Europaudvalget 2016
KOM (2016) 0864
Offentligt
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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}
EN
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Abstract of the Impact Assessment of the Market Design Initiative
I.
POLICY CONTEXT AND KEY CHALLENGES
The Energy Union framework strategy puts forward a vision of an energy market 'with
citizens at its core, where citizens take ownership of the energy transition, benefit from
new technologies to reduce their bills, participate actively in the market, and where
vulnerable consumers are protected'.
Well-functioning energy markets that ensure secure and sustainable energy supplies at
competitive prices are essential for achieving growth and consumer welfare in the
European Union and hence are at the heart of EU energy policy.
To live up to this vision, a series of legislative proposals have been prepared, following the
objectives of secure and competitive energy supplies and building on the EU's 2030 climate
commitments reconfirmed in Paris last year.
The electricity sector will be one of the main contributors to decarbonise the economy.
Currently, 27.5% of Europe's electricity is produced using renewable energy and the
modelling shows that close to half of our electricity will come from renewables by 2030.
With increasing use of electricity in sectors like transport or heating and cooling,
traditionally dominated by fossil fuels, it is ever more important to further increase the
share of renewable energies in electricity and to unlock flexible demand, generation and
storage solutions.
A new regulatory framework is needed to address these challenges and opportunities. The
new proposals for a revised Renewable Energy Directive and for a new Market Design
will precisely do this, by deepening integration of the internal energy market, empowering
consumers, stepping up regional and EU-wide cooperation and providing the right signals
for investment, thus ensuring secure, sustainable and competitive electricity systems.
A successful transition of the energy system delivering on the ambition to become world
leader in renewables will require substantial investment in the sector, and in particular
investments in low-carbon generation assets as well as network infrastructure. This
requires a revised Emissions Trading System in order to address the current surplus of
allowances and to deliver a strong investment signal to reach 40% greenhouse gas
emissions reductions by 2030, but also specific rules to complement market revenues if
those are not sufficient to attract investments in renewable electricity. In addition, measures
to promote renewable energies in sectors like transport or heating and cooling are also
crucial. Reaching the 2030 framework targets and achieving an Energy Union will be
underpinned by a strong Energy Union governance, which will ensure the necessary
ambition level in an iterative dialogue between the Commission and all Member States.
Finally, a successful transition of the energy system will also require continued
commitment and support for infrastructure development both locally as well as across
borders.
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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
of
incumbents by not allowing alternative providers to enter the market.
Despite best efforts to build an integrated and resilient power market, crisis situations can
never be excluded. The potential for crisis situation increases with climate change (e.g.
extreme weather conditions) and the emergence of new areas that are subject to criticalities
such as malicious attacks and cyber-threats. Such crises tend to often have an immediate
cross-border effect in electricity. Where systems are interconnected, incidents that start
locally can rapidly spread beyond borders and crisis situations might also affect several
Member States at the same time (e.g. prolonged heat waves or cold spells).
Today,
risk assessments as well as plans and actions for dealing with electricity crisis
situations focus on the national context only
and there is insufficient information-sharing
and transparency across Member States. In addition, there are different views on what is
to be considered as a risk to security of supply. In an increasingly inter-connected
electricity market, the lack of common approach and coordination can seriously imperil
security of supply across borders and dangerously undermine the functioning of the
internal electricity market.
In addition, missing opportunities to exchange energy with neighbours remains a key
obstacle to the internal energy market. Even where interconnectors are in place, they often
remain unused due to a lack of coordination between Member States. Rules are therefore
needed that ensure that the use of interconnection is not unduly limited by national
interventions.
Based on the above-mentioned shortcomings and underlying drivers, the present impact
assessment has identified four key problem areas that are addressed in the proposed
initiative:
i) the current market design is not fit for integrating an increasing share of
variable, decentralised generation and for reaping the potential of technological
developments; ii) uncertainty about sufficient future generation investments and
uncoordinated capacity mechanisms; iii) Member States do not take sufficient
account of what happens across their borders when preparing for and managing
electricity crisis situations; and iv) as regards retail markets, there is a slow
deployment and low levels of services and poor market performance are wide-spread
in the EU.
III.
SUBSIDIARITY
Article 194 of the Treaty of the Functioning of the EU consolidated and clarified the
competences of the EU in the field of energy and is the legal basis of the current proposal.
