kom (2016) 0863 - Ingen titel

Europaudvalget 2016
KOM (2016) 0863
Offentligt

EUROPEAN

COMMISSION

Brussels, 30.11.2016

SWD(2016) 410 final

PART 1/5

COMMISSION STAFF WORKING DOCUMENT

IMPACT ASSESSMENT

Accompanying the document

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

rules for the internal market in electricity (recast)

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

electricity market (recast)

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

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

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

preparedness in the electricity sector

{COM(2016) 861 final}

{SWD(2016) 411 final}

{SWD(2016) 412 final}

{SWD(2016) 413 final}

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Abstract of the Impact Assessment of the Market Design Initiative

POLICY CONTEXT AND KEY CHALLENGES

The Energy Union framework strategy puts forward a vision of an energy market 'with

citizens at its core, where citizens take ownership of the energy transition, benefit from

new technologies to reduce their bills, participate actively in the market, and where

vulnerable consumers are protected'.

Well-functioning energy markets that ensure secure and sustainable energy supplies at

competitive prices are essential for achieving growth and consumer welfare in the

European Union and hence are at the heart of EU energy policy.

To live up to this vision, a series of legislative proposals have been prepared, following the

objectives of secure and competitive energy supplies and building on the EU's 2030 climate

commitments reconfirmed in Paris last year.

The electricity sector will be one of the main contributors to decarbonise the economy.

Currently, 27.5% of Europe's electricity is produced using renewable energy and the

modelling shows that close to half of our electricity will come from renewables by 2030.

With increasing use of electricity in sectors like transport or heating and cooling,

traditionally dominated by fossil fuels, it is ever more important to further increase the

share of renewable energies in electricity and to unlock flexible demand, generation and

storage solutions.

A new regulatory framework is needed to address these challenges and opportunities. The

new proposals for a revised Renewable Energy Directive and for a new Market Design

will precisely do this, by deepening integration of the internal energy market, empowering

consumers, stepping up regional and EU-wide cooperation and providing the right signals

for investment, thus ensuring secure, sustainable and competitive electricity systems.

A successful transition of the energy system delivering on the ambition to become world

leader in renewables will require substantial investment in the sector, and in particular

investments in low-carbon generation assets as well as network infrastructure. This

requires a revised Emissions Trading System in order to address the current surplus of

allowances and to deliver a strong investment signal to reach 40% greenhouse gas

emissions reductions by 2030, but also specific rules to complement market revenues if

those are not sufficient to attract investments in renewable electricity. In addition, measures

to promote renewable energies in sectors like transport or heating and cooling are also

crucial. Reaching the 2030 framework targets and achieving an Energy Union will be

underpinned by a strong Energy Union governance, which will ensure the necessary

ambition level in an iterative dialogue between the Commission and all Member States.

Finally, a successful transition of the energy system will also require continued

commitment and support for infrastructure development both locally as well as across

borders.

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At the same time the transition will only be successful if consumers are given the

information, opportunities and rewards to actively participate in it. The availability of new

technologies that allow consumers to both consume electricity in a smarter way as well as

produce it themselves at costs which are more and more competitive opens up manifold

possibilities. What is still needed to fully reap these opportunities is the appropriate

regulatory framework accompanying the digital transformation and technological

development that will empower consumers to take part in the energy transition by

becoming active market participants. Empowering consumers in this way will also

contribute to a more efficient use of energy and is therefore an integral part of

implementing the efficiency first principle.

Finally, the EU will only be able to manage the energy transition successfully and cost-

effectively in a more deeply integrated internal electricity market. Only a more competitive

and better interconnected market will allow Europe to drive cost-efficient investment and

in particular to integrate the rising share of renewable energy production in a cost-efficient

and secure manner into the system, profiting fully from complementarities between

Member States and broader regions.

Such a deeply integrated and competitive market is also a key building block for

guaranteeing security of supply and policies and mechanisms intended to reach this

objective should follow a cooperative logic. National security of supply policies need to

be better coordinated and aligned. This will ensure that Member States are duly prepared

to tackle possible crisis situations, in particular those that affect several countries at the

same time.

The present package of legislative measures directly contributes to the Energy Union

dimensions of energy security, solidarity and trust, a fully integrated internal energy market

as well as decarbonisation of the economy, while also indirectly contributing to the other

two.

II.

LESSON LEARNED AND PROBLEM DEFINITION

Three consecutive legislative packages have transformed what used to be fragmented

energy markets in Europe into a more integrated Internal Electricity Market, thus

increasing competition. However, Europe's energy markets are undergoing further

profound changes.

The transition towards a low-carbon electricity production

poses a number of

challenges for the secure and cost-effective

organisation and operation of Europe’s power

grids and electricity markets. The increasing penetration of variable and decentralised

renewable energy

–

driven

inter alia

by the EU’s goals for

climate change and energy in

line with the 2020 and 2030 targets

–

requires the electricity sector to be operated more

flexibly and efficiently.

Today, most new installed capacity is based on wind and solar power which are inherently

more variable and less predictable when compared to conventional sources of energy

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(predictable central, large-scale fossil fuel-based power plants) or flexible renewable

energy technologies (e.g. biomass, geothermal or hydropower). By 2030, this trend is

expected to be ever more pronounced. As a result, there will be times when variable

renewables could cover a very large share - even 100% - of electricity demand and times

when they only cover a minor share of total consumption. The overall electricity supply

and demand needs to be in balance in physical terms at any given point in time (including

production or storage of electricity). This balance is a precondition for the secure operation

and stability of the electricity grid, thus avoiding the risk of black-outs.

Current market arrangements do not adequately incentivize all market participants

–

including renewable energy generation - to adjust their portfolios by revising production

and consumption plans on short notice. The manner in which the trading of electricity is

arranged and in which the methods for allocating the network capacity to transport

electricity are organized, allow only for efficient trading of electricity in timeframes of one

or more days ahead of physical delivery. Yet, the increasing penetration of variable

renewable sources of electricity ('RES E') requires efficient and liquid short-term markets

that can operate as close to real time as possible

–

until very shortly before the time of

physical delivery (i.e. the moment when electricity is consumed). Indeed, most renewable

generation can only be accurately predicted shortly before the actual production (due to

weather uncertainties). Flexibility is essential to deal effectively with an increased share

of variable renewable generation. Besides, these markets do not fully take into account

possible contribution of cross-border resources.

Retail markets for energy in most parts of the EU suffer from persistently low levels

of competition, consumer choice and engagement.

In spite of falling prices on wholesale

markets, retail prices have risen steadily for households as a result of significantly

increased network charges, taxes and levies in recent years. Market concentration remains

generally high due to persisting barriers to new entrants. Switching related fees such as

contract termination charges continue to constitute a significant financial barrier to

consumer engagement. In addition, the high number of complaints related to billing

suggests that there is still scope to improve the comparability, clarity and accuracy of

billing information.

Despite technical innovations that allow consumers to better and more easily manage their

energy use

–

smart grids, smart homes, rooftop solar panels and storage, for example

–

consumers are not sufficiently able to actively participate in electricity markets and match

demand with supply during peak times, particularly through demand-response. This is

because households and businesses often have scarce knowledge and little or no incentive

to change the amount of electricity they use or produce in response to changing prices in

the markets. Indeed, a host of issues such as a slow roll out of fully functional smart

metering systems, regulated prices, lacklustre competition between retailers and an

increasing portion of fixed charges in energy bills mean that real-time price signals are

usually not passed on to final consumers.

In some Member States, up to 90% of renewable electricity generation is connected at

distribution level, putting more pressure on distribution system operators ('DSOs') to

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actively manage their grids and to efficiently adjust to the increasing share of variable and

decentralized renewable electricity injected into their networks. However

–

in contrast to

transmission system operators ('TSOs')

–

the current regulatory framework does not always

provide appropriate tools to DSOs to do this, resulting in network charges that are often

higher than they could be for end consumers. Ensuring that all DSOs become more flexible

would create a level playing field for the deployment of renewable generation that would

make attaining the EU's climate and energy objectives easier.

The deployment of information technology offers the possibility to address these issues,

facilitating the development of new services, improving consumer's comfort and making

the market more contestable and efficient. However, to fully benefit from the digitalisation

of the electricity market we need a non-discriminatory data management framework that

makes the right information immediately available to the right market actors, while at the

same time ensuring a high level of data protection.

With regard to consumer protection, there is a need to ensure that the move towards more

efficient retail markets does not lead to any group of consumers being left behind. In

particular, rising energy poverty as well as a lack of clarity on the most appropriate means

of tackling consumer vulnerability and energy poverty can hamper the further deepening

of the internal energy market.

In the current context, wholesale electricity prices have been decreasing

due to number

of coinciding drivers: a decline in primary energy prices, a surplus of carbon allowances

and an overcapacity of power generation facilities in some regions of the EU caused by a

drop in electricity demand, rising investments in renewables driven by EU policies and

increased sharing of resources among Member States through market coupling.

For most regions in Europe,

current electricity wholesale prices do not indicate the

need for new investments into electricity generation.

However, in the current market

arrangement, prices often do not reflect the real value of electricity due to regulatory

failures such as the lack of scarcity pricing and inadequately delimited price (or bidding)

zones. These regulatory failures, taken together with the increasing penetration of

electricity generated from renewable sources with low operating costs, affect the

remuneration of conventional electricity generation units that operate less often but

contribute to providing security and flexibility to the system

–

alongside non-conventional

flexible generation, interconnections, storage and demand response.

In light of the 2030 objective for renewable energy, considerable new investment in

electricity generation capacity will be required. The largest part will be provided by

variable renewable generation, complemented to a certain extent by more predictable,

flexible, less carbon-intensive forms of power generation. Independently of current

overcapacities, there are growing concerns in some areas of Europe that current average

wholesale prices may not provide appropriate signals for the necessary investments into

future generation or for keeping sufficient capacity in the market. A number of Member

States anticipate inadequate generation capacity in future years and introduce capacity

mechanisms at national level to support investment in capacity and ensure system

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adequacy (i.e. the ability of the electricity system to serve demand at all times).

When

uncoordinated

and designed without a proper assessment of the appropriate level of

supply security,

capacity mechanisms may risk affecting cross-border trade, distorting

investment signals,

affecting thus the ability of the market to deliver any new investments

in conventional and low-carbon generation,

and strengthening market power

incumbents by not allowing alternative providers to enter the market.

Despite best efforts to build an integrated and resilient power market, crisis situations can

never be excluded. The potential for crisis situation increases with climate change (e.g.

extreme weather conditions) and the emergence of new areas that are subject to criticalities

such as malicious attacks and cyber-threats. Such crises tend to often have an immediate

cross-border effect in electricity. Where systems are interconnected, incidents that start

locally can rapidly spread beyond borders and crisis situations might also affect several

Member States at the same time (e.g. prolonged heat waves or cold spells).

Today,

risk assessments as well as plans and actions for dealing with electricity crisis

situations focus on the national context only

and there is insufficient information-sharing

and transparency across Member States. In addition, there are different views on what is

to be considered as a risk to security of supply. In an increasingly inter-connected

electricity market, the lack of common approach and coordination can seriously imperil

security of supply across borders and dangerously undermine the functioning of the

internal electricity market.

In addition, missing opportunities to exchange energy with neighbours remains a key

obstacle to the internal energy market. Even where interconnectors are in place, they often

remain unused due to a lack of coordination between Member States. Rules are therefore

needed that ensure that the use of interconnection is not unduly limited by national

interventions.

Based on the above-mentioned shortcomings and underlying drivers, the present impact

assessment has identified four key problem areas that are addressed in the proposed

initiative:

i) the current market design is not fit for integrating an increasing share of

variable, decentralised generation and for reaping the potential of technological

developments; ii) uncertainty about sufficient future generation investments and

uncoordinated capacity mechanisms; iii) Member States do not take sufficient

account of what happens across their borders when preparing for and managing

electricity crisis situations; and iv) as regards retail markets, there is a slow

deployment and low levels of services and poor market performance are wide-spread

in the EU.

III.

SUBSIDIARITY

Article 194 of the Treaty of the Functioning of the EU consolidated and clarified the

competences of the EU in the field of energy and is the legal basis of the current proposal.

Electricity markets have become more integrated and interdependent physically,

economically and from a regulatory point of view, due to increasing cross-border

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electricity trade, growing share of renewable energy sources and more interconnections in

the European electricity grid. The challenges can no longer be addressed as effectively by

individual Member States. New frameworks to further integrate the internal energy market

and improve the conditions for competition while at the same time adjusting to the

decarbonisation targets and ensuring a more coordinated policy response to security of

supply, can most effectively be achieved at European level.

IV.

SCOPE AND OBJECTIVES

Against this background and in line with the Union's policy on climate change and energy,

the general policy objective of the present initiative is to make electricity markets more

secure, efficient and competitive, while ensuring that electricity is generated in a

sustainable way and remains affordable to all consumers. The present impact assessment

reflects and analyses the need and policy options for a possible revision of the main

framework governing electricity markets and security of supply policies in Europe.

There are four specific objectives: i) adapt the market design for the cost effective

operation of variable and often decentralised generation, taking into account technological

developments; ii) facilitate investments in generation capacity in the right amount and type

of resources for the EU: iii) improve Member States' resilience on each other in times of

system stress and reinforce their coordination and cooperation regarding crisis situations;

and iv) address the root causes of weak competition on energy retail markets and improve

consumer protection and engagement.

Interlinkages with parallel initiatives

The proposed initiative is strongly linked to other energy and climate related legislative

proposals brought forward in parallel, including the renewable energy package which

covers a number of measures deemed necessary to attain the EU binding objective of

reaching a level of at least 27% renewables in final EU energy consumption by 2030. The

renewable energy directive has synergies with the present initiative, which seeks to adapt

the current market design to the increasing share of variable decentralised generation and

technological development and to create an environment conducive for investments in

renewables.

In particular, the reflections on a revised Renewables Energy Directive will include

framework principles on support schemes for market-oriented, cost-effective and more

regionalised support to RES E up to 2030, in case Member States were opting to have them

as a tool to facilitate target achievement. Conversely, measures aimed at the integration of

RES E in the market, such as provisions on priority dispatch and access previously

contained in the Renewables Directive are part of the present market design initiative. The

Renewable Package also deals with legal and administrative barriers for self-consumption,

whereas the present package addresses market related barriers to self-consumption.

Both the market design and renewable energy impact assessments come to the conclusion

that the improved electricity market, supported through a revised Emission Trading System

('ETS'), could, under certain conditions, by 2030 deliver investments in the most mature

low-carbon technologies (such as PV and onshore wind). However, until such conditions

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materialise, market-based support schemes will still be needed in order to provide

investment certainty. Less mature RES E technologies, such as offshore wind, will likely

need some form of support throughout the transitional period.

The Energy Union governance initiative also has synergies with the present initiative and

will contribute to ensure policy coherence and reduce administrative impact. It will also

streamline the reporting obligations by Member States and the Commission that are

presently enshrined in the Third Package.

In general terms, energy efficiency measures also interact with the present initiative as they

affect the level and structure of electricity demand. In addition, energy efficiency measures

can alleviate energy poverty and consumer vulnerability. Besides consumer income and

energy prices, energy efficiency is one of the major drivers of energy poverty. The

provisions previously contained in the energy efficiency legislation on demand response,

billing and metering will be set out in the present initiative.

The present initiative is furthermore consistent with the findings of the sector inquiry on

capacity mechanisms. Pointing out that there is a lack of adequate assessment of the actual

need for capacity mechanisms, the sector inquiry emphasizes that where needed capacity

mechanisms need to be designed with transparent and open rules of participation that does

not undermine the functioning of the electricity market, taking into account cross border

participation.

The Commission Regulation establishing a Guideline on Electricity Balancing ('Balancing

Guideline') is also closely related to the present initiative as it aims to harmonise certain

aspects of the EU's balancing markets and to optimise cross-border usage. Indeed, efficient,

integrated balancing markets are an important building block for the consistent functioning

and flexibility of the market which in turn is needed for a cost effective integration of RES

E into the electricity market.

DESCRIPTION OF POLICY OPTIONS AND METHODOLOGY

In assessing all possible options (ranging from non-regulatory to legislative policy options)

the following approach was taken:

Identification of a set of high level options for each problem area. Each of these high

level options contains sub-options for specific measures;

Assessment of each specific measure, comparing a number of options in order to select

the preferred approach.

The following policy options have been considered:

Regarding Problem Area I: the need to adapt the market design to the increasing

share of variable decentralised generation and technological developments,

Option 0+ (Non-regulatory approach) provides little scope for improving the market and

the level-playing field among resources. Indeed, the current EU regulatory framework is

limited in certain areas (e.g., balancing and intraday markets) and even non-existent for

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other areas (e.g., role of DSOs in data management). Besides, voluntary cooperation may

not provide for the appropriate levels of harmonisation or certainty to the market and

legislation. This option was therefore discarded.

Two possible paths going beyond the baseline scenario were however identified and

assessed: (i) enhancing current market rules through EU regulatory action in order to

increase the flexibility of the system, retaining to a certain extent the national operation of

the systems (Option 1) and, (2) moving to a fully integrated approach via relatively far-

reaching changing to the current regulatory framework (Option 2).

Option 1 of enhancing the current market rules comprises three different sub-options:

Option 1(a)

Creating a level-playing field among all generation technologies and

resources and remove existing market distortions. It addresses rules that

discriminate between resources and which limit or favour the access of

certain technologies to the electricity grid (such as so-called 'must-run'

provisions and rules on priority dispatch and access). In addition, all market

participants would bear financial responsibility for the imbalances caused

on the grid and all resources would be remunerated in the market on equal

terms. Barriers to demand-response would be removed. Exemptions from

certain regulatory provisions may, in some cases, be required, notably for

certain small-scale installations and emerging technologies.

(In addition to sub-option (a)) Strengthening the short-term markets by

bringing them closer to real-time in order to provide maximum opportunity

to meet the flexibility needs and balance the market. The sizing of balancing

reserves and their use would be harmonised in larger balancing zones in

order to optimally exploit interconnections and cross-border exchange in

shorter term markets.

(In addition to sub-option (a) and (b)) Pulling all flexible distributed

resources concerning generation, demand and storage, into the market via

proper incentives and a market framework better adapted to them. This

would be based on smart-metering allowing consumers to directly react to

price signals and measures to incentivise DSOs to manage their networks in

a flexible and cost-efficient way.

Option 1(b)

Option 1(c)

Option 2 (fully integrated market) considers measures that would aim to deliver a truly

integrated pan-European electricity market through the adoption of far-reaching measures

changing the current regulatory framework.

Regarding Problem Area II: uncertainty about sufficient future generation

investments and uncoordinated capacity mechanisms,

four options were considered.

As regards Option 0+ (Non-regulatory approach), existing provisions under EU legislation

are not sufficiently clear and robust to cope with the challenges facing the European

electricity system. In addition, voluntary cooperation may not provide for appropriate

levels of harmonisation across all Member States or certainty to the market. Legislation is

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needed in this area to address the issues in a consistent way. This Option was therefore

discarded.

Various policy options going beyond the baseline scenario were assessed. They differ

according to which extent market participants can rely on energy market payments. Each

policy option also considers varying degrees of alignment and coordination among

Member States at EU-level.

Option 1 (energy-only market without capacity mechanisms) builds upon Option 1(a) to

1(c) under problem area I and would be based on additional measures to further strengthen

the internal electricity market. Under this option, it is assumed that European markets, if

sufficiently interconnected and undistorted, can provide for the necessary price signals to

incentivise investments in new generation thus also reducing the need for government

interventions in support thereof. This option consists of improving price signals by

removing price caps in order to allow scarcity pricing during peak time. At the same time,

price signals could drive the geographical location of new investments and production

decisions, via price zones aligned with structural congestion in the transmission grid.

Option 2 and 3 include the measures presented in Option 1, but allow capacity mechanisms

under certain conditions and propose possible measures to better align them among

Member States in order to avoid negative consequences for the functioning of the internal

market. These options build on the European Commission's 'EEAG' state aid Guidelines

and the Sector Inquiry on capacity mechanisms. In Option 2, capacity mechanisms are

based on a transparent and EU-wide resource adequacy assessment carried-out by the

European Network of Transmission System Operators for electricity ('ENTSO-E'). Such

EU-wide assessment would also allow for effective cross-border participation.

Additionally, Option 3 would provide for common design features for better compatibility

between national capacity mechanisms and harmonised cross-border cooperation.

Under Option 4 based on regional or EU-wide generation adequacy assessments, entire

regions or ultimately all EU Member States would be required to roll out capacity

mechanisms on a mandatory basis. This option was found to be disproportionate and was

discarded.

Regarding Problem Area III: the lack of coordination among Member States when

preparing for and managing electricity crisis situations,

five policy options ranging

from the baseline scenario (Option 0) to the full harmonization and decision making at

regional level have been identified.

Option 0+ (Non-regulatory approach). As current legislative provisions do not prescribe

how Member States should prevent and manage crisis situations nor mandate any form of

cross-border co-operation, better implementation and enforcement actions will be of no

avail. In addition, whilst there is some voluntary cross-border cooperation in this area, it is

limited to a few regional parts of the EU. This option was discarded.

Under Option 1 (Common minimum EU rules), Member States would have to respect a

set of common rules and principles regarding crisis prevention and management, agreed at

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the European level ('minimum harmonisation'). Accordingly, non-market measures should

only be introduced as a means of last resort, when duly justified. Member States would be

obliged to address electricity crisis situations, in particular situations of a simultaneous

crisis, in a spirit of co-operation and solidarity. Member States should inform each other

and the Commission without undue delay when they see a crisis situation coming or when

being in a crisis situation. Member States would be obliged to develop national Risk

Preparedness Plans ('Plan') with the aim to avoid or better tackle crisis situations. Plans

could be prepared by TSOs, but need to be endorsed at the political level. On cyber-

security, Member States would need to set out in the Plan how they will prevent and

manage cyberattack situations.

Option 2 (EU rules + regional cooperation) would include all common rules included in

Option 1. In addition, it would put in place rules and tools to ensure that effective cross-

border co-operation takes place in a regional and EU context. Thus, there would be a

systematic assessment of rare/extreme risks at the regional level. The identification of

crisis scenarios would be carried out by ENTSO-E in a regional context and tasks would

be delegated to Regional Operation Centres (ROCs). For cybersecurity, the Commission

would propose the development of a network code/guideline which would ensure a

minimum level of harmonization in the energy sector throughout the EU. The Risk

Preparedness Plans would contain two parts

–

a part reflecting national measures and a

part reflecting measures to be pre-agreed in a regional context (including regional 'stress

tests', procedures for cooperation in different crisis scenarios and agreement on how to deal

with simultaneous electricity crisis situations).

Option 3 (Full harmonisation) entails full harmonisation and decision-making at regional

level. The risk preparedness plans would be developed on regional level in order to allow

a harmonised response to potential crisis situation in each region. On cybersecurity, Option

3 would go one step further and nominate a dedicated body (agency) to deal with

cybersecurity in the energy sector. Crisis would have to be managed according to the

regional plans agreed among Member States. A detailed 'emergency rulebook' for crisis

handling would be put in place, containing an exhaustive list of measures that can be taken

by Member States in crisis situations.

Regarding Problem Area IV: retail markets and the slow deployment and low levels

of services and poor market performance,

four policy options have been considered

ranging from baseline scenario (Option 0) to full harmonization and extensive safeguards

for consumers.

Option 0+ (Improved implementation/enforcement and non-regulatory approach) consists

in sharing of good practices and increasing the efforts to correctly implement the

legislation. This non-regulatory approach addresses competition and consumer

engagement issues by strengthening the enforcement of the existing legislation as well as

through bilateral consultation with Member States to progressively phase-out price

regulation, starting with prices below costs. It also considers developing a

Recommendation on energy bills. However, this option does not tackle the third problem

driver of the market failures that prevent effective data flow between market actors.

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Under Option 1 (Flexible legislation), all problem drivers are addressed through new

legislation. To improve competition, Member States progressively phase-out blanket price

regulation by a deadline specified in new EU legislation, starting with prices below costs,

while allowing transitional price regulation for vulnerable consumers. To increase

consumer engagement, the use of contract termination fees is restricted. Consumer

confidence in comparison websites is fostered through national authorities implementing

a certification tool. In addition, high-level principles ensure that energy bills are clear and

easy to understand, through minimum content requirements. A generic adaptable,

definition of energy poverty based on household income and energy expenditure is

proposed in the legislation for the first time. Finally, to allow the development of new

services by new entrants and energy service companies, non-discriminatory access to

consumer data is ensured.

Building on Option 1, Option 2 (Full harmonisation and extensive consumer safeguards)

aims to provide maximum safeguards for consumers and extensive harmonisation of

Member States action throughout the EU. Exemptions to price regulation are defined at

EU level on the basis of either a consumption threshold or a price threshold. A standard

data handling model is enforced and assigns the responsibility to a neutral market actor

such as a TSO. All switching fees including contract termination fees are banned and the

content of energy bills is partially harmonized. Finally, an EU framework to monitor

energy poverty based on an energy efficiency survey done by Member States of the

housing stock as well as preventive measures to avoid disconnections are put in place.

POLICY TRADE-OFFS

The measures considered in this impact assessment are highly complementary. Most of the

different options considered in each problem area would reinforce the effect of options in

other problem areas, with little trade-offs between the different areas. The overall

beneficial effects will be achieved only if all measures are implemented as a package

The measures under Problem Area I and II are strongly linked in that they collectively aim

at improving market functioning, including the delivery of investment by the market.

Measures under Problem Area I and Option 1 of Problem area II thus reduce the need for

market government intervention by means of capacity mechanisms. The other measures

under Problem Area II reduce their distortive effects if such mechanisms are nonetheless

justified.

Scarcity pricing and capacity mechanisms can to a certain degree be seen as alternative

measures to foster investments. With assets remunerated by capacity mechanisms, the

effectiveness of scarcity prices may be reduced. It needs also to be noted that scarcity prices

and market-wide capacity mechanisms incentivise different investment decisions: whereas

such capacity mechanisms may reward any firm capacity, scarcity pricing will improve

remuneration of flexible capacity in particular.

The measures aiming at providing adequate price signals (measures under Problem Area I

and Problem Area Option 1) are no-regret options. Until these conditions are achieved and

under specific circumstances (like energy isolation), State intervention in the form of some

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type of capacity mechanism may be necessary. That is why it is essential that such

mechanisms are properly designed, taking into account the wider regional and European

resources and allowing cross-border participation in a technology-neutral manner.

The measures assessed under various options in the impact assessment seek to improve the

overall flexibility of the electricity system. However, they do this by employing different

means. Investment in new interconnection capacity may reduce the need for new

generation and vice-versa, new generation can reduce the incentives for new interconnector

capacity. Similarly, pulling demand response into the market will reduce the profits of

generation capacity. Ultimately, the efficient markets should opt for the most cost-efficient

solutions.

Energy poverty safeguards whose costs directly accrue to suppliers

–

particularly, the

disconnection safeguards considered in Option 2 (Harmonization and extensive consumer

safeguards) of Problem Area IV (Retail markets)

–

may act as a barrier to retail-level

competition, and diminish the associated benefits to consumers, including lower prices,

new and innovative products, and higher levels of service. Although the implementation

costs of these safeguards will be passed on to consumers, and therefore socialized, different

energy suppliers may have different abilities to do this, and to deal with the additional

consumer engagement costs. Some may therefore choose not to enter markets with such

safeguards in place.

VII.

ANALYSIS OF IMPACTS AND CONCLUSIONS

All options have been compared against each other using, the baseline scenario as a

reference and applying the following criteria:

Effectiveness: the options proposed should first and foremost be effective and thus be

suitable to addressing the specified problem;

Efficiency: this criterion assesses the extent to which objectives can be achieved at the

least cost (benefits versus the costs).

Policy options regarding the need to adapt the market design to the increasing share

of variable decentralised generation and technological developments (Problem Area

Options 1(a) (level playing field), 1(b) (strengthening short-term markets) and 1(c)

(demand response/distributed resources) represent an interlinked set of measures regarding

the integration of the national electricity markets and present a compromise between

bottom-up initiatives and top-down steering of the market development, without

substituting the role of national governments, regulators and TSOs by a centralised and

fully harmonised system.

However, Option 1(a) (level playing field) and Option 1(b) (strengthening short-term

markets) do not cover measures to pull all distributed flexible resources (demand-response,

renewable electricity and storage) into the market. These options do not take advantage of

the potential offered by these resources to efficiently operate and decarbonise the

electricity market.

kom (2016) 0863 - Ingen titel

In this context, Option 1(c) (demand response/distributed resources) provides a more

holistic, effective and efficient package of solutions. While this option may lead to minor

additional administrative impacts for Member States and competent authorities regarding

the implementation and monitoring of the measures, these impacts will be offset by lower

barriers to entry to start-ups and SMEs, by the benefits to market parties from more stable

regulatory frameworks and new business opportunities as well as by the benefits to

consumers from more competition and access to wider choice.

As regards Option 2 (fully integrated market), while having advantages in terms of less

coordination requirements (i.e., a fully integrated EU-market can be operated more

efficiently), the results of the assessment indicate that the move towards a more integrated

European approach has less significant economic added value since most of the benefits

will have already been reaped under the regional, more decentralised approach under

option. In addition, it has significant impacts on stakeholders, Member States and

competent authorities since it requires significant changes to established practices.

Preferred option for Problem Area I: Option 1(c) (demand

response/distributed

resources, also encompassing options 1(a) (level playing field) and 1(b) (strengthening

short-term markets))

Policy options regarding uncertainty about sufficient future generation investments

and uncoordinated capacity mechanisms (Problem Area II)

Option 1 (reinforced energy only market without capacity mechanisms) can in principle

provide the right signals for market operation and ensure system adequacy and ensure

better utilisation of resources across borders, demand participation and renewable

integration without subsidies. Improving the functioning of electricity markets will

improve the conditions for investment in the electricity market to ensure reliable and

effective supply of electricity, even in times of scarcity. This will in turn decrease the need

for capacity mechanisms.

However, markets are today still characterised by manifold regulatory distortions today

and removing the distortive effects will not be possible with immediate effects in many

Member States. Besides under such option, uncertainty about future policy directions or

governmental interventions still exists. Such uncertainty may hamper investment and in

turn create the need for mechanisms that address the lack of investments ('missing money').

It should be noted that undistorted energy price signals are fundamental irrespective of

whether generators are solely relying on energy market incomes or also receive capacity

payments. Therefore the measures aimed at removing distortions from energy-only

markets discussed under Option 1(a) to 1(c) (e.g. scarcity pricing or reinforced locational

signals) are 'no-regrets' and assumed as being integral parts of Options 2, 3 and 4.

Option 2

(Improved

energy markets

–

Capacity Mechanisms ('CM's) only when needed,

based on a common EU-wide adequacy assessment can improve the overall cost-efficiency

of the electricity sector through establishing an EU-wide approach to system adequacy

assessments as opposed to national-based adequacy assessments. At the same time Option

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2 does not allow reaping the full benefits of cross-border participation in capacity

mechanisms.

A more coordinate approach to state interventions across Member States is needed and is

a clear priority for reform. Placing capacity mechanisms into a more regional/EU context

is a pre-requisite to reduce market distortions. It is indeed necessary that the schemes

Member States introduce are compatible with internal market rules.

Option 3 (Improved energy market

–

CMs only when needed, plus cross-border

participation) proposes additional measures to avoid fragmentation of capacity

mechanisms and ensures that foreign resource providers can effectively participate in

national capacity mechanisms and avoids competition and market distortions resulting

from capacity payments which are reserved to domestic participants. As a result, it reduces

investment distortions that might be present in Option 2 because of uncoordinated

approaches to cross-border participation.

Preferred option for Problem Area II: Option 3 (Improved energy market

–

CMs

only when needed, plus cross-border participation)

(encompassing also Options 1 and

Policy options regarding the lack of coordination among Member States when

preparing for and managing electricity crisis situations (Problem Area III)

Based on a set of clear common rules, Option 1 (Common minimum EU rules) would

improve the level of transparency and crisis management across Europe and is likely to

reduce the chances of premature market intervention. The policy tools proposed under this

option would bring economic benefits to businesses and consumers by helping to prevent

costly blackout situations. However, this option does not solve the issue of uncoordinated

planning and preparation ahead of a crisis since Member State are not required to take into

account cross-border risks and crisis.

Under Option 2 (EU rules + regional cooperation), the regionally coordinated plans ensure

the regional identification of risks and the consistency of the measures for prevention and

managing crisis situations while respecting national differences and competences. This

significantly improves the level of preparedness (compared to Option 1) at national,

regional and EU level, as the cross border considerations are duly taken into account since

the beginning. A regional approach to security of supply results in a better utilisation of

power plants and guarantees risk preparedness at a lesser cost.

Under Option 3 (Full harmonisation), the estimated impact on cost is likely to be high

(notably with the creation of an EU agency on cyber-security) and the measures put

forward appear disproportionate compared to the expected effectiveness. Indeed, this

option represents a highly intrusive approach

–

with significant administrative impact - by

resorting to a full harmonisation of principles and the prescription of concrete solutions.

Preferred option for Problem Area III: Option 2

(EU

rules + regional cooperation)

Policy options regarding retail markets and the slow deployment and low levels of

services and poor market performance (Problem Area IV)

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Given its low implementation costs, Option 0+ (Non-regulatory approach) is a highly

efficient option. However, the effectiveness of Option 0+ is significantly limited by the

fact that non-regulatory measures are not suitable for tackling the poor data flow between

retail market actors that constitutes both a barrier to entry and a barrier to higher levels of

service to consumers. In addition, shortcomings in the existing legislation make it

impossible to significantly improve consumer engagement and energy poverty safeguards.

They also introduce great uncertainty around the drive to phase out price regulation which

does not provide sufficient incentives to consumers to play an active role in the market and

which also limits competition and new entrants into the market.

Option 1 (Flexible legislation) would lead to substantial economic benefits. Retail

competition would be improved as a result of the progressive phase-out of blanket price

regulation, non-discriminatory access to consumer data, and increased consumer

engagement. In addition, consumers would see direct benefits through improved switching.

In Option 2 (Harmonization and extensive consumer safeguards) there is uncertainty over

the size of the economic benefits. This uncertainty stems from the tension some of the

measures in Option 2 may have with competition (stronger disconnection safeguards, an

outright ban on all switching-related charges), and from the difficulty of prescribing EU-

level solutions in certain areas (defining exceptions to price deregulation, implementing a

standard EU bill design). Besides, a single EU data management model would have high

implementation costs, thus reducing the efficiency of the option.

Preferred option for Problem Area IV: Option 1 (Flexible legislation)

***

TABLE OF CONTENTS

1.1.

INTRODUCTION ............................................................................................................. 22

Background and scope of the market design initiative ............................................................. 22

Context of the initiative ............................................................................................................. 22

1.1.1.1.

The gradual process of creating an internal electricity market ....................................... 22

1.1.1.2.

The Union's policy concerning climate change ................................................................ 22

1.1.1.3.

Paradigm shift in the electricity sector ............................................................................ 23

1.1.1.4.

The vision for the EU electricity market in 2030 and beyond .......................................... 24

Scope of the initiative ................................................................................................................ 30

1.1.2.1.

Current relevant legislative framework ........................................................................... 30

1.1.2.2.

Policy development subsequent to the Third Package .................................................... 31

1.1.2.3.

Scope and summary of the initiative ............................................................................... 32

Organisation and timing ............................................................................................................ 33

1.1.3.1.

Follow up on the Third Package ....................................................................................... 33

1.1.3.2.

Consultation and expertise .............................................................................................. 34

1.2.

Interlinkages with parallel initiatives........................................................................................ 34

The Renewable Energy Package comprising the new Renewable Energy Directive and

bioenergy sustainability policy for 2030 ('RED

II')

................................................................................... 34

Commission guidance on regional cooperation ........................................................................ 36

The Energy Union governance initiative .................................................................................... 36

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The Energy Efficiency legislation ('EE') and the related Energy Performance of Buildings

Directive ('EPBD') including the proposals for their amendment. ........................................................... 36

The Commission Regulation establishing a Guideline on Electricity Balancing ('Balancing

Guideline') ................................................................................................................................................ 37

Other relevant instruments ....................................................................................................... 38

PROBLEM DESCRIPTION............................................................................................. 38

2.1.

Problem Area I: Market design not fit for an increasing share of variable decentralized

generation and technological developments ......................................................................................... 38

Driver 1: Short-term markets, as well as balancing markets, are not efficiently organised ...... 40

Driver 2: Exemptions from fundamental market principles ...................................................... 42

Driver 3: Consumers do not actively engage in the market and demand response potential

remains largely untapped ........................................................................................................................ 44

Driver 4: Distribution networks are not actively managed and grid users are poorly

incentivised .............................................................................................................................................. 50

2.2.

Problem Area II: Uncertainty about sufficient future generation investments and

uncoordinated capacity markets ............................................................................................................ 51

Driver 1: Lack of adequate investment signals due to regulatory failures and imperfections in

the electricity market ............................................................................................................................... 55

Driver 2: Uncoordinated state interventions to deal with real or perceived capacity problems

2.3.

Problem Area III: Member States do not take sufficient account of what happens across their

borders when preparing for and managing electricity crisis situations................................................... 63

Driver 1: Plans and actions for dealing with electricity crisis situations focus on the national

context only ............................................................................................................................................. 65

Driver 2: Lack of information-sharing and transparency ........................................................... 67

Driver 3: No common approach to identifying and assessing risks ........................................... 68

2.4.

Problem Area IV: The slow deployment of new services, low levels of service and questionable

market performance on retail markets .................................................................................................. 69

Driver 1: Low levels of competition on retail markets .............................................................. 70

Driver 2: Possible conflicts of interest between market actors that manage and handle data 74

Driver 3: Low levels of consumer engagement ......................................................................... 75

2.5.

2.6.

What is the EU dimension of the problem? .............................................................................. 76

How would the problem evolve, all things being equal? .......................................................... 77

The projected development of the current regulatory framework ........................................... 77

Expected evolution of the problems under the current regulatory framework........................ 78

Issues identified in the evaluation of the Third Package ........................................................... 79

2.7.

3.1.

SUBSIDIARITY ................................................................................................................ 80

The EU's right to act ................................................................................................................. 80

3.2.

Why could Member States not achieve the objectives of the proposed action sufficiently by

themselves? ........................................................................................................................................... 80

3.3.

Added-value of action at EU-level ............................................................................................ 82

4.1.

OBJECTIVES ..................................................................................................................... 83

Objectives and sub-objectives of the present initiative ............................................................ 83

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4.2.

Consistency of objectives with other EU policies ...................................................................... 84

POLICY OPTIONS ........................................................................................................... 87

5.1.

Options to address Problem Area I (Market design not fit for an increasing share of variable

decentralized generation and technological developments) .................................................................. 88

Overview of the policy options .................................................................................................. 88

Option 0: Baseline Scenario

–

Current Market Arrangements .................................................. 89

Option 0+: Non-regulatory approach ........................................................................................ 90

Option 1: EU Regulatory action to enhance market flexibility .................................................. 91

5.1.4.1.

Sub-option 1(a): Level playing field amongst participants and resources ....................... 93

5.1.4.2.

Sub-option 1(b): Strengthening short-term markets ....................................................... 95

5.1.4.3.

Sub-option 1(c): Pulling demand response and distributed resources into the market .. 98

Option 2: Fully Integrated EU market ...................................................................................... 102

For Option 1 and 2: Institutional framework as an enabler .................................................... 104

Summary of specific measures comprising each Option ......................................................... 106

5.2.

Options to address Problem Area II (Uncertainty about sufficient future generation

investments and uncoordinated capacity markets) .............................................................................. 110

Overview of the policy options ................................................................................................ 110

Option 0: Baseline Scenario

–

Current Market Arrangements ................................................ 111

Option 0+: Non-regulatory approach ...................................................................................... 112

Option 1: Improved energy market - no CMs .......................................................................... 112

Option 2: Improved energy market

–

CMs only when needed, based on a common EU-wide

adequacy assessment) ........................................................................................................................... 114

Option 3: Improved energy market - CMs only when needed, based on a common EU-wide

adequacy assessment, plus cross-border participation ......................................................................... 116

Option 4: Mandatory EU-wide or regional CMs ...................................................................... 117

Discarded Options ................................................................................................................... 117

Summary of specific measures comprising each Option ......................................................... 117

5.3.

Options to address Problem Area III (When preparing or managing crisis situations, Member

States tend to disregard the situation across their borders) ................................................................ 120

Overview of the policy options ................................................................................................ 120

Option 0: Baseline scenario

–

Purely national approach to electricity crises .......................... 120

Option 0+: Non-regulatory approach ...................................................................................... 121

Option 1: Common minimum rules to be implemented by Member States ........................... 122

Option 2: Common minimum rules to be implemented by Member States, plus regional co-

operation ............................................................................................................................................... 124

Option 3: Full harmonisation and decision-making at regional level ...................................... 127

Discarded Options ................................................................................................................... 128

Summary of specific measures comprising each Option ......................................................... 128

5.4.

Options to address Problem Area IV (Slow deployment and low levels of services and poor

market performance) ........................................................................................................................... 132

Overview of the policy options ................................................................................................ 132

Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer

engagement and poor data flows .......................................................................................................... 132

Option 0+: Non-regulatory approach to address competition and consumer engagement ... 133

Option 1: Flexible legislation addressing all problem drivers .................................................. 134

Option 2: EU Harmonization and extensive safeguards for consumers addressing all problem

drivers 136

Summary of specific measures comprising each Option ......................................................... 137

ASSESSMENT OF THE IMPACTS OF THE VARIOUS POLICY OPTIONS ....... 139

6.1.

Assessment of economic impacts for Problem Area I (Market design not fit for an increasing

share of variable decentralized generation and technological developments ...................................... 139

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Methodological Approach ....................................................................................................... 139

6.1.1.1.

Impacts Assessed ........................................................................................................... 139

6.1.1.2.

Modelling and use of studies ......................................................................................... 140

6.1.1.3.

Summary of Main Impacts ............................................................................................. 140

6.1.1.4.

Overview of Baseline (Current Market Arrangements) ................................................. 141

Policy Sub-option 1(a) (Level playing field amongst participants and resources) ................... 144

6.1.2.1.

Economic impacts .......................................................................................................... 144

6.1.2.2.

Who would be affected and how ................................................................................... 147

6.1.2.3.

Administrative impact on businesses and public authorities......................................... 147

Impacts of Policy Sub-option 1(b) (Strengthening short-term markets) ................................. 147

6.1.3.1.

Economic Impacts .......................................................................................................... 147

6.1.3.2.

Who would be affected and how ................................................................................... 150

6.1.3.3.

Administrative impact on businesses and public authorities......................................... 150

Impacts of Policy Sub-option 1(c) (Pulling demand response and distributed resources into the

market) 151

6.1.4.1.

Economic Impacts .......................................................................................................... 151

6.1.4.2.

Who would be affected and how ................................................................................... 152

6.1.4.3.

Impact on businesses and public authorities ................................................................. 153

Impacts of Policy Option 2 (Fully integrated EU market) ........................................................ 154

6.1.5.1.

Economic Impacts .......................................................................................................... 154

6.1.5.2.

Who would be affected and how ................................................................................... 155

6.1.5.3.

Impact on businesses and public authorities ................................................................. 155

Environmental impacts of options related to Problem Area I ................................................. 155

Summary of modelling results for Problem Area I .................................................................. 156

6.2.

Impact Assessment for Problem Area II (Uncertainty about future generation investments and

fragmented capacity mechanisms) ....................................................................................................... 164

Methodological Approach ....................................................................................................... 164

6.2.1.1.

Impacts Assessed ........................................................................................................... 164

6.2.1.2.

Modelling ....................................................................................................................... 164

6.2.1.3.

Overview of Baseline (Current Market Arrangements) ................................................. 165

Impacts of Policy Option 1 (Improved energy markets - no CMs ) .......................................... 166

6.2.2.1.

Economic Impacts .......................................................................................................... 166

6.2.2.2.

Who would be affected and how ................................................................................... 167

6.2.2.3.

Administrative impact on businesses and public authorities......................................... 167

Impacts of Policy Option 2 (Improved energy markets

–

CMs only when needed, based on a

common EU-wide adequacy assessment) ............................................................................................. 168

6.2.3.1.

Economic Impacts .......................................................................................................... 168

6.2.3.2.

Who would be affected and how ................................................................................... 169

6.2.3.3.

Impact on businesses and public authorities ................................................................. 169

Impacts of Policy Option 3 (Improved energy market

–

CMs only when needed, plus cross-

border participation).............................................................................................................................. 170

6.2.4.1.

Economic Impacts .......................................................................................................... 170

6.2.4.2.

Who would be affected and how ................................................................................... 170

6.2.4.3.

Impact on businesses and public authorities ................................................................. 171

Environmental impacts of options related to Problem Area II ................................................ 171

Overview of modelling results for Problem Area II ................................................................. 171

6.2.6.1.

Improved Energy Market as a no-regret option ............................................................ 171

6.2.6.2.

Comparison of Options 1 to 3 ........................................................................................ 173

6.2.6.3.

Delivering the necessary investments............................................................................ 178

6.2.6.4.

Level and volatility of wholesale prices .......................................................................... 185

6.3.

Impact Assessment for problem Area III (reinforce coordination between Member States for

preventing and managing crisis situations) .......................................................................................... 187

Methodological Approach ....................................................................................................... 187

Impacts of Policy Option 1 (Common minimum rules to be implemented by Member States)

188

6.3.2.1.

Economic impacts .......................................................................................................... 188

6.3.2.2.

Who would be affected and how ................................................................................... 189

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6.3.2.3.

Impact on businesses and public authorities ................................................................. 189

Impacts of Policy Option 2 (Common minimum rules to be implemented by Member States

plus regional co-operation) .................................................................................................................... 190

6.3.3.1.

Economic impacts .......................................................................................................... 190

6.3.3.2.

Who would be affected and how ................................................................................... 192

6.3.3.3.

Impact on businesses and public authorities ................................................................. 192

Impacts of Policy Option 3 (Full harmonisation and full decision-making at regional level) ... 193

6.3.4.1.

Economic impacts .......................................................................................................... 193

6.3.4.2.

Who would be affected and how ................................................................................... 193

6.3.4.3.

Impact on businesses and public authorities ................................................................. 194

6.4.

Impact Assessment for Problem Area IV (Increase competition in the retail market) ............. 194

Methodological Approach ....................................................................................................... 194

Impacts of Policy Option 0+ (Non-regulatory approach to improving competition and

consumer engagement) ......................................................................................................................... 194

6.4.2.1.

Economic Impacts .......................................................................................................... 194

6.4.2.2.

Who would be affected and how ................................................................................... 195

6.4.2.3.

Impact on businesses and public authorities ................................................................. 196

Impacts of Policy Option 1 (Flexible legislation addressing all problem drivers) .................... 196

6.4.3.1.

Economic Impacts .......................................................................................................... 196

6.4.3.2.

Who would be affected and how ................................................................................... 197

6.4.3.3.

Impact on businesses and public authorities ................................................................. 198

Impacts of Policy Option 2 (Harmonization and extensive safeguards for consumers

addressing all problem drivers) ............................................................................................................. 199

6.4.4.1.

Economic Impacts .......................................................................................................... 199

6.4.4.2.

Who would be affected and how ................................................................................... 200

6.4.4.3.

Impact on businesses and public authorities ................................................................. 201

Environmental impacts ............................................................................................................ 202

Impacts on fundamental rights regarding data protection ..................................................... 202

Social impacts......................................................................................................................... 205

6.5.

COMPARISON OF THE OPTIONS ............................................................................ 208

7.1.

Comparison of options for adapting market design for the cost-effective operation of variable

and often decentralised generation, taking into account technological developments ........................ 208

7.2.

Comparison of Options for facilitating investments in the right amount and in the right type of

resources for the EU............................................................................................................................. 210

7.3.

Comparison of options for improving Member States' reliance on each other in times of system

stress and reinforcing coordination between Member States for preventing and managing crisis

situations ............................................................................................................................................. 213

7.4.

Comparison of options for addressing the causes and symptoms of weak competition in the

energy retail market ............................................................................................................................ 215

7.5.

Synergies, trade-offs between Problem Areas and sequencing .............................................. 217

Synergies .................................................................................................................................. 217

Trade-offs ................................................................................................................................ 219

Sequencing of measures .......................................................................................................... 220

8.1.

8.2.

MONITORING AND EVALUATION.......................................................................... 220

Future monitoring and evaluation plan .................................................................................. 220

Annual reporting by ACER and evaluation by the Commission ............................................... 221

Annual reporting by ACER ....................................................................................................... 221

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Evaluation by the Commission ................................................................................................ 221

8.3.

8.4.

8.5.

Monitoring by the Electricity Coordination Group .................................................................. 221

Operational objectives ........................................................................................................... 222

Monitoring indicators and benchmarks .................................................................................. 223

GLOSSARY AND ACRONYMS.................................................................................... 225

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1.1.

NTRODUCTION

Background and scope of the market design initiative

Context of the initiative

1.1.1.1.The gradual process of creating an internal electricity market

Well-functioning energy markets that ensure secure energy supplies at competitive prices

are key for achieving growth and consumer welfare in the European Union.

Since 1996, the European Union has put in place legislation to enable the transition from

an electricity system traditionally dominated by vertically integrated national incumbents

that owned and operated all the generation and network assets in their territories to

competitive, well-functioning and integrated electricity markets. The first step was the

adoption of the First Energy Package (1996 for the electricity sector and 1998 for the gas

sector), which allowed for the partial opening of the market where the largest consumers

were given the right to choose their supplier. The Second Energy Package (2003)

introduced changes concerning the structure of the vertically integrated companies (legal

unbundling), the preparation of the full opening of the market by 1 July 2007 and the

reinforcement of the powers of the national regulators. The most recent comprehensive

reform of European energy market rules, the Third Internal Energy Market Package

(2009)

('Third Package') has principally aimed at improving the functioning of the internal

energy market and resolving structural problems.

Since the adoption of the Third Package, electricity policy decisions have enabled

competition and increasing cross-border flows of electricity, notably with the introduction

of so called "market coupling"

and "flow-based" capacity allocation. In spite of significant

differences in the maturity of markets in Europe, overall electricity wholesale markets are

increasingly characterised by fair and open competition, and

–

though still insufficient

–

competition is also taking root at the retail level.

1.1.1.2.The Union's policy concerning climate change

The decarbonisation of EU economies is at the core of

the EU’s agenda for climate change

and energy. The targets in the Climate and Energy Package (2007) require Member States

to cut their greenhouse gas emissions by 20% (from 1990 levels), to produce 20% of their

energy from renewable energy sources (RES), and to improve energy efficiency by 20 %

(the

'2020 targets').

In 2011, the European Union committed to reduce greenhouse gas emissions to 80-95%

below 1990 levels by 2050. For this purpose, the European Commission adopted an Energy

Section 1.1.2.1 provides a more detailed explanation of the Third Energy Package.

A mechanism that manages cross-border electricity flows in an optimal way, smoothing out price

differences between Member States.

http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52008DC0030&from=EN

Fejl! Brug fanen Hjem til at anvende Heading 1,Livello 1 på teksten, der skal vises her.

kom (2016) 0863 - Ingen titel

Roadmap

and a roadmap for moving to a competitive low carbon economy

exploring

the transition of the energy system in ways that would be compatible with this greenhouse

gas reductions target while also increasing competitiveness and security of supply. The

2050 roadmap will require a higher degree of decarbonisation from the electricity sector

compared to other economic sectors.

These ambitions were reaffirmed by the European Council of October 2014, which

endorsed targets for 2030 of at least 40 % for domestic greenhouse gas emissions reduction

(compared to 1990 levels), at least 27 % for the share of renewable energy consumption,

binding at EU level and at least 27 % energy savings, to be reviewed by 2020, having in

mind an EU level of 30% (the

'2030 targets').

At the Paris climate conference (COP21) in December 2015, 195 countries adopted the

first-ever legally binding global climate deal. The European Council of March 2016

confirmed the EU's commitment to implement the 2030 targets. The Paris Agreement was

ratified by the European Union and entered into force on 4 November 2016..

1.1.1.3.Paradigm shift in the electricity sector

The Union's goals for climate change and energy have led to a paradigm shift in the means

employed to generate electricity: since the adoption of the Third Package, there has been

a move towards the deployment of capital-intensive low marginal cost, variable and often

decentralised electricity from RES E (mostly from solar and wind technologies) that is

expected to become more pronounced by 2030.

The increasing penetration of RES E is driven

inter alia

by the objective to reduce

greenhouse gas emissions in line with the 2020 and 2030 targets. The 2030 greenhouse gas

emission reduction target is to be delivered through reducing emissions by 43% compared

to 2005 for the sectors in the EU's ETS

(including the electricity sector and industry) and

by 30% compared to 2005 for the sectors outside the ETS. Within the electricity sector,

the reduction of greenhouse gas emissions is supported by the Renewable Energy

Directive

, the ETS and the additional national policies by Member States to increase the

share of renewables in the energy mix.

The Renewable Energy Directive established a European framework for the promotion of

renewable energy, setting mandatory national renewable energy targets for achieving a

20% EU share of renewable energy in the final energy consumption and a 10% share of

http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52011DC0885&from=EN

COM (2011) 112;

http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX:52011DC0112

http://www.consilium.europa.eu/uedocs/cms_data/docs/pressdata/en/ec/145397.pdf

The ETS works on the

'cap and trade'

principle. A

'cap',

or limit, is set on the total amount of certain

greenhouse gases that can be emitted by the factories, power plants and industrial installations in the

system. The cap is reduced over time so that total emissions fall. This policy instrument equally fosters

penetration of RES E as it renders production of electricity from non- or less-emitting generation

capacity comparatively more economical in relation to more carbon intensive capacity.

Directive 2009/28/EC on the promotion of the use of energy from renewable sources, OJ L 140/16,

5.6.2009

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energy from renewable sources in transport by 2020. These objectives have translated into

a need to foster the increased production of electricity from reneweble energy sources.

In parallel with the increased deployment of variable and decentralized RES E, the

increasing digitalisation of electricity networks and the environment behind the meter now

enables many elements of the electricity system to be operated more flexibly and

efficiently in the context of RES E generation. It also allows smaller actors to play an

increasingly important part in the market on both the supply side and

–

crucially

–

the

demand side, potentially untapping a vast new system resource.

From the consumer's perspective, increasingly intelligent grids unlock a host of other

possibilities, including innovative new products and services, lower entry barriers for new

suppliers, and improved billing and switching. This promises to unlock value and improve

the consumer experience

–

provided the legislative framework adapts to the changing

needs and possibilities. Indeed, fully engaging end consumers will be essential to realizing

the full benefits that the digital transformation can bring in terms of grid flexibility.

Moreover, electricity demand will progressively reflect the increasing electrification of

transport and heating.

The challenges the EU's electricity systems face are reflected in the European Commission

Communication of February 2015 on

“A Framework Strategy for a Resilient Energy Union

with a Forward-Looking

Climate Change Policy”

where the Commission announced a

new electricity market design linking wholesale and retail markets. As part of the

legislative reform process needed to establish the Energy Union, it also announced new

legislation on security of electricity supply.

In the light of the Energy Union Framework Strategy, the present impact assessment

reflects and analyses the need and policy options for a possible revision of the main

framework governing electricity markets and security of electricity supply policies in

Europe. The new electricity market design contributes strongly to the overall Energy Union

objectives of securing low carbon energy supplies to the European consumers at least costs.

1.1.1.4.The vision for the EU electricity market in 2030 and beyond

The Energy Union Framework Strategy sets out the vision of an Energy Union "with

citizens at its core, where citizens take ownership of the energy transition, benefit from

new technologies to reduce their bills, participate actively in the market, and where

vulnerable consumers are protected".

Well-functioning energy markets that ensure secure

energy supplies at competitive prices are important for achieving growth and consumer

welfare in the European Union. The future of the entire energy sector will, to a significant

extent, be shaped by the evolution of the electricity sector, which is key to addressing

climate change. With the quick ratification of the global Paris Agreement on climate

change and its subsequent entry into force, it becomes clear how important it is for all

Moreover, following the 2030 targets set by the European Council in October 2014, the Commission

published a Communication on A Framework Strategy for a Resilient Energy Union with a Forward-

Looking Climate Change Policy of February 2015 confirming the political commitment for the European

Union to become the world leader in renewable energy.

EC (2015a) - COM(2015) 80 final

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parties to the agreement, including the EU, to deliver on the clean energy transition on the

ground. In fact, amongst all sectors that make up our energy system, electricity is the most

cost-effective to decarbonise. Currently 27.5% of Europe's electricity is produced from

renewable energy sources. The share of RES E in electricity generation needs to almost

double by 2030 in order for the EU to meet its 2030 energy and climate targets cost-

effectively. This will require creating the right conditions for the massive amount of

investment needed for this energy transition to come about. At the same time electricity

markets will have to adapt to the radical change in the structure of the generation pattern

which will foremost require creating a more flexible market, going across borders, that is

able to allow more active participation of a much wider range of actors.

The EU's vision of the electricity system in 2030 is therefore based on a functioning market

that is adapted to implementing the decarbonisation agenda at least cost together with a

revised EU ETS. A well-functioning electricity market is also the most efficient tool to

ensure secure electricity supplies at the lowest reasonable cost.

The transition of the energy system towards the 2030 vision

The starting point is the existing reality, which dates back to an era with large-scale,

centralised power plants, largely fuelled by fossil fuels, had the key aim of supplying every

home and business in a delineated area

–

typically a Member State

–

with as much

electricity as they wanted, and in which consumers

–

households, businesses and industry

–

were passive users.

However, the electricity market is undergoing profound change and requires a new set of

rules to ensure secure supplies, competitiveness while enabling cost-effective

decarbonisation. The electricity market of the next decade will be characterised by more

variable and decentralised electricity production, an increased interdependence between

Member States and new technological opportunities for customers to reduce their bills and

actively participate in electricity markets through demand response, self-consumption or

storage.

The electricity market design initiative aims to improve the functioning of the internal

electricity market in order to allow electricity to move freely to where and when it is most

needed, empower consumers, reap maximum benefits for society from cross-border

competition and provide the right signals and incentives to drive the right investments

compatible with climate change, renewable energy and energy efficiency ambitions.

The proposed initiative constitutes a next-step in a wider and longer evolutionary process

that will guide the EU's electricity markets towards the 2030 vision.

