European Electricity Regulatory Forum convenes once or twice a year. The market

design initiative was discussed in this stakeholder forum at several occasions, notably the

Forum

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

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

2020

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

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e_Fora

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policy. This group was used to discuss issues related to the present impact assessment on

16 November 2015 and 3 May 2016.

On demand response two specifc stakeholder workshops were organised by the

Commission: (i) Workshop on Status, Barriers and Incentives to Demand Response in EU

Member States, organised be the European Commission on 23 October 2015, and (ii)

Smart Grids Task Force, Expert Group 3 workshop on market design for demand response

and self-consumption, March 2, 2016; and Expert Group 3 workshop on smart homes and

buildings, April 26, 2016.

Member States' views

The support of Member States to the proposed initiatives is also apparent for instance from:

The

"Council conclusions on implementation of the Energy Union"

of June 2015.

In this regard, the conclusions state that: "While

STRESSING the importance of

establishing a fully functioning and connected internal energy market that meets

the needs of consumers, REAFFIRMS the need to fully implement and enforce

existing EU legislation, including the Third Energy Package; the need to address

the lack of energy interconnections, which may contribute to higher energy prices;

the need for appropriate market price signals while improving competition in the

retail markets; the need to address energy poverty, paying due attention to national

specificities, and to assist consumers in vulnerable situations while seeking

appropriate combination of social, energy or consumer policy; the need to inform

and empower consumers with possibilities to participate actively in the energy

market and respond to price signals in order to drive competition, to increase both

supply-side and demand-side flexibility in the market, and to enable consumers to

control their energy consumption and to participate in cost-effective demand

response solutions for example through smart grids and smart metres."

The

"Messages from the Presidency on electricity market design and regional

cooperation"

of April 2016.

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.

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Annex III: Who is affected by the initiative and how

The present initiative covers a large area of measures. The tables below provide an

overview of the parties affected, separately for each of the measures resulting from the

preferred policy options developed in the Annexes 1.1 through to 7.6.

Such matters are equally referred to in section 6 of the main text for the (more aggregated)

main policy options developed there.

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

Affected party

1.1. Priority access and dispatch

Member States

Need to change national legislation in so far as it contains priority dispatch; need to

include provisions on transparency and compensation of curtailment and redispatch

Need to oversee implementation of provisions, notably determination which generators

continue to benefit from priority rules, and ensure correct curtailment compensation.

Measure

1.2. Regulatory exemptions from balancing responsibility

Need to change national legislation in so far as it contains

exemptions from balancing responsibility

Need to oversee implementation of provisions, notably oversight of

TSOs.

1.3. RES E access to provision of non-frequency

ancillary services

They need to adapt national legislation to create

conditions for non-discriminatory procurement of non-

frequency ancillary services.

They need to oversee implementation and monitoring

of provisions, notably oversight of TSOs.

National

regulatory

authorities

(NRAs)

Transmission

System

Operators

(TSOs)

Distribution

System

Operators

(DSOs)

Generators

Reduction of priority dispatch and priority access facilitates grid operation and lowers

dispatch costs. Introduction of clear compensation rules on the other hand can increase

redispatch costs where such compensation is currently insufficient.

Where DSOs curtail generation to resolve local grid constraints, they are affected

identically to TSOs.

Implementation of balancing rules, notably settlement of parties in

imbalance.

They need to change the way non-frequency ancillary

services are contracted, procured and possibly

remunerated.

DSOs very likely would also be affected, because most

RES are connected at distribution level and the DSO's

role in managing their network would have to change

in order to allow RES assets to participate to the

provision of ancillary services.

Owners of generation assets (RES and not) would be

affected by changes in the rules of how non-frequency

ancillary services are procured. More transparent and

competitive procurement rules could enable market

entrance by new actors and technologies, such as

battery storage.

Most likely not affected.

No direct impact, as balancing is the role of TSOs; indirectly,

increased balancing responsibility of generators increases system

transparency also to the benefit of DSOs.

Suppliers

Generators currently subject to priority rules will be exposed to increased curtailment

risks and lower likelihood of dispatch (for high marginal cost generators; likelihood of

dispatch actually increases for low marginal cost generators) unless they continue to

benefit from the exemptions. Generators not subject to exemptions will be less likely

to be curtailed and more likely to be dispatched where they are the most efficient

generator available. All generators will benefit from increased transparency and legal

certainty on redispatch and curtailment compensation.

Suppliers are not directly affected.

Balancing responsible parties, including suppliers, traders and

generators currently subject to balancing responsibility are not

directly impacted. Generators currently exempted or partly shielded

from balancing responsibility will have to increase their efforts to

remain in balance (e.g. through better use of weather forecasts) or

will be exposed to financial risks.

Balancing responsible parties, including suppliers, traders and

generators currently subject to balancing responsibility are not

directly impacted.

Power exchanges could benefit from the increased market liquidity

particularly for short-term products which results from balancing

responsibility of RES E.

Aggregators are likely to benefit in particular by offering to small

generators services to fulfil their balancing responsibility.

End consumers are not directly affected.

Power exchanges

Power exchanges could benefit from the increased market liquidity particularly for

short-term products which results from market-based curtailment and redispatch.

Aggregators are likely to benefit in particular by offering market-based resources to be

used by TSOs in redispatch or curtailment.

End consumers are not directly affected.

Most likely not affected.

Aggregators

End consumers

Aggregators are likely to benefit from a more level

playing field and get access to additional remuneration

streams.

End consumers are not directly affected.

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

Affected party

2.1. Reserves sizing and procurement

Member States

Member State authorities define the country's overall

policy regarding energy mix and power grid investments.

Measure

2.2. Removing distortions for liquid short-term markets

Member States authorities generally play a limited direct role in the

operation of intraday markets. They will, however be impacted if they

are responsible for implementing/enforcing requirements.

2.3. Improving the coordination of Transmission System Operation

Member States authorities will be impacted if they are responsible for

implementing/enforcing/monitoring the requirements. This topic is likely to have

a particularly political angle, as Member States may not be willing to entrust

ROCs with decision-making powers under the assumption that security of supply

is a national responsibility (although based on the TFEU, it constitutes a shared

responsibility between the EU and MS).

NRAs of each of the regions where a ROC is established would be required to

carry out the regional oversight of the concerned ROC. This would include

competences at least equivalent to those established for NRAs in the Third Energy

Package.

It may be necessary to entrust ACER with the EU-wide oversight of ROCs. It

would be necessary to set out a framework for the interaction between the regional

groupings of NRAs and ACER.

National TSOs would be complemented by ROCs performing functions of

regional relevance, whilst real time operation functions would be left solely in the

hands of national TSOs.

ROCs could potentially be entrusted with certain decision making responsibilities

for a limited number of operational functions, whilst TSOs would retain their

responsibility as regards all other functions for which they are currently

responsible at national level. It may be necessary to entrust additional tasks to

ENTSO-E related to the cooperation and coordination between ROCs.

National

regulatory

authorities

(NRAs)

NRAs approve the methodology for sizing and

procurement of balancing reserves. They are also

responsible for any impact on TSOs' tariffs and how cross-

border infrastructure is allocated.

Transmission

System

Operators

(TSOs)

Generators

Aggregators

TSOs analyse system's state and propose the methodology

for sizing and procurement of balancing reserves in their

control areas.

Shifting responsibilities for sizing and procurement of

balancing reserves at regional level implies a need for

strong governance at regional level.

Existing physical constraints would still need to be taken

into account in the regional procurement platform.

Major impacts are expected on the current design of

system operation procedures and responsibilities. Cost

allocation and remuneration would have to be agreed,

requiring the development of a clear and robust framework

of responsibilities between national and regional TSOs.

Generators, as Balancing Service Providers, would have

additional opportunity to participate in the balancing

market even though significant operational impact might

increase due to the procurement frequency. Such

framework would, however, allow the participation of

renewable energy sources in the balancing market

potentially leading to a sharp decrease of balancing reserve

cost.

Smaller products and time units will give aggregators

more access to intraday markets.

Regional procurement of reserves would lead to regional

settlement of imbalances; therefore allowing for increase

competition of suppliers across borders.

In case an optimisation process for the allocation of

transmission capacity between energy and balancing

markets has to developed, day-ahead market coupling

algorithm currently operates by power exchanges might be

NRAs are responsible for regulatory oversight of intraday markets,

including as part of the implementation of the CACM Guideline, where

they are responsible for approving a number of methodology

developed by TSOs and power exchanges. They will, therefore, be

affected by changes in so far as it could alter the basis for their

regulatory decisions. However, the direct impact on NRAs is

anticipated to be relatively limited.

TSOs are heavily involved in the operation of intraday markets,

notably in determining the cross-border capacity made available to the

market, and in using the results for operation of the system. They are

therefore likely to be significantly impacted by any changes.

Generators will be affected by any changes in wholesale prices they

receive for their energy on the intraday market. More efficient price

signals, and more potential for trading, will open up the market to

smaller generators, particularly renewable.

Generators could benefit from a more secure power system and a more efficient

market leading to increased market opportunities.

Suppliers

Power

exchanges

Increased price fluctuations will give aggregators more opportunities

to operate, thereby helping to ensure that demand meets supply at any

point in time.

Suppliers will be affected insofar as they are the ones who buy power

on the wholesale market. Any changes in intraday clearing prices will

change how much they pay for their power, the extent to which will

depend on how much trading they do in the intraday market.

Power exchanges will be the most affected by any changes to intraday

arrangements, as they are the ones who operate the platforms on which

energy is traded in the intraday timeframe. They will therefore have to

adapt systems and process to meet new requirements.

Limited impact on aggregators.

Limited impact on suppliers.

Limited impact on power exchanges. It is expected that they could benefit power

exchanges as the optimisation of market-related functions such as capacity

calculation would entail more liquidity in the markets that could be exchanged.

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Affected party

2.1. Reserves sizing and procurement

impacted and solution will have to be found on sharing

transmission capacity in an optimal way for the markets

preceding the balancing market.

End consumers will be able to participate in balancing

markets via demand response aggregators allowing for

stronger supplier's competition at regional level.

Measure

2.2. Removing distortions for liquid short-term markets

2.3. Improving the coordination of Transmission System Operation

End consumers

End consumers will be affected insofar as changes to the wholesale

price are passed on to them in their retail price.

Regional TSO cooperation through the creation of ROCs would benefit

consumers through improved security of supply (by minimising the risk of wide

area events such as brownouts and blackouts), and lowering costs through

increased efficiency in system operation and maximised availability of

transmission capacity to market participants.

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

Affected party

3.1. Unlocking demand side response

Member States

Those 17 Member States that roll out smart meters

will not be affected by the new provisions on smart

meters, apart from the obligation to comply with the

recommended functionalities, which may need to

transpose into national legislation. Similarly for

those two Member States that opted for partial roll-

out and are not expected to face any other additional

burden from allowing additional consumers to

request smart meters.

However, those 9 Member States that currently do

not plan to install any smart meters will need to

establish legislation with technical and functional

requirements for the roll-out and face some

additional administrative impact by re-evaluating

their cost-benefit analyses.

What concerns market rules for demand response,

Member States are already obliged through the EED

to enable demand response. The new provisions will

rather provide additional guidance for Member

States on how to create the enabling framework

instead of imposing additional burden to them.

Additional administrative impact may be created for

the NRAs for enforcing actions regarding the

consumer entitlement to request a fully functional

smart meter. This includes assessing the costs to be

borne by the consumer, and overseeing the process

of deployment. At the same time, improved

consumer engagement thanks to smart metering,

would make it easier for NRAs to ensure proper

functioning of the national (retail) energy markets.

Already under the existing legislation NRAs are

obliged to encourage demand side resources to

participate alongside supply in markets. The new

provisions under the preferred option only further

specify which aspects have to be addressed by NRAs

but they do not create additional burden for them.

Apart from the minor changes necessary to ensure

effective market monitoring in the changed market

context, ACER will not be affected by changes in

unlocking demand side response..

Measure

3.2. Distribution networks

The competent ministries in each Member State who

will be involved in the transposition of the relevant

EU legislation and monitor the implementation and

effectiveness of the measures under the preferred

option.

3.3. Distribution network tariffs and DSO

remuneration

The competent ministries in each Member State who

will be involved in the transposition of the relevant

EU legislation and monitor the implementation and

effectiveness of the measures under the preferred

option.

3.4. Improving the institutional framework

MS authorities will be in charge of national

implementation of the revised Third Package.

National

regulatory

authorities

(NRAs)

As DSOs are regulated entities is expected that NRAs

will have the main role of ensuring the effective

application of measures. NRAs will be mostly

involved in the application of the measures and in

designing the necessary rules for the practical

implementation. As the measures under the preferred

option are closely linked to a suitable remuneration

methodology, NRAs will also probably have to

modify existing schemes. This will require the

availability of the necessary human, technical and

financial resources.

According to the Electricity Directive NRAs have the

main role in fixing or approving network tariffs or

their methodologies. The overall aim is to move

towards more sophisticated network tariff

methodologies. To this end, some NRAs might have

to modify the existing methodologies for distribution

tariffs. The introduction of smarter regulatory

frameworks will require the availability of the

necessary human, technical and financial resources.

Their role, powers and responsibilities will be

further clarified, especially as regards issues

which are relevant at regional/EU level. This

will affect the way NRAs have cooperated at

regional and EU-level, including within

ACER, in order to enhance the collaboration

between NRAs and ACER.

In the context of clarifying the respective roles

of NRAs and ACER, some of the powers and

responsibilities currently conferred to NRAs

may be shifted to ACER.

Agency for the

cooperation

energy

regulators

(ACER)

ACER will be affected to the extent which will be

called to oversight the activities of EU DSO entity and

its involvement in relevant network codes or

guidelines.

ACER will be affected to the extent which will be

called to oversight the activities of EU DSO entity

and its involvement in network codes or guidelines

on network tariffs.

Its role, powers and responsibilities will be

further enhanced in order to ensure that ACER

can continue fulfilling its role of supporting

NRAs in exercising their functions at EU level

and to coordinate their actions where

necessary. For a number of specific and

defined instances, some of the powers and

responsibilities of NRAs will be shifted to

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Affected party

3.1. Unlocking demand side response

Measure

3.2. Distribution networks

3.3. Distribution network tariffs and DSO

remuneration

3.4. Improving the institutional framework

ACER, to ensure that it can carry out an EU-

level oversight.

ACER's role will be affected by the changes

envisaged for the process of development of

Commission implementing regulations in the

form of network codes and guidelines.

Some of the transparency obligations imposed

on ENTSO-E as well as some of the

governance rules applying to this association

will indirectly affect TSOs.

Some of the proposed rules (e.g. co-financing

of ACER by contributions from market

participants) might directly impact on TSOs.

Transmission

System

Operators

(TSOs)

European

network

transmission

system operators

(ENTSOs)

A greater roll-out of smart meters allows TSOs to

better calculate settlements and balancing penalties

as the consumption figures can be based on real

consumption data and not only on profiles.

TSOs are affected by opening markets for

aggregated loads and demand response. Those

effects are dealt with in the Impact Assessment on

markets. TSOs are not directly affected by the

proposed measures on removing market barriers for

independent aggregators. However, they are

indirectly affected: A greater participation of

flexibility products in ancillary service markets (e.g.

balancing markets) can help TSOs cost-effectively

manage the network.

ENTSO-E will not be affected by changes in

unlocking demand response.

TSOs will be involved as more coordination with

DSOs will be required. TSOs will have to allocate the

necessary human and technical resources in order to

achieve such coordination.

TSOs will not be affected by changes in distribution

tariffs.

ENTSO-E will have to cooperate with the EU DSO

entity on issues which are relevant to both

transmission and distribution networks.

ENTSO-E will not be affected by changes in

distribution tariffs.

Distribution

System

Operators

(DSOs)

In most Member States, DSOs are responsible for

organising the installation of smart meters. The

additional costs to be determined by the NRAs can

however be charged to the users.

DSOs also benefit from access to real time data

coming from smart metering. It supports them in

their work on monitoring and controlling the

network, improving its reliability and power quality,

and its overall effectiveness, particularly in the

presence of distributed generation. This ultimately

contributes to the increased distribution network

efficiency and increased revenue for the DSOs (e.g.

via reduced technical and commercial losses)

DSOs are not directly affected by the proposed

measures on removing market barriers for

independent aggregators. However, DSOs can

DSOs will be directly affected by the possible

measures under the preferred option as they will have

to have in place the necessary human and technical

resources in order to implement the envisaged

measures. Additional personnel or infrastructure

might be necessary. However, DSOs will use

flexibility solutions in order to increase efficiencies,

only where benefits will outweigh additional costs.

It is expected that the envisaged measures under the

preferred option will positively affect DSOs as they

aim to a more efficient utilisation of the distribution

system and the incentivisation of DSOs towards more

optimal development and operation of their grids.

More advanced tariff schemes may require the

availability and monitoring of detailed data (financial

and technical) and the achievement of specific

targets. Any additional administrative costs should be

offset by the expected benefits.