Electricity markets have become more integrated and interdependent physically,
economically and from a regulatory point of view, due to increasing cross-border
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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.
V.
DESCRIPTION OF POLICY OPTIONS AND METHODOLOGY
In assessing all possible options (ranging from non-regulatory to legislative policy options)
the following approach was taken:
-
-
Identification of a set of high level options for each problem area. Each of these high
level options contains sub-options for specific measures;
Assessment of each specific measure, comparing a number of options in order to select
the preferred approach.
The following policy options have been considered:
Regarding Problem Area I: the need to adapt the market design to the increasing
share of variable decentralised generation and technological developments,
Option 0+ (Non-regulatory approach) provides little scope for improving the market and
the level-playing field among resources. Indeed, the current EU regulatory framework is
limited in certain areas (e.g., balancing and intraday markets) and even non-existent for
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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.
VI
POLICY TRADE-OFFS
The measures considered in this impact assessment are highly complementary. Most of the
different options considered in each problem area would reinforce the effect of options in
other problem areas, with little trade-offs between the different areas. The overall
beneficial effects will be achieved only if all measures are implemented as a package
The measures under Problem Area I and II are strongly linked in that they collectively aim
at improving market functioning, including the delivery of investment by the market.
Measures under Problem Area I and Option 1 of Problem area II thus reduce the need for
market government intervention by means of capacity mechanisms. The other measures
under Problem Area II reduce their distortive effects if such mechanisms are nonetheless
justified.
Scarcity pricing and capacity mechanisms can to a certain degree be seen as alternative
measures to foster investments. With assets remunerated by capacity mechanisms, the
effectiveness of scarcity prices may be reduced. It needs also to be noted that scarcity prices
and market-wide capacity mechanisms incentivise different investment decisions: whereas
such capacity mechanisms may reward any firm capacity, scarcity pricing will improve
remuneration of flexible capacity in particular.
The measures aiming at providing adequate price signals (measures under Problem Area I
and Problem Area Option 1) are no-regret options. Until these conditions are achieved and
under specific circumstances (like energy isolation), State intervention in the form of some
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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
I)
Options 1(a) (level playing field), 1(b) (strengthening short-term markets) and 1(c)
(demand response/distributed resources) represent an interlinked set of measures regarding
the integration of the national electricity markets and present a compromise between
bottom-up initiatives and top-down steering of the market development, without
substituting the role of national governments, regulators and TSOs by a centralised and
fully harmonised system.
However, Option 1(a) (level playing field) and Option 1(b) (strengthening short-term
markets) do not cover measures to pull all distributed flexible resources (demand-response,
renewable electricity and storage) into the market. These options do not take advantage of
the potential offered by these resources to efficiently operate and decarbonise the
electricity market.
13
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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
14
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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
2)
Policy options regarding the lack of coordination among Member States when
preparing for and managing electricity crisis situations (Problem Area III)
Based on a set of clear common rules, Option 1 (Common minimum EU rules) would
improve the level of transparency and crisis management across Europe and is likely to
reduce the chances of premature market intervention. The policy tools proposed under this
option would bring economic benefits to businesses and consumers by helping to prevent
costly blackout situations. However, this option does not solve the issue of uncoordinated
planning and preparation ahead of a crisis since Member State are not required to take into
account cross-border risks and crisis.
Under Option 2 (EU rules + regional cooperation), the regionally coordinated plans ensure
the regional identification of risks and the consistency of the measures for prevention and
managing crisis situations while respecting national differences and competences. This
significantly improves the level of preparedness (compared to Option 1) at national,
regional and EU level, as the cross border considerations are duly taken into account since
the beginning. A regional approach to security of supply results in a better utilisation of
power plants and guarantees risk preparedness at a lesser cost.
Under Option 3 (Full harmonisation), the estimated impact on cost is likely to be high
(notably with the creation of an EU agency on cyber-security) and the measures put
forward appear disproportionate compared to the expected effectiveness. Indeed, this
option represents a highly intrusive approach
with significant administrative impact - by
resorting to a full harmonisation of principles and the prescription of concrete solutions.
Preferred option for Problem Area III: Option 2
(EU
rules + regional cooperation)
Policy options regarding retail markets and the slow deployment and low levels of
services and poor market performance (Problem Area IV)
15
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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.