The 2030 electricity market is highly flexible and provides a level playing field amongst

all

forms of generation as well as demand response…

The bulk of the new generation capacity is likely to come from renewable sources, mainly

wind and sun that are variable and predictable only to a limited extent. The future

electricity market will therefore need to be more flexible and liquid than today and allow

for integrated short-term trading. This would also set the ground for renewable energy

producers

–

who will over time acquire increasing share in generation - to equally access

energy wholesale markets and to compete on an equal footing with conventional energy

producers. Short-term markets will also allow Member States to share their resources

across all "time frames" (forward trading, day-ahead, intraday and balancing), taking

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advantage of the fact that peaks and weather conditions across Europe do not occur at the

same time. This would provide maximum opportunity to meet the flexibility needs and

balance the market. The sequence of forward markets and spot markets - day-ahead,

intraday and balancing - will optimise prices and the system in the short-run and will reveal

the true value of electricity and, therefore, provide appropriate investments signals in the

long-run.

The closer to real time electricity is traded (supply and demand matched), the less the need

for costly interventions by TSOs to maintain a stable electricity system. Although TSOs

would have less time to react to schedule deviations and unexpected events and forecast

errors, the liquid, better interconnected balancing markets, together with the regional

procurement of balancing reserves and more balancing actors and products available from

both demand and supply side, would be expected to provide them adequate and more

efficient resources in order to manage the grid and facilitate RES E integration.

All this will help to create a level playing field not only among all modes of generation but

also the demand side. At the same time market distortions and rules that artificially limit

or favour the access of certain technologies to the grid would be removed. All market

participants would become gradually responsible for balancing their position in the market,

bearing financial responsibility for the imbalances they cause and would, therefore, be

incentivised to reduce the risk of such imbalances. The most cost-efficient sources of

electricity would be used first, curtailment of generation due to limited transmission and

distribution infrastructure would be a measure of last resort and confined to situations in

which no market-based responses (including storage and demand response) are available,

and subject to transparent rules known in advance to all market actors and adequate

financial compensation. All resources would be remunerated in the market on equal terms.

…and active consumers.

Ensuring that all consumers

–

big and small

–

can actively participate in the energy market

would unlock a vast system resource that could play an important role in reducing system

costs. Technology

–

including smart grids and smart homes - is already available and will

further develop to enable consumers to modulate their demand while maintaining comfort

and reducing costs.

In the future, consumers would be sufficiently incentivised to benefit from these

opportunities and thus demand response would be provided by all willing consumer

groups, including residential and commercial consumers either directly or through

intermediaries (like aggregators). This would further increase the flexibility of the

electricity system and the resources for the TSOs and DSOs to manage it. At the same time

it should lead to a much more efficient operation of the whole energy system.

Consumers would be able to react to price signals on electricity markets both in terms of

consumption and production; they would consume when prices are low, when there is

plenty of electricity available, and reduce their consumption at times of low electricity

production and high prices. To make this possible, consumers have access to a fit-for-

purpose smart metering system, smart homes and storage as well as electricity supply

contracts with prices linked dynamically to the wholesale markets.

More and more consumers would produce their own electricity. Such decentralised

production further strengthens security of supply and helps to implement the

decarbonisation agenda as most of this production comes from renewable sources. If

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combined with local storage solutions, consumers could significantly contribute to

balancing the distribution grids at local level. Analysis suggests that this development will

be progressive, and that most consumers would still remain connected to the distribution

grid to use it as back-up for when the prosumers' own generation is inadequate (e.g. for

sustained periods of low sunlight) or for the opportunity to sell excess electricity to the

market (e.g. during prolonged sunny periods when their installed storage is at full

capacity).

Reducing barriers to market entry for electricity suppliers and consumer engagement

–

notably phasing out price regulation

–

results in increased competition at the retail level

allowing consumers to save money through better information and a wider choice of action.

This also helps drive the uptake of innovative new products and services that increase

system flexibility through demand response whilst catering to consumers' changing needs

and abilities.

In addition, DSOs would be enabled and incentivised, without compromising their

neutrality as system operators, to manage their networks in a flexible and cost-efficient

way

–

inter alia through revised tariff structures.

Increased cross-border trade is a pillar of the electricity market.

Competition and cross-border flows of electricity would further increase, with fully

coupled markets where price differences between Member States are smoothened out.

Electricity wholesale markets will be characterised by fair and open competition, including

across borders. Cooperation between TSOs will be enhanced by regional operational

centres. The cross-border cooperation of TSOs would be accompanied by an increased

level of cooperation between regulators and governments. An adequate cross-border

infrastructure remains crucial to underpin a well-functioning electricity market.

Increasingly investments are triggered by the market with a decreasing need for state

subsidies.

The enhanced market design, the revised renewables directive and the strengthened ETS

will all help to improve the viability of RES E investments, in particular as follows:

Where the marginal producer is a fossil fired power plant, a higher carbon price

translates into higher average wholesale prices. The existing surplus of

allowances is expected to decrease due to the implementation of the Market

Stability Reserve and the higher Linear Reduction Factor, reducing the current

imbalance between supply and demand for allowances;

greater system flexibility will be critical for better integration of RES E in the

system, reducing their hours of curtailment and the related forgone revenues;

improving overall system flexibility is equally essential to limit the merit-order

effect

and thus in avoiding the erosion of the market value of RES E produced

electricity;

the revision of priority dispatch rules, removal of must-run units, increasing

demand response and storage, together with the better functioning of the short-

term markets will strongly reduce or even eliminate the occurrence of negative

Also occasionally referred to as the 'cannibalisation effect'.

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prices

–

leading again to higher average wholesale prices (especially during the

hours with significant variable RES E generation);

improved rules for intraday and balancing markets will increase their liquidity

and allow access to those markets for all resources, thus helping generators

reduce their balancing costs;

removing existing (explicit or implicit) restrictions for the participation of all

resources to the reserve and ancillary services markets will allow RES E to

generate additional revenues from these markets;

price signals reflecting the actual value of electricity at each point of time, as

well as the value of flexibility, will ensure that the flexible assets most needed

for the system are invested in or, at least, are less likely to be decommissioned.

Low exit barriers to facilitate exit of overcapacities.

The above mentioned changes will all help to improve the competitive situation of RES E

and reduce the need for dedicated support.

The results of the modelling for this Impact Assessment indicate that investments in the

most mature renewable technologies could be driven by the market by 2030 (such as

certain solar PV and onshore wind). At the beginning of the period, generation over-

capacity in certain areas, weaker investment signal from the ETS and low wholesale market

prices and still high RES E technology costs, make the case for investments in RES E

technologies more difficult. The underpinning modelling and analysis, points that the RES

E funding gap in 2020 is gradually reducing towards 2030 as the market conditions

improve. Less mature RES E technologies, needed for meeting the 2030 and 2050 energy

and climate objectives, such as off-shore wind, will likely need some form of support to

cover at least a fraction of total project costs (complementing the revenues obtained from

the energy markets) throughout the 2021-2030 period.

The picture also depends on regions. RES E technologies could be more easily financed

by the market in the regions with the highest potential (e.g. onshore wind in the Nordic

region or solar in Southern Europe), while RES E could continue to require support in the

British Isles and in Central Europe. Conditions however also depend on the cost of capital.

At the same time it has to be acknowledged that whether and what point in time financing

of RES E through markets alone will actually take off remains difficult to predict. This is

because financing of capital intensive technologies such as most RES E through markets

based on marginal cost pricing will remain challenging. In the absence of measures that

address system flexibility, higher penetration of RES with low marginal cost could reduce

the market value that such RES E can actually achieve. Removing barriers to the

flexibilisation of demand and improving the responsiveness of demand and supply to price

signals stands out as a key measure in this regards in order to further stabilise the revenue

of RES E producers from the market.

On the other hand the future capacity of RES to be financed through the market will also

depend on certain conditions outside of the market design and ETS prices, such as

continued decrease in the costs of technologies, availability of capital at a reasonable price,

social acceptance and sufficiently high and stable fossil fuel prices.

While the market reforms described above are therefore no regret options to facilitate RES

investment, support schemes will still be needed at least for a transitional period. It is

therefore essential to further reform such schemes to make them as market-oriented as

possible.

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… with a market-based

and more Europeanised approach to support schemes to cover any

investment gap .

Where needed, support will be (i) cost-effective and kept to a minimum, and (ii) will create

as little distortions as possible to the functioning of electricity markets, and to competition

between technologies and between Member States. The legal frame for RES E support

schemes would ensure sufficient investor certainty over the 2021-2030 period and require

the use (where needed) of market-based and cost-effective schemes, based on the design

of emerging best practices. Auctions could introduce competitive forces to determine the

level of support needed on top of market revenues and incentivise RES E producers to

develop business models that maximise market-based revenues. The use of tenders would

imply a natural phase-out mechanism for support, determining the remaining level of

support required to bridge any financing gap. The continued participation of small and

local actors, including energy communities, in the energy transition should be ensured in

this process.

The market should also provide, as a principle, security of supply.

By 2030, the market, as described above, could in principle successfully attract the required

investments to ensure adequate matching of supply and demand.

Today, most of the EU's power markets have more capacity than needed. However, with

demand increasing, e.g. due to E-Mobility and heat pumps, and older power plants retiring

supply margins are likely to get tighter. Therefore, a legal framework needs to be in place

to allow for the formation of electricity prices that send the signals for tomorrow's

investments. In this context, scarcity prices will become more and more important to

provide the right incentives for the operation of resources (including for demand response)

when they are most needed. Hedging products which suppliers can buy to protect

themselves against peaks are already available now and more innovative tools are expected

to be brought forward by market participants without the need for additional intervention

by national authorities. This will also provide opportunities for generators (who will be

natural provider of such hedging tools) to secure further revenues.

In the new market framework capacity mechanisms might only be considered if a residual

risk to security of supply can be proven after underlying market distortions have been

removed and the contribution of market integration to security of supply has been taken

into account.

The legal framework will provide tools to facilitate an objective case-by-case judgement

on whether the introduction of capacity mechanisms is needed and set out measures to

ensure that their potentially distortive effects are kept at a minimum, while placing them

in a more regional context. Accordingly, their need would have to be proven against an

EU-wide system adequacy assessment and they would have to allow for cross-border

participation to minimise distortions of investment incentives across the borders. Capacity

mechanisms would be designed in a way as to not discriminate against different generation

technologies and demand side capacities. Additionally, where need has been demonstrated

for such mechanisms, Member States should take into account how such mechanisms

would impact the achievement of the decarbonisation objectives.

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Member States should regularly review their resource adequacy

situation and phase out

capacity mechanisms once the underlying market or regulatory concerns have been

resolved.

Despite best efforts to build an integrated and resilient power market, crisis situations can

never be excluded. The potential for crisis situation increases with climate change (i.e.

extreme weather conditions) and with the emergence of new areas that are subject to

criticalities (i.e. malicious attacks, cyber-threats). Such crises tend to often have an

immediate cross-border effect in electricity. The legal framework would provide tools to

ensure that national security of supply policies are better coordinated and aligned to tackle

possible crisis situations, in particular those that affect several countries at the same time.

Scope of the initiative

1.1.2.1.Current relevant legislative framework

EU's electricity markets are currently regulated at EU level by a series of acts collectively

referred to as the "Third Package"

The main objectives of the Third Package were:

Improving competition through better regulation, unbundling and reducing

asymmetric information;

Improving security of supply by strengthening the incentives for sufficient

investment in transmission and distribution capacities; and,

Improving consumer protection and preventing energy poverty.

The Third Package mainly focused on improving the conditions for competition as

resulting from previous generations of legislation by improving the level playing field. The

most important root cause for the lack of competition identified at the time

was the

existence of vertically integrated companies, which not only controlled essential facilities

(such as electricity transmission systems) but also enjoyed significant market power in the

wholesale and, often, retail markets. Many of the measures associated with the Third

Package sought to directly or indirectly address this issue, such as by improving the

As not only generation, but also demand response or storage can solve problems of situations in which

demand exceeds production, this Impact Assessment uses the term "resource adequacy" instead of

"generation adequacy" (other authors refer to "system adequacy").

The relevant elements of the Third Package as regards electricity are Directive 2009/72 of the European

Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in

electricity and repealing Directive 2003/54/EC, OJ L 211, 14.8.2009, p. 55–93; Regulation (EC) No

714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the

network for cross-border exchanges in electricity repealing Regulation (EC) No 1228/2003. OJ L 211,

14.8.2009, p. 15–35 and Regulation (EC) No 713/2009 of the European Parliament and of the Council

of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators. OJ L 211, 14.8.2009,

p. 1–14. The Third package also covered other acts, in particular acts related to the regulation of gas

markets. However, only one of these acts is pertinent for the present impact assessment

–

the Gas

Directive.

In the impact assessment for the Third Package (SEC(2007) 1179/2

http://ec.europa.eu/smart-

regulation/impact/ia_carried_out/docs/ia_2007/sec_2007_1179_en.pdf.

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unbundling regime, strengthening regulatory oversight, improving the conditions for cross-

border market integration and lowering entry barriers such as by improving transparency.

The Third Package also created the possibility to enact secondary legislation concerning

cross-border issues, often referred to as network codes or guidelines ('network codes')

and provided a mandate for developing these network codes (as well as other tasks related

to the EU's electricity markets) to transmission system operators within the

ENTSO-E

and to national regulatory authorities, within the Agency for the Cooperation of Energy

Regulators ('ACER')

The main framework for electricity security of supply in the Union is currently Directive

2005/89/EC ("Security

of Electricity Supply Directive'

'SoS Directive'")

. This SoS

Directive requires Member States to take certain measures with the view to ensuring

security of supply, but leaves it by and large to the Member States how to implement these

measures. The Third Package complemented the SoS Directive and superseded

de facto

some of its provisions.

1.1.2.2.Policy development subsequent to the Third Package

The present initiative builds on previous related policy initiatives and reports that

intervened since the adoption of the Third Package and the Security of Electricity Supply

Directive, in particular:

"Report on the progress concerning measures to safeguard security of electricity

supply and infrastructure investment"

COM (2010) 330 final

;

"Delivering the internal electricity market and making the most of public

interventions"

(C(2013) 7243). This Communication was accompanied

inter alia

by a Commission Staff working document (SWD(2013)438) entitled

"Generation

Adequacy in the internal electricity market

–

guidance on public intervention";

Communication on the "Progress

towards completing the Internal Energy Market"

COM(2014) 634 final. This Communication emphasized that energy market

integration has delivered many positive results but that, at the same time, further

steps are needed to complete the internal market;

"Communication on Energy Security"

(COM(2014)330). This Communication

emphasised

inter alia

the need achieve a better functioning and a more integrated

energy market;

Special Report by the European Court of Auditors

"Improving the security of

energy supply by developing the internal energy market: more efforts needed".

This

For an overview of these network codes and guidelines and their pertinence to the present initiative,

please refer to Annex VII.

https://www.entsoe.eu/about-entso-e/inside-entso-e/official-mandates/Pages/default.aspx

http://www.acer.europa.eu/en/The_agency/Mission_and_Objectives/Pages/default.aspx

Directive 2005/89/EC of the European Parliament and of the Council of 18 January 2006 concerning

measures to safeguard security of electricity supply and infrastructure investment, OJ L 33, 4.2.2006, p.

22–27.

http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:52010DC0330&from=EN

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special report made nine recommendations to reap the benefits of market

integration

;

"Communication on energy prices and costs in Europe"

(COM(2014) 21 /2) and

the accompanying "Energy

prices and costs report"

(SWD(2014)020 final 2)

highlighting

inter alia

the competiveness of the EU's retail electricity markets, the

missing link between wholesale and retail prices and the need for EU cooperation

by DSOs as well as the Energy prices and costs report (SWD(2016)XX

, this

report

inter alia

that shed light on the drivers of retail and wholesale price

developments;

"Delivering a new deal for energy consumers"

(COM(2015) 339). This

Communication laid out the Commission's intention to enable all consumers to

fully participate in the energy transition, taking advantage of new technologies that

enable wholesale and retail markets to be better linked.

The Commisison published a study on

"Investment perspectives in electricity

markets"

Technical Report

by the European Commission on "The

economic impact of

enforcement of competition policies on the functioning of EU energy markets".

The

report includes an assessment of the intensity of competition in the energy

markets

(both wholesale and retail) and points out that, between 2005 and 2012,

the intensity of competition in European energy markets may have declined

The Commission Staff working document (SWD(2015)249) entitled

"Energy

Consumer Trends 2010 - 2015"

presents market research into the problems that

energy consumers continue to be confronted with.

The Commission launched a a sector inquiry into national capacity mechanisms,

The resulting

"Interim Report of the Sector Inquiry on Capacity Mechanisms"

(SWD SWD(2016) 119 final)

points out that there is a lack of adequate

assessment of the actual need for capacity mechanisms. It also appears that some

capacity mechanisms in place could be better targeted and more cost effective. It

emphasizes the need to design capacity mechanisms with transparent and open

rules of participation and a capacity product that does not undermine the

functioning of the electricity market, taking into account cross-border participation.

1.1.2.3.Scope and summary of the initiative

In line with the Union's policy on climate change and energy, the proposed initiative aims

at deepening energy markets and setting a framework governing security of supply policies

that enables the transition towards a low carbon electricity production.

http://www.eca.europa.eu/en/Pages/DocItem.aspx?did=34751

Report to be published in conjunction with the present impact assessment..

"Energy Economic Developments, Investment perspectives in electricity markets".

Institutional paper

003, 1 July 2015

http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf

Published on 16.11.2015, at

http://ec.europa.eu/competition/publications/reports/kd0216007enn.pdf

Ibid

Section 3.3 of the non-technical summary at p. 23.

Based on the productivity dispersion and the Boone indicator over this period,

ibid

Section 3.4

"Summary

of key findings"

at p. 25.

Published

13.04.2016

at:

http://ec.europa.eu/competition/sectors/energy/capacity_mechanism_report_en.pdf

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The transition towards a low carbon electricity sector as well as technical progress will

have profound implications on the manner in which the electricity sector is organised and

the roles of market actors and consumers, not all of which can be foreseen with accuracy

today. As it cannot be predicted how the electricity markets and progress of innovation

will look like in a few decades from now, the proposed initiative constitutes a next step in

a wider and longer evolutionary process that will guide the EU's electricity markets

towards the future. The initiative will consequently not address the challenges that might

arise when operating a fully decarbonised power system.

This initiative also aims at improving consumer protection and engagement for both

electricity and gas consumers

Organisation and timing

1.1.3.1.Follow up on the Third Package

Full and timely transposition of the Directives of the Third Package has been a challenge

for the vast majority of the Member States. In fact, by the end of the transposition deadline

(March 2011), none of the Member States had achieved full transposition. However,

progess has been made and at present all of the infringement proceedings

for partial

transposition of the Electricity Directive have been closed as the Member States achieved

full transposition in the course of the proceedings.

In addition to ensuring compliance of national rules with the Third Package, the

Commission has carried out assessments to identify and resolve problems concerning

incorrect transposition or bad application of the Third Package. On this basis, the

Commission has opened EU Pilot cases against a number of Member States. As of 7th July

2016, 8 of these EU Pilot cases have resulted in infringement procedures where,

inter alia,

the violation of the EU electricity market rules is at stake.

In January 2014 the Directorate General for Energy of the European Commission ('DG

ENER') launched a public consultation on retail markets for energy.

Whilst preparing the single market progress report (COM(2014) 634 final), published on

13 October 2014, DG ENER decided to study a number of changes to the current

legislation.

The Commission (DG ENER) started in 2015 the preparatory work for the present impact

assessment to assess policy options related to the internal energy market for electricity and

For some of the arising issues and challenges see Chapter 2.3 in Investment Perspectives in Electricity

Markets, European Commission, DG EFCIN, 2015

http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf

With regards to gas consumers, only the consumer-related provisions of the Gas Directive are concerned:

Article 3 and Annex I. These address issues such as public service obligations, metering, billing and a

broad range of consumer rights that Member States shall ensure.

The Commission opened 38 infringement cases against 19 Member States for not transposing or for

transposing only partially the Directives.

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to security of electricity supply and consulted in July 2015 the public on a new energy

market design (COM(2015) 340 final)

In April 2015, the Commission (DG Competition) launched a sector inquiry into national

capacity mechanisms. The Commission interim report and the accompanying Commission

staff working document, adopted on 13 April 2016 have provided a significant input for

the proposed initiative. This will be further completed by the final report.

1.1.3.2.Consultation and expertise

The Commission has conducted a number of wide public consultations on the different

policy areas covered by the present Impact assessment which took place between 2014 and

2016. In addition to the public consultations, it has organised a number of targeted

consultations with stakeholders throughout 2015 and 2016

Given the cross-cutting nature of the planned impact assessment work, the Commission

set up an inter-service steering group which included representatives from a selected

number of Commission Directorate Generals. The inter-service steering group held regular

meetings to discuss the policy options of the proposed initiatives and the preparation of the

impact assessment

In parallel, the Commission has also conducted a number of studies mainly or specifically

for this impact assessment

1.2.

Interlinkages with parallel initiatives

The proposed initiatives are strongly linked to other energy and climate related legislative

proposals brought forward in parallel with the present initiative equally aimed at delivering

upon the five dimensions of the Energy Union, namely energy security, solidarity and trust,

a fully integrated European energy market, energy efficiency contributing to moderation

of demand, decarbonisation, research, innovation and competitiveness. These other energy

related legislative proposals include:

The Renewable Energy Package comprising the new Renewable Energy Directive

and bioenergy sustainability policy for 2030 ('RED

II')

The RED II covers a number of measures deemed necessary to attain the EU binding

objective of reaching a level of at least 27% RES in final energy consumption by 2030

across the electricity, heating and cooling, and transport sectors. As regards electricity in

particular, the Renewables Directive proposes a framework for the design of support

schemes for renewable electricity, a framework for renewable self-consumption and

renewable energy communities, as well as various measures to reduce administrative costs

and burden.

https://ec.europa.eu/energy/sites/ener/files/documents/1_EN_ACT_part1_v11.pdf

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

For more information on the consultation process, please refer to Annex 3

For more information on inter-service steering group, please refer to Annex 1.

For the list of studies and a summary description, please refer to Annex 5.

and

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Conversely, measures aimed at the integration of RES E in the market, such as provisions

on priority dispatch and access previously contained in the renewables directive are part

of the present market design initiative. The reflections on a revised Renewables Energy

Directive will include specific initiatives on support schemes for market-oriented, cost-

effective and more regionalised support to RES up to 2030 in case Member States were

opting to have them as a tool to facilitate target achievement. The Renewable Package is

expected to deal with legal and administrative barriers for self-consumption, whereas the

present package will address market related barriers to self-consumption.

The Renewable Energy package has synergies with the present initiative as it seeks to adapt

the current market design, optimised for large-scale, centralised power plants, to a suitable

one for the cost-effective operation of variable, decentralised generation of electricity

whilst taking into account technological progress creating the conditions for a cost efficient

achievement of the binding EU RES target in the electricity sector.

The enhanced market design will improve the viability of RES E investments, but

electricity market revenues alone might not prove sufficient in attracting renewable

investments in a timely manner and at the required scale to meet EU's 2030 targets. The

MDI and RED II impact assessments thus jointly come to the conclusion that the improved

electricity market, in conjunction with a reformed EU ETS could, under certain conditions,

deliver investments in the most mature renewable technologies (such as solar PV and

onshore wind). The underpinning modelling and analysis, points that the RES E funding

gap in 2020 is gradually reducing towards 2030 as market conditions improve. Less mature

RES E technologies, needed for meeting the 2030 and 2050 energy and climate objectives,

such as off-shore wind, will likely need some form of support to cover at least a fraction

of total project costs (complementing the revenues obtained from the energy markets)

throughout the 2021-2030 period. These technologies are required if RES E technologies

are to be deployed to the extent required for meeting the 2030 and 2050 energy and climate

objectives, and provide an important basis for the long-term competitiveness of an energy

system based on RES E.

Similarly, the progressive reform of RES E support schemes as proposed by the RED II

initiative, building on the Guidelines on State aid for environmental protection and energy

2014-2020 ('EEAG'), is a prerequisite for the results of the present initiative to come about.

In order to ensure that a market can function, it is necessary that market participants are

progressively exposed to the same price signals and risks. Support schemes based on feed-

in-tariffs prevent this and would need to be phased-out

–

with limited exemptions

–

and

replaced by schemes that expose all resources to price signals, as for instance by means of

premium based schemes. Such schemes would be made even more efficient by setting aid-

levels through auctioning as RES E investments projects will then be incentivised to

develop business models that optimise market based returns

The issue is explored in more detail in section 6.2 of the present impact assessment and, in

particular, the RED II impact assessment.

See Box 7 and Annex IV for more information

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Commission guidance on regional cooperation

The forthcoming guidance on regional cooperation may set out general principles for

regional cooperation across all five dimensions of the Energy Union, described how these

principles are being addressed in this initiative and other legislative proposal for

Renewables and Energy Union governance, and will offer suggestions on how regional co-

operation, where it applies, can be made to work in practice.

The present initiative seeks to improve market functioning, and calls for a more regional

approach to system operation and security of supply. The guidance document should help

Member States best achieve regional co-operation, including in areas where the present

initiative mandates effective co-operation (e.g. the initiative calls on Member States to

prepare risk preparedness plans in a regional context, cf. infra).

The Energy Union governance initiative

The Energy Union governance initiative aims at ensuring a coordinated and coherent

implementation of the Energy Union Strategy across its five dimensions with emphasis on

the EU's energy and climate targets for 2030. This is established through a coherent

combination of EU-level and national action, a strengthened political process and with

reduced administrative burden.

With these objectives in mind, the draft Regulation is based on two pillars:

Streamlining and integration of existing planning, reporting and monitoring

obligations in the energy and climate fields, in order to reduce unnecessary

administrative burden;

A political process between Member States and the Commission with close

involvement of other EU institutions to support the achievement of the Energy

Union objectives, including notably the 2030 targets for greenhouse gas emission

reductions, renewable energy and energy efficiency.

In relation to this initiative the governance initiative will also streamline reporting

obligations by Member States and the Commission that are presently enshrined in the Third

Package.

The Energy Efficiency legislation ('EE')

and the related Energy Performance of

Buildings Directive ('EPBD')

including the proposals for their amendment.

In general terms, energy efficiency measures interact with the present initiative as they

affect the level and structure of electricity demand. In addition, energy efficiency measures

can alleviate energy poverty and consumer vulnerability. Besides consumer income and

energy prices, energy efficiency is one of the major drivers of energy poverty.

Directive 2012/27/EU of the European Parliament and of the Council of 25 October 2012 on energy

efficiency, amending Directives 2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and

2006/32/EC; OJ L 315, 14.11.2012, p. 1–56.

Directive 2010/31/EU of the European Parliament and of the Council of 19 May 2010 on the energy

performance of buildings. OJ L 153, 18.6.2010, p. 13–35.

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The provisions currently still in the current energy efficiency legislation concerning

metering and billing (to the extent related to electricity) may become part of the present

initiative as these relate to consumer conduct and their participation in the market which

are important issues in the context of the present initiative. This logic is reinforced by the

fact that the Third Package already contains closely related provisions on smart metering

deployment and fuel mix and comparability provisions in billing.

Similarly, all provisions on priority dispatch for Combined Heat and Power ('CHP')

previously contained in the energy efficiency legislation will be set out in the present

initiative as these provisions relate to the integration of these resources in the market and

as they are very similar to the priority dispatch provisions for RES E, also dealt with in the

present initiative.

The provisions previously contained in the energy efficiency legislation on demand

response will be set out in the present initiative

because these relate to incentivising

flexibility in the market and participation of consumers in the market, both core subjects

of the present initiative. This logic is reinforced by the fact that the Third Package already

contains related provisions on demand response.

The Commission Regulation establishing a Guideline on Electricity Balancing

('Balancing Guideline')

The Balancing Guideline constitutes an implementing act that will be adopted using the

Electricity Regulation as a legal basis. The Balancing Guideline is closely related to the

present initiative. This is because efficient, integrated balancing markets are an important

building block for the consistent functioning of wholesale markets which in turn are needed

for a cost effective integration of RES E into the electricity market.

The Balancing Guideline aims at harmonising certain aspects of the EU's balancing

markets, with a focus on optimising the cross-border usage that TSOs make of the

balancing reserves that each have decided to contract individually, such as harmonisation

of the pricing methodology for balancing; standardisation of balancing products and merit-

order activation of balancing energy.

The present initiative seeks in contrast to focus on a more integrated approach to deciding

and contracting of the balancing reserves, as opposed to their usage, which touches upon

the optimal allocation of the cross-border transmission capacities and a regional approach

to balancing reserves.

Thus, the Balancing Guideline deals principally with exchanges of balancing energy

whereas the present initiative focusses on the exchange and sharing of balancing capacity.

The latter issue is much more political than the exchange of balancing energy and closely

related to other questions dealt with in the present initiative, such as regional TSO

cooperation or the reservation of transmission capacities. The assessments of the two

In a manner that will preserve DG Energy's ability to continue infringing Member States that have not

correctly implemented what is now Article 15(8) of the Energy Efficiency Directive.

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initiatives are fully coherent. Indeed, the implementation of the guidelines on electricity

balancing is part of the baseline for the present impact assessment

Other relevant instruments

Other relevant instruments are the Commission proposal for setting national targets for

2030 for the sectors outside the EU's ETS, the revision of the EU's ETS for the period after

2020, EU's competition instruments and the EU state aid rules applicable to the energy

sector and clarified in the EEAG. and the decarbonisation of the transport sector initiative.

The manner in which this policy context is interacting with the present initiative is explored

further in section 4.2.

2.1.

ROBLEM

ESCRIPTION

Problem Area I: Market design not fit for an increasing share of variable

decentralized generation and technological developments

The European Union's policy to fight global warming will require the electricity systems

to shift from a generation mix that is mostly based on fossil fuels to a virtually decarbonised

power sector by 2050. Indeed, with the 2030 targets agreed by the October 2014 European

Council (EuCo 169/14) the share of electricity generated from renewable sources is

projected to be close to 49% of total electricity produced, while their share in total net

installed capacity is projected to be 62.45%

Table 1: RES E % share in total net electricity generation

Year

2000

2005

422

467

RES E total (TWh)

Total net generation (TWh)

2,844

3,119

RES E

15%

Source: PRIMES; based on EUCO27 scenario

2010

683

3,168

22%

2015

916

3,090

30%

2020

1,193

3,221

37%

2025

1,443

3,317

43%

2030

1,654

3,397

49%

Whereas renewable electricity can be produced by a variety of technologies, most new

installed capacity today is based on wind and solar power. By 2030, this is expected to be

even more pronounced.

Table 2: Share of variable RES E (solar and wind power) in RES E and total net

generation

Year

2000

Variable RES E (TWh)

422

Total RES E (TWh)

Variable RES E in RES E

Variable RES E in total net generation

Source: PRIMES; based on EUCO27 scenario

2005

467

16%

2010

171

683

25%

2015

378

916

43%

12%

2020

618

1,193

52%

19%

2025

820

1,443

57%

25%

2030

995

1,654

62%

29%

The patterns of electricity production from wind and sun are inherently more variable and

less predictable when compared to conventional sources of energy (e.g. fossil-fuel-fired

See also Section 5.1.2 of the present impact assessment and in the Annex IV on the modelling

methodology.

These figures are based on the PRIMES EUCO27 results.

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power stations) or flexible RES E technologies (e.g. biomass, geothermal or hydropower).

Weather-dependent production also implies that output does not follow demand.

Consequently, there will be times when renewables could cover a very large share

–

even

100%

–

of electricity demand and times when they only cover a minor share of total

consumption. While the demand-side and decentralized power storage could in theory

react to the availability of renewable energy sources and even to extreme variations, current

market arrangements do not enable most consumers to actively participate in electricity

markets either directly through price signals or indirectly through aggregation.

While renewable technologies and individual projects differ significantly in size (from

rooftop solar on households with 5 to 20 kW to several hundreds of MW for large offshore

wind parks), the majority of renewable investments are developed at comparatively small

scale. Given that the typical installation size of an onshore wind farm or a solar park is

generally multiple

times smaller than of a conventional power station, the number of

power producing units and operators will increase significantly. Consequently, the

transition towards more renewables implies that more and more power will be generated

in a decentralised way. Market roles and responsibilities will have to be adapted.

Finally, these new installations will not necessarily be located next to consumption centres

but where there are favourable natural resources. This can create grid congestion and local

oversupply.

The transition towards a low carbon electricity production poses a number of challenges

for the cost-effective organisation and operation of Europe's power system and its

electricity markets. The existing market framework was designed in an era in which large-

scale, centralised power stations, primarily fired by fossil fuels, supplied passive customers

at any time with as much electricity as they wanted in a geographically limited area

–

typically a Member State. This framework is not fit for taking up large amounts of variable,

often decentralised electricity generation nor for actively involving more consumers in

electricity markets.

The main underlying drivers are: (i) the inefficient organisation of short-term electricity

markets and balancing markets, (ii) exemptions from fundamental market principles, (iii)

consumers that do not actively engage in the market, (iv) consumers do not actively engage

in the market and demand response potential remains largely untapped; and (v) distribution

networks that are not actively managed and grid users are poorly incentivised.

The largest solar PV park in the EU is the 300 MW Cestas Park in France,

http://www.pv-

magazine.com/news/details/beitrag/frances-300-mw-cestas-solar-plant-

inaugurated_100022247/#axzz4Cxalbrhc.

The largest wind farm is the offshore farm "London array"

with 630 MW distributed over 175 turbines. By comparison, the largest nuclear power plant in Europe

is the Gravelines plant in France, with a net capacity of 5460MW. The largest coal-fired power station

in Europe is the Polish Bełchatów plant with a capacity of 5420 MW.

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Driver 1: Short-term markets, as well as balancing markets, are not efficiently

organised

Today's short-term markets are not efficiently organised, because they do not give all

resources

–

conventional power, renewables, the demand-side, storage

–

equal

opportunities to access these markets and because they do not fully take into account the

possible contribution of cross-border resources. The latter problem often originates from a

lack of coordination between national entities and a lack of harmonisation of rules, while

the former relates to the trading products themselves, e.g. their commitment period, which

sometimes are too restrictive to allow for a level playing field of all kinds of resources

Short-term markets play a major role in any liberalised power system due to the

characteristics of electricity as a product. Electricity must be generated and transmitted as

it is consumed. The overall supply and demand needs to be in balance in physical terms at

any given point in time. This balance guarantees the secure operation of the electricity grid

at a constant frequency. Imbalances between injections and withdrawals of electricity

render the system unstable and, ultimately, may give rise to a black-out.

As a consequence, market participants need to be incentivised to have a portfolio of

electricity injections into and withdrawals from the network that net-out. Market

participants can adjust their portfolio by revising production and consumption plans and

selling or buying electricity

. Efficient and liquid markets with robust price signals are

crucial to guide these decisions

The fact that the production patterns from weather dependent RES E can only be predicted

with acceptable accuracy within hours, creates challenges for market parties and for system

operation. In the absence of efficient and liquid short-term electricity wholesale markets,

system operators have to take actions to balance the system and manage network

EPRG Working paper 1614 (2016) "Overcoming

barriers to electrical energy storage: Comparing

California and Europe"

by F. Castellano Ruz and M.G. Pollitt concludes: "In

Europe, there is a need

to clarify the definition of EES, create new markets for ancillary services, design technology-neutral

market rules and study more deeply the necessity of EES."

Depending on the delivery period, bulk electricity can be traded on "spot markets" or "forward markets".

Spot markets are currently mainly "day-ahead markets" on which electricity is traded up to one day

before the physical delivery takes place. On "forward markets", power is traded for delivery further

ahead in time.

IEA "Re-powering

markets"

(2016) suggests:

"A market design with a high temporal and geographical

resolution is therefore needed".

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congestions once the production forecasts become more precise. Moreover, operators of

RES E are unable to adjust their portfolios once the production forecasts become more

precise, leaving them exposed to risks and costs, when they deviate from their plans. An

increasing penetration of RES E thus requires efficient and liquid short-term markets that

can operate until very shortly before the time of physical delivery i.e. the moment when

electricity is consumed. The entire electricity system must become more flexible, also

through the progressive introduction of new flexible resources such as storage, to

accommodate variations in RES E production.

Current trading arrangements are however not optimised for a world in which market

participants have to adjust portfolios on short notice. The manner in which the trading of

electricity is arranged and the methods for allocating the network capacity to transmit

electricity are organised, allow for efficient trading of electricity in timeframes of one or

more days ahead of physical delivery. These arrangements befit well a world of

conventional electricity production that can be predictably steered but not the new

electricity landscape with a high share of renewables with limited forecasting abilities in a

day-ahead timeframe.

The current market framework already envisages that these short-term adjustments can be

made in intraday markets to correct. However, whilst liquidity has increased over the past

few years, there remains significant scope for further increases in these markets

. As way

of illustration, in 2014, in the intraday timeframe, only five markets in Europe had a ratio

of traded energy to demand of greater than 1%

. Further, progress remains in connecting

('coupling') national intraday markets in the same way as day-ahead markets. This can lead

to a low level of cross-border competition in intraday markets. In 2014 only 4.1% of

available interconnection capacity at the intraday stage was used, compared to 40% at day-

ahead.

Improving liquidity of intraday markets requires addressing various issues, including

removing the barriers that today exist for trading power across borders as well as providing

proper incentives to rebalance portfolios by trading until short notice before markets close.

In addition, technical rules of the market (i.e. products, bid sizes, gate closure times) are

often not defined with renewables or demand response in mind creating

de facto

barriers

for its participation.

Specific issues include a variation in commitment periods across Europe, with some

Member States choosing 15-minute and other Member States choosing 60-minute

products, and the time to which market participants can trade, which can be as short as 5

minutes or, in some instances, upto several hours before real time. There is also a difference

in how markets are organised: in continuously traded markets, transactions are concluded

throughout the trading period every time there is a match between bids and offers.

Transactions are concluded differently in auction markets, where previously collected bids

and offers are all matched at once at the end of the trading period.

The last market-based measure to net out imbalances between injections and withdrawals

of electricity is the balancing market. As such, the balancing market is not solely a

See Annex 2.2 for further details.

Spain (12.1%) Portugal (7.6%), Italy (7.4%) Germany (4.6%) Great Britain (4.4%). ACER,

Market

Monitoring Report 2015

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technicality ensuring system stability but has significant commercial implications and, in

turn, implications for competition. Procurement rules often fit large, centralised power

stations but do not allow for equal access opportunities for smaller (decentralised)

resources, renewables, demand-side and batteries. ACER's market monitoring reports

revealed high levels of concentration within national balancing markets. TSOs are often

faced with few suppliers or (in case of vertically integrated TSOs) procure balancing

reserves from their affiliate companies. This, combined with a low degree of integration,

enables a limited number of generators to influence the balancing market outcome.

Moreover, the procurement rules can lower the overall economic efficiency of the power

system by creating so-called must-run capacity, i.e. capacity that does not (need to) react

to price signals from other markets, because it generates sufficient revenues from balancing

markets.

Beside procurement

rules,

there is a potential issue with procurement

volumes

due to

national sizing of reserves. Possible contributions of neighbouring resources are not

properly taken into account, thus over-estimating the amount of reserves to be procured

nationally.

Driver 2: Exemptions from fundamental market principles

Two fundamental principles of today's market framework are that (i) market participants

should be financially responsible for any imbalance in their portfolio and that (ii) the

operation of generation facilities should be driven by market prices. For a number of

reasons a wide range of exceptions from these principles exist today which could lead to

distortions, thus diminishing market efficiency.

The principle of financial responsibility for imbalances is often referred to as balancing

obligation. In many Member States, some market participants are fully or partly exempted

from this obligation, notably many renewable energy but also CHP generators. Exemptions

are typically granted on policy grounds, e.g. the existence of policy targets for renewables.

Such a special treatment constitutes a challenge for the cost-effective functioning of

electricity markets, because these technologies represent a significant share in total power

generation already and are expected to further grow in importance in the forthcoming

decade. For RES E, exemptions from balancing responsibility were initially justified on

the basis of significant errors in production forecasts being unavoidable (as production for

many RES E technologies is based on wheather) and on the absence of liquid short-term

markets which would have allowed RES E generators to trade electricity closer to real

time, thus reducing the error margin. Significant improvements have been made in

wheather forecasts, reducing the error margin. Part of these improvements was based on

financial incentives from increased balancing responsibilities

. Furthermore, cross-border

integration and liquidity of short-term markets has improved over the last years, with

further progress expected over the coming years, such as through the progressive

penetration of storage, and following the present proposal. Thus, the underlying reasons

for the exemption of RES E from this principle have to be revisited.

ENTSO-E provided figures that following the introduction of balancing responsibility in one Member

States, the average hourly imbalance of PV installations improved from 11.2 % in 2010 to 7.0 % in

March 2016, and the average hourly imbalance of wind improved from 11.1 % to 7.4 % over the same

period.

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A consequence of this lack of balancing obligation is that plant operators have no incentive

to maintain a balanced portfolio. The balancing obligation is typically passed on to the

responsible system operator, a regulated party, meaning that their balancing costs will be

socialised. This represents a market distortion and lowers the liquidity and efficiency of

short-term markets as the concerned market operators do not become active on the short-

term market to balance their portfolio. So the absence of full balancing responsibility is in

fact a major driver preventing the emergence of liquid and efficient short-term markets.

Moreover, costs arising from forecast errors for renewables are likely higher than

necessary due to a lack of incentive to minimise them by short-term market operations.

This creates a higher than necessary burden on consumers' electricity bills.

The principle that the operation of generation facilities should be driven by market prices

is also referred to as economic dispatch. When a unit's variable production costs are below

market price, it is economically efficient to dispatch it first, because the operator generates

(gross) profits from selling electricity. This principle guarantees that power is produced at

the lowest cost to reliably serve consumers, while taking into account operational limits.

However, priority dispatch deviates from this principle, by giving certain technologies

priority independent of their marginal cost. This represents a market distortion and leads

to a sub-optimal market outcome.

Given the expected massive increase in share of wind and solar technologies, it is likely

that unconditional dispatch incentives for these technologies will aggravate the situation,

as will the fact that certain RES E technologies and often CHP have positive variable

production costs. The review of priority dispatch rules for RES E is thus closely related to

the review of rules on public support in the RED II. Compared to the impact on RES E

from low marginal cost technologies, fully merit order-based dispatch has more significant

impact on conventional generation (CHP and indigenous fuels) and high marginal cost

RES E (e.g. RES E based on biomass), as these technologies will not be dispatched first

under the normal merit order. Achieving merit order based dispatch will in these cases

allow to use flexibility resources to their maximum extent, creating e.g. incentives for CHP

to use back-up boilers or heat storage to satisfy heat demand in case of low electricity

demand, and use flexible biomass generation to satisfy demand peaks rather than

producing as baseload generation.

Similarly, the principle of priority access reduces system efficiency in situations of

network congestion. When individual grid elements are congested, the most efficient

solution is often to change the dispatch of power generation or demand located as closely

as possible to the congested grid element. Priority rules deviate from this principle, forcing

the use of other, potentially much less efficient resources. With sufficient transparency and

legal certainty on the process for curtailment and redispatch, and financial compensation

where required, priority access should be limited to where it remains strictly necessary.

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R&D results

In relation to dispatching and curtailment, the Integral project showed that load-shedding

based on software tools and remote control can be a useful tool to manage grid constraints and prevent

network problems. It demonstrated that load-shedding can be done on a procurement basis by the grid

operator and is a viable alternative to RES E curtailment. Thus, the grid operator can find the most cost-

efficient solution on market based terms as opposed to taking recourse to simply curtailing certain sources

of generation.

Driver 3: Consumers do not actively engage in the market and demand response

potential remains largely untapped

The active participation of consumers in the market is currently not being promoted,

despite technical innovation such as smart grids, self-generation

and storage equipment

that allow consumers

–

even smaller commercial and residential consumers

–

to generate

their own electricity, store it, and manage their consumption more easily than ever. While

more and more consumers have access to smart meters and distributed renewable energy

resources such as roof-top solar panels, heat pumps and batteries, a minor share manages

their consumption and these resources actively.

Large-scale industrial consumers already are active participants in electricity markets.

However, the vast majority of other consumers neither has the ability nor the incentive to

take consumption, production and investment decisions based on price signals that reflect

the actual value of electricity and grid infrastructure. The metering and billing of

consumers does not allow them to react to prices within the time frames in which wholesale

markets operate. And even where technically possible, many electricity suppliers appear

reluctant to offer consumer tariffs that enable this. This leads to the

overconsumption/underproduction of electricity at times when it is scarce and the

underutilisation/overproduction of electricity at times when it is abundant.

Indeed, current markets do not enable us to reap the full benefits of technological progress

in terms of reducing transaction costs, reducing information asymmetries, and (thereby)

reducing barriers to market participation for smaller commercial and residential

consumers.

Periods of abundance and scarcity will increasingly be driven by high levels of RES E

generation. To deal with an increased share of variable renewables generation in an

efficient way, flexibility is key. Traditionally, almost all flexibility was provided in the

electricity systems by controlling the supply side. However, it is now possible to provide

demand side flexibility cost effectively. New technological developments such as smart

metering systems, home automation, etc. but also new flexible loads such as heat pumps

and electric vehicles allow for the reduction of demand peaks and, hence, significantly

reduce system costs.

Technological developments are both part of the drivers that affect the present initiative and part of the

solutions of the identified problems they affect. Therefore reference is made to finding of various

research and development projects that provide insights where these are pertinent. A list of the research

and development projects mentioned in this box and their findings relevant to the present impact

assessment is provided in Annex 8.

The specific issue of self-generation and self-consumption is analysed in detail in the Impact Assessment

for the RED II.

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The current theoretical potential of demand response adds up to approximately 100,000

MW and is expected to increase to 160,000 MW in 2030. This potential lies mainly with

residential consumers, and its increase will greatly depend on the uptake of new flexible

loads such as electric vehicles and heat pumps.

Figure 1: Theoretical demand response potential 2016 (in MW)

50000

45000

40000

35000

30000

25000

Industrial

20000

15000

10000

5000

Commercial

Residential

Source: Impact Assessment support Study on downstream flexibility, demand response and

smart metering, COWI, 2016

For the industrial sector demand response is mainly related to flexible loads in electric steel

makings. In the commercial sector, a high theoretical potential exist for ventilation of

commercial buildings while in the residential sector mainly freezers and refrigerators, and

the electric heater with storage capacity show a high theoretical potential.

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Figure 2: Theoretical potential of demand response per appliance

Theorertical potential of demand response per

appliance

Residential heat circulation pumps

Electric storage heater residential sector

Storage hot water residential sector

Residential AC

Dish washers

Laundry driers

Washing machines

Residential refrigerators/freezers

Waste water treatment

Pumps in water supply

Electric storage heater commercial sector

Storage hot water commercial sector

AC Commercial Buildings

Ventilation Commercial Buildings

Cooling Hotels/Restaurants

Cold storage houses

Cooling Retail

Industrial Building Ventilation

Industrial Cooling

Air Seperation

Calcium Carbide

Cement

Electric Steel

Paper Recycling

Paper Machines

Mechanical Pulp

Chlorine

Zinc

Copper

Aluminum

4000

8000

12000

16000

2030

2020

2010

Source: Impact Assessment support Study on downstream flexibility, demand response and

smart metering, COWI, 2016

Approximately 30-40% of this potential can be considered technically and economically

viable and, hence, can expected to be activated if the right technologies, incentivising

mechanisms and market arrangements are in place. Demand response service providers

(often referred to as aggregators) can play an important role in activating this potential by

enabling smaller consumers and distributed generation in general to interact with the

market and have their resources being managed based on price signals, or provide

balancing or grid congestion services. These aggregators effectively reduce transaction

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costs and information asymmetries in the market, enabling a large number of smaller

and/or distributed resources to praticipate.

Of this potential, currently only around 21,000 MW demand response is used in the market.

Approx. 15,000 MW are contracted from large industrial consumers through direct

participation in the market while approx. 6,000 MW come from residential consumers who

are on traditional time of use tariff (usually just differentiating between day and night).

Only in the Nordic markets a slow uptake of dynamic price contracts linked to the

wholesale market is taking place. This shows that especially in the residential and

commercial sector with a theoretical potential of more than 70,000 MW the uptake of

deman dresponse is slow.

The main reasons for residential and commercial consumers not taking part in the demand

response schemes are mostly technical but can also be explained by currently relative small

benefits for those consumer groups:

The technological prerequisites are not yet installed and even where smart meters

are being rolled out they do not always have the functionalities necessary for

consumers to take active control of their consumption;

Dynamic electricity price contracts are only available for commercial/residential

consumers in very few Member States and hence consumers do not have a

financial incentive to shift consumption;

In many Member States, third-party service providers helping consumers to

manage their consumption can not freely engage with consumers and do not have

full access to the markets;

In many European markets price spreads are reletively small and price peaks either

not incur often or only lead to peak prices that are slightly higher than the average

price which makes demand response currently not very interesting from a financial

point of view. However, with an increase in renewables generation this price

spreads are likely to increase and participating in demand response will become

more profitable for consumers in the future. Variable network tariffs can equally

contribute to increasing the price spread;

Consumers are more likely to participate in demand response when they have

significant single loads such as electric heating or electric boilers that are easy to

shift. In that respect the uptake of electric vehicles and heat pumps will also open

new opportunities for consumers to engage in demand response;

Finally, automatisation is key to untap the full potenial of demand response in the

residential and commercial sector. Considering the relatively small economic

benefit residential consumers are likley to realise by participating in demand

response it is essential that theparticipation does not require active efforts but

devices can react automatically to price signals. Hence, interoperability of smart

metering systems will be crucial for the uptake of demand response.

In addition, the current design of the electricity market has not evolved to fully accomodate

demand side flexibility. It was meant for a world where consumers are passive consumers

of electricity that do not actively participate in the market. Hence, current market

arrangements at both the wholesale and retail level often make it very difficult for demand-

side flexibility to compete on a level playing field with generation:

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Similar to RES E, consumption is variable and subject to forecast errors. As a

consequence, it is often infeasible for most individual customers to offer demand-

response many days ahead of the moment when electricity is actually consumed

The liquidity of intraday markets

–

where demand response at short notice can

fetch a high price

–

is currently limited, providing little incentive to offer demand-

side flexibility;

Procurement timeframes for balancing reserves capacity have generally long lead

times (week-, month- or year-ahead) for which demand response cannot always

secure firm capacity.

Balancing markets often require that units can offer both upward regulation (i.e.

increasing power output) and downward regulation (i.e. reducing power output;

offering demand reduction) at the same time, making it difficult for demand

response to participate in those markets;

And finally, product definitions make it difficult for aggregated loads to compete

in many markets.

The table below summarizes in which Member States markets are open to demand

response and the volume of demand response contracted. While demand response is

allowed to participate in most Member States, volumes of more than 100MW can only be

found in 13 Member States.

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Table 3: Participation of explicit Demand Response in different markets

Member State

Demand Response

in energy markets

Demand Response

in balancing

markets

Demand

Response in

Capacity

mechanisms

Estimated

Demand

Response for

2016 (in MW)

104

689

566

810

1689

860

1527

4131

Austria

Yes

Belgium

Yes

Bulgaria

Croatia

Cyprus

No market

Czech Republic

Yes

Denmark

Yes

Estonia

Yes

Finland

Yes

France

Yes

Germany

Yes

Greece

No (2015)

Hungary

Yes

Ireland

Yes

Italy

Yes

Latvia

Yes

Lithuania

unclear

Luxembourg

No information

Malta

No market

Netherlands

Yes

170

Poland

Yes

228

Portugal

Yes

Romania

Yes

Slovakia

Yes

Slovenia

Yes

Spain

Yes

2083

Sweden

Yes

666

Yes

1792

Total

15628

Source: Impact Assessment support Study on downstream flexibility, demand response and smart metering,

COWI, 2016

R&D results:

VSync demonstrated that PV or wind generation, if equipped with a technology as

demonstrated in the VSync project, can replace the inertia that large power plants possess that is needed to

reduce frequency variations. Therefore, such technologies could in principle be used to provide balancing

services to the TSO.

EvolvDSO has identified and worked-out the details of future roles for actors active in the management of

power systems at the distribution level. The project identifies ways in which flexibility of resources

connected at distribution level could be revealed, valorised, contracted and exploited by various actors of the

power system. It identified roles that could be fulfilled by DSOs and by market parties and asks that these

are clarified

Several European demonstration projects such as ECOGRID-EU, Integral, EEPOS, V-Sync and S3C have

provided evidence that demand response is sufficiently mature from a technical point of view, while stressing

the need to removing market related barriers to its deployment.

In particular, Integral and ECOGRID-EU show that valuing flexibility through price signals is possible and

easy, that local assets can participate and earn money in the wholesale market, and that the economic viability

depends on the value of flexibility. Integral also demonstrated that flexibility of a household's energy

consumption (and hence the ability to provide demand response) was higher than initially expected, probably

due to the automated response that did not require active consumer participation. ECOGRID-EU showed

that a customer with manual control gave a 60 kW total peak load reduction while automated or semi-

automated customers gave an average peak reduction of 583 kW

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RES E and flexible electricity systems

Demand response, like other measures that improve the degree of flexibility in the system,

have an connection to the ability of RES E to finance itself in the market, through what is

often referred to as the 'merit order effect'.

During windy and sunny days the additional

electricity supply reduces the prices. Because the drop is larger with more installed

capacity, the market value of variable renewable electricity falls with higher penetration

rate, translating into a gap to the average market value of all electricity generators over a

given period. Inflexible markets where demand and generation are non-responsive to price

signals (including through measures such as priority dispatch or 'must-run' obligations)

render this effect more pronounced. This effect is already visible today in certain Member

States, and in the absence of measures, can be expected to become even more relevant as

renewables penetration increases further.

At the one hand, this implies that as renewables are further gaining market shares in the

coming decade, the regulatory framework should not only incentivise the deployment of

renewables where costs are low (e.g. due to abundant wind or solar resources), but also

where and when the value of the produced electricity is the highest. On the other hand, by

improving the market framework in which RES E operates by rendering it more flexible,

unnecesarry erosion of the value of RES E assets can be prevented.

Reference is made to the box in Section 6.2.6.3 and Section 6.2.6.4 for further information.

Driver 4: Distribution networks are not actively managed and grid users are poorly

incentivised

Most of the time, the present regulatory framework does not provide appropiate tools to

distribution network operators to actively manage the electricity flows in their networks.

It also does not provide incentives to customers connected to distribution grids to use the

network more efficiently. Because smaller consumers have historically participated in the

broader electricity system only to a limited extent, currently no framework exists that puts

such incentives in place. This has led to fears over the impact that the deployment of

distributed resources could have at system-level (e.g. that the costs of upgrading the

network to integrate them would outweigh their combined benefits in other terms).

Moreover, the regulatory framework for DSOs, which most of the times is based on cost-

plus regulation, does not provide proper incentives for investing in innovative solutions

which promote energy efficiency or demand-response and fails to recognise the use of

flexibility as an alternative to grid expansion.

With RES E being a source of electricity generation that is often decentralised in nature,

DSOs are gradually being transformed from passive network operators primarily

concerned with passing-on electricity from the transmission grid to end-consumers, to

network operators that, not unlike TSOs, actively have to manage their grids. At the same

See Hirth, Lion,

"The Market Value of Variable Renewables",

Energy Policy, Volume 38, 2013, p.

218-236). The merit order effect is occasionally also referred to as the 'cannibalisation effect'.

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time, technological progress allows distribution system operators to reduce network

investments by managing locally the challenges that more decentralised generation brings

about. However, outdated national regulatory frameworks may not incentivise or even

permit DSOs to make these savings by operating more innovatively and efficiently because

they reflect the technological possibilities of yesteryear. The resulting inflexibility of

distribution networks significantly increases the cost of integrating more RES E

generation, particulary in terms of investment.

R&D results:

Reduced network investment by managing locally decentralised generation is demonstrated

in European projects like: SuSTAINABLE, MetaPV, evolvDSO, PlanGridEV, BRIDGE and REServices

According to EvolvDSO, flexibility procurement and activation by DSOs are not addressed in the regulatory

framework in most Member States: they are not excluded in principle but not incentivised either and, because

they are not explicitly addressed, this creates uncertainty for the DSO to apply them.

The REServices study has analysed the possible services that wind and solar PV energy can provide to the

grid in theory but concludes that they are not able to (in the Member States analysed) due to the way the

market rules are defined.

The project SuSTAINABLE demonstrated that intelligent management supported by more reliable load and

weather forecast can optimise the operation of the grid. The results show that using the distributed flexibility

provided by demand-side response can bring an increase of RES E penetration while, at the same time, avoid

investments in network reinforcement, and this leads to a decrease in the investment costs of distribution

lines and substations.

The BRIDGE project recommended that products for ancillary services should be consistent and

standardized from transmission and down to the local level in the distribution network. Such harmonization

will facilitate the participation of demand-side response and small-scale RES in the markets for these

services, and thereby increase the availability of the services, enable cross-border exchanges and lower

system costs.

Tests in the project PlanGridEV with controllable loads (demand response, electric vehicles) performed in a

large variety of grid constellations have shown that peak loads could be reduced (up to 50%) and more

renewable electricity could be transported over the grid compared to scenarios with traditional distribution

grid scenarios. As a result, critical power supply situations can be avoided, and grids, consequently, do not

call for reinforcement

Both MetaPV and EvolvDSO suggest that a DSO makes a multiannual investment plan that takes into

account flexibility it can purchase from connected demand-side response or self-producers and consumers

(MetaPV suggests to do this through a cost-based analysis)

MetaPV also demonstrated that remotely controllable inverters connecting PV-panels to the distribution grid

can offer congestion management services to the distribution grid (in the form of voltage control obtained

via reactive power modulation). This increases the capacity of the distribution grid to integrate intermittent

RES by 50%, at less than 10% of

the costs of ‘traditional’ investments in hardware such as copper.

2.2.

Problem Area II: Uncertainty about sufficient future generation investments

and uncoordinated capacity markets

In light of the 2030 objectives, considerable new investment in electricity generation

capacity will be required. The power sector is likely to play a central role in the energy

transition. First, it has been the main sector experiencing decarbonisation since the last

A list of the research and development projects mentioned in this box and their findings relevant to the

present impact assessment is provided in Annex 8.

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decade and its challenges still remain high. Second, in the near future, the power sector is

expected to support the economy in reducing its dependence on fossil fuels, notably in the

transport and heating and cooling sectors.

Generation capacity in the EU increased sharply from 2009 onwards due to the addition of

new renewables technologies to the already existing capacity. The composition of the

capacity mix progressively changed. Nuclear capacity started declining in recent years

(2010-2013) due to phasing out decisions in some Member States. Other conventional

capacity showed a decline in 2012-2013 as well

The largest part of the required new capacity will be variable wind and solar based,

complemented by more firm, flexible and less carbon-intensive forms of power generation.

At the same time, in light of the ageing power generation fleet in Europe with more than

half of the current capacity expected to be decommissioned by 2040

, it is important to

maintain sufficient capacity online to guarantee security of supply. The modelling results

nevertheless indicate that investment needs in additional thermal capacity will be limited

especially in the period 2021-2030. According to PRIMES EUCO27, about 81% of net

power capacity investments will be in low-carbon technologies, of which 59% in RES E

and 22% in nuclear generation

Table 4: Investment Expenditure (including new construction, life-time extension

end refurbishment) in generation capacity by technology (average over 5 year

period) in MEuro'13

Period

Nuclear

Renewable energy

Hydro (pumping

5,995

2,557

excl.)