ENTSO-E's mandate will be mainly clarified,

whilst ensuring that its added value of

providing technical expertise is preserved.

Transparency of ENTSO-E will be further

improved.

The role of ENTSO-E will be affected by the

changes envisaged for the process of

development of Commission implementing

regulations in the form of network codes and

guidelines.

DSOs will be able to participate more actively

as a result of the changes envisaged for the

process of development of Commission

implementing regulations in the form of

network codes and guidelines.

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Affected party

3.1. Unlocking demand side response

indirectly benefit from a better uptake of demand

response as the reduction in peaks it will reduce the

need to invest in distribution networks.

Measure

3.2. Distribution networks

3.3. Distribution network tariffs and DSO

remuneration

3.4. Improving the institutional framework

Generators

Demand response is designed to reduce peak

demand and thereby effectively replace marginal

power plants and reduce electricity prices at the

wholesale market. As such generators are likely to

face reduced turnover from lower peak prices and

from operating reserve capacities.

Generators are not likely to be effected by an

accelerated smart meter roll out.

Generators will not be affected by the measures under

the preferred option.

Suppliers

Power exchanges

Smart meters can have a direct impact on suppliers,

as they enable consumers to easily switch.

Furthermore, there is one Member State where

suppliers are responsible for the roll-out. Moreover,

smart metering allows suppliers to offer dynamic

pricing contracts that reduce suppliers' risk of

changing wholesale prices.

The effect of demand response on suppliers can be

positive as suppliers will benefit from lower

wholesale prices. On the other hand demand

response will make it more difficult for suppliers to

calculate retail prices. Also as balancing responsible

parties they may face higher penalty payments for

imbalances incurred due to their customers changing

consumption patterns. Finally, new competition

from aggregators may reduce their income.

However, suppliers can also offer demand response

services to their customers and expand their range of

services and thereby turnover.

The overall financial impact of smart meters and of

more competition through demand response on

suppliers will hence depend on the ability of the

individual supplier to adapt to the new market with

innovative services and competitive pricing offers.

No impact expected

Suppliers will not be affected as the envisaged

measures will not affect their normal business.

The envisaged measures aim to the overall reduction

of network costs through the incentivisation of DSOs

to raise efficiencies, which will have an overall

positive impact to system users. The envisaged

measures also aim to a fair allocation of costs among

different system users. Therefore, to the extent to

which the envisaged measures will incite changes in

existing tariffs, generators or other system users may

be affected from any new tariffs which will result to

reallocation of costs.

It is not expected that the envisaged measures will

affect the suppliers.

Generators will be able to participate more

actively as a result of the changes envisaged

for the process of development of Commission

implementing regulations in the form of

network codes and guidelines.

Suppliers will be able to participate more

actively as a result of the changes envisaged

for the process of development of Commission

implementing regulations in the form of

network codes and guidelines.

No impact expected

Power exchanges will be subject to an

enhanced regulatory oversight at EU level

exercised by ACER and NRAs.

Power exchanges will be able to participate

more actively as a result of the changes

envisaged for the process of development of

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Affected party

3.1. Unlocking demand side response

Measure

3.2. Distribution networks

3.3. Distribution network tariffs and DSO

remuneration

3.4. Improving the institutional framework

Commission implementing regulations in the

form of network codes and guidelines.

Aggregators and other new market entrants

will be able to participate more actively as a

result of the changes envisaged for the process

of development of Commission implementing

regulations in the form of network codes and

guidelines

Aggregators (and

other

new

market entrants)

End consumers

Aggregators are likely to benefit from an accelerated

roll out of smart meters as this technology facilitates

market access for demand service providers and

aggregators. Equally all measures aimed at removing

market barriers and increasing competition in the

retail market will immediately facilitate market

access for aggregators and new energy service

providers and hence opens new business

opportunities for them.

End consumers will get the right to request smart

meters and have access to dynamic electricity

pricing contracts which clearly gives puts them in a

position to become active market participants.

Furthermore, provision of accurate and reliable data

flows due to smart metering would enable easier and

quicker switch between suppliers, access to choices,

smart home solutions and innovative automation

services, and can also lead to energy savings.

Consumers will equally benefit from more

competition, wider choice, and the possibility to

actively engage in price based and incentive based

demand response and hence from reduced energy

bills. But also those consumers who do not engage

themselves in demand response can profit from

lower wholesale prices as a result of demand

response if those price reductions are being passed

on to consumers.

Aggregators will be positively affected as DSOs will

request their services in order to use flexibility for

managing congestion in their networks.

Insofar as distribution tariffs incentivise grid users to

use the network more efficiently, aggregators will not

be called upon as much to help to manage network

congestion..

Use of flexibility from DSOs will result to lower

network costs. This reduction will be reflected in

distribution tariffs and the final electricity bill of the

consumer.

The envisaged measures aim to the overall reduction

of network costs through the incentivisation of DSOs

to raise efficiencies, which will have an overall

positive impact to system users. The measures also

aim to a fair allocation of costs among different

system users. Therefore, to the extent to which the

envisaged measures will incite changes in existing

tariffs, consumers or other system users may be

affected from any new tariffs which will result to

reallocation of costs.

Consumers will be able to benefit from

enhanced transparency and in general from

well-functioning energy markets.

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

Affected party

4.1. Removing price caps

Measure

4.2. Improving locational price signals

4.3. Minimise investment and dispatch

distortions due to transmission tariff

structures

Member States authorities will be impacted if

they

are

responsible

for

implementing/enforcing/monitoring

the

requirements.

4.4. Congestion income spending to increase cross-

border capacity

Member States authorities will be impacted if they are

responsible for implementing/enforcing/monitoring the

requirements.

Member States

Member States authorities will be impacted if they

are

responsible

for

implementing/enforcing/monitoring

the

requirements.

National

regulatory

authorities

(NRAs)

NRAs will be impacted if they are responsible for

implementing/enforcing/monitoring

the

requirements.

Member States authorities will be impacted if they are

responsible for implementing/enforcing/monitoring the

requirements. This topic is likely to have a particularly

political angle, as splitting price zones within a Member

State will result in different wholesale electricity in that

Member State depending on location (although not

necessarily retail prices).

Member States authorities will be impacted if they are

responsible for implementing/enforcing/monitoring the

requirements.

NRAs play a significant role in monitoring,

authorising, etc. tariffs and connection

charges. Any change would impact on how

they do this.

Transmission

System

Operators

(TSOs)

Generators

There will be limited impact on TSOs.

TSOs will be affected as it will likely mean they hold

and operate networks over more than one price zone. It

will also change those transmission lines that

accumulate revenue from congestion.

Different price zones will change the prices that

generators receive depending on their location.

Changes would have limited impact on TSOs

themselves, as proposals are not generally

looking at how TSOs are remunerated, but

rather how the money is collected.

Changes would most affect generators

–

lower

connection charges or tariffs (where they are

applied to generators) would have a positive

impact on their revenues.

NRAs are currently responsible for reviewing the use

of congestion income, and for authorising it to be spent

on the reduction of tariffs. They will be affected by

Option 2 and 3 as they no longer need to authorise it to

be spent on the reduction of tariffs. Option 1 could

require them to make a more them to make a more

thorough assessment.

ACER will be affected by changes to monitoring and

transparency requirements and the requirement on

them to develop harmonised rules.

It will change how transmission system operators are

able to use congestion income. Options 1-3 could lead

to more investment activity of the TSO.

If Option 1, 2 and 3 lead to more investment in

networks, this would impact generators by delivering

more cross-border competition and present further

trading opportunities to sell energy by an increases in

the liquidity of cross-border markets.

Increased price variability will impact the revenue

generators will see from the energy market

–

they

will likely see higher prices for short periods of

time, which will incentivise flexible generation.

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Affected party

4.1. Removing price caps

Measure

4.2. Improving locational price signals

Suppliers

Increased price variability will impact the price paid

by suppliers -

–

they will likely see higher prices for

short periods of time.

Different price zones will change the prices that

suppliers pay depending on their location.

4.3. Minimise investment and dispatch

distortions due to transmission tariff

structures

Limited impact on suppliers.

4.4. Congestion income spending to increase cross-

border capacity

If Option 1, 2 and 3 lead to more investment in

networks, this would impact generators by delivering

more cross-border competition and present further

trading opportunities to buy energy by an increase in

the liquidity of cross-border markets.

If Option 1, 2 and 3 lead to more investment in

networks, this would impact power exchanges if it

leads to greater cross-border trade on their platforms.

Power

exchanges

Power exchanges will be required to implement the

requirements, which could require changes to

systems and practices.

Different price zone will change the practices of power

exchanges

–

currently they operate based on MS-level

markets (in general)

–

they would need to differential

markets based on different price boundaries.

Different price zones

could

affect end-consumers

depending on their location. However, possibilities exist

to retail MS-level retail prices,

Limited impact on power exchanges.

End

consumers

End consumers will be affected insofar as changes

to the wholesale price are passed on to them in their

retail price. However, more variable prices will not

necessarily be felt by end-consumers as they may

be hedged (particularly household) against this

volatility in their retail contracts.

End consumers could be affected if more

tariffs were charged on load, as opposed to

production. However, overall the impact is

likely to be similar as the overall cost basis

would not changing.

End consumers may be affected by any reduction in the

amount that can be offset against tariffs. However, this

may be outweighed by the positive effect of more

cross-border capacity being available, and the benefit

this has on competition and energy prices.

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

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

Affected party

5.1. Improved generation adequacy methodology

Member States

Member States would be better informed about the likely development of security of supply indicators

and would have to exclusively rely on the EU-wide generation adequacy assessment carried out by

ENTSO-E when arguing for CMs.

NRAs/ ACER would be required to approve the methodology used by ENTSO-E for the generation

adequacy methodology and potentially endorse the assessment.

Measure

5.2. Cross-border operation of capacity mechanisms

Each Member State would not need to design a separate individual solution

–

and this would potentially

reduce the need for bilateral negotiations between TSOs.

NRAs/ ACER would be required to set the obligations and penalties for non-availability for both

participating generation/ demand resources and cross-border transmission infrastructure.

National

regulatory

authorities (NRAs)

Transmission System

Operators (TSOs)

TSOs would be obliged to provide national raw data to ENTSO-E which will be used in the EU-wide

generation adequacy assessment.

Generators

ENTSO-E would also have to provide for an updated methodology with probabilistic calculations,

appropriate coverage of interdependencies, availability of RES and demand side flexibility and

availability of cross-border infrastructure.

Suppliers

Aggregators

ENTSO-E would be required to carry out an EU-wide or regional system adequacy assessment based

on national raw data provided by TSOs (as opposed to a compilation of national assessments).

With the updated methodology provided by ENTSO-E, intermittent RES generators/ demand-side

flexibility would be less likely to be excluded from contributing to generation adequacy.

Limited impact on suppliers

Limited impact on aggregators

ENTSO-E would be required to establish an appropriate methodology for calculating suitable capacity

values up to which cross-border participation would be possible.

Based on the ENTSO-E methodology, TSOs would be required to calculate the capacity values for each

of their borders. They might potentially be penalized for non-availability of transmission infrastructure.

TSOs would be required to check effective availability of participating resources.

ENTSO-E may also be required to establish common rules for crediting foreign capacity resources for

the purpose of participation in CMs reflecting the likely availability of resources in each country/zone.

Foreign capacity providers would participate directly into a national capacity auction, with availability

rather than delivery obligations imposed on the foreign capacity providers and the cross-border

infrastructure.

Foreign capacity providers/ interconnectors would be remunerated for the security of supply benefits

that they deliver to the CM zone and would receive penalties for non-availability.

Limited impact on suppliers

Just like generators they shall be able to participate in cross-border CMs.

Power exchanges

End consumers

Limited impact on power exchanges

Explicit cross-border participation in CMs would preserve the properties of market coupling and ensure

that the distortions of uncoordinated national mechanisms are corrected and the internal market is able

to deliver the benefits to consumers.

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Table 6. Persons affected by measures for Problem Area III

Affected party

Member States

Measure

National

regulatory

authorities (NRAs)

Transmission System

Operators (TSOs)

Generators

Suppliers

Aggregators

Power exchanges

End consumers

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

Member States from their region, including ex-ante agreements on assistance during (simultaneous) crisis and financial compensation.

Member States would designate a ministry or the NRA as 'competent authority' as responsible body for preparing the Risk Preparedness Plan and for cross-border

coordination in crisis.

As members of an empowered Electricity Coordination Group they would consult and coordinate Plans.

The above described responsibilities might involve an increased administrative impact. However, most of the tasks are already carried out in a purely national

context and there might also be benefits from exploiting synergies of improved cooperation. In addition, existing national reporting obligations would be reduced

(e.g. repealing the obligation of Article 4 of Electricity Directive "Monitoring security of supply").

NRAs could possibly fulfil certain tasks as part of the Risk Preparedness Plan of their Member State.

Furthermore they might be appointed as 'competent authority' by Member States. In this case, they would be responsible for preparing the Risk Preparedness Plan

and for cross-border coordination during crisis, possibly requiring additional resources.

ENTSO-E would be responsible for identification of crisis scenarios and risk assessment in a regional context. A common methodology for short-term assessments

(ENTSO-E Seasonal Outlooks and the week-ahead assessments of the RSCs) should be developed by ENTSO-E.

This might require additional resources within ENTSO-E and within the RSCs, in case that ENTSO-E delegates all or part of these tasks to them. However,

additional costs would be limited as some of these tasks are already carried out today. Giving these bodies a clear mandate, it would however significantly improve

cross-border coordination.

Generation companies and other market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from

clearer rules on crisis management and the prevention of unjustified market intervention.

Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management

and the prevention of unjustified market intervention.

Market participants would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management

and the prevention of unjustified market intervention.

Market operators would not be directly affected by preparation of Risk Preparedness Plans. However, they would benefit from clearer rules on crisis management

and the prevention of unjustified market intervention.

As described above the impacts of blackouts on industry and society proved to be severe. Consequently, end consumers benefit extensively from improved risk

preparedness as it would help to prevent future blackouts more effectively.

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

Affected party

7.1. Monitoring energy poverty

Member States

Option 1 leads to an improved framework to measure energy poverty.

Member States will have a better understanding of energy poverty as a

result of a clearer conceptual framework (through the common

understanding of energy poverty) and better information on the level of

energy poverty (measuring energy poverty). Ultimately, this will contribute

to better identification and targeted public policies to alleviate energy

poverty.

NRAs will need to monitor and report to the European Commission and

ACER the number of disconnections. According to ACER Market

Monitoring Report, only 16 Member States met this requirement.

Measure

7.2. Options for phasing out regulated prices

Those Member States still practicing some form of price regulation will

have to make the necessary legislative and market changes in order to

ensure a smooth and effective phase out.

7.3. Creating a level playing field for access to data

The competent ministries and authorities who will be

involved in the transposition of the relevant EU legislation

and will monitor the implementation and effectiveness of

the measures under the preferred option.

National regulatory

authorities (NRAs)

Transmission

System Operators

(TSOs)

The preferred option would not directly affect TSOs.

In most countries with price regulation, NRAs are the bodies

responsible for setting the level of regulated prices for a defined

regulatory period. In few cases NRAs are only giving their opinion on

regulated prices set by the government. Phasing-out regulated prices

would remove these responsibilities of the NRAs therefore reducing

administrative costs and resource needs. However new tasks for the

NRAs might be defined by Member States in the follow-up of the price

deregulation process such as monitoring the level of market prices with

the possibility to intervene ex post in the price setting in case of market

abuse. The costs of carrying out such new tasks are likely to be less

important than the costs of setting regulated prices, resulting overall in

reduces resource needs for the NRAs.

The preferred option would not directly affect TSOs.

The envisaged measures will partly affect the NRAs as most

probably will have a role in the implementation of the

measures at national level. Other authorities such as data

protection authorities may be involved in the

implementation of the envisaged measures at national level.

NRAs will have to monitor the data handling procedures as

part of the retail market functioning. The involvement of

NRAs is expected to be higher in Member States where

smart metering systems are deployed.

Distribution System

Operators (DSOs)

The preferred option would not directly affect DSOs.

TSOs might be affected in terms of costs in cases where

Member States will decide that they are responsible for the

operation of the data-hub. However, the envisaged measures

do not impose an obligation to Member States regarding the

data management model and the party responsible for acting

as a data-hub. The measures under the preferred option will

benefit TSOs and other operators as the will allow them,

under specific terms, to have access to aggregated

information which will be useful for network planning and

operation.

In the large majority of Member States DSOs will be

involved directly in the data handling process. DSOs will

have the same benefits as TSOs in terms of system operation

and planning. Under the preferred option DSOs which are

not fully unbundled (DSOs below the 100.000 threshold)

will have to implement measures which link to the non-

discriminatory

treatment

information.

The

implementation of such measures will most probably create

costs which will vary depending on the national framework.

It is not expected however that these costs will create a high

burden, as they can implemented through automated IT

systems.

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Affected party

7.1. Monitoring energy poverty

Generators

The preferred option would not directly affect generators.