1.1.
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
2.
PROBLEM DESCRIPTION............................................................................................. 38
2.1.
Problem Area I: Market design not fit for an increasing share of variable decentralized
generation and technological developments ......................................................................................... 38
Driver 1: Short-term markets, as well as balancing markets, are not efficiently organised ...... 40
Driver 2: Exemptions from fundamental market principles ...................................................... 42
Driver 3: Consumers do not actively engage in the market and demand response potential
remains largely untapped ........................................................................................................................ 44
Driver 4: Distribution networks are not actively managed and grid users are poorly
incentivised .............................................................................................................................................. 50
2.2.
Problem Area II: Uncertainty about sufficient future generation investments and
uncoordinated capacity markets ............................................................................................................ 51
Driver 1: Lack of adequate investment signals due to regulatory failures and imperfections in
the electricity market ............................................................................................................................... 55
Driver 2: Uncoordinated state interventions to deal with real or perceived capacity problems
58
2.3.
Problem Area III: Member States do not take sufficient account of what happens across their
borders when preparing for and managing electricity crisis situations................................................... 63
Driver 1: Plans and actions for dealing with electricity crisis situations focus on the national
context only ............................................................................................................................................. 65
Driver 2: Lack of information-sharing and transparency ........................................................... 67
Driver 3: No common approach to identifying and assessing risks ........................................... 68
2.4.
Problem Area IV: The slow deployment of new services, low levels of service and questionable
market performance on retail markets .................................................................................................. 69
Driver 1: Low levels of competition on retail markets .............................................................. 70
Driver 2: Possible conflicts of interest between market actors that manage and handle data 74
Driver 3: Low levels of consumer engagement ......................................................................... 75
2.5.
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.
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.
4.1.
17
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
5.
POLICY OPTIONS ........................................................................................................... 87
5.1.
Options to address Problem Area I (Market design not fit for an increasing share of variable
decentralized generation and technological developments) .................................................................. 88
Overview of the policy options .................................................................................................. 88
Option 0: Baseline Scenario
Current Market Arrangements .................................................. 89
Option 0+: Non-regulatory approach ........................................................................................ 90
Option 1: EU Regulatory action to enhance market flexibility .................................................. 91
5.1.4.1.
Sub-option 1(a): Level playing field amongst participants and resources ....................... 93
5.1.4.2.
Sub-option 1(b): Strengthening short-term markets ....................................................... 95
5.1.4.3.
Sub-option 1(c): Pulling demand response and distributed resources into the market .. 98
Option 2: Fully Integrated EU market ...................................................................................... 102
For Option 1 and 2: Institutional framework as an enabler .................................................... 104
Summary of specific measures comprising each Option ......................................................... 106
5.2.
Options to address Problem Area II (Uncertainty about sufficient future generation
investments and uncoordinated capacity markets) .............................................................................. 110
Overview of the policy options ................................................................................................ 110
Option 0: Baseline Scenario
Current Market Arrangements ................................................ 111
Option 0+: Non-regulatory approach ...................................................................................... 112
Option 1: Improved energy market - no CMs .......................................................................... 112
Option 2: Improved energy market
CMs only when needed, based on a common EU-wide
adequacy assessment) ........................................................................................................................... 114
Option 3: Improved energy market - CMs only when needed, based on a common EU-wide
adequacy assessment, plus cross-border participation ......................................................................... 116
Option 4: Mandatory EU-wide or regional CMs ...................................................................... 117
Discarded Options ................................................................................................................... 117
Summary of specific measures comprising each Option ......................................................... 117
5.3.
Options to address Problem Area III (When preparing or managing crisis situations, Member
States tend to disregard the situation across their borders) ................................................................ 120
Overview of the policy options ................................................................................................ 120
Option 0: Baseline scenario
Purely national approach to electricity crises .......................... 120
Option 0+: Non-regulatory approach ...................................................................................... 121
Option 1: Common minimum rules to be implemented by Member States ........................... 122
Option 2: Common minimum rules to be implemented by Member States, plus regional co-
operation ............................................................................................................................................... 124
Option 3: Full harmonisation and decision-making at regional level ...................................... 127
Discarded Options ................................................................................................................... 128
Summary of specific measures comprising each Option ......................................................... 128
5.4.