Wind

9,238

17,095

Solar

1,556

9,019

Other renewables

Biomass-waste fired

2,626

3,438

Geothermal heat

100

Thermal

11,989

14,019

Solids fired

1,029

1,237

Oil fired

639

373

Gas fired

7,595

8,880

Hydrogen plants

Total (incl. CHP)

30,280

43,430

Source: PRIMES; based on EUCO27 scenario

2000-2005

1,502

16,789

2005-2010

739

28,672

2010-2015

270

43,393

3,289

19,614

20,487

4,157

110

13,391

5,333

362

3,427

57,054

2015-2020

6,291

38,957

2,239

28,553

7,870

295

11,779

182

17,151

2,610

2,505

62,399

2020-2025

11,011

25,217

354

14,059

10,581

223

465

3,355

870

1,987

39,583

2025-2030

14,312

21,911

633

14,219

6,728

332

433

3,274

192

2,641

39,497

See on this and for further information,

European Commission, Investment perspectives in electricity

markets,

Institutional

Paper

003,

July

2015,

page

http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf.

World Energy Outlook 2015, IEA

The challenge to attract sufficient investment in RES E is examined in detail in the RED II impact

assessment

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At the same time, short-term market prices at wholesale level have decreased substantially

over the past years. In parallel with high fossil fuel prices, European wholesale electricity

prices peaked in the third quarter of 2008; then fell back as the economic crisis broke out,

and slightly recovered between 2009 and 2012. However, since 2012 wholesale prices have

been decreasing again. Compared to the average of 2008, the pan-European benchmark for

wholesale electricity prices were down by 55% in the first quarter of 2016, reaching 33

EUR/MWh on average, which was the lowest in the last twelve years

Figure 3 on pan-European wholesale market prices

Source: Platts and European power exchanges

Prices declined for a number of reasons

including (i) a decrease in primary energy prices

(e.g. coal, and more recently also natural gas), (ii) an increasing imbalance between the

supply and demand for carbon allowances, leading to a surplus of over 2 billion allowances

by 2012 and a corresponding decrease in carbon allowance prices

, and (iii) an

See the "main findings" of Section 1.1 on Wholesale electricity prices from the 2016 Commission Staff

Working Document accompanying the forthcoming

'Report on energy prices and costs in Europe'.

The influence of each market factor might strongly very across different regions. For example, the share

of renewables and carbon prices have strong impact on wholesale price evolution in North Western

Europe, while in Central and Eastern Europe the main price driver is the share of coal and gas in the

generation mix.

Between April 2011 and May 2013 carbon emission allowance contracts underwent a significant price

fall (decreasing from 17 EUR/tCO2e to 3.5 EUR/tCO2e) reflecting the fall in demand for allowances

due to the recession. Since April 2013 carbon prices have increased, reaching an average auction clearing

price of €7,62/tCO2e in 2015.

(See:

http://ec.europa.eu/clima/policies/ets/auctioning/docs/cap_report_201512_en.pdf).

The extent to which the carbon price impacts the wholesale power price depends on the carbon intensity

of the marginal power producer.

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overcapacity of power generation facilities

, putting a downward pressure on wholesale

prices.

Overcapacity was, in turn, caused by: (i) a drop in electricity demand as electricity

consumption decoupled from an already low economic growth

, (ii) over-investments in

thermal plants

, (iii) the increasing proportion of renewables with low marginal costs

driven by EU policies, (iv) barriers to decommission capacity

, and (v) continuing

improvement in the field of coupling national electricity markets

, leading to an increased

sharing of resources among Member States

As a result, for most regions in Europe current electricity wholesale prices do not indicate

the need for new investments into generation capacity. There are, however, doubts whether

the market, as currently designed, would be able to produce investment signals in case

generation capacities were needed. Independently of current overcapacities of most regions

in Europe, a number of Member States anticipate inadequate generation capacity in future

years and introduce capacity mechanisms at national level.

In parallel with decreasing fossil fuel and carbon prices (resulting in decreasing marginal costs of

electricity generation(, and the generation overcapacity, the share of renewable energy sources (wind,

solar, biomass, also including hydro) has been gradually increasing over the last few years. In most of

the EU countries fossil fuel costs set the marginal cost of electricity generation, being decisive for the

wholesale electricity price. However, increasing share of renewables in the electricity mix, together with

significant baseload generation capacities, shifted the generation merit order curve to the right, resulting

in lower equilibrium price set by supply and demand. Consequently, we can say that increasing share of

renewable energy sources, in an already oversupplied market, have significantly contributed to low

wholesale electricity prices in the EU markets.

Consumption of electricity in the EU decoupled from economic growth during the last few years due to

energy efficiency gains.

Investment decisions in the electricity sector are typically taken long before returns on investment are

effectively earned, due to the time to construct new power plants. At the same time, the decentralised

nature of investment decision-making means that each generator has limited information about the

generation capacity that competitors will make available in the coming years. The result is what has

been referred to as boom-bust cycles: alternate periods of shortages and overcapacity resulting from lack

of coordination in the investment decisions of competing generators.

In some Member States, there is an overcapacity situation that is in fact artificially extended by clear

regulatory exit barriers, which in the short-term depress market prices and in the mid/long-term ruin the

investment incentives.

In parallel, progressing market integration decreased price divergence within the EU. Indeed in the first

quarter of 2008 the price difference between the most expensive and the cheapest European wholesale

electricity market was 44 EUR/MWh, eight years later this difference has shrunk to 24 EUR/MWh.

Based on "main findings" from 2016 costs and prices report and underlying studies, published in

conjunction with the present impact assessment

See also Box 9 behind section 6.4.6 for more on overcapacity, market exit and prices

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Driver 1: Lack of adequate investment signals due to regulatory failures and

imperfections in the electricity market

The internal energy market is built on competitive (short and long-term) wholesale power

markets where price signals are central to guide market participants production and

consumption decisions. Short-term prices signal prevailing supply and demand conditions

while long-term prices are formed according to expectations about future supply and

demand. Conditions, such as for example shortages or oversupply that are expected to

prevail in the future will not only determine short-term (spot) prices but also impact long-

term (forward, futures) prices.

In around half of Member States sales achieved at short and long term markets determine

the bulk of generators' income

. This income is required to cover their full costs, mainly

fuel, maintenance and amortisation of assets (i.e. investments). These arrangements are

often referred to as energy-only markets. In the other half of Member States there are also

measures (either market based or non-market based) in place to pay generators for keeping

their capacity available (capacity mechanisms or 'CM's), regardless as to whether they are

producing electricity or not

. For generators who operate on the market these payments

represent an additional income next to their earnings on the wholesale markets for energy.

Capacity payments, thus, represent additional support to maintain and/or develop capacity.

Irrespective whether generators are expected to earn their investments solely on the

'energy-only' market or whether they can also rely on additional payments for capacity,

wholesale power prices are central to provide the right signals for efficient market

See below, figure 1 and ACER Market Monitoring Report 2014; generators may also collect additional

income from offering their capabilities, including the availability of (short-term) electricity to TSO's

who rely on them to manage the system (i.e. short-term balancing and ancillary Services)

"Capacity

mechanisms exist worldwide both in regulated and in non-regulated markets":

CIGRE paper

C5-213, "Capacity

Mechanisms: Results from a World Wide Survey",

H. Höschle, G. Doorman (2016).

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operations. For the EU-target model

to function properly, prices need to be able to

properly reflect market conditions

Price signals and long-term confidence that costs can be recovered in reasonable payback

times are essential ingredients for well-functioning market. In a market which is not

distorted by external interventions, the variability of the spot price on the wholesale

market, plays a role in signalling the need of investment in new resources. In the absence

of the right short- and long-term price signals, it is more likely that inappropriate

investment or divestment decisions are taken, i.e. too-late decisions or technology choices

that turn out to be inefficient in the long run. Price differentials between different bidding

zones should determine where generation and demand should ideally be located,

In 2013 the Commission published an assessment identifying reasons why the market may

fail to deliver sufficient new investment to ensure generation adequacy

. These reasons

are a combination of market failures and regulatory failures. For example when consumers

cannot indicate the value they place on uninterrupted electricity supply, the market may

not be effective performing its coordination function. Equally however, regulatory

interventions, as well as the fear of such interventions, such as price caps and bidding

restrictions (regardless as to whether effectively restricting price formation at that moment

or only later) limit the price signal for new investments. Likewise the prices on balancing

markets operated by TSOs should not undermine the price signals from wholesale markets.

Power generators and investors have argued that regulatory uncertainty and the lack of a

stable regulatory framework undermine the investment climate in the Union compared to

other parts of the world and to other industries.

In fact, current market arrangements often do not allow prices to reflect the real value of

electricity, especially when supply conditions are tight and when prices should reflect its

scarcity, affecting the remuneration of electricity generation units that operate less often

but provide security and flexibility to the system.

These regulatory failures are amplified by the increasing penetration of RES E. RES E is

capacity that often has a cost structure typified by low operational costs

, resulting in more

The "Electricity

Target Model"

aims at integrating wholesale power markets by harmonising the way

how transmission capacity is allocated between Member States. Central to it is market coupling which

is based on the, so-called, "flow based" capacity calculation, a method that takes into account that

electricity can flow via different paths and optimises the representation of available capacities in meshed

grids. The implementation of the target models in gas and electricity is equivalent to achieving the

completion of the internal energy market.

Evidently, efficient market outcome also presumes that all assets are treated equally in terms of the risks

and costs to which they are exposed and the opportunities for earning revenues from producing

electricity i.e. they operate on a level playing field as is esually fostered by the present intiative.

See on price signals, European Commission,

Investment perspectives in electricity markets,

Institutional

Paper

003,

July

2015,

pages

and

following.

(http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf

See also VaasaETT

(2014), '

Market Entrant Processes, Hurdles and Ideas for Change in the Nordic Energy Market',

p.22,

http://www.nordicenergyregulators.org/wp-content/uploads/2014/12/VaasaETT-Report-

Market_Entry_Barriers.pdf.

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default presentation of deals by some websites, the use of misleading language, and a lack

of transparency about commission arrangements. Indeed, a third of respondents to a recent

EU survey somewhat or strongly agreed that they did not trust comparison websites

because they were not impartial and independenct.

131

And thirdly, consumer groups report that consumers have difficulties understanding their

energy bills and comparing offers in spite of existing EU legislation aiming to facilitate

this. There is a broad divergence in national requirements around billing and consumer

satisfaction with their bills varies significantly between different Member States. Whereas

energy bills are the foremost means through which suppliers communicate with their

customers, consumers' inability to correctly answer simple questions about their own

electricity use reveals that bills are not effective in providing information that could

facilitate effective consumer choice.

132

Addressing this will be increasingly important with

the shift to more varied consumer products.

R&D results:

The project S3C has developed a toolkit for the active engagement of end users and identifies

improvements to the way and content of the communication of energy system actors with customers and

citizens.

2.5.

What is the EU dimension of the problem?

The EU's electricity market is strongly integrated physically, economically and from a

regulatory point of view. The discretion of Member States to act individually has been

substantially reduced by the resulting interdependencies and, in fact, can create significant

externalities if not adequately framed within an EU-wide context.

RES E deployment is expected to increase in all Member States. The need to spur the

emergence of a more flexible electricity system thus exists EU-wide. Moreover, as the EU

electricity system is both physically and economically integrated, non-coordinated action

is likely to increase the costs of RES E integration.

The same applies to CMs where the externalities of non-coordinated action are one of the

underlying reasons for the proposed measures. It is true that not all Member States have

enacted CMs, however the benefits of a more coordinated approach will benefit all

Member States. Member States that have implemented a CM will be able to lower their

costs by increased cross-border competition whereas the avoidance of negative spill-over

effects will benefit all Member States regardless as to whether they enacted a CM or not.

In an integrated electricity market, considering the prevention and management of

electricity crisis a purely national issue leads to serious problems. Where crisis situations

occur, they often have a cross-border effect, and can entail serious adverse consequences

for the EU as a whole. Evidence shows that non-coordinated approaches to preventing and

managing electricity crisis may seriously distort the internal electricity market and put at

risk the security of supply of neighbouring Member States.

131

132

"Study

on the coverage, functioning and consumer use of comparison tools and third-party verification

schemes for such tools"

(2013) European Commission, pp. xix, 191.

For example, less than one third of consumers recently surveyed strongly agreed that they knew what

kind of a contract they currently had (fixed price, variable price, green, etc.).

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Well designed and implemented consumer policies with a European dimension can enable

consumers to make informed choices that reward them through healthy competition, and

support the European goal of sustainable and resource-efficient growth, whilst taking

account of the needs of all consumers. Increasing confidence and ensuring that unfair

trading practices do not bring a competitive advantage will also have a positive impact in

terms of stimulating growth. The consumer-related measures undertaken as part of this

initiative therefore play an essential role in the establishment and functioning of the

internal market.

2.6.

How would the problem evolve, all things being equal?

The projected development of the current regulatory framework

In the absence of additional measures, the electricity market would continue to be governed

by the Third Package and the Electricity Security of Supply Directive. Various network

codes may still be adopted and implemented

133

, such as the draft Network Code on

Emergency and Restoration and the Balancing Guideline. Whilst these network codes will

help address some of the issues identified above, they will not offer a sufficient remedy on

their own.

Solving the above-identified problems requires measures that cannot be addressed in the

current legal framework. As the network codes constitute secondary implementing

legislation designed to amend non-essential elements of the Third Package by

supplementing it, their scope is confined to the same limits drawn by the Third Package

and hence, developing new network codes cannot be expected to provide for adequate

solutions either.

In view of the fact that the proposals in essence develop new areas for which currently no

clear legal basis exist in the Third Package or in the Electricity Security of Supply

Directive, stronger enforcement is not an option either (with some limited exceptions,

which are further developed below).

Member States have developed forms of voluntary collaboration that attempt to address

some of the problems identified. However, these initiatives cannot be expected to resolve

all problems and with the same effectiveness as EU action (See also EU value added).

Regarding security of supply in particular, both the evaluation and the results of the public

consultation clearly show that Directive 2009/89 is outdated. It does not take account of

the current, fast evolving situation of the electricity market. And it offers no framework

for coordinating national policies in the area of security of electricity supply.

With regards to consumer issues, the Commission may develop guidance to tackle

implementation issues caused by difficulties in interpreting the existing legislation. In

particular, it may issue an interpretative note on the existing provisions in the Electricity

and Gas Directives covering switching-related fees, as well as further guidance on how the

dozen or so consumer Directives relevant to comparison tools should be applied.

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For a full overview of network codes, see Annex VII.

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On energy poverty, the Commission will already set up the EU Energy Poverty

Observatory using funds already secured from the European Parliament. However, the

extent to which the Observatory continues to share good practices and improve data

gathering is uncertain, as continued funding is not secured beyond the first year of

operation. Moreover, the impact of this measure may be limited as the current legislation

does not require Member States to measure energy poverty and hence to address it.

Expected evolution of the problems under the current regulatory framework

Both this and the impact assessment for the parallel RED II initiative come to the

conclusion that the electricity market, provided that it is improved, together with projected

CO2 prices, may deliver investments in most mature low-carbon technologies such as solar

PV and onshore wind by 2030. However, in the absence of a market optimised for

increasing levels of renewable penetration, achieving the 2030 objectives will only be

possible at significantly higher costs.

In the absence of a better defined framework for government interventions, the current

trend of non-coordinated implementation of national resource adequacy measures risks

proliferating, undermining the efficiency of the market to deliver efficient production and

investment decisions and defragmenting its regulatory framework.

In fact, in the absence of measures that will improve investment incentives and efficient

market functioning, it is likely that more Member States will have to take recourse to means

other than the market to secure sufficient investments for resource adequacy purposes,

setting in motion a negative spiral in which government interventions increase the need for

the subsequent one.

Failing to integrate all participants in the market means that their decisions will not be

guided by market signals, entailing the risks that their investment and production decisions

will be sub-optimal from a welfare perspective, if not distort markets.

In addition, in the absence of a clear framework for co-ordinated action between Member

States when it comes to preventing and managing crisis situations, the EU's electricity

system risks being increasingly exposed to risks of serious incidents, without the EU or its

Member States having any means to properly tackle them. There is a real risk that Member

States will continue to do as they see fit in crisis situations, thus undermining the proper

functioning of the internal electricity market.

Regarding active consumer engagement, Member States have committed to deploying

smart meters to around two thirds of the population while access to innovative services

such as demand response or in the area of self generation remains limited in many Member

States. Individual action by Member States would perpetuate current differences in the

Union regarding consumer awareness, choice and access to dynamic prices, demand

response and integrated smart services. Consumer-friendly functionalities would be taken

up partially and the flexibility consumers can provide to the electricty system would remain

largely untapped.

With regards to consumer protection and engagement, enforcement could help diminish

the illegal switching-related costs currently faced by an estimated 4% of all EU electricity

consumers. And some Member States may also voluntarily cease or reduce excessive

regulatory interventions in price-setting as their retail markets mature. However,

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shortcomings in the existing legislation will greatly limit the Commission's ability to tackle

these and other consumer-related problem drivers more effectively.

The issue of energy poverty is likely to remain relevant. Pressure on energy prices may

continue as a result of the efforts to decarbonise the energy system. If energy prices grow

faster than household income, more and more households will find it difficult to pay their

energy bills. This may have a knock-on effect on Member States willingness to lift price

regulation which will ultimately impact suppliers' ability to innovate, competition and

consumer welfare. Thus, the greater the importance of enhanced transparency to estimate

the number of energy poor households.

And whilst many Member States may seek to ensure the neutral, expedient, and secure

management of consumer data, it is highly likely that national requirements will vary

significantly, leading to an uneven playing field for new suppliers and energy service

companies in the EU. Here, the only credible approach to effectively tackling the potential

conflicts of interest among market actors is a legislative one.

2.7.

Issues identified in the evaluation of the Third Package

A retrospective evaluation was carried out in parallel with the present impact assessment

and has been added as Annex VI. Its main conclusions are:

That the initiative of the Third Package to further increase competition and to

remove obstacles to cross-border competition in electricity markets has generally

been effective and that active enforcement of the legislation has led to positive

results for electricity markets and consumers. Markets are in general less

concentrated and more integrated than in 2009. As regards retail markets, the set

of new consumer rights introduced by the Third Energy Package have clearly

improved the position of consumer in energy markets.

However, the success of the rules of the Third Package in developing the internal

electricity market further to the benefit of customers remains limited in a number

of fields concerning wholesale and retail electricity markets.

Moreover, while the principles of the Third Package achieved its main purposes

(e.g. more supplier competition), new developments in electricity markets such as

the increase of RES E, the increase of state interventions into the electricity markets

and the changes taking place on the technological side have led to significant

changes in the market functioning in the last five years and have dampened the

positive effect of the reforms for customers. There is a gap in the existing legislation

regarding how to deal with these developments.

The conclusions of the evalution are also reflected in section 3 of each of the Annexes

1.1 throught to 7.6 to the present impact assessment.

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3.1.

UBSIDIARITY

The EU's right to act

In order to create an internal energy market, the EU has adopted three consecutive

packages of measures between 1996 and 2009 aiming at the integration and liberalisation

of the national electricity and gas markets and addressing a wide range of elements such

as market access, the improvement of the level playing field, transparency, increased rights

for consumers, stronger independence of regulatory authorities, etc. In February 2011, the

European Council set the objective of completing the internal energy market by 2014 and

of developing interconnections to put an end to any isolation of Member States from the

European gas and electricity grids by 2015. In June 2016, the European Council called for

Single Market strategies, including on energy, and action plans to be proposed by the

Commission and to be completed and implemented by 2018.

Article 194 of the Treaty on the Functioning of the European Union ('TFEU') consolidated

and clarified the competences of the EU in the field of energy. According to Article 194

TFEU, the main aims of the EU’s energy policy are to: ensure the functioning of the energy

market; ensure security of energy supply in the Union; promote energy efficiency and

energy saving and the development of new and renewable forms of energy; and promote

the interconnection of energy networks.

The planned measures of the present intiative further progress towards the objective of

improving the conditions for competition by improving the level playing field, while at the

same time adjusting to the decarbonisation targets and enhancing the solidarity between

Member States in relation to security of supply.

Therefore, Article 194 TFEU is the legal basis of the current proposal.

3.2.

Why could Member States not achieve the objectives of the proposed action

sufficiently by themselves?

The section below provides a high-level summary of the necessity of EU action, based on

the four problem areas identified in section 2.

The issue of subsidiarity is also discussed in section 6 of Annexes 1.1 to 7.6 to the present

impact assessment.

As regards the issue concerning a market design that is not fit for taking up large amounts

of variable, decentralised electricity generation and allowing for new technical

developments, it is important to note that EU action is necessary to ensure that national

markets are comparable in order to improve the functioning of the internal electricity

market and enable maximum cross-border trading to happen. EU-action is also necessary

in order to enhance the transparency in the functioning of the electricity markets and avoid

discrimination between market parties. Moreover, a number of the measures proposed to

address this issue (e.g., measures for the common sizing and procurement of balancing

reserves) require full cooperation of neighbouring TSOs and NRAs, and hence individual

Member States might not be able to deliver a workable system or might only provide

suboptimal solutions. Moreover, existing provisions under the Third Package are arguably

not sufficiently clear and robust and their implementation of such rules has highlighted

areas with room for improvement and hence EU action will be necessary to address the

identified shortcomings.

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With specific respect to DSOs, distribution grids will have to integrate even greater

amounts of RES E generation in the future, and so ensuring all DSOs can efficiently

manage their networks will help to reduce distribution costs and thereby support the

achievement of EU RES targets. In addition, widely divergent distribution tariff regimes

may affect the development of the internal energy market as they affect the conditions

under which RES E generation or other resources can access the grid and participate in the

national and cross-border energy markets. EU action in these areas would thereby facilitate

the deployment of RES E and create a level playing field for flexibility services such as

demand response by ensuring a coherent approach by Member States based on common

principles. Developing this through independent Member State action would not be

feasible given the heterogeneity of current national networks and regulations.

Concerning the uncertainty about future investments in generation capacity and

uncoordinated government interventions, the measures in the proposed initiative aim at

improving the functioning of the electricity markets and at improving the coordination

between Member States for capacity mechanisms. The necessity of EU action derives from

the fact that as regards the measures for improving the functioning of the electricity

markets, these are already covered by EU legislation, although not sufficiently clearly, and

therefore an amendment to such measures to address the distortions and deficiencies

identified would require EU action. For the measures concerning the improvement of the

coordination between Member States for capacity mechanisms, given that the aim is to

address the shortcomings identified from resource adequacy assessments carried out at

national level and to develop the cross-border participation in capacity mechanisms, the

EU is best placed to provide for a harmonised framework.

In relation to the problem that Member States do not take into account of what happens

across their borders when preparing for and managing electricity crisis situations, the

necessity of EU action is based on the evidence that uncoordinated national approaches

not only lead to the adoption of suboptimal measures but that they also make the impacts

of a crisis more accute. Given the interdependency between the electricity systems of

Member States, the risk of a blackout is not confined to national boundaries and could

directly or indirectly affect several Member States. Therefore, the actions concerning

preparedness and mitigation of crisis situations cannot be defined only nationally, given

the potential impact on the level of security of supply of a neighboring Member State

and/or on the availability of measures to tackle scarcity situations.

Regarding the slow deployment of new services, low quality of services and increasing

mark-ups on retail markets, there is a clear need for EU action to ensure convergence of

national rules, which is a precondition for the development of cross-border activity in the

retail markets. Moreover, national regulations have in some instances led to distortions,

weakening the internal energy market. Such distortions can be observed in relation to the

protection of vulnerable and energy poor consumers which is a policy area characterised

by a great variety in types of public internvention across Member States, both in terms of

the definitions used and in terms of the levels of protection established. In that case EU

action is justified not only to ensure customer protection and enhanced transparency but

also to improve the functioning of the internal market through a more cohesive approach

across all markets.

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3.3.

Added-value of action at EU-level

The initiative aims at amending existing EU legislation and at creating new frameworks

for cross-border cooperation, which can legally and practically only be achieved at the

European level.

National policy interventions in the electricity sector have direct impact on neighbouring

Member States. This even more than in the past as the increasing cross-border trade, the

spread of decentralised generation and more enhanced consumer participation increases

spill-over effects. No state can effectively act alone and the externalities of unilateral action

have become more important.

To illustrate, uncoordinated national policies for distribution tariffs may distort the internal

market for distributed resources such as distributed generation or storage, as such resources

will increasingly participate in energy markets and provide ancillary services to the system,

including across borders. Furthermore, the lack of appropriate incentives for DSOs may

slow down the integration of RES E, and the uptake of innovative technologies and energy

services. EU action therefore has significant added value by ensuring a coherent approach

in all Member States.

It is true that certain Member States collaborate on a voluntarily basis in order to address

certain of the identified problems (e.g. Pentalateral Energy Forum

–PLEF-,

CEEE).

However, these fora are characterised by different levels of ambition and effectiveness and

are held-back by the fact that no means exist to enforce agreements on market design

related arrangements. Moreover, even if one would presume that they would be fully

effective in these regards, they geographically cover only part of the EU electricity market.

It should be added that clear synergies exist between the present initiative and other EU

policy objectives, notably the EU's climate policies and other policy objectives in the

energy field. Indeed, a well-functioning market is the base upon which the ETS can most

efficiently deliver its goals and will permit a cost effective integration of RES E in the EU's

electricity markets.

Consequently, the objectives of this initiative cannot be achieved only by Member States

themselves and this is where action at EU-level provides an added value.

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4.1.

BJECTIVES

Objectives and sub-objectives of the present initiative

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4.2.

Consistency of objectives with other EU policies

The consistency of the present initiative with various parallel initiatives in the energy

policy area was already explored in section 1.2.

The

ETS

constitutes a cornerstone of the European Union's policy to combat climate

change and its key tool for reducing industrial and electricity sector greenhouse gas

emissions cost-effectively. To achieve the at least 40% greenhouse gas emission reduction

target, the sectors covered by the ETS, which includes electricity generation, have to

reduce their emissions by 43% compared to 2005. The ETS interacts with the electricity

markets as it places a price on emissions of CO2, which is proportional to the emissions'

intensity of electricity production. This can be taken into account for both operational

decisions as well as for investment decisions, in which price expectations for the future

will also play a larger role due to the long-term nature of investments in the electricity

sector. (By contrast, decommissioning decisions may be primarily driven by short-term

considerations relating primarily to operational costs and revenues). The ETS thus

functions by affecting production and investment decision of electricity market actors

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It follows that an ETS can only function if its is complemented by an efficient electricity

market is. The objectives of the ETS and the present proposals are hence complementary

to one another and mutually reinforcing.

The

Effort Sharing Decision

establishes binding annual greenhouse gas emissions for

Member States for the period 2013-2020 in sectors not covered by the ETS and forms part

of the climate and energy package. As part of the 2030 climate and energy framework, a

similar binding emission reduction framework is proposed for the period 2021-2030.

Reducing greenhouse gas emissions by 30% in effort sharing sectors below 2005 levels

can have an indirect impact on the projection for the demand of electricity in 2030 and this

has been taken into account in the Impact Assessment by using the EUCO27 scenario in

the baseline against which the impacts of the present initiative is being assessed.

The

Communication on the decarbonisation of transport in 2030

aims at setting out a

strategy covering several legislative and non-regulatory initiatives covering the transport

sector which will be subsequently proposed to contribute to meeting the agreed 2030

greenhouse gas reduction targets. The decarbonisation of transport in 2030 has an impact

on the projection for the demand of electricity in 2030, primarily via the electrification of

transport, and this has been taken into account in the Impact Assessment by using the

EUCO27 scenario in the baseline against which the impacts of the present initiative is

being assessed. The efficient integration of electric vehicles into the electricity system

requires incentivising their charging to take place at times of low electricity demand and/or

134

The existing imbalance between the supply and demand for ETS allowances has limited the impact of

the carbon price in recent years. However, the agreement in 2014 to postpone the auctioning of 900

million allowances, and the decision in 2015 to introduce a Market Stability Reserve from 2019 onwards,

as well as the proposal to revise the EU ETS, including a higher annual reduction to the number of

allowances in the ETS from 2021 onwards, will gradually address the surplus of allowances. With the

introduction of the auctioning of allowances as the default method of allocation for installations in the

power sector from 2013 onwards and a single EU wide limit or cap on the overall number of allowances

in the system, the EU ETS already provides a largely harmonised incentive for decarbonisation at EU

level.

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high supply. The present initiative aims at enabling and rewarding consumers to manage

their consumption, including when charging their electric vehicles, actively via demand

response thus enabling smart charging. In essence, electric vehicles will thus become part

of the supply of flexibility to the electricity system.

EU's competition instruments and, in particular, the EU state aid rules are applicable to the

energy sector. They have been clarified in the

Guidelines on State aid for environmental

protection and energy 2014-2020

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. These EEAG aim at supporting Member States in

reaching their 2020 targets while addressing the market distortions that may result from

subsidies granted to RES. To this end, the EEAG promote a gradual move to market-based

support for RES E. They also include provisions on aid to energy infrastructure and rules

on aid to secure adequate electricity capacity, allowing Member States to introduce CMs

when there is a real risk of insufficient electricity generation capacity. The objectives and

the rules of the EEAG are set to avoid undue competition distortions from national support

provided in the energy sector. The proposed initiative to strenghten efficient, integrated

and functioning electricity markets is complementary to this framework.

The existing EEAG already go a considerable way in guiding CMs. The present initiaitve

intends to complement this framework. For instance:

The EEAG require that state intervention in support of resource adequacy must be

necessary. The MDI impact assessment

136

thus explores options for creating a

robust framework for assessing the EU's adequacy situation which could give a

good sense how much intermittent renewables can contribute to security of supply

or to what extent Member States can rely on supplies from their neighbours. Today,

Member States introduce capacity mechanisms based on national reports which

assess these factors very differently and underestimate the contribution of RES E

or foreign supplies to a Member States' security of supply. Therefore a genuine and

high quality assessment which will help assessing real needs and question

unfounded national claims.

The EEAG already require that national capacity markets are open to foreign

resources. However, organising effective foreign participation in national

mechanism requires active contributions of several parties. The MDI impact

assessment

137

explores options for defining clear roles and responsibilities to

capacity providers, transmission system operators and regulators so that foreign

participation becomes effective and that investment incentives are not distorted

across the borders.

The proposed changes on the new performance based remuneration framework for DSOs

would also support the

Digital Single Market Strategy

in the sense that those would

provide further incentives to enable cross sector synergies in electronic communication

infrastructure deployment allowing win win solutions for the cost efficient and timely

smartening of grids and high speed connectivity for EU citizens, also decreasing the digital

divide and providing the backbone for digital products and services which have the

potential to support all aspects of the lives of EU citizens, and drive Europe's economic

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136

137

http://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A52014XC0628(01)

See the preferred option in problem area II

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recovery. The proposed measures would complement from the energy regulatory side the

measures already introduced with Directive

2014/61/EU

which aims at reducing the cost

of high speed broadband infrastructure deployment partly via cross sector synergies.

The proposed measures do in general have no interaction with the fundamental rights laid

down in the

Charter of Fundamental Rights,

with the exception of the processing of

personal data and improvement of consumer protection. These elements are discussed in

more detail in section 6.4.6, Annex 7.1 and Annex 7.3.

The New Skills Agenda for Europe

focuses on skills as an elevator to people's

employability and prosperity, in line with the objective of a "social triple-A" for Europe.

It will promote life-long investment in people, from vocational training and higher

education through to digital and high-tech expertise and the life skills needed for citizens'

active engagement in changing workplaces and societies. The energy transition will bring

significant shifts in employment and skill sets required for employees active in the energy

sector as traditional means of generation will be replaced by RES E. This transition is

however primarily driven by EE and RED II related measures as well as national choices

as to the generation mix. More relevant for the present initiative are the measures aiming

at inducing the development of the retail markets from electricity supply markets towards

including more service oriented product offerings facilitating the participation of

consumers in the electricity market.

As regards

consumer rights,

the Unfair Commercial Practices Directive is the overarching

piece of EU legislation regulating unfair commercial practices in business-to-consumer

transactions. It applies to all commercial practices that occur before (i.e. during advertising

or marketing), during and after a business-to-consumer transaction has taken place. Where

sector-specific EU law is in place and its provisions overlap with the provisions of the

UCPD, the corresponding provisions of the sector-specific EU rules prevail, so no

contradictions exist.

Research, Innovation and Competitiveness

being Energy Union's 5

dimension, cuts

across all its elements. The Strategic Energy Technology Plan implements the energy

union's fifth dimension, promotes research and innovation for low carbon technologies,

contributing to the transformation of the EU's energy system and creating jobs, growth and

global export opportunities in the fast-growing clean-technology sector. Technological

developments create opportunities for citizens to turn from being passive consumers of

electricity into prosumers that actively manage their consumption, storage and production

of electricity and participate in the market and allow for the increasing penetration of

distributed resources. A new Research, Innovation and competitiveness strategy,

encompassing energy, transport and industrial competitiveness aspects is expected to be

presented in the months to come. This strategy builds on the achievements of the SET Plan

and further addresses the R&I challenges particularly towards industrialisation of

innovative low carbon technologies.

The present initiative is fully coherent as it seeks to remove barriers for the participation

of consumers, for bringing new resources to the market and seeks to improve price

formation with a view to create the conditions for new business models to emerge and for

innovative products to be absorbed by the market.

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OLICY OPTIONS

A fully functioning European wide electricity market is the best means to ensure that

electricity can be delivered to consumers in the most cost-efficient way at any time. To

continue fulfilling that purpose, the electricity market needs to be able to adapt to the

significant increase of variable renewable electricity production, integrate new enabling

technologies such as smart grids, smart metering, smart-home, self-generation and storage

equipment, empower citizens to take ownership of the energy transition and assure security

of electricity supply at least costs. Market mechanisms may need to be complemented by

initiatives which help preventing and managing electricity crisis situations.

Any EU action aimed at strengthening the market should build on the gradual liberalisation

of the EU energy markets resulting from the three Energy Packages described earlier in

this document.

The following policy options have been considered to address the problems of today's

electricity market and to meet the broad energy policy objective of ensuring low carbon

electricity supply to European customers at least costs. In assessing all possible options to

achieve this broad objective, the following approach was taken:

Identification of the main areas where initiatives might be needed to achieve

the main objectives of a new electricity market design. These Problem Areas

are set out in Box 2 below: "Overview of Problem Areas".

To address each Problem Area a set of high level options was identified (set-

out in the following paragraphs). Each of these high level options groups

options for specific measures.

A bottom-up assessment was performed for each specific measure, comparing

a number of options in order to select the preferred approach. The assessments

of the specific measures can be found in the Annexes to the present impact

assessment.

To help the reader, a table matching the assumed measures for each high level option is

included at the end of each problem area with references to the Annexes.

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Box 2: Overview of Problem Areas

Problem Area I:

Market design not fit for taking up large amounts of variable,

decentralised electricity generation and allowing for new

technological developments

Problem Area II:

Problem Area III:

Uncertainty about sufficient future investments in generation

capacity and un-coordinated government interventions

Member States do not take sufficient account of what happens

across their borders when preparing for and managing electricity

crisis situations

Problem Area IV:

5.1.

The slow deployment of new services, low levels of service and

poor retail market performance

Options to address Problem Area I (Market design not fit for an increasing

share of variable decentralized generation and technological developments)

Overview of the policy options

With a significant part of the produced electricity coming from variable renewable sources

and distributed resources, new challenges will be arising in terms of security of supply and

electricity price volatility. The options examined here aim to address these challenges in

the most cost-effective way for the whole European electricity system. These system cost

savings will be passed on to consumers by way of lower network charges. They will also

make it easier for RES E assets to earn a higher fraction of its revenues through the market.

Two possible paths were identified: the path of enhancing current market rules in order to

increase the flexibility of the system, retaining to a certain extent the national operation of

the systems (with more or less coordination assumed depending on the related sub-options)

and the path of moving to a fully integrated approach.

Box 3: Overview of the Policy Options for Problem Area I

Each policy option consists of a package of measures which address the drivers of the

problem. In the following sub-sections, the high level policy options and the packages of

measures they contain are described. Details on the individual measures are included in

the Annexes. It is then explained if any of those options are to be discarded at this stage,

prior to assessment, or whether other options were considered but were discarded from the

outset. The section is closed by a table summarising all specific measures included in each

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option and references to the Annexes where each measure is described and asessed in more

detail.

The relevant Annexes addressing the policy options below in more detail are: 1.1 to 3.4.

Option 0: Baseline Scenario

–

Current Market Arrangements

Under this option no new legislation is adopted, but there is some effort to implement

existing legislation including via the adoption of so-called network codes or guidelines.

The network codes, provided for in Article 6 and the guidelines provided for in Article 18

of the Electricity Regulation specify technical rules on the operation of European electricty

markets

138

. They are, as such, only designed to amend non-essential elements of the

Electricity Regulation and can only be adopted in areas specifically mentioned in the above

mentioned Articles.

139

Under these limitiations, network codes/guidelines are not the suitable instrument to

achieve all objectives of this initiative. For instance, whereas the implementation of the

Guideline on Capacity Allocation and Congestion Management ('CACM Guideline') will

bring a certain degree of harmonisation of cross-border intraday markets, gate closure

times and products for the intraday, as well as a market clearing, there is no guarantee that

the local market will adapt to reflect the cross-border approach and practices (auctions /

continuous trading) and local intraday markets across Europe will continue to remain non-

harmonised. This means that the EU-wide intraday market coupling envisaged by the

CACM Guideline will not be able to reach its full potential.

The Balancing Guideline is expected to bring certain improvements to the balancing

market, namely the common merit order list for activation of balancing energy, the

standardisation of balancing products and the harmonisation of the pricing methodology

for balancing. Nonetheless, other important areas like balancing capacity procurement

rules, frequency, geographical scope and sizing will not be affected by this regulation.

Priority dispatch rules, must-run priorities and other technology specific rules related to

the scheduling and operation of the system do not change at all with the adoption of

network codes. The same applies for the possibility for demand and distributed resources

to access the markets, and to compete on a level playing field with thermal generation. The

baseline assumes that demand response exists only in countries where it currently has

access to the market, with only industrial consumers being able to participate.

Overall, this option assumes that the future situation will remain more or less the same as

today, except from some specific measures included in the network codes (as above). The

138

139

More detail as regards network codes and guidelines is provided in Annex VII.

CIGRE paper C5-202 (2016): "Market

coupling, facing a glorious past?"

by R.Hirvonen, A.Marien,

B.Den Ouden, K.Purchala, M.Supponen, describes the past and future challenges of implementing

market coupling.

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baseline does not consider explicitly any type of existing support schemes for power

generation plants, neither in the form of RES E subsidies nor in the form of CMs

140

Stakeholders' opinions

141

None of the respondents to the public consultation expressed

the opinion that there is no need for further upgrade of the current market arrangements.

142

Option 0+: Non-regulatory approach

Whilst systematically considered

143

, no such option could be identified

144

Stronger enforcement provides little scope for improving the level playing field among

resources. To the extent the lack of a level playing field is due to the variety of provisions

in national law, a clear and transparent EU framework is a prerequisite for any

improvement. If the lack of a level playing field is due to exemptions in the EU regulatory

framework, stronger enforcement of these would actually be counter productive. In this

regard, the Evaluation report indicates that the rules of the Third Energy Package appear

to be insufficient to cope with the challenges facing the European electricity system.

145

Moreover, voluntary cooperation has resulted in significant developments in the market

and a lot of benefits. However, it it unlikely to provide for appropriate levels of

harmonisation or certainty to the market and legislation is needed in this area to address

the issues in a consistent way.

The current EU regulatory framework contains very limited rules on balancing and

intraday markets in a manner that allow to strengthening these short-term markets. In

particular, the Third Package does not address regional sizing and procurement of

balancing reserves nor contain rules allowing achieving a larger degree of harmonisation

of intraday trading arrangements.

Given that the existence of Regional Security Coordinators ('RSCs') depends on the

implementation of the System Operation Guideline, RSCs may only be fully operational

140

141

142

143

144

145

More details on the baseline and the reasons for not considering existing support schemes can be found

in Annex IV.

Stakeholders' opinions are reflected through-out Section 5 (and occasionally Section 6) of the main text

of this impact assessment to provide insides into their views as to the various options considered.

Stakeholder views are moreover reflected in detail in Section 7 of of each of the Annexes 1.1 throught

to 7.6 to the present impact assessment.

Some stakeholders propose to preserve only particular rules of the current market arrangements, while

being supportive to other Commission proposals for upgrading of the electricity market. E.g., one

stakeholder is supportive to more aligned framework for balancing markets and European measures to

incentivise demand side flexibility and in the same time supports the priority dispatch and priority access

for renewables. Similarly, one stakeholder strongly supports measures to incentivise the demand side

response and strengthening the powers of ACER, but considers that power exchanges should not be

subject to governance rules as well as that redesigning of the balancing markets is the task of Member

States and not the EU.

For each measure the opportunities for stronger enforcement have also been assessed in the annexes

with measures associated with each option. References to the relevant annexes are provided in Sections

5.1.7, 5.2.9, 5.3.8 and 5.4.6

The Commission has conducted

–

and is still conducting

–

a systematic

ex-officio

compliance check of

national legislation with the Third Energy Package. While EU-Pilot or formal infringement procedures

are still ongoing, they will however not be able to fulfil the policy objectives of the proposed measures.

See Section 7.3.1., 7.34 and 7.3.4 of the Evaluation.

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around mid-2019. Hence, stronger enforcement is currently not a possible option. Any

progress beyond the framework in the System Operation Guideline and the application of

other network codes would depend on the voluntary initiatives of TSOs. However, these

voluntary initiatives would be limited due to constraints deriving from differing national

legal frameworks.

As to demand response, stronger enforcement of existing provisions in the electricity and

energy efficiency directives are unlikely to untap the potential of flexibility. This is because

the existing provisions give Member States a high degree of freedom that has proven not

to be specific enough to ensure a full removal of existing market barriers.

Evidence suggests that voluntary cooperation will not result in progress in this area, as

there has been to date already significant opportunity to effect the necessary changes

voluntarily.

In the case of DSOs the current EU regulatory framework does not provide a clear set of

rules when it comes to additional tools that DSOs can employ to improve their efficiency

in terms of costs and quality of service provided to system users. Moreover, the current

framework does not address the role of DSOs in activities which are expected to have a

key impact in the development of the market (e.g. data management).

Option 1: EU Regulatory action to enhance market flexibility

Electricity production from wind and sun is more variable and less predictable than

electricity production from conventional sources of energy. Due to this, there will be times

when renewables cover a very large share of electricity demand and times when they only

cover a minor share of it. The large scale integration of such variable electricity production

thus requires a more flexible electricity system, one which matches the variable production.

Options to deliver the desired flexibility may comprise:

a. Abolishing (i) those measures that enhance the inflexibility of the current system,

namely priority dispatch for certain technologies (e.g. RES E, CHP, indigenous

fuels) and "must-runs" of conventional generation, (Creating

a level playing field)

and (ii) barriers preventing demand response from participating in the energy and

reserve markets;

b. In addition to the measures under a), better integrating short-term markets,

harmonizing their gate closure times and bringing them closer to real-time, in order

to take advantage of the diversity of generation resources and demand across the

EU and to improve the estimation and signalling of actual flexibility needs

(Strengthening

the short-term markets);

c. In addition to the measures under a) and b),

pulling all flexible distributed

resources

concerning generation, demand and storage,

into the market

via proper

incentives and a market framework better adapted to them, based on active

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aggregators, roll-out of smart-metering and time-of-use supply tariffs linked to the

wholesale prices.

146

The sub-options described above reflect a different degree of ambition to change the

market, as well as the different views expressed among stakeholders on how strong the

proposed interventions should be. Sub-option 1(a) (level playing field) retains a more

national status of the markets, Sub-option 1(b) (strengthening short-term markets) moves

also to more regionally coordinated markets, while Sub-option 1(c) (demand

response/distributed resources) makes an additional step towards a more decentralised

electricity market and system.

European Parliament:

"…[I]n order to achieve

the climate and energy targets, the

energy system of the future will need more flexibility, which requires investment in all four

flexibility solutions

–

flexible production, network development, demand flexibility and

storage"[.]

147

European Economic and Social Committee:

"The goal of a low-carbon energy supply,

with a high proportion of adjustable renewable energy sources, can only be achieved in

the short to medium term if all market participants (including new ones) have at their

disposal enough options that afford flexibility, such as sufficient storage capacity, flexible,

consumer-friendly demand options and flexible power generation technologies (e.g.

cogeneration), as well as adequately upgraded and interconnected power distribution

infrastructure. Other conditions are that consumers must receive adequate, timely and

correct information, they must have the chance to develop their own marketing

opportunities and the necessary investments in technology and infrastructure should pay

off. None of this is currently the case"

148

Stakeholders' opinions:

In the public consultation on Market Design Initiative most

stakeholders supported full integration of renewable energy sources into the market e.g.

through full balancing obligation and phasing-out priority dispatch. Also, most

146

147

148

IEA "Re-powering

markets"

(2016) suggests:

… “dispatching” demand response as a generator

requires complex market rules. Demand response can only be assessed according to a baseline

consumption levels, which are difficult to define and can lead to hidden subsidies. Setting the right level

of remuneration for aggregators has proven to be complex. Instead, dynamic pricing should be

encouraged, using new measurement and automation technologies such as smart meters.

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, Recital C.

Opinion of the European Economic and Social Committee on the ´Communication

from the Commission

to the European Parliament, the Council, the European Economic and Social Committee and the

Committee of the Regions

–

Launching the public consultation process on a new energy market

design´(COM

(2015) 340 final) (2016/C 082/03), OJ C 82, 3.3.2016, p. 13-21, § 1.4.

http://eur-lex.europa.eu/legal-

content/EN/TXT/?uri=uriserv:OJ.C_.2016.082.01.0013.01.ENG&toc=OJ:C:2016:082:TOC

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stakeholders agree with the need to speed up the development of integrated short-term,

balancing and intraday, markets.

5.1.4.1.Sub-option 1(a): Level playing field amongst participants and resources

The first group of measures aims at removing market distortions resulting from manifold

different regulatory rules for generation from different sources. Creating a level playing

field among all generation modes and restoring the economic merit order curve is an

important prerequisite for a well-functioning electricity market with prices that reflect

properly actual demand and supply conditions. For this reason the measures described here

are an integral part of all sub-options under Option 1.

The measures considered under this option would mainly target the removal of existing

market distortions and create a level playing field among technologies and resources. This

could involve abolishing rules that artificially limit or favour the access of certain

technologies to the electricity market (such as so-called "must-run" provisions, rules on

priority dispatch and access and any other rules discriminating between resources

149

Industrial consumers would become active in the wholesale markets, both for energy and

reserves, in all Member States. All market participants would become balance responsible,

bearing financial responsibility for the imbalances caused and thus being incentivized to

reduce the risk of such imbalances. Dispatch and redispatch decisions would be based on

using the most efficient resources available, curtailment should be a measure of last resort

which is limited to situations in which no market-based resources are available (including

storage and demand response), and only subject to transparent rules.

Therefore, all resources would be remunerated in the market on equal terms. This would

not mean that all resources earn the same revenues, but that different resources face the

same prices for equal services. In most cases the TSO should follow the merit order,

allowing the market to define the dispatch of available resources, using the inherent

flexibility of resources to the maximum potential (e.g. by significantly reducing must-run

generation, creating incentives for the use of heat storage combined with CHP and the use

of biomass generation in periods of peak demand rather than as baseload, and using

demand response or storage where it is more efficient than generation). Where resources

are used on the basis of merit order (thus on the basis of the marginal cost for using a

particular resource at a given point in time)

150

, supply costs are reduced.

Imposing additional obligations increases the risk and hence the financing costs of some

technologies such as RES E. Part of this risk will be hedged through the more liquid

intraday and balancing markets resulting from the full implementation of the Network

Codes, in combination with the increased participation of resources due to the removal of

must-run and priority dispatch provisions. These obligations should be also accompanied

by measures that reduce their costs of compliance, such as the introduction of transparent

149

150

See in detail Annex 1(1)

–

Where marginal costs are based on the use of fuel, this can also result in lower CO2 emissions. However,

inflexible conventional plants will include the cost of starting or stopping power generation into their

market bids, thus possibly deciding to operate at a price below their fuel costs. In this case, the cost of

not operating the power plant exceeds the cost of operating it.

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curtailment rules. Additionally, exemptions from certain regulatory provisions may, in

some cases, be required. This can e.g. be the case for emerging technologies, which,

although they are not yet competitive, need to reach a minimum number of running hours

to gather experience. For certain generators, particularly small RES E (e.g. rooftop solar),

exemptions can be furthermore justified to avoid excessive administrative efforts related

to being active on the wholesale markets.

Stakeholders' opinions:

151

Most stakeholders support the full integration of all

technologies into the market, e.g. through full balancing obligations for all technologies,

phasing-out priority dispatch and removing subsidies during negative price periods.

Also stakeholders from the renewable sector often recognize the need to review the priority

dispatch framework. However, in their view, a phase-out of priority dispatch for renewable

energy sources should only be considered if (i) this is done also for all other forms of power

generation, (ii) liquid intraday markets with gate closure near real-time exist, (iii) balancing

markets allow for a competitive participation of wind producers; (short gate closure time,

separate up/downwards products, etc.), and (iv) curtailment rules and congestion

management are transparent to all market parties.

Cogeneration sector stakeholder seek for a least parity between CHP and RES E.

European Parliament:

"European

Parliament […]stresses that a new market design for

electricity as part of an increasingly decentralised energy system must be based on market

principles, which would stimulate investment, ensure that SMEs have access to the energy

market and unlock a sustainable and efficient electricity supply through a stable,

integrated and smart energy system[...]"

152

"European

Parliament […] [i]nsists that, with the increasing technical maturity and

widespread use of renewable energy sources, subsidy rules must be geared to market

conditions, such as feed-in premiums, in order to keep costs for energy consumers within

reasonable bounds[.]"

153

151

152

153

More detailed depictions of stakeholder's opinions are provided in Sections 7 of each annexe describing

the more detailed measures i.e. annexes 1.1 to 7.6 of the Annexes to the Impact Assessment.

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, §5.

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, §52.

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"European Parliament […] recalls the existing provisions of the Renewable Energy

Directive, which grant priority access and dispatch for renewables; suggests that these

provisions should be evaluated and revised once a redesigned electricity market has been

implemented which ensures a more level playing field and takes greater account of the

characteristics of renewable energy generation[.]"

154

Council:

"[…] Renewable energy sources should become an integrated part of the

electricity market by ensuring a level playing field for all market participants and enabling

renewable energy producers to be fully involved in the market, including in balancing their

portfolio and reacting to market price signals."

155

European Electricity Regulatory Forum, Florence:

"The Forum stresses that the

renewables framework for the post 2020 period should be based on an enhanced market

design, fit for the full integration of renewables, a strong carbon price signal through a

strengthened ETS, and specific support for renewables, that when and if needed, should

be market based and minimise market distortions. To this end, the Forum encourages the

Commission to develop common rules on support schemes as a part of the revision of the

Renewables Directive that facilitate a market based and more regionalised approach to

renewables."

156

5.1.4.2.Sub-option 1(b): Strengthening short-term markets

Sub-option 1(b) (strengthening short-term markets) includes the measures described under

1(a) (level playing field ) and a set of additional measures, further enhancing the measures

foreseen in the CACM and EB Guidelines (and are assumed as part of the baseline). As

explained above, variable RES E have fundamentally different generation characteristics

compared to traditional fuel based generation (e.g. variability, only short-term

predictability). An important additional step would therefore be to have more liquid and

better integrated short-term markets, going beyond what the implementation of technical

implementing legislation ("Network Codes") will achieve, setting the ground for

renewable energy producers to better access energy wholesale markets and to compete on

an equal footing with conventional energy producers. Short-term markets will also allow

Member States to share their resources across all "time frames" (forward trading, day-

ahead, intraday and balancing), taking advantage of the fact that peaks and weather

conditions across Europe do not occur at the same time.

Also, the closer to real time electricity is traded (supply and demand matched), the less the

need for costly TSO interventions to maintain a stable electricity system. Although TSOs

would have less time to react to deviations and unexpected events and forecast errors, the

liquid, better interconnected balancing markets, together with the regional procurement of

154

155

156

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, §54.

See

Messages from the Presidency on electricity market design and regional cooperation

(2016), Note

to the Permanent Representatives Committee/Council, Annex, paragraph 4.

http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf

31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §6.

https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf

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balancing reserves, would be expected to provide them with adequate and more efficient

resources in order to manage the grid and facilitate RES E integration.

In order to support these actions and mainly in order to be able to optimally exploit

interconnections along all "time frames", a number of measures are assumed to be taken:

gate closure times could be brought closer to real-time to provide maximum opportunity

for the market to balance its positions before it becomes a TSO responsibility and some

harmonisation would be brought to trading products for intraday markets in order to further

incentivize cross-border participation of market parties. The sizing of balancing reserves

and their procurement would be harmonized in larger balancing zones, allowing to reap

benefits of cross-border exchange of reserves and use of the most efficient reserves

available.

At the same time, the integration of national electricity systems, from the market and

operational perspectives, requires the enhancement of cooperation between TSOs. The

creation of a number of regional operational centres ('ROCs'), with an enlarged scope of

functions, an optimised geographical coverage compared to the existing regional security

coordinators and with an enhanced advisory role for all functions, including the possibility

to entrust them decision-making responsibilities for a number of relevant issues, could

contribute to better TSO cooperation at regional level.

157

Measures on enhanced

cooperation between TSOs could be accompanied by an increased level of cooperation

between regulators and governments.

158

All these options would be expected to strongly incentivize participation in the intraday

and balancing markets, further increasing their liquidity, while at the same time minimizing

TSOs' interventions.

Stakeholders' opinions:

Most stakeholders agree with the need to speed up the

development of integrated short-term (intraday and balancing) markets. A significant

number of stakeholders argue that there is a need for legal measures, in addition to the

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

balancing markets. Many stakeholders note that the regulatory framework should enable

RES E to participate in the market, e.g. by adapting gate closure times and aligning product

specifications.

European Parliament:

"European Parliament […][c]alls for the completion of the

integration of internal market and balancing and reserve services by fostering liquidity

and cross-border trading in all market timeframes; urges that efforts to achieve the

ambitious goals of the Target Model regarding intraday and balancing markets be speeded

157

158

For more details concerning policy measures for the establishment of ROCs, refer to Option 1 in Annex

2.3.

For more details concerning policy measures for the enhanced cooperation between regulators and

governments, refer to Option 1 in Annex 3.4.

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up, starting with the harmonisation of gate closure times and the balancing of energy

products[.]"

159

Council:

"An integrated European electricity market requires well-functioning short term

markets and an increased level of cross-border cooperation with regard to day-ahead,

intraday and balancing markets, without hampering the proper functioning of the

networks, as this will enhance security of supply at lower costs for the system and

consumers"

160

European Economic and Social Committee:

"The EESC underlines the particular

importance of intraday trade as a way of ensuring meaningful trade involving

VREs[variable renewable energies]"

161

European Electricity Regulatory Forum, Florence:

"The Forum supports the view that

further steps are needed beyond agreement and implementation of the Balancing

Guideline. In particular, further efforts should be made on coordinated sizing and cross--

‐

border sharing of reserve capacity. It invites the Commission to develop proposals as part

of the energy market design initiative, if the impact assessment demonstrates a positive

cost--

‐

benefit, which also ensures the effectiveness of intraday markets"

162

"The Forum Acknowledges the significant progress being made on the integration of cross

- border markets in the intraday and day--

‐

ahead timeframes, and considers that market

coupling should be the foundation for such markets. Nevertheless, the Forum recognises

that barriers may continue to exist to the creation of prices that reflect scarcity and invites

the Commission, as part of the energy market design initiative, to identify measures needed

to overcome such barriers"

163

"[T]he Forum invites the Commission to identify those aspects of national intraday

markets that would benefit from consistency across the EU, for example on within--

‐

zone

gate closure time and products that should be offered to the market. It also requests for

action to increase transparency in the calculation of cross--

‐

zonal capacity, with a view to

maximising use of existing capacity and avoiding undue limitation and curtailment of

cross--

‐

border capacity for the purposes of solving internal congestions"

164

159

160

161

162

163

164

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 46.

See

Messages from the Presidency on electricity market design and regional cooperation

(2016), Note

to the Permanent Representatives Committee/Council, Annex, paragraph 6.

http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf

31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §3.5.

https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf

meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §3,

https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-

%20Florence%20Forum%20-%20Final.pdf

meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §

https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-

%20Florence%20Forum%20-%20Final.pdf

meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §

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"The Forum stresses that, whilst scarcity pricing in short--

‐

term markets is critical to

creating the right signals, the importance of hedging opportunities and forward/future

markets in creating more certainty for investors and alleviating risks for consumers must

not be overlooked. Further, it considers that the Commission must recognise the risks of

State Interventions undermining scarcity pricing signals"

165

5.1.4.3.Sub-option 1(c): Pulling demand response and distributed resources into the

market

166

Sub-option 1(c) (demand response/distributed resources) includes the measures described

under 1(a) (level playing field) and 1(b) (strengthening short-term markets), as well as a

set of additional measures, aiming at using the full potential of demand response, storage

and distributed generation. The previous options would introduce a level playing field for

all resources and improve the short-term market framework. They would, however, not

include any measure intending to pull all the additional available potential from distributed

resources into the market. Such resources are most importantly demand response,

distributed RES E and storage.

167

A significant part of the current costs for the electricity system stem from the new

challenges of variable generation for the system, notably the increased need to deal with

supply peaks and unexpected generation gaps. As the elecricity grid requires a constant

balance of demand and supply, grid operators need to take costly measures. Demand

response, distributed RES E and storage can play an important role to reduce these costs.

The measures considered under Option 1(c) bring demand response from all consumer

groups, including residential and commercial consumers

168

, and storage as additional

https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-

%20Florence%20Forum%20-%20Final.pdf

165

meeting of the European Electricity Regulatory Forum, Florence, 3-4 March 2015, Conclusions, §

https://ec.europa.eu/energy/sites/ener/files/documents/Conclusions%20-

%20Florence%20Forum%20-%20Final.pdf

166

This set of measures could have been introduced alternatively as Sub-Option 1(b), thus before the

improved short-term market functioning related measures, as a further enhancement to the rules creating

a level-playing field for all technologies. However, the benefits from the participation of these additional

resources in the market are enhanced via their participation in the balancing markets and the procurement

of reserves. Introducing this set of measures in the context of improved short-term market functioning

therefore allows the full benefits of them to be realised. See also footnote 294, Section 6.1.7.