Measure

7.2. Options for phasing out regulated prices

In countries where artificially low regulated end-user prices are backed

up by generation deliveries at non cost-reflective level agreed by long-

term contracts, deregulation of end user prices could trigger a rethinking

of such system by a renegotiation of long-term contracts which would

stimulate investment in efficient generation capacities with positive

effects on the competition on the generation market.

Alternative (non-regulated) suppliers would benefit from the

deregulation of prices by increased possibilities to compete on the price

and therefore to gain more market share. This is particularly true for

countries where regulated prices set at non cost-reflective levels prevent

alternative suppliers from contesting the regulated offer. For the

regulated suppliers (usually former incumbents) the removal of price

regulation would lead to increased operational costs related to the

implementation of the transition from the regulated offer to market

based offer for its customer base. Moreover, regulated suppliers are

likely to lose significant market shares if customers will switch to

competitive offers of alternative suppliers.

The preferred option would not directly affect power exchanges.

However, power exchanges could benefit from increased liquidity due

to better functioning competition on retail and wholesale markets

following price deregulation.

Removing price regulation would stimulate the development of energy

services which create market opportunities for aggregators.

7.3. Creating a level playing field for access to data

Generators will not be affected under the preferred option.

Suppliers

Power exchanges

The preferred option would not directly affect suppliers.

However, should the improved monitoring of energy poverty lead to

increased action to tackle the problem by Member States, then the costs of

these measures may be borne by suppliers. Depending on each Member

States, these costs may then be recovered as network charges, passed on to

consumers or taken against energy providers overall benefits.

Preventative measures, such as debt management or providing additional

information on where to find support, represent an additional cost to energy

retailers in those Member States where these measures are not yet in place.

A moratorium of disconnection will reduce energy retailers' revenue as

energy will be supplied free of charge. However, such costs will to some

extent be mitigated by lower numbers of bad debtors in the long run.

The preferred option would not directly affect power exchanges.

The availability of consumption data under non-

discriminatory terms and interoperability of data formats

will have positive effects on suppliers and other retailers.

The aim of the measures under the preferred option is to

bring down the administrative costs for the various retail

service providers including suppliers.

Aggregators

The preferred option would not directly affect aggregators.

Consumers

Consumers in a situation of energy poverty or at risk of energy poverty will

be positively impacted by the preferred option. A clearer understanding and

measuring of energy poverty will have positive impacts on Member States

efforts to tackle energy poverty..

Phase-out of regulated prices for end customers would stimulate

competition on retail markets which translates for customers into more

choice and better offers in terms of price and service quality. Customers

would be able to better manage their own energy consumption by using

energy services and technologies such as demand response, self-

generation, and self-consumption. However, notably in countries where

prices are artificially regulated at low levels, price deregulation could

be followed by substantial increases in end user prices; to help

customers face such price increases, appropriate protection measures

for vulnerable customers should be in place prior to deregulation.

In the preferred option aggregators and other retail service

providers will have equal access to data as suppliers in a

transparent and non-discriminatory way. This will allow

aggregators to develop new services for consumers and will

facilitate their entrance in the market.

The envisaged measures under the preferred option aim to

support the development of a competitive retail market. It is

expected that the measures will bring developments which

will affect positively consumers through the availability of

wider choice of services, focusing on demand response and

energy efficiency.

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

Affected party

7.4. Facilitating supplier switching

Member States

The preferred option may need to be transposed into national

law, resulting in administrative impacts.

Some Member States (e.g. BE, IT) have eliminated exit fees

already, the latter reporting increased consumer trust as a

result. Others with a relatively high preponderance of exit fees

(NL, IE, SI) are likely to be more reserved, particularly in light

of the fact that they may have relatively competitive markets

already.

The preferred option would likely lead to additional

stakeholder engagement and enforcement actions, resulting in

increased administrative impacts to NRAs.

However, any clarification and simplification of EU legal

provisions may lead to greater ease of enforcement, and

commensurate savings.

In addition, improved consumer engagement would make it

easier for NRAs to ensure the proper functioning of national

(retail) energy markets they are charged with.

Not affected.

7.5. Comparison Tools

The preferred option will need to be transposed into national law, resulting in

administrative impacts.

However, some 13 Member States already have at least one independent CT run by a

government or government-funded body. As these are free of conflicts of interest, we

can assume they are likely to meet the accreditation criteria.

Measure

7.6. Improving Billing Information

The preferred option will need to be transposed into national

law, resulting in modest implementation costs.

National

regulatory

authorities

(NRAs)

The preferred option would likely lead to additional stakeholder engagement and

enforcement actions, resulting in increased administrative impacts. However, this

would not necessarily be a role for the NRAs as an independent body might be assigned

the task (e.g. GB where an independent auditor audits the CT).

However, any strengthening of EU legal provisions should lead to a reduction in the

number of consumer complaints.

In addition, improved consumer engagement would make it easier for NRAs to ensure

the proper functioning of national (retail) energy markets.

Not affected.

The preferred option would likely lead to additional

stakeholder engagement and enforcement actions, resulting

in increased administrative impacts to NRAs.

However, improved billing clarity would make it easier for

NRAs to ensure the proper functioning of national (retail)

energy markets they are charged with.

Transmission

System

Operators

(TSOs)

Distribution

System

Operators

(DSOs)

Not affected.

Suppliers

Any change in consumer switching behaviour resulting from

the preferred option would be reflected in switching

operations, and their associated administrative impacts.

However, as DSOs are regulated monopolies, these costs (or

savings, if switching decreases) will eventually be passed

through to end consumers.

Most suppliers are unlikely to welcome measures to further

restrict switching-related fees, as these limit their ability to

tailor tariffs to different consumers.

Some may also financially benefit from the increased

'stickiness' switching-related fees create amongst their

consumer base.

In addition, any change in consumer switching behaviour

resulting from the policy options would be reflected in

switching operations, and the associated administrative

impacts to suppliers.

Insofar as the measures lead to increased switching, this will result in increased

administrative costs to DSOs. However, these costs will be passed through to consumers

through network charges.

Not affected.

Comparison tool

providers

Not affected.

Industry associations (EURELECTRIC and Eurogas) have publicly supported

consumer access to neutral and reliable comparison tools. In particular, increased

reliability and impartiality in comparison tools may encourage new market entrants,

thereby improving the likelihood of a level playing field.

However, some suppliers are unlikely to welcome measures to certify comparison tools

as this may have an impact on how and where their offers are published, and their ability

to tailor tariffs to different consumers (in terms of cost, etc.).

Some may also lose out financially if they are no longer able to influence the ranking

of search results to promote certain offers; this applies both to energy suppliers and to

CT providers.

Insofar as the measures lead to increased switching, this will result in increased

administrative costs to suppliers.

More stringent requirements in terms of reliability and impartiality may increase their

costs, as may the need for accreditation. However, such costs may be offset by an

increase in sales due to improved trustworthiness of the comparison tool.

Most suppliers are unlikely to welcome EU legislation

addressing the content or format of energy bills, as this limit

their ability to tailor bills to different consumers.

Some may also benefit from the low awareness amongst

their consumer base of information that may be contained in

bills, such as switching information, consumer rights, and

consumption levels.

Not affected.

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Affected party

7.4. Facilitating supplier switching

End consumers

Some end consumers would benefit from contract exit fees

(permitted in the preferred option) if such fees mean that

suppliers are able to offer them lower prices or better levels of

service.

However, all consumers are likely to benefit from a complete

ban on other switching-related fees (as per the preferred

option), as well as greater transparency around any switching-

related fees they may be charged.

More generally, the majority of consumers would benefit from

further restricting the use of switching-related charges. Such

charges are a financial barrier to accessing better deals,

disproportionately affect decision making, foster uncertainty

on the benefits of switching, and reduce retail-level

competition.

7.5. Comparison Tools

Measure

7.6. Improving Billing Information

Some end consumers would benefit from contract exit fees

if such fees mean that suppliers are able to offer them lower

prices or better levels of service.

However, all consumers are likely to benefit from a complete

ban on other switching-related fees, as well as greater

transparency around any switching-related fees they may be

charged.

More generally, the majority of consumers would benefit

from further restricting the use of switching-related charges.

Such charges are a financial barrier to accessing better deals,

disproportionately affect decision making, foster uncertainty

on the benefits of switching, and reduce retail-level

competition.

The preferred option would benefit many consumers, as the offers displayed would be

more representative of the best ones (e.g. those offering the best value for money and

the best service levels) available on the market. Asymmetric access to information

would be reduced. Consumers would have greater trust in their ability to select the best

offer through improvements in levels of service, and they would be better protected.

They will be better able to make informed choices, and to benefit from the internal

market.

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

Description of analytical models used

In order to perform the quantitative analysis for the various Problem Areas, most notably

Problem Areas I and II, as well as for the evaluation of certain individual measures

described in the Annexes, a number of specialized energy modelling tools were used. The

selection of the modelling tool to be used in each case was made based on its ability to

answer the specific questions raised in each Problem Area.

METIS

For assessing the benefits of specific market design measures and their effect to power

system operation and market functioning, a new optimization software

–

METIS

–

was

used, currently being developed for the Commission

METIS was presented to the Member States' Energy Economists Group on April 5

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

Global Description

METIS is an on-going project initiated by DG ENER for the development of an energy

modelling software, with the aim to

further support DG ENER’s evidence-based

policy

making, especially in the areas of electricity and gas. The software is developed by a

consortium (Artelys, IAEW (RWTH Aachen University), ConGas, and Frontier

Economics) and a first version covering the power and gas system has already been

delivered to DG ENER.

It is an energy model covering with high granularity (geographical, time etc.) the whole

European energy system for electricity, gas and heat. In its final version it should be able

to simulate both system and markets operation for these energy carriers, on an hourly level

for a whole year and under uncertainty (capturing weather variations and other stochastic

events). METIS works

complementary

to long-term energy system models (like PRIMES

and POTEnCIA), as it focuses on simulating a specific year in greater detail. For instance,

it can provide hourly results on the impact of higher shares of intermittent renewables or

additional infrastructure built, as determined by long-term energy system models.

Upon final delivery, METIS will be able to answer a large number of questions and

perform highly detailed analyses of the electricity, gas and heat sectors. A number of topics

will be possible to tackle with METIS for the whole EU and/or specific regions, like:

The impacts of mass Renewable Energy Sources integration to the energy system

operation and markets functioning (for one or all sectors);

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

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

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

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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

costs, installed capacities at Member State-level and interconnection

capacities.

Geographical scope

–

In addition to EU Member States, METIS scenarios incorporate

ENTSO-E countries outside of the EU (Switzerland, Bosnia, Serbia, Macedonia,

Montenegro and Norway) to model the impact of power imports and exports to the EU

power markets and system.

Market models

–METIS market module replicates the market participants’ decision

process. For each day of the studied year, the generation plan (including both energy

generation and balancing reserve supply) is first optimized based on day-ahead demand

and RES E generation forecasts. Market coupling is modeled via NTC constraints for

interconnectors. Then, the generation plan is updated during the day, taking into account

updated forecasts and asset technical constraints. Finally, imbalances are drawn to simulate

balancing energy procurement.

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Figure 1: Simulations follow day-ahead to real-time market decision process

Source: METIS

Reserve product definition

–

METIS simulates FCR, aFRR and mFRR reserves. The

product characteristics for each reserve (activation time, separation between upward and

downward offers, list of assets able to participate, etc.) are inputs to the model.

Reserve dimensioning

–

The amount of reserves (FCR, aFRR, mFRR) that has to be

secured by TSOs can be either defined by METIS users or be computed by METIS

stochasticity module. The stochasticity module can assess the required level of reserves

that would ensure enough balancing resources are available under a given probability.

Hence, METIS stochasticity module can take into account the statistical cancellation of

imbalances between Member States and the potential benefits of regional cooperation for

reserve dimensioning.

Balancing reserve procurement

–

Different market design options can also be compared

by the geographical area in which TSOs may procure the balancing reserves they require.

METIS has been designed so as to be able to constrain the list of power plants being able

to participate to the procurement of reserves according to their location. The different

options will be translated in different geographical areas in which reserves have to be

procured (national or regional level). Moreover, METIS users can choose whether demand

response and renewable energy are allowed to provide balancing services.

Balancing energy procurement

–

The procurement of balancing energy is optimized

following the same principles as described previously. In particular, METIS can be

configured to ban given types of assets, to select balancing energy products at national

level, to share unused balancing products with other Member States, or to optimize

balancing merit order at a regional level.

Imbalances

–

Imbalances are the result of events that could not have been predicted before

gate closure. METIS includes a stochasticity module which simulates power plant outages,

demand and RES E generation forecast errors from day-ahead to one hour ahead. This

module uses a detailed database of historical weather forecast errors (for 10 years at hourly

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and sub-national granularity), provided by the European Centre for Medium-Range

Weather Forecasts ('ECMWF'), to capture the correlation between Member State forecast

errors and consequently to assess the possible benefits of imbalance netting. The

stochasticity module will be further extended in the coming year to include generation of

random errors picked from various probability distributions either set by the user or based

on historical data.

Figure 2: Example of wind power forecast errors for a given hour of the 10 years of

data.

Source:

METIS

PRIMES suite of models

In order to assess the impacts of the various market design options on generator profits and

investments, as well as the impact of capacity remuneration mechanisms and their different

designs, a suite of models built by NTUA were used, with PRIMES model being at its

core.

PRIMES

is a partial-equilibirum model of the energy system. It has been used extensively

by the European Commission for settting the EU 2020 targets, the Low Carbon Economy

and the Energy 2050 Roadmaps, as well as the 2030 policy framework for climate and

energy.

PRIMES is a private model which has been developed and is maintained by E3MLab/ICCS

of National Technical University of Athens

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

http://ec.europa.eu/clima/policies/strategies/analysis/models/docs/primes_model_2013-2014_en.pdf.

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

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

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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

emission results and cost curves, it also covers total GHG emissions

and total non-ETS sector emissions. It provides details on the Member State level, showing

differential impacts across Member States.

Decision making behaviour is forward looking and grounded in micro-economic theory.

The model also represents in explicit way energy demand, supply and emission abatement

technologies, and includes technology vintages. The core model is complemented by a set

of sub-modules modelling specific sectors. The model proceeds in five year steps and has

been calibrated to Eurostat data for the years 2000 to 2010.

For the electricity sector, the PRIMES model quantifies projection of capacity expansion

and power plant operation in detail by Member State distinguishing power plant types

according to the technology type (more than 100 different technologies). The plants are

further categorised in utility plants (plants with as main purpose to generate electricity for

commercial supply) and in industrial plants (plants with as main purpose to cogenerate

electricity and steam or heat, or for supporting industrial processes). The model finds

optimal power flows, unit commitment and capacity expansion as a result of an inter-

temporal non-linear optimisation; non-linear cost supply functions are assumed for all

resources used by power plants for operation and investment, including for fuel prices

(relating fuel prices non-linearly with available supply volumes) and for plant development

sites (relating site-specific costs non-linearly with potential sites by Member State); the

non-linear cost-potential relationships are relevant for RES E power possibilities but also

for nuclear and CCS.

The simulation of plant dispatching considers typical load profile days and system

reliability constraints such as ramping and capacity reserve requirements. Flow-based

optimisation across interconnections is simulated by considering a system with a single

bus by country and with linearized DC interconnections. Capacity expansion decisions

depend on inter-temporal system-wide economics assuming no uncertainties and perfect

foresight.

The optimisation of system expansion and operation and the balancing of demand and

supply are performed simultaneously across the EU internal market assuming flow-based

allocation of interconnecting capacities. The outcome of the optimisation is influenced by

policy interventions and constraints, such as the carbon prices (which vary endogenously

to meet the ETS allowances cap), the RES E feed-in tariffs and other RES E obligations,

the constraints imposed by legislation such as the large combustion plant directive,

constraints on the application of CCS technologies, policies in regard to nuclear phase-out,

etc.

The optimality simulated by the model can be characterised either by a market regime of

perfect competition with recovery of stranded costs allowed by regulation or as the

outcome of a situation of perfectly regulated vertically integrated generation and energy

supplying monopoly. This is equivalent of operating in a perfect way a mandatory

wholesale market with marginal cost bidding just to obtain optimal unit commitment and

a perfect bilateral market of contracts for differences for power supply through which

generators recover the capital costs.

According to the model-based simulations, the capital costs of all plants, taken all together

as if they belonged to a portfolio of a single generating and supplying company, are exactly

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recovered from revenues based on tariffs applied to the various customer types. This result

does not guarantee that the optimal capacity expansion fleet suggested by the model-based

projections cam be delivered in the context of more realistic market conditions with

fragmentation and imperfections.

PRIMES was not directly used in this impact assessment, although the PRIMES EUCO27

setup was the basis for all analyses, with all inputs exogenous to the power sector, as well

as generation capacities, coming from it. The main obstacle in using PRIMES for this

impact assessment was that it assumes a perfectly competitive and well-functioning

market.