Options to address Problem Area IV (Slow deployment and low levels of services and poor
market performance) ........................................................................................................................... 132
Overview of the policy options ................................................................................................ 132
Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer
engagement and poor data flows .......................................................................................................... 132
Option 0+: Non-regulatory approach to address competition and consumer engagement ... 133
Option 1: Flexible legislation addressing all problem drivers .................................................. 134
Option 2: EU Harmonization and extensive safeguards for consumers addressing all problem
drivers 136
Summary of specific measures comprising each Option ......................................................... 137
6.
ASSESSMENT OF THE IMPACTS OF THE VARIOUS POLICY OPTIONS ....... 139
6.1.
Assessment of economic impacts for Problem Area I (Market design not fit for an increasing
share of variable decentralized generation and technological developments ...................................... 139
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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.
7.
COMPARISON OF THE OPTIONS ............................................................................ 208
7.1.
Comparison of options for adapting market design for the cost-effective operation of variable
and often decentralised generation, taking into account technological developments ........................ 208
7.2.
Comparison of Options for facilitating investments in the right amount and in the right type of
resources for the EU............................................................................................................................. 210
7.3.
Comparison of options for improving Member States' reliance on each other in times of system
stress and reinforcing coordination between Member States for preventing and managing crisis
situations ............................................................................................................................................. 213
7.4.
Comparison of options for addressing the causes and symptoms of weak competition in the
energy retail market ............................................................................................................................ 215
7.5.
Synergies, trade-offs between Problem Areas and sequencing .............................................. 217
Synergies .................................................................................................................................. 217
Trade-offs ................................................................................................................................ 219
Sequencing of measures .......................................................................................................... 220
8.
8.1.
8.2.
20
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
9.
GLOSSARY AND ACRONYMS.................................................................................... 225
21
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1.
1.1.
I
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)
1
('Third Package') has principally aimed at improving the functioning of the internal
energy market and resolving structural problems.
Since the adoption of the Third Package, electricity policy decisions have enabled
competition and increasing cross-border flows of electricity, notably with the introduction
of so called "market coupling"
2
and "flow-based" capacity allocation. In spite of significant
differences in the maturity of markets in Europe, overall electricity wholesale markets are
increasingly characterised by fair and open competition, and
though still insufficient
competition is also taking root at the retail level.
1.1.1.2.The Union's policy concerning climate change
The decarbonisation of EU economies is at the core of
the EU’s agenda for climate change
and energy. The targets in the Climate and Energy Package (2007) require Member States
to cut their greenhouse gas emissions by 20% (from 1990 levels), to produce 20% of their
energy from renewable energy sources (RES), and to improve energy efficiency by 20 %
(the
'2020 targets').
3
In 2011, the European Union committed to reduce greenhouse gas emissions to 80-95%
below 1990 levels by 2050. For this purpose, the European Commission adopted an Energy
1
2
3
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
22
Fejl! Brug fanen Hjem til at anvende Heading 1,Livello 1 på teksten, der skal vises her.
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Roadmap
4
and a roadmap for moving to a competitive low carbon economy
5
exploring
the transition of the energy system in ways that would be compatible with this greenhouse
gas reductions target while also increasing competitiveness and security of supply. The
2050 roadmap will require a higher degree of decarbonisation from the electricity sector
compared to other economic sectors.
These ambitions were reaffirmed by the European Council of October 2014, which
endorsed targets for 2030 of at least 40 % for domestic greenhouse gas emissions reduction
(compared to 1990 levels), at least 27 % for the share of renewable energy consumption,
binding at EU level and at least 27 % energy savings, to be reviewed by 2020, having in
mind an EU level of 30% (the
'2030 targets').
6
At the Paris climate conference (COP21) in December 2015, 195 countries adopted the
first-ever legally binding global climate deal. The European Council of March 2016
confirmed the EU's commitment to implement the 2030 targets. The Paris Agreement was
ratified by the European Union and entered into force on 4 November 2016..
1.1.1.3.Paradigm shift in the electricity sector
The Union's goals for climate change and energy have led to a paradigm shift in the means
employed to generate electricity: since the adoption of the Third Package, there has been
a move towards the deployment of capital-intensive low marginal cost, variable and often
decentralised electricity from RES E (mostly from solar and wind technologies) that is
expected to become more pronounced by 2030.