167

RSCAS Research report (2015), "Conceptual

framework for the evolution of the operation and regulation

of electricity transmission systems towards a decarbonised and increasingly integrated electricity

system in the EU"

by J.-M.Glachant, J.Vasconcelos, V.Rious, states:

"EU has a target model for the EU

internal market and for the transmission system operation.

It has none for EU “RES pocket markets”

and for the distribution system operation".

168

As big industrial consumers are assumed to already participate directly in the market in Option 1(a)

(level playing field), this sub-option extends the participation of demand response to all consumer groups

(including residential and commercial consumers) who, because of their small individual loads, can enter

the market only through third party service providers, e.g. aggregators. At the same time though the

described measures are expected to significantly increase the DR potential for all categories, including

industrial consumers who do not wish to engage directly in the market and by allowing DSOs to procure

additional flexibility services.

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resources into the market, especially to the balancing market. This would even further

increase the flexibility of the electricity system and the resources for the TSOs to manage

it. At the same time it should lead to much more efficient operation of the whole energy

system.

This option would include more in particular:

Enabling consumers to directly react to price signals on electricity markets both in terms

of consumption and production, by giving consumers access to a fit-for-purpose smart

metering system, enabling suppliers to measure and settle electricity consumption close to

real time, as well as requiring suppliers to offer consumers electricity supply contracts with

prices linked dynamically to the wholesale spot market that will enable consumers to

directly react to price signals on electricity markets both in terms of consumption and

production.

Box 4: Benefits and risks of dynamic electricity pricing contracts

The preferred policy option is to provide all consumers the possibility to voluntarily choose

to sign up to a dynamic electricity price contract and to participate in demand response

schemes. All consumers will however have the right to keep their traditional electricity

price contract.

Dynamic electricity prices reflect

–

to varying degrees

–

marginal generation costs and

thus incentivise consumers to change their consumption in response to price signals. This

reduces peak demand and hence reduces the price of electricity at the wholesale market.

Those price reductions can be passed on to all consumers. At the same time, suppliers can

pass parts of their wholesale price risk on to those consumers who are on dynamic

contracts. Both aspects can explain why, according to the ACER/CEER monitoring report

2015, on average existing dynamic electricity price offers in Europe are 5% cheaper than

the average offer.

While consumers on dynamic price contracts can realise additional benefits from shifting

their consumption to times of low wholesale prices they also risk facing higher bills in case

they are consuming during peak hours. Such a risk is deemed to be acceptable if taking

this risk is the free choice of the consumer and if he is informed accurately about the

potential risks and benefits of dynamic prices before signing up to such a contract.

Aggregators are companies that act as intermediaries between the electricity system and

distinct agents in the electricity system, mainly small, individual resoures but that exist in

large numbers, and which are usually located in the distribution grid (consumers,

prosumers and producers).

169

Developing a comprehensive framework for demand, supply

and storage aggregators would facilitate their participation in the market and thus increase

flexibility in the energy system and complement large generation connected to the

169

EPRG working paper 1616 (2016),

"Which Smart Electricity Services Contracts Will Consumers

Accept?"

by L-L.Richter and M.G.Pollit states:

"By combining appropriate participation payments with

sharing of bill savings, service providers could attract the number of customers required to provide the

optimal level of demand response."

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transmission grid.

170

Larger storage facilities can be connected at distribution or

transmission level, and provide services on a peer basis with other providers.

R&D results:

The economic and technical viability of the concept of aggregation has already been

demonstrated in European projects like: Integral, IDE4L, Grid4eu, INTrEPID, INCREASE, DREAM. The

ability of small-scale RES to participate in the balancing market or contribute to solving grid congestion has

been demonstrated in European projects like: V-Sync and MetaPV.

In order to pull all available resources into the market, it is also important to enable and

incentivise DSOs, without compromising their neutrality as system operators, to manage

their networks in a flexible and cost-efficient way, This could be achieved by establishing

a performance-based remuneration framework for DSOs that would reward them for

innovating and improving overall efficiency of their networks through synergies with other

actors, making full use of energy storage, and/or investing in electronic communication

infrastructure. This would be enabled by the deployment of intelligent infrastructure and

by ensuring coherence with other Commission policies in the field of the Digital Single

Market and the General Data Protection Regulation

171

Measures under this option would also include defining the conditions under which DSOs

may acquire flexibility services without distorting the markets for such services, and

putting in place distribution tariff structures that send accurate price signals to all grid

users. Such initiative would be aimed at facilitating the integration of the increasing

amounts of variable RES E generation that will be connected directly to distribution grids

in the future.

Stakeholders' opinions:

Many stakeholders identified a lack of smart metering systems

offering the full functionalities to consumers and dynamic electricity pricing (more flexible

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

obstacles to kick-starting

demand side response,

along with the distortion of retail prices

by taxes/levies and price regulation.

Other factors include market rules that discriminate against consumers or aggregators who

want to offer demand response, network tariff structures that are not adapted to demand

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

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

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

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

framework for demand reponse (e.g. operation and settlement). A number of respondents

also underline the need to support the development of aggregators by removing obstacles

for their activity to allow full market participation of renewables. Many submissions

170

171

CIGRE paper C5-304 (2016), B. Guédou and A. Rigard-Cerison, RTE France says:

"One

can learn,

from French experience, that building an appropriate market for DSR requires to benefit from a strong

political commitment (intense involvement from the administration, the regulatory authorities and the

TSO) and to solve some key issues, requiring innovative answers both on the regulatory side and the

technical side (e.g. role of aggregators / independent DR operators, adaptation of the regulatory

framework to enable competition, role of TSOs and DSOs, data collection and privacy…)".

This would entail also close cooperation with TSOs, as elaborated for example in CIGRE paper C2-111:

"Increased

cooperation between TSO and DSOs as precondition for further developments in ancillary

services due to increased distributed (renewable) generation",

M.Kranhold, 50Hertz Transmission

GmbH (2016)

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highlight the crucial role of scarcity pricing for kick-starting demand response at industrial

and household level.

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

market facilitation and data hub management as possible functions for DSOs. Some

stakeholders point at a potential conflict of interests for DSOs who are able to actively

menage their networks where these DSOs are also active in the supply business,

emphasizing that the neutrality of DSOs should be ensured. A large number of the

stakeholders stressed the importance of data protection and privacy, and consumer's

ownership of data. Furthermore, a high number of respondents stressed the need of specific

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

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

stakeholders, while others stress that the concrete design should generally considered to be

subject to national regulation.

European Parliament:

"European Parliament […] considers that this framework should

promote and reward flexible storage solutions, demand-side response technologies,

flexible generation, increased interconnections and further market integration, which will

help to promote a growing share of renewable energy sources and integrate them into the

market[.]"

172

"European Parliament[…] recalls that the transition to scarcity pricing implies improved

mobilisation of demand response and storage, along with effective market monitoring and

controls to address the risk of market power abuse, in particular to protect consumers;

believes that consumer engagement is one of the most important objectives in the pursuit

of energy efficiency, and that whether prices that reflect the actual scarcity of supply in

fact lead to adequate investment in electricity production capacity should be evaluated on

a regular basis[.]"

173

"European parliament […][c]onsiders that energy storage has numerous benefits, not

least enabling demand-side response, assisting in balancing the grid and providing a

means to store excess renewable power generation; calls for the revision of the existing

regulatory framework to promote the deployment of energy storage systems and other

flexibility options, which allow a larger share of intermittent renewable energy sources

(RES), whether centralised or distributed, with lower marginal costs to be fed into the

energy system; stresses the need to establish a separate asset category for electricity or

energy storage systems in the existing regulatory framework, given the dual nature

–

generation and demand

–

of energy storage systems[.]"

174

Council:

"The future electricity retail markets should ensure access to new market players

(such as

aggregators and ESCO’s) on an equal footing and facilitate introduction of

innovative technologies, products and services in order to stimulate competition and

growth. It is important to promote further reduction of energy consumption in the EU and

172

173

174

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 5.

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 10.

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 28.

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inform and empower consumers, households as well as industries, as regards possibilities

to participate actively in the energy market and respond to price signals, control their

energy consumption and participate in cost-effective demand response solutions. In this

regard, cost efficient installation of smart meters and relevant data systems are essential.

Barriers that hamper the delivery of demand response services should be removed"

175

European Electricity Regulatory Forum, Florence:

"The Forum recognises that the

development of a holistic EU framework is key to unlocking the potential of demand

Response and to enabling it to provide flexibility to the system. It notes the large

convergence of views among stakeholders on how to approach the regulation of demand

response, including: the need to engage consumers; the need to remove existing barriers

to market access, including to third--

‐

party aggregators; the need to make available

dynamic market--

‐

based pricing; the importance of both implicit and explicit demand

response; and the cost--

‐

efficient installation of the required technology"

176

Option 2: Fully Integrated EU market

This option considers measures that would aim to deliver a single truly pan-European

electricity market via relatively far-reaching changes to the current regulatory framework,

aiming at the full integration of electricity markets and system operation, and at mobilising

all available flexibility of the EU-wide system.

For a fully integrated EU market, one would need to significantly change the current

regulatory approach of the internal market. The current EU wholesale market design of the

Third Package provides for a coordination framework between grid operators and national

regulators and sets some rules for certain issues which are relevant for cross-border

exchange of electricity (e.g. coordinated electricity trading and grid operation measures).

However, under the Third Package, regulatory decisions are in principle left to Member

States, the 28 national regulators and the 42 European grid operators if not otherwise

provided in the Third Package.

Leaving scope for national decision-making on trading and system operation may lead to

inefficiencies due to unsufficiently coordinated and contradicting decisions. A more

centralised regulatory approach could therefore be considered to achieve more integrated

EU markets.

Under this option, procurement of balancing reserves would be performed directly at EU

level, instead of a regional level. For system operation, this could mean shifting from a

system of separate national TSOs to an integrated system managed by a single European

Independent System Operator ("EU

ISO").

System operation (including real time

175

176

See

Messages from the Presidency on electricity market design and regional cooperation

(2016), Note

to the Permanent Representatives Committee/Council, Annex, paragraph 8.

http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf

31st EU Electricity Regulatory Forum, 13-14 June 2016, Draft Conclusions, §1.

https://ec.europa.eu/energy/sites/ener/files/documents/Draft%20conclusions%20FINAL14June.pdf

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operation) and planning functions could be performed by this EU ISO, which would be

competent for the whole Union.

177

In order to optimally deal with congestion between countries and to let the market transmit

the right price signals, this option would entail to move from zonal to nodal pricing

178

. The

values of available transmission capacities would be calculated centrally and could be

closely coordinated across market regions, thereby taking advantage of all information

available among the TSOs in different grid arreas and also taking into account the

interrelationship between different interconnectors. As a result, it is assumed that more

interconnector capacity is made available to the market(s) and resources are expected to

be utilized more efficiently across regions.

In general, Option 2 would not only entail coordination, approximation and harmonisation

of selected topics relevant for national market and grid operation rules, but also to apply

the same rules and specifications for products and services across the EU, including

centrally fixed rules for electricity trading, for common EU-wide procurement of reserves

and central system planning and operation. Such centralised integrated market would also

provide for mandatory smart meter roll-out and a full EU framework for incentive-based

demand response to better exploited demand reponse. Under Option 2, also distribution

tariff structures would be harmonised, stronger unbundling rules for DSOs be created as

well as harmonised renumeration methodologies that ensure DSOs' incentives to invest in

innovative and efficient technologies.

ACER would need to gain significant competences and take over most NRAs'

responsibilities directly or indirectly related to cross-border and EU-level issues. ENTSO-

E would need to be formally separated from its members' interest and take up more

competences.

179

Such measures, intended to optimise the cost-efficiency and flexibility of the European

electricity system, would involve going significantly beyond the measures described under

Option 1, requiring also particularly far-reaching institutional changes.

Stakeholders' opinions:

No stakeholder expressed support for the possibility of designing

measures leading to the creation of a fully integrated EU electricity market. For example,

as regards the establishment of an EU Independent System Operator, a number of

stakeholders emphasized that while it is necessary to reinforce TSO coordination, this

should take place through a step-wise regional integration of system operation

177

178

179

For more details on policy option concerning the establishment of an EU ISO, please refer to Option 3

in annex 2.3.

Nodal Pricing is a method of determining prices in which market clearing prices are calculated for a

number of locations on the transmission grid called nodes. Each node represents the physical location

on the transmission system where energy is injected by generators or withdrawn by loads. The price at

each node represents the locational value of energy, which includes the cost of the energy and the cost

of delivering it, i.e. losses and congestion

For more details on ACER's and ENTSO-E's enhanced competences in a fully integrated EU market,

refer to Option 2 in Annex 3.4.

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For Option 1 and 2: Institutional framework as an enabler

Each set of proposed measures under Options 1(a) to 1(c), as well as (2), will necessitate

a different degree of reinforcement of the institutional framework of the EU's electricity

markets. Since the harmonisation of regulatory aspects (e.g. gate closure times, rules for

the curtailment of cross-border capacities, bidding zones etc.) often has different economic

impacts in different Member States, an institutional framework is needed to find the

necessary compromises. Experience has shown that it will generally be more difficult to

achieve ambitious harmonisation goals with an institutional framework that grants veto

rights to each national regulator or TSO (i.e. in cooperative institutions applying

unanimous decision-making). An alignment or harmonisation of aspects concerning the

electricity market design is therefore more likely to happen with an institutional framework

which applies (qualified) majority decision-making or which replaces the decision-making

by 28 different regulators/TSOs by a central body which takes the decision in the European

interest

180

A robust institutional framework constitutes a pre-requisite for the integration and proper

functioning of the EU market. For this reason, it is necessary that the institutional

framework reflects the realities of the electricity system and the resulting need for regional

cooperation as well as that it addresses existing and anticipated regulatory gaps in the

energy market.

In order to effectively establish a level playing field between all potential market

participants and resources (Sub-option 1(a) (level playing field)), it is necessary to

reinforce ACER's competences at EU level in order to address regulatory gaps already

identified in the implementation of the Third Package and ensure the oversight over

entities and functions with relevance at EU level.

When markets and market regulation achieve a regional dimension (Sub-option

1(b)(strenghening short-term markets)), the institutional framework needs to be adapted

accordingly, if it is to remain efficient and effective. Currently, the EU institutional

framework is based on the complementarity of regulation at national and EU law. Hence,

the regulatory framework would then need to be reinforced to address the need for

additional regional cooperation. In this regard, ACER's competences and NRAs'

cooperation at regional level should be enhanced, corresponding to increased regional

TSO cooperation and to the implementation of network codes and guidelines at regional

level. The mandate of ENTSO-E could be clarified to strengthen its obligation to take a

European / internal market perspective and to emphasize its transparency and monitoring

obligations. The role of power exchanges in cross-border electricity issues should be

acknowledged and they should be involved in all regulatory procedures relevant for them.

Finally the use of congestion income should be altered, increasing the proportion spent on

investments that maintain or increase interconnection, thus creating the basis for the

regional co-operation through a strongly interconnected system

181

180

181

The transfer of decisions on cross-border cost allocation to the Director of ACER is one example of

decision-making by an independent supranational body. See Article 12(6) of Regulation 347/2013

(TEN-E Regulation).

As is in fact discussed under Option 1 of Problem Area II

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In order to facilitate distributed resources to participate in the market (Sub-option 1(c)

demand response/distributed resources), DSOs must become more active at European level

and have increased responsibilities and tasks, similar to those of the TSOs. Their role

should be formalised into a European organisation with an efficient working structure to

render their participation effective and independent. In particular, whereas DSOs are

currently represented at EU level by four associations (Eurelectric, Geode, CEDEC and

EDSO), none of these has the necessary characteristics to represent the sector by engaging

in tasks that might include the codification of formal EU market rules: Either they or their

members are listed as lobbyists on the EU Transparency Register, none of their

memberships is representative of all EU DSOs, and none has the explicit mandate to

represent EU DSOs in such activities.

Finally, Option 2 requires significantly restructuring the institutional framework, going

beyond addressing the regulatory gaps and moving towards more centralised institutional

structures with additional power and responsibilities, particularly for ACER and ENTSO-

Stakeholders' opinions:

Opinions with regard to strengthening ACER’s

powers are

divided. There is clear support for increasing ACER's legal powers by many stakeholders.

However, the option to keep the

status quo

is also visibly present, notably in the

submissions from Member States and national energy regulators. While some stakeholders

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

others highlighted rather the need for appropriate financial and human resources for ACER

to fulfil its tasks.

With regard to ENTSO-E, stakeholders' positions are divided as to whether ENTSO-E

needs strengthening remain divided. Some stakeholders mention a possible conflict of

interest in ENTSO-E’s

role –

being at the same time an association called to represent the

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

commercial interests

–

and ask for measures to address this conflict. Some stakeholders

have suggested in this context that the process for developing network codes should be

revisited in order to provide a greater a balance of in interests.

Some submissions advocate for including DSOs and stakeholders in the network code

drafting process. While a majority of stakeholders support governance and regulatory

oversight of

power exchanges,

particularly as regards the market coupling operator

function, other stakeholders are sceptical whether additional rules are needed for power

exchanges given the existing rules in legislation on market coupling (in the CACM

Guideline).

European Parliament:

"European Parliament […][n]otes the importance of effective,

impartial and ongoing market monitoring of European energy markets as a key tool to

ensure a true internal energy market characterised by free competition, proper price

signals and supply security; underlines the importance of ACER in this connection, and

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looks forward to the Commission’s position on new and strengthened powers for ACER on

cross-border issues[.]"

182

"European Parliament […][s]tresses that in most cases renewables are fed in at

distribution system level, close to the level of consumption, and therefore calls for DSOs

to play a greater role as facilitators and to be more closely involved in the design of

European regulatory framework and in the relevant bodies when it comes to drawing up

guidelines on issues of concern to them, such as demand-side management, flexibility and

storage, and for closer cooperation between DSOs and TSOs at the European level[.]"

183

Summary of specific measures comprising each Option

The following table summarizes the specific measures comprising each package of

measures, as well the corresponding specific measure option considered under each high

level option

184

. The detailed presentation and assessment of each measure can be found in

the indicated Annex.

182

183

184

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 70.

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 63.

The preferred options for the specific measures set out in the annex are highlighted in the table in green.

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Table 6: Summary of Specific Measures investigated for Problem Area I

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Specific Measures

Option 0

Option 1(a)

Option 1(b)

Option 1(c)

Option 2

Baseline

Priority Access and

Dispatch

(Annex 1.1)

+ Balancing

Responsibility

(Annex 1.2)

+ RES providing non-

frequency ancillary

services

(Annex 1.3)

+ Reserves Sizing and

Procurement

(Annex 2.1)

+ Remove distortions

for liquid short-term

markets

(Annex 2.2)

+ TSO Co-operation

(Annex 2.3)

+ Demand Response

(Annex 3.1)

Maintain priority dispatch

for RES, indigenous fuels

and CHP

(Annex 1.1.4 Option 0)

Financial balancing

responsibility under EEAG

(Annex 1.2.4 Option 0)

Services continue to be

Principles for transparent, non-discriminatory market-based framework for

provided by large

the provision of these services

conventional generation

(Annex 1.3.4 Option 2)

(Annex 1.3.4 Option 0)

National sizing of balancing reserves, frequency of

Regional sizing and procurement of balancing

procurement as today (e.g. many products, not

reserves, daily procurement of upward/downward

necessarily separete upwards/downwards

products

products)

(Annex 2.1.4 Option 2)

(Annex 2.1.4 Option 0)

Selected harmonisation of national intraday markets

National non-harmonised intraday markets

of gate closure times and products, with gradual

implementation

(Annex 2.2.4 Option 0)

(Annex 2.2.4 Option 2)

Upgrade RSCs to Regional Operational Centres

Regional Security Coordinators (RSCs) to perform

(ROCs) centralising additional functions over

five tasks at regional level for national TSOs

relevant geographical areas

(Annex 2.3.4 Option 0)

Give consumers access to

enabling technologies that will

Smart meter rollout remains limited in geographical scope and

expose them to market price

functionalities, market barriers to aggregators persist, and the full

signals and a common European

potential of demand response and self-consumption remains untapped

framework defining roles and

(Annex 3.1.4 Option 0)

responsibilities of aggregators

(Annex 3.1.4 Option 2)

Option (a) +

Option 1(a), 1(b) +

Level playing

Strengthening

Demand response/distributed

field

short-term

resources

markets

Abolish priority dispatch and introduce clear curtailment rules to replace

priority access, with the exception of emerging technologies and small

CHP and RES E plants

(Annex 1.1.4 Options 2 and 3)

Balancing responsibility for all parties, with the exception of emerging

technologies and small CHP and RES E plants

( Annex 1.2.4 Option 2)

Fully integrated markets

Fully abolish priority dispatch and

access

(Annex 1.1.4 Option 1)

Full balancing responsibilities for all

parties

(Annex 1.2.4 Option 1)

EU market framework for such services

(Annex 1.3.4 Option 1)

European sizing and procurement of

balancing reserves, daily procurement of

upward/downward products

(Annex 2.1.4 Option 3)

Full harmonisation and coupling of

intraday markets

(Annex 2.2.4 Option 1)

Creation of Regional or EU Independent

System Operators

(Annex 2.3.4 Options 2 and 3)

Mandatory smart meter roll out and full

EU framework for incentive based

demand response

(Annex 3.1.4 Option 3)

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Specific Measures

Option 0

Option 1(a)

Option 1(b)

Option (a) +

Strengthening

short-term

markets

Option 1(c)

Option 1(a), 1(b) +

Demand response/distributed

resources

Specific requirements and

conditions for 'active' DSOs;

Clarification of DSO's role in

specific tasks; Enhanced DSO-

TSO cooperation (Annex 3.2.4

Option 1)

EU-wide principles on

remuneration schemes; NRAs

monitor the performance of

DSOs (Annex 3.3.4 Option 1)

EU wide principles to make

tariffs structures become more

transparent and more accurately

reflect the impact of each

system user on the grid,

especially during different times

of the day; NRAs to implement

more detailed requirements

(Annex 3.3.4 Option 1)

Option 2

Baseline

Level playing

field

Fully integrated markets

+ Ensuring that DSOs

become active and

remain neutral towards

other market actors

(Annex 3.2)

+ A performance-based

remuneration

framework for DSOs

(Annex 3.3)

Broad variety of national approaches to DSO roles and responsibilities

(Annex 3.2.4 Option 0)

EU framework for a specific set of DSO

tasks and stricter unbundling rules

(Annex 3.2.4 Option 2)

Broad variety of national approaches to DSO compensation

(Annex 3.3.4 Option 0)

Fully harmonize remuneration

methodologies (Annex 3.3.4 Option 2)

+ Distribution tariffs

that send accurate price

signals to grid users

(Annex 3.3)

Broad variety of national approaches to distribution tariffs

(Annex 3.3.4 Option 0)

Fully harmonize distribution tariff

structures through concrete requirements

(Annex 3.3.4 Option 2)

+ Adapting Institutional

Framework to reality of

integrated markets

(Annex 3.4 institutional

framework)

Retain Status Quo (no

change)

(Annex 3.4.4 Option 0)

Adapt institutional framework to the new realities of the electricity system

and the resulting need for additional regional cooperation and to address

regulatory gaps (relevant to each respective policy sub-option)

(Annex 3.4.4 Option 1)

Restructure the EU Institutional

Framework providing for more

centralised institutional structures

(Annex 3.4.4 Option 2)

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5.2.

Options to address Problem Area II (Uncertainty about sufficient future

generation investments and uncoordinated capacity markets)

Overview of the policy options

A number of Member States anticipate inadequate generation capacity in future years and

plan to introduce or have already introduced unilateraly, unaligned capacity mechanisms.

Capacity mechanisms remunerate the guaranteed availability of electricity resources (e.g.

generation or demand response) rather than paying for electricity actually delivered. The

current regulatory market design does provide for rules on capacity mechanisms

185

. While

it does not prohibit nor encourage capacity mechanisms, the Third Package is, in principle,

built on the concept of an "energy-only" market, in which generators are remunerated

mainly based on the energy delivered

186

. Undistorted cross-border markets should provide

for the necessary investment signals to ensure stable generation at all times. Price signals

should drive production and investment decisions, whereas price differentials between

different bidding zones should determine where facilities should ideally be located,

provided that all assets are treated equally in terms of the risks and costs to which they are

exposed and the opportunities for earning revenues from producing electricity i.e. they

operate within a level playing field.

Several Options will be considered to address the concerns regarding investment certainty

and fragmented approaches to CMs:

Box 5: Overview of the Policy Options for Problem Area II

Each policy option consists of a package of measures which act upon the drivers of the

problem. Some of the options differ according to whether generators can only rely on

energy market payments or whether they receive additional remuneration from CMs.

Option 1 (Improved energy-only markets) would be based on additional measures to

further strengthen the internal electricity market (complementing the measures described

above in options 1(a) (level playing field), 1(b) (strengthening short-term markets) and (c)

185

186

Capacity markets are only indirectly addressed, e.g. through the obligation for Member States under the

Third Package to maximise cross-border capacities (see e.g. Art. 16 (3) of Regulation 714/2009) and to

avoid unnecessary limitations of cross-border flows, e.g. through State Interventions.

It may be noted that generators can receive additional revenues from providing frequency reserves,

which could be described as a form of (short-term) capacity markets.

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(demand response/distributed resources) presented in Problem Area I). Under this option,

CMs would no longer be allowed. Option 2 and 3 would also include the proposed

measures to strengthen the internal energy market as presented in Option 1, but also

propose possible measures to better align national CMs. The possibility to set up a

mandatory EU-wide CM is described in Option 4.

The following sub-sections describe the policy options and the packages of measures they

comprise. It then explains which options can be discarded at this stage, prior to assessment,

as well as present other options that were considered but were discarded from the

beginning. A table summarising all specific measures for each option is provided at the

end of this section.

The relevant Annexes addressing the policy options below are: 4.1 to 5.2.

Option 0: Baseline Scenario

–

Current Market Arrangements

Under the baseline scenario, price formation on electricity wholesale markets is

constrained, e.g. through price caps. Prices may not be able to reach levels which truly

reflect the value of energy when the demand and supply balance is tight and, hence,

electricity is scarce. Therefore price signals from wholesale markets would, in times of

scarcity, be distorted and revenue streams of generators cannot properly reflect their value

to the system. This affects, in particular, the remuneration of assets that can provide

flexibility to the electricity system, regardless to whether this concerns flexible generation

capacity, electricity storage or demand response.

At this stage most electricity markets in Europe face generation overcapacities. In this

situation, price caps do in practice not matter

–

scarcity prices cannot be expected anyway.

However, once old capacities will have exited the market and the power mix has adjusted

(see in this regard the analyses presented in section 6.2.6.3), true price formation would be

essential to produce signals for new investments. This could not happen as long as price

caps exist.

Price signals are also not aligned with structural congestion in the transmission grid, thus

not revealing the locations where investments would relieve congestion and production

decisions. TSOs then can only operate sub-optimally the existing network and need to take

frequent congestion management measures. Although the CACM Guideline provides a

process for reviewing price or bidding zones, the current process lends itself to maintaining

the

status quo

(mostly price zones along Member State borders), making this the most

plausible assumption for the baseline. This is because there are likely to be competing

interests at stake. In particular, some Member States are unlikely to want to amend bidding

zones where it would create price differentials within their borders; it is sometimes

considered to be right for all consumers to pay the same price within a Member State, and

for all producers to receive the same price. The current legislation does not, therefore,

provide for the socially optimal solution to be agreed.

187

Based on perceived or real resource adequacy concerns, several Member States take

actions concerning the introduction of national resource adequacy measures or the

187

For more details concerning the deficiencies of current legislation concerning bidding zone

configuration, see Sections 4.2.2 and 4.2.3 of Annex 4.2 to this Impact Assessment.

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imposition of regulatory barriers to decommissioning. These measures are usually based

on national resource adequacy assessments and projections, which may substantially differ

depending on the underlying assumptions made and the extent to which foreign capacities

as well as demand side flexibility are taken into account in calculations. Some of these

concerns and projections are a result of the current market arrangements.

The Commission's current tool to assess whether government interventions in support of

resource adequacy are legitimate is state aid scrutiny. The EEAG require among others a

proof that the measure is necessary, technological neutral and allows for explicit cross-

border participation. However, the EEAG do not clarify how an effective cross-border CM

regime could be deployed.

The baseline is common with the one presented in 5.1.2, with only two differences: (a)

presence of price caps based on current practices and (b) existence of structural congestion

in the transmission grid.

Stakeholders' opinions:

None of the respondents to the public consultation took the view

that the current market arrangements were sufficient and no further measures are required.

Option 0+: Non-regulatory approach

Whilst systematically considered

188

, no such policy option could be identified.

This option would entail relying on existing legislation to improve the current market

arrangements. The likelihood of seeing any meaningful change as a result of this process

is minimal. Existing provisions under EU legislation are arguably not sufficiently clear and

robust. In this regard, the Evaluation report indicates that the rules of the Third Energy

Package appear to be insufficient to cope with the challenges facing the European

electricity system.

189

In addition, certain areas, like resource adequacy, are not addressed

in the Third Package. Consequently, the Evaluation report concludes that the Third

Package does not not ensure sufficient incentives for private investments in the new

generation capacities and network because of the minor attention in it to effective short-

term markets and prices which would reflect actual scarcity.

190

Voluntary cooperation has resulted in significant developments and a lot of benefits (e.g.,

the PLEF, whereby some Member States have voluntarily decided to cooperate and deliver

a regional resource adequacy assessment). However it may not provide for appropriate

levels of harmonisation across all Member States and certainty to the market and

legislation is needed in this area to address the issues in a consistent way.

Option 1: Improved energy market - no CMs

Option 1 assumes that European electricity markets, if sufficiently interconnected and

undistorted, can provide for the necessary price signals to incentivise investments into new

generation. Wholesale markets would be strengthened by a set of specific measures aiming

at improving price signals so as to deliver the necessary investments based only on price

188

189

190

For each measure the opportunities for stronger enforcement has been assessed in the annexes.

See Section 7.3.1 and 7.3.3 of the Evaluation.

See Sections 7.3.2 of the Evaluation.

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signals. CMs, whether at national, regional or European level would not be justifiable to

secure electricity supplies under this option as the market should be incentivising

investments.

Even if such price signals concern the spot price on the wholesale market corresponding

to the day-ahead market, these prices are the reference for the forward market and would

thus have a long-term effect. Having as a starting point the reformed market design as

described in section 5.1.4.3

191

, it is additionaly assumed that no administrative mechanisms

directly affecting investments and price signals are allowed to be in place, in the form of

CMs or (below Value of Lost Load

192

or 'VoLL') price caps. In the case of the latter this

would be effected by ensuring that any technical limits imposed by power exchanges are

merely that, and are raised in the event they are reached, and, in order to provide maximum

investor confidence, an end-date, after which such limits must not be below VoLL.

The strengthened short and long-term markets and the participation of distributed

generation offer the necessary flexibility required to integrate variable RES E into the

market. Combined with the removal of (below VoLL) price caps,

193

the market should be

able to drive investments towards the needed flexible assets, such as storage and demand

response, and sufficient generating capacity. Furthermore, proper incentives are introduced

aiming to unlock the flexibility that can be provided by existing assets, such as demand

response and storage.

At the same time price signals could drive the geographical location of new investments

and production decisions, via price zones aligned with structural congestion in the

transmission grid. The location of the price zone borders would be decided through a robust

regulatory decision-making process. Price differentials between these price zones should

help determine where investments are needed and make the best use of natural resources

(particularly important for RES E, but also for interconnectors) and, for those assets

already deployed, which one will be producing. Such locational prices would also provide

efficient signals for the location of demand

–

for example new energy intensive industries

would choose to locate in areas where there is excess generation and therefore low

prices.

194

Measures would also be taken to further restrict the practice of limiting cross-

border capacity in order to deal with internal network contraints and, finally, measures

would be taken to minimise, in the long-term, the most significant investment and

operational distortions on generators arising as a result of network charges.

195

Stakeholder's opinions:

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

only" market (possibly augmented however with a strategic reserve, which is a form of a

capacity market). Many stakeholders share the view that properly designed energy markets

would make capacity mechanisms gradually redundant. Many generators and some

191

192

193

194

195

Sub-option 1(c) (demand response/distributed resources) from problem area I was used as the basis here,

as it was identified as the preferred option when comparing the respective options in Section 7.1.

Value of Lost Load is a projected value reflecting the maximum price consumers are willing to pay to

be supplied with electricity

For more detail on policy measures related to the removal of price caps, refer to Annex 4.1.

For more detail on policy measures related to the improvement of locational signals, refer to Annex 4.2.

For more detail, refer to Annexes 4.3 and 4.4.

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governments disagree and are in favour of capacity remuneration mechanisms (assessed in

Options

2, 3 and 4).

large majority of stakeholders agreed that scarcity pricing is an important element in the

future market design. While single answers point at risks of more volatile pricing and price

peaks (e.g. political acceptance, abuse of market power), others stress that those respective

risks can be avoided (e.g. by hedging against volatility).

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

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

transmission pricing). While some stakeholders criticised the current price zone practice

for not reflecting actual scarcity and congestions within bidding zones, leading to missing

investment signals for generation, new grid connections and to limitations of cross-border

flows, others recalled the complexity of prices zone changes and argued that large price

zones would increase liquidity.

Many submissions highlight the crucial role of scarcity pricing for kick-starting demand

response at industrial and household level.

European Parliament:"…[N]ational

capacity markets make it harder to integrate

electricity markets and run contrary to the objectives of the common energy policy, and

should only be used as a last resort once all other options have been considered, including

increased interconnection with neighbouring countries, demand-side response measures

and other forms of regional market integration[.]"

196

"European Parliament […] [i]s

sceptical of purely national and non-market-based capacity mechanisms and markets,

which are incompatible with the principles of an internal energy market and which lead to

market distortions, indirect subsidies for mature technologies and high costs for

end-consumers; stresses, therefore, that any capacity mechanism in the EU must be

designed from the perspective of cross-border cooperation following the completion of

thorough studies on its necessity, and must comply with EU rules on competition and State

aid; believes that better integration of national energy production into the EU energy

system and the reinforcement of interconnections could reduce the need for, and cost of,

capacity mechanisms[.]"

197

Option 2: Improved energy market

–

CMs only when needed, based on a common

EU-wide adequacy assessment)

198

This Option includes the measures to strenghten the internal energy market (as described

in Option 1 above), i.e. every Member State is assumed to have in place a well-functioning

energy market.

196

197

198

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, Recital H.

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 24.

Further elements of this option are presented in Annex 5.1.

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In addition to Option 1 however, Member States would be allowed to implement national

CMs, but only under certain conditions. Additional measures are proposed in order to avoid

negative consequences of uncoordinated CMs for the functioning of the internal market,

building on the EEAG' state aid Guidelines and the Sector Inquiry on CMs.

To address the problem of diverging and purely national assessments of the needs for CMs,

ENTSO-E would be required under this option to propose a methodology for an EU-wide

resource adequacy assessment. The upgraded methodology should be based on transparent

and common assumptions

199

and ENTSO-E would carry out the assessment anually. The

prerequisite for a Member State to implement a CM or prohibit capacity from exiting the

market would be that ENTSO-E's assessment indicated a lack of generation capacity and

where markets cannot be expected to close the gap. This would avoid that back-up

capacities are developed based on a purely national perspective (i.e. national adequacy

assessments, using different methodologies and not taking into account the generation

potential across borders).

When proposing or applying CMs, Member States would need to introduce resource

adequacy targets, which can be diverging (as an expression of their diverging preference

for resource adequacy). The standards should be expressed in a unique format to become

comparable across the EU

–

as Expected Energy Non Served ('EENS'), and it should be

derived following a methodology provided by ENTSO-E which takes into account the

value that average customers in each bidding zone put on electricity supplies (Value of

Lost Load

–

'VoLL').

Stakeholders' opinions:

There is almost a consensus amongst stakeholders on the need

for a more aligned method for resource adequacy assessment. A majority of answering

stakeholders supports the idea that any legitimate claim to introduce CMs should be based

on a common methodology. When it comes to the geographical scope of the harmonized

assessment, a vast majority stakeholders call for regional or EU-wide resource adequacy

assessment, while only a minority favour a national approach. There is also support for the

idea to align adequacy standards across Member States.

European Parliament:

"[…]stresses the importance of a common analysis of resource

adequacy at regional level, facilitated by the Agency for the Cooperation of Energy

Regulators (ACER) and the European Network of Transmission System Operators

(ENTSO-E), and calls for the transmission system operators (TSOs) of neighbouring

199

The ENTSO-E assessment should have the following characteristics:

i. It should cover all Member States

ii. It should have a granularity of Member State/ bidding zone level to enable the analysis of national/

local adequacy concerns;

iii. It should apply probabilistic calculations that consider dynamic characteristics of system elements

(e.g. start-up and shut-down times, ramp up and ramp-down

rates…)

iv. It should calculate generation adequacy indicators for all countries (LOLE, EENS, etc.)

v. It should appropriately take into account foreign generation, interconnection capacity, RES , storage

and demand response

vii. Time span of 5-10 years

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markets to devise a common methodology, approved by the Commission, to that end;

highlights the enormous potential of strengthened regional cooperation[…]"

200

Council:

"Member States considering implementing capacity mechanism should take into

account synergies of cross-border regional cooperation and avoid any disincentive for

investment in interconnection, while minimising market distortion"

201

Option 3: Improved energy market - CMs only when needed, based on a common

EU-wide adequacy assessment, plus cross-border participation

202

Option 3 includes the measures to strenghten the internal energy market as described in

Option 1 above. It also includes the requirement for national CMs to be justified by a

European adequacy assessment (see Option 2). In addition, Option 3 would however

provide for design rules for better compatibility between national CMs, also building on

the EEAG state aid guidelines and the Sector Inquiry on CMs notably in order to facilitate

cross-border participation ('blue-print') .

To date, in order to comply with EEAG, Member States have to individually organise, for

each of their borders separately, the necessary cross-border arrangements involving a

multitude of parties (e.g. resource providers, regulators, TSOs).

This option would provide a harmonised cross-border participation scheme across the EU

by setting out procedures including roles and responsibilities for the involved parties (e.g.

resource providers, regulators, TSOs).

Stakeholders' opinions:

Most of the stakeholders including Member States agree that a

regional/European framework for CMs are preferable. Indeed, 85% of market participant

respondents and 75% of public body respondents to the sector inquiry on Capacity

Mechanisms

203

felt that rules should be developed at EU level to limit as much as possible

any distortive impact of CMs on cross national integration of energy markets. Member

States might instinctively want to rely more on national assets and favour them over cross-

border assets. It is often claimed that in times of simultaneous stress, governments might

choose to 'close borders' putting other Member States who might actually be in bigger need

in trouble.

European Parliament:

"[…][c]alls for cross-border

capacity mechanisms to be

authorised only when the following criteria, inter alia, are met: a. the need for them is

confirmed by a detailed regional adequacy analysis of the production and supply situation,

including interconnections, storage, demand-side response and cross-border generation

resources, on the basis of a homogeneous, standardised and transparent EU-wide

methodology which identifies a clear risk to uninterrupted supply; b. there is no possible

alternative measure that is less costly and less market-intrusive, such as full regional

200

201

202

203

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 14.

See

"Messages from the Presidency on electricity market design and regional cooperation"

(2016), Note

to the Permanent Representatives Committee/Council, Page 2.

http://data.consilium.europa.eu/doc/document/ST-8400-2016-INIT/en/pdf

Further elements of this option are presented in Annex 5.

"Interim Report of the Sector Inquiry on Capacity Mechanisms"

SWD(2016) 119 final.

http://ec.europa.eu/competition/sectors/energy/capacity_mechanisms_swd_en.pdf

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market integration without restriction of cross-border exchanges, combined with targeted

network/strategic reserves; c. their design is market-based and is such that they are

non-discriminatory in respect of the use of electricity storage technologies, aggregated

demand-side response, stable sources of renewable energy and participation by

undertakings in other Member States, so that there is no cross-border cross-subsidisation

or discrimination against industry or other customers, and it is ensured that they only

remunerate the capacity strictly necessary for security of supply; d. their design includes

rules to ensure that capacity is allocated sufficiently in advance to provide adequate

investment signals in respect of less polluting plants; e. sustainability and air quality rules

are incorporated in order to eliminate the most polluting technologies (consideration

could be given to an emissions performance standard in this connection) […]"

204

Option 4: Mandatory EU-wide or regional CMs

Under this option based on regional or EU-wide resource adequacy assessments, entire

regions or ultimately all EU Member States would be required to roll-out CMs on a

mandatory basis. The design of the CMs would follow a EU 'blue print' (i.e. a set of design

requirements for CMs), with the required resource adequacy target to be set at regional or

EU level. This approach would assess

and address

adequacy concerns at a regional or EU

level. Decisions on whether to introduce CMs or not would no longer be left with

individual Member States, but an EU-wide CM would be created, as a mandatory

additional layer to the "energy-only" market. Differences between Member States (e.g.

whether all areas within larger regions actually face adequacy challenges, or network

congestions) would not justify exception from the obligation to introduce a CM.

Discarded Options

Option 0+ will not be further analysed as no means were identified to implement it.

Option 4 does not consider the significant regional differences when it comes to resource

adequacy. The EU-wide or region-wide roll-out would disregard existing congestions in

the European network and it would consequently over- or underestimate the resource

adequacy in single bidding zones/ Member States belonging to a wider region. As a result

CMs might need to be introduced in bidding zones/Member States that do not face any

adequacy concerns. Alternatively, emerging resource adequacy problems in certain

bidding zones/Member States might not be identified and addressed appropriately. In

addition, as a number of Member States rely on energy-only markets to provide for the

necessary investments in their power systems it would not be appropriate to force them to

adopt CMs.

Summary of specific measures comprising each Option

The following table summarizes the specific measures comprising each package of

measures, as well the corresponding specific measure option considered under each high

204

European Parliament,

Report on Towards a New Energy Market Design

(2015/2322(INI)), Committee

on Industry, Research and Energy, 21.6.2016, § 25.

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level option

205

. The detailed presentation and assessment of each measure can be found in

the indicated Annex.

205

The preferred options for the specific measures set out in the annex are highlighted in the table in green.

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Table 7: Summary of Specific Measures Examined for Problem Area II

Specific Measures

Option 0

Option 1

Improved

energy

market/ no

Option 2

Improved energy

market/ CMs only

when needed,

based on a common

EU-wide adequacy

assessment)

Option 3

Option 4

Baseline (Current market

arrangements)

Improved energy market/ CMs

only when needed, plus cross-

border participation)

Mandatory EU-wide or

regional CMs

Specific Measures related to the

Energy Market

+ Price Caps

(Annex 4.1)

+ Locational Price Signals

(Annex 4.2)

As in section 5.1.2

Lower than VoLL

(Annex 4.1.4 Option 0)

Price Zones defined based on

arrangements in CACM Guideline

(4.2.4 Option 0)

Limited harmonisation of the

methodologies setting

transmission tariffs

(Annex 4.3.4 Option 0)

Limited restrictions on the use of

congestion income

(Annex 4.4.4 Option 0)

As in section 5.1.4.3

At VoLL

(Annex 4.1.4 Option 2)

Strengthened process for deciding on price zones, leading to the definition

of zones based on systematic congestion in networks

(4.2.4 Option 3)

More concrete principles on the setting of transmission tariffs and other

network charges.

(Annex 4.3.4 Option 2)

Nodal Pricing

(4.2.4 Option 1)

Full harmonisation of the

methodologies setting

transmission tariffs

(Annex 4.3.4 Option 3)

+ Transmission Tariff Structures

(Annex 4.3)

+ Congestion Income

4.4)

(Annex

Further prescription on the use of congestion income, with the aim of an even more European approach

(Annex 4.4.4 Option 1)

Common EU-wide assessment by ENTSO-E becomes the basis for MS to introduce CMs

(Annex 5.1.4 Option 3)

No EU framework

with rules for cross-

border participation

(Annex 5.2.4 Option

+ Resource Adequacy Plans

(Annex 5.1)

+ Cross-border Participation of

CMs

(Annex 5.2)

National plans following different methodologies

(Annex 5.1.4 Option 0)

No EU framework with rules for

cross-border participation

(Annex 5.2.4 Option 0)

N/A

Harmonized EU framework for cross-border participation

(Annex 5.2.4 Option 1)

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5.3.

Options to address Problem Area III (When preparing or managing crisis

situations, Member States tend to disregard the situation across their borders)

Overview of the policy options

With the intention to meet the objectives set out in the previous section, the Commission

services have identified several policy options ranging from an enhanced implementation

of the existing legislation to the full harmonization and decision making at regional level.

Option 0 represents the baseline or the measures currently in place. Each policy option

consists of a package of measures combining existing tools, possible updated and improved

tools and new tools which act upon the drivers of the problem. This section finalizes with

a table summarising all specific measures comprising each option.

The relevant Annex addressing the policy options below is Annex 6.

Table 8: Overview of the Policy Options for Problem Area III

Option 0: Baseline scenario

–

Purely national approach to electricity crises

Under the baseline scenario, Member States would continue identifying and addressing

possible crisis situations based on a national approach, in accordance with their own

national rules and requirements.

There would be no rules or structures facilitating and guaranteeing a proper identification

of cross-border crisis situations

206

and ensuring that Member States take the necessary

action to deal with them, in co-operation with one another. Whilst some co-operation

between Member states could take place (e.g., between the Nordic countries as well as

within the context of the PLEF

207

), in practice such cooperation would remain entirely

206

207

In the framework of the SESAME project (which was financed under FP7) tools were developed for the

identification of grid and production plants vulnerabilities and for estimating the damage resulting from

network failures. However, this project had a more national focus (in particular on Romania and Austria)

and the identification and management of cross-border crisis was outside the scope of this project

(https://www.sesame-project.eu/).

Pentalateral Energy Forum, consisting of the Ministries, NRAs and TSOs of BENELUX, Germany,

France, Austria, Switzerland.

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voluntary, and might be hampered in practice by different national rules and procedures,

and a lack of appropriate structures at regional and EU level.

Innovative tools

208

have been also developed for TSOs in the area of the system security

in the last years, improving monitoring, prediction and managing secure interconnected

power systems and preventing, in particular, cascading failures

209

. In addition, the recently

adopted network codes and guidelines bring a certain degree of harmonisation on how to

deal with electricity systems in different states (normal state, alert state, emergency state,

black-out and restoration) and should bring more clarity as to how TSOs should act in

crisis situations, and as to how they should co-operate with one another. However, network

codes and guidelines focus on technical issues and co-operation between TSOs (in

implementation of the current legal framework). They do not offer a framework ensuring

a proper co-ordination and co-operation between Member States on how to prepare for and

handle electricity crisis situations, in particular in situations of simultaneous scarcity.

210

For instance, political decisions such as where to curtail, to whom and when, would still

be taken nationally, by reference to very different national rules and regulations. In

addition, any cross-border assistance in times of crisis would be hampered by a lack of

common principles and rules governing co-operation, assistance and cost compensation.

Finally, risks would still assessed and adressed on the basis of very different methods, and

from a national perspective only.

Stakeholders' opinions:

Stakeholders agree that the current framework does not offer

sufficient guarantees that electricity crisis situations are properly prepared for and handled

in Europe. They also take the view that, whilst network codes and guidelines will offer

some solutions at the technical level, there is a need for a better alignment of national rules

and cooperation at the political level

211

Option 0+: Non-regulatory approach

As current legislative framework established by the SoS Directive set general principles

rather than requires Member States to take concrete measures, better implementation and

enforcement actions will be of no avail.

208

209

210

211

ITESLA project (which was financed under FP7) developed methods and tools for the coordinated

operational planning of power transmission systems, to cope with increased uncertainties and variability

of power flows, with fast fluctuations in the power system as a result of the increased share of resources

connected through power electronics, and with increasing cross-border flows. The project shows that

the reliance on risk-based approaches for corrective actions can avoid costly preventive measures such

as re-dispatching or reduced the overall risk of failure.

In addition the AFTER project (which was financed under FP7) also developed tools for TSOs to

increase their capabilities in creating, monitoring and managing secure interconnected electrical power

system infrastructures, being able to survive major failures and to efficiently restore service supply after

major disruptions (http://www.after-project.eu/).

In addition, whilst the guidelines and codes require TSOs to co-operate, they do not require them to

engage in joint action (e.g. through the ROCs).

See for examle the answers to the public consultation of the International Energy Agency, ENTSO-E.

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In fact, as the progress report of 2010 shows

212

, the SoS Directive has been implemented

across Europe, but such implementation did not result in better co-ordinated or clearer

national policies regarding risk preparedness.

In addition, the evaluation of the SoS Directive has revealed the existence of numerous

deficiencies in the current legal framework

213

. It highlights the ineffectiveness of the SoS

Directive in achieving the objectives pursued, notably contributing to a better security of

supply in Europe. Whilst some of its provisions have been overtaken by subsequent

legislation (notably the Third Package and the TEN-E Regulation), there are still regulatory

gaps notably when it comes to preventing and managing crisis situations.

The evaluation also reveals that the SoS Directive intervention is no longer relevant today

as it does not match the current needs on security of supply. As electricity systems are

increasingly interlinked, purely national approaches to preventing and managing crisis

situations can no longer be considered appropriate. It also concludes that its added value

has been very limited as it created a general framework but left it by and large to Member

States to define their own security of supply standard. Whilst electricity markets are

increasingly intertwined within Europe, there is still no common European framework

governing the prevention and mitigation of electricity crisis situations. National authorities

tend to decide, one-sidedly, on the degree of security they deem desirable, on how to assess

risks (including emerging ones, such as cyber-security) and on what measures to take to

prevent or mitigate them.

The recently adopted network codes and guidelines offer some improvements at the

technical level, but do not address the main problems identified.

In addition, today voluntary cooperation in prevention and crisis management is scarce

across Europe and where it takes place at all, it is often limited to cooperation at the level

of TSOs. It is true that certain Member States collaborate on a voluntary basis in order to

addresss certain of the problems identified (e.g. Nord-BER, PLEF). However, these

initiatives have different levels of ambition and effectiveness, and they geografically cover

only part of the EU electricity market. Therefore, voluntary cooperation will not be an

effective tool to solve the problems identified timely in the whole EU.

Option 1: Common minimum rules to be implemented by Member States

Under Option 1, Member States would have to respect a set of common rules and principles

regarding crisis prevention and management, agreed at the European level ('minimum

harmonisation'). In particular, Member States would be obliged to develop national

Risk

Preparedness Plans

('Plan') with the aim to avoid or better tackle crisis situations. Plans

could be prepared by TSOs, but need to be endorsed at the political level. Plans should be

based on an

assessment

of the most relevant crisis scenarios originated by rare/extreme

risks. Such assesment would be carried out in a national context (as is the case today), but

would have to based on a common set of rules. In particular, Member States would be

required, for instance, to consider at least the following risks: a) rare/extreme natural

212

213

Report on the progress concerning measures to safeguard security of electricity supply and

infrastructure investment

COM (2010) 330 final.

See Evaluation of the EU rules on measures to safeguard security of electricity supply and infrastructure

investment (Directive 2005/89/EC).

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hazards, b) accidental hazards which go beyond N-1, c) consequential hazards such as fuel

shortage, d) malicious attacks (terrorist attacks, cyberattacks).

Plans would have to respect a set of common minimum requirements. They would need to

set out who does what to prevent and to manage crisis situations, including in a situation

of a crisis affecting more than one countrry at the same time. More specifically on

cybersecurity,

Member States would need to set out in the Plans how they will prevent

and manage cyberattack situations. This would be combined with soft guidance on

cybersecurity in the energy sector, based on the NIS Directive

214

. Member States would

also be required to set out how they ensure that assets that are important from a security of

supply perspective, are protected against undue influences in case ownership control

changes.

Plans should be adopted by relevant governments / ministries, following an inclusive

process, and (at least some parts of the Plans) should be rendered public. Plans should be

updated on a regular basis.

In addition, under Option 1 there would be

new common rules and principles governing

crisis management,

in replacement of the current Article 42 of the Electricity Directive,

which allows Member States to take 'safeguard measures' in crisis situations. All crisis

management actions (whether taken at the level of the TSOs or at the level of governments)

would need to respect three principles:

'Market comes first':

Non-market measures (such as obligatory demand reduction

schemes) should only be introduced as a means of last resort, when duly justified,

and should be temporary in nature. Use of such measures should not undermine

market and system functioning;

'Duty to offer assistance':

Member States would be obliged to address electricity

crisis situations, in particular situations of a simultaneous crisis, in a spirit of co-

operation and solidarity. This means agreeing in advance on practical solutions on

e.g. where to shed load and how much in cross-border crisis situations, subject to

financial compension (which is also to be agreed upon in advance).

'Transparency and information exchange':

Member States should inform each

other and the Commission without undue delay when they see a crisis situation

coming (e.g., as a result of a seasonal outlook pointing at upcoming problems) or

when being in a crisis situation. They should also be transparent about measures

taken and their effect, both when taking them and afterwards.

The main benefits this option would bring is better preparedness, due to the fact that a

common approach is followed across Europe, thus excluding the risk that some Member

States being 'under-prepare'. In addition, better preparedness is likely to reduce the chances

of premature market interventions, where Member States act in a transparent manner and

214

Directive (EU) 2016/1148 of the European Parliament and of the Council of 6 July 2016 concerning

measures for a high common level of security of network and information systems across the Union, OJ

L 194, 19.07.2016, p. 1-30.

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on the basis of a clear set of rules. By imposing obligations to cooperate and lend

assistance, Member States are also less likely to 'over-protect' themselves against possible

crisis situations, which in turn will contribute to more security of supply at a lesser cost.

Since a 'minimum' harmonisation approach would be followed, Member States would have

still room to take account of national specificities, where needed and appropriate.

Stakeholders' opinions:

A large majority of stakeholders is in favour of risk preparedness

plans based on common rules and principles, as a tool to ensure a more common and more

transparent approach. Consulted stakeholders

215

agree on the need for a common approach

what Member States can do in crisis situations and call for more transparency.

Option 2: Common minimum rules to be implemented by Member States, plus

regional co-operation

Option 2 would build on Option 1. It would include all common rules included in Option

1 (i.e., define a set of minimum obligations Member States would need to respect). In

addition, it would put in place rules and tools to ensure that effective cross-border co-

operation takes place, in a regional and EU context. Given the interlinked nature of EU's

electricity systems, enhanced regional co-operation brings clear benefits when it comes to

preventing and managing crisis situations.

First, under Option 2, there would be a

systematic assessment of rare/ extreme risks at

the regional level.

The identification of crisis scenarios would be carried out by ENTSO-

E, who would carry out such assessments in a regional context. To achieve this, ENTSO-

E would be able to delegate all or part of its tasks to the ROCs. This regional approach

would ensure that the risks originating across borders, including scenarios of a possible

simultaneous crisis, are taken into account. The crisis scenarios identified by ENTSO-E

would be also discussed in the Electricity Coordination Group, to ensure that a coherent

and transparent approach is followed across Europe. For

cybersecurity,

building on

Option 1, the Commission would propose the development of a network code/guidelines

which would ensure a minimum level of harmonization in the energy sector throughout the

216.

The Risk Preparedness Plans would contain two parts

–

a part reflecting national

measures and a part reflecting measures to be pre-agreed in a regional context.

The

latter part includes in particular preparatory measures such as simulations of simultaneous

crisis situations in neighbouring Member States

("stress tests" in regional context

organised by ENTSO-E who can delegate all or part of its tasks to the ROCs); procedures

for

cooperation

with other Member States in different crisis scenarios, as well as

215

216

See for example the Public Consultation answers of the Dutch and Latvian Governments, GEODE,

CEDEC, EDF UK, TenneT, Eurelectric and Europex welcoming risk preparendess plans.

The network code/guidelines should take into account at least: a) methodology to identify operators of

essential services for the energy sector; b) risk classification scheme; c) minimum cyber-security

prerequisites to ensure that the identified operators of essential services for the energy sector follow

minimum rules to protect and respond to impacts on operational network security taking the identified

risks into account. A harmonized procedure for incident reporting for the energy sector shall be part of

the minimum prerequisites.

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agreements on

how to deal with simultaneous electricity crisis situations.

Through such

regional agreements, Member States would be required to define in advance, in a regional

context, how information will be shared, how they will ensure that markets can work as

long as possible, and what kind of assistance will be offered accross borders, For instance,

Member States would be required to agree in advance in which situations and according to

what priorities customers would be curtailed in simultaneous crisis situations. The regional

coordination of plans would build trust and confidence between Member States, which is

crucial in times of crisis. It would also allow optimising scarce resources in times of crisis,

whilst ensuring that markets can work as long as possible.

The regional parts of the Plans should be pre-agreed in a regional context. Such regionally

co-ordinated plans would help ensure that increased TSO cooperation is effectively

matched by a more structured cooperation between Member States.

217

For this reason,

Member States would be called upon to co-operate and agree in the context of the same

regional settings as are used for the ROCs. Effective regional co-operation and agreements

would help ensure that electricity crisis situations are dealt with in the most effective

manner, whilst respecting the needs of electricity consumers and systems at large.

To facilitate cross-border cooperation, Member States should designate one 'competent

authority', belonging either to the national administration or to the NRA.

Additionally,

ENTSO-E

would be required to develop a

common method

for carrying

out short-term risk assessments, to be used in the context of seasonal outlooks and weekly

risk assessments by TSOs.

To allow for a precise monitoring,

ex-ante

and

ex-post,

of how well Member States'

systems perform in the area of security of supply, harmonised security of supply

indicators

would be introduced, as well as obligation on Member States

to inform the Electricity

Coordination Group and the Commission on crisis situations,

their impact and the

measures taken. This would enhance transparency, comparability and mutual trust in

neighbours.

Further, in this option, the role of the

Electricity Coordination Group

218

would be

reinforced, so that it can act as an effective forum to monitor security of supply in Europe

and oversee the way (possible) electricity crisis situations are dealt with. For instance, the

Group would be asked to review the cross-border crisis scenario's developed by ENTSO-

E and to review

ex ante

risk preparedness plans put in place by Member States. The Group

could issue recommendations and develop best practice. Overall, the reinforcement of its

tasks and powers would contribute to enhance cooperation and to build trust and

confidence among Member States.

For cases of crisis, in particular simultaneous scarcity, also ENTSO-E sees a need for

"not only on a

technical level but political cooperation"

and plans which

"should cover extreme crisis situations beyond

the measures provided by e.g. network codes and RSCs services"

(Source: ENTSO-E (2016):

"Recommendations to the regulatory framework on risk preparedness (WS5)").

218

The members of the Electricity Coordination Group are Member States authorities (ministries competent

for Energy), National Regulatory Authorities, ACER and ENTSO-E.