For this scope two sub-modules closely linked to PRIMES were used instead:

PRIMES/IEM is a day-ahead and unit commitment simulator, modelling the

operation of the European electricity markets and system for a given year, being

able to capture different market designs and market participant behaviours.

PRIMES/OM is a variant of PRIMES, modifying the use of PRIMES in order to

simulate investments under various competition regimes and with the possibility to

capture the effect of CMs.

The two models are described below in more detail

PRIMES / IEM

PRIMES/IEM aims at simulating in detail the sequence of power markets - Day-ahead,

Intraday, Balancing and Reserve Procurement - in the EU for one year, covering all EU 28

Member States and their interconnections (also linked to non-EU European countries).

PRIMES/IEM is calibrated to PRIMES projections, taking as exogenous inputs:

Load (hourly);

Power plant capacities (as projected) and their technical-economic characteristics,

including old plants as available in projection period, new investments and

refurbishments as projected by PRIMES;

Fuel prices, ETS carbon prices, taxes, etc.;

Resource availability for intermittent renewables;

Interconnection capacities;

Heat or Steam serving obligations of CHP plants having production of heat or

steam as main purpose;

Restrictions derived from policies, e.g. operation restrictions on old plants,

renewable production obligations, if applicable, support schemes of renewables,

biomass and CHP.

PRIMES/IEM disaggregates the interconnection network, considering more than one node

per country, with connecting grids within the countries, in order to represent intra-country

grid congestions. The assumptions about the grid within each country and across the

countries change over time, reflecting an exogenously assumed grid investment plan. It

The detailed methodology followed, along with results, is described in a relevant report prepared for the

scope of the impact assessment: "Methodology

and results of modelling the EU electricity market using

the PRIMES/IEM and PRIMES/OM models", NTUA (2016)

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also uses a more disaggregated hourly resolution than PRIMES, in representing load and

availability of intermittent RES E resources, as well as more disaggregated technical and

economic data for each plant than PRIMES, to represent cyclical operation of plants,

possible shut-downs and start-ups. Finally, PRIMES-IEM uses detailed data on ancillary

services (reserves) and the capability of plants to offer balancing services.

The day-ahead algorithm (GAMS program, written by E3MLab) is based on the

EUPHEMIA

algorithm. The code runs for all countries and the user can select countries

to simulate market coupling. The power plant capacities, demand (hourly for the days

selected) and other information (e.g. grid) come from PRIMES database and projections.

The linkage of data to PRIMES is fully automatic. The user can define rules for bidding

by the plants, and the power plants (production hourly) which are 'must-take' and/or

nominations. Available transfer capacities between countries can also be specified in the

interface.

The unit commitment algorithm (GAMS program written by E3MLAB and solved as a

mixed integer linear program) is a fully detailed plant operation scheduling algorithm. It

includes the technical features of the power plants (technical minimum, minimum up-time,

minimum down-time, ramp-up rates, ramp-down rates, time to synchronize, time to shut

down and capability of providing ancillary reserve services to the system), the technical

features of the interconnectors (applying DC linear power flows) and the reserve

requirements of the system (primary, secondary, spinning tertiary, non-spinning tertiary

and optionally ramping-flexibility reserves). The program runs simultaneously for the

selected countries, which are assumed to operate under a coordinated-synchronized unit

commitment. The program runs on an hourly basis and simultaneously for the sequence of

typical days; runs fully one day having assumed next day, and so on. The code is fully

consistent with the unit commitment codes ran by TSOs in Europe and in the USA

(compatible with the recommended code by FERC in the USA).

The day-ahead market Simulator (DAM_Simul) runs all EU countries simultaneously,

solving market clearing by node (one node per country) and calculating interconnection

flows restricted by DC power flows and by Available Transfer Capacities (defined by pair

of countries).

Market participant bidding

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.

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/).

Bidding functions are defined by plant in DAM on the basis of the marginal fuel cost of the plant,

increased by a mark-up defined hourly as depending on scarcity. The modelling of the bidding behavior

of generators, similar in PRIMES/IEM and PRIMES/OM, is discussed in detail in the PRIMES/OM

Section.

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The unit commitment simulator (UC_Simul) includes exogenously defined reserve

requirements, the outcomes of the event generator, the operation schedule of all units, the

bids in DAM and penalty factors for slack variables (re-dispatching). Operation of small-

RES E and must-take CHP is fixed. The unit commitment simulator runs pan-European

limited by power flows and NTC values.The purpose of this run is to determine the

deviations from DAM schedule, to be used in the intraday and balancing simulator.

The Intraday and Balancing Simulator (IDB_Simul) runs the above intraday and balancing

market (once for 24-hours all together) and determines a price for deviations, the financial

settlement of deviations and a revised schedule for operation of units and interconnectors.

In IDB_Simul, eligible resources can bid for supplying power to meet the deviations. The

bids can differ for upward and for downward changes of power supplied by the eligible

resources. Eligibility is defined specifically for each policy option. Capacity from

interconnectors may be eligible but only if remaining capacities (beyond the schedule of

the unit commitment) allow for this.

Figure 3: Modelling Sequence in PRIMES/IEM

Source: PRIMES/IEM

In the Reserve and ancillary services procurement Simulator (RAS-Simul) demand for

reserves is defined exogenously (equal to demand used in the UC_Simul). The outcome of

RAS-Simul is the remuneration of the resources for providing reserves and a possible

(small) modification of the schedule of units and interconnection flows.

For each policy option the demand for reserves is differentiated. Eligible resources can bid

for supplying power to meet the demand for the different types of frequency reserves. Also,

a subset of plants are eligible in each market for reserve. When the bids are endogenous

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and market-based, the prices include scarcity markups, with scarcity referring to the market

for reserves. Eligibility of resources is defined differently for each policy option. Resources

available cross-border can participate (differently constrained by policy option) in the

markets for reserves subject to limitation from availability of interconnection capacity,

which is the capacity remaining after the schedule of the unit commitment and intraday.

Resources not scheduled after the unit commitment and the intraday can submit bids to the

markets for reserves (only for tertiary reserve) but only gas turbines are eligible for this

purpose.

For the finalisation of the simulation, the unit commitment simulator is run again assuming

as given the schedule of units and interconnection flows resulted from previous steps and

the load (hourly). The objective function includes only penalties for deviation from the

schedule resulted from the previous step. The ascending order of penalties is RES E,

interconnection flows, gas, solids, nuclear, demand or another order defined specifically

by policy option. If must-take CHP and small-RES E can be curtailed then they are also

included with penalties, otherwise they are fixed. The unit commitment simulator runs at

this stage pan-European and applies flow based allocation of interconnections. The

purpose of this run is to calculate the production by plant, consumption of fuel, operation

cost by plant and emissions.

Demand response is modelled similarly to pumping transferring power from peak- to

baseload; the amount of energy reduced in peak hours is compensated in the same day by

additional energy consumption in other time segments, chosen endogenously. Therefore

demand response bids for differential demand reduction and demand increase at different

times, the bidding price reflecting costs (exhibiting decreasing return to scale), scarcity

cost opportunity and the bidding quantity being subject to potential. Demand response

(defined differently for each policy option) can be incorporated in all stages, i.e. DAM,

intraday, reserves.

The simulation cycle closes by the reporting of financial balances (load payments,

revenues and costs) for each generator, load and the TSO and calculating unit cost

indicators (e.g. for reserves, etc.). As the simulation is stochastic, the expected values of

the outcomes are calculated as the average of results by case of random events weighted

by the frequency of the case.

PRIMES / OM

PRIMES/OM is a modified version of the power sector model of PRIMES, tailored to the

needs of the impact assessment. It uses the PRIMES database, as well as its scenario

assumptions. By departing from the usual perfect competition assumption of PRIMES, it

can simulate investment behavior and the influence of CMs under various competition

regimes and bidding behaviours. Simulations are dynamic, demand is price elastic and

cross-border flows endogenous.

The model variant covers the power sector of all EU Member States linked together. The

model simulates an organized wholesale market, calculating prices, revenues and costs,

and estimating the probability of eventual mothballing of old plants and the cancelling

(partially or entirely) of investment in new plants as a consequence of the revenues

associated to the individual plant.

The model includes as an option a stylized CM auction, with or without cross-border

participation, which is general in scope in terms of eligibility and covers all dispatchable

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generators. The inclusion or not of national CMs varies by scenario simulated. The model

considers that the presence of a CM leads to lower risk premium factors which are used by

generators to decide mothballing of old plants or cancelling of investments. However, the

CM demand functions, as specified according to the logic of the model, are such that they

may grant unnecessarily capacity payment to some plant categories.

Figure 4: Modelling Sequence in PRIMES/OM

Source: PRIMES/OM

The model runs dynamically from 2020 until 2050, in 5-year steps. It uses a full PRIMES

model scenario as starting point, from where it takes the first input for load, renewables

and the projection of power plant capacities. Subsequently it modifies load based on

demand response, capacity availability and investment (except for renewables, industrial

and district heating CHP) as a result of the mechanism described above.

A fundamental assumption of the oligopoly model is that the economics on which capacity-

related decisions are made by generators are specified individually for each plant.

However, the standard PRIMES model looks at the economics of portfolios of plants to

determine the outcome of capacity-related decisions. It also, enables us to quantify the

differences between market outcomes in perfect competition, where marginal cost bidding

is applied, and under the oligopoly market structure where uplift is applied to the bids of

market participants.

Main characteristics of PRIMES/OM

Investment Evaluation

–

A stochastic analysis is performed with respect to the main

uncertainty factors affecting investments or early retirement of old plants, thus introducing

a probability space for the simulation of investment decision under uncertainty. These

factors have been identified as follows: (a) ETS carbon prices, (b) natural gas prices in

relation to coal prices, and (c) the volume of demand for electricity net of renewables. In

addition to the uncertainties pertaining to the framework conditions, the heterogeneity of

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decision makers in the investment evaluation process has also been taken into account.

This is accomplished by considering a distribution probability of the hurdle rates that an

investor considers (subjectively) for undertaking an investment. The hurdle rates are

equivalent to the minimum Internal Rate of Return value for deciding positively upon an

investment. The frequency distribution is modified in terms of mean and standard deviation

dependent upon the certainty or lack thereof of revenues; revenues coming from the energy

only market compared to those coming from a CM imply higher mean and standard

deviation of the distribution of hurdle rates.

Combining all of the above, a sample of about 100 combinations is generated around the

EUCO27 trajectory for the three stochastic factors for the whole time period (as vectors

over time) and 100 hurdle rate cases with combined probabilities. For the purposes of

investment evaluation, the pan-EU energy-only market is run for each sample of the

stochastic factors and revenues and costs for each plant are calculated for their total

lifetime, including possible extension of operation. Two sources of revenues are accounted

for: from operation in the energy-only market and from supplying reserve to the system.

For the cost calculation, capital annuity payments were excluded. Using the revenues and

costs calculated as such, the economic performance of each power plant is found, defined

as the present value of future earnings above operation costs for each sample of uncertain

factors and each hurdle rate case. The expected economic performance of a plant is the

result of an average of performances weighted by the probabilities.

Heterogeneous decision makers, identified by the distribution of the hurdle rates as

mentioned above, have a different threshold probability in order to decide whether or not

to continue operating a plant or cancelling investment. In other words, there is an

association of expected economic performance of each plant, as represented by its present

value, with investment cost of new plants or with salvage value (remaining capital value)

for plants, which are distributed across the decision makers according to a normal

probability distribution function. Therefore, the frequency of decision about survival of a

plant’s capacity as a function

of the economic performance indicator is used as the

probability of survival. The capacity volume of the plant as projected by PRIMES in the

context of the EUCO27 scenario multiplied by the probability of survival provides us with

an update of the capacity volume.

Modelling of CMs

–

When a CM is assumed to be in place, it is modelled in a stylized

manner. All capacities are eligible, if dispatchable, including hydro lakes and storage,

provided that they are not under a different support scheme. For example, CHP, biomass,

etc. are excluded. Also, plants in the process of decommissioning or operating few hours

per year due to environmental restrictions as projected in PRIMES are excluded. All

capacities are remunerated for the available capacity excluding outages.

The CM payment is a result of an auction. The CM price is derived from the intersection

of demand for capacity and the offers, sorted in ascending price order. Demand for capacity

is defined as a negative-sloped linear line depending upon a price cap and linking two

capacity points: the minimum and maximum requirements. For all capacity offered up to

the minimum requirement the auction clearing price is equal to the price cap, while for the

maximum requirement it is equal to zero. The definition of the demand curve takes into

account trusted imports at peak load times and the guaranteed proportion of exports.

Therefore, implicit participation of flows over interconnections is taken into account.

Cross-border participation, when applicable, increases capacity offering. Removal of

capacities (due to mothballing or cancelling of investment, or because the capacity is

offered to a foreign CM) also decreases capacity offering. The CM winners sign a

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reliability option (one way option) which has a strike price. If the wholesale market price

is above the strike price they are assumed to return the revenues above strike price. The

results of the CM auctions, namely the stream of revenues they provide to generators, are

taken into account by the oligopoly model in the final step of investment evaluation.

Bidding Behaviour -

The model assumes a scarcity bidding function as a means to mimic

the strategic behaviour of market players in an oligopoly. The bidding function is specific

to each individual plant and it takes into account hourly demand, plant technology and

plant fixed costs in order to evaluate the hourly bid price of each generator.

In order to model the bidding behaviour of plants, they are assigned to one of four different

types of merit order: no-merit, baseload, mid-load, and peak load. Hydro-reservoirs

consider also water availability. The assignment of plants takes place based on their

technology as well as on whether they participate in the energy only market; non-

dispatchable generators are considered as must-take, and therefore are assumed to bid at

zero price. The no-merit order type is intended to include this type of plants. The baseload

category includes mainly nuclear and coal/lignite plants, the mid-load CCGTs, and the

peak load of GTs and Reservoir Hydro.

Subsequently, the capacities of all plants within a merit order type are summed up in order

to determine the total capacity of every type, developing a merit stack. Then the hourly

demand is compared with the merit stack in order to estimate for every hour which merit

order type is expected to be on the margin. This is the type on which a scarcity mark-up

will be applied, assuming this is the market segment in which all strategic behaviour of

market participants takes place for a specific hour. The marginal cost which sets the basis

for the price at which each plant offers its energy is calculated based on variable cost data

from the PRIMES database. The mark-up is calculated based on the following equation:

P is the plant identifier,

the merit order type,

the Marginal cost,

��

the total

supply (capacity) of merit order type,

the hourly demand specific to merit order

type,

��

the price ceiling for merit order type,

the (inverse) rate of mark-up and

the scarcity bid. The demand specific to a generation type is calculated as the residual

of hourly demand minus the capacity of the merit order types which lie below the marginal.

The price ceiling is specific to every merit order type and is applied in order to guarantee

that the merit order is never reversed, i.e. peak load plants being dispatched before mid-

load plants, mid-load before baseload, etc. Also, the rate specific to each plant is dependent

upon the fixed costs of the plant, which comprise mainly of capital costs, in a risk averse

manner. This convention is in place so that plants with high fixed costs are more reluctant

to apply a mark-up to their marginal cost in fear of staying out-of-merit and not being

dispatched due to the mark-up being too high. Finally, if in post-calculation the scarcity

bid exceeds the price ceiling, it is set equal to the ceiling.

Description of methodological approach followed concerning baseline

PRIMES EU Reference Scenario 2016

A common starting point to all Impact Assessments is the EU Reference Scenario 2016

('REF2016'). It projects greenhouse gas emissions, transport and energy trends up to 2050

on the basis of existing adopted policies at national and EU level and the most recent

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��

∗e

− ��

��

∙[

��

−1]

��

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market trends. This scenario was prepared by the European Commission services in

consultation with Member States. All other PRIMES scenarios build on results and

modelling approach of the REF2016.

Although REF2016 presents a comprehensive overview of the expected developments of

the EU energy system on the basis of the current EU and national policies, and could be

considered as the natural baseline for all impact assessments, it fails doing so for an

important reason. This scenario does not have in place the policies to achieve the 2030

climate and energy targets that are already agreed by Member States in the European

Council Conclusions of October 2014. It also does not reflect the European Parliament's

position on these targets.

Therefore, although it was important for all initiatives to have a common "context" in order

to ensure coherent assessments, each Impact Assessment required the preparation of a

specific baseline scenario, which would help assess specific policy options relevant for the

given Impact Assessment.

Central Policy Scenario: PRIMES EUCO27

Because of the need to take into account the minimum agreed 2030 climate and energy

targets (and the 2050 EU's decarbonisation objectives) when assessing policy options for

delivery of these targets, a central policy scenario was modelled ('EUCO27').

This scenario is the common policy scenario for all Impact Assessments. Additional

baseline and policy scenarios were prepared for each Impact Assessment, addressing the

specific issues to be assessed by each initiative, notably which measures or arrangements

have to be put in place to reach the 2030 targets, how to overcome market imperfections

and uncoordinated action of Member States, etc. A summary of the approach followed in

each respective impact assessment can be found in the Annex IV of the RED II impact

assessment.