The increasing penetration of RES E is driven
inter alia
by the objective to reduce
greenhouse gas emissions in line with the 2020 and 2030 targets. The 2030 greenhouse gas
emission reduction target is to be delivered through reducing emissions by 43% compared
to 2005 for the sectors in the EU's ETS
7
(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
8
, the ETS and the additional national policies by Member States to increase the
share of renewables in the energy mix.
The Renewable Energy Directive established a European framework for the promotion of
renewable energy, setting mandatory national renewable energy targets for achieving a
20% EU share of renewable energy in the final energy consumption and a 10% share of
4
5
6
7
8
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
23
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energy from renewable sources in transport by 2020. These objectives have translated into
a need to foster the increased production of electricity from reneweble energy sources.
9
In parallel with the increased deployment of variable and decentralized RES E, the
increasing digitalisation of electricity networks and the environment behind the meter now
enables many elements of the electricity system to be operated more flexibly and
efficiently in the context of RES E generation. It also allows smaller actors to play an
increasingly important part in the market on both the supply side and
crucially
the
demand side, potentially untapping a vast new system resource.
From the consumer's perspective, increasingly intelligent grids unlock a host of other
possibilities, including innovative new products and services, lower entry barriers for new
suppliers, and improved billing and switching. This promises to unlock value and improve
the consumer experience
provided the legislative framework adapts to the changing
needs and possibilities. Indeed, fully engaging end consumers will be essential to realizing
the full benefits that the digital transformation can bring in terms of grid flexibility.
Moreover, electricity demand will progressively reflect the increasing electrification of
transport and heating.
The challenges the EU's electricity systems face are reflected in the European Commission
Communication of February 2015 on
“A Framework Strategy for a Resilient Energy Union
with a Forward-Looking
Climate Change Policy”
10
where the Commission announced a
new electricity market design linking wholesale and retail markets. As part of the
legislative reform process needed to establish the Energy Union, it also announced new
legislation on security of electricity supply.
In the light of the Energy Union Framework Strategy, the present impact assessment
reflects and analyses the need and policy options for a possible revision of the main
framework governing electricity markets and security of electricity supply policies in
Europe. The new electricity market design contributes strongly to the overall Energy Union
objectives of securing low carbon energy supplies to the European consumers at least costs.
1.1.1.4.The vision for the EU electricity market in 2030 and beyond
The Energy Union Framework Strategy sets out the vision of an Energy Union "with
citizens at its core, where citizens take ownership of the energy transition, benefit from
new technologies to reduce their bills, participate actively in the market, and where
vulnerable consumers are protected".
Well-functioning energy markets that ensure secure
energy supplies at competitive prices are important for achieving growth and consumer
welfare in the European Union. The future of the entire energy sector will, to a significant
extent, be shaped by the evolution of the electricity sector, which is key to addressing
climate change. With the quick ratification of the global Paris Agreement on climate
change and its subsequent entry into force, it becomes clear how important it is for all
9
10
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
11
and thus in avoiding the erosion of the market value of RES E produced
electricity;
the revision of priority dispatch rules, removal of must-run units, increasing
demand response and storage, together with the better functioning of the short-
term markets will strongly reduce or even eliminate the occurrence of negative
-
-
11
Also occasionally referred to as the 'cannibalisation effect'.
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-
-
-
-
prices
leading again to higher average wholesale prices (especially during the
hours with significant variable RES E generation);
improved rules for intraday and balancing markets will increase their liquidity
and allow access to those markets for all resources, thus helping generators
reduce their balancing costs;
removing existing (explicit or implicit) restrictions for the participation of all
resources to the reserve and ancillary services markets will allow RES E to
generate additional revenues from these markets;
price signals reflecting the actual value of electricity at each point of time, as
well as the value of flexibility, will ensure that the flexible assets most needed
for the system are invested in or, at least, are less likely to be decommissioned.
Low exit barriers to facilitate exit of overcapacities.
The above mentioned changes will all help to improve the competitive situation of RES E
and reduce the need for dedicated support.