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Figure 7: Overview of measures in Option 2

Source: DG ENER

Stakeholders' opinions:

The majority of consulted stakeholders are in favour of regional

coodination of risk preparedness plans

219

and a stronger co-ordinating role of the

Electricity Coordination Group

220

. Various stakeholders make the case for a common

methodology for assessing risks in various time horizons, to detect cross-border crisis

situations and guarantee comparability of results

221

. Several stakeholders also see a need

for clear rules and

ex-ante

cross-border agreements to ensure that markets function as long

as possible in (simultaneous) crisis situations

222

The

European Electricity Regulatory Forum, Florence:

The Florence Forum welcomes

a more co-ordinated approach to risk preparedness based on risk preparendess plans and a

common framework for how to deal with (simultaneous) crisis situations, including the

principle that the market should act first

223

219

220

221

222

223

See for example the Public Consultation answers of the Finish, Dutch, Norwegian governments, TenneT

and the German Association of Local Utilities.

See for example the Public Consultation answers of the Dutch government and ENTSO-E.

See for example the Public Consultation answers of the Dutch government, EDF, ENTSO-E.

See for example ENTSO-E's presentation on Capacity Mechanisms (TOP 2.4) from the Florence Forum

in June 2016 (available here:

https://ec.europa.eu/energy/en/events/meeting-european-electricity-

regulatory-forum-florence).

See conclusions from Florence Forum, March 2016, paragraph 10.

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"The Forum recognises the need for more co-ordination across Member States and clearer

rules on coping with electricity crisis situations. It encourages the Commission to quickly

bring the draft Emergency and Restoration Network Code forward for discussion with the

Member States. It also welcomes the Commission's work on a new proposal on risk

preparedness in the electricity sector and considers that risk preparedness plans and

common framework for how to deal with critical situations should be its key builing blocks.

It stresses the need that all action on risk preparedness should respect the principle that

the market should act first."

The European Parliament

224

calls for more regional co-operation, notably as regards

'action to be taken in the event of an electricity crisis, in particular when such a crisis has

cross-border effects,'

and calls on the Commission

'to propose a revised framework to that

end".

Council:

The Council recognizes the responsibility of Member States for ensuring security

of supply but sees a "benefit

from a more coordinated and efficient approach",

necessity

to work on a further harmonization of of methods for assessing norms and indicators for

security of supply"

and "a

need to develop a more common approach to preparing for and

managing crisis situations within the EU".

225

Option 3: Full harmonisation and decision-making at regional level

Building on Option 2, under Option 3 the

risk preparedness plans

would be developed

regional level.

This would allow a harmonised response to potential crisis situations in

each region. On

cybersecurity,

Option 3 would go one step further and nominate a

dedicated body (agency) to deal with cybersecurity in the energy sector. The creation of

the agency would guarantee full harmonisation on risk preparedness, communication,

coordination and a coordinated cross-border reaction on cyberincidents.

Crisis would have to be managed according to the regional plans

agreed among

Member States. The Commission would determine the key elements of the regional plans

such as: commonly agreed regional load-shedding plans, rules on customer categorisation,

a harmonised definition of protected customers at regional level or specific rules on crisis

information exchanges in the region.

Regarding

crisis handling,

under Option 3, a

detailed 'emergency rulebook'

would be

put in place, containing an exhaustive list of measures that can be taken by Member States

in crisis situations, with detailed indications as regards what measures can be taken, in

what circumstances and when.

224

225

See European Parliament:

Towards a New Energy Market Design

(2016), Werner Langen, paragraph

68.

See

Messages from the Presidency on electricity market design and regional cooperation

(2016), Note

to the Permanent Representatives Committee/Council, paragraph 7.

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Stakeholders' opinions:

The results of the public consultation showed that only few

stakeholders were in favour of regional or EU wide plans. Some stakeholders mentioned

the possibility to have plans on all three levels (national, regional and EU)

226

Whilst stakeholders generally acknowledge the need for more commonality and more

regional co-operation on risk prevention and management, there is no support for a fully

harmonised approach based on rulebooks

227

Discarded Options

Option 0+ was disregarded as no means for enhanced implementing of the existing acquis

were identified.

Summary of specific measures comprising each Option

The following table summarizes the specific measures to be taken under each option

228

. A

more detailed discussion can be found in annex.

226

227

228

See for example the Public Consultation answers of Latvian government, EDSO, GEODE, Europex.

See for example the Public Consultation answers of the Finish and German governments.

The preferred options for the specific measures set out in the annex are highlighted in the table in green.

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Table 8: Sumary of Specific Measures Examined for Problem Area III

Specific

Measures

Option 0

Option 0+

Option 1

Option 2

Option 3

Baseline

Non-regulatory

approach

Common minimum EU rules for

prevention and crisis management

Common minimum EU rules plus regional

cooperation, building on Option 1

Full harmonisation and full

decision-making at regional

level, building on Option 2

All rare/extreme risks

undermining security of supply

assessed at the EU level, which

would be prevailing over

national assessment.

Assessments

Rare/extreme risks

and short-term risks

related to security of

supply are assessed

from a national

perspective.

Risk identification &

assessment methods

differ across Member

States.

This option was

disregarded as no

means for

enhanced

implementing of

the existing acquis

nor for enhanced

voluntary

cooperation were

identified.

Member States to identify and assess

rare/extreme risks based on common risk

types.

ENTSO-E to identify cross-border electricity

crisis scenarios caused by rare/extreme risks,

in a regional context. Resulting crisis

scenarios to be discussed in the Electricity

Coordination Group.

Common methodology to be followed for

short-term risk assessments (ENTSO-E

Seasonal Outlooks and week-ahead

assessments of the RSCs).

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Member States take

measures to prevent

and prepare for

electricity crisis

situations focusing on

national approach,

and without

sufficiently taking

into account cross-

border impacts.

Plans

No common approach

to risk prevention &

preparation (e.g., no

common rules on

how to tackle

cybersecurity risks).

Member States to develop mandatory

national Risk Preparedness Plans setting

out who does what to prevent and

manage electricity crisis situations.

Plans to be submitted to the Commission

and other Member States for

consultation.

Plans need to respect common minimum

requirements. As regards cybersecurity,

specific guidance would be developed.

Mandatory Risk Preparedness Plans including

a national and a regional part. The regional

part should address cross-border issues (such

as joint crisis simulations, and joint

arrangements for how to deal with situations

of simultaneous crisis) and needs to be agreed

by Member States within a region.

Plans to be consulted with other Member

States in the relevant region and submitted for

prior consultation and recommendations by

the Electricity Coordination Group.

Member States to designate a 'competent

authority' as responsible body for coordination

and cross-border cooperation in crisis

situations.

Development of a network code/guideline

addressing specific rules to be followed for the

cybersecurity.

Extension of planning & cooperation

obligations to Energy Community partners.

Mandatory Regional Risk

Preparedness Plans, subject to

binding opinions from the

European Commission.

Detailed templates for the plans

to be followed.

A dedicated body would be

created to deal with

cybersecurity in the energy

sector.

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Each Member State

takes measures in

reaction to crisis

situations based on its

own national rules

and technical TSO

rules.

No co-ordination of

actions and measures

beyond the technical

(system operation)

level. In particular,

there are no rules on

how to coordinate

actions in

simultaneous crisis

situations between

adjacent markets.

No systematic

information-sharing

(beyond the technical

level).

Monitoring of

security of supply

predominantly at the

national level.

ECG as a voluntary

information exchange

platform.

Minimum common rules on crisis

prevention and management (including

the management of joint electricity crisis

situations) requiring Member States to:

(i) not to unduly interference with

markets;

(ii) to offer assistance to others where

needed, subject to financial

compensation, and to;

(iii) inform neighbouring Member States

and the Commission, as of the moment

that there are serious indications of an

upcoming crisis or during a crisis.

Minimum obligations as set out in Option 1.

Cooperation and assistance in crisis between

Member States, in particular simultaneous

crisis situations, should be agreed ex-ante; also

agreements needed regarding financial

compensation. This also includes agreements

on where to shed load, when and to whom.

Details of the cooperation and assistance

arrangements and resulting compensation

should be described in the Risk Preparedness

Plans.

Crisis is managed according to

the regional plans, including

regional load-shedding plans,

rules on customer

categorisation, a harmonized

definition of 'protected

customers' and a detailed

'emergency rulebook' set forth at

the EU level.

Crisis

management

Systematic discussion of ENTSO-E

Seasonal Outlooks in ECG and follow

up of their results by Member States

concerned.

Monitoring

Systematic monitoring of security of supply in

Europe, on the basis of a fixed set of indicators

and regular outlooks and reports produced by

ENTSO-E, via the Electricity Coordination

Group.

Systematic reporting on electricity crisis

events and development of best practices via

the Electricity Coordination Group.

A European Standard (e.g. for

EENS and LOLE) on Security

of Supply could be developed to

allow performance monitoring

of Member States.

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5.4.

Options to address Problem Area IV (Slow deployment and low levels of

services and poor market performance)

Overview of the policy options

To recap, the drivers in this Problem Area are:

Low levels of competition on retail markets;

Low levels of consumer engagement;

Market failures that prevent effective data flow between market actors.

Each policy option consists of a package of measures that addresses the problem drivers in

a different way and to a different extent. They aim to tackle the existing competition and

technical barriers to the emergence of new services, better levels of service, and lower

consumer prices, whilst ensuring the protection of energy poor consumers.

Box 5: Overview of the Policy Options for Problem Area IV

In the following sub-sections the policy options and the packages of measures they

comprise are described. This section is closed by a table summarising all specific measures

comprising each option.

The relevant annexes addressing the policy options below are: 7.1 to 7.6.

Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer

engagement and poor data flows

Under this option no new legislation is adopted, there are no further efforts to clarify the

existing legislation through guidance, and no additional work through non-regulatory

means to address the problem drivers. It assumes that the future situation will remain more

or less the same as today.

Stakeholders' opinions:

A significant number of stakeholders consider that the level of

competition in retail markets is too low and there is no record of significant support for

current market arrangements and their organic development. The sole exception is on

billing information, where energy suppliers and industry associations indicate that there

may be little scope for EU action to ensure bills facilitate consumer engagement in the

market due to subsidiarity considerations.

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Option 0+: Non-regulatory approach to address competition and consumer

engagement

Under this option, the problem drivers are addressed to the greatest extent possible without

resorting to new legislation. This means strengthening enforcement to tackle cases of the

non-transposition or incorrect application of existing legislation, new Commission

guidance to tackle implementation issues related to difficulties in interpreting the existing

legislation, and examining new soft law provisions to address gaps in the legislation itself.

To improve competition, bilateral consultations are held with Member States to

progressively phase out price regulation, starting with prices below costs. Should it be clear

that Member State interventions in price setting are not proportionate, justified by the

general economic interest or not compliant with any other condition specified in the current

EU acquis

229

, then enforcement action is taken under the existing

acquis

and recent Court

judgements, which require these criteria. Section 7.1.1 of the Evaluation argues that the

regulation of electricity and gas prices limits consumer choice, restricts competition, and

discourages investment.

To improve consumer engagement, the Commission issues an interpretative note on the

existing provisions in the Electricity and Gas Directives covering switching-related fees.

Section 7.1.1 and Annex IV of the Evaluation show that the current framework remains

both complex and open to interpretation with regard to the nature and scope of certain key

obligations.

The Commission works to ensure the dissemination and uptake of the key cross-sectorial

principles for comparison tools. Enforcement action follows. Nevertheless, Section 7.3.5

and Annex V of the Evaluation show that the relevance of the existing legislation is

challenged by the fact that it is not adapted to reflect new ways of consumer-market

interaction, such as through comparison tools.

The Commission also develops a Recommendation on energy bills that builds upon the

recommendations prepared by the Citizen's Energy Forum's Working Group on e-Billing

and Personal Energy Data Management

230

. Section 7.1.1 and Annex V of the Evaluation

show that there is poor consumer satisfaction with energy bills, and poor awareness of

information conveyed in bills. This suggests that there may still be scope to improve the

comparability and clarity of billing information.

Finally, to better protect energy poor and vulnerable consumers

231

, the Commission

establishes the EU Energy Poverty Observatory which will contribute to the sharing of

good practices and strengthens enforcement around existing requirements for National

229

230

231

Article 3(2) of the Electricity Directive and of the Gas Directive

https://ec.europa.eu/energy/sites/ener/files/documents/20131219-e-billing_energy_data.pdf

As a result of the Third Energy Package, Member States have to defined and protect vulnerable

consumers in energy markets. The evaluation of the provisions related to consumer vulnerability found

the definitions of vulnerable consumers to vary widely across Member States. ACER grouped these

definitions in two groups (i) explicit definitions when characteristics of vulnerability are stated in the

definition such as age, income, or health; and (ii) implicit definitions when vulnerability is linked to be

beneficiary of a social support measure. A study commissioned by DG ENER concluded that energy

poverty is usually a narrower term than vulnerability as it mostly refers to lack of affordability of energy

services.

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Regulatory Authorities to monitor disconnection rates

–

an area identified as lacking in the

Evaluation (Section 7.1.1 and Annex III).

However, no action is taken to address the market failures that prevent effective data flow

between market actors. As this involves tackling possible conflicts of interest among

market actors, non-regulatory measures were not deemed appropriate to credibly

addressing this problem driver. Section 7.3.6 and Annex IX of the Evaluation show that

the current legislation was not designed to address currently known challenges in managing

large, commercially valuable consumption data flows.

By tackling regulatory interventions in price setting, this option would enable suppliers to

profitably develop value-added products, thus fostering innovation in energy retail

markets. It would also promote the consumer-driven uptake of such innovative products

by addressing switching fees, unreliable comparison tools and unclear bills

–

each a key

barrier to consumer engagement.

Stakeholders' opinions:

There are no explicit opinions among the stakeholders on a non-

regulatory approach. However, some of the points raised by the stakeholders, like

increased transparency on switching suppliers, exit fees, comparison tools as well as

transparent bills, may be addressed by non-regulatory measures.

Option 1: Flexible legislation addressing all problem drivers

Under this option, all problem drivers are addressed through new legislation that provides

Member States leeway to adapt their laws to the conditions in national markets.

To improve competition, Member States progressively phase out blanket price regulation

by a deadline specified in new EU legislation, starting with prices below costs.

Transitional, targeted price regulation for vulnerable consumers is permitted (e.g. in the

form of social tariffs), allowing a case-by-case assessment of the proportionality of

exemptions to price regulation that takes into account the social and economic

particularities in Member States.

To both improve competition and reduce transaction costs in the market, consumer data

management rules that can be applied independently of the national data-management

model are put in place. These include criteria and measures to ensure the impartiality of

market actors involved in data handling, as well as the implementation of standardised,

national data formats to facilitate data access. These measures aim at eliminating barriers

to entry associated with data access, and helping all market actors provide a higher level

of service to consumers through the efficiencies that information technology offers.

To increase consumer engagement, the use of contract termination fees is restricted. Such

fees are only permissible for the early termination of fixed-term contracts, and they must

be cost-reflective. Consumer confidence in comparison websites is fostered through

national authorities implementing a certification tool for the most useful and reliable

websites in their markets. In addition, high-level principles ensure that energy bills are

clear, easy to understand, and free from unnecessary information, whilst leaving Member

States some scope to tailor billing format and content to national requirements. Certain

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information elements in bills would be mandatory and would need to be prominently

displayed to facilitate the comparison of offers and switching.

232

Finally, to better protect energy poor and vulnerable consumers, an improved, principle-

based EU legal framework to support Member State action on vulnerable and energy poor

consumers is put in place. A generic adaptable, definition of energy poverty based on

household income and energy expenditure is included in the legislation for the first time.

Member States would measure and report energy poverty with reference to household

income and energy expenditure, and NRAs would publish the number of disconnections

due to non-payment

–

figures they should already be collecting under the current

legislation. These actions are taken cumulatively, on top of the non-regulatory measures

on energy poverty described in Section 5.4.3.

These measures build upon the existing provisions on energy poverty in the Electricity and

Gas Directives which state that Member States must adress energy poverty where it is

identified. They offer the necessary clarity about the meaning of energy poverty, as well

as, the transparency with regards to the number of household in energy poverty. Better

monitoring of energy poverty across the EU will, on one hand, help Member States to be

more alert about the number of households falling into energy poverty, and on the other

hand, peer pressure will also encourage Member States to put in place measures to reduce

energy poverty. Since currently available data can be used to measure energy poverty, the

administrative cost is limited

233

. Likewise, the actions proposed do not condition Member

States on their primary competence of social policy, hence, respecting the principle of

subsidiarity.

Taken together, this option would strongly promote innovation on retail markets by

ensuring that new entrants and energy service companies receive non-discriminatory

access to consumer data

–

access that will allow these market actors to develop and offer

the value-added products that (integrated) incumbents have not. A firm commitment to

phase out blanket price regulation would enable suppliers in many Member States to

differentiate their offers to consumers through non-price competition. And by tackling

financial barriers to switching, improving the availability of comparison tools and helping

consumers understand important information in their bills; this option would increase

consumer engagement with the market and the selective pressure for new services.

Stakeholders' opinions:

Feedback indicates that the general principles put forward as part

of Option 1 would likely enjoy broad support amongst stakeholders. The sole exception

would be the measures on billing information, where energy suppliers and industry

associations have stated that there may be little scope for EU action. However, even here,

the general principles proposed in this option would give broad leeway to Member States

to tailor national requirements to the conditions and consumer preferences in each market.

232

233

EPRG Working paper 1515 (2015), "Why

Do More British Consumers Not Switch Energy Suppliers?"

by X. He D. Reiner:

"We conclude that policies which emphasize simplification of energy tariffs,

increasing convenience of switching, improving consumers’ concerns about energy issues, improving

consumers’ confidence to exercise switch are likely to increase consumer activity."

See Annex 7.1, Table 16.

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Option 2: EU Harmonization and extensive safeguards for consumers addressing

all problem drivers

Under this option, all problem drivers are addressed through new legislation that aims to

provide maximum safeguards for consumers and the extensive harmonisation of Member

State action throughout the EU.

To improve competition, Member States progressively phase out all blanket price

regulation, starting with prices below costs, by a deadline specified in new EU legislation,

as per Option 1 (flexible legislation). However, exemptions to price regulation are defined

at the EU level in terms of either: a) a price threshold to be defined based on principles

ensuring coverage of the cost incurred by the energy undertakings above which Member

States may set retail prices; and/or b) a consumption threshold below which household

may benefit from a regulated tariff.

To both improve competition and reduce transaction costs in the market, a standard

consumer data handling model is enforced. This assigns the responsibility for data handling

to a neutral market actor, such as a TSO or independent third-party, eliminating all

possibility of conflicts of interest. Nationally standardised formats are devised to facilitate

data access to all market actors concerned, including cross-border access.

To increase consumer engagement, all switching-related fees are banned, including

contract termination fees. NRAs establish comparison websites to ensure consumers have

access to at least one neutral comparison resource, alongside private sector offerings. In

addition, the format and content of energy bills is partially harmonized through the

inclusion of a standard 'comparability box' that prescriptively presents key information in

exactly the same way in every EU bill.

Finally, to better protect energy poor and vulnerable consumers, a uniform EU framework

to monitor energy poverty and reduce disconnections is put in place. A specific,

harmonised definition of energy poverty is included in EU legislation referring to

households that fall below the poverty line after meeting their required energy needs. In

order to measure energy poverty, Member States survey the energy efficiency of their

national housing stock and calculate the amount of energy, and costs, required to make all

housing comfortable. These survey results are reported to the Commission.

In addition, a host of preventive measures on disconnections are put in place: (i) Member

States are to give all customers at least two months (approximately 40 working days) notice

before a disconnection from the first unpaid bill; (ii) before a disconnection, all customers

receive information on sources of support, and are offered the possibility to delay payments

or restructure their debts; and (iii) the disconnection of vulnerable consumers is prohibited

in winter.

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These actions are taken cumulatively, on top of the non-regulatory measures

on energy poverty described in Sections 5.4.3.

As with Option 1 (Flexible legislation), this option would strongly promote innovation on

retail markets through non-discriminatory access to consumer data, a firm commitment to

phase out blanket price regulation, and by tackling barriers to consumer engagement.

However, any negative impacts to competition resulting from the stronger, and more

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Similar legislation is already in place in 14 Member States.

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costly, safeguards for the vulnerable and energy poor may also reduce the availability of

new services. In addition, Member States may be better suited to design disconnection

safeguard schemes to ensure that synergies between general national social service

provisions and disconnection safeguards are achieved.

Stakeholders' opinions:

Whilst many stakeholders support the objectives Option 2 aims

to achieve, several have flagged reservations regarding the prescriptive approach to

achieving them. In particular, NRAs have voiced their unease over an over-prescriptive

EU billing format, and recommend that the decision on whether or not to allow contract

exit fees is best taken at the national level. NRAs also point out that it is their role to define

the appropriate methodologies for applicable price regulation. Most of the Member States

consider that the model for data handling should be best decided at national level. And

finally, whilst many stakeholders have supported comparison tool accreditation schemes

(Option 1

–

flexible legislation), none have called for government authorities to provide

comparison tools exclusively.

Summary of specific measures comprising each Option

The following table summarizes the specific measures comprising each package of

measures, as well the corresponding specific measure option considered under each high

level option.

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The detailed presentation and assessment of each measure can be found in

the indicated Annex.

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The preferred options for the specific measures set out in the annex are highlighted in the table in green.

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Table 9: Summary of Specific Measures Examined for Problem Area IV

Specific

Measures

Option 0

Baseline

Energy poverty

and

disconnection

protection

(Annex 7.1)

Option 0+

Non-regulatory approach

EU observatory for energy

poverty. Sharing of good

practices and increase efforts

to correctly implement

legislation (Annex 7.1.4

Option 0+)

Option 1

Flexible legislation

Option 2

Harmonization and extensive consumer safeguards

Introducing a specific, harmonised definition of energy

poverty in EU legislation, a comprehensive EU

framework to monitor energy poverty based on an energy

efficiency survey of the housing stock, and a host of

preventive measures to avoid disconnections (Annex 7.1.4

Option 2)

Requiring MS to progressively

phase out price regulation for

households below a certain

consumption threshold to be

defined in new EU legislation

or by MS, with support from

Commission services

(Annex 7.2.4 Option 2a)

Requiring MS to phase

out below cost price

regulation by a

deadline specified in

new EU legislation

(Annex 7.2.4Option

2b)

Sharing of good

practices(Annex 7.1.4

Option 0)

Introducing a generic adaptable, definition

of energy poverty in EU legislation, and

setting an EU framework to monitor

energy poverty (Annex 7.1.4 Option 1)

Price regulation

(Annex 7.2)

Making use of existing acquis to continue bilateral

consultations and enforcement actions to restrict price

regulation to proportionate situations justified by manifest

public interest

(Annex 7.2.4 Option 0)

Requiring MS to progressively phase out

price regulation for households, starting

with prices below costs, by a deadline

specified in new EU legislation, while

allowing transitional, targeted price

regulation for vulnerable customers

(Annex 7.2.4 Option 1)

EU data management rules that can be

applied independently of the national data-

management model (Annex 7.3.4 Option

Flexible legislative measures to further

limit switching-related charges,

establishing a certification scheme to

improve consumer confidence in

comparison tools, and making information

in bills clearer through minimum content

requirements (not format) (Annexes 7.4.4,

7.5.4 and 7.6.4 Option 1)

Data

management

(Annex 7.3)

Member States are primarily responsible on deciding roles

and responsibilities in data handling (Annex 7.3.4 Option 0)

A standard EU data management model (data hub)

(Annex 7.3.4 Option 2)

Consumer

engagement

(Annexes 7.4, 7.5

and 7.6)

Lacklustre consumer

engagement persists,

diminishing the demand

for new services and

competitive pressure in the

market

Improved EU guidance and

Recommendations on

switching-related charges and

comparison tools (Annexes

7.4.4, and 7.5.4 Option 0+)

Outlawing all switching-related charges, making all

national authorities offer (or fund) an independent

comparison tool, and full EU harmonization of the

presentation of certain information in bills (Annexes

7.4.4, 7.5.4 and 7.6.4 Option 2)

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SSESSMENT OF THE IMPACTS OF THE VARIOUS POLICY OPTIONS

This section assesses the impacts of the options under each Problem Area. The analysis focuses

on the broad impacts of those options. The impacts of the specific measures included in each

option are assessed in more detail in separate annexes attached to this impact assessment.

Each option was assessed both quantitatively and qualitatively, in an effort to capture at the

highest possible detail the impacts of the underlying measures within each option. When

reliable quantitative analysis or information was not available, the assessment could only be

performed qualitatively, based on specific criteria.

6.1.

Assessment of economic impacts for Problem Area I (Market design not fit for an

increasing share of variable decentralized generation and technological

developments

Methodological Approach

6.1.1.1.Impacts Assessed

The market design options are examined on the basis of their effectiveness in addressing the

identified problems and achieving the desired objectives, while at the same time facilitating the

delivery of the 2030 climate and energy targets

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in a cost-efficient and secure way for the

whole of Europe.

As the examined measures focus on the better functioning of the electricity markets

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economic impacts are in particular analysed with respect to competition, cost-efficiency, better

utilization of resources, as well as impacts on security of electricity supply.

The effect of the measures on the wholesale markets will induce indirect social impacts and

have limited effect on innovation and research. The effects of energy market related polices on

employment are primarily associated with the policy measures seeking to secure the

achievement of the 2030 decarbonisation objectives

238

. They will therefore not be assessed in-

depth for all options.

Some indirect environmental impacts are also expected, due to the different types of fuel used

for power generation, as a well-functioning flexible electricity market would incentivize the

increase of low carbon generation.

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237

238

See:

http://ec.europa.eu/clima/policies/strategies/2030/index_en.htm

Note that these options are not touching the issue of investment, which is examined under Problem Area II.

Therefore the same power generation mix is assumed for all options.

Reference is hence made to the impacts assessments for the EE and RED II initiatives and the one elaborated

in the context of Communication from the Commission to the European Parliament, the Council, the European

Economic and Social Committee and the Committee of the Regions, "A

policy framework for climate and

energy in the period from 2020 up to 2030"

(SWD(2014) 15 final)

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Other significant impacts, direct or indirect, are not expected for the examined options, unless

specifically noted.

The assessment is presented individually for each option, with qualitative analysis and

interpretation of quantitative results. Summary tables reporting the modelling results for all

options are included in section 6.1.6.

6.1.1.2.Modelling and use of studies

For most of the quantitative analysis, the METIS

239

modelling software was used to underpin

the findings on the impact of the different options. METIS is a modular energy modelling

software covering with high granularity (geographical, time) the whole European power system

and markets. Simulations adopted a Member State-level spatial granularity and an hourly

temporal resolution for year 2030 (8760 consecutive time-steps per year), capturing also the

uncertainty related to demand and RES E power generation.

For consistency with all parallel European Commission work on the 2030 Energy and Climate

Framework, in the Red II, EE and Effort Sharing Regulation impact assessments, METIS was

set-up (calibrated) such as to reflect as close as possible

240

the year 2030 projection of the power

sector in the PRIMES EUCO27 scenario. The PRIMES EUCO27 scenario

241

, built on the EU

Reference Scenario 2016, ensures a cost-efficient achievement of at least 40% GHG reduction

(including agreed split of reductions between ETS and non-ETS), 27% RES and 27% EE target.

A stand-alone analysis of the impact of potential policies promoting downstream price and

incentive based demand response, at all customer segments (industrial, commercial,

residential), has also been undertaken (detailed information hereon can be found in Annex 3.1).

The options analysed looked at how to reach the full potential of demand response in order to

reduce overall system costs, considering (i) both price and incentive based demand response,

and their combination, as well as (ii) the level of access of demand service providers to the

market (access rules and incentives), and (iii) customers' ability to react (by means of access to

required technologies-smart metering, tariff structures and knowledge) for engaging in price

based demand response. The analysis focused on the assessment of the theoretical potential of

demand response, based on the nature of the electricity use/ability to shift demand by different

clusters of consumers, its current level, and how the different options are likely to increase the

share of the theoretical potential being realised, as well as in the estimation of associated cost

and benefits.

6.1.1.3.Summary of Main Impacts

Figure 8 below summarizes the annual quantified benefits of the assessed options for 2030

242

as presented in detail in sections 6.1.2 to 6.1.5. It illustrates the significant benefits of the

239

240

241

242

A detailed description of the METIS model can be found in Annex IV, including details on the implemented

modelling methodology.

A detailed description of the METIS calibration to PRIMES EUCO27 can be found in Annex IV.

More details on the methodological approach followed concerning the baseline, on EUCO27, as well as on

the coherence with the scenarios of all parallel initiatives can be found in Annex IV.

All impacts were assessed for one full year (8760 hours) reflecting projected situation in 2030. Reported

figures are in annual real terms (€'13).

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measures under Options 1 to adapt the market design, with annual savings in 2030 of EUR 5.9

billion only for Sub-option 1(a) (level playing field), EUR 8.6 billion for 1(b) (strengthening

short-term markets) and EUR 9.5 billion for Sub-option 1(c) (demand response/distributed

resources). For Option 2 (fully integrated market) the calculated benefits would amount to EUR

10.6 billion.

Figure 8: Annual cost savings for Problem Area I in 2030 by option

Source: METIS

6.1.1.4.Overview of Baseline

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(Current Market Arrangements)

244

Under the baseline, the power system in 2030 relies heavily for energy on RES E generators,

as well as conventional generation which is to a large degree inflexible. In particular, the share

of RES E in electricity generation has almost reached 50%, thus being equal to the share of all

other conventional generation together (i.e. gas, coal, lignite, nuclear, oil). The share of variable

generation (solar and wind) in total generation approaches 30% across Europe. Concerning

conventional generation, nuclear holds a 22% share, coal and lignite a 15% share, and natural

gas 13%. The respective shares tend to differentiate across EU regions, based on the

particularities of each region (Figure 9).

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244

The assumptions concerning the baseline can be found in Section 5.1.2 and in Annex IV.

Although all modelling work was based on the PRIMES EUCO27, the PRIMES scenario has as a basic

assumption the existence of well-functioning competitive markets. As this is the ultimate goal of the assessed

measures, the baseline departs form EUCO27, reflecting the observed distortions or inefficiencies of current

market arrangements.

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Figure 9: Shares of Electricity Generation per Region

245

in EU in the Baseline

Region 5

Region 4

Region 3

Region 2

Region 1

10%

Region 1

Variable RES

Generation

Hydro

Biomass, Waste

& Other RES

Gas

Oil

Solids

Nuclear

27%

10%

21%

27%

20%

30%

Region 2

14%

49%

18%

40%

50%

Region 3

34%

15%

24%

22%

60%

70%

Region 4

48%

19%

12%

14%

80%

90%

100%

Region 5

29%

19%

20%

17%

Source: METIS

A number of rules affecting dispatch remain in place, most notably priority dispatch

246

for RES

E and that certain technologies are considered as must-run

247

, reflecting current practices and

nominations in the market. In fact special dispatch rules concern 60% of total installed capacity

(752 GW on a total of 1,247 GW).

245

246

247

For the modelling purposes, an indicative split of Europe into five regions was made as follows (Cyprus was

excluded as assumed not directly interconnected to the rest countries):

Region 1 (CE):

Austria, Belgium, Czech Republic, Demark, France, Germany, Hungary, Luxembourg,

Netherlands, Poland, Slovakia, Slovenia

Region 2 (NEE):

Estonia, Finland, Latvia, Lithuania, Sweden and Norway.

Region 3 (NWE):

Ireland and UK

Region 4 (SWE):

Portugal and Spain

Region 5 (SEE):

Bulgaria, Croatia, Cyprus, Greece, Italy, Malta, and Romania

In "Evaluating

the impacts of priority dispatch in the European electricity market",

Oggioni et al (2014), show

using a stylized model that significant increase of wind penetration under priority dispatch can cause even the

collapse of the EU Target Mode. Test-runs performed using METIS came to a similar conclusion. Initial runs

lead to significant hours of loss of load for many MS. In order to resolve this issue a "softened" definition for

priority dispatch was assumed for the modelling, allowing the curtailment of units (which should not be

normally the case under priority dispatch) but at a cost.

In general, when scheduled in day ahead, must-run units cannot be decommitted during intraday and are

required to operate at least at their technical minimum level. For the scope of the modelling, coal and lignite

units were assumed as being must-run in the baseline. Day-ahead scheduling was assumed though always

optimal (so only units with priority dispatch were assumed to disrupt the economic merit order in day-ahead,

namely biomass) for each national market, which may not be true in practice due to nominations, scheduling

practices, etc. Modelling performed with PRIMES/IEM, results presented in Section 6.2.6.1, captured also the

effect of nominations and other practices in the baseline.

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Figure 10: Projected Generation Capacity in 2030 per Member State in GW

248

250

Nuclear

200

Solids

Oil

150

Gas

100

Biomass, Waste

& Other RES

Hydro

Variable RES

Generation

Source: METIS

Another factor reducing the flexibility of the European power system is the limited allocation

of interconnection capacity during intraday and balancing time frames, as well as the varying

gate closures and products, which in practice reduce the opportunities for trading in the short-

term markets and thus their liquidity.

Reserves are procured on a national level and in many cases in infrequent intervals

249

, with

corresponding services mainly provided by (large) thermal generators and only in some

Member States by industrial consumers.

Demand response, storage (excl. hydro) and distributed generation have very limited

participation in the market. In most cases available products are not customized for these

resources, minimum thresholds exist for participating in the market, etc. At the same time, a

large part of the generation, mainly RES E, are not balance responsible and do not have a strong

incentive to perform accurate forecasts and declare accurate schedules in the day-ahead market

(the share of variable generation is about 42% of total generation capacity). As a consequence,

the observed imbalances are large, leading to increased needs for frequency reserves.

The deficiencies of the current regulatory framework create significant inflexibility to the

system operation; the inflexibility in turn increases further the need for reserves (notably so-

called replacement reserves)

250

. Close to real-time, the TSOs can mainly rely either on units

248

249

250

Please note that the assumed generation capacities in the baseline have certain differences compared to the

ones in EUCO27 PRIMES scenario, as a preliminary version of EUCO27 was used for the calibration. Further

details can be found in Annex IV.

For the scope of the modelling, a yearly procurement by (large) thermal generators and hydro has been

assumed for countries with no reserve market, while daily optimal procurement is modelled in countries with

such markets. More details can be found in Annex IV and in

"Electricity Market Functioning: Current

Distortions, and How to Model Their Removal"

COWI (2016).

It should be emphasized that METIS does not include a grid model. Thus the main use of replacement reserves

('RR'), to address grid (non-frequency related) issues, is not captured. The implemented methodology can only

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providing replacement reserves or on very flexible (and expensive) units to avoid loss of load

(peakers). In this context, in METIS replacement reserves provide than 600 GWh of electricity

in the baseline, mainly in Poland and South East Europe. The same applies for RES E

curtailment, as curtailment is the only alternative to the encountered stress of the system and

the lack of available flexible resources: 13.0 TWh of RES E is found to be curtailed on an

annual basis, mainly in the Iberian Peninsula (8.3 TWh) and UK/Ireland (4.1 TWh).

Policy Sub-option 1(a) (Level playing field amongst participants and resources)

6.1.2.1.Economic impacts

The restoration of the economic merit order curve in the wholesale electricity market has a

direct and

significant positive impact

to the cost-efficient operation of the power system,

leading to tangible reductions of the costs consumers. It would also allow to feed in (and

remunerate from the market) more RES E (notably from wind and solar) to the system.

With special rules concerning unit dispatching eliminated (i.e. must-runs, priority dispatch), the

TSOs are able to schedule and re-dispatch units more efficiently. As a result (in conjunction

with the other measures under this option):

total costs of the power system are reduced by 7%;

the activation of replacement reserves is reduced by about 500 GWh;

RES E curtailments (e.g. wind and solar) decline by 4.7 TWh

251

; and,

the occurrence of negative prices is completely eliminated

252

Figure 11 - which presents the merit order

253

at a given hour - illustrates how preferential

dispatch rules for certain technologies shift the merit order to the right, resulting in price

decreases but at the same time in an increase of the overall costs for the system. The example

shown for biomass priority dispatch is also applicable for must-runs and priority dispatch of

other (expensive) technologies. Restoring the economic merit order thus reduces the overall

costs for the power system at times where these technologies would be out-of-the-money, while

increasing the electricity price during these hours.

251

252

253

be considered as a proxy in an effort to capture a part of the impacts of RR. As some of the scenarios (Options

0 (baseline) and 1(a)( level playing field)) were characterised by important values of Loss of Load during the

intraday time frame, it was assumed that this was addressed by replacement reserves. To compute the costs

related to RR, first the intraday loss of load curve was identified at country level and then the amount of peaker

capacity needed to bring the Loss of Load duration down to 3 hours in each country was computed. A cost of

60k EUR/MW/y for peaker units and fuel costs of 180 EUR/MWh was assumed.

From a system perspective, it can sometimes be economical to reduce the generation of wind and solar in

order to maintain the system balance.

This result is directly linked with the modelling assumption that all electricity is traded in the market.

Each generation fleet is represented as a block, as large as its power capacity and as high as its generation

cost. Without distortions, the market dispatches the lowest (cheapest) blocks until demand is met. The

generation cost of the most expensive dispatched power plant sets the clearing price.

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Figure 11: Merit order effect of priority dispatch

With

biomass priority dispatch

Without

biomass priority dispatch

Source: METIS

Focusing on priority dispatch, which was found to be the main distortion for the day-ahead

market scheduling for the modelling

254

, the biggest impacts on generation would be observed

in Denmark, UK and Finland, where biomass holds a large share of generation capacity. The

removal of priority of dispatch would have a considerable effect on expensive biomass

production

255

, which in most cases is dispatched out of the merit order. It can also be expected

that the share of CHP generation would be negatively affected, due to the relatively inflexible

character of CHP production

256

. On the other hand, removing priority dispatch rules would

benefit variable RES E which could expand its production (due to the reduction in curtailments).

More importantly, variable RES E producers could significantly increase their revenues due to

the increase of the wholesale prices (partly due to the elimination of negative prices)

257

. Overall,

the removal of priority dispatch and must-runs helps better integrating variable RES E

generation and leads to significant system costs reductions and thus cost savings for consumers.

254

255

256

257

Data availability on must-runs, nominations and other practices affecting the day-ahead schedule, leading to

an operation of the system deviating from the economic merit order, was very limited and thus were not

captured by the model. The impacts of must-runs were captured however for the intraday market and amounted

to around EUR 0.5 billion.

The Commission's study indicates that up to 85% of biomass generation could be affected by removing priority

dispatch. This result is also partly due to the assumption of having only one fuel for biofuel/biogas, this being

exclusively wood, rendering biomass very expensive. Note also that the analysis focuses on electricity

dispatch and does not examine why would a biomass (or any other) plant want to operate with losses in the

wholesale market (most likely an additional revenue stream like income from selling heat or some kind of

operational support would be required), as is often the case today. A more complete analysis of this result is

presented under environmental impacts, Section 6.1.6.

As part of the limitations of the modelling, one should note that the effects of removing priority dispatch from

CHP are not captured in the assessment. In particular CHP and small scale RES E are not modelled as separate

assets. It can be expected though that the results on biomass would be applicable also to a large part of the

CHP generation, unless they are able to recover their losses from the heat market or are industrial CHP, in

which case industrial opportunity costs need to be considered.

Because of biomass' assumed flexibility, a part of the lost revenues is recovered from its participation in

reserve procurement and balancing energy activation

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Figure 12: Effect of removal of special dispatch rules to negative prices

Source: METIS

The above also leads to an increase of the share of Combined Cycle Gas Turbines ('CCGTs') in

power generation

258

. RES E generation enters the market merit order, thus catering for more

efficient price formation in the day-ahead and intraday markets. The removal of priority

dispatch will offer access on equal terms to all resources. Moreover, it will more than double

the competitive segment of the market, which in the baseline was only 40% of the market.

As more resources participate under the same competitive rules in the markets, markets would

become more competitive

259

. This implies an increase in wholesale prices as they will now

reflect the actual marginal cost of generation instead of one technically lowered via rules

affecting dispatch

260

. As a result, this will lead to a much more cost-efficient operation of the

power system, and consequently to a 7% decrease of its total cost.

Finally, the extension of balance responsibility to all generating and consuming entities, offers

a strong incentive for variable RES E and other balance responsible parties to improve their

forecasting, bid more accurately in the day-ahead market and be more active in the intraday

markets. This leads to smaller imbalances and a lower requirement for reserve procurement by

the TSOs. In particular the needs for mFRR are reduced by around 30%. This, combined with

the capability of the demand response to also participate

261

in the reserve procurement and

balancing markets, leads to a more cost-efficient reserve procurement process.

258

259

260

261

Share of CCGT in total net electricity generation increases from 12.3% to 15.1%.

See for a more detailed discussion of the arguments for and against maintaining priority dispatch in Annex 1.

The elimination of the significant hours with negative prices also contributes to the increase of the average

wholesale price.

Note though that as no measures are assumed to be implemented here for incentivizing the wider participation

of demand response, only industrial consumers are assumed to be participating in the respective markets.

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6.1.2.2.Who would be affected and how

Abolishing priority dispatch and priority access would mainly affect RES E producers using

biofuels and CHP

262

and operators that benefit from priority dispatch when producing using

indigenous resources fuels (if their marginal costs are substantial). For low marginal cost,

variable generators, such as wind and solar power plants, the impact is actually positive, which

will be amplified by measures to enable RES E access to ancillary services markets.

In any event, all generators will benefit from increased transparency and legal certainty on

redispatch and curtailment rules. For TSOs, the removal of priority dispatch and priority access

would also facilitate grid operation.

Introducing balancing responsibilities (with exemption possibilities for emerging

technologies

263

and or small installations

264

) will mainly impact generators currently exempted

or partly shielded from balancing responsibility. Accordingly, this measure will mean they have

to increase their efforts to remain in balance (e.g. through better use of weather forecasts)

though at the costs of being exposed to financial risks.

6.1.2.3.Administrative impact on businesses and public authorities

The removal of priority dispatch, priority access and ensuring compliance with the balancing

rules would give rise to administrative impacts for RES E (and CHP) generators, in particular

for operators of very small installations. This administrative impact can however be

significantly reduced by facilitating aggregation, allowing the joint operation and management

of a large number of small plants (as discussed in more detail under Option 1(c)).

Impacts of Policy Sub-option 1(b) (Strengthening short-term markets)

6.1.3.1.Economic Impacts

Strengthening short-term electricity markets improves market coupling across time-frames,

leads to a more efficient utilization of interconnector capacity and reduces the amount of

required reserves, as well as their cost.

The efficiency of the intraday markets is improved due to the harmonization of their market

specifications, including the transition to continuous trade and harmonisation of gate closures,

as well as by an improved allocation of interconnector capacity across time-frames.

Harmonising intraday markets across Europe

265

allows to further reduce RES E curtailment by

460 GWh and the utilisation of replacement reserves by 100 GWh. Note that curtailment is not

only reduced in countries where implicit auctions were not implemented in Option 1(a) (level

262

263

264

265

As part of the limitations of the modelling, one should note that the effects of removing priority dispatch from

CHP are not captured in the assessment. See also footnote 254.

In the PRIMES EUCO27 scenario, the emerging technologies of tidal and solar thermal generation (other

technologies having insignificant shares) are projected to have a total installed capacity of 7.26 GW (0.7% of

total generation capacity) and produce 10 TWh of electricity in 2030 (0.3% of total generation).These shares

only slightly increase by 2050.

In the PRIMES EUCO27 scenario, RES E small-scale capacity is projected in 2030 to reach 85 GW (7.8 %

share in generation capacity) and produce 96 TWh of energy (2.9% share of total generation).

Continuous trading was modelled as consecutive hourly implicit auctions.

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playing field), but in already implicitly coupled regions too. Thus, extending the coupled area

also benefits already coupled countries such as Germany, since it can export more of its variable

RES generation. The effects are illustrated in Figure 13.

Figure 13: Positive impacts of harmonising intraday markets across Europe

266

Source: METIS

By improving the methodologies for reserve dimensioning and procurement of balancing

reserves, the need for balancing reserves is further reduced compared to Option 1(a). Certain

improvement comes from the separation of the bids and prices for up and down regulation in

order to reflect their true underlying marginal costs, which may be different both for generation

and load

267

. The separate provision of downwards reserves greatly improves the efficiency of

the system, as now thermal plants are not forced to be online to provide such reserves. Another

means is via the procurement of reserves on a day-ahead basis, thus their sizing being able to

reflect the hourly needs for these services, while at the same time allowing the most efficient

resources at a given hour to be procured as reserves by the TSO.

The reduction in the reserve needs though is mainly achieved by the regional reserve

dimensioning and more efficient exchange and sharing of balancing capacity among TSOs, as

the generation and consumption patterns differs between Member States according to the

generation mix, renewable energy sources and differences in energy consumption. Thus, the

79.6 GW of reserve needs (FCR + FRR) in Option 0, is reduced to 65.8 GW in Option 1(a)

The figures presented in this paragraph show the impact of implicit intraday auctions only. Other measures of

Option 1(b) (strengthening short-term markets), in particular interconnection reservation at day-ahead for

reserve procurement, tend to increase intraday costs.

267

Although the separation of upward and downward balancing was initially foreseen for this initiative, and thus

assessed herein, it may be introduced earlier in the EB GL.

266

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(level playing field) and to only 42.3 GW in Option 1(b) (strengthening short-term markets) (a

reduction of 47% compared to the baseline).

It is important to note that the reduction in FRR

268

is stronger in the well-interconnected regions

(about 50% reduction), namely Central Europe, the Nordics and South / South East Europe,

while the benefits for UK/Ireland and Spain/Portugal are smaller due to their limited

interconnection (about 20% reduction). In order to achieve these reductions from the sharing of

reserves, the Member States need to ensure that sufficient interconnection capacity is reserved

for this purpose, in order to ensure that despite the lower reserve requirements, the national

ability to balance the system remains the same

269

. The amount of capacity that needs to be

reserved for this purpose is on average approximately 6%

270

of the Net Transfer Capacities

('NTCs'), with actual values varying significantly per interconnector and per hour of the day.

Similarly, different market areas have different access to flexible resources and such flexible

resources are vital to the cost-efficient integration of renewable electricity generation. TSOs

may not only procure smaller volumes of reserves but providers of relatively cheap flexibility

resources may supply a larger volume thereof. Hence, overall balancing market payments are

reduced, while at the same time more interconnection capacity can be given to the market by

reducing transmission reliability margins ('TRMs').

An interesting observation coming from the assessment is the increased generation by baseload

thermal plants, compared to more flexible thermal plants. In particular, the electricity

generation of nuclear, CCGTs, coal and lignite plants increases by 10%, while the generation

of gas and oil peakers reduces by 50% compared to the baseline

271

. The reason is that by sharing

resources between countries and decreasing reserve needs, the baseload plants do not need to

retain part of their capacity on stand-by for supplying reserves and thus can increase the

quantities of energy they generate. At the same time, though, flexible plants end up competing

for reduced amounts of reserve needs, thus their revenues are significantly reduced compared

to Option 0 (baseline) and Option 1(a) (level playing field)/ Therefore, better interconnecting

268

269

270

271

Both mFRR and aFRR

Adopting a regional approach to reserve dimensioning results in lower reserve requirements because of the

statistical cancellation that can occur between imbalances originating from different countries. As a result the

reserve needs are lower when adopting a regional dimensioning approach. The regional reserve need is then

translated into minimal reserve requirements at national level by using an allocation criteria (in METIS case

the national annual demand). However a national TSO still has to face the same level of risk - the imbalances

on its Control Area remain the same

–

and the minimal reserve requirements may not be sufficient to balance

its system. As a consequence, national TSOs have to reserve a share of the interconnection capacity for

reserves, so that the other countries can assist it to balance the system. METIS does not explicitly model

reserve exchanges, but risk pooling.

Considering that for Option 1(b) an assumption was made that the NTC capacities were increased by 5%,

reflecting e.g. the reduced TRM compared to Option 1(a) due to the increased co-operation between MS via

ROCs, it is interesting to notice that the average capacity that needs to be reserved for sharing balancing

reserves is around the same level. On the other hand this does not signify something, as the averaging hides

the huge variability among hours and interconnectors.

It should be noted that the analysis excludes the effect that increased generation by thermal plants would have

on the carbon market and how this in turn would indirectly impact electricity generation.

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markets and making them more flexible serves as a second option for bringing more flexibility

into the system, complementary to but also competing with flexible generation plants.

Enhancing TSO regional coordination through the establishment of regional operational centres

and by optimising market, operational, risk preparedness and network functions from the

national to the regional level will entail significant efficiency gains and increase social

welfare.

272

For example, the regional sizing and procurement of reserves via ROCs could lead

to benefits of EUR 3.4 billion compared to benefits of EUR 1.8 billion from national sizing and

procurement of reserves based on daily probabilistic methodologies.

273

Significant welfare

benefits would,

inter alia,

derive from the more efficient use of infrastructure and from a

decrease of financial losses that would otherwise result from the disconnection of demand in

case of generation shortages.

6.1.3.2.Who would be affected and how

Improving short-term markets will affect all generation operators to a certain extent but it will

in particular improve the ability of

variable RES E operators

to participate in the market.

Improving intraday and balancing markets would impact the work of the

TSOs

and

Power

Exchanges,

because of their involvement in the operation of these markets. On the one hand

this will require operating the system and organising trade within shorter timeframes. On the

other hand, the shorter timeframe will allow TSOs to benefit from significant efficiencies and

to reduce the risk of system problems.

TSOs

will also be affected through the need to

collaborate closer with neighbouring TSOs through ROCs and through the changes to the

balancing markets which they operate. This has the positive effect of requiring TSOs to consider

systematically the impact of their actions on their neighbouring TSOs.

6.1.3.3.Administrative impact on businesses and public authorities

The administrative impact on

businesses

is marginal as compared with the baseline.

Power exchanges

and

TSOs

would have to review and adapt their business practises to

facilitate the changes to the market functioning as envisaged under this option. Notably,

changes will have to be made to trading arrangements for intraday and balancing products.

TSOs would collaborate through ROCs, which will have to be set up. The setting up of the

ROCs can be estimated to cost between 9.9 and 35.6 million Euros per entity, depending on the

functions and degree of responsibilities attributed to the ROCs.

274

Whereas these costs are not insignificant, these costs of several million Euros (which would be

covered and compensated by grid fees) are minor when compared with the benefits this option

will bring.

272

273

274

For more information on the assessment of the economic impact of ROCs, please refer to Table 2 of Annex

2.3 of the Annexes to the Impact Assessment.

"Integration

of electricity balancing markets and regional procurement of balancing reserves",

COWI (2016).

"Integration

of electricity balancing markets and regional procurement of balancing reserves",

COWI (2016).

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Impacts of Policy Sub-option 1(c) (Pulling demand response and distributed resources

into the market)

6.1.4.1.Economic Impacts

The series of measures assumed in this Option include (i) the adaptation of balancing products

closer to what distributed resources like demand response, variable RES and small scale storage

can provide, (ii) the facilitation of the participation of distributed resources in the market mainly

via aggregators and (iii) stronger incentives for the roll-out of smart-meters. These measures

significantly improve the efficiency of the market and the reduce costs.

The market set-up under Option 1(c) provides the opportunity to variable RES E to better

manage their imbalances due to forecast errors at lower cost (due to more competitive prices),

but also to receive additional revenues for any flexibility they can provide to the market.

Similarly, demand is offered the incentives and capability to respond to market prices and thus

complete existing electricity markets. This can be achieved by either shifting load from hours

of peak demand to hours with low demand (e.g. via storage or changing consumption partterns)

or by simply adjusting consumption (when load cannot be shifted or is not really needed)

275

Available data coming from a standalone analysis

276

performed on the impact of potential

policies promoting downstream price- and incentive-based demand response, at all customer

segments (industrial, commercial, residential), show that demand response can be of great

service, and deliver net benefits to the system as a whole while engaging all consumer segments.

More in particular, it has been demonstrated that demand response schemes can lead to a

reduction of the peak demand and thereby of the required backup capacity in both the

transmission and distribution networks. This also translates into lower investment needs.

The analysis has shown that in a business as usual scenario (reflected in Option 0) demand

response can account for approximately 34 GW, of which 19 GW will come from incentive and

15GW from price based demand response. With a supporting policy framework in place, as in

Option 1(c), demand response can account for approximately 57 GW in 2030, of which 39 GW

will come from incentive and 18 GW from price based demand response.

Allowing small-scale producers, storage and consumers to participate in the market, e.g.,

through aggregated bids, creates incentives for demand side response and flexible solutions,

pulls the above potential in the market and creates a more dynamic market. New flexible

resources are made available for reserve procurement and balancing market. These resources

bring significant short-term and mid-term flexibility

277

to the system, contributing to the more

efficient handling of scarcity situations and integrating variable RES E. This abundance of

275

276

277

As part of the limitations of the modelling approach, these benefits were not fully assessed because of data

unavailability. Therefore the same load profile was used, based on the ENTSO-E’s

TYNDP assumptions,

without being known at which extent it already included some DR (at least for EV charging)

See Annex 3.1 and "Impact

Assessment support Study on downstream flexibility, demand response and smart

metering",

COWI (2016).

For more details on the flexibility needs of the system and how storage, interconnections and demand response

can answer such needs please see "METIS

Study S7: The role and need of flexibility in 2030. Focus on Energy

Storage",

Artelys (2016).

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available resources significantly reduces the cost of the power system and, most importantly,

the load payments to EUR 253 billion, from EUR 278 billion in the baseline and EUR 293

billion in Option 1(a).

These reported savings

278

are mainly a result of a significant shift in the provision of reserves

from thermal plants to demand side response (incl. storage) and wind. For example, while in

Option 1(b) (strengthening short-term markets), gas was providing about 20 GW of reserves,

hydro 19 GW and coal 3 GW, under Option 1(c) demand response partly replaces the above

plants by providing 5 GW of reserves. In particular demand response and small scale storage

(electric vehicles and heating storage) become the main providers of upward synchronized

reserves, providing 33% of corresponding needs

279

. Wind provides an additional 90 MW of

upwards synchronized reserves and 330 MW of downward synchronized reserves.

6.1.4.2.Who would be affected and how

The new provisions opening up the markets to aggregated loads and demand response will bring

business opportunities for aggregators, new energy service providers, and suppliers who choose

to expand their portfolio of services, but will also affect generators who are likely to face

reduced turnover from lower peak prices and from providing reserves.

Furthermore, demand side flexibility, along with access to real time data coming from smart

metering, will help the network operators optimise their network investments and cost-

effectively manage their systems. In the case of TSOs, it also allows for the better calculation

of settlements and balancing penalties based on real consumption data. On the other hand,

suppliers may face higher imbalances and resulting penalties as their customers change

consumption patterns.

Finally, end consumers are expected to benefit from more competition, access to wider choice,

and the possibility to actively engage in price based and incentive based demand response, and

hence from reduced energy bills. Even those end users who choose not to participate in demand

response schemes could still profit from lower wholesale prices that result from demand

response, assuming that the respective price reductions are passed on to consumers.

Box 6: The possibility of large-scale grid disconnection

Looking forward, our modelling (the EUCO27 scenario) shows a continuation of the general

trend of rising retail electricity prices through to 2030, stabilising from 2035 onwards. Given

the decreasing costs of small-scale renewable generation and storage technologies, concerns

have been raised that this trend could result in a growing number of prosumers becoming self-

278

The proposed measures are expected to also have an impact on the day-ahead market, but as explained in Annex

IV this was not possible to assess due to the lack of sufficient detailed data. Benefits from load shifting or load

reductions were not assessed with METIS due to the lack of a dynamic profile for demand and storage, which

would better capture the reactions of demand to market prices. These impacts were captured though with

PRIMES/IEM, results presented in Section 6.2.6.1. The benefits of demand response and its full potential is

analysed in more detail in Annex 3.

279

The analysis shows the demand response does not provide any downwards balancing at all (by increasing

demand when needed), as this is provided at a much lower cost by RES and conventional generation (by

decreasing generation and saving fuel costs). This result is subject to the limitations of the modelling that does

not use dynamic load profiles for demand and storage. Therefore the relevant benefits are most likely

underestimated in the assessment.

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sustainable and disconnecting from the electricity network

–

a development that could have

several consequences.

On the one hand, this potential 'flight from the grid' could see the remaining connected

ratepayers bear an increasing share of the burden of contributing to public finances and

financing the electricity network. On the other, grid costs may actually fall as distributed

generation and storage assets enable network operators to more efficiently manage the grid and

connect remote customers.

Predicting the full extent and implications of this trend is difficult given the current

uncertainties, including regarding future cost reductions in small scale renewables and storage

technologies, and the lack of real-world case studies. Nevertheless, our analysis suggests that

this development will be progressive, and that the risks of large scale disconnections are limited

given the difficulties of achieving complete self-sufficiency throughout the year.

In particular, even if decentralised generation and storage becomes competitive, it is

questionable whether self-sufficient prosumers will fully disconnect from the grid.

Disconnecting would imply losing the grid as back-up for when their own generation is

inadequate (e.g. for sustained periods of low sunlight). It would also mean that prosumers

forego the opportunity to sell excess electricity to the market (e.g. during prolonged sunny

periods when their installed storage is at full capacity). This is one of the reasons why the MDI

aims at ensuring full access of prosumers to electricity markets.

It should be added that the discussion of disruptive large scale disconnections is not only

connected with distributed resources but to the perception that consumers are increasingly

confronted with perverse incentives and hidden subsidies. To address this, the initiative includes

measures that should lead to more cost-reflective distribution tariffs i.e. tariffs that allocate the

costs of the grid fairly amongst system users. Cost-reflective tariffs will send the right long-

term economic signals to system users and allow a market-driven move towards a more efficient

electricity system, which will contribute to limiting network tariffs and lead to investments that

are economically rational and efficient.

What is certain is that public authorities and network operators will have to adapt in order to

effectively manage the challenges of any transition towards a more decentralized electricity

system, and make the most of the opportunities this presents. Completely self-sufficient

consumers who do not wish to be connected to the grid should not contribute to the grid costs.