This approach of separating a central policy scenario reaching the 2030 targets in a cost-

effective manner and other scenarios that look into specific issues related to

implementation of cost effective policies enables to focus on "one issue at a time" in the

respective separate analysis. It enabled to assess in a manageable manner the impacts of

several policy options and provide elements of answers to problem definitions listed in the

2016 impact assessment, without the need to consider the numerous possible combinations

of all the options proposed under each respective initiative.

PRIMES EUCO27 scenario is based on the European Council conclusions of October

2014

. 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;

http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdata/en/ec/145397.pdf.

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This overall target will be delivered collectively by the EU in the most cost-

effective manner possible, with the reductions in the ETS and non-ETS sectors

amounting to 43% and 30% by 2030 compared to 2005, respectively;

A well-functioning, reformed ETS with an instrument to stabilise the market in line

with the Commission proposal will be the main European instrument to achieve

this target; the annual factor to reduce the cap on the maximum permitted emissions

will be changed from 1.74% to 2.2% from 2021 onwards;

An EU target of at least 27% is set for the share of renewable energy consumed in

the EU in 2030. This target will be binding at EU level;

An indicative target at the EU level of at least 27% is set for improving energy

efficiency in 2030 compared to projections of future energy consumption based on

the current criteria. It will be delivered in a cost-effective manner and it will fully

respect the effectiveness of the ETS-system in contributing to the overall climate

goals. This target will be reviewed by 2020, having in mind an EU level of 30%;

Reliable and transparent governance system is to be established to help ensure that

the EU meets its energy policy goals, with the necessary flexibility for Member

States and fully respecting their freedom to determine their energy mix;

The above requirements, with a minimum energy saving level of 27%, are reflected in

EUCO27. Concrete specifications on assumptions were made by the Commission in order

to reach the relevant targets by using a mix of concrete and yet unspecified policies. A

detailed description of the construction of this scenario is presented in Section 4 of the EE

impact assessment and its Annex IV.

As this scenario is not directly used in the present impact assessment, the reader is referred

to the relevant technical annexes of the EE and RED II impact assessments for more details

on its main assumptions and results. Table 1 below presents the main projections for 2030

related to the power system for EU28.

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Table 1: PRIMES EUCO27 Modelling Results for the power system (EU28)

2000

Electricity consumption (in TWh)

Final energy demand

Industry

Households

Tertiary

Transport

Energy branch

Transmission and distribution losses

Net Installed Power Capacity (in

)

Nuclear energy

Renewable energy

Hydro (pumping excluded)

Wind on-shore

Wind off-shore

Solar

Biomass-waste fired

Other renewables

Thermal power

Solids fired

Oil fired

Gas fired

Net Electricity generation by plant

type (in TWh)

Nuclear energy

Renewable energy

Hydro (pumping excluded)

Wind on-shore

Wind off-shore

Solar

Biomass-waste fired

Other renewables

Thermal power

Solids fired

Oil fired

Gas fired

Source: PRIMES

3,029.0

2,530.7

1,061.1

713.8

683.5

72.3

281.7

216.2

683.5

139.6

129.0

115.8

12.7

0.1

0.2

12.7

0.8

414.9

194.5

83.3

123.8

2,844.0

893.9

374.5

351.6

22.2

0.1

42.9

5.0

1,575.6

866.3

178.4

483.4

2015

3,271.8

2,802.4

1,001.4

833.6

899.3

68.2

262.6

206.7

965.6

120.8

366.7

127.5

130.6

11.0

97.4

27.9

1.1

478.1

176.6

53.1

219.6

3,090.0

825.7

736.2

357.7

241.4

32.8

103.8

130.6

7.1

1,528.0

780.3

30.2

580.4

2030

3,525.6

3,081.3

1,054.8

899.7

982.2

144.6

231.2

213.1

1,131.0

109.9

652.2

133.3

246.1

37.9

233.8

53.1

2.1

368.9

99.4

15.3

200.1

3,396.7

738.4

1,372.8

375.1

564.4

127.3

303.6

238.1

9.7

1,285.6

448.6

14.6

576.8

Share in

total for

2030 (%)

30%

26%

28%

% diff

2015-

2010

11%

-6%

17%

32%

-6%

-7%

-4%

41%

-13%

184%

10%

121%

32%

15%

-9%

-36%

77%

-8%

97%

204%

42%

-3%

-10%

-83%

20%

% diff

2030-

2015

10%

112%

-12%

17%

-9%

78%

88%

246%

140%

90%

86%

-23%

-44%

-71%

-9%

10%

-11%

86%

134%

288%

193%

82%

37%

-16%

-43%

-52%

-1%

10%

58%

12%

22%

21%

33%

18%

22%

40%

11%

17%

38%

13%

17%

Baseline: Current Market Arrangements ('CMA')

The Market Design Initiative addresses four different Problem Areas. The first two,

addressing market functioning and investments, share a common baseline which is highly

dependent on the context (e.g. based on REF2016 or EUCO27). The other two Problem

Areas, concerning risk preparedness and retail markets, are more independent of the overall

context, as in each case the envisaged baseline and options can apply in either context

(moreover the assessment tends to be mainly qualitative). Therefore the discussion on the

baseline is meaningful mainly for the first two Problem Areas.

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Similar to the other 2016 Energy Union initiatives, EUCO27 was chosen as the starting

point (i.e. context) of the baseline for the Market Design Initiative (so-called "Current

Market Arrangements"

–

CMA). The EUCO27 scenario is the most relevant to the

objectives of the initiative, as it provides information on the investments needed and the

power generation mix in a scenario in line with the EU's 2030 objectives.

As all analysis focuses on the power sector, all assumptions exogenous to the power sector

were taken from the EUCO27 scenario. This also applied for the energy mix, the power

generation capacities for each period, the fuel and carbon prices, electricity demand,

technology costs etc. The main obstacle in further using the EUCO27 as a baseline for this

impact assessment was that it assumes a perfectly competitive and well-functioning

European electricity market, more matching the end point than the starting point of the

analysis. Therefore CMA differs from the EUCO27 scenario by including existing market

distortions, as well as current practices and policies on national and EU level.

The CMA assumes implementation of the Network Codes, including the CACM and the

EB Guidelines (the later in their proposed form). It is assumed that the CACM Guideline

will bring a certain degree of harmonisation of cross-border intraday markets, gate closure

times and products for the intraday, as well as a market clearing. National intraday and

balancing markets will be created across EU and a certain degree of market-coupling of

intraday markets will be achieved. At the same time, the EB Guideline is expected to bring

certain improvements to the balancing market, namely the common merit order list for

activation of balancing energy, the standardisation of balancing products and the

harmonisation of the pricing methodology for balancing. Nonetheless, other important

areas like harmonisation of intraday markets and balancing reserve procurement rules will

not be affected by the guidelines.

The baseline does not consider explicitly any type of existing support schemes for power

generation plants, neither in the form of RES E subsidies nor in the form of CMs

. 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.

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

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

. 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

Preliminary EUCO27

The same applies for CHP, when the main use of those plants is the production of heat/steam.

The CMs would not affect the merit order in problem area I, as the analysis assumes bidding based on

marginal costs (not scarcity pricing, which is introduced in problem area II).

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

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

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The two versions of EUCO27 are in general quite close from an EU energy system

perspective. Two differences can be found in 2030, one in the RES E shares and the other

in CO2 prices, slightly affecting power generation capacities and production.

RES E overall share is in both cases 27%, with a differentiation in the sectoral contribution:

in the preliminary version the share of RES E is at 48.4%, while being 47.3% in the final

EUCO27 version. This was mainly driven by differences in off-shore wind deployment.

There is more switching from coal to gas in the final version. This is translated to 2 p.p.

increase of gas in the share of power gas generation, while solids decreased by 0.5 p.p. and

RES E by 1.3 p.p.. The CO

price, which was 38.5 EUR/tCO

in the preliminary version

is 42 EUR/tCO

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

;

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

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

. For

certain EU28 countries the split between hydro lake and run-of-river of PRIMES

was reviewed based on historical data form ENTSO-E, due to differences in the

Actually reserve procurement was not modelled for other non-EU28 Member States, as well as for Malta,

Cyprus and Luxembourg.

"METIS

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

Artelys

(2016)

CHP units were treated as electricity-only gas plants, as currently METIS does not model the heat sector.

Division of RES to small and large scale (e.g. rooftops solar) was also not captured.

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definitions used in PRIMES (based on Eurostat) and METIS (based on ENTSO-

E).

4. Generation of ten historical yearly profiles for wind and solar power was performed

according to the methodology depicted in Figure 5. The methodology followed

delivered annual load-factors closely matching the ones of PRIMES EUCO27.

Figure 5: PV and wind generation profiles

Source: METIS

5. Thermal plant fleets comprised of the following technologies: hard coal, lignite,

CCGT, OCGT, oil, biomass. The various fleets, except oil and biomass, were

divided into two or three classes (only CCGT were divided into three). Thermal

installed capacities were based on PRIMES EUCO27, without though enforcing

any type of constraint on the net electricity generation of these plants (which was

a pure result of the modelling). The technical-economic assumptions of PRIMES

were used for the power plants, complemented by other sources or databases when

missing.

6. Water inflow profiles, as well as storage parameters, required important

reconciliation work combing data from ENTSO-E, TSOs and PRIMES.

7. The international fuel price assumptions of PRIMES EUCO27 were used for

calculating the marginal production costs of the thermal fleets. Specifically for coal

and biomass, end-user fuel prices coming again from PRIMES EUCO27–

including also transportation costs

–

were used instead.

8. METIS used the same NTC values as in PRIMES EUCO27

. 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”

- Regarding grid development and the interconnectors between countries, they are based on the ENTSO-

E TYNDP, following the respective timelines. After the end of the TYNDP, expansions are based on

known plans and the development of RES E.

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OGCT capacities as variables over 50 years of weather data. Capacities of “oldest”

OCGT fleets remain fixed to the installed capacities in 2000 which have not been

replaced by 2030. Table 2 presents the results of the OCGT capacity optimization

consisting in the added OCGT installed capacities per country. These additional

capacities are added to the installed capacities in 2030 excluding the investment

between 2000 and 2030.

Table 2: Additional OCGT capacities needed to satisfy security of supply standards

OCGT added capacity

(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

"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

DR deployment

RES E priority dispatch

Biomass reserve procurement

Coal/lignite unit commitment at intraday

Balance responsibility

Intraday coupling

Time granularity for reserve sizing

Reserve procurement methodology

Joint/separate upward/downward reserve

Use of NTC

Reserve dimensioning and risk sharing

PV, Wind and RoR reserve procurement

1(a)

1(b)

1(c)

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

) were

considered.

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

currently access to the market and only for industrial resources based

on BAU potentials. In sub-option "b" DR by industrial resources

appears in all countries based on BAU potentials. In sub-option "c" all

DR resources participate based on the potential of the PO2 scenario,

adjusted to better match EUCO27 projections and the activation limits

of DR potential.

Two options were considered:

a. Penalty factor for PV and Wind curtailment, priority dispatch

for Biomass

b. No penalty factor or priority dispatch for PV, Wind and

Biomass

For sub-option "a", modelling RES E priority dispatch for wind and

PV was performed via a penalty factor and not by explicit priority

dispatch. The reason was that there were a number of hours for certain

Member States that if an explicit priority dispatch was enforced for all

RES E, their power system collapsed (solution was infeasible). In

reality this would most likely be addressed by the TSOs via the

curtailment of RES E.

Two options for participation of biomass in reserve procurement:

a. Biomass does not participate in FCR or FRR

b. Participation of Biomass (the absence of priority dispatch is

a prerequisite)

Two options for coal and lignite unit commitment:

a. The day-ahead unit commitment decision (i.e. which plants

are turned on or off) for coal and lignite power plants cannot

be refined during intraday, i.e. coal and lignite plants are

treated as must-runs in intraday once scheduled in day-ahead.

b. Coal and Lignite can re-optimise their commitment in

intraday (subject to their technical constraints).

By making RES E producers financially responsible for the

imbalances they are encouraged to improve their generation forecasts.

Two options were considered:

a. H-2 forecasts were used for Wind and PV generation for

reserve dimensioning and generation of imbalances.

b. H-1 forecasts were used for demand and PV, while 30 min

forecasts were used for Wind, leading to lower imbalances

and lower reserve requirements.

DR deployment

RES E priority

dispatch

Biomass reserve

procurement

Coal/lignite unit

commitment at

intraday

Balance

responsibility

"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:

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

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

procurement at day-ahead) or on a fixed basis per year (in which case

the mean annual value of optimal reserve procurement is used). The

options were:

a. Current practices

b. Day-ahead procurement

Two options were considered for upwards and downwards reserve:

a. Joint procurement according to current practices

b. Being two separate products which can be procured

independently

To model the process of interconnection allocation, three options were

considered:

a. National TSOs need to have a high security margin. For the

scope of METIS, EUCO27 NTCs were reduced by 5%.

b. Collaboration between TSOs reduces the need for security

margins. EuCo NTC values were used.

c. The introduction of a supranational entities will result in a

further reduction of the security margins, leading to an

increase by 5% of the EuCO NTCs.

To assess whether risk sharing can reduce the needs for national

reserves, three options were considered. Reserve was sized using a

probabilistic approach:

a. At national level

b. At regional level

c. At EU level

In order to ensure Member States can face similar security of supply

risks when less reserves can be procured (Options b. and c.), part of

the interconnections' capacity was reserved for mutual assistance

between Member States.

Two options:

a. PV, Wind and Hydro RoR do not participate in FCR or FRR

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

Intraday coupling

Time granularity

for reserve sizing

Reserve

procurement

methodology

Joint/separate

upward/downward

reserve

Use of NTC

Reserve

dimensioning and

risk sharing

Source: METIS

PV, Wind and RoR

reserve

procurement

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A more detailed description of the scenarios, how each option/measure was modelled and

what were the identified relevant current practices, can be found in an explanatory

technical report

It is important to highlight that the scenarios under Problem Area I do not consider

explicitly the possible existence of capacity mechanisms nor support schemes for RES E,

focusing strictly on the wholesale market operation over the various time frames (day-

ahead, intraday, balancing). Nevertheless, certain assumptions (like priority dispatch for

biomass) would make economic sense only in the case of existing economic subsidies.

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

Source: METIS

"METIS

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

intraday and balancing markets",

Artelys and THEMA Consulting (2016).

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

DR participation in balancing markets

Source: METIS

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

PRIMES/IEM scenarios were setup very similarly to the METIS scenarios. As can be

deduced from the description of the model, PRIMES/IEM puts more emphasis on the

simulation of the bidding behaviour of market participants and the modelling of the grid,

thus making it a better tool to capture the additional measures considered in Option 1 of

Problem Area II (on top of Option 1(c) of Problem Area I), i.e. the removal of low price

caps and the addition of locational price signals.

The consideration of market participant bidding behaviour and internal grid congestion,

made it necessary to re-run the baseline (Option 0) also of Problem Area I under these new

assumptions, in order to be used as the baseline of Problem Area II, with one caveat: similar

to METIS, PRIMES/IEM cannot model CMs. On one hand this implies an underestimation

of the benefits of the energy only market (Option 1) related to the more efficient operation

of the system. On the other hand the modelled baseline could not be used for the

comparison with Options 2 and 3. The approach followed to resolve this issue is described

in the next section.

In order to enrich the analysis, and provide more comparability with the analysis performed

for Problem Area I, it was decided to run also Options 1(a) (level playing field) and Option

1(b) (strengthening short-term markets) of Problem Area I. For the better understanding of

the reader, the construction of these options is presented in a similar manner as for the

METIS scenarios, highlighting that Option 0 corresponds to the baseline and Option 1(c)

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to Option 1 of Problem Area II. Options 1(a) (level playing field) and 1(b) (strengthening

short-term markets) do not correspond to any specific option of Problem Area II, but are

presented for completeness. The identification and methodology for the quantification of

current practices was supported by the same study used for the METIS modelling.

Table 5: Overview of MDI impact assessment Problem Area II scenarios as modelled

by PRIMES/IEM (read in conjunction with Table 4)

MDI options

Action Field

1(a) 1(b)

DR deployment

RES E priority dispatch

Day-ahead and intraday liquidity

Intraday coupling

Reserve dimensioning

Reserve procurement methodology

Use of NTC and bidding zones assumption

Price Caps

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

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

applicable).

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

aggregators.

Note that removal of priority dispatch is assumed to imply balance

responsibility and capability to participate in intraday and offer

balancing services. Thus for sub-option (d) all resources participate in

intraday, offer balancing services and have balancing responsibilities.

Three options were considered:

a. Low liquidity. DAM covers part of the load, with many

bilateral contracts nominated. ID illiquid in certain countries,

in which case TSO has significant RR.

b. Improved liquidity. DAM covers the large majority of the

load, no nominations. ID illiquid in certain countries, in which

case TSO has significant RR.

c. Liquid markets. DAM covers the whole load. Liquid and

harmonised ID markets.