The results of the modelling for this Impact Assessment indicate that investments in the
most mature renewable technologies could be driven by the market by 2030 (such as
certain solar PV and onshore wind). At the beginning of the period, generation over-
capacity in certain areas, weaker investment signal from the ETS and low wholesale market
prices and still high RES E technology costs, make the case for investments in RES E
technologies more difficult. The underpinning modelling and analysis, points that the RES
E funding gap in 2020 is gradually reducing towards 2030 as the market conditions
improve. Less mature RES E technologies, needed for meeting the 2030 and 2050 energy
and climate objectives, such as off-shore wind, will likely need some form of support to
cover at least a fraction of total project costs (complementing the revenues obtained from
the energy markets) throughout the 2021-2030 period.
The picture also depends on regions. RES E technologies could be more easily financed
by the market in the regions with the highest potential (e.g. onshore wind in the Nordic
region or solar in Southern Europe), while RES E could continue to require support in the
British Isles and in Central Europe. Conditions however also depend on the cost of capital.
At the same time it has to be acknowledged that whether and what point in time financing
of RES E through markets alone will actually take off remains difficult to predict. This is
because financing of capital intensive technologies such as most RES E through markets
based on marginal cost pricing will remain challenging. In the absence of measures that
address system flexibility, higher penetration of RES with low marginal cost could reduce
the market value that such RES E can actually achieve. Removing barriers to the
flexibilisation of demand and improving the responsiveness of demand and supply to price
signals stands out as a key measure in this regards in order to further stabilise the revenue
of RES E producers from the market.
On the other hand the future capacity of RES to be financed through the market will also
depend on certain conditions outside of the market design and ETS prices, such as
continued decrease in the costs of technologies, availability of capital at a reasonable price,
social acceptance and sufficiently high and stable fossil fuel prices.
While the market reforms described above are therefore no regret options to facilitate RES
investment, support schemes will still be needed at least for a transitional period. It is
therefore essential to further reform such schemes to make them as market-oriented as
possible.
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… with a market-based
and more Europeanised approach to support schemes to cover any
investment gap .
Where needed, support will be (i) cost-effective and kept to a minimum, and (ii) will create
as little distortions as possible to the functioning of electricity markets, and to competition
between technologies and between Member States. The legal frame for RES E support
schemes would ensure sufficient investor certainty over the 2021-2030 period and require
the use (where needed) of market-based and cost-effective schemes, based on the design
of emerging best practices. Auctions could introduce competitive forces to determine the
level of support needed on top of market revenues and incentivise RES E producers to
develop business models that maximise market-based revenues. The use of tenders would
imply a natural phase-out mechanism for support, determining the remaining level of
support required to bridge any financing gap. The continued participation of small and
local actors, including energy communities, in the energy transition should be ensured in
this process.
The market should also provide, as a principle, security of supply.
By 2030, the market, as described above, could in principle successfully attract the required
investments to ensure adequate matching of supply and demand.
Today, most of the EU's power markets have more capacity than needed. However, with
demand increasing, e.g. due to E-Mobility and heat pumps, and older power plants retiring
supply margins are likely to get tighter. Therefore, a legal framework needs to be in place
to allow for the formation of electricity prices that send the signals for tomorrow's
investments. In this context, scarcity prices will become more and more important to
provide the right incentives for the operation of resources (including for demand response)
when they are most needed. Hedging products which suppliers can buy to protect
themselves against peaks are already available now and more innovative tools are expected
to be brought forward by market participants without the need for additional intervention
by national authorities. This will also provide opportunities for generators (who will be
natural provider of such hedging tools) to secure further revenues.
In the new market framework capacity mechanisms might only be considered if a residual
risk to security of supply can be proven after underlying market distortions have been
removed and the contribution of market integration to security of supply has been taken
into account.
The legal framework will provide tools to facilitate an objective case-by-case judgement
on whether the introduction of capacity mechanisms is needed and set out measures to
ensure that their potentially distortive effects are kept at a minimum, while placing them
in a more regional context. Accordingly, their need would have to be proven against an
EU-wide system adequacy assessment and they would have to allow for cross-border
participation to minimise distortions of investment incentives across the borders. Capacity
mechanisms would be designed in a way as to not discriminate against different generation
technologies and demand side capacities. Additionally, where need has been demonstrated
for such mechanisms, Member States should take into account how such mechanisms
would impact the achievement of the decarbonisation objectives.