6.1.4.3.Impact on businesses and public authorities

The measures proposed to enable the uptake of demand response are designed to reduce market

barriers for new entrants and provide them with a stable operating framework. This is

particularly important for start-ups and small and medium-sized enterprises ('SMEs') who

typically offer innovative energy services and products. However, these measures may

introduce an additional administrative impact for Member States and their competent

authorities that will be required to clearly define in such a new setting: (i) roles and

responsibilities of aggregators, as well as (ii) arrangements for consumers' entitlement to

participate in price based demand response schemes, including their access to the enabling

smart metering infrastructure. At the same time, access to smart metering will support consumer

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engagement, with better informed and more selective consumers also making it easier for NRAs

to ensure proper functioning of the national (retail) energy markets

280

Moreover, thanks to the wider deployment of smart metering, the distribution system operators

will be in a position to lighten, and improve, some of their administrative processes (linked to

meter reading, billing, dis/re-connection, switching, identification of system problems,

commercial losses), and offer increased customer services

281

. Similarly, transmission system

operators will optimise their settlement and balancing penalty calculations, as they can make

use of real time data coming from smart metering

282

Impacts of Policy Option 2 (Fully integrated EU market)

6.1.5.1.Economic Impacts

By creating a centralised, fully integrated European market with market design features and

procedures in place in order to deal with grid constraints and increase the available

interconnection capacity offered to the market (e.g. due to the further reduction of security

margins and the implementation of flow based market coupling across time-frames), the

European power system can be operated even more efficiently than in the options above.

Benefits coming from the further improvements in the dimensioning and procurement of

balancing reserves, now on a European level, as well as the better utilization of interconnectors

by the EU Independent System Operator, lead to further reductions of the total costs compared

to Option 1(c) by 1.5%. Reserve needs are further reduced by 30% compared to Option 1(c)

and 63% compared to the baseline, although downwards reserves, which have a low

procurement cost, are mainly procured on a national level, in order to use interconnectors

mainly for exchanging electricity instead of reserving it for potential assistance to/from the

neighbours.

The results indicate that although the economic benefits of moving from a national to a regional

approach (Option 1(b) (strengthening short-term markets)) are significant, the move towards a

more integrated European approach (Option 2) has a less significant economic value-added, as

most of the benefits have already been harvested by moving towards a regional approach. On

the other hand this result is also subject to the limitations of the modelling, not being able to

280

281

282

See Annex1(c).1, Stakeholders views; Reference CEER discussion paper

"Scoping of flexible response",

May 2016

“Bringing

intelligence to the grids

–

case studies”

(2013) Geode Report;

http://www.geode-eu.org/uploads/REPORT%20CASE%20STUDIES.pdf;

also

“Eurelectric

policy statement on smart meters”

(2010);

http://www.eurelectric.org/media/44043/smart-

metering-final-2010-030-0335-01-e.pdf

“Towards

smarter grids: developing TSO and DSO roles and interactions for the benefit of

consumers”

(2015) ENTSO-E;

https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/150303_ENTSO-

E_Position_Paper_TSO-DSO_interaction.pdf;

“Market

design for demand side response”

(2015) ENTSO-E

Position paper;

https://www.entsoe.eu/Documents/Publications/Position%20papers%20and%20reports/entsoe_pp_dsr_web.

pdf

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capture the positive impacts from the more efficient operation of the network (since METIS

does not include detailed network modelling).

6.1.5.2.Who would be affected and how

Under this option, TSOs, DSOs, power exchanges, electricity undertakings in general as well

as Member States and competent authorities would be subject to far-reaching organisational

changes (e.g. EU ISO and EU Regulator instead of national TSOs and regulators), and bound

by fully harmonised rules setting out the full integration of the EU electricity market. This

increases the likelihood that these rules may be difficult to implement in specific countries. This

could lead to high resource requirements amongst these stakeholders, public authorities and

Member States, that may be ultimately borne by consumers.

6.1.5.3.Impact on businesses and public authorities

The creation of a fully integrated European electricity market can be considered the most

efficient of all the options and could, in the long run, avoid frictions from coordination and

provide for a high quality electricity system with a high degree of security of supply. Under this

option, it could be argued that in the long run the impact on stakeholders (e.g., TSOs, DSOs,

power exchanges, electricity undertakings, etc.) may be reduced, since the integration of the

electricity market would ensure a high degree of consistency.

However, this option would entail significant changes compared to the current state of the art

of the electricity systems across the EU. It would be necessary to build new entities, processes

and methods without being able to draw upon established practice (e.g., for the establishment

of an EU ISO). Hence, there is a risk that this would lead to disruptions and would require a

significant amount of time to become operational.

This option would also reduce the scope to take into account regional specificities and to draw

upon established regional actors. This option would reduce the scope to develop rules at the

regional level between the parties involved in organising the cross-border trade and system

operation. This is because the key framework as well as the institutional structure would already

be set out at the pan-European level.

In light of the above, it should be noted that the political and administrative effort required

under this option would be considerable.

Environmental impacts of options related to Problem Area I

The measures proposed in this Problem Area aim to improve the cost-efficiency and the

flexibility of the power system. By doing so, climate-friendly variable RES E can be better

integrated in the market; resources are used more efficiently, and unnecessary fuel-based

generation (e.g. backup generation needed because of missing rules for cross-border short-term

markets) can be avoided by better using the aggregation potential of the internal market. Using

the full potential of demand response has also a positive effect on the environment. If

consumption can be shifted more easily to off-peak times, less backup generation from fuel-

based plants is needed.

On the other hand, the removal of privileged rules for certain production forms may lead to a

shift from some RES E production (i.e. biomass) to other generation types which will not only

be wind and solar, but also fossil fuel-based. Therefore, although direct CO

emissions from

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the power sector decrease while moving from Option 1(a) to Option 1(c), from 615 Mt CO

600 Mt C0

, METIS results show an increase when moving from the baseline to Option 1(a) by

60 Mt CO

. The analysis of the impact on emissions is, however, complex

283

The removal of priority dispatch from biomass (as well as from any other resource, including

must-run generation) is pivotal in restoring the economic merit order in the power markets and

significantly increasing their economic efficiency. Such a measure would discontinue the use

of expensive biomass as baseload generation, replacing it by the marginal technologies (mainly

coal and gas). Expensive biomass would then mainly be used in the power sector as a flexible

generation technology, as well as for providing reserves.

The replacement of biomass by gas and coal could lead in the short-term to increasing

emissions. The environmental impacts of the market design measures cannot though be

examined in isolation from all other complementary energy and climate policies. At the EU

level, the reduction in greenhouse gas emissions within the sectors covered by the EU ETS is

guaranteed by the declining cap which in turn ensures that the emissions reductions objective

is met cost-effectively. In the event of an increase in emissions from certain changes in the

power sector mix, the corresponding increase in demand for allowances would raise the carbon

price leading to an increase in abatement through other means, whether this is through a fuel

switch in power generation elsewhere or an emissions reduction in other ETS sectors. Due to

the binding limit on overall emissions a reduction in the use of biomass would therefore

eventually result in the same amount of GHG emissions over time, with a different fuel mix at

a lower total system cost.

The main effects of removing priority dispatch for biomass are therefore:

only cheaper fractions of biomass are being used (such as waste streams), while the

more expensive one is being used as flexible dispatchable generation, rather than

subsidised baseload;

overall higher CO

prices and lower generation costs, and higher wholesale electricity

prices (but most likely lower retail prices, as no subsidies will need to be recuperated

outside the wholesale market).

more favourable conditions for gas, with more operating hours;

The possible increase in emissions in the power sector is in reality the effect of current energy

policies for RES E (and specifically the incentives given by the subsidization of biomass) and

not of electricity market related policies. By removing the distortions currently present in the

electricity markets, the market is able to give clearer signals on the interactions between climate

and energy policies and help identify the right balance between cost and resource efficiency

and emissions reduction.

Summary of modelling results for Problem Area I

The analysis shows that although today electricity markets function much better than in the

past, there are still significant gains to be harvested. Restoring the merit order and creating a

283

It should be noted that the analysis excludes the effect that increased generation by thermal plants would have

on the carbon market and how this in turn would indirectly impact electricity generation.

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level-playing field for all technologies can reduce the operational cost

284

from EUR 83.4 billion

in Option 0 to EUR 77.5 billion in Option 1(a). Another EUR 2.7 billion can be saved by further

strengthening and linking the short-term markets; EUR 0.9 billion by better integrating demand

response and RES E into the market; and EUR 1.1 billion from fully integrating EU markets.

Overall, the measures under Option 1(c) can lead to cost reductions up to 11.4% compared to

the baseline, while the additional measures under Option 2 would raise this to 12.7%.

When considering the above results, three important points need to be made. First of all the cost

saving estimates for each option are directly related to the volume of traded energy (and

reserves) they concern. Option 1(a) (level playing field) affects all market frames, but most

notably the day-ahead, where the largest volume of trades takes place. Options 1(b)

(strengthening short-term markets) and Option 2 (fully integrated markets) focus on

interconnections (for all market time frames), intraday and balancing; traded volumes there are

only a fraction of the ones of the day-ahead. Option 1(c) (demand response/distributed

resources) concerns mainly the balancing and reserve markets

285

. Secondly, the effect of the

measures on the intraday and balancing traded volumes is much greater, but more difficult to

quantify, as it is bi-directional (upwards and downwards compared to the day-ahead scheduled

energy) and complementary to the day ahead market

286

. Finally the proposed blocks of

measures were deemed as the most efficient ones, but also were found to have limited impact

on the reported results

287

Apart from the cost savings, which relate only to the generation side costs, it is important to

also examine the final cost of the wholesale market for the consumers, referred to below as

'Load Payments' (see Glossary). With the removal of all special rules affecting dispatch, the

wholesale price begins reflecting the actual marginal value of electricity and thus increases; this

affects also the Load Payments which increase by 5%. Subsequent Options though bring more

resources into the market, better utilizing the interconnections and further improving the cost-

efficiency of the market, gradually reducing the Load payments by 6% in Option 1(b)

(strengthening short-term markets), 9% for Option 1(c) (demand response/distributed

resources) and 11.5% for Option 2 (fully integrated market) compared to the baseline. The

above are equivalent to a reduction of the wholesale market cost for the consumer

288

from 78

EUR/MWh in the baseline to 71 EUR/MWh for Option 1(c) and 70 EUR/MWh for Option 2.

284

285

286

287

288

Cost reflects the operational cost of the electricity system (reflecting mainly fuel cost and CO

cost). Lower

cost implies a more efficient operation of the system.

The proposed measures are expected to also have an impact on the day-ahead market, but this was not possible

to assess due to the lack of sufficient detailed data. See also footnote 278.

There are two important connections with the day-ahead market. The closer the day-ahead schedule matches

the optimal dispatch (based on realized demand and generation), the smaller the need to act in the shorter term

markets; and how interconnection is split between day-ahead and intraday. For this reason it is preferable to

look at the results as a whole and not separately for each market frame.

A sensitivity performed with METIS introducing the Option 1(c) measures (demand response/distributed

resources) before Option 1(b) (strengthening short-term markets) shows a marginal improvement of Option

1(c) benefits by EUR 0.3 billion, despite the much higher potential for improvement still available in the

market in the context of this Option.

If these costs were shared equally among consumers.

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Table 10: Monetary Impacts (in billion EUR) of the assessed Options (for EU28+NO+CH

in 2030)

Monetary Impacts (billion EUR)

289

Option 0

Option

1(a)

Level

playing

field

76.9

0.9

-0.3

0.5

-0.8

77.5

5.9

293

-15

Option

1(b)

Strengtheni

ng short-

term

markets

73.5

1.2

0.1

0.7

-0.6

74.8

8.6

262

Option

1(c)

Demand

response/

distributed

resources

72.7

1.1

0.1

0.7

-0.6

73.9

9.5

253

Option 2

Baseline

Cost day-ahead

Cost intraday

Cost balancing

upwards

downwards

Total cost

Cost savings

Load Payments

day-ahead

Load Payment

Savings

Source: METIS

82.5

1.4

-0.5

0.7

-1.2

83.4

278

Fully integrated markets

72.4

0.3

0.1

0.7

-0.6

72.8

10.6

246

The monetary impacts described in Table 10 are very closely linked to the impacts of the

measures on the wholesale prices. In Option 1(a) (level playing field) the increase of the

competitive segment of the market from 40% (due to priority dispatch and must-runs) to 100%

is the main driver for a more cost-efficient operation of the system, with no negative prices

observed in the performed model runs, leading in the end to higher day-ahead prices. In parallel

the reserve prices are generally lowered, due to the reduction of the inflexibility in the system.

Only mFRR upwards prices increase, as these services are now primarily offered by peaking

units.

In Options 1(b) (strengthening short-term markets) the trends reverse, as more resources enter

the market, thus lowering day-ahead prices. The better utilized interconnection capacity and the

improved functioning of the reserve markets allows baseload plants to produce more electricity

in the day-ahead, while the more flexible (and expensive) plants become the main providers of

reserves. As a consequence, balancing prices tend to increase (together with intraday prices).

Subsequently, the introduction of demand response and the provision of reserves by RES E in

Option 1(c) (pulling demand response and distributed resourced into the market) further lower

wholesale prices (as more resources enter the market), with the exception of downwards reserve

prices which increase

290

. Finally the impacts of Option 2 (fully integrated markets) are similar

to the ones of Option 1(b) (strengthening short-term markets).

289

290

Unless otherwise noted, figures in all tables represent annual numbers for 2030. The geographical context is

always noted in the title of each graph and in some cases it also covers NO and possibly CH because of the

market coupling of EU Member States with these countries.

Downwards balancing activation is a benefit (fuel savings) for the system, while there is no gain (in METIS)

to increase demand.

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Table 11: Impacts (EUR/MWh) to Average Annual Wholesale Prices (for EU28 in 2030)

Average Wholesale Prices (EUR/MWh)

Option 0

Baseline

Day-ahead Market

Price

291

Balancing Price -

aFRR upwards

Balancing Price -

aFRR downwards

Balancing Price -

mFRR upwards

Balancing Price -

mFRR downwards

Source: METIS

Option 1(a)

Level playing

field

82.5

58.3

52.5

82.3

65.2

Option 1(b)

Strengthening

short-term

markets

73.9

76.2

54.4

85.6

64.7

Option 1(c)

Demand

response/

distributed

resources

71.3

59.8

76.3

58.4

Option 2

Fully

integrated

markets

69.6

72.3

60.6

76.3

58.3

78.4

71.9

52.8

72.1

70.1

An interesting aspect to examine is the distributional impact of the various options on the

generator surplus (i.e. revenues above cost) and consumer surplus (i.e. cost below VoLL). It is

important to note that this should not be interpreted as an investment or "missing money"

analysis, since the modelling used here is static (based on the same set of capacities across the

options). The issue of investments is analysed in Section 6.2.6.3, using a dynamic investment

model (PRIMES/OM).

With the day-ahead prices significantly affected by the measures, so does generator surplus (i.e.

revenues above cost). The distributional impacts on the market players though are concentrated

on thermal generators, with competitive RES E generators even increasing their day-ahead

revenues (not considering the additional revenues from the other markets).

Although in the baseline thermal generation seems to be making reasonable revenues, sufficient

in many cases to cover fixed costs

–

especially for gas units

–

the improvements in the market

design introduced in Options 1(b) (strengthening short-term markets), 1(c) (demand

response/distributed resources) and 2 (fully integrated markets) lead to a significant decrease

of their revenues, turning their operation to loss-making. Note, this result is a large extent due

to the static modelling approach followed here and the increased competition in the market, as

a result of bringing more resources into it and better utilising interconnections (thus better

sharing national resources across EU). With the power generation capacities remaining constant

across Options, this leads to a market with increasing resources participating (to the point of

oversupply) and more intense competition, thus shrinking revenues.

291

EU weighted average price on Member States' demand

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Table 12: Generator Surplus

292

(in EUR/kW) for different plant categories (for EU28 in

2030)

Generator Surplus (EUR/kW)

Option 0

Baseline

Solids

OCGT

CCGT

Nuclear

Hydro

Solar

Wind onshore

Wind offshore

Source: METIS

394

112

191

451

204

117

176

Option 1(a)

Level playing

field

393

102

178

490

215

133

204

Option 1(b)

Strengthening

short-term

markets

146

435

200

137

211

Option 1(c)

Demand

response/

distributed

resources

124

418

194

137

213

Option 2

Fully

integrated

markets

108

413

190

137

213

Similarly, the introduced measures have certain consequences on the generation production,

although these tend to be relatively limited. Summarizing what has already been discussed in

the dedicated assessment of each option, and presented in Table 13:

The main impact on the electricity generation patterns appears in Option 1(a), when

dispatch begins reflecting the economic merit order. Most notably, biomass generation

is replaced mainly by gas and coal generation.

Otherwise, generation patterns remain relatively stable across Options, except for some

shifting of gas generation to nuclear in Option 1(b) (strengthening short-term markets).

This comes as a result of the more efficient interconnection allocation and procurement

of reserves, which leads to the utilisation of nuclear and lignite plants mainly for

producing energy, while the more expensive gas plants are used more for reserves and

balancing.

RES E curtailment and activation of replacement reserves is steadily reduced across all

options, as all measures introduce more and more flexibility to the system. In fact

replacement reserves are no longer needed in Option 2.

Procurement of Balancing Reserves also decreases substantially, from 79.6 GW in the

baseline to only 29.6 GW in Option 2. The gradual drop in the required reserves is an

outcome of the specific measures assumed in each case and explained in more detail in

the assessment of the respective options.

292

Reported surplus concerns day-ahead and reserve market revenues. Some additional revenues (but minor in

comparison) should be expected from the intraday and balancing markets (but were difficult to identify and

report).

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Table 13: System Operation Results (for EU28+NO+CH in 2030)

Option 0

Option 1(a)

Level playing

field

Option 1(b)

Strengthening

short-term

markets

Option 1(c)

Demand

response/

distributed

resources

Option 2

Fully integrated

markets

Baseline

Net Electricity Generation (TWh)

Total

Biomass & Waste

Hydro

293

Wind

Solar

Lignite

Nuclear

Coal

Gas

Others

RES Curtailment

(GWh)

3618

236

632

722

303

269

755

237

455

13.0

3606

623

726

303

274

775

272

545

8.3

3599

618

728

303

278

800

274

515

6.0

3588

609

729

303

279

803

268

516

5.0

3586

607

729

303

280

804

266

515

4.6

Balancing Procurement (GW)

Reserve

Dimensioning

of which FCR

of which aFRR

of which mFRR

Reserves via

interconnections

294

Replacement

Reserves

Activation

295

(GWh)

Source: METIS

79.6

12.4

20.5

46.6

600

65.8

12.4

20.4

33.1

100

42.3

12.4

10.1

19.8

12.2

42.3

12.4

10.1

19.8

11.7

29.6

12.4

6.0

11.1

18.7

In terms of distributional impacts across the EU regions, results are strongly related to the

respective generation mix of each region, as well as to how well interconnected each region is

to the others. For the regions with significant biomass generation (e.g. region 3), there are

significant cost savings when moving from the baseline to Option 1(a) (level playing field).

293

294

295

Hydro includes pumped hydro storage whose utilisation decreases from Option 0 to Option 2.

The reserves via interconnections are computed as the difference between the reserves needed to face the

national risks and the procured reserves.

Activated for avoidance of Loss of Load

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Similarly, the benefits of Option 1(b) (strengthening short-term markets) and Option 2 (fully

integrated markets) are more significant for the Member States that are better interconnected

(Regions 1 and 2). Option 1(c) (demand response and distributed resources) reduces costs for

all regions, except for Region 5, as the competition with additional reserve resource decreases

the cost for reserve procurement. Similar observations apply for the load payments and the

wholesale prices. It is also worth noting how wholesale prices tend to converge as markets

become more harmonised and better functioning, with the exception of Region 4 (Spain &

Portugal), which has a limited interconnection to the rest of EU only via France.

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Table 14: Distributional Impacts

–

regional perspective

296

(for EU28 in 2030)

Option 0

Baseline

Option 1(a)

Level playing

field

Option 1(b)

Strengthening

short-term

markets

Option 1(c)

Demand

response/distributed

resources

Option 2

Fully

integrated

markets

Total cost

–

Day Ahead Market (billion EUR)

Region 1

Region 2

Region 3

Region 4

Region 5

42.1

6.9

13.3

5.5

14.3

40.3

5.5

10.7

5.3

14.9

39.4

4.8

9.6

5.0

14.6

38.9

4.5

9.4

4.9

14.9

38.6

4.4

9.3

5.0

14.9

Total Load Payments

–

Day-Ahead Market (billion EUR)

Region 1

Region 2

Region 3

Region 4

Region 5

157

161

138

131

126

Average Day-Ahead Market Price (EUR/MWh)

Region 1

Region 2

Region 3

Region 4

Region 5

Source: METIS

88.1

87.6

63.3

49.6

70.9

90.6

97.2

75.5

53.2

71.8

77.3

81.6

73.8

55.2

70.6

73.3

78.0

73.0

54.6

70.6

73.6

73.0

55.5

70.8

296

Regions as indicated in footnote 244.

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6.2.

Impact Assessment for Problem Area II (Uncertainty about future generation

investments and fragmented capacity mechanisms)

Methodological Approach

6.2.1.1.Impacts Assessed

Similarly to Problem Area I, the assessment focused on the economic impacts of the examined

options. The emphasis though is not on the operation of the power system and the integration

of RES E, but on whether the market revenues can incentivize the necessary investments and

–

most importantly

–

on the relevant cost for the consumer. Inefficiencies resulting from

fragmented approaches to CMs are also considered.

The impacts of the options to the environment and the society, excluding their economic

aspects, are directly linked with the changes in the generation capacities of each option. Other

significant, direct or indirect, impacts for the examined options were not identified.

The assessment is presented individually for each option, with qualitative analysis and

references to quantitative results. The detailed modelling results for the various options, along

with their interpretation, are presented in section 6.2.6.

6.2.1.2.Modelling

The modelling for this part was performed using PRIMES/OM, a specific version of the

PRIMES model that can assume different types of competition in the electricity market, as well

as model how CMs affect the investment decisions of the market participants. PRIMES/OM

was selected over METIS for this part of the analysis, because it can model in detail the

investment decisions of the market participants over an extended time-period, namely until

2050, while at the same time being able to capture the effect of different bidding behaviours

from the side of the market participants (necessary to assess the impact of scarcity pricing).

In addition, PRIMES/IEM (a day-ahead and unit commitment simulator developed by NTUA)

was used to assess in more detail the benefits of the energy-only market. Contrary to METIS

297

PRIMES/IEM places more emphasis on accurately simulating the market behaviour of

generators by assuming specific bidding strategies followed by the market participants and

departing from the usual marginal cost assumption

298

. Moreover, PRIMES/IEM was able to

capture the effect of introducing locational price signals, as it includes a network model. Further

297

298

Due to the differences in the two modelling approaches and underpinning assumptions of METIS and

PRIMES/IEM, a direct comparison of the two sets of modelling results could be misleading.

The marginal cost assumption is perhaps the most usual assumption in the dispatch type of models, as it helps

focus more on the effect of market design measures and departs from competition or behavioural issues.

However, one cannot capture well the effect of measures like scarcity pricing under the marginal cost bidding

assumptions, as the prices would fluctuate between the marginal cost of the most expensive running plant and

VoLL (or price cap), which is not what is observed in practice in the market.

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details on both models and the methodological approach followed can be found in Annex IV,

as well as in the relevant NTUA report

299

The above tools were complemented by a study performed using METIS, analysing the revenue

related (weather-driven) risks faced by conventional generation and how these could be

mitigated, while also identifying the value of co-ordinated solutions

300

6.2.1.3.Overview of Baseline (Current Market Arrangements)

The baseline reflects the current market arrangements of Problem Area I, similar to what is

described in section 6.1.1.4. In addition it is assumed that Member States put in place price

caps, as well as that there may be systemic congestion in the transmission grid.

Comparing the baselines of Problem Areas I and II in modelling terms, certain differences exist

in terms of figures and assumptions, mainly reflecting the differences in the respective

modelling approaches

301

intended to better capture the options assessed in each Problem Area,

as well as their calibration to a different version of EUCO27

302

. Under this baseline:

Price caps apply as today

303

;

Units bid according to bidding functions by plant category

304

and not marginal costs;

The unit commitment simulator applies a flow-based allocation of interconnections;

Modelling includes more detailed information on generation capacities, including

vintages, technology types and technical characteristics of plants;

The day-ahead market covers only part of the load, as is the case today. A large part

of the energy (especially produced by inflexible units) is nominated.

The baseline of this Problem Area fully reflects EUCO27.

Nevertheless, both models identify similar trends concerning the operation and the revenues of

the various generation types, as already presented in Problem Area I.

299

300

301

302

303

304

"Methodology

and results of modelling the EU electricity market using the PRIMES/IEM and PRIMES/OM

models",

NTUA (2016)

"METIS

Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",

Artelys

(2016)

Further details can be found in Annex IV.

METIS had to be calibrated to PRIMES much earlier than PRIMES/IEM. Therefore, a preliminary version of

EUCO27 was used as the basis for the calibration. The main differences of the two versions concerning the

power sector can be found in Annex IV.

For more details please see: "Electricity

Market Functioning: Current Distortions, and How to Model Their

Removal",

COWI (2016).

The basis is the marginal fuel cost of the plant, increased by a mark-up defined hourly as a function of scarcity,

calculated for each market segment in which the respective plant category usually operates (e.g. peak, mid-

merit, baseload). Further details can be found in Annex IV.

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Impacts of Policy Option 1 (Improved energy markets - no CMs )

6.2.2.1.Economic Impacts

Option 1 assumes that Member States can no longer put in place CMs. The analysis is hence

solely based on a strengthened energy-only market.

With sufficient economic certainty, investments should in principle be able to take place based

on the electricity price signal alone, provided that the price signal is not significantly distorted.

Further, the electricity price, and its behaviour, should stimulate not only investment in

sufficient capacity when needed (be it production or demand), but also in the right type of

capacity. A steady electricity price, one that does not vary significant on an hour-to-hour basis,

should steer investment to the types of capacity that can operate steadily at lowest production

cost. A rapidly fluctuating electricity price should steer investment to capacity that can ramp-

up and ramp-down very quickly and can take advantage of high prices at short notice and avoid

operation when prices are too low. The shift to variable generation will increasingly require

fast-ramping and highly flexible generation and cause the market exit of less flexible types of

generation capacity. Investment uncertainty and varying prices are not a unique feature to the

electricity industry

305

In this way, the effect of variable renewables, insofar as their deployment will increase the

variability of the electricity price, should stimulate investment in the flexible capacity needed

to keep the system in balance at all times. Ensuring that prices can reflect market fundamentals

is key to this and removing as many potential distortions on electricity prices is critical to

enabling it to play this function.

Indeed, the analysis performed with PRIMES/OM supports the arguments above, showing that

an energy-only market can in general deliver cost-efficiently the necessary investments in

thermal capacity (especially flexible one). The enhanced market design will also improve the

viability of RES E investments, but electricity market revenues alone might not prove sufficient

in attracting investments in RES E in a timely manner and at the required scale to meet EU's

2030 targets. (See in this regard also the box on RES E investments in Section 6.2.6.3).

Moreover, PRIMES/IEM results show that undistorted, energy-only markets can significantly

decrease load payments by around EUR 50 billion

306

in 2030. The largest part of these savings

is attributable to the improvements in the short-term markets and the participation of demand

response in the market, representing EUR 20 billion and EUR 26 billion savings respectively

in 2030. The implementation of measures introducing a level playing for all technologies and

removing price caps brings EUR 5 billion savings in 2030 and at the same significant more

cost-efficiency to the system, as explained in Section 6.1.2.1.

305

306

See in this respect e.g. the report by Frontier Economic on

"Scenarios for the Dutch electricity supply system",

p. 134.

https://www.rijksoverheid.nl/documenten/rapporten/2016/01/18/frontier-economics-2015-scenarios-

for-the-dutch-electricity-supply-system

The benefits become almost double compared to Option 1(c) as assessed with METIS, due to the additional

distortions included in the baseline and measures to address them, on top of the expected differences due to

the different modelling approach. The two figures give a satisfactory range on the possible benefits for Europe

from an improved energy only market design.

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As resources are better utilised across the borders compared to the baseline, and demand can

better participate in markets, undistorted energy-only markets are able to improve the overall

cost-efficiency of the power sector significantly. Equally, it can ensure resource adequacy (See

in the regard also Section 6.2.6.3).

It thus follows that by improving the energy markets, the need of government intervention to

support investments in electricity resources is reduced

6.2.2.2.Who would be affected and how

As this option encompasses to the largest extent the options discussed under Problem Area 1,

the assessment made there as to who would be affected and how applies here as well.

With regard to more variable pricing, they will benefit owners of flexible resources, such as

flexible

generation capacity, storage and demand response,

and incentivise them to come to

or stay in the market. In this end, they will provide the motor for more innovative services and

assets to be deployed.

End consumers

will be affected insofar as changes to the wholesale price are passed on to them

in their retail price. However, more variable prices will not necessarily be felt by end-consumers

as they can be hedged (particularly households) against this volatility in their retail contracts or

through wholesale market arrangements. In fact, more variable pricing will incentivise the

development of more sophisticated energy wholesale market products allowing price and

volume risks to be hedged more effectively.

Power exchanges

would be impacted by removal

of price caps as they will be required to introduce changes to systems and practices.

Minimising investments and dispatch distortions due to transmission tariff structures would

mostly affect

generators.

Positive impacts on their revenues would be expected due to lower

connection charges or tarrifs.

TSOs

will be affected by improvements in locational price signals as it would likely mean that

they hold and operate networks over more than one price zone. To a lesser extent this applies

power exchanges

as these are often already operating in different price zones today.

Spending of the congestion income to increase cross-border capacity may have impact on

end

consumers,

where the congestion income is used for the reduction of tariffs. But this should be

outweighed by the positive effect of more cross-border capacity being available, and the benefit

this has on competition and energy prices.

6.2.2.3.Administrative impact on businesses and public authorities

As this option encompasses to the largest extent the options discussed under Problem Area I,

the assessment made there as regards administrative impacts made there also applies here

307

Overall, the administrative impact on

businesses and public authorities

should be limited as,

even if the measures associated with Option 1 (in addition to those assessed under Problem

307

For the impact of the additional measures (removing price caps, introduction of locational price signals, etc.),

a detailed analysis is also presented in Annexes 4.1 to 4.4.

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Area I) require changes, they are not fundamentally different from the tasks performed already

under the baseline scenario.

More variable pricing will incite the development of more sophisticated energy wholesale

market products allowing price and volume risks to be hedged more effectively. This should

help reduce lower overall risks to

businesses.

Impacts of Policy Option 2 (Improved energy markets

–

CMs only when needed, based

on a common EU-wide adequacy assessment)

6.2.3.1.Economic Impacts

This option builds on a strengthened energy market (Option 1). Indeed, as developed in Section

2.2.1, undistorted energy price signals are fundamental irrespective of whether generators are

solely relying on energy market income or also receive capacity payments. Therefore, the

measures aimed at removing distortions from energy-only markets are 'no-regrets' and assumed

as being integral parts of Options 2 and 3.

In addition, the option assumes the presence of CMs but only in those Member States for which

a resource adequacy assessment performed at European level has demonstrated a resource

adequacy problem. As no restrictions are placed on these CMs, it is assumed they foresee

implicit cross-border participation (i.e. only taking into account imports and exports in the

dimensioning of the CM, without any remuneration of foreign capacity).

In order to highlight the importance of considering the regional aspects in a generation adequacy

assessment, Artelys performed an independent study

308

assessing the capacity savings that can

be obtained from a European approach in capacity dimensioning for resource adequacy in

comparison to a resource adequacy assessment conducted at Member State level.

The mode used jointly optimises peak capacities given security of supply criteria

309

for two

reference cases

–

without cooperation (capacities are optimised for each country individually,

as if countries could not benefit from the capacities of their neighbours) vs. with cooperation

(capacities are optimised jointly for all countries, taking into account interconnection capacities

(i.e. NTCs). The difference in installed capacity between the two cases reveals the savings could

be made from cooperation in investments.

Results show that almost 80 GW of capacity savings across the EU can be achieved with

cooperation in investments. This represents a gain of EUR 4.8 billion per year of investments

310

when comparing the two extremes. A reason for these savings is that Member States have

different needs in terms of capacity with peak demands that are not necessarily simultaneous.

Therefore, they can benefit from cooperation in the production dispatch and in investments. It

should be noted that this figure does not assess at which stage Member States are currently (i.e.

308

309

310

"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",

Artelys

(2016). The results of this study are spelled-out in more detail in Annex 2.2.

A value of 15k€/MWh for loss of load is used and system adequacy is assessed on 50 years of hourly weather

data. For more details on the characteristics of capacity dimensioning, see Annex 2.2.

The 80 GW of capacity savings are a result of optimal investment decisions on EU level, based on an EU

approach vs a national approach. Efficient market functioning can also provide efficient investment signals

leading to more efficient investments. See section 6.2.6.3.

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whether some Member States already benefit from the capacities of their neighbours), as the

benefits have already been reaped by some. It should also be noted that this figure does not

include savings on production dispatch, which could lead to much higher monetary benefits.

PRIMES/OM was used to assess the impact of introducing CMs on a certain number of

countries, with the CMs foreseeing implicit cross-border participation. The runs assumed that

four countries were justified based on a EU-wide adequacy assessment, to have a CM: UK,

Italy, Ireland and France. This assumption was based on a selection of countries from the Sector

Inquiry on Capacity Mechanisms (as the model always ensures that the expected security of

supply levels are always met).

The analysis shows that the introduction of CMs lowers wholesale prices, but to a limited

degree, primarily in the MS introducing CMs, but also to all EU countries due to the assumed

well-functioning markets. On the other hand this does not translate to reduced Load Payments

for the consumers on a EU level, as the CM related costs slightly exceed the reductions in the

cost of the wholesale energy market in 2030. This difference though becomes quite significant

in the longer term, making Option 1 cheaper than Option 2 by an average of EUR 4

billion/annum when comparing over the period 2021-2050. Interestingly enough, the

consumers of the Member States introducing CMs face a EUR 7 billion increase in costs in

2030, while the cost for all other EU Member States drop by a similar amount.

6.2.3.2. Who would be affected and how

EU-wide resource adequacy assessments would benefit

consumers

through maintaining high

standards of security of supply while lowering costs through reduced risk of over procurement

of local assets as foreign contribution to national demand and demand side flexibility would be

sufficiently taken into account.

ENTSO-E

would be required to carry out an EU-wide resource adequacy assessment based on

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

ENTSO-E

would also have to provide an updated methodology with probabilistic calculations,

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

and availability of cross-border infrastructure.

NRAs/ ACER

would be required to approve the

methodology used by ENTSO-E for the resource adequacy methodology and potentially

endorse the assessment.

TSOs

would be obliged to provide national raw data to ENTSO-E

which will be used in the EU-wide resource adequacy assessment.

Member States

would be better informed about the likely development of security of supply

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

by ENTSO-E when arguing for CMs.

With the updated methodology provided by ENTSO-E, intermittent

RES generators/ demand-

side flexibility

would be less likely to be excluded from contributing to resource adequacy.

6.2.3.3.Impact on businesses and public authorities

The main burden would be for ENTSO-E having to provide for a single 'upgraded' methodology

and to carry out the assessment for all EU countries. Important to note is that ENTSO-E has

already been carrying out an EU-level resource adequacy assessment based on Union

legislation. However, the methodology used has to be upgraded which would require increased

manpower. Nonetheless, the

administrative costs

of this 'updated' assessment are expected to

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be marginal compared to the economic benefits that would be reaped. It is estimated that these

these costs

311

would range from EUR 4-6 million per year (representing mainly personnel and

IT costs).

Impacts of Policy Option 3 (Improved energy market

–

CMs only when needed, plus

cross-border participation)

6.2.4.1.Economic Impacts

This option builds on Option 2, i.e. a strengthened energy market and CMs only in Member

States where justified by a European adequacy assessment. In addition, this option provides an

EU framework for explicit cross-border participation in CMs.

Explicit cross-border participation lowers overall system costs compared to implicit

participation, as it corrects investment signals and enables a choice between local generation

and alternatives. As more capacity will be participating in the CM, than in the implicit

participation case, competition will be more intense and thus CM payments lower. In addition,

the enhanced competition will extend also to the wholesale market, thus leading to lower market

clearing prices.

Based on the same setup as in Option 2 (Improved energy market

–

CMs only when needed,

based on EU resource adequacy assessment) only now with explicit cross-border participation

(i.e. remunerating foreign resources for their services) instead of only implicit (i.e. only taking

into account imports and exports in the dimensioning of the CM, without any remuneration of

foreign capacity), PRIMES/OM estimates that explicit cross-border participation would result

in significant savings. Results show that explicit participation brings savings of EUR

2 billion

(in 2030) compared to implicit participation, with savings significantly increasing in the long

run to more than EUR 100 billion over the whole projectin period of 2021-2050 (i.e. about EUR

3.5 billion per annum). The main reason is enhancement of competition in the CM auction and

the resulting lower auction prices.

By remunerating foreign resources for their services, this option is likely to better ensure that

the investment distortions of uncoordinated national mechanisms present in Option 2 are

corrected and that the internal market able to deliver the benefits to consumers.

6.2.4.2.Who would be affected and how

A positive impact of cross-border capacity mechanism would be expected on the foreign

capacity providers,

generators, interconnectors and aggregators.

They would receive the

possibility to participate directly in a national capacity auction, with availability obligations

imposed on the foreign capacity providers and the interconnecting cross-border infrastructure.

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

benefits that they deliver to the CM zone and but would also receive penalties in case of non-

availability.

311

The economic costs linked to resource adequacy assessments are based on own estimations, resulting from

discussions with stakeholders and experts. For more details, see Annex 5.1.

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NRAs/ACER

would be required to set the obligations and penalties for non-availability for

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

ENTSO-E

would be required to establish an appropriate methodology for calculating suitable

capacity values up to which cross-border participation would be possible. Based on the ENTSO-

E methodology,

TSOs

would be required to calculate the capacity values for each of their

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

TSOs

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

6.2.4.3.Impact on businesses and public authorities

Providing an EU framework with roles and responsibilities of the involved parties would enable

explicit cross-border participation (as already required by the EEAG). Although the cost of

designing cross-border participation in CM depends to some extent on the design of the CMs,

an expert study

312

estimated that such cost corresponds roughly to 10% of the overall cost of

the design of a CM

313

. In addition, they estimate costs associated with the operation of a cross-

border scheme i.e. additional costs if cross-border participation is facilitated to amount to 6-30

FTEs

314

for TSOs and regulators combined. Providing for an EU framework would remove the

need for each

Member State

to design a separate solution and potentially reduce the need for

bilateral negotiations between

TSOs and NRAs,

reducing the overall impact on these

authorities. According to the same study, TSOs and NRAs bear the main costs related to cross-

border participation as they have to check eligibility and ensure compliance. The study

estimates cost savings of 30% on these eligibility and compliance costs compared to the

baseline. It would also reduce complexity and the administrative impact for

businesses

operating in more than one zone.

Environmental impacts of options related to Problem Area II

The impacts of these measures to the environment are very limited, as they mainly influence

the generating capacity but not so much the operation of the units, which is the source of

emissions. The actual emissions depend on the merit order and the relation of the marginal cost

of coal in comparison to the marginal cost of gas. This in turn depends on the CO

price and

the relation of coal versus gas price, and not on whether there is a CM in place or not.

Overview of modelling results for Problem Area II

6.2.6.1.Improved Energy Market as a no-regret option

Several facts speak in favour of market design which relies on an improved energy market as

the driver for investment and operation. As already described in the assessment of Problem

Area I, the improvements in the wholesale market described under Option 1 of Problem Area I

(level playing field, strengthening short-term markets, pulling demand response and distributed

resources into the market) are expected to bring significant benefits and reduce the need to

correct market failures with capacity markets. These benefits are further enhanced when

considering the additional measures considered in this Option (e.g. removal of price caps, a

312

313

314

Thema (2016),

Framework for cross-border participation in capacity mechanisms

(First interim report)

The same expert study also found that the overall cost of of the design are fairly small compared to the overall

cost of the CM (remuneration of the participation ressources).

FTEs in other phases refer to (annually) recurring costs.

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process which leads to the introduction of locational price signals reflecting systematic

congestion, limiting curtailments of interconnector capacity).

The benefits of further improving the market in this way, assessed this time using the

PRIMES/IEM model, are presented in Table 15 below. The level of the reported figures in

Table 15 are higher compared to Table 10 due to the inclusion of more distortions in the baseline

of PRIMES/IEM, as well as the use of scarcity bidding, instead of marginal cost bidding in

METIS

315

Table 15: Cost of supply in the wholesale market in the year 2030

316

Load Payments (billion EUR)

Day-

ahead

Market

Current Market Arrangements

(in context of low price caps, systematic

congestion)

Level playing field + removal of low

price caps

Strengthening short-term markets +

removal of low price caps, locational

price signals

Demand response / distributed resources

into the market + removal of low price

caps, locational price signals, demand

response in day-ahead

Source: NTUA modelling (PRIMES/IEM)

Intra Day

Market

22.1

17.1

11.6

Reserves

and

balancing

7.7

6.8

1.9

Total

356.0

351.4

331.2

326.2

327.5

317.6

300.4

4.0

1.0

305.4

Overall, despite differences in the modelling approaches, results of PRIMES/IEM are fairly

consistent with METIS results used to access the options from Problem Area I, especially

concerning the ranking of the respective options. The results indicate that the "improved energy

market" Option could significantly decrease wholesale supply costs by around EUR 50 billion

in the year 2030. As a consequence, the unit cost of generation paid by the consumers would

315

316

At the same time the assumption that CHP, small scale RES E and biomass retain (implicitly in some cases)

priority dispatch in PRIMES/IEM in the first three examined cases

–

but not for small scale RES in the last

one -, implies lower percentage changes when moving between the first three options, due to the smaller

generation affected by the measures, but at the same time a more significant one for the last option. More

details on the exact assumptions can be found in Annex IV.

The rows correspond to the respective options of problem area I (except Option 2). In addition though Option

1(a) (level playing field) is complemented by the removal of price caps; Option 1(b) (strengthening short-term

markets) is complemented by the introduction of locational price signals; and Option 1(c) with demand

response participating also in the day-ahead market (which could not be captured by METIS, as it captured

demand response in the intraday and balancing markets only). The last row reports the aggregate costs of

Option 1 of Problem Area II.

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drop from 102.9 EUR/MWh to 94.7 EUR/MWh, the largest part of which is attributable to the

participation of demand response in the market

317

The above analysis highlights the importance of an improved market design, with all the

measures described under Option 1(c) of Problem Area I, together with scarcity pricing and the

proper locational signals (as added under Option 1 of Problem Area II), irrespective of whether

generators are solely relying on energy market income or also receive capacity payments.

Therefore the measures aimed at removing distortions from energy markets are considered as

'no-regrets'.

6.2.6.2.Comparison of Options 1 to 3

In order to better assess the dynamic behaviour of markets and how markets can also provide

investment signals, modelling analysis was performed using PRIMES/OM

318, 319

. Option 1

assumes an improved energy-only market for all Member States. Options 2 and 3 assume that

the improved energy-only market is complemented in certain cases by a national CM

320,321

as a

means for the Member States to address possible forecasted resource adequacy problems in

their markets, on the basis of a resource adequacy assessment performed at the European level.

The difference between the two options is that Option 3 assumes that the CM foresees rules for

effective, explicit cross-border participation, while Option 2 does not.

For the scope of this assessment, four countries were assumed to be in need of a CM: France,

Ireland, Italy and UK. This hypothesis was not based on a resource adequacy analysis, but on

the CMs examined under DG COMP's Sector Inquiry, focusing specifically on countries with

market-wide CMs. (Results could differ if different countries were selected, which is why a

sensitivity, presented below, was performed).

317

318

319

320

321

Contrary to METIS, in PRIMES/IEM demand response resources participate also in the day-ahead market,

thus bringing additional savings for the relevant Option. The impact is much more significant in this case

because the day-ahead market covers the vast majority of transactions.

PRIMES/OM delivers results complementary to the ones of market simulation models, like METIS and

PRIMES/IEM, as its focus is on investments. The main difference of PRIMES/OM with other energy system

investment models, like PRIMES, is that while PRIMES model analyses revenues/costs at the level of the

generation portfolio, the PRIMES/OM evaluates the probability of plant survival depending on the economic

performance calculated individually for each plant. A detailed description of PRIMES/OM can be found in

Annex IV.

The results will not be compared directly to the baseline as it was not technically possible to produce robustly

this scenario using PRIMES/OM. Nevertheless this does not affect the assessment, as all options build upon

the preferred option of Problem Area I.

The simulation of the CM auction by country, which is based on an estimation of a demand curve for capacity

procurement, takes into account imports and exports in the context of market integration using power flow

allocation of interconnection capacities. Therefore, the capacity procurement is configured so as to avoid

demanding for unnecessary capacities, as imports are considered to contribute to resource adequacy. Similarly,

exporting countries configure demand for capacity procurement taking into account capacity needed to

support exports.

When a country is assumed to have a CM in place, it is assumed that generators no longer follow scarcity

pricing bidding behaviour, but shift to marginal cost bidding. This is partly a result of competition, as more

generation remains in the market, as well as the expectation that when a plant gets a CM remuneration as a

result of an auction it foregoes revenues that would otherwise be needed to be covered from the day-ahead

market (e.g. because it signs a reliability option contract or a contract for differences with a strike price

effectively acting as a price cap to the generator's revenues from the energy market).

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The main conclusions when comparing Options 1-3 are presented in Table 16 and can be

summarized in the following:

The load payments for the three Options are very comparable when assessed at the EU28

level. For the year 2030, Option 3 (Improved energy market

–

CMs only when needed,

plus cross-border participation) is slightly cheaper by EUR 1 billion compared to Option

1 (Improved energy markets - no CMs) and by EUR 2 billion compared to Option 2

(Improved energy markets

–

CMs only when needed, based on a common EU-wide

adequacy assessment);

Results actually show that Option 3 is consistently cheaper than Option 2 throughout

the projection horizon until 2050 and on a EU28 level. This is mainly due to the lower

cost of the CMs, as through the cross-border participation more resources can compete

for the relevant payments;

As a result of the above, the average annual cost of total demand is very close for Option

1 and Option 3, with the lowest cost option alternating along the years. Option 3 is

always less costly for the consumer than Option 2 though.

When comparing the Options for the whole projection period, i.e. 2021-2050, Option 1

is found to be EUR 17 billion cheaper than Option 3 (on average about EUR 0.5

billion/annum) and EUR 120 billion cheaper than Option 2 (on average EUR 4

billion/annum). The main reason for this difference is that CMs provide incentives to

retain capacity on the system that otherwise would have exited the market. This cost is

somewhat balanced by the slightly lower energy prices observed in the market, although

the final cost to the consumer comprises of both the energy and the CM cost.

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Table 16: Main Impacts over the projection period 2020-2050 on EU28 level

2020

2025

2030

2035

2040

2045

Option 1

Option 2

Option 3

Option 1

Option 2

Option 3

Option 1

Option 2

Option 3

Option 1

Option 2

Option 3

Option 1

Option 2

Option 3

241

Load Payments (billion EUR)

316

351

419

447

312

306

352

350

428

426

454

452

557

560

553

2050

516

530

526

516

518

516

122

123

122

132

135

134

Load Payments for energy and reserves (billion EUR)

241

316

351

419

447

557

241

302

297

340

417

443

548

543

Load Payments to capacity mechanisms (billion EUR)

135

133

132

146

147

145

Average SMP (billion EUR)

103

118

115

100

117

114

Average cost of total net demand (EUR/MWh)

102

111

127

125

101

111

110

129

127

126

Source: NTUA Modelling (PRIMES/OM)

Note:Option 1: Improved energy markets - no CMs

Option 2: Improved energy markets

–

CMs only when needed, based on a common EU-wide adequacy assessment

Option 3: Improved energy market

–

CMs only when needed, plus cross-border participation

In order to better understand the impacts

322

of the CMs and the effect of cross-border

participation, Table 17 presents the impacts in 2030 for the three following groups of countries:

(a) the countries implementing a CM, (b) their direct neighbours and (c) the rest of the EU

countries.

Results for Option 2 shows that by introducing a CM in the assumed four countries, the actual

distribution of cost varies among the different groups of countries. Countries implementing a

CM are significantly burdened, mainly due to the cost of the CM, while their neighbours benefit

from it.

322

The impacts of CMs on the energy mix were very limited, inducing only some limited switching in electricity

generation from coal to gas plants.

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In particular countries implementing the CM are burdended with an additional EUR 6.8 billion

of costs, while the cost of their neighbours drops by EUR 3.6 billion. Even the cost of the rest

of the EU countries drops by EUR 2.9 billion. The cost of energy and reserves is reduced for

all countries

323

. In the countries implementing a CM the cost is reduced about two times more

than in the rest coutries, thus leading to lower payments for energy and reserves. However,

these reductions are outbalanced by the CM costs, borne solely by the countries introducing

CMs. The CMs induce an additional EUR 11 billion of payments, part of which are attributed

to the 5 GW of capacity which would otherwise have retired early in the absence of CMs.

Moving to Option 3, i.e. assuming explicit cross-border participation in the CMs, the results

compared to Option 2 improve in terms of cost-efficiency, not only for the whole EU as

presented above, but also for the countries implementing CMs. On the other hand the benefits

for the countries without a CM are slightly reduced.

In particular, the analysis for the year 2030 shows that explicit cross-border participation is still

worse-off for the countries with a CM compared to the energy-only market, costing EUR 3.6

billion more then the energy-only market, but better than implicit cross-border participation,

which costs an additional EUR 3.2 billion to the countries with CM.

In general, modelling results indicate that a CM, compared to an energy-only market, is likelier

to keep more capacity in the system, part of which would have otherwise exited due to making

losses in the energy market. As more capacity is kept in the Member States with a CM, less

capacity is needed in the other Member States, especially the neighbouring ones, which then

rely more on imports.

As it was discussed above, these results are influenced by the specific choice of countries

assumed to have a CM. To address this issue, an additional sensitivity was performed,

comparing the cases of all Member States introducing a CM, either with implicit or explicit

cross-border participation (same applying for all). Results show that the case of CMs with

explicit cross-border participation is less costly, with load payments being EUR 7 billion less

(about 2%) in the year 2030. Half of this benefit is coming from the reduced CM payments and

half from the reduced energy and reserve payments.

323

This result is related to some specific characteristics of these countries. France is heavily exporting electricity

based on nuclear and this is not affected by the establishment of a CM in France. This is also the reason why

energy costs drop across Europe. The UK and Italy heavily depend on CCGT plants in the context of the

scenario examined and, in addition, have limited free space in interconnections, because they are saturated by

import flows of nuclear energy coming from France.

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Table 17: Distributional Impacts of Options for Member States in 2030

324

Option 1

Option 2

Improved energy

markets

–

CMs only

when needed, based

on a common EU-

wide adequacy

assessment

140

131

Option 3

Improved energy

market

–

CMs only

when needed, plus

cross-border

participation

Improved energy

markets - no CMs

Load Payments in 2030 (billion EUR)

MS with CMs

MS directly neighbouring MS with CM

Rest of the MS

133

135

137

132

Load Payments for energy and reserves (billion EUR)

MS with CMs

MS directly neighbouring MS with CM

Rest of the MS

133

135

129

132

127

132

Load Payments to capacity mechanisms (billion EUR)

MS with CMs

MS directly neighbouring MS with CM

Rest of the MS

Average SMP (EUR/MWh)

MS with CMs

MS directly neighbouring MS with CM

Rest of the MS

104

102

103

100

101

100

101

Cancelling of Investments or Early Retirements of Capacity in 2021-2030 (GW)

325

MS with CMs

MS directly neighbouring MS with CM

Rest of the MS

Source: NTUA modelling (PRIMES/OM)

The main reason for the overall improved performance and reduced costs of Option 3 compared

to Option 2 is the enhancement of competition in the CM auction and the resulting lower auction

prices when allowing for explicit cross-border participation. This reduction lowers the revenues

of generators from a CM, but the probability of capacity reduction does not significantly

increase, compared to the case with implicit cross-border participation. Explicit cross-border

324

325

Impacts comparing the effects to countries assumed to have CMs and countries without. The 4 countries

assumed to have CMs in 2030 (France, Italy, UK, Ireland) were chosen based on the finding of DG COMP

Sector Inquiry. No specific assumption was made for the design of the relevant CMs. Differences are due to

the peculiarities of each national energy system, mainly related to its power mix and its level of

interconnections. Results could be different if other MS had been chosen.

The values under "cancelling of investments or early retirements of capacity" represent excess capacity which

becomes redundant due to the improved market functioning. Early retirement in the model is market-based,

coming as a result of anticipating a negative present value of earnings above operation costs in the future, in

comparison to the remaining value of the plant.

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participation in the CM auctions implies that competition is stengthened not only in the CM,

but also in the electricity wholesale market.

6.2.6.3.Delivering the necessary investments

Despite the different modelling approaches followed, the analysis with both METIS and

PRIMES/IEM reach a similar conclusion: improving the electricity market design is a no regret

option for the society as a whole. It is expected to reduce both the cost of operating the power

system, as well as the final cost for the consumers.

At the same time though the two models showed that these savings come to the detriment of

the thermal generator revenues, which are expected to be reduced compared to the baseline.

This modelling conclusion is a consequence mainly of the following two reasons:

on one hand, the improved market design increases competition in the market, by

bringing more resources into the market and better utilisation of interconnections;

on the other hand, capacities are assumed to be constant due to the nature of the

modelling (static, focusing on 2030 based on the same capacities across all options).

The combination of the two points above leads to a market with overcapacity

326

and thus low

prices, since there is no scarcity and there is sufficient capacity of flexible resources. In reality

though, the low prices in a well-functioning market would serve as a signal for lower

investments and exit of loss-making generators. Therefore this overcapacity should either never

appear or only be temporary.

The above dynamic interactions were better captured with PRIMES/OM, which simulated

investment behaviour till 2050

327

. In an energy-only market context, PRIMES/OM projected

that 63 GW of capacity would either be retired early or the relevant investments would be

cancelled in the period 2021-2030. About half of it would come from (mainly old) coal plants

and another half from peaking units or steam turbines fuelled by oil and gas.

The reason for retiring capacity and cancelling investments is the unprofitable operation of the

units. From the results it is indicated that the market can be successful in maintaining CCGT in

operation and, partly, peak devices. On the other hand it does not provide sufficient incentives

to retain old coal and old oil/gas steam turbine power plants, which are loss-making.

Table 18: Power generation

328

capacity in EU28

Power Generation

Capacity (GW)

2030

2040

1,271

2050

1,504

Cancelling of Investments or Early

Retirements of Capacity (GW)

2021-2030

2031-2040

2041-2050

Total

1,094

326

327

328

Moreover the capacity mix is not optimal any more.

All modelling runs assume certain reliability standards are met (i.e. security of supply concerns are always

met)

Reported generation capacities do not include capacities of CHP plants. Reported figures on cancelled

investments do not include 2 GW of cancelled nuclear investments in 2021-2030 and another 2 GW in 2041-

2050.

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Coal & Lignite

Peakers & Steam

turbines (oil/gas)

CCGT

Nuclear

158

110

165

124

175

122

0.3

Source: NTUA Modelling (PRIMES/OM)

In this context of adjusting capacities, the profitability

329

of thermal generation changes

significantly for the better. Scarcity pricing and the reduction of overcapacity are the main

drivers for this. Table 19 below shows how the adjustment of capacities, together with scarcity

pricing, would affect wholesale prices and allow thermal plants to at least recover their total

costs from the market.

Table 19: Effect of adjusting capacities to wholesale market prices in 2030

Day-Ahead Market Price

Before Adjusting Capacities

Day-Ahead Market Price

After Adjusting Capacities

103

137

Average Price (EUR/MWh)

Baseload

Mid-merit

Peak load

Spread (EUR/MWh)

Source: NTUA Modelling (PRIMES/IEM, PRIMES/OM)

330

In this context, the market seems able to deliver to a large extent the necessary investments for

all competitive technologies in the long term. A new CCGT plant, which is the marginal

technology, constructed post-2025 (when overcapacity is gradually resolving) will likely

remain profitable over the following 20 years of its operation. If this plant is part of a larger

portfolio, especially if it includes competitive RES E technologies, then it will be able to better

hedge its risks and further increase the likelihood that the whole portfolio will be profitable.

More specifically per technology:

CCGT

Scarcity bidding succeeds in maintaining the vast majority of CCGT

capacity, a large part of it being new investments in the period 2021-

2030. These plants have a variety of revenue sources (day-ahead,

intraday, balancing, reserves) and the projected increase in ETS prices

makes them economically more attractive to operate. As a result CCGT

plants are dispatched more often at full capacity.

329

Profits are highly dependent on the assumed fuel costs, technology costs and CO

price. Therefore the

discussion in this Section should be read in a probabilistic context, i.e. the "likelihood" of the investments

being profitable, similar to how the modelling of investment decisions was performed. Concerning the specific

assumptions used, PRIMES/OM was based on the relevant PRIMES EUCO27 projections, reported in Annex

IV.

330

PRIMES/IEM results are before capacity adjustment, PRIMES/OM after adjustment. Similar assumptions and

the same bidding strategies were used in both models, thus results are comparable, within the limitations of

each modelling approach.

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Nuclear

Nuclear plants do not have any revenue issues, due to their low

marginal cost. Note that new investments in nuclear appear only in the

long-term.

These plants have the biggest revenue problems, as market revenues

prove insufficient even to cover their fuel and variable (non-fuel) costs.

There was very limited new investment in the projections even in the

baseline, so this issue mainly concerns decisions for the refurbishment

of coal plants.

Peak units and steam turbines (many of them old) do not produce

comfortable revenues until 2035

331

. Around that period though and due

to the strong investments in variable RES E and the increasing needs

for flexible capacity, the situation turns around, rendering these units

very profitable.

The situation for RES E is contrasted, depending on the level of

maturity of RES E technologies. Even if some less advanced RES E

technologies would need support to emerge as part of the power

generation mix towards 2030, this is not the case for many competitive

RES E technologies, such as hydro, onshore wind and solar PV (at least

in some parts of Europe)

332

. For a more elaborate discussion on this

point see the text box below on RES E investments and market design.

Coal / Lignite

Peak devices

RES E

(excl. biomass)

CHP

biomass)

(incl. CHP

333

remains unprofitable over the whole projection period when

considering only their electricity market related revenue streams. It

should be considered though that the main use of these plants is

assumed to be the production of industrial steam/heat, with electricity

being a side-product. Therefore, no conclusion should be made based

on these partial results. Similar for biomass (outside industrial CHP),

additional revenues are assumed to come from support schemes and

the value of heat when producing heat for district heating.

331

332

333

"METIS

Study S16"

shows that peakers’ revenues highly depend on the occurrence of scarcity hours that

happen mainly during very cold years, which constitutes an additional risk for peakers who rely on scarcity

prices to generate revenues. On the contrary, base-load producers have more stable revenues from one year to

the other.

A more detailed analysis can be found in the RED II impact assessment, specifically in Annex 5, where a

detailed analysis on the viability of RES E projects is presented for the period post-2020.

The category of CHP plants includes only those which serve industrial steam and district heating as their main

function. Other CHP plants have been appropriately distributed within the capacities of the respective

technologies.