DR deployment

RES E priority

dispatch

Day-ahead and

intraday liquidity

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Measure Topic

Description of the options

Three options were considered:

a. Very limited participation of flows over interconnectors (as

available capacity for intraday is restricted to the minimum

–

defined by country)

b. Limited participation of flows over interconnectors

c. Entire physical capacity of interconnectors allocated to IDM

and flow-based allocation of capacities, after taking into

account remaining capacity of interconnectors.

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

considered:

a. High reserve requirements (national)

b. High reserve requirements (national) but slightly reduced than

in Option 0

c. EU-wide reserve requirements (nonetheless taking into

account areas systematically congested)

The options were:

a. Current practices

b. Day-ahead

procurement(which

was

modelled

PRIMES/IEM as a joint optimization of power and reserve

day-ahead procurement)

Two options were considered:

a. Restrictive ATC (NTC

–

bilateral contracts

–

TSO reserves)

–

defined by country. National Bidding Zones (NTC values are

given on existing border basis)

b. Entire physical capacity of interconnectors allocated to DAM

and flow-based allocation of capacities

Two options:

a. Reflecting current practices

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

Intraday

coupling

Reserve

dimensioning

Reserve

procurement

methodology

Use of NTC and

bidding zones

assumption

Price Caps

Source: PRIMES/IEM

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

As already discussed in the previous section, the technical difficulty to model

simultaneously specific wholesale market measures (removal of low price caps, locational

signals for investments) with the issues on the coordination of CMs led to a two-step

approach:

Initially PRIMES/IEM was used to model Option 0 and Option 1 of Problem Area

II. This was sufficient to show the benefit of Option 1.

Subsequently PRIMES/OM was used to model Options 1 to 3 of Problem Area II,

but not Option 0, this time the focus being on CMs. Comparison was performed

among these three Options.

Due to the limitations of PRIMES/OM, all the detailed measures and assumptions under

Option 1 could not be captured. Concerning bidding behaviour, the same approach as in

PRIMES/IEM was followed. Table 7 presents a short comparison of the main results

related to power generation for 2030 for the three models (PRIMES, PRIMES/IEM and

PRIMES/OM).

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

and PRIMES/OM Option 1 for 2030.

PRIMES

EUCO27

Net Installed Power Capacity (in MW

)

Nuclear energy

Hydro (pumping excluded)

Wind on-shore

Wind off-shore

Solar

Biomass-waste fired

Other renewables

Solids fired

Oil fired

Gas fired

Net generation by plant type (in GWh)

Nuclear energy

Hydro (pumping excluded)

Wind on-shore

Wind off-shore

Solar

Biomass-waste fired

Other renewables

Solids fired

Oil fired

Gas fired

Source: PRIMES

1,131,045

109,905

133,335

246,064

37,949

233,813

53,073

2,079

99,396

15,304

200,127

3,396,680

738,363

375,138

564,407

127,334

303,625

238,108

9,732

448,640

14,572

576,760

PRIMES/IEM

Option 1(b)

PRIMES/OM

Option 1

1,094,290

109,905

133,335

246,064

37,949

233,813

53,073

2,066

80,844

15,930

181,312

3,378,950

737,365

375,020

564,539

127,388

299,070

200,828

9,268

469,182

11,754

584,537

as in

EUCO27

3,339,769

678,318

364,089

552,893

126,953

266,644

231,813

9,732

368,460

28,816

712,051

Apart from the differences in the installed capacities for solids and gas plants, explained

in more detail in Section 6.2.6.3, the main difference is the increased generation of gas

plants in detriment of solids and nuclear in PRIMES/IEM, most likely due to the better

capturing of the flexibility needs of the system.

With Option 1 described above, Options 2 and 3 assume on top the inclusion of CMs for

specific countries. Both Options assume CMs only in the case of Member States foreseeing

adequacy problems in their markets. Therefore certain Member States needed to be chosen

indicatively for this role. For the scope of this assessment, four countries were assumed to

be in the need of a CM: France, Ireland, Italy and UK. This assumption was not based on

a resource adequacy analysis, but on the CMs examined under DG COMP's Sector Inquiry,

focusing specifically on countries with market-wide CMs.

When a country was assumed to have a CM in place, it was assumed that generators no

longer followed scarcity pricing bidding behaviour, but shifted to marginal cost bidding.

Therefore in Options 2 and 3 a hybrid market was considered for EU28, with 24 Member

States having an energy only market (with scarcity pricing behaviour), while 4 Member

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

the reported figure in the table for oil fired generation includes peak units, steam turbines (both oil and

gas) as well as CHP with oil as main fuel.

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States having and energy market (with marginal pricing behaviour) supplemented with a

capacity mechanism.

Finally the only difference between Options 2 and 3, is that in Option 3 the CM is assumed

to include rules foreseeing explicit participation of cross-border capacities. Cross-border

capacities were assumed to participate to a CM up to a certain upper bound. The main idea

for this calculation of this upper bound was similar to the concept of unforced available

capacity, which is used in CMs for the generation capacities. Note though that using this

concept for calculating unforced available capacity (or de-rated capacity) of

interconnectors during system stress times is more complex because the probability of non-

delivery is not due only to technical factors but it is mainly due to congestion factors, which

can considerably vary depending on power trade circumstances during system stress times.

To do this calculation it was necessary to dispose simulation results of the operation of the

multi-country system. Alternatively, the calculation could be based on statistical data on

system operation in past years. In both cases, the simulation requires calculation of power

flows over the interconnection system.

Data collection and data gaps

The modelling performed for the impact assessment had significant data requirements. For

example METIS requires about twenty different types of data (such as installed capacities,

variable costs, availabilities, load factors and such). Depending on the type of simulation,

over 25 million individual data points can be required for each single test case, mostly

coming from hourly data (such as hourly national demands). For the NTUA models an

ever larger set of data was required (multiple times larger), as PRIMES covers the whole

European energy sector and all existing or emerging technologies, from household

appliances to industrial processes and means of transport. The respective data were

collected from public and commercial databases, as well as DG ENER EMOS database.

Moreover, in order to assess the impact of various measures and regulations aimed at

improving the market functioning, one needs to compare the market outcome in the

distorted situation, i.e. under current practices, with the market outcome after the

implementation of new legislative measures. These distortions should be based on the

current situation and practices and form the baseline for the impact assessment.

For this purpose the Commission requested assistance in the form of a study providing the

necessary inputs, i.e. facts and data for the modelling of the impacts of removal of current

market distortions. Although a significant amount of data was collected, a large number of

desired data sets was either unavailable or undisclosed. This unavailability of data

sometimes applied only for specific Member States for certain series, creating difficulties

in using the collected data for the rest of the Member States. In these cases proxies need to

be defined that could fill in the data gaps

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

"Electricity

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

COWI (2016).

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models. This can very quickly result in overfitting (i.e. modelling relationships and cause

and effects that do in this way not apply to reality, but yielding a better fit), and

transparency issues (i.e. understanding in the end not the model results, or drawing wrong

conclusions). It is therefore essential to find the right balance between complexity and

transparency, taking the strengths and weakness of each modelling approach into account.

For these reasons, considering the limitations of each modelling approach, a number of

compromises were made. There was an effort these compromises to retain the complexity

of the modelling at the lowest possible level, in order to allo interpretability of results. The

aforementioned study on market distortions also contributed in identifying the best

modelling approaches to capture all major distortions.

One should also expect that the different models used, although all of them focus on the

power sector, can produce different results due to the varying methodological approaches

followed. As long as these differences are well-founded on the underlying methodology

and scope of each model, while being based on the same underlying assumptions and input

data, they can be considered as complementary, as they give a better overview of the

impacts of the various policy options and help producing a more robust assessment.

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Tool

Concerned

Main Modelling Limitations

Leading to a possible overestimation of

benefits

The baseline assumes current practices for a number

of market design related measures and policies, not

considering their possible evolution and the expansion

of existing initiatives.

As the situation is very unclear how these will advance

in the coming years, and since modelling requires a

specific assumption for each of these measures, it was

decided for these cases (e.g. DR participation in the

markets) to reflect a more pessimistic view, where

only few advancements are made. In this respect the

costs of the baseline are quite likely overestimated.

Leading to a possible underestimation of

benefits

The detrimental effects of capacity mechanisms or

support schemes for RES E to the efficiency of the

electricity market operation over the various time

frames, as well as the external costs to the power

system (in relation to the energy market), were not

considered.

Still these are touched in Problem Area II and the

RED II impact assessment, as well as strong

indication on the impacts of RES E subsidies can be

deduced by the effect of the removal of priority

dispatch for biomass plants.

The softer approach used for the modelling of

priority dispatch of variable RES E (wind, solar)

underestimates the relevant cost of the baseline

scenario. Similarly for the balancing responsibility,

where H-2 forecasts for RES E are used, even when

balance responsibility is not assumed to apply to

them.

METIS did not model CHP and small scale RES E

separately, which would further enhance the impacts

of priority dispatch, currently assessed only for

biomass.

The issue of the limited liquidity currently observed

in intraday and balancing markets is not captured in

the modelling. Thus METIS assumed that markets

would be liquid in 2030, which may very well be

indeed the case without any policy action. Note

though that in certain Member States these markets

may not even exist today,

With an unclear effect

Modelling of the day-ahead and reserve procurement is

based on the so-called co-optimization of energy and

reserves. This approach was the one implemented for

simplicity and transparency. At the same time though it

does lead to the optimal scheduling of units. This on one

hand underestimates the costs of the baseline (in the case

of METIS), but at the same time possibly over-estimates

the benefits of the policy options.

Still overall the specific choice should not be considered

pivotal. Well-designed markets should lead to the same

efficient operation of the power system. Liquid intraday

and balancing markets should optimize operation and

resolve possible infeasibility issues resulting from the DA

schedule.

METIS &

PRIMES/IEM

METIS

The yearly dimensioning and procurement of reserves

overestimates the cost of current practices, not even

considering their possible evolution, based on which

are very likely to be brought even closer to real time in

the coming years.

This is partially compensated by assuming that

dimensioning is performed based on the more accurate

probabilistic approach (despite currently performed in

many Member States based on the deterministic one).

Also by the fact that in all sub-options dimensioning

of mFRR and FCR does not vary (thus no benefits are

reported for this).

Continuous intraday trading was modelled as consecutive

hourly implicit auctions.

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Tool

Concerned

Main Modelling Limitations

Leading to a possible overestimation of

benefits

Leading to a possible underestimation of

benefits

Even in the baseline, interconnector capacity is

assumed to be allocated and used relatively

efficiently.

Moreover the absence of network modelling implied

that all relevant (and in many cases significant) costs

were not considered, especially related to internal

congestion (within Member States).

DR was modelled as if participating only in

balancing markets and reserves, but not in day-ahead

/ intraday.

Benefits from load shifting or load reductions were

not assessed due to the lack of sufficient detailed

data.

A standard load profile was used for demand, based

on ENTSO-E's TYNDP 2016 assumptions. A

dynamic profile for demand and storage would better

capture the reactions of demand to market prices (and

the associated benefits).

Competition issues, effects of nominations and

block-bids, as well as possible strategic behaviour of

the market participants were not considered. On the

contrary, perfect competition was assumed based on

marginal pricing.

Assumed bidding behaviour on behalf of market

participants was not considered very aggressive, with

the electricity price rarely reaching the price caps.

With an unclear effect

The assumed effect of the measures on the interconnector

capacities (i.e. the increase of NTC capacities) for the

various options was performed in a stylized manner. It was

based on very rough estimations due to the significant lack

of relevant data.

METIS

Stylized modelling approach concerning costs of DR.

METIS

PRIMES/IEM

& PRIMES/OM

Modelling required a significant amount of inputs and

exogenous assumptions, e.g. on market behaviour etc.,

with data not necessarily available (generally, not just

publicly).Moreover significant amount of data (e.g.

detailed data on RR, nominations, technical details on the

transmission grid) were missing, so had to be estimated by

the modellers. Thus results are quite dependant on these

inputs. Still every effort was made to confirm assumptions

based on currently observed market operation data.

The selection of the countries assumed to have a CM may

be influencing the results (in an uncertain direction). Each

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PRIMES/OM

The fact that the baseline does not capture the

possible overcapacity in the power markets, e.g. due

to existing CMs or RES E support schemes or due

kom (2016) 0863 - Ingen titel

Tool

Concerned

Main Modelling Limitations

Leading to a possible overestimation of

benefits

Leading to a possible underestimation of

benefits

to unrealised forecasts of the market participants,

takes away part of the benefits that would be

realised from well-functioning markets (and CMs).

With an unclear effect

combination of countries could possibly lead to different

results.

For this reason

sensitivity was performed assuming the

existence of CMs for all countries, and then performing

the comparison of Options 2 and 3 in this context.

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Annex V: Evidence and external expertise used

The present impact assessment is based on a large body of material, all of which is

referenced in the footnotes. A number of studies have however been conducted mainly or

specifically for this impact assessment. These are listed and described further in the table

below.

The Commission (DG Competition) has also been conducting a sector inquiry into national

capacity mechanisms and organised Working Groups with Member States with a view to

help them implement the provisions in the EEAG related to capacity mechanisms and to

share experience in the design of capacity mechanisms

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

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Study

Study serve to study/substantiate

impact of

Assessing elements for upgrading the market

(all options under Problem Area I) with a focus

on the more efficient operation of the power

system:

Removing Market Distortions

Allocating interconnection capacity

across time frames

Procurement and Sizing of Balancing

Reserves

Impacts of the participation of Distributed

Generation in the market

Assessing the benefits from a coordinated

approach in Generation and System Adequacy

Analysis

Effect of weather related uncertainty to

revenues. Capacity savings due to cooperation.

CM coordination/cross-border participation.

Contractor

Published

METIS

Study 12: Assessing Market Design

Options in 2030.

Modelling tool DG ENER/METIS

Consortium

To be published

METIS

Study 04: Stakes of a common approach

for generation and system adequacy.

METIS

Study 16: Weather-driven revenue

uncertainty for power producers and ways to

mitigate it .

METIS

Technical Note T04: Methodology for the

integration of PRIMES scenarios into

METIS.

Modelling tool DG ENER/METIS

Consortium

To be published

Modelling tool DG ENER/METIS

Consortium

To be published

Technical note providing details on the

methodological approach followed with METIS.

METIS Consortium

To be published

METIS

Technical note providing details on the

methodological approach followed with METIS.

METIS Consortium / Thema

Consulting

To be published

Once operational, the envisaged link is expected to be the following:

https://ec.europa.eu/energy/en/data-analysis/energy-modelling/metis. Same applies for all METIS studies.

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Study

Technical Note T05: METIS market module

configuration for Study S12 - Focus on day-

ahead, intraday and balancing markets.

Study serve to study/substantiate

impact of

Contractor

Published

"Methodology

and results of modelling the

EU electricity market using the

PRIMES/IEM and PRIMES/OM models"

A. Assessing elements for upgrading the market

(main options under Problem Area I) with a

focus on the revenues for the market players,

including:

Scarcity pricing

Bidding Zones

Assessing investment incentives and the

need for coordination of CMs:

Profitability of power generation

investments

Coordination of CMs

Impact removing market distortions:

Identifying market distortions

Providing data input and support for the

modelling

CM cross-border arrangements

Options for locational signals/regulatory

framework IC construction

Main study supporting Balancing Guidelines

IA. For MDI: regional sizing and procurement

balancing reserves

NTUA

To be published

Electricity Market Functioning: Current

Distortions, and How to Model Their

Removal

Framework for cross-border participation in

capacity mechanisms

Transmission tariffs and Congestion income

policies

Integration of electricity balancing markets

and regional procurement of balancing

reserves

COWI / Thema / NTUA

To be published

COWI/Thema/NTUA

To be published

Trinomics

To be published

COWI/Artelys

To be published

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

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Study

Impact Assessment support Study on

downstream flexibility, demand response

and smart metering

Study on future European electricity system

operation

System adequacy assessment

Identification of Appropriate Generation

and System Adequacy Standards for the

Internal Electricity Market

Impact assessment support study on:

“Policies for DSOs, Distribution Tariffs and

Data Handling”

Second Consumer Market Study on the

functioning of retail electricity markets for

consumers in the EU

National policies on security of electricity

supply

Measures to protect vulnerable consumers

in the energy sector: an assessment of

disconnection safeguards, social tariffs and

financial transfers

Energy poverty and vulnerable consumers

in the energy sector across the EU: analysis

of policies and measures

Selecting indicators to measure energy

poverty

Fuel poverty in the European Union: a

concept in need of definition?

The role of DSOs in a Smart Grid

environment

Study serve to study/substantiate

impact of

Costs and benefits of measures to remove

market barriers to demand response and make

dynamic price tariffs more accessible

Future model TSO collaboration

Methodology for system adequacy assessments

System adequacy standards practises and

methods

Cost and benefits of different options

concerning DSO roles, distribution network

tariffs, data handling models

Billing information; contract exit fees; price

comparison tools; disclosure and guarantees of

origin

Review of current national rules and practices

relating to risk preparedness in the area of

security of electricity supply

Removing market distortions by phasing-out

regulated prices

Appraisal of disconnection safeguards across

the EU.

Review of measures to protect energy poor and

vulnerable consumers

Review, appraisal and computation of indicators

to measure energy poverty

Critical assessment of the pros and cons of an

energy poverty definition at the EU level

Assessment of the future role of DSOs in

specific activities

Contractor

COWI / ECOFYS / THEMA /

VITO

To be published

Published

Ecorys, DNV-GL,ECN

JRC

Mercados, E-bridge, ref4e

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

15-

3071%20DNV%20GL%20report%20Options%20for

%20future%20System%20Operation.pdf

To be published

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

Generation%20adequacy%20Final%20Report_for%2

0publication.pdf

To be published

Copenhagen Economics, and VVA

Ipsos, London Economics, and

Deloitte

VVA Consulting & Spark

To be published

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

DG%20ENER%20Risk%20preparedness%20final%2

0report%20May2016.pdf

To be published

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

INSIGHT_E_Energy%20Poverty%20-

%20Main%20Report_FINAL.pdf

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

Selecting%20Indicators%20to%20Measure%20Energ

y%20Poverty.pdf

http://extra.shu.ac.uk/ppp-online/wp-

content/uploads/2016/04/fuel-poverty-european-

union.pdf

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

20140423_dso_smartgrid.pdf

INSIGHT_E

Trinomics, University College

London, and 7Seven

Harriet Thomson, Carolyn Snell

and Christine Liddell

ECN & Ecorys

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Study

Study on the effective integration of

Distributed Energy Resources for providing

flexibility to the electricity system

From Distribution Networks to Smart

Distribution Systems: Rethinking the

Regulation of European Electricity DSOs

Options on handling Smart Grids Data

Regulatory Recommendations for the

Deployment of Flexibility

Identifying energy efficiency improvements

and saving potential in energy networks and

demand response

Study on tariff design for distribution

systems

Study serve to study/substantiate

impact of

Assessment of distributed energy resources and

their effectiveness in providing flexibility to the

energy system

Assessment of the DSO role in the context of

four regulatory areas including remuneration,

network tariff structure and DSO activities

Description of different data handling options

for smart grids

Description of the flexibility context,

commercial and regulatory arrangements,

incentives for the development of flexibility,

policy recommendations

Analysis of different options for improving

efficiency in energy networks according to

Article 15 of the EED

Benchmarking of different distribution tariff

structures and levels for electricity and gas

across EU

Contractor

PwC, Sweco, Ecofys, Tractebel

Published

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

5469759000%20Effective%20integration%20of%20

DER%20Final%20ver%202_6%20April%202015.pdf

http://www.eui.eu/projects/think/documents/thinktopi

c/topic12digital.pdf

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

xpert_group3_first_year_report.pdf

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

EG3%20Final%20-%20January%202015.pdf

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

GRIDEE_4NT_364174_000_01_TOTALDOC%20-

%2018-1-2016.pdf

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

20150313%20Tariff%20report%20fina_revREF-

E.PDF

THINK

EC Smart Grids Task Force

Tractebel, Ecofys

AF Mercados, refE, Indra

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Annex VI: Evaluation

The evaluation is presented as a self-standing document.

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This page was deliberately left empty

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Annex VII: Overview of electricity network codes and guidelines

This annex provides an overview of electricity network codes and guidelines adopted or

envisaged under Articles 6, 8 and 18 of the Electricity Regulation as well as a brief

description to the present initiative, if any.

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Electricity network codes

and guidelines adopted

or envisaged under

Articles 6, 8 and 18 of the

Electricity Regulation

Commission Regulation

establishing a Guideline on

capacity allocation and

congestion management

Commission Regulation

establishing a Network code on

requirements for grid

connection of generators

Commission Regulation

establishing a Network Code on

High Voltage Direct Current

Connections and DC-connected

Power Park Modules

Commission Regulation

establishing a Network code on

demand connection

State of play

Brief description of contents

Link to MD

Adopted on 24 July

2015

Legal implementation of day-ahead

and intraday market coupling, flow-

based capacity calculation

Linked to short-term

markets

For more details, see

Annex 2.2

No direct link with MD

Adopted on 14 April

2016

Defines the necessary technical

capabilities of generators in order to

contribute to system safety and to

create a level playing field.

Technical connection rules for

HVDC lines, e.g. used for

connections of offshore wind farms

Adopted on 26 August

2016

No direct link with MD

Adopted on 17 August

2016

Defines the necessary technical

specifications of demand units

connected to a grid and DSOs in

order to contribute to system safety

and to create a level playing field.

Creation of hedging opportunities

for the electricity market; important

to facilitate cross-border trade;

capacity to be allocated through

auctions on a central booking

platform; harmonisation of capacity

products

Rules to react to system incidents

(TSO interaction when the system

goes beyond acceptable operational

ranges)

Creation of a framework for TSO

cooperation in the preparation of

system operation (i.e. planning

ahead of real time).

Guidance for how TSOs should

create a framework for keeping

system frequency within safe

operational ranges

First step to the development of

common merit order lists for the

activation of balancing energy and

the start of a harmonisation of

balancing products.

Defines requirements of the plans to

be adopted by TSOs concerning

procedures to be followed when

blackouts happen

Link to demand response

and to measures on

ancillary services For

more details, see Annex

3.1

Link to short-term

markets, scarcity pricing

and locational signals.

See Annexes 2.2, 4.1,

4.2

Commission Regulation

establishing a Guideline on

Forward Capacity Allocation

Adopted on 26

September 2016

Commission Regulation

establishing a Guideline on

electricity transmission System

Operation

Text voted favourably

by MS on 4 May

Target date for

launching scrutiny:

December 2016

Linked to TSO

cooperation in the

planning and operation

of transmission systems.

For more details, see

Annex 2.3

Draft Commission Regulation

establishing a Guideline on

Electricity Balancing

('Balancing Guideline')

Draft Commission Regulation

establishing a Network code on

Emergency and Restoration

Target for vote in

comitology: by end

2016

Target for vote in

comitology: first

quarter 2017

Linked to procurement

rules and sizing of

balancing reserves.

For more details, see

Annex 2.1

Linked to security of

supply measures.

For more details, see

Annex 6

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Annex VIII: Summary tables of options for detailed measures assessed

under each main option

The tables provided here reflect the in-depth assessment made of the options for detailed

measures described in the Annexes to the impact assessment Chapter 1.1 through to 7.6

The manner in which they correspond to the main options assessed in the present document is

set out in Table 6, Table 7, Table 8 and Table 9 in the present document

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

Priority access and dispatch

Objective:

To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus ensuring that

the most efficient option for meeting the policy objectives is found. Dispatch should be based on the most economically efficient solution which respects policy objectives.

Option 0

Option 1

Option 2

Option 3

Do nothing.

This would maintain

rules allowing priority

dispatch and priority

access

for

RES,

indigenous fuels and

CHP.

Lowest

resistance

political

Abolish priority dispatch and priority

access

This option would generally require full

merit order dispatch for all technologies,

including RES E, indigenous fuels such as

coal, and CHP. It would ensure optimum

use of the available network in case of

network congestion.

Efficient use of resources, clearly

distinguishes

market-based

use

capacities and potentially subsidy-based

installation of capacities, making subsidies

transparent.

Priority dispatch and/or priority access only for emerging

technologies and/or for very small plants:

This option would entail maintaining priority dispatch

and/or priority access only for small plants or emerging

technologies. This could be limited to emerging RES E

technologies, or also include emerging conventional

technologies, such as CCS or very small CHP.

Certain emerging technologies require a minimum number

of running hours to gather experiences. Certain small

generators are currently not active on the wholesale market.

In some cases, abolishing priority dispatch could thus bring

significant challenges for implementation. Maintaining also

priority access for these generators further facilitates their

operation.

Same as Option 1, but with less concerns about blocking

potential for trying out technological developments and

creating administrative effort for small installations.

Especially as regards small installations, this could however

result in significant loss of market efficiency if large shares

of consumption were to be covered by small installations.

Abolish priority dispatch and introduce clear

curtailment and re-dispatch rules to replace

priority access.

This option can be combined with Option 2,

maintaining priority dispatch/access only for

emerging technologies and/or for very small

plants

As Option 1, but also resolves other causes for

lack of market transparency and discrimination

potential. It also addresses concerns that

abolishing priority dispatch and priority access

could result in negative discrimination for

renewable technologies.

Legal clarity to ensure full compensation and

non-discriminatory curtailment may be

challenging to

establish.

Unless

full

compensation and non-discrimination is

ensured, priority grid access may remain

necessary also after the abolishment of priority

dispatch.

Most suitable: Option 3.

Abolishing priority dispatch and access exposes generators to market signals from which they have so far been shielded, and requires all generators to actively

participate in the market. This requires clear and transparent rules for their market participation, in order to limit increases in capital costs and ensure a level playing field. This should be

combined with Option 2: while aggregation can reduce administrative efforts related thereto, it is currently not yet sufficently developed to ensure also very small generators and/or emerging

technologies could be active on a fully level playing field; they should thus be able to benefit from continuing exemptions.

Pros

Description

Cons

Politically, it may be criticized that

subsidized resources are not always used if

there are lower operating cost alternatives.

Adds uncertainty to the expected revenue

stream, particularly for high variable cost

generation.

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Regulatory exemptions from balancing responsibility

Objective: To ensure that all technologies can compete on an equal footing, eliminating provisions which create market distortions unless clear necessity is demonstrated, thus

ensuring that the most efficient option for meeting the policy objectives is found. Each entity selling electricity on the market should be responsible for imbalances caused.

Option 0

Option 1

Option 2

Option 3

Do nothing.

This would maintain the status

quo, expressly requiring financial

balancing responsibility only

under the state aid guidelines

which allow for some exceptions.

Lowest political resistance

Full balancing responsibility for all

parties

Each entity selling electricity on the

market has to be a balancing responsible

party and pay for imbalances caused.

Balancing responsibility with exemption

possibilities for emerging technologies

and/or small installations

This would build on the EEAG.

Balancing responsibility, but possibility to

delegate

This would allow market parties to delegate the

balancing responsibility to third parties.

This option can be combined with the other

options.

The impact of this option would depend on the

scope and conditions of this delegation. A

delegation on the basis of private agreements, with

full financial compensation to the party accepting

the balancing responsibility (e.g. an aggregator)

generally keeps incentives intact.

The impact of this option would depend on the

scope and conditions of this delegation. A full and

non-compensated delegation of risks e.g. to a

regulated entity or the incumbent effectively

eliminates the necessary incentives. Delegation to

the incumbent also results in further increases to

market dominance.

Description

Shielding from balancing responsibilities

creates serious concerns that wrong

incentives reduce system stability and

endanger market functioning. It can

increase reserve needs, the costs of which

are partly socialized. This is particularly

relevant if those exemptions cover a

significant part of the market (e.g. a high

number of small RES E generators).

Most suitable: Option 2

combined with the possibility for delegation based on freely negotiated agreements.

Costs get allocated to those causing them.

By creating incentives to be balanced,

system stability is increased and the need

for reserves and TSO interventions gets

reduced. Incentives to improve e.g.

weather forecasts are created.

Financial risks resulting from the

operation of variable power generation

(notably wind and solar power) are

increased.

Cons

Pros

This could allow shielding emerging

technologies or small installations from the

technical and administrative effort and

financial risk related to balancing

responsibility.

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RES E access to provision of non-frequency ancillary services

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

Option 0

Option 1

Option 2

BAU

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

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 non- capabilities of RES E and other new technologies is available, Allows gradual phase-in of services based on local/regional needs

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

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.

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

Reserves sizing and procurement

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

Option 0: business as usual

Option 1: national sizing and

Option 2: regional sizing and procurement

procurement of balancing reserves on 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

smooth implementation of the

binding regulation that would require

regulation requiring TSOs to use regional

Balancing Guideline. Existing on-

TSOs to size their balancing reserves on platforms for the procurement of balancing

going experiences will remain and

daily probablistic methodologies. Daily

reserves. Therefore this option foresees the

be free to develop further, if so

calculation allows procuring lower

implementation of an optimisation process for

decided. However, sizing and

balancing reserves and, together with

the allocation of transmission capacity between

procurement of balancing reserves

daily procurement, enables participation energy and balancing markets, which then

will mainly remain national,

of renewable energy sources and

implies procuring reserves only a day ahead of

frequency of procurement as

demand response.

real time

foreseen in the Balancing Guideline. This option foressees separate

This option would result in a higher level of

procurement of all type of reserves

coordination betwRReen European TSOs, but

Active participation in the

between upward (i.e. increasing power

still relies on the concept of local

Balancing Stakeholder Group could output) and downward (i.e. reducing

responsibilities of individual balancing zones

ensure stronger enforcement of the

power output; offering demand

and remains compatible with current

Balancing Guideline.

reduction) products.

operational security principles.

Option 3: European sizing and procurement

of balancing reserves

This option would have a major impact on the

current design of system operation procedures

and responsibilities and current operational

security principles. A supranational

independent system operator ('EU ISO') would

be responsible for sizing and procuring

balancing reserves, cooperating with national

TSOs. This would enable TSOs to reduce the

security margin on transmission lines, thus

offering more cross-zonal transmission

capacity to the market and allowing for

additional cross-zonal exchanges and sharing

of balancing capacity.

Description

Pros

Optimal national sizing and

procurement of balancing reserves.

No cross-border optimisation of

balancing reserves.

Regional areas for sizing and procurement of

balancing reserves.

Balancing zones still based on national borders

but cross-border optimisation possible.

Single European balancing zone.

Extensive standardisation through replacement

of national systems, difficult and costly

implementation.

Most suitable: Option 2.

Sizing and procurement of balancing reserves across borders require firm transmission cross-zonal capacity. Such reservation might be limited by the physical

topology of the European grid. Therefore, in order to reap the full potential of sharing and exchanging balancing capacity across borders, the regional approach in Option 2 is the preferred

option.

Cons

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Removing distortions for liquid short-term markets

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

Option 0

Business as usual

Local markets mostly unregulated, allowing for national

differences, but affected by the arrangements for cross-

border intraday and day-ahead market coupling.

Option 1

Fully harmonise all arrangements in local

markets.

Option 2

Selected harmonisation, specifically on issues relating to gate closure

times and products.

Description

Stronger enforcement and volunatry cooperation

There is limited legislation to enforce and voluntary

cooperation would not provide certainty to the market

Simplest approach, and allows the cross-border

arrangements to affect local market arrangements. Likely to

see a degree of harmonisation over time.

Would minimise distortions, with very limited

opportunity for deviation.

Targets issues that are particularly important for maximising liquidity

of short-term markets and allows for participation of demand response

and small scale RES.

Pros

Differences in national markets will remain that can act as a

barrier.

Extremely complex; even the cross-border

arrangements have not yet been decided and

need significant work from experts.

Additional benefit unclear.

May still be difficult to implement in some Member States with

implication on how the system is managed

–

central dispatch systems

could, in particular, be impacted by shorter gate closure time.

Most suitable: Option 2

–

Provides a proportionate response targeting those issues of most relevance.

Cons

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Improving the coordination of Transmission System Operation

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

Option 0

BAU

Limit the TSO coordination efforts to the

implementation of the new Guideline on

Transmission System Operation (voted at the

Electricity Cross Border Committee in May 2016

and to be adopted by end-2016) which mandates the

creation of Regional Security Coordinators (RSCs)

covering the whole Europe to perform five relevant

tasks at regional level as a service provider to

national TSOs.

Lowest political resistance.

Option 1

Enhance the current set up of existing RSC by

creating Regional Operational Centers (ROCs),

centralising some additional functions at regional

level over relevant geographical areas and

delineating competences between ROCs and

national TSOs.

Option 2

Go beyond the establishment of ROCs

that coexist with national TSOs and

consider the creation of Regional

Independent System Operators that can

fully take over system operation at

regional

level.

Transmission

ownership would remain in the hands

of national TSOs.

Option 3

Create

European-wide

Independent System Operator

that can take over system

operation at EU-wide level.

Transmission ownership would

remain in the hands of national

TSOs.

Description

Suboptimal in the medium and long-term.

Most suitable option(s): Option 1

(Option 2 and Option 3 constitute the long-term vision)

Cons

Enlarged scope of functions assuming those tasks

where centralization at regional level could bring

benefits

A limited number (5 max) of well-defined regions,

covering the whole EU, based on the grid topology

that can play an effective coordination role. One

ROC will perform all functions for a given region.

Enhanced cooperative decsion-making with a

possibility to entrust ROCs with decision making

competences on a number of issues.

Could find political resistance towards

regionalisation. If key elements/geography are not

clearly enshrined in legislation, it might lead to a

suboptimal outcome closer to Option 0.

Improved system and market operation

leading to optimal results including

optimized infrastructure development,

market facilitation and use of existing

infrastructure, secure real time

operation.

Seamless and efficient system

and market operation.

Pros

Politically challenging. While this

option would ultimately lead to an

enhanced system operation and might

not be discarded in the future, it is not

considered proportionate at this stage

to move directly to this option.