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The following table summarizes the projected profitability for all generation technologies over

the period 2020-2050:

Table 20: Average profits or losses

334

for different plant categories in the case of an energy

only market over the projected horizon 2020

–

2050 in EUR/kW for EU28

Total

Sol i ds

Stea m turbi nes oi l /ga s

CCGT

Pea k

Nucl ea r

La kes

Run of Ri ver

Geotherma l

Wi nd ons hore

Sol a r PV (l a rge)

RES (s ma l l )

Wi nd offs hore

Bi oma s s

Sol a r therma l

Ti da l

CHP s ol i ds

CHP ga s

CHP bi oma s s

CHP oi l

2020

-46.9

69.9

-66.2

-75.1

-53.7

-47.5

144.0

268.4

153.3

1.9

-63.0

-115.0

-6.2

-137.9

-678.7

-5,569.9

-136.9

-163.8

-338.5

-333.2

2025

9.1

94.8

-116.7

-55.6

-50.1

102.8

162.3

309.3

235.4

30.7

-1.2

-101.4

-83.8

-171.2

-666.4

-4,105.4

-203.5

-185.8

-336.1

-459.2

2030

35.7

1.6

-117.3

-23.2

-51.9

141.0

185.6

335.4

313.8

82.2

25.6

-48.5

-85.9

-141.3

-466.2

-308.5

-208.5

-169.3

-324.0

-487.9

2035

78.4

-111.5

-93.8

27.6

-11.8

249.4

205.9

355.3

438.3

117.2

58.6

34.7

-18.2

-59.0

-422.0

-252.8

-227.6

-128.4

-289.9

-372.3

2040

68.8

-80.9

-90.7

-23.5

224.2

233.8

211.9

304.9

477.1

118.5

49.0

19.1

2.6

-74.1

-385.3

-175.7

-315.5

-207.7

-292.3

-367.8

2045

129.2

-89.7

-68.5

21.1

344.1

374.5

270.5

345.3

443.4

173.1

86.1

24.9

127.7

20.5

-265.1

-116.0

-364.8

-235.5

-128.3

-629.5

2050

80.5

-207.7

-120.9

-59.6

36.8

259.4

263.4

209.0

356.1

142.1

62.5

5.0

55.9

13.2

-415.0

-130.0

-434.8

-328.0

-90.1

-413.8

Source: NTUA modelling (PRIMES/OM)

It is important to highlight that the above analysis has been performed per individual plant basis.

Although this reflects project finance type of decisions, it does not reflect portfolio-based

decisions, which are closer to the usual power sector business model for utilities, due to

economies of scale. The portfolio approach (e.g. investing in both wind and peak generators)

allows the sharing of risks between different technologies, directly improving the performance

of the investments.

Similarly the above analysis does not consider the existence of any type of contracts between

supply and demand, be it long-term contracts, futures (e.g. EEX hedging products) or even

typical contracts between utilities and residential/commercial consumers. Such contracts,

concluded on a purely voluntary market basis, would again transfer part of the risk of the

generators to consumers, in exchange of higher security of supply, protection against price

spikes and more stable payments, allowing both sides to better manage their risks. This would

in turn increase the likelihood of the investments turning out to be profitable.

The above analyses also highlights that the market, of improved along the lines with the

measures assessed in the present impact assessment, can deliver to a large extent the necessary

334

The reported results concern financial evaluation at individual plant level. In the context of PRIMES/OM,

profits or losses are defined as follows: revenues from day-ahead market, revenues from reserve market,

revenues from CM (if applicable) minus sum of fuel costs, variable non-fuel costs, O&M fixed costs and

capital costs. For capital costs the model estimates the not-yet amortized value of initial investment

expenditure for old plants (including cost of refurbishment if applicable) and the investment expenditures for

new investments. As these are aggregate numbers, they approximate but are not equal to the missing money

(as when calculating aggregate profits, one unit's losses may cancel out with another unit's profits, while when

calculating missing money you only add the losses).

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investments for a wide range of technologies in the long term, thereby reducing the need for

government intervention to support investment in electricity resources.

Box 7: RES E investments and market design

Amongst all sectors that make up our energy system, electricity is the most cost-effective to

decarbonize. Currently about one fourth of Europe's electricity is produced from renewable

energy sources. Modelling indicates that the share of RES E in electricity generation needs to

almost double by 2030 in order for the EU to meet its 2030 energy and climate targets.

A functioning market is the most efficient tool to implement the decarbonisation agenda at least

costs while securing electricity supplies at all times.

The Commission's ambition for the post-2020 context is that renewable electricity generators

can earn an increasingly larger fraction of their revenues from the energy markets.

This ambition requires adapting the market design for the cost-effective operation of variable,

decentralised generation, and improving the market as the catalyst for investments by removing

regulatory failures and market imperfections. In a nutshell, markets will need to:

(a)

be more focused on short-term trading, including cross-border trading, to allow

electricity from wind and solar energy to effectively compete in the market;

(b)

link wholesale and retail markets to increase the flexibility of the system, let consumers

benefit from times of cheap electricity, let them engage in demand response systems

and produce electricity themselves; and,

(c)

become even better at generating investment signals

–

as a matter of principle, it should

be the market through its price signals triggering investments.

In this context, the present impact assessment investigates a number of options that improve

market functioning by removing market distortions between different types of generation, that

render the market's operation more flexible and adapted to the cost-effective operation of

variable generation and improving the conditions for the participation of decentralised, flexible

resources, such as demand and storage, into the market. Moreover, it investigates various means

to improve price signals inciting investment in the right resources and location and investments

in infrastructure.

The enhanced market design will improve the viability of RES E investments, but electricity

market revenues alone might not prove sufficient in attracting renewable investments in a

timely manner and at the required scale to meet EU's 2030 targets.

The enhanced market design and the strengthened ETS will improve the viability of RES E

investments, in particular through the following channels:

Where the marginal producer is a fossil fired power plant, a higher carbon price translates

into higher average wholesale prices. The existing surplus of allowances is expected to

decrease due to the implementation of the Market Stability Reserve and the higher Linear

Reduction Factor, reducing the current imbalance between supply and demand for

allowances;

Greater system flexibility will be critical for a better integration of RES E in the system,

reducing their hours of curtailment and the related forgone revenues; improving overall

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system flexibility is equally essential to limit the merit-order effect

335

and thus in avoiding

the erosion of the market value of RES E produced electricity

336

The revision of priority dispatch rules and the better functioning of the short-term markets

will strongly reduce (even eliminate according to the analysis) the occurrence of negative

prices

–

leading again to higher average wholesale prices (especially during the hours with

significant variable RES E generation);

Improved market rules for intraday and balancing markets will increase their liquidity and

allow access to those markets for all resources, thus helping RES E generators reduce their

balancing costs;

Removing existing (explicit or implicit) restrictions for the participation of all resources to

the reserve and ancillary services markets will allow RES E to generate additional revenues

from these markets.

Price signals reflecting the actual value of electricity at each point of time, as well as the

value of flexibility, will help ensure that flexible capacity is properly rewarded, channelling

investment into such capacities or prevent its decommissioning.

With technology costs gradually reducing, ETS price increasing and the electricity market

prices better reflecting the value of electricity, RES E investments in the electricity market will

gradually become more and more market-based, reflecting the balance of supply and demand

for the coming years and the associated costs to each technology.

The present impact assessment and the one on the RED II thus jointly come to the conclusion

that the improved electricity market, in conjunction with a revised ETS could, under these

conditions, deliver investments in the most mature renewable technologies (such as solar PV

and onshore wind).

However, despite best efforts in market integration, electricity market revenues alone might not

prove sufficient in attracting renewable investments in a timely manner and at the required scale

to meet EU's 2030 targets. This investment gap is analysed in more details in the RES II impact

assessment. The analysis shows that the picture is dynamic, with the enhanced market design

and the strengthened ETS gradually and increasingly improving RES E profitability over the

2021-2030 period. At the beginning of the period, over-capacity, low ETS and wholesale

market prices and still high RES E technology costs, make the case for investments in RES E

technologies more difficult. However, an increasing ETS price, a more flexible and dynamic

electricity market, technology costs reductions and adjustments in capacity increasingly

facilitate investments over this period

337

335

336

Also referred occasionally as the 'cannibalisation effect'.

The inherent variability of wind exposure and solar radiation affects the price that variable renewable

electricity generators receive on the market (market value). During windy and sunny days the additional

electricity supply reduces the prices. Because the drop is larger with more installed capacity, the market value

of variable renewable electricity falls with higher penetration rate, translating into a gap to the average market

value of all electricity generators over a given period (See Hirth, Lion, "The

Market Value of Variable

Renewables",

Energy Policy, Volume 38, 2013, p. 218-236)

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The impact assessment for RED II concludes that over the period 2021-2030 around half of the

additional RES E capacity will still need some kind of support, but with significant decrease in

the number of investments needing support towards 2030.

In particular, less mature RES E technologies, such as off-shore wind, will likely need some

form of support throughout the 2021-2030 period. These technologies are required if RES E

technologies are to be deployed to the extent required for meeting the 2030 and 2050 energy

and climate objectives, and provide an important basis for the long-term competitiveness of an

energy system based on RES E.

The picture also depends on regions. RES E technologies are more easily financed from the

market in the regions with the highest potential (e.g. onshore wind in the Nordic region or solar

in Southern Europe), while RES E continue to largely require support in the British Isles and in

Central Europe.

Additionally, it should be noted that the speed at which RES E parity

338

is reached, in addition

to the successful implementation of the MDI and ETS, also depends on factors that lay outside

of the scope of these initiatives, including: (i) continued decrease in technology costs for RES

E as well as complementary technologies (e.g. storage); (ii) the availability of (reasonably

cheap) capital, which is a function of many variables, including project-specific and RES E

framework-specific risks, but also general country risk; (iii) continued social acceptance; (iv)

sufficiently high and stable fossil fuel prices.

The need for a framework for RES E support schemes

In order to address the risks associated with investments in RES E and the chance of failing to

meet EU's 2030 target for RES, the MDI and the RED II impact assessments jointly consider

that electricity market and ETS policies need to be complemented by an improved policy

framework on RES E support schemes.

Against this background, the RED II impact assessment investigates options to ensure that, if

and where support is needed, support is only applied where needed in a manner that is: (i) cost-

effective and kept to a minimum, and (ii) creates as little distortions as possible to the

functioning of electricity markets, and to competition between technologies and between

Member States. Indeed, the market can only deliver the full benefits sketched above, if policies

fostering RES E are compatible with the market environment in which they operate.

In particular, the RED II impact assessment suggests creating a common European framework

for support schemes. The framework would be effective as it would define design principles (i)

that ensure sufficient investor certainty over the 2021-2030 and (ii) require the use (where

needed) of market-based and cost-effective schemes based on emerging best practice design

(including principles that are not covered by the current State Aid guidelines).

At the same time, the framework would be proportionate by leaving actual implementation to

the State Aid guidelines (e.g. for the definition of thresholds applicable for any foreseen

exemptions) and, most importantly, to the case by case, evidence-based, in-depth assessment

338

i.e. the moment when LCOE decreases to the level of the actual market value of the asset to be financed.

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of individual schemes by the services of DG Competition .Importantly, the framework would

enshrine in legislation and expand the requirement to tender support; it would define tender

design principles, based on emerging best practice, to ensure the highest cost-efficiency gains

and to ensure market incentives are least distorted by the support mechanism.

The framework would thus strengthen the use of tenders as a natural phase-out mechanism for

support, by which a competitive bidding process determines the remaining level of support

required to bridge any financing gap

–

such level of support being expected to disappear for the

most mature technologies over the course of the 2021-2030 period.

The importance of a framework for RES E support schemes for the present initiative.

It is also important to note that the progressive reform of RES E support schemes as proposed

by the RED II initiative, building on the EEAG, is a prerequisite for the results of the present

initiative to come about. In order to ensure that a market can function, it is necessary that market

participants are progressively exposed to the same price signals and risks. Support schemes

based on feed-in-tariffs prevent this and would need to be phased-out, with limited exemptions,

and replaced by schemes that expose RES E to price signals, as for instance premium based

schemes. This would be further supported by setting aid-levels through auctioning as RES E

investment projects will then be incentivised to develop business models that optimise market-

based returns

339

How different types of CMs might affect RES E remuneration in the market

In market-wide, volume-based CMs, assets are remunerated if they can respond to specific

technical performance criteria (i.e. in practice if they are dispatchable). Hence, it is likely that

variable RES E producers (wind and solar) cannot participate in such schemes to the same

extent as dispatchable generators. As the introduction of a market-wide volume-based scheme

might render scarcity-based pricing less effective, RES E producers might receive less income

then they would otherwise be able to earn on energy-only markets. A well-designed strategic

reserve (provided it is activated (only at value of lost load and activated as a measure of last

resort (see above)), is less likely to have a negative impact on market revenues for intermittent

RES E, as such a scheme relies on commodity price signals only and does not interact with

scarcity-based pricing.

6.2.6.4.Level and volatility of wholesale prices

The analysis performed using all three models (METIS, PRIMES/IEM, PRIMES/OM)

confirms that the projected investments in low carbon technologies, combined with increased

demand response participation, are not expected to lead to the collapse of the wholesale market

prices in the short and medium term. Although there will be hours with low (or even negative)

prices, the wholesale prices will most probably be set by the marginal thermal generation

technology during most hours of the year. Table 21 presents the distribution of wholesale prices

339

See also Annex IV for more information for information on the robustness on

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in 2030, assessed for the various options of Problem Area I with PRIMES/IEM. Results indicate

that the wholesale prices will fluctuate, but within reasonable limits on an EU level

340

Table 21: Distribution of load weighted day-ahead market prices

341

in 2030

Number of Hours

Day-ahead price

in 2030 (EUR/MWh)

Option 0

Option 1(a)

Option 1(b)

Option 1(c)

Strengthening

Fully

Level playing

Baseline

short-term

integrated

field

markets

Below 60

Between 60-80

Between 80-90

Between 90-100

Between 100-110

Between 110-120

Between 120-140

Above 140

2482

3254

2197

372

455

2642

3290

2013

555

260

1155

2394

2870

1288

528

353

1572

3169

3121

484

150

264

Source: NTUA Modelling (PRIMES/IEM)

The above results do indicate that the improved market design will lead to more volatile average

hourly prices, partly due to the introduction of locational signals which reveal the different

value of electricity in the various nodes. This volatility though will be fairly restricted and will

not be the result of extreme price fluctuations between zero and VoLL. The observed price

ranges will be fairly constrained, as long as the share of variable RES E remains within certain

limits

342

. When the share of RES E, and specifically of variable RES E technologies, exceeds

these rough limits though, price volatility may increase significantly if other resources like

storage are not in place yet to absorb a large part of it.

As can be seen in the table below, in 2050 the share of RES E is projected to approach 60%. In

this case the spread between the baseload and peak load prices increases significantly, mainly

due to the lower baseload prices compared to the previous periods. The average day-ahead

340

341

342

Certain Member States though with very high RES E shares, like Spain and Portugal, and limited

interconnections are expected to have significantly more volatile wholesale prices than other Member States.

Reported results reflected assumed bidding behaviour of generators. The behaviour was relatively

conservative, reflecting though a stable condition in the market and the effects of competition (though market

power was considered). The most important assumption driving these results is that plants bid above marginal

costs and the hydro plants bid at opportunity costs. Minimum price observed (on EU28 level) was not lower

than 60 EUR/MWh, highest price did not exceed 200 EUR/MWh. There were higher and lower prices on

Member State level.

A study by METIS finds that as long as the share of solar generation is lower than 10-12% of total electricity

generation, solar production coincides with periods of high power demand and tends to smooth-out residual

demand over the day, which is expected to lead to less variable prices. This changes though considerably for

higher shares of solar. On the other hand, wind energy is directly related to variability and is a significant

driver for flexibility needs. "METIS

Study S7: The role and need of flexibility in 2030. Focus on Energy

Storage",

Artelys (2016).

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market prices though remain high throughout the projection horizon, as thermal generation is

still expected to be marginal (thus setting the day-ahead market price) during most hours of the

year.

Table 22: Average wholesale prices and RES E Shares

2020

2025

2030

2035

2040

2045

2050

Average wholesale market prices

343

(EUR 13/MWh)

Average day-ahead market prices

baseload

mid-merit

peak load

Spread between average

baseload and peak load SMP

103

137

118

135

115

116

134

135

108

137

149

122

138

Share of RES E in net electricity generation (%)

Share of variable RES E

Solar

Wind

Source: NTUA modelling (PRIMES/OM)

30.8

4.8

14.4

36.0

7.7

17.0

40.4

8.9

20.4

43.0

9.4

22.7

49.6

9.9

29.3

53.2

11.1

32.1

57.5

13.6

34.1

6.3.

Impact Assessment for problem Area III (reinforce coordination between Member

States for preventing and managing crisis situations)

Methodological Approach

In this section the impacts of the different policy options are identified and assessed. The

options proposed should first and foremost be effective in improving trust of Member States to

rely on neighbours' electricity markets in times of system stress. They should also lead to a

more effective functioning of markets, with less undue market distortions. Additionally,

reinforced coordination and cooperation between Member States in the identification and

mitigation of risks and the management of crisis have also been identified as specific objectives.

The methodological approach followed for this analysis is mostly qualitative; however some

quantitative analysis is provided as well, notably via the METIS simulations.

As regards the impacts, given the administrative nature of the measures and the objectives

pursued, the most relevant impacts in terms of magnitude are the

economic

impacts.

343

Based on the modelling methodology followed, described in Annex IV, reported wholesale prices reflect the

level of electricity prices which would lead to the recovery of the full costs of generators only via the wholesale

market, on a plant by plant basis and over the lifetime of each asset in the case of an Energy only Market (i.e.

Option 1). This modelling context differs significantly from the current one, characterised by different

underlying market conditions (overcapacity, low fuel prices, distorted markets etc). See also Box 9 in Section

6.2.6.4 for a further discussion on this topic.

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The measures proposed (e.g. enhanced regional coordination and information exchange)

anticipates a very limited impact, if any, on the

environment.

Therefore, the assessment does

not examine the impact of the proposed measures on the environment.

Impacts of Policy Option 1 (Common minimum rules to be implemented by Member

States)

6.3.2.1.Economic impacts

Overall, the policy tools proposed under this option should have positive effects. Putting in

place a more common approach to crisis prevention and management would not entail

additional costs for businesses and consumers. It would, by contrast, bring clear benefits to

them.

First, a more common approach would help better prevent blackout situations, which are

extremely costly. The immense costs of large-scale blackouts provide an indication of potential

benefits of improved preparation and prevention

344

Table 23: Overview over most severe blackouts in Europe

Number of end-

Duration,

Country & year

consumers

energy not

interrupted

served

0.86 million

2.1 hours, 18

Sweden/Denmark,

(Sweden); 2.4

GWh

2003

million (Denmark)

2 days–2 weeks,

France, 1999

1.4 - 3.5 million

400 GWh

Italy/Switzerland,

55 million

18 hours

2003

1 day

–

5 weeks,

Sweden, 2005

0.7 million

11 GWh

Less than 2

Central Europe, 2006

45 million

hours

Estimated costs to

whole society

EUR 145

–

180

million

EUR 11.5 billion

EUR 400 million

Source: SESAME: Securing the European Electricity Supply Against Malicious and Accidental Threats

A more common approach to emergency handling, with an obligation for Member States to

help each other, would help to avoid or limit the effects of potential blackouts. A more common

approach, with clear obligations to e.g., follow up on the results of seasonal outlooks, would

also reduce the costs of remedial actions TSOs have to face today. This, in turn, should have a

positive effect with a reduction of costs overall.

344

Previous blackouts in Europe had severe consequences. For example, the blackout in Italy in September 2003

resulted in a power disruption for several hours affecting about 55 million people in Italy and neighbouring

countries and causing around 1.2 billion euros worth of damage. (source:

The costs of blackouts in Europe

(2016), EC CORDIS:

http://cordis.europa.eu/news/rcn/132674_en.html).

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In addition, improving transparency and information exchange would facilitate coordination,

leading to a more efficient and less costly measures.

By ensuring that electricity markets operate as long as possible also in stress situations, cost-

efficient measures to prevent and resolve crisis are prioritized.

6.3.2.2.Who would be affected and how

Option 1 is expected to have a positive effect on society at large and electricity consumers in

particular, since it helps prevent crisis situations and avoid unnecessary cut-offs. Given the

nature of the measures proposed, no major other impact on market participants and consumers

is expected.

On cybersecurity, given the voluntary approach of this option, several stakeholders (TSOs,

DSOs, generators, suppliers and aggregators) could be affected, as long as they implement the

guidance proposed. However, the impact is estimated limited as the costs of cybersecurity for

regulated entities merely need to get considered and taken into account by the regulatory

authority. Thus, the TSOs and DSOs affected could recover their costs via grid tariffs. In that

case, the pass through of costs would have an impact on consumers that could see a slightly

increased in the final prices of electricity.

6.3.2.3.Impact on businesses and public authorities

The preparation of risk preparedness plans as well as the increased transparency and

information exchange in crisis management imply a certain administrative effort

345

. However,

the impact in terms of administrative impact would remain low, as currently Member States

already assess risks relating to security of supply, and all have plans in place for dealing with

electricity crisis situations

346

In addition, it is foreseen to withdraw the current legal obligation for Member States to draw

up reports monitoring security of supply

347

, as such reporting obligation will no longer be

necessary where national plans reflect a common approach and are made transparent. This

would reduce administrative impacts.

345

346

347

Administrative costs are defined as the costs incurred by enterprises, the voluntary sector, public authorities

and citizens in meeting legal obligations to provide information on their action or production, either to public

authorities or to private parties.

See

Risk Preparedness Study.

Article 4 of the

Electricity Directive;

Article 7 of the

Electricity SoS Directive.

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Impacts of Policy Option 2 (Common minimum rules to be implemented by Member

States plus regional co-operation)

6.3.3.1.Economic impacts

This option would lead to better preparedness for crisis situations at a lesser cost through

enhanced regional coordination. The results of METIS simulations

348

show that well integrated

markets and regional coordination during periods of extreme weather conditions (i.e. very low

temperature

349

) are crucial in addressing the hours of system stress (i.e. hours of extreme

electricity demand), and minimizing the probability of loss of load (interruption of electricity

supply).

Most importantly, while a national level approach to security of supply disregards the

contribution of neighboring countries in resolving a crisis situation, a regional approach to

security of supply results in a better utilization of power plants and more likely avoidance of

loss of load. This is due to the combined effect of the following three factors: (i) the variability

of renewable production is partly smoothed out when one considers large geographical scales,

(ii) the demands of different countries tend to peak at different times, and (iii) the power supply

mix of different countries can be quite different, leading to synergies in their utilization.

The following table compares the security of supply indicator, EENS, assessed by METIS for

the three levels of coordination (national, regional, European)

350

. It highlights the highest value

of the loss of load (electricity non-served expressed as percentage of annual load) when it is

measured in a scenario of non-coordinated approach, which does not take into account the

potential mutual assistance between countries. When cooperation takes place among Member

States, the percentage of electricity non-served significantly decreases.

Table 24 - Global expected energy non-served as part of global demand within the three

approaches for scenario ENTSO-E 2030 v1 with CCGT/OCGT current generation

capacities

Level

EENS (% of annual load)

–

ENTSO-E V1 scenario

National level

Regional level

European level

0,36 %

0,02 %

0,01 %

ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario where no common

European decision regarding how to reach the CO

-emission reductions has been reached. Each country has its

own policy and methodology for CO2, RES and resource adequacy.

Source: METIS

348

349

350

"METIS Study S16: Weather-driven revenue uncertainty for power producers and ways to mitigate it",

Artelys

(2016).

Even though periods with very low temperature occur rarely (9C difference between the 50 year worst case

and the 1% centile) countries can face high demand peaks (e.g. Nordic countries and France) mainly due to

the high consumption for the electric heating. As example, the additional demand for the 50 years peak

compared to the annual peak demand is 23% for France, 18% for Sweden and 17.3% for Finland.

"METIS Study S04: Stakes of a common approach for generation and system adequacy",

Artelys (2016).

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The EENS for the three levels of coordination are represented on the figure below. When the

security of supply is assessed at the national level, many countries of central Europe seem to

present substantial levels of loss of load. However, since these countries are interconnected, a

regional assessment of security of supply (taking into account power exchanges within this

region) significantly decreases the loss of load levels.

Figure 14 - EENS (%) estimation by country for scenario ENTSO-E 2030 v1 with

CCGT/OCGT current generation capacities. From left to right: EENS estimated at

European, regional and national levels

CCGT: Combined Cycle Gas Turbine OCGT: Open Cycle Gas Turbine

ENTSO-E 2030 v1: vision for 2030 "Slowest progress". The perspective of Vision 1 is a scenario where no common

European decision regarding how to reach the CO

-emission reductions has been reached. Each country has its

own policy and methodology for CO2, RES and resource adequacy.

Source: METIS

METIS simulations also show that thanks to regional cooperation the stress situations would

decrease and concentrate in a limited number of hours that may occur simultaneously

351

Therefore, it highlights the need for specific rules on how Member States should proceed in

these particular circumstances, as proposed in this Option 2.

As the overall cost of the system would decrease thanks to enhanced coordination this could

have a positive impact on prices for consumers.

On the contrary, a lack of coordination on how to prevent and manage crisis situations would

imply significant opportunity costs. A recent study also evidenced that the integration of the

European electricity market could deliver significant benefits of EUR 12.5 to 40 billion until

2030. However, this amount would be reduced by EUR 3 to 7.5 billion when Member States

pursue security of electricity supply objectives following going alone approaches

352

351

352

Please also see in

Annexes to the Impact Assessment: Assessment of the Measures Associated with the Main

Option:

Graphs 1 and 2 in

"6. Detailed measures assessed under problem area 3: a new legal framework for

preventing and managing crises situations".

Benefits of an Integrated European Energy Market

(2013), BOOZ&CO.

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6.3.3.2.Who would be affected and how

As in the case for Option 1, Option 2 is expected to have a positive effect on society at large

and electricity consumers in particular, since it helps prevent crisis situations and avoid

unnecessary cut-offs. Given that, under Option 2, Member States would be required to

effectively cooperate, and tools would be in place to monitor security of supply via the

Electricity Coordination Group, such crisis prevention and management would be even more

effective.

The measures would also have a positive effect on the business community, as there would be

much more transparency and comparability as regards how Member States prepare for and

intend to manage crisis situations. This will increase legal certainty for investors, power

generators, power exchanges but also for TSOs when managing short-term crisis situations.

Among the stakeholders the most affected would be the competent authorities (e.g. Ministry,

NRA) as actors responsible for the preparation of the risk preparedness plans (see below,

assessment of impacts on public authorities).

6.3.3.3.Impact on businesses and public authorities

The assessment of this option shows a limited increase in administrative impact, although it

would be to some extent higher than Option 1, given that national authorities would be required

to pre-agree part of their risk preparedness plans in a regional context.

However, existing experiences show that a more regional approach to risk assessment and risk

preparedness is technically and legally feasible. Further, since the regional parts of the plans

would in practice be prepared by regional co-ordination centres between TSOs, the overall

impact on Member States' administrations in terms of 'extra burdens' would be limited, and be

clearly offset by the advantages such co-operation would bring in practice.

353

In addition, more regional cooperation would also allow Member States to create synergies, to

learn from each other, and jointly develop best practices. This should, overtime, lead to a

reduction in administrative impacts.

Finally, European actors such as the Commission and ENTSO-E would provide guidance and

facilitate the process of risk preparation and management. This would also help reduce impacts

on Member States.

It should be noted, that under Option 2 (as is the case for Option 1) no new body or new

reporting obligation is being created, and that existing obligations are being streamlined. Thus,

the Electricity Coordination Group is an existing body meeting regularly, for the future it is

foreseen to make this group more effective by giving it concrete tasks. Further, national

reporting obligations would be reduced (e.g. repealing the obligation of Article 4 of Electricity

Directive) and EU-level reporting would take place within the context of existing reports and

353

The Nordic TSOs, regulators and energy authorities cooperate through

NordBER,

the Nordic Contingency

and Crisis Management Forum. This includes information exchange and joint working groups and

contingency planning for the overall Nordic power sector as a supplement to the national emergency work

and TSO cooperation (www.nordber.org).

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existing reporting obligations (e.g. ACER annual report Monitoring the Internal Electricity and

Natural Gas Markets).

Impacts of Policy Option 3 (Full harmonisation and full decision-making at regional

level)

6.3.4.1.Economic impacts

The regional coordination through the regional plans would have a positive impact in term of

cost as the number of plans would be necessary less than twenty-eight plans and limited to the

number of regions. In addition, the coordination at European level would decrease slightly the

loss of load level compared to the regional coordination (EENS 0.01% compared to 0.02%).

On the contrary, on cybersecurity, the creation of a dedicated agency at EU level would have

important economic implications as this agency would be a new body that does not exist yet

and which is also not foreseen in the NIS Directive. The costs of creating this new agency are

not only limited to the creation of a new agency itself, but the costs would also have to include

the roll-out of a whole security infrastructure. For example, the estimated costs of putting in

place the necessary security infrastructure and related services to establish a comparable

national body - cross-sectorial governmental Computer Emergency Response Team ("CERT")

with the similar duties and responsibilities at national level as the planned pan-European sector-

specific agency - would be approximately EUR 2.5 million

354

per national body. This means

that the costs for the security infrastructure would be manifold for a pan-European body. In

terms of human resources, for the proper functioning of the new agency with minimum scope

and tasks at EU level, it is estimated a staff of 168 full time equivalents (considering 6 full time

equivalents per Member State sent to the EU agency). The representation from all Member

States in the agency is essential in order to ensure trust and confidence on the institution.

However, the availability of network and information security experts who are also well-versed

in the energy sector is limited.

6.3.4.2.Who would be affected and how

The obligation of regional plans would have important implications for the competent

authorities as the coordination and agreement of common issues (e.g. load shedding plan,

harmonised definition of protected customers) would be a lengthy and complex process.

On cybersecurity, the creation of the new agency at EU level would mobilize highly qualified

human resources with skills in both energy and information and communication technologies.

This could have a potential impact on national administrations and energy companies as long

as some of the experts in the field could be recruited by the new institution. However, the impact

would be limited as the representation for all Member States should be guaranteed. Therefore,

a small number of experts (around 6) per country could be recruited.

354

"Impact Assessment accompanying the document Proposal for a Directive of the European Parliament and

of the Council Concerning measures to ensure a high level of network and information security across the

Union".

SWD(2013) 32 final.

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6.3.4.3.Impact on businesses and public authorities

Overall Option 3 would imply significantly administrative impact in the preparation of the

regional plans. It would require important efforts to gather information related to national and

regional circumstances and contribute to the joint task of assessing the risks and identifying the

measures to be included in the plans. In any case, it would seem difficult to coordinate within

a region the national specificities and risks originate mostly in one Member State.

The creation of a new agency on cybersecurity would imply significant administrative impacts

in the preparation and set-up of the agency, as well as in the communication structure with

already existing cross-sectorial bodies of Member States (CERTs/ Computer Security Incident

Response Teams "CSIRTs").

6.4.

Impact Assessment for Problem Area IV (Increase competition in the retail

market)

Methodological Approach

This section compares the costs and benefits of each of the policy options to address this

Problem Area in a semi-quantitative manner.

No data or methodology exists that would allow us to accurately quantify all the benefits of the

measures examined.

However, this section draws on behavioural experiments from a controlled environment to

evaluate the impact of some policy options on consumer decision-making. Where economic

impacts cannot be quantified, quantitative desktop research and case studies are used to inform

estimates of the extent of possible impacts, as well as possible winners and losers. Where

appropriate, this section aims to illustrate the possible direct benefit to consumers assuming

certain conditions. Implementation costs in terms of the impact on businesses and public

authorities were estimated using the standard cost model for estimating administrative costs.

And finally, this section also highlights important qualitative evidence that policymakers should

also incorporate into their analysis of costs and benefits.

Impacts of Policy Option 0+ (Non-regulatory approach to improving competition and

consumer engagement)

6.4.2.1.Economic Impacts

Option 0+ would lead to an estimated EUR 415 million in benefits to consumers for the period

2020-2030, which come as a result of an enforcement drive to tackle the switching costs

currently faced by an estimated 4% of all EU electricity consumers that do not comply with EU

law

355

See Annex 7.4, Section 7.4.5.

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Other unquantifiable economic benefits include improved retail level competition resulting

from the phase-out of regulated prices in some Member States

356

, and more comparison tools

that comply with the Unfair Commercial Practices Directive

357

In addition, one may expect modest, indirect improvements to the health and well-being of

energy poor consumers from the exchange of good practices stemming from the activities of

the EU Observatory for energy poverty

358

In spite of these considerations, it is unlikely that Option 0+ (Non-regulatory approach) would

most effectively address the problems identified.

First, this option does not address the poor data flow between retail market actors that

constitutes both a barrier to entry and a barrier to higher levels of service to consumers. Whereas

Option 0+ is non-regulatory, a credible policy to tackle conflicts of interest among market actors

around data handling would require a legislative intervention.

Secondly, as a non-regulatory option, the effectiveness of Option 0+ is significantly limited by

shortcomings in the existing legislation. This significantly reduces the ability to address

contract termination fees (which are currently legal under EU law), the partial availability of

comparison websites in Member States, as well as energy poverty, which the current legislation

does not require Member States to measure, and hence address it.

And finally, a non-regulatory approach to tackling price-regulation may lead to a fragmented

regulatory framework across the EU given: (i) the uncertainty that surrounds the Commission's

ability to convince hold-out Member States to voluntarily cease excessive regulatory

interventions in price-setting; and (ii) the uncertainty that surrounds the success of any

subsequent legal measures to infringe Member States on the issue.

6.4.2.2.Who would be affected and how

Consumers

will benefit from more easily being able to compare offers in the market, as well

as lower financial barriers to switching. Whilst consumer prices may rise in Member States

phasing out price regulation, this would be offset by higher levels of service and the greater

availability of value added products on the market.

Member States

will benefit from a clearer understanding and measurement of energy poverty

will have indirect positive impacts on

energy poor consumers.

Suppliers

would benefit from increased access to the market of any Member State phasing out

price regulation. However, certain suppliers would also face tougher competition and increased

pressure on margins as the result of the modestly greater consumer engagement expected.

Any increase in consumer switching would increase the administrative impacts to

DSOs.

However, these costs would be passed through to end consumers.

356

357

358

See Annex 7.2, Section 7.2.5.

See Annex 7.5, Section 7.5.5.

See Annex 7.1, Section 7.1.5.

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NRAs

in any Member States phasing out price regulation will need to significantly step up

efforts to monitor the market, ensure efficient competition, and guarantee consumer protection.

They will need to more closely monitor and report the number of disconnections. However, this

may be offset by a reduction in price setting interventions, and increased competition resulting

from greater consumer engagement.

6.4.2.3.Impact on businesses and public authorities

Option 0+ (Non-regulatory approach) would lead to quantifiable implementation costs of

around EUR 0.9 million for the period 2020-2030, all resulting from setting up and running an

EU Observatory for energy poverty

359

. It is anticipated that the soft law and enforcement

measures associated with making better use of the existing legislation on regulated prices,

switching fees and comparison tools would not result in significant additional costs compared

with a business as usual scenario.

Impacts of Policy Option 1 (Flexible legislation addressing all problem drivers)

6.4.3.1.Economic Impacts

Option 1 would lead to an estimated EUR 2.2 billion in direct benefits to consumers for the

period 2020-2030, which come as a result of: (i) reducing the switching-related charges faced

by 21% of household electricity consumers, and so helping them realize the potentially

significant gains of moving to a cheaper tariff

360

; (ii) further improvements to the switching rate

for both electricity and gas household consumers as a result of the improved availability of price

comparison tools

361

; (iii) an improved ability for consumers to identify the best offer in the

market through improved access to information on the bill (although the gains of this latter

intervention are not easy to quantify compared for instance with interventions aimed at making

switching less costly for consumers)

362

Other unquantifiable economic benefits include significantly improved retail competition

resulting from the definitive phase-out of blanket price regulation in the 17 Member States still

practicing it

363

. The impact of phasing out price regulation on retail price levels is impossible

to quantify. However, the evidence strongly suggests it will lead to higher levels of consumer

satisfaction. Indeed, even the energy component of retail bills does increase slightly in the short-

term, consumer surplus (the difference between the price of the service and the price a consumer

would be willing to pay for that service) may actually increase too as a result of the better

service levels consumers receive in the non-regulated market. In addition, retail price

competition is an important prerequisite for new services that would increase system flexibility

359

360

361

362

363

The Commission secured funding to set up the Observatory for the period 2016-2019. The costs included in

the Impact Assessment refer to the running annual cost to continue operating the Observatory. See Annex 7.4,

Table 11 and Section 7.1.5.

See Annex 7.4, Section 7.4.5.

See Annex 7.6, Section 7.6.5.

See Annex 7.4, Section 7.4.5.

See Annex 7.2, Section 7.2.5.

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(benefits examined in Section 6.1.4), and should lead to lower system costs that are passed

through to consumers in both the energy and network components of bills in the longer term.

Non-discriminatory access to consumer data and nationally harmonized data formats will also

help new suppliers and service providers to enter the market and develop innovative new

products, resulting in further competition benefits and facilitating the transition to a more

flexible electricity system

364

Greater consumer engagement will also drive retail competition improvements, as competitive

suppliers and service providers find it easier to take market share from less competitive

alternatives. Other benefits come in terms of the higher levels of service electricity consumers

can expect from more efficient data handling, and greater consumer awareness of the market

and their own energy situation.

In addition, one may expect improvements in the targeting of measures to tackle energy poverty.

Better measurement of the number of households on energy poverty will allow Member States

and the EU to design better policies and exchange good practices. A generic definition of energy

poverty in the legislation will clarify the concept of energy poverty, improving the functioning

of the current provision and further helping knowledge dissemination and synergies across EU

policies in energy efficiency and consumer protection.

6.4.3.2.Who would be affected and how

Consumers

will benefit significantly from more easily being able to compare offers in the

market, as well as lower financial barriers to switching. Whilst consumer prices may rise in the

Member States phasing out price regulation, this would be offset by higher levels of service and

the greater availability of value added products on the market. Consumers would also benefit

from increased competition and higher levels of service resulting from rules that ensure quick

and non-discriminatory access to data.

Box 8: Impacts on different groups of consumers

The benefits of the vast majority of the measures contained in the preferred options in Problem

Areas I, II and III would manifest through lower system costs and greater system reliability,

and therefore accrue to all consumers in an even manner. However, most of the measures

contained in the preferred option of Problem Area IV, above, would benefit certain kinds of

consumers more than others.

For example, whereas energy poor households would be the chief beneficiaries of new

obligations to measure energy poverty levels, the marginally increased burdens of these

obligations would be socialized amongst other ratepayers/taxpayers. In addition, whereas

phasing out price regulation would free public finances to better protect households who qualify

for targeted social support measures (i.e. vulnerable and/or energy poor consumers), the biggest

losers from this policy would be high-volume, often higher-income consumers who have

hitherto benefitted from retail prices that have been set at artificially low levels. Both these

measures can therefore be considered progressive in nature i.e. they tend to redistribute surplus

364

See Annex 7.3, and

“Policies for DSOs, Distribution Tariffs and Data Handling”

(2016) Copenhagen

Economics, and VVA.

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from relatively high-income ratepayers/taxpayers in order to increase the welfare of lower-

income ratepayers.

The measures on switching-related fees and comparison tools would predominantly benefit

consumers who are engaged in the market i.e. those who compare offers and/or switch

regularly. Whilst the measures would also increase consumer engagement levels, and whilst the

increased competition engendered by the measures would lead to more competitive offers on

the market, disengaged consumers, including consumers who may be vulnerable, will not reap

as many direct benefits.

And finally, the benefits of the billing measures would accrue predominantly to consumers who

do not engage in the market or better control their energy consumption because of insufficient

billing information or confusing bills. This may include a varied range of consumers, including

certain vulnerable consumers, or those who are time poor.

Many

Member States

will benefit from a clearer understanding of energy poverty, which will

have indirect positive impacts on

energy poor consumers.

However, Member States will also

need to collect and report more information on energy poverty as a result of requirements in

this option.

Suppliers

would benefit from increased access to the market of the Member States phasing out

price regulation. New entrants and

energy service companies

offering innovative products

would also benefit from quick and non-discriminatory access to data. However, suppliers would

also likely face increased pressure on margins as the result of the modestly greater consumer

engagement expected. Certain suppliers may need to adjust contractual conditions and reformat

their consumer bills in order to comply with new requirements on contract termination fees and

billing information. And they would likely also bear the brunt of the significant costs to protect

energy poor consumers.

TSOs and DSOs

are normally the market actors charged with data management, they would

be the most affected by the new data management requirements

–

particularly the DSOs who

currently fall below the unbundling threshold as they would need to implement further measures

to ensure non-discriminatory data handling. Any increase in consumer switching would also

increase the administrative impacts to

DSOs.

However, all these costs would be passed through

to end consumers. In addition, network operators would benefit from the anticipated entrance

of aggregators and other energy service companies who facilitate network flexibility, as a result

of non-discriminatory data flows.

NRAs

in the 17 Member States phasing out price regulation will need to significantly step up

efforts to monitor the market, ensure efficient competition, and guarantee consumer protection.

However, these impacts may be offset by increased consumer engagement, which would

naturally foster competition in the market.

6.4.3.3.Impact on businesses and public authorities

It is estimated that implementing the consumer-related elements of Option 1 (Flexible

legislation) would lead to quantifiable costs of between EUR 21 million and EUR 24 million

for the period 2020-2030. These would mainly stem from national authorities having to set up

and run certification schemes for energy comparison tools or an independently run energy

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comparison tool themselves

365

. However, many suppliers would also bear costs associated with

modifying their consumer bills to comply with the modest requirements in this option

366

Unquantifiable impacts come in the form of the reduced contractual freedom that suppliers

have, which is associated with the restriction on contract termination fees for certain kinds of

contracts only

367

Implementing the energy poverty provisions in Option 1 (Flexible legislation) would result in

quantifiable costs of EUR 2.3 million for the period 2020-2030. These primarily result from

measuring energy poverty making reference to household income and household energy

expenditure using data already collected by Member States

368

Significant, albeit unquantifiable costs are associated with creating a level playing field for

access to data in Option 1 (Flexible legislation). In particular, ensuring that Member States

implement a standardised data format at the national level will significantly impact many

market actors (suppliers, DSOs, third parties such as energy service companies, data

administrators), who would have to redesign their IT systems to accommodate this format.

However, these costs will be mitigated by the fact that measures can be applied independently

of the data management model that each Member State has chosen. This reduces the potentially

very significant scope for sunk costs if Member States were to all conform to a common data

management model

369

Impacts of Policy Option 2 (Harmonization and extensive safeguards for consumers

addressing all problem drivers)

6.4.4.1.Economic Impacts

Option 2 (Harmonization and extensive safeguards) could lead up to up to EUR 3.5 billion in

direct benefits to consumers for the period 2020-2030, which come as a result of: (i) an outright

ban on all switching-related charges

370

; (ii) further improvements to the switching rate as a

result of every Member State establishing a government (funded) price comparison tool

guaranteed to work in the consumer's interest

371

; (iii) an improved ability for consumers to

identify the best offer in the market through fully standardised billing information

372

However, there is greater uncertainty surrounding the benefits that stem from these

interventions. Whilst an outright ban on all switching-related charges would increase the

financial incentive to switch, it could also make it more difficult to finance certain energy

service investments (i.e. solar panels or energy efficiency upgrades packaged with energy

supply contracts) if implemented poorly. It might also result in a smaller range of tariffs

365

366

367

368

369

370

371

372

See Annex 7.5, Section 7.5.5.

See Annex 7.6, Section 7.6.5.

See Annex 7.4, Section 7.4.5.

See Annex 7.1, Section 7.1.5 and Table 16.

See Annex 7.3, and “Policies

for DSOs, Distribution Tariffs and Data Handling”

Copenhagen Economics,

and VVA (2016).

See Annex 7.4, Section 7.4.5.

See Annex 7.5, Section 7.5.5.

See Annex 7.6, Section 7.6.5.

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available to consumers. Not all government (funded) price comparison tools may work better

for consumers than the comparison tools already available on the market. And it may be

difficult, if not impossible, to devise a standard EU bill design that accommodates differences

in consumer preferences and market conditions in all Member States.

Whilst phasing-out blanket price regulation in the 17 Member States still practicing it would

lead to improved retail competition, defining the conditions under which price regulation could

continue at the EU level would be problematic. In particular, permitting price regulation for

households who consume below a certain price threshold would not accurately target those

most in need of assistance. In addition, permitting regulators to only set price caps above cost

would be difficult to enforce due to opaque cost structures. It also risks holding back

investments in product innovation and service quality, which require higher margins

373

. As with

Option 1 (Flexible legislation), the impact of phasing out price regulation on retail price levels

is impossible to quantify, whereas the evidence strongly suggests it will lead to higher levels of

consumer satisfaction.

Defining a specific EU data management model for all Member States, such as an independent

central data hub, would bring similar benefits to Option 1 in terms of helping new suppliers and

service providers to enter the market. In addition, it would be easier to enforce at the EU level

374

6.4.4.2.Who would be affected and how

Consumers

will benefit from more easily being able to compare offers in the market, as well

as lower financial barriers to switching. However, these gains may be tempered by a reduction

in the availability of beneficial products on the market. Whilst consumer prices may rise in the

Member States phasing out price regulation, this would be offset by higher levels of service and

the greater availability of value added products on the market. Consumers would also benefit

from increased competition and higher levels of service resulting from rules that ensure quick

and non-discriminatory access to data.

Energy poor consumers

in many Member States would enjoy significant benefits from the

comprehensive set of disconnection safeguards outlined as they are more likely to be on risk of

disconnection. Whilst many

Member States

will benefit from a prescriptive EU definition of

energy poverty and from better information on the energy efficiency of the housing stock, the

benefits of better measurement may not composite for the significant resources required to

survey the housing stock at national level. Energy poor and vulnerable consumers may also be

impacted by more poorly targeted support as the result of permissible instances of price setting

being defined at the EU-level, rather than being assessed on a case by case basis.

Suppliers

would benefit from increased access to the market of the Member States phasing out

price regulation. However, all suppliers would need to significantly reformat their bills in order

to comply with a standard EU bill design. They would likely also bear the brunt of the very

significant costs to protect energy poor consumers introduced under Option 2 (Harmonization

and extensive safeguards)

–

in particular the complete ban on winter disconnections. However,

373

374

See Annex 7.2, Section 7.2.5.

See Annex 7.3, and

“Policies for DSOs, Distribution Tariffs and Data Handling”

Copenhagen Economics,

and VVA (2016)

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new entrants and

energy service companies

offering innovative products would benefit from

quick and non-discriminatory access to data.

TSOs and DSOs

are normally the market actors charged with data management, they would

be the most affected by the requirement to establish a standard EU data management model that

all Member States. Indeed, since many would incur significant sunk costs in adopting a model

different from their own, the impacts could be significant. However, all these costs would be

passed through to end consumers. In addition, network operators would benefit from the

anticipated entrance of aggregators and other energy service companies who facilitate network

flexibility, as a result of non-discriminatory data flows.

NRAs

in the 17 Member States phasing out price regulation will need to significantly step up

efforts to monitor the market, ensure efficient competition, and guarantee consumer protection.

However, these impacts may be offset by increased consumer engagement, which would

naturally foster competition in the market.

6.4.4.3. Impact on businesses and public authorities

It is estimated that implementing the consumer-related elements of Option 2 ((Harmonization

and extensive safeguards) would lead to quantifiable costs of between EUR 42 million and EUR

51 million for the period 2020-2030. These would mainly stem from national authorities having

to set up and run energy comparison tools

375

, and energy suppliers having to heavily modify

their consumer bills to comply with the requirements in this option

376

. Unquantifiable impacts

come in the form of the greatly reduced contractual freedom that suppliers have, which is

associated with the ban on contract termination fees

377

Implementing the energy poverty provisions in Option 2 (Harmonization and extensive

safeguards) would result in quantifiable costs of between EUR 1.2 billion and EUR 3.8 billion

for the period 2020-2030. Unless public authorities step in, these costs would most likely fall

on suppliers and result from: (i) the additional costs of unpaid bills resulting from the

requirement for suppliers to give all customers a disconnection notice of at least two months;

(ii) the additional costs of unpaid bills resulting from the cessation of winter disconnections;

and (iii) refinancing costs resulting from the obligation to offer all consumers the possibility to

delay payments or restructure their debt prior to disconnection

378

As these costs associated with disconnection safeguards are large, it is likely that this option

would result in distortions to competition in Member States where the public does not cover

these costs. Whilst suppliers active in such markets could raise margins to socialize losses from

unpaid bills, certain suppliers

–

especially smaller ones who are less well equipped to deal with

the additional pressure on their operations

–

may seek to avoid entering markets where there

are likely to be significant risks of disconnections.

Member States may be better suited to design these schemes to ensure that synergies between

national social services and disconnection safeguards are achieved. These synergies may also

375

376

377

378

See Annex 7.5, Section 7.5.5.

See Annex 7.6, Section 7.6.5.

See Annex 7.4, Section 7.4.5.

See Annex 7.1, Section 7.1.5 and Table 24.

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result in public sector savings which may be significant given the substantial costs of these

measures and the overlap between social policy and disconnections for non-payment.

Very significant costs are associated with creating a level playing field for access to data in

Option 2 (Harmonization and extensive safeguards). A mandatory data handling model will

imply the administrative costs of defining and designing such a model, and more importantly

high sunk costs for existing data models and additional costs for rebuilding a new one, both in

terms of personnel costs and IT infrastructure. Designing and building a new data handling

model is a complex procedure and may well take several years of planning and implementation.

For example, in Denmark alone, the central data hub took more than 4 years to design and

develop in its simple form, and 7 years in its enhanced form, and is estimated to a cost of

approximately EUR 165 million, where approximately EUR 65 million accrued to the data hub

administrator (the TSO), and around EUR 100 million accrued to DSOs and energy suppliers

379

Environmental impacts

The legislative options examined above

–

Option 1 (Flexible legislation) and Option 2

(Harmonization and extensive safeguards)

–

can each be expected to have significant, albeit

indirect, environmental benefits because they enable the uptake of technologies that help the

electricity system become more flexible, thus enabling higher levels of variable and

decentralized RES E penetration. Non-discriminatory access to consumer data and a phase-out

of regulated prices will allow new entrants and energy service companies to develop and offer

value-added products such as dynamic price supply contracts, incentive-based demand response

services, green tariffs, and supply contracts with bundled energy efficiency or rooftop solar

investments. In addition, tackling the barriers to consumer engagement will increase the

selective pressure for such new services. The measures will benefit smaller consumers in

particular, the group of market actors which the analysis has shown represents the greatest

remaining source of low hanging fruit in terms of system flexibility potential.

In addition, phasing out blanket price regulation

–

particularly in Member States with very low

margins

–

will help address the high levels of electricity and gas consumption caused by

artificially low prices. This will make it easier to achieve climate objectives and provide a

proper price signal for energy efficiency investments.

Impacts on fundamental rights regarding data protection

A key building block for the completion of the Digital Single Market and the Energy Union

includes strong and efficient protection of fundamental rights in a developing digital

environment. The proposed policy measures on data management were developed in this

context, to ensure widespread access and use of digital technologies while at the same time

guaranteeing a high level of the right to private life and to the protection of personal data as

enshrined in Articles 7 and 8 of the Charter of Fundamental Rights of the EU.

As data on individual consumers' consumption and billing become central to the deployment of

distributed energy resources and the development of new flexibility services, the measures on

data management in the various policy options proposed (from compliance with data protection

379

See Annex 7.3, and

“Policies for DSOs, Distribution Tariffs and Data Handling”

Copenhagen Economics,

and VVA (2016).

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legislation and the Third Energy Package - Option 0 (Baseline); to further introduction of

specific requirements on data handling responsibilities based on principles of transparency and

non-discrimination

–

Option 1 (Flexible legislation); and implementation of a specific data

management model to be described in EU legislation

–

Option 2 (Harmonization and extensive

consumer safeguards)) seek to ensure the impartiality of the entity which handles data and to

ensure uniform rules under which data can be shared. Indeed, consumers must be reassured that

their consumption and metering data remain under their control. Access to a consumer's

metering or billing details can only happen when authorised by that consumer and under the

condition that the personal data protection and privacy are guaranteed.

In this light, the data management policy options are therefore fully aligned and further

substantiate the fundamental rights to privacy and protection of personal data of Articles 7 and

8 of the Charter of Fundamental Rights of the EU, as well as with the General Data Protection

Regulation and with the Commission Recommendation on the Data Protection Impact

Assessment Template for Smart Grid and Smart Metering Environments.

Box 9: External factors and the assessment of the impacts

Price signals and long-term confidence that costs can be recovered in reasonable payback times

are essential ingredients for a well-functioning market. In a market which is not distorted by

external costs and interventions, the level and variability of the spot price on the wholesale

market, plays a role in signalling the need for investments in new resources. With external costs

and in the absence of the right short- and long-term price signals, it is more likely that

inappropriate investment or divestment decisions are taken, i.e. too-late decisions or technology

choices that turn out to be inefficient in the long run. It also renders it more likely that capacity

exits that is valuable for the system as a whole.

The impact assessment demonstrates that an improved market design can lead to a much more

efficient utilisation of resources and establish the market as a main driver of investments in

generation assets (even if only progressively and not fully for all RES E technologies (See Box

7)). This will be mainly driven by the restoration of the economic merit order curve (see Section

6.1.2, Figure 11) and the improved reflection of scarcity in short term electricity prices (see

Section 6.2.6.4, Table 21), both resulting from the measures proposed by the current initiative,

combined with the exit of non-economical units as a result of the transition towards a market

equilibrium (See section 6.2.6.3, Table 18) from the current overcapacity.

Market exit should be brought about by market forces and the initiative generally aims at

removing existing obstacles to this in regulation. Market exit is framed to some degree by the

measures proposed under Problem Area II. The extent to which a system with capacity

remuneration exacerbate or not existing excess capacity depends on how the capacity

requirement is set within the mechanism. If the system is correctly calibrated by means of a

genuine resource adequacy assessment (See Problem Area II, Option 2) there will be no

overcapacities. This is both important to ensure that CMs do not incite lower than economically

optimal wholesale prices, which would inhibit investments, and prevent delays upon the

transition path by preventing exit of non-essential resources. Moreover, the measures under

Problem Area I and Problem Area II, option I, will ensure that prices better reflect the real value

of electricity, affecting specifically the remuneration of electricity generation units that operate

less often but provide security and flexibility to the system. For the same reason, it is important

that TSOs (as responsible entities for overall operation of the system) define and remunerate

ancillary services appropriately, remunerating generators for the full range of services they

provide. These market improvements affect exit in the sense that they ensure that only those

resources will exit that genuinely have no value for the system as a whole.

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It is true that overall price developments in the electricity sector will also depend on cost factors

beyond the present initiative, such as the carbon prices, prices for primary fuels or technological

costs.

These external factors would mainly impact the level of wholesale prices

380

, possibly affecting

to a certain extent the overall level of benefits to be expected from the present initiative or their

distribution among individual options (in manners which are not easily predictable in view of

the many interactions that take place). However, such changes are not expected to affect the

order of preferred options. Indeed, the proposed measures in essence derive their benefits from

the removal of current market distortions and imperfections, while at the same time having

comparably small implementation costs. These are benefits that are inherent to the measures

themselves and do not depend on the precise context in which they are implemented. Moreover,

strong synergies exist between the sets of options within the package (See Section 7.5.1),

meaning that the overall benefits of a given option are more affected by the coherence of the

package as a whole, than by its interactions with factors outside the present initiative.

Low wholesale prices though would affect investments in electricity resources such as demand

response, RES E and peaking plant investments. Concerning demand response, the aim of the

initiative is to offer to the consumers the opportunity to participate in the market if they wish

to, either directly (e.g. industrial consumers) or indirectly (e.g. via aggregators). The initiative

is not aiming to affect the level and variability of wholesale prices, but to make the functioning

of the markets more efficient so that it can deliver price signals reflecting the value of electricity

at each moment of time and the need for future investments (and in what type). Although

persistent low electricity wholesale prices could lead to low investments, this is a normal

outcome if it is a result of market dynamics and not distortions. For example a system

characterized by overcapacity should have low prices to signal that investments are not needed.

It is equally noteworthy that the modelling work (as presented in section 6.2.6.4) indicates that

in the mid-long term, even in the presence of larger shares of variable RES E, conventional

generators will set the marginal price in a sufficient number of hours to produce meaningful

price signals to guide overall market operations. Increasing RES E penetration therefore does

not necessarily give rise to low(er) average wholesale market prices.

The assessment of the benefits also depends to a certain degree on the progress made in the

implementation of measures proposed by parallel initiatives, considered as part of the baseline

for the present initiative, most notably the REDII. In this context, it is important to note that the

assessment of the present initiative assumes the full phase-out of non-market based support

mechanisms by 2030 for RES E, i.e. feed-in-tariffs would be phased-out and replaced by

schemes that expose RES E to price signals, as for instance premium based schemes. Such

investments would be further triggered by setting support-levels through auctioning as RES E

investments projects would then be incentivised to develop business models that optimise

380

For example the prices projected by PRIMES/OM tend to be quite higher even in 2020 compared to the

currently observed market prices. Several reasons contribute to this: (a) fuel costs are projected to increase by

25% for gas and coal, (b) demand increases, (c) few new investments take place (mainly RES to reach the

2020 target); this point combined with demand increase described above , make it the first step in reducing

the currently observed overcapacity, (d) a well-functioning EoM without distortions is assumed, (e) scarcity

bidding is assumed, in the sense that there is a mark-up on the bids so that generators can recover their full

costs only from the market in the long-run.

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market based returns. These are reasonable assumptions in view of the rules that are expected

to be in place well before 2030 (see in particular Annex IV).

The success or failure to implement such measures for RES E in time would have a direct

impact on the effectiveness of the present initiative. A partial or delayed implementation of the

closely associated policies, as proposed in the revised Renewable Energy Directive, especially

if combined with the prolongation of existing distortions, would reduce the efficiency of the

market design initiative in the medium term and postpone its expected benefits further into the

future. On the contrary, an expedient implementation would achieve the establishment of

efficient markets and the delivery of the associated benefits sooner.

6.5.

Social impacts

European social partner's joint position

381

"Citizens and especially low-income households should be able to pay their bills"

The new market design should be:

"ensuring that the provision of electricity is secure, safe,

reliable and reasonably priced"

It was also underlines that:

"workers in and outside of the electricity sector are relying on a

stable electricity market for their jobs. There is currently a precarious situation for many

workers in the electricity sector, especially among power plant workers. Many plants are not

adequately remunerated for the services they provide (e.g. flexibility, security of supply) and

therefore several companies foresee closure. Workers could lose their jobs".