Extremely

challenging

politically. The implications of

such an option would need to

be carefully assessed. It is

questionable whether, at least

at this stage, it would be

proportionate to take this step.

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

Unlocking demand side response

Objective: Unlock the full potential of Demand Response

Option O: BAU

Option 1: Give consumers access to

technologies that allow them to

participate in price based Demand

Response schemes

Stronger enforcement of existing

Give each consumer the right to request the

legislation that requires MS to roll

installation of, or the upgrade to, a smart

out smart meters if a cost-benefit

meter with all 10 recommended

analysis is positive and to ensure that functionalities.

demand side resources can

Give the right to every consumer to request

participate alongside supply in retail

a dynamic electricity pricing contract.

and wholesale markets

No new legislative intervention.

This option will give every consumer the

right and the means (fit-for-purpose smart

meter and dynamic pricing contract) to fully

engage in price based DR if (s)he wishes to

do so.

Roll out of smart meters will remain

limited to those MS that have a

positive cost/benefit analysis.

In many MS market barriers for

demand response may not be fully

removed and DR will not deliver to

its potential.

Roll out of smart meters on a per customer

basis will not allow reaping in full system-

wide benefits, or benefits of economies of

scale (reduced roll out costs)

Incentive based demand response will not

develop across Europe.

Option 2: as Option 1 but also fully enable

incentive based Demand Response

Option 3: mandatory smart meter roll out and

full EU framework for incentive based demand

response

Mandatory roll out of smart meters with full

functionalities to 80% of consumers by 2025

Fully harmonised rules on demand response

including rules on penalties and compensation

payments.

It ignores the fact that in 11 MS the overall costs

of a large-scale roll out exceed the benefits and

hence that in those MS a full roll out is not

economically viable under current conditions.

Fully harmonised rules on demand response

cannot take into account national differences in

how e.g. balancing markets are organised and may

lead to suboptimal solutions.

Most suitable option(s): Option 2.

Only the second option is suited to untap the potential of demand response and hence reduce overall system costs while respecting subsidiarity

principles. The third option is likely to deliver the full potential of demand response but may do so at a too high cost at least in those Member States where the roll out of smart meters is not

yet economically viable. Options zero and one are not likely to have a relevant impact on the development of demand response and reduction of electricity system cost.

In addition to measures described under Option

1, grant consumers access to electricity markets

through their supplier or through third parties

(e.g. independent aggregators) to trade their

flexibility. This requires the definition of EU

wide principles concerning demand response

and flexibility services.

This option will allow price and incentive

based DR as well as flexibility services to

further develop across the EU. Common

principles for incentive based DR will also

facilitate the opening of balancing markets for

cross-border trade.

As for Option 1, access to smart meters and

hence to price based DR will remain limited.

Member States will continue to have freedom

to design detailed market rules that may hinder

the full development of Demand Response.

This guarantees that 80% of consumers across the

EU have access to fully functional smart meters by

2025 and hence can fully participate in price based

DR and that market barriers for incentive based

DR are removed in all MS.

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Distribution networks

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

Option: 0

Option 1

Option 2

BAU

Allow and incentivize DSOs to acquire flexibility services from distributed

Allow DSOs to use flexibility under the conditions set in

Member

States

are

primarily

Option 1.

energy resources.

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

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.

take advantage of their monopolistic position in the market.

national measures.

Under certain condition, stricter unbundling rules would also

be a more robust way to minimizing DSO conflicts of interest

given the broad range of changes to the electricity system, and

the difficulty of anticipating how these changes could lead to

market distortions.

Con

Not all Member States are integrating 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.

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Remuneration of DSOs

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

Option: O

Option 1

Option 2

BAU

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 at EU level.

DSOs, including flexibility services in the cost-base and incentivising efficient

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

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

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

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Distribution network tariffs

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

Option: 0

Option 1

Option 2

BAU

Impose on NRAs more detailed transparency and comparability requirements

Harmonization of distribution tariffs across EU; fully

Member States (NRAs) are mainly

harmonize distribution tariff structures at EU level for all

for distribution tariffs methodologies.

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.

tariff setting.

dependent distribution tariffs in order to facilitate the integration of distributed

energy resources and self-consumption.

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

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

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Improving the institutional framework

Objective: To adapt the Institutional Framework, in particular ACER's decision-making powers and internal decision-making to the reality of integrated regional markets and the

proposals of the Market Design Initiative, as well as to address the existing and anticipated regulatory gaps in the energy market.

Option 0

Option 1

Option 2

Maintain status quo, taking into account that the implementation

of network codes would bring certain small scale adjustments.

However, the EU institutional framework would continue to be

based on the complementarity of regulation at national and EU-

level.

Adapting the institutional framework to the new

realities of the electricity system and to the

resulting need for additional regional cooperation

as well as to addressing existing and anticipated

regulatory gaps in the energy market.

Providing for more centralised institutional structures with

additional powers and/or responsibilities for the involved

entities.

Description

Lowest political resistance.

Addresses the shortcomings identified and

provides a pragmatic and flexible approach by

combining bottom-up initiatives and top-down

steering of the regulatory oversight.

Requires strong coordination efforts between all

involved institutional actors.

Pros

Addresses the shortcomings identified with

coordination requirements for institutional actors.

limited

Most suitable: Option 1,

as it adapts the institutional framework to the new realities of the electricity system by adopting a pragmatic approach in combining bottom-up initiatives and top-

down steering of the regulatory oversight.

Cons

The implementation of the Third Package and network codes is

not sufficient to overcome existing shortcomings of the

institutional framework.

Significant changes to established institutional processes with

the greatest financial impact and highest political resistance.

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

Removing price caps

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

Option 0: Business as usual

Existing regulations already require harmonisation of

maximum (and minimum) clearing prices in all price zones to

a level which takes "into account an estimation of the value of

lost load".

Stronger enforcement/non-regulatory approach

Enforceability of

"into account an estimation of the value of

lost load"

in the CACM Guideline is not strong. Enforcement

action is unlikely to be successful or expedient. Relying on

stronger enforcement would leave considerable more legal

uncertainty to market participants than clarifying the legal

framework directly.

Voluntary cooperation would not provide the market with

sufficient confidence that governments would not step in

restrict prices in the event of scarcity

Simple to implement

–

leaves administration to technical

implementation of the CACM Guideline.

Option 1: Eliminate all price caps

Eliminate price caps altogether for balancing,

intraday and day-ahead markets.

Removes barriers for scarcity pricing Avoids setting

of VoLL (for the purpose of removing negative

effects of price caps).

Option 2: Create obligation to set price caps, where they

exist, at VoLL

Reinforced requirement to set price limits taking "into account

an estimation of the value of lost load"

Allow for technical price limits as part of market coupling,

provided they do not prevent prices rising to VoLL.

Establish requirements to minimise implicit price caps.

Description

Measure simple to implement; unequivocally and

creates legal certainty.

Compatible with already existing requirement to set price limit,

as provided for undert the CACM regulation, provides concrete

legal clarity

Pros

Difficult to enforce; no clarity on how such clearing prices will

be harmonised. Does not prevent price caps being

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..

Cons

Can be considered as non-proportional; could add

significant risk to market participants and power

exchanges if there are no limits.

VoLL, whilst a useful concept, is difficult to set in practice. A

multitude of approaches exist and at least some degree of

harmonisation will be required.

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Improving locational price signals

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

wholesale market.

Option 0

Option 1

Option 2

Option 3

Business as Usual

–

decision on bidding

zone configuration left to the arrangements

defined under the CACM Guideline or

voluntary cooperation, which has, to date,

retained the status quo .

Move to a nodal pricing system.

Introduce locational signals by new means,

i.e. through transmission tariffs.

Improve currently existing the CACM

Guideline procedure for reviewing bidding

zones and introducing supranational

decision-making, e.g. through ACER.

This would be coupled with a strengthened

requirement to avoid the reduction of cross-

zonal capcity in order to resolve internal

congestions.

This improvement will render revisions of

bidding zones a more technical decision.

It will also increase the available cross-

zonal capacity.

Does not address a situation where the

results of the bidding zone review are sub-

optimal. I.e. this option only covers

procedural issues.

Description

Approach already agreed.

Theoretically, nodal pricing is the most

optimal pricing system for electricity

markets and networks.

Would unlock alternative means to provide

locational signals for investment and

dispatch decisions.

Incentives would be not be the result of

market signals (value of electricity) but cost

components set by regulatory intervention

of a potentially highly political nature.

Does not address the underlying difficulty of

introducing locational price zones, namely

the difficulties to arrive at decisions that

reflect congestion instead of political

borders.

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.

Pros

Risks maintenance of the status quo, and

therefore misses the opportunity to address

issues in the internal market.

Nodal pricing implies a complete,

fundamental overhaul of current grid

management and electricity trading

arrangements with very substantial

transition costs.

Cons

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Minimise investment and dispatch distortions due to transmission tariff structure

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

Option 0: Business as usual

This option would see the status quo

maintained, and transmission tariffs set

according to the requirements under

Directive 72 and the ITC regulation.

Stronger enforcement and voluntary

cooperation:

There is no stronger enforcement action to

be taken that would alone address the

objective. Voluntary cooperation would, in

part, be undertaken as part of

implementation of Option 2.

Pros: Minimal change; likely to receive

some support for not taking any action in

the short-term.

Option 1: Restrict charges on producers

(G-charges)

This option could see the prohibition of

transmission charges being levied on

generators based on the amount of energy

they generate (energy-based G-charges)

Option 2: Set clearer principles for transmission

charges

This option would see a requirement on ACER to

develop more concrete principles on the setting of

transmission tariffs, along with an elaboration of

exiting provisions in the electricity regulation

where appropriate.

Option 3: Harmonisation

transmission tariffs

Full harmonisation of

transmission tariffs.

Description

Eliminating energy-based G-charges would

serve to limit distortionary effects on dispatch

of generation caused by transmission tariffs.

Social welfare benefits of approximately EUR

8 million per year. Would impact a minority

of Member States (6-8 depending on design).

Social welfare benefits relatively small

–

could be outweighed by transitional costs in

the early years. Can be considered

'incomplete' as a number of other design

elements of transmission tariffs contribute to

distortionary effects.

Unlikely to a proportionate

response to the issues at this

stage; given the technicalities

involved, it could be more

appropriate to introduce such

measures as implementing

legislation in the future.

Most suitable option(s): Option 2

–

aside from some high-level requirements, given the complexity of transmission charges, the precise modalities should be set-out as part of

implementing legislation in the future if and when appropriate. The value in Option 2 will be to set the path for the longer-term.

In the longer-term, likely to be a drive to do

more and maintaining the status quo

unlikely to be attractive; risks of continued

divergence in national approaches.

Provides an opportunity to move in the right

direction whilst not risking taking the wrong

decisions or introducing inefficiencies because of

unknowns; consistent with a phased-approach;

could eliminate any potential distortions without

the need to mandate particular solutions; consistent

with the introduction of legally binding provisions

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

Still leaves the door open for variation in national

approaches; will not resolve all potential issues.

Minimises distortion between

Member States on both

investment and dispatch;

creates a level-playing field.

Cons

Pros

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Congestion income spending to increase cross-border capacity

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

Option 0: Business as usual

This option would see the current situation

maintained, i.e. that congestion income can be

used for (a) guaranteeing the actual

availability of allocated capacity or (b)

maintaining or increasing interconnection

capacities through network investments; and,

where they cannot be efficiently used for these

purposes, taken into account in the calculation

of tariffs.

Stronger enforcement: current rules do not

allow for stronger enforcement.

Voluntary cooperation: would offer no

certainty that the allocation of income would

change.

Minimal disruption to the market; consumers

can benefit from tariff reductions

–

unclear

whether benefits of better channelling income

towards interconnection would provide more

benefits to consumers, given that it may offset

(at least in part) money spent on

interconnection from other sources.

Option 1

Further prescription on the use of

congestion income, subjecting its use on

anything other than (a) guaranteeing the

actual availability of allocated capacity or

(b) maintaining or increasing

interconnection capacities (i.e. allowing it

to be offset against tariffs) to harmonised

rules.

Option 2

Require that any income not used for (a)

guaranteeing availability or (b)

maintaining or increasing interconnection

capacities flows into the Energy part of

CEF-E or its successor, to be spent on

relieving the biggest bottlenecks in the

European electricity system, as evidenced

by mature PCIs.

Option 3

Transfer the responsibility of using the

revenues resulting from congestion and not

spent on either (a) guaranteeing availability

or (b) maintaining capacities to the

European Commission. De facto all

revenues are allocated to CEF-E or

successor funds to manage investments

which increase interconnection capacity.

Description

More guarantee that income will be spent

on projects that increase or maintain

interconnection capacity and relieve the

most significant bottlenecks; could

provide around 35% extra spend; approach

reflects the EU-wider benefits of

electricity exchange through

interconnectors; can be linked to the PCI

process.

Guarantees that income will be spent on

projects that increase or maintain

interconnection capacity and relieve the

most important bottlenecks; could

provide up to 35% extra spend; approach

reflects the EU-wider benefits of

electricity exchange through

interconnectors; firm link with the PCI

process.

Best guarantee that income will be spent

on the biggest bottlenecks in the European

electricity system, ensuring the best deal

for European consumers in the longer run;

approach reflects the EU-wider benefits of

electricity exchange through

interconnectors; to be linked to the PCI

process.

Pros

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Missing a potentially significant source of

income which could be spent on

interconnection and removing the biggest

bottlenecks in the EU.

Restricts regulators in their tariff approval

process and of TSOs on congestion

income spending.

Additional reporting arrangements will be

necessary.

Requires stronger role of ACER.

Restricts regulators in their tariff approval

process and of TSOs on congestion

income spending.

Could mean that congestion income

accumulated from one border is spent on

a different border or different MS.

Additional reporting arrangements will be

necessary.

Requires stronger role of ACER.

Could prove complicated to set up such an

arrangement; could mean that congestion

income accumulated from one border is

spent on a different border or different MS.

Requires a decision to apportion generated

income to where needs are highest in

European system. Will face national

resistance.

Will require additional reporting

arrangements to be put in place.

Requires stronger role of ACER.

Most suitable option(s): Option 2

–

provides additional funding towards project which benefit the EU internal market as a whole, while still allowing for national decision making in the

first instance. Considered the most proportionate response.

Cons

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

Improved resource adequacy methodology

Objective: Pan-European resource adequacy assessments

Option 0

Do nothing.

National decision makers would continue to

rely on purely national resource adequacy

assessments which might inadequately take

account of cross-border interdependencies.

Due to different national methodologies,

national assessments are difficult to

compare.

Stronger enforcement:

Commission would continue to face

difficulties to validate the assumptions

underlying national methodologies including

ensuing claims for Capacity Mechanisms

(CMs).

Option 1

Binding EU rules requiring TSOs to

harmonise their methodologies for

calculating resource adequacy +

requiring MS to exclusively rely on them

when arguing for CMs.

Option 2

Binding EU rules requiring ENTSO-E to

provide for a single methodology for

calculating resource adequacy

requiring MS to exclusively rely on them

when arguing for CMs.

Option 3

Binding EU rules requiring ENTSO-E to carry

out a single resource adequacy assessment for

the EU + requiring MS to exclusively rely on it

when arguing for CMs.

Description

National resource adequacy assessments

would become more comparable.

In addition to benefits in Option 1, it

would make it easier to embark on the

single methodology.

Even in the presence of a single

methodology, national assessments

would not be able to provide a regional or

EU picture.

National TSOs might be overcautious

and not take appropriately cross-border

interdependencies into account.

Difficult to coordinate the work as the

EU has 30+ TSOs.

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.

Even in the presence of harmonised

methodologies national assessment

would not be able to provide a regional or

EU picture.

In addition to benefits in Options 1 & 2, it would

make sure that the national puzzles neatly add up

to a European picture allowing for national/

regional/ European assessments.

Results are more consistent and comparable as

one entity (ENTSO-E) is running the same

model for each country.

It would potentially reduce the 'buy-in' from

national TSOs who might still be needed for

validating the results of ENTSO-E's work.

Cons

Pros

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Cross-border operation of capacity mechanisms

Objective: Framework for cross-border participation in capacity mechanisms

Option 0

Option 1

Do nothing.

No European framework laying out the details of an effective cross-

border participation in capacity mechanisms. Member States are likely

to continue taking separate approaches to cross-border participation,

including setting up individual arrangements with neighbouring

markets.

Stronger enforcement

The Commission's Guidance on state interventions

and the EEAG

require among others that such mechanisms are open and allow for the

participation of resources from across the borders. There is no reason to

believe that the EEAG framework is not enforced. To date, however,

there are not many practical examples of such cross-border schemes.

Harmonised EU framework setting out procedures including roles

and responsibilities for the involved parties (e.g. resource

providers, regulators, TSOs) with a view to creating an effective

cross-border participation scheme.

Option 2

Option 1 + EU framework harmonising

the main features of the capacity

mechanisms

per