A shown above, more efficiently organised cross-border electricity markets can avoid

significant costs for energy customers. Given the importance of energy costs for many

companies and for individual households, realising the possible cost savings can be expected to

improve competitiveness of commercial players (with positive impact on jobs and growth) and

on private customers (especially relevant for low-income households).

The electricity industry (i.e. production, transmission, distribution and trade of electricity) is a

key economic sector with a turnover amounting to not less than EUR

1.182 billion

in 2014

382

EU households spent

EUR 148.2 billion

on electricity bills (EUR 97.4 billion on gas), which

means that every household had to pay

EUR 686,- per year for electricity

(EUR 451,- for gas)

on average, with important variations between single Member States

383

. Especially for low-

income households, costs for electricity can eat up large parts of the available income

384

. Also

382

383

384

Eurostat Data for 2014.

In 2014, EU households in the lowest income quintile spent an average of 9% of their household income on

electricity and gas, whereas middle income households spent 6% on electricity and gas. Source: DG ENER

Data.

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for many industries, especially those in competition at a world-wide scale, energy costs are an

important factor for competitiveness. EU wholesale electricity prices are still higher than in

other regions in the world (e.g. around 30% compared to the U.S.

385

). Avoiding unnecessary

prices increases by an intelligent organisation of electricity markets (e.g. market-based

solutions and using advantages of aggregation across borders) can therefore save jobs and create

growth in the EU.

The possible measures analysed to better adapt the current market rules to decarbonised

electricity markets through revised legislation (See options in

'Problem Area I'

e.g. re-

establishing the level playing field, improving short-term markets and removing barriers for

demand response and distributed resources) would allow to integrate electricity generated from

RES E at lower costs. They would also increase the potential for cross-border trade, leading to

more competition and better possibilities to level out production and demand differences across

larger areas.

Grid fees and other system costs have increased in recent years due to the suboptimal

organisation of markets, but also through the need to adapt the infrastructure to decentralised

generation. Better organised electricity markets would therefore not only save costs for

electricity, but also keep grid costs in check (e.g. by limiting the necessary costs for TSO-

interventions to keep the grid stable, so-called 're-dispatching'

386

). Measures to keep the further

expansion of grid fees in check can therefore bring tangible benefits to industry and private

(low-income) customers

387

The analysed measures to improve investors' certainty and limit state interventions ('Problem

Area II',

e.g. better co-ordinating capacity mechanisms between countries) can also be

expected to have a positive impact on competitiveness and on energy bills to of households. As

shown above, fragmented adequacy planning and capacity mechanisms leads to higher energy

costs and network charges. If each Member State builds its backup generation in its own country

without taking into account generation from neighbours, this will necessarily lead to

inefficiencies through unnecessary duplication of investments

388

. Notably Options 2 (regional

adequacy assessment) and Option 3 (cross-border openness of capacity mechanisms) would

help to keep the prices for state interventions concerning capacity mechanism in check.

389

385

386

387

388

389

See e.g. Communication on

"A Framework Strategy for a Resilient Energy Union with a Forward-Looking

Climate Change Policy"

of 25.2.2015 COM (2015), p.3.

See e.g. the estimations for Germany, where grid tariff component already exceeds the energy costs and where

re-dispatching costs are estimated to grow to EUR 4 billion/year in the next years, see e.g.

http://www.zfk.de/artikel/bis-zu-vier-milliarden-fuer-engpassmanagement-2023.html

According to the Commission's modelling, the assessed options under Problem Area I reduce the average cost

of total demand, i.e. the cost of each MWh generated, apart from Option 1(a) (level playing field). More

specifically and compared to the baseline, Option 1(a) (level playing field) increases it by 6%, while Options

1(b) (strengthening short-term markets), 1(c) (demand response/distributed resources) and Option 2 decrease

it by 6%, 9% and 11%, respectively.

See for further evidence on the disadvantages of fragmented CMs above, Problem Area II (investment

uncertainty/fragmented CMs), discussion of Option 3.

Option 4 (EU wide capacity market) is not considered here as it was already discarded above. However, it is

useful to note that it would also be more costly (about 5% pursuant to the Commission's model) than the other

options.

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In a similar manner, the analysed measures to improve risk preparedness ('Problem

Area III',

e.g. better co-ordinated planning and rules to better coordinate possible load shedding in case

of crises) options are likely to have a positive impact for EU citizens and businesses. Previous

blackouts have shown that even in the "traditional" electricity market with low shares of RES

E so-called "cascade blackouts" resulting from problems in other Member States can seriously

harm businesses and customers, in particular those depending on electrical heating (see on the

system blackouts in 2003 and 2006 above, section 6.3.2.1). Amounts of variable RES E have

increased ever since, and so has the importance of a reliable electricity grid for citizens and

customers (e.g. increased risks of blackouts for internet-driven businesses and private

communication). Minimising blackout risks through better regional coordination will therefore

contribute to avoid negative impacts on businesses and households.

Finally, the analysed measures to enhance performance of retail markets (Problem

Area IV,

e.g. measures facilitating to change suppliers, more targeted support for "energy-poor")

customers in the transition to market-based prices, etc.) will also have a positive impact on

businesses and households. In addition, the proposals relative to the phasing out of regulated

prices, should incentivise Member States which currently use blanket price regulation to

provide targeted support for vulnerable and energy poor consumers instead of providing an

indirect support to all consumers regardless of their circumstances as is currently often the case.

Improvements to the health

390

and well-being of energy poor consumers, savings to the health

sector

391

, and economy-wide productivity gains

392

can be expected from the packages of energy

poverty measures evaluated above. Due to the indirect nature of the way these measures would

address energy poverty, and a lack of specific data on their impact, these benefits are impossible

to quantify.

Health impacts most commonly associated with energy poverty and under-heated dwellings can

be fatal, resulting in higher mortality during winter period. Benefits of effective action to reduce

excess winter mortality could be substantial given the scale of the issue. In fact independent

research shows that over 200,000 excess winter deaths have occurred across 11 Western

European countries alone

393

during the winter of 2014/2015. In addition to the physical impacts,

cold homes are directly related to mental health problems.

The energy transition and decarbonisation policies play a key role in developing Europe’s

competitive edge internationally as growth and jobs increasingly will have to come from

innovative products and services which are closely linked to sustainable and smart solutions.

"Fuel

Poor & Health. Evidence work and evidence gaps. DECC. Presented at Health, cold homes and fuel

poverty

Seminar

the

University

Ulster".

2015.

Cole,

Available

at:

http://nhfshare.heartforum.org.uk/HealthyPlaces/ESRCFuelPoverty/Cole.pdf;

"Towards an identification of

European indoor environments’ impact on health and performance

- homes and schools.

2014. Grün &

Urlaub,

Excess winter mortality: a cross-country analysis identifying key risk factors. Journal of

Epidemiology & Community Health"

2003. Healy.

391

"2009

Annual Report of the Chief Medical Officer (London: Department of Health", 2010. Donaldson, L.

392

"Indoor

cold and mortality. In Environmental Burden of Disease Associated with Inadequate Housing",

(Bonn: World Health Organisation (Regional office for Europe)).

2011. Rudge, J.

393

Excess mortality in Europe in the winter season 2014/15, EuroMOMO, source:

http://www.euromomo.eu/methods/pdf/winter_season_summary_2015.pdf

390

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Recent studies on the impact of EU’s energy and climate targets suggest a net increase in job

demand in the power generation market as a result of the transition of the energy system. One

factor behind this is the higher labour intensity in power generation from renewable sources

compared to gas or nuclear. There will also be a change in the employment structure as many

of the jobs associated with the energy transition require higher skills and increased supply of

workers that outweigh job losses in somewhat less qualified jobs in conventional energy

generation. The total number of jobs in the power sector (operation, maintenance, construction,

installation, and manufacturing) is forecast to increase by around a half by 2030

394

. Further

positive impacts are expected in the indirect and substitution effects.

395

Whereas these effects

are related to the energy transition as such and cannot be attributed solely to the measures

assessed here, by ensuring a cost effective transition in more smoothly functioning markets,

these beneficial social effects stand a much increased chance of being realised and retained.

OMPARISON OF THE OPTIONS

Taking into account the impacts of the options and the assessment presented in Section 6, the

following section compares the different options against each other using, the baseline scenario

as the reference and applying the following criteria:

Effectiveness: the options proposed should first and foremost be effective and thus

be suitable to addressing the specified problem;

Efficiency: this criterion assesses the extent to which objectives can be achieved at

the least cost (benefits versus the costs).

The tables provide a summary of the assessment of the policy options against these criteria. The

options are measures against the criteria applied for the assessment of the impacts specified for

options developed to address each Problem Area (See Sections 6.1, 6.2, 6.3 and 6.4

respectively) and the comparison of the options below. Each policy option is rated between "--

-" (very negative), 0 (neutral) and "+++" (very positive).

The options are not compared here on the basis of their coherence with parallel initiatives. The

design of the baseline already assures that all option are compatible with parallel initiatives. In

particular, the baseline in the present impact assessment ensures that under all investigated

options, the RES E targets (as well as other policy targets) are met. Consequently, comparing

options on the basis of their compatibility with the RED II initiative is meaningless.

7.1.

Comparison of options for adapting market design for the cost-effective operation

of variable and often decentralised generation, taking into account technological

developments

All options, except for Option 0 (baseline scenario) can contribute to achieving to a degree the

objective of adapting the market design to make it suitable for the cost-effective operation of

variable, often decentralised generation of electricity and capture some of the potential social

welfare and environmental opportunities (e.g. lower wholesale electricity prices; incentivise the

394

395

Between 2 and 2.5 million in 2030, depending on the decarbonisation scenario (source Neujobs/CEPS)

Neujobs/CEPS report “Impact

on Decarbonisation of the Energy System on Employment in Europe”

2015 ,

The methodology is based on applying “employment factors” (i.e. labour intensities) of different energy

technologies to changing energy mixes as projected by the EU decarbonisation scenarios.

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increase of low carbon electricity generation). However, the effectiveness and efficiency of the

different options, as well as their impact, vary significantly.

Table 25: Summary of assessment of policy options

Impacts

Criteria



---------

Options



Policy Option 0

(Baseline)

Policy Option

1(a)

(level

playing field)

Policy Option

1(b)

(strengthening

short-term

markets)

Policy Option

1(c)

(demand

response/

distributed

resources )

Policy Option 2

(fully integrated

markets)

Source: DG ENER

Effectiveness

Efficiency

Economic

impact

Impact on

stakeholders

Impact on business

and public

authorities

+++

---

In summary:

Option 0 (baseline scenario): will fall short in providing for the adaptation of the market design

to the new realities of the interconnected electricity system and will not allow the internal

electricity market to reach its full potential.

Options 1(a) (level playing field), 1(b) (strengthening short-term markets) and 1(c) (demand

response/distributed resources) reflect an increasing degree of ambition regarding the

integration of the national electricity markets, with Option 1(c) building on the packages of

measures covered under Options 1(a) and 1(b) and including additional measures. All these

options present a compromise between bottom-up initiatives and top-down steering of the

market development, without substituting the role of national governments, regulators and

TSOs by a centralised and fully harmonised system. Option 1(a) and Option 1(b) are

significantly more efficient than Option 0 but cannot be expected to fully meet the specific

objectives, given that these options do not cover measures for including additional resources

(i.e., demand response, distributed RES E and storage) in the electricity markets to further

increase the flexibility of the electricity system and the resources for the TSOs to manage it.

The value of these additional resources for the efficient operation of decarbonised electricity

markets and hence for the energy transition should not be underestimated. Option 1(c) provides

a more holistic, effective and efficient package of solutions and has the added value that it will

not lead to significant additional impacts on stakeholders or on businesses and public

authorities. Indeed, while Option 1(c) may lead to additional administrative impacts for

Member States and competent authorities regarding the implementation and monitoring of the

measures, these impacts will be offset by lower barriers to entry to start-ups and SMEs, by the

benefits to market parties from more stable regulatory frameworks and new business

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opportunities as well as by the benefits to consumers from more competition and access to

wider choice.

As regards Option 2 (fully integrated market), while having advantages in terms of lower

coordination requirements (i.e., a fully integrated EU-market can be operated more efficiently),

the results of the assessment indicate that the move towards a more integrated European

approach has less significant economic added value since most of the benefits will have already

been reaped under the regional, more decentralised approach under Option 1(c) (demand

response/distributed resources). Moreover, Option 2 (fully integrated market) has the

disadvantage of requiring significant changes to established practices, systems and processes

and hence a significant impact on stakeholders, businesses, Member States and competent

authorities. Such profound changes of national competences in favour of centralised powers

"across the board" would also raise serious questions concerning the subsidiarity of the

measure. Therefore, in view that for Option 2 (fully integrated market) the efficiency gains are

not significantly higher compared to Option 1(c) (demand response/distributed resources) but

the impacts and required changes to national competences much greater, it appears

disproportionate and not the most appropriate option at the current stage of development of the

internal electricity market.

In the light of the previous assessment, the preferred option would be Option 1(c) (pulling

demand response and distributed resources in the market) (which encompasses Options

1(a) (level playing field) and 1(b) (strengthening short-term markets). This option is the

best in terms of effectiveness and, given its impacts, has been demonstrated to be the most

efficient as well as consistent with other policy areas.

This preferred Option has large support among stakeholders. No support exists for retaining the

status quo (i.e. Option 0 or 0+) whereas Option 2 (fully integrated market) was generally

deemed a step too far. It is noted that hesitations by stakeholders on aspects of the preferred

option, such as the removal of priority dispatch provisions under Option 1(a) (level playing

field), are based on the notion that this should go hand in hand with a reform rendering the

market more adapted to RES E resources, which is what is foreseen under Option 1(b)

(strengthening short-term markets) and Option 1(c) (demand response/distributed resources)

396

7.2.

Comparison of Options for facilitating investments in the right amount and in the

right type of resources for the EU

All options, except for Option 0 (baseline scenario), can improve the overall cost-efficiency of

the electricity sector and contribute towards achieving the objective of facilitating investments

in the right amount and in the right type of resources for the EU. However, the effectiveness

and efficiency of the different options, as well as their viability and impact, vary significantly.

396

Reference is made to Section 5.1.1 through to 5.1.5 and Sections 7 of Annexes 1.1 through 3.4 for more

detailed representations of stakeholders' opinions.

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Table 26: Summary of assessment of policy options

Impacts

Criteria



---------

Options



Policy Option 0

(Baseline

scenario)

Policy Option 1

(Reinforced

energy-only

market without

CMs)

Policy Option 2

(reinforced

energy-only

market + EU

adequacy

assessment for

CMs)

Policy Option 3

(reinforced

energy-only

market + EU

adequacy

assessment for

CMs + EU

framework on

cross-border

participation

CMs)

Source: DG ENER

Effectiveness

Efficiency

Economic

impact

Impact on

stakeholders

Impact on business

and public

authorities

+/-

In summary:

Option 0

(baseline scenario), which would assume the existence of national capacity

mechanisms without coordination at EU-level will fall short of achieving the specific objectives

of improving market functioning to reduce the need to have recourse to state intervention and

of ensuring that state-interventions, where needed, are more coordinated, efficient and

compatible with the EU's internal energy market.

Option 1

(reinforced energy-only market without CMs) can improve the overall cost-efficiency

of the electricity sector significantly. The analysis shows that undistorted energy-only markets

increase overall system efficiency as make sure that resources are better utilized across the

borders, demand can better participate in markets, and renewables can be better integrated into

the system without additional need for subsidies. This will in turn decrease the need for capacity

mechanisms (which are often introduced as a reaction to markets which do not produce correct

price signals due to state interventions).

The analysis also shows that reinforced energy-only markets can in principle provide the right

signals for market operation and ensure resource adequacy. Option 1 also has slightly more

positive environmental impacts than any of the other options.

However, markets are still characterised by manifold regulatory distortions today, and

removing the distortive effects will not be possible with immediate effects in many Member

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States. The observation that undistorted markets can provide the necessary investment signals

has therefore to be weighed against the observation that a significant transition time to phase

out the existing distortions will be necessary. Furthermore, some national distortions (e.g.

resulting from differences in taxation) cannot be addressed by a reform of energy law and are

therefore likely to continue.

Investors also do not have perfect foresight of market conditions, and confidence that they will

not be distorted for the economic lifetime of their investments. Such certainty is increasingly

difficult to find, often due to uncertainty as to the regulatory measures that could be taken in

the future that may supress prices and reduce the load factors of plants compared to the

assumptions made when the investment decision is taken. In a market that requires more and

more varied sources of funding that in many cases are competing with other, non-electricity,

projects for capital, relying solely on the energy price as a basis for investment is not always

easy. Uncertainty about future policy developments or the perception thereof can create

'missing money' that may require addressing

397

The legislator should also take into account that the level of interconnection is markedly

different among Member States. This militates for a more nuanced approach than a

straightforward EU-wide prohibition of CMs.

In this perspective, not allowing Member States to introduce any type of CMs would mean that

Member States would be prevented from addressing adequacy concerns with CMs. As those

concerns might be legitimate, this option is not considered to be appropriate.

But, as developed in Chapter 2.2.1 undistorted energy price signals are fundamental irrespective

of whether generators are solely relying on energy market incomes or also receive capacity

payments. Therefore the measures aimed at removing distortions from energy-only markets

discussed under Option 1 (e.g. scarcity pricing or reinforced locational signals) are 'no-regrets'

and assumed as being integral parts of Options 2 (CMs + EU adequacy assessment

)

and 3 (CMs

+ EU framework on cross-border participation)..

When compared with the baseline,

Option 2

(CMs + EU adequacy assessment) can improve

the overall cost-efficiency of the electricity sector as significant savings can be achieved

through establishing an EU-wide approach to resource adequacy assessments as opposed to

national-based adequacy assessments. At the same time Option 2 does not allow reaping the

full benefits of cross-border participation in CMs.

Option 3

(CMs + EU framework on cross-border participation) (which includes the market

reforms under Option 1 and the regional assessment under Option 2) goes beyond Option 2 as

it proposes additional measures to avoid fragmentation of CMs. This would achieve significant

additional net benefits when compared with Option 2. This is because it makes sure that foreign

resource providers can effectively participate in national capacity mechanisms and avoids

competition and market distortions resulting from capacity payments which are reserved to

domestic participants. By remunerating foreign resources for their services this option reduces

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It must however also be recognised that CMs by themselves are not a panacea as they can equally be a source

of regulatory uncertainty. Indeed, in practise CM designs are regularly found imperfect and consequently

adjusted on a regular basis.

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investment distortions that might be present in Option 2 as a result from uncoordinated

approaches to cross-border participation.

In view of the assessment above,

Option 3

(CMs + EU framework on cross-border

participation)

(encompassing options 1 and 2) is the preferred option.

This preferred Option has large support among stakeholders. There is almost a consensus

amongst stakeholders on the need for a more aligned method for generation adequacy

assessment. A majority of stakeholders support the idea that any legitimate claim to introduce

CMs should be based on a common methodology. When it comes to the geographical scope of

the harmonised assessment, a vast majority of stakeholders call for regional or EU-wide

adequacy assessments, while only a minority favour a national approach. There is also support

for the idea to align adequacy standards across Member States. Stakeholders clearly support a

common EU framework for cross-border participation in CMs

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Most stakeholders including Member States agree that a regional/ European framework for

CMs is preferable. Member States, however, might want to keep a large degree of freedom

when proposing a CM. They might claim that beyond a revamped regional/ EU generation

adequacy assessment, there is legitimacy for a national assessment based on which they can

claim the necessity of their CM. Similarly Member States might instinctively want to rely more

on national assets and favour them over cross-border assets.

7.3.

Comparison of options for improving Member States' reliance on each other in

times of system stress and reinforcing coordination between Member States for

preventing and managing crisis situations

All options, except for Option 0 (baseline scenario), can contribute to achieve the objective of

improving Member State's reliance on each other in times of system stress and reinforcing their

coordination and cooperation at times of crisis situation. However, the effectiveness and

efficiency of the different options, as well as their viability and impact, vary significantly.

398

Reference is made to Section 5.2.1 through to 5.2.9 and Sections 7 of Annexes 4.1 through 5.2 for more

detailed representations of stakeholders' opinions.

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Table 27: Summary of assessment of policy options

Criteria



---------

Options



Policy Option 0

(Baseline

scenario)

Policy Option 1

(Common

minimum EU

rules)

Policy Option 2

(EU rules +

regional

cooperation)

Policy Option 3

(Full

harmonisation)

Impacts

Effectiveness

Efficiency

Economic

impact

Impact on

stakeholders

Impact on

business and

public authorities

0/-

+++

0/-

+++

0/--

From the point of view of impacts, particularly costs and administrative impact, Option 1

(Common minimum EU rules) could in principle appear as preferred option. However, the

performance in terms of effectiveness and efficiency is limited compared to Option 2 (EU rules

+ regional cooperation) and Option 3 (Full harmonisation). Additionally, impacts associated

with Option 3 (Full harmonisation) are neither proportionate nor fully justified by the

effectiveness of the solutions, which makes Option 3 (Full harmonisation) perform poorly in

terms of efficiency compared to Option 2 (EU rules + regional cooperation).

Overall, the more harmonized approach to security of supply through minimum rules pursued

by Option 1 (Common minimum EU rules) would not solve all the problems identified, in

particular, the uncoordinated planning and preparation ahead of a crisis. As regards Option 1

(Common minimum EU rules), the main drawback of this approach is that each Member State

would be drafting and adoption the national risk preparedness plans under its own

responsibility. While the regionally coordinated plans with crisis scenarios identified at regional

level and the agreement of some aspects of the plan (e.g. load shedding plan) in a regional

context, aim at ensuring that all regional specificities are fully considered. Given the urgency

to enhance the level of protection against cyber threats and vulnerabilities, it must be concluded

that Option 1 (Common minimum EU rules) regarding cybersecurity is not recommended,

because it is not viable for reaching the policy objectives, given that the effectiveness would

depend on whether the voluntary approach would actually deliver a sufficient level of security.

Option 2 (EU rules + regional cooperation) addresses many of the shortcomings of Option 1

(Common minimum EU rules) providing a more effective package of solutions. In particular,

the regionally coordinated plans ensure the regional identification of risks and the consistency

of the measures for prevention and managing crisis situations. For cybersecurity this option

creates a harmonised level of preparedness in the energy sector and ensures that all players have

the same understanding of risks and that all operators of essential services follow the same

selection criteria for the energy sector throughout Europe.

Overall, Option 3 (Full harmonisation) represents a highly intrusive approach that tries to

address possible risks by resorting to a full harmonisation of principles and the prescription of

concrete solutions. For example, the preparation of risk preparedness plans at regional level

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ensures full coherence of actions ahead and during a crisis. However, the major limitation is

that national specificities could not be addressed through regional plans. The detailed

"emergency

rulebook"

with an exhaustive list of measures would also reduce the room of

manoeuvre of Member States to tackle local problems. The creation of a dedicated agency on

cybersecurity at EU level would be also a costly solution. The assessment of impacts in Option

3 (Full harmonisation) shows that the estimated impact on cost is likely to be high and looking

at the performance in terms of effectiveness, it makes Option 3 (Full harmonisation) a

disproportionate and not very efficient option.

In the light of the previous assessment, the preferred option would be Option 2 (EU rules

+ regional cooperation). This option is the best in terms of effectiveness and, given its

economic impacts, has been demonstrated to be the most efficient as well as consistent

with other policy areas.

This preferred Option has large support among stakeholders. The majority of stakeholders are

in favour of regional coordination of risk preparedness plans and ex-ante cross-border

agreements to ensure that markets function as long as possible in crisis situations. No support

exists for retaining the status quo (i.e. Option 0 or 0+), as stakeholders agree that the current

framework does not offer sufficient guarantees that electricity crisis situations are properly

prepared for and handled in Europe. Option 3 (Full harmonisation) was deemed a step too far;

stakeholders did not support a fully harmonised approached based on rulebooks

399

7.4.

Comparison of options for addressing the causes and symptoms of weak

competition in the energy retail market

Although there is a significant level of uncertainty in quantifying the benefits of the options in

this Problem Area, all options, except for Option 0 (baseline scenario), are expected to improve

retail competition. However, the anticipated effectiveness and efficiency of the different options

vary markedly.

399

Reference is made to Section 5.3.1 through to 5.3.6 and Section 6 of Annexes (6.1.4 presentation of options

and 6.1.8 for more detailed representations of stakeholders' opinions).

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Table 28: Summary of assessment of policy options

Criteria



---------

Options



Policy Option 0

(Baseline

scenario)

Policy Option

0+ (Non-

regulatory

approach)

Policy Option 1

(Flexible

legislation)

Policy Option 2

(Harmonization

and extensive

consumer

safeguards)

Impacts

Effectiveness

Efficiency

Economic

impact

Impact on

stakeholders

Implementation

costs

+++

+/0

+++

+++/--

+++ / ++

++/---

---

Option 0+

(Non-regulatory approach) can be expected to lead to

modest, albeit tangible,

economic benefits

primarily as a result of the voluntary phase-out of regulated prices in some

Member States and the drive to tackle illegal switching costs. Given its

low implementation

costs,

it is a

highly efficient

option. And the few stakeholders that will be affected will be

affected positively. However, the

effectiveness of Option 0+ is significantly limited

by the

fact that non-regulatory measures are not suitable for tackling the poor data flow between retail

market actors that constitutes both a barrier to entry and a barrier to higher levels of service to

consumers. In addition, shortcomings in the existing legislation make it impossible to

significantly improve consumer engagement and energy poverty. They also introduce great

uncertainty around the drive to phase out price regulation.

Option 1

(Flexible legislation) would probably lead to

substantial economic benefits.

Retail

competition would be improved as a result of the definitive phase-out of blanket price

regulation, non-discriminatory access to consumer data, and increased consumer engagement.

In addition, consumers would see direct benefits through improved switching. And the energy

poor would be better protected, leading to knock-on benefits to the broader economy. Given

that Option 1 would entail

moderate implementation costs

(these stem primarily from

ensuring a standardised format for consumer data, and the various burdens associated with

improving consumer engagement) it is

an efficient option

as these costs are considerably

outweighed by the benefits. Many stakeholder groupings are likely to be positively and

negatively affected by the collection of policy measures in Option 1. But none would bear a

disproportionate burden that would not be offset by commensurate benefits. Likewise, the

proposed measures in Option 1 respect the principle and limits of subsidiarity.

Option 2

(Harmonization and extensive consumer safeguards) would also lead to

substantial

economic benefits,

albeit with a

greater degree of uncertainty

over the size of these benefits.

This uncertainty stems from the tension some of the measures in Option 2 may have with

competition (stronger disconnection safeguards, an outright ban on all switching-related

charges), and from the difficulty of prescribing EU-level solutions in certain areas (defining

exceptions to price deregulation, implementing a standard EU bill design). Whilst a single EU

data management model would be just as effective and easier to enforce, and whilst the energy

poor would be even better protected by the stronger safeguards proposed, the

high

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implementation cost

of these measures would

reduce the efficiency

of Option 2 compared

with Option 1. Disconnection safeguards may be better designed by Member States to ensure

synergies between national social services. As social policy is a primary competence of Member

States, Option 2 may go beyond the boundaries of subsidiarity. Finally, many stakeholders will

be affected by the collection of policy measures in Option 1, both positively and negatively.

Suppliers and DSOs in particular would face significant burdens that they would at least

partially pass on to consumers i.e. socialise.

In the light of the analysis, the preferred option is Option 1 (Flexible legislation). This

option is most likely to be the most effective, is efficient, and is consistent with other policy

areas.

Most stakeholders would support (or at least be indifferent to) the measures in preferred Option

1 (Flexible legislation). This is due to the fact that a flexible legislative approach allows the

problems identified to be largely addressed while accommodating: 1) the broad range of

national differences that still exist in retail markets for energy; and 2) the specific concerns

aired in the stakeholder outreach. Nevertheless, some Member States practising blanket price

regulation will likely oppose a phase out of this, and industry associations representing energy

suppliers have stated that they would not welcome any EU legislation addressing the content of

bills.

Almost no support exists for retaining the status quo (i.e. Option 0) or for tackling the issues in

the Problem Area through soft law (Option 0+), except for isolated instances already mentioned.

Several measures in Option 2 (Harmonization and extensive consumer safeguards) were

generally deemed a step too far by a number of stakeholders, including stakeholders such as

ACER, or NRAs who represent the interest of the public.

400

7.5.

Synergies, trade-offs between Problem Areas and sequencing

The measures considered in this impact assessment are highly complementary. Most of the

different Options considered in each Problem Area would reinforce the effect of options in other

Problem Areas, with little trade-offs between the different areas.

Synergies

The measures to make intraday and balancing markets more flexible such as pursued under

Problem Area I, in particular Option 1(b) (strenghening short-term markets) and Problem Area

II , Option 1 (reinforced energy-only market) will foster a price signal that better reflects the

value of electricity, notably when it is scarce. It will hence provide a price signal benefical for

flexible resources, in particular demand response and storage and improve the business case for

innovative assets and service models to enter the market as assessed under Problem Area I

Option 1(c) (demand response/distributed resources). It will also reinforce liquidity and

competition in the electricity wholesale electricity markets. As choice on the wholesale market

is a pre-condition for more competition on retail markets, more liquid wholesale markets will

also contribute to improving competition in retail markets (Problem Area VI).

400

See Section 5.4.2 through to 5.4.5, and Sections 7 of Annexes 7.1 through 7.6 for more detailed representations

of stakeholders' opinions.

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Helping RES E resources to be remunerated through the market as fostered with the measures

under Problem Area I will ultimately reduce the high level of taxes and levies currently

necessary to drive RES E deployment, decreasing overall system costs and making energy more

affordable compared with a scenario where markets remain poorly adapted to RES E.

The measures proposed to improve the functioning of the electricity markets as discussed under

Problem Areas I and II, in particular Option 1 (reinforced energy market/No CMs), will also

lead to a more robust formation of price signals. Robust price signals will reduce the need for

assets to be remunerated by alternative revenue streams to be a credible investment opportunity

or avoid its decommissioning and hence reduce the need for government intervention in the

form of CMs or otherwise to ensure resource adequacy such as discussed under Problem Area

II, Option 3. Moreover, the measures assessed Problem area II, in particular the preferred

Option 3 will reduce market distorition caused by genuinly justifed CMs and improve the ability

of the market to operate optimally. In other words, improving the energy markets will reduce

the need for governement intervention to ensure investments in electricity resources.

Measures to improve retail competition, consumer engagement and data handling as fostered

with the measures under Problem Area IV (Retail markets) will increase system flexibility as

targeted by the measures under Problem Area I, in particuler Option 1(c) (pulling demand

response and distributed resources into the market). This is because the majority of untapped

demand response potential originates from smaller consumers and because retail price

regulation can have a detrimental effect on the deployment of innovative consumer products

such as dynamic price supply contracts.

Improving the market in its ability to renumerate (in particular, flexible) resources and

removing the distortions that prevent resources to reacte to proper price signals (such as those

aimed at in Problem I area I and Option 1 of Problem Area II) will overall improve the

robustness of the system to satisfy demand at all times and, hence, the freqeuncy and overall

number of hours that recourse has to be taken to out-of-market measures to operate the system,

such as the demand curtailment, as discussed under Problem Area III (Crisis situations).

Phasing out price regulation as fostered with the measures under Problem Area IV (particularly

in Member States with very low retail margins) will help address the high levels of electricity

and gas consumption caused by artificially low prices and provide an accurate price signal for

energy efficiency investments that would ultimately mitigate the effects of security of supply

events as targeted by the measures under Problem Area III (Crisis situations). Removing price

regulation will also allow for a more flexible organisation of the market and increase the

incentives to participate in the market through demand response as fostered by the measures

assessed un Problem Area I. Option 1(c) (pulling demand response and distributed resources

into the market)

Measures to improve retail competition as discussed under Problems Area IV, will ensure that

all benefits, including those expected under Problem Areas I, II and III are transferred to end-

consumers, ultimately increasing the beneficial effects on social welfare and competiveness.

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Overall, market improvement measures will address increasing energy poverty as discussed in

Problem Area IV. Indeed, one of the three main drivers

401

of energy poverty has been the

gradual increase in retail prices.

Measures to ensure a common approach to crisis prevention and management as is the objective

under Problem Area III avoid unduly interventions in market functioning. Better preparedness,

transparency and clear rules on crisis management will build trust between Member States to

rely on the internal electicity market for resource adequacy, helping the achievement of the

objectives under Problem Area II. By imposing obligations to cooperate and lend assistance,

Member States are also less likely to "over-protect" themselves againt possible crisis situations.

Trade-offs

The mesures selected as the preferred option under Problem Area I and II are mutually

reinforcing in that they collectively aim at improving market functioning, thereby reducing the

need for market gouvernment intervention through CMs, and reducing their distortive effects if

nonetheless required. However, scarcity pricing and CMs to a certain degree can be seen as

alternative measures to foster investments. Even if CM deployment rules and design principles

are ringfenced, the mere fact that resources are also renumerated by CMs means that the

effectiveness of scarcity prices to drive investment may be reduced as the number of hours that

scarcity occurs and thus the profits that more flexible resources can earn from selling energy in

the market is reduced. It needs also to be noted that scarcity prices and CMs (at least in its

market-wide version) act differently on investment decision in a crucial manner. Whereas such

CMs rewards any capacity, removing barriers for scarcity pricing will improve remuneration of

flexible capacity in particular.

The measures assessed under various options in the impact assessment seek to improve the

overall flexibilty of the electricity system. However, they do this by employing different means.

It can therefore be expected that some trade-offs exist between these options. Improvements in

the usage of interconnection capacity (as assessed under Problem Area I, Option 1(b)

(strenghening short-term markets)) allow a given plant to exploit variations in production and

demand over a larger geographcial area allowing for a more stable intertemporal production

pattern of the plant. Improving the usage of interconnection capacity will hence favour the

usage of less flexible resources over flexible ones. Similarly, pulling demand response into the

market will reduce the profits of generation capacity and, in particular, flexible generation

capacity which may amplify the amount of capacity that needs to exit the market into the

transition towards 2030. Ultimately, efficient markets should select the most cost-efficient

solutions.

Energy poverty safeguards whose costs directly accrue to suppliers

–

particularly, the costly

disconnection safeguards considered in Option 2 (Harmonization and extensive consumer

safeguards) of Problem Area IV (Retail markets)

–

may act as a barrier to retail-level

competition, and diminish the associated benefits to consumers, including lower prices, new

and innovative products, and higher levels of service. Although the implementation costs of

these safeguards will be passed on to consumers, and therefore socialized, different energy

suppliers may have different abilities to do this, and to deal with the additional consumer

401

The other two drivers being wage growth and the energy efficiency of housing stock

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engagement costs. Some may therefore choose not to enter markets with such safeguards in

place. A uniform level of such safeguards throughout the market would help create a level

playing field and address such competition impacts.

Sequencing of measures

Over all, the synergies between the measures are large and the temporal dependency low, the

overall beneficial effects will be achieved only if all measures are implemented as a package.

A sequencing of measures is not necessarily appropriate to establish at EU level. The judgement

of moving to a next stage of market development much depends on the development stage of

the electricity market at hand. The reality is that Member States are at different, sometimes even

very different stages, in the development of their market arrangements. As an example only, as

a result of the individual characteristics of national markets, the timing of the phase out of price

regulation may differ on a case-by-case basis. This is to enable national authorities to ensure

that the necessary prerequisites of a smooth transition are in place before all regulatory

interventions in price setting are discontinued. Such prerequisites may include, for example, the

number of suppliers in the market, the market share of the largest suppliers, or retail price levels.

The same is true for other measures proposed.

The EU legislation ultimately adopted should therefore need to find the appropriate balance

between setting out a well-defined endpoint whilst allowing sufficient space for Member States

to manage their transition thereon.

8.1.

ONITORING AND EVALUATION

Future monitoring and evaluation plan

The Commission will systematically monitor the transposition and compliance of the Member

States and other actors with the finally adopted measures and take enforcement measures if and

when required and report on the progress made in this regard on a regular basis. For this

purpose, the Commission will be supported by ACER as described below.

In addition, as it has already done in the context of the implementation of the Third Package,

the Commission will provide guidance documents providing assistance on the implementation

of the adopted measures.

Parallel to the proposed initiatives, the Commission will bring forward an initiative concerning

the governance of the Energy Union that will streamline the monitoring and reporting

requirements. Based on the initiative of the governance of the Energy Union, the current

monitoring and reporting requirements of Commission and Member States' reporting

obligations in the Third Energy Package will be integrated in a horizontal monitoring report.

More information on the streamlining of the monitoring and reporting requirements can be

found in the impact assessment for the governance of the European Union.

The annual reporting by ACER and the evaluation by the Commission, together with the

reporting from the Electricity Coordination Group are part of the proposed initiatives and

described in the sections below.

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8.2.

Annual reporting by ACER and evaluation by the Commission

The monitoring of the proposed initiatives will be carried out following a two tier approach:

annual reporting by ACER and an evaluation by the Commission.

Annual reporting by ACER

ACER's duties

402

under the Third Package include the monitoring of and reporting on the

internal electricity market. ACER prepares and publishes an annual market monitoring report

that tracks the progress of the integration process and the performance of electricity markets

and identifies any barriers to the completion of the internal electricity retail and wholesale

markets.

The sources of data on which ACER relies to compile its annual market monitoring report are:

the Commission, NRAs, ENTSO-E, the Bureau Européen des Unions de Consommateurs

(BEUC) and other relevant organisations. ACER's annual report is based on publicly available

information and the information provided by these entities.

Based on the present proposals, ACER will continue to monitor and report on the internal

electricity market on an annual basis after the adoption of the proposals. ACER's annual

reporting will replace the Commission's reporting obligations that are currently still existing

under the Electricity Directive. The present proposals also foresee extending ACER's

monitoring mandate to include matters related to security of supply.

Evaluation by the Commission

The Commission will carry out a fully-fleged evaluation of the impact of the proposed

initiatives, including the effectiveness, efficiency, continuing coherence and relevance of the

proposals, within a given timeline after the entry into force of the adopted measures

(indicatively, 5 years).

In the context of this evaluation, the Commission will pay particular attention as to whether the

assumptions underlying its analyses in the present impact assessment were valid.

The evaluation report will be developed by the Commission with the assistance of external

experts, on the basis of terms of reference developed by the Commission services. Stakeholders

will be informed of and consulted on the evaluation report, and they will also be regularly

informed of the progress of the evaluation and its findings. The evaluation report will be made

public.

8.3.

Monitoring by the Electricity Coordination Group

The Electricity Coordination Group will be also a tool to monitor developments in the internal

electricity market and in particular as regards security of supply more closely. To this end a

402

The

legal basis for the Agency’s market monitoring duties is in Article 11 of Regulation (EC) No. 713/2009.

ACER equally monitors and reports on many more detailed aspects of the regulatory framework.

(http://www.acer.europa.eu/Official_documents/Publications/Pages/Publication.aspx)

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concrete mandate will be given to the Electricity Coordination Group, in particular to monitor

the security of supply in the EU on the basis of a set of indicators (e.g. EENS, LoLE) and regular

outlooks and reports produced by ENTSO-E

403

8.4.

Operational objectives

The key objective of the present initiative is to make electricity markets more secure, efficient

and competitive whilst ensuring that electricity is generated in a sustainable way and remains

affordable to all. The operational objectives for the preferred options are listed as follows:

Problem Area I (market design not fit for an increasing share of variable decentralised

generation and technological developments):

Adoption of measures directed at removing market distortions deriving from the

different treatment to generation from different sources;

Adoption of measures aiming at providing for liquid and better integrated short-term

markets;

Adoption of measures directed at removing barriers preventing demand response from

participating in energy and reserve markets;

Adoption of measures aiming at strengthening the role of ACER, clarifying the role of

NRAs at regional level, criteria for enhancing ENTSO-E's transparency and monitoring

obligations, rules for formalising the role of DSOs at European level.

Problem Area II (uncertainty about sufficient future generation investments and uncoordinated

capacity markets):

Adoption of measures aiming at improving the price signals of the electricity markets;

Specific requirements to align national CMs by requiring ENTSO-E to propose a

methodology for an EU-wide resource adequacy assessment and requiring Member

States to rely on the assessment.

Adoption of rules aiming at enhancing the compatibility between CMs.

Problem Area III (reinforce coordination between Member States for preventing and managing

crisis situations):

Adoption of measures aiming at improving risk assessment and preparedness;

Adoption of rules aiming at improving coordination in emergency;

Adoption of measures aiming at improving transparency and information sharing.

Problem Area IV (retail markets):

Adoption of measures aiming at reducing regulatory intervention in retail price setting;

Adoption of measures aiming at protecting energy poor and vulnerable consumers;

Adoption of measures directed at removing barriers to market entry for new supply and

service companies;

403

See Preferred Option (Option 2 (EU rules + regional cooperation)) to address problem Area III (When

preparing or managing crisis situations, Member States tend to disregard the situation across their borders).

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8.5.

Adoption of measures aimed at increasing consumer engagement and choice.

Monitoring indicators and benchmarks

As of 2021, ACER will be invited to review its current monitoring indicators with a view to

ensure their continuing relevance for monitoring progress towards the objectives underlying the

present proposals. ACER will continue relying on the same sources of data used for the

preparation of the market monitoring report. It will be tasked to cover in that report the security

of supply dimension as well. Monitoring indicators could include:

Problem Area I (market design not fit for an increasing share of variable decentralised

generation and technological developments):

Indicators relating to market and regulatory barriers that affect the level playing field

between market participant and types of resources, such as the degree of capacity

dispatched - fully, partially or not at all - on the basis of price signals only, and the

usage of market and non-market based curtailment;

Indicators related to the degree of flexibility available within the electricity system and

the development of intraday and balancing markets, such the level of market liquidity

in intraday and balancing markets and the allocation and use of cross-border capacity

for these time-frames, and related efficiency gains;

Indicators related to the participation of distributed resources and demand in the market

(including use from system operators), energy service operators such as aggregators and

barriers to market participation. Such for example, the capacity and production by

distributed RES E and storage, the capacity of demand response available and its

activation, the number of facilities and their capacity operated by aggregators;

Indicators related to consumer access to smart metring systems, their functionalities and

availability/uptake of dynamic electricity pricing contracts;

Indicators related to the evaluation of the performance by ACER, ENTSO-E and NRAs

of their duties.

Problem Area II (uncertainty about sufficient future generation investments and

uncoordinated capacity markets):

Indicators pointing to the effectiveness of market arrangements in providing locational

signals and reflecting the value of electricity, also in times of scarcity, such as the extent

to which market prices have been contrained by any implicit or explict limits on prices,

levels of investment and correlation with price in different bidding zones.

State interventions to support resource adequacy and their interaction with the EU's

electricity markets, such as their incidence, design features and degree of participation

of cross-border capacity;

Problem Area III (reinforce coordination between Member States for preventing and

managing crisis situations):

Indicators for monitoring security of supply, such as expected energy non-served

(EENS) and loss of load expectation (LoLE);

In the case that electricity crisis situations occur, the lessons learnt from these stress

situations should also feed in the analysis of security of supply.

Problem Area IV (retail markets):

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The incidence of regulated prices and the progress towards their phase-out;

Market developments regarding consumer switching, switching facilitation such as

switching rates, costs and incidence of price and non-price barriers to switching.

Key performance indicators measuring the economic and technical effectiveness of

DSOs and impact on system users (level of distribution charges).

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ACER

LOSSARY AND

CRONYMS

The Agency for the Cooperation of Energy Regulators, a European

Union Agency that was created by the Third Energy Package to

further progress the completion of the internal energy market both

for electricity and natural gas.

Regulation (EC) No 713/2009 of the European Parliament and of the

Council of 13 July 2009 establishing an Agency for the Cooperation

of Energy Regulators, OJ L 211, 14.8.2009, p. 1–14.

(Resource) adequacy can be defined as the ability of the system to

meet the aggregate power and energy requirements of all consumers

at virtually all times. In this impact assessment the term resource

adequacy is favoured over other terms often used in this context,

such as generation or system adequacy

See FFR

A service provider that combines multiple consumer loads

(flexibility or energy) and/or supplied energy units for sale or auction

in organised energy markets.

Services necessary to support the transmission of capacity and

energy from resources to loads while maintaining reliable operation

of the transmission service provider. They refer to a range of

functions which TSOs contract so that they can guarantee system

security. These include services like the provision of mFFR and

aFFR or reactive power.

The situation after markets have closed (gate closure) in which a

TSO acts to ensure that demand is equal to supply, in and near real

time.

Commission Regulation establishing a Guideline on Electricity

Balancing, one of the legal acts to be adopted under Article 18 of the

Electricity Regulation.

All resources, if procured

ex ante

or in real time, or according to

legal obligations, which are available to the TSO for balancing

purposes.

Business As Usual, i.e. the state of the world if no additional action

is taken.

A bidding Zone means a geographical area within which electricity

market wholesale prices are uniform and market participants not

have to take into account grid constraints. Market participants who

wish to buy or sell electricity in another bidding zone have to take

into account grid constraints and related congestion rent payments.

ACER Regulation:

Adequacy

aFFR

Aggregator

Ancillary Services:

Balancing

Balancing Guideline

Balancing reserves

BAU

Bidding zone

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BRPs

BSPs

Balance responsible parties, such as producers and suppliers, keep

their individual supply and demand in balance in commerical terms.

Balancing Service Providers, such as generators or demand facilities,

balance-out unforeseen fluctuations on the electricity grid by rapidly

increasing or reducing their power output.

Guideline on Capacity Allocation and Congestion Management, one

of the legal acts adopted under Article 6 of the Electricity

Regulation.

Combined Cycle Gas Turbine, a common type of gas-fired

generation plant

Central Eastern European Electricity Forum, a platform for

cooperation between certain EU Member States.

Computer Emergency Response Team.

Combined Heat and Power units produce heat and electricity

simultaneously. Their production of electricity is not necesarrily

deterined only by prices for electricity.

Capacity Mechanism, a regulatory intervention that remunerates the

availability of electricity resources instead of the production of

electricity (or the avoidance of electricity consumption).

Means a situation in which an interconnection linking national

transmission networks cannot accommodate all physical flows

resulting from international trade requested by market participants,

because of a lack of capacity of the interconnectors and / or the

national transmission systems concerned.

CACM Guideline

CCGT

CEEE

CERT

CHP

Congestion

Conventional generation The non-low carbon technologies, based on fossil fuels (lignite, hard

coal, natural gas, oil). They usually constitute the mid-range and

peaking plants.

Cross-zonal transmission capacity: The capability of the interconnected system to

accommodate energy transfers between bidding zones.

CSIRT

Curtailment

Day-ahead market

Computer Security Incident Response Team.

Comparison Tools, websites that help consumers to compare

different offers in the market.

Curtailment means a reduction in the scheduled capacity or energy

delivery.

The market timeframe where commercial electricity transactions are

executed the day prior to the day of delivery of traded products.

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DER

Distributed Energy Resources, a generic term referring electricity

assets such as small-scale RES E, storage connected to distribution

grids or by end-consumers on their premises.

EU policy strategy aimed at: (i) helping to make the EU's digital

world a seamless and level marketplace to buy and sell; (ii) designing

rules which match the pace of technology and support infrastructure

development; and (iii) ensuring that Europe's economy, industry and

employment take full advantage of what digitalisation offers.

Demand (side) response, the ability of consumers of electricity to

actively adapt their consumption to market conditions.

Distribution System Operator, the entity that operates, maintains and

develops the low voltage networks in a given area to which most

consumers are connected.

The Electricity Coordination Group was created in 2012 by

Commission Decision of 15 November 2012. The Group is a

platform for the exchange of information and coordination of

electricity policy measures having a cross-border impact. It also aims

to facilitate the exchange of information and cooperation on security

of electricity supply, including the coordination of action in case of

an emergency within the Union.

Energy Efficiency Directive. Directive 2012/27/EU of the European

Parliament and of the Council of 25 October 2012 on energy

efficiency, amending Directives 2009/125/EC and 2010/30/EU and

repealing Directives 2004/8/EC and 2006/32/EC. This directive

establishes a set of binding measures to help the EU reach its 20%

energy efficiency target by 2020.

Communication from the Commission - Guidelines on State aid for

environmental protection and energy 2014-2020, OJ C 200,

28.6.2014, p. 1–55. The Guidelines aim to help Member States

design state aid measures that contribute to reaching their 2020

climate targets. The guidelines will be in force until the end of 2020.

Expected Energy Non Served, a metric to measure security of supply

and to set a reliability standard.

The European Economic and Social Committee.

Directive 2009/72 of the European Parliament and of the Council of

13 July 2009 concerning common rules for the internal market in

electricity and repealing Directive 2003/54/EC, OJ L 211,

14.8.2009, p. 55–93. Together with the Electricity Regulation, the

Electricity Directive sets the main parts of the legal framework for

the EU's electricity markets.

Digital Single Market

DSO

ECG

EEAG

EENS

EESC

Electricity Directive

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Electricity Regulation

Regulation (EC) No 714/2009 of the European Parliament and of the

Council of 13 July 2009 on conditions for access to the network for

cross-border exchanges in electricity repealing Regulation (EC) No

1228/2003, OJ L 211, 14.8.2009, p. 15–35. Together with the

Electricity Directive, the Electricity Regulation sets the main parts

of the legal framework for the EU's electricity markets.

End-customers procure electricity for their own use.

European Network of Transmission System Operators for

Electricity. ENTSO-E was established and given legal mandates by

Third Package.

European Network of Transmission System Operators for Gas.

ENTSOG was established and given legal mandates by Third

Package.

Energy Performance of Buildings Directive or Directive

2010/31/EU of the European Parliament and of the Council of 19

May 2010 on the energy performance of buildings. OJ L 153,

18.6.2010, p. 13–35, concerning energy efficiency of building.

Modifications are being proposed to the EPBD.

Emmission Trading System, works on the 'cap and trade' principle.

A 'cap', or limit, is set on the total amount of certain greenhouse

gases that can be emitted by the factories, power plants and other

installations in the system. The cap is reduced over time so that total

emissions fall. This policy instrument equally fosters penetration of

RES E as it renders production of electricity from non- or less-

emitting generation capacity more economical.

Term refering to the current design of the EU's electricity markets.

The EU target model is based on two broad principles: (i) the

development of integrated regional wholesale markets, preferably

established on a zonal basis, in which prices provide important

signals for generators' operational and investment decisions; and (ii)

market coupling based on the so-called "flow-based" capacity

calculation, a method that takes into account that electricity can flow

via different paths and optimises the representation of available

capacities in meshed electricity grids.

The central policy scenario modelled by PRIMES, reflecting the

agreed 2030 climate and energy targets (and the 2050 EU's

decarbonisation objectives).

Frequency Containment Reserve are reserves from reserve providers

(generators, storage, demand response) used by TSOs to maintain

frequency stable in the whole synchronous area (e.g. continental

Europe). This category typically includes automatically activated

reserves with the activation time up to 30 seconds.

End-customer

ENTSO-E

ENTSO-G

EPBD

ETS

EU Target Model:

EUCO27

FCR

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Florence Forum

The Florence Forum was set up to discuss the creation of a true

internal electricity market in Europe. The participants are national

regulatory authorities, Member States, the European Commission,

international organisations in the area of energy and European-wide

associations representing transmission and distribution system

operators, electricity traders, consumers, network users and power

exchanges.

Frequency Restoration Reserve are reserves from reserve providers

(generators, storage, demand response) used by TSOs to restore

system frequency and power balance after sudden system imbalance

occurrence (e.g. the outage of a power plant). Those reserves replace

FCR if the frequency deviation lasts longer than 30 seconds. This

category includes operating reserves with an activation time

typically between 30 seconds up to 15 minutes. FRR can be

distinguished between reserves with automatic activation (aFRR)

and reserves with manual activation (mFRR).

Directive 2009/73 of the European Parliament and of the Council of

13 July 2009 concerning common rules for the internal market in gas

and repealing Directive 2003/55/EC, OJ L 211, 14.8.2009, p. 94–

136. Together with the Gas Regulation, the Gas Directive sets the

main parts of the legal framework for the EU's gas markets.

Regulation (EC) No 715/2009 of the European Parliament and of the

Council of 13 July 2009 on conditions for access to the natural gas

transmission networks and repealing Regulation (EC) No

1775/2005, OJ L 211, 14.8.2009, p. 36-54. Together with the Gas

Directive, the Gas Regulation sets the main parts of the legal

framework for the EU's gas markets.

The moment when contracts are frozen. After gate closure, no

trading is allowed anymore. At this point, parties are expected to

adhere to the physical data submitted to the System Operator and to

the contracted volumes submitted before Gate Closure.

Charges for network usage imposed on generators

A generator produces electricity and sells this to suppliers or end-

customers

Aggregator that is not affiliated to a supplier or any other market

participant.

Commission Regulation (EU) No 838/2010 of 23 September 2010

on laying down guidelines relating to the inter-transmission system

operator compensation mechanism and a common regulatory

approach to transmission charging

FRR

Gas Directive:

Gas Regulation:

Gate closure

G-charges

Generator

Independent aggregator

ITC Regulation

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LFC block

Load-Frequency Control block or balancing zone, defines the size of

the network area for which the balancing reserves are being

procured.

The total electricity demand

Load Payments correspond to the amount of money retail

companies/consumers need to pay to generators for the electricity

bought from the wholesale market. For each hour, it corresponds to

the product of served demand with the electricity price.

Loss of load expectation, a metric to measure security of supply and

to set a reliability standard

Long-term contract.

A modelling tool used by the Commission, described in more detail

in Annex IV.

See FFR

Network Code on Emergency and Restoration

Nominated Electricity Market Operator; an entity designated by

competent authroities to perform tasks related to single day-ahead

and intraday coupling as defined in the Guideline on Capacity

Allocation and Congestion Management, one of the legal acts

adopted under Article 6 of the Electricity Regulation.

Load

Load Payments

LoLE

LTC

METIS

mFFR

NC ER

NEMO

Electricity network codes and guidelines: a legal act adopted under Articles 6, 8 and 18 of the

Electricity Regulation. Examples of such codes and guidelines are

the NC ER, the CACM guideline, the RfG, the System Operation

Guideline or the Balancing guideline. For a full overview of these

network codes and guidelines, reference is made to Annex VII.

NIS Directive

Directive (EU) 2016/1148 of the European Parliament and of the

Council of 6 July 2016 concerning measures for a high common

level of security of network and information systems across the

Union, OJ L 194, 19.07.2016, p. 1-30.

National Regulatory Authorities, are national authorties set up and

empowered by the Third Package to over see national electricity (and

gas) markets.

Net Transfer Capacity, a metric to measure the capacity available on

interconnectors to transfer electricity.

Risk Preparedness Plans, a measure proposed under Problem Area

III

Pentalateral Energy Forum, a platform for collaboration consisting

of the Ministries, NRAs and TSOs of the BENELUX, DE, FR, AT,

NRAs

NTC

Plan

PLEF

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CH as well as a market parties platform and the European

Commission.

Power exchange

Power exchanges facilitate the trading of electricity at wholesale

level, often for delivery the next day or at even shorter intervals

(intraday). They cooperate with TSOs in optimising interconnection

capacity in the contex of market coupling.

A modelling tool used by the Commission, described in more detail

in Annex IV.

Photovoltaic

The Renewable Energy Package comprising the new Renewable

Energy Directive and bioenergy sustainability policy for 2030

A measure activated by one or several system operators by altering

the generation and/or load pattern in order to change physical flows

in the transmission system and relieve a physical network

congestion.

A platform or regionally coordinated platforms for the attribution of

Long Term Cross Zonal Capacity for a single border or set of

borders.

Renewable sources of electricity

Network code on Requirements for Grid Connection of Generators

Regional Operational Centre

Replacement Reserve are reserves from reserve providers

(generators, storage, demand response) used by TSOs to restore the

required level of FCR and FRR due to their earlier usage. Contrary

to FCR and FRR, not all TSOs in the EU maintain RR. This category

includes operating reserves with activation time from several

minutes up to hours.

Regional Security Coordinators, an entity foreseen under the System

Operation Guidelines to assist TSOs in maintaining the operational

security of the electricity system.

The sector inquiry into capacity mechanisms as conducted by DG

Competition of the European Commission

An electronic device that records consumption of electric energy in

intervals of an hour or less and communicates that information at

least daily back to the utility for monitoring and billing. Smart meters

enable two-way communication between the meter and the central

system.

PRIMES

RED II

Redispatching

Regional platform

RES E

RfG

ROC

RSC

Sector Inquiry

Smart meter

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SME

Small and Medium-sized Enterprises as defined in the Commission

Recommendation of 6 May 2003 concerning the definition of micro,

small and medium-sized enterprises (notified under document

number C(2003) 1422), OJ L 124, 20.05.2003, p. 36-41.

Security of Electricity Supply Directive or Directive 2005/89/EC of

the European Parliament and of the Council of 18 January 2006

concerning measures to safeguard security of electricity supply and

infrastructure investment, OJ L 33, 4.2.2006, p. 22–27

Suppliers are active in the retail segment of the market and supply

electricity to end-consumers

The percentage of consumers changing suppliers in any given year.

SoS Directive

Supplier

Switching rate

System Operation Guideline: Draft Commission Regulation which will set down rules relating

to the maintenance of the secure operation of the interconnected

transmission system in real time.

TFEU

Third Package:

Treaty of the Functioning of the European Union

A package of legislation adopted in 2009 comprising the Electricity

Directive, the Electricity Regulation, the ACER Regulation as well

as similar legislation concerning the gas markets.

Time-of-Use tariffs: Time-based pricing is a pricing strategy where

the provider of a service or supplier of a commodity, may vary the

price depending on the time-of-day when the service is provided or

the commodity is delivered.

The transmission capacity, also called TTC (Total Transfer

Capacity), is the maximum transmission of active power in

accordance with the system security criteria which is permitted in

transmission cross-sections between the subsystems/areas or

individual installations.

Transmission Reliability Margin, a metric to capture the amount of

transmission transfer capability necessary to provide reasonable

assurance that the interconnected transmission system will be secure

during changing system conditions

Transmission System Operator, the entity that operates, maintains

and develops the high voltage networks in a given area.

Ten-Year Network Development Plan

The Vulnerable Consumer Working Group provides advice to the

European Commission on the topics of consumer vulnerability and

energy poverty, its membership comprising industry, consumer

associations, regulators and Member States representatives.

ToU tariffs

Transmission capacity

TRM

TSO

TYNDP

VCWG

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VoLL

Value of Lost Load is a projected value reflecting the maximum

price consumers are willing to pay to be supplied with electricity.

VoLL is typically quite high (e.g. several thousands of EUR/MWh)

and not necessarily the same for each (group of) consumer, thus

enabling DR activation by consumers before the VoLL is reached.

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