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Member States should regularly review their resource adequacy
12
situation and phase out
capacity mechanisms once the underlying market or regulatory concerns have been
resolved.
Despite best efforts to build an integrated and resilient power market, crisis situations can
never be excluded. The potential for crisis situation increases with climate change (i.e.
extreme weather conditions) and with the emergence of new areas that are subject to
criticalities (i.e. malicious attacks, cyber-threats). Such crises tend to often have an
immediate cross-border effect in electricity. The legal framework would provide tools to
ensure that national security of supply policies are better coordinated and aligned to tackle
possible crisis situations, in particular those that affect several countries at the same time.
Scope of the initiative
1.1.2.1.Current relevant legislative framework
EU's electricity markets are currently regulated at EU level by a series of acts collectively
referred to as the "Third Package"
13
.
The main objectives of the Third Package were:
-
-
-
Improving competition through better regulation, unbundling and reducing
asymmetric information;
Improving security of supply by strengthening the incentives for sufficient
investment in transmission and distribution capacities; and,
Improving consumer protection and preventing energy poverty.
The Third Package mainly focused on improving the conditions for competition as
resulting from previous generations of legislation by improving the level playing field. The
most important root cause for the lack of competition identified at the time
14
was the
existence of vertically integrated companies, which not only controlled essential facilities
(such as electricity transmission systems) but also enjoyed significant market power in the
wholesale and, often, retail markets. Many of the measures associated with the Third
Package sought to directly or indirectly address this issue, such as by improving the
12
13
14
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')
15
,
and provided a mandate for developing these network codes (as well as other tasks related
to the EU's electricity markets) to transmission system operators within the
ENTSO-E
16
and to national regulatory authorities, within the Agency for the Cooperation of Energy
Regulators ('ACER')
17
.
The main framework for electricity security of supply in the Union is currently Directive
2005/89/EC ("Security
of Electricity Supply Directive'
or
'SoS Directive'")
18
. This SoS
Directive requires Member States to take certain measures with the view to ensuring
security of supply, but leaves it by and large to the Member States how to implement these
measures. The Third Package complemented the SoS Directive and superseded
de facto
some of its provisions.
1.1.2.2.Policy development subsequent to the Third Package
The present initiative builds on previous related policy initiatives and reports that
intervened since the adoption of the Third Package and the Security of Electricity Supply
Directive, in particular:
-
-
"Report on the progress concerning measures to safeguard security of electricity
supply and infrastructure investment"
COM (2010) 330 final
19
;
"Delivering the internal electricity market and making the most of public
interventions"
(C(2013) 7243). This Communication was accompanied
inter alia
by a Commission Staff working document (SWD(2013)438) entitled
"Generation
Adequacy in the internal electricity market
guidance on public intervention";
Communication on the "Progress
towards completing the Internal Energy Market"
COM(2014) 634 final. This Communication emphasized that energy market
integration has delivered many positive results but that, at the same time, further
steps are needed to complete the internal market;
"Communication on Energy Security"
(COM(2014)330). This Communication
emphasised
inter alia
the need achieve a better functioning and a more integrated
energy market;
Special Report by the European Court of Auditors
"Improving the security of
energy supply by developing the internal energy market: more efforts needed".
This
-
-
-
15
16
17
18
19
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
20
;
"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
21
, this
report
inter alia
that shed light on the drivers of retail and wholesale price
developments;
"Delivering a new deal for energy consumers"
(COM(2015) 339). This
Communication laid out the Commission's intention to enable all consumers to
fully participate in the energy transition, taking advantage of new technologies that
enable wholesale and retail markets to be better linked.
The Commisison published a study on
"Investment perspectives in electricity
markets"
22
Technical Report
23
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
24
(both wholesale and retail) and points out that, between 2005 and 2012,
the intensity of competition in European energy markets may have declined
25
.
The Commission Staff working document (SWD(2015)249) entitled
"Energy
Consumer Trends 2010 - 2015"
presents market research into the problems that
energy consumers continue to be confronted with.
The Commission launched a a sector inquiry into national capacity mechanisms,
The resulting
"Interim Report of the Sector Inquiry on Capacity Mechanisms"
(SWD SWD(2016) 119 final)
26
points out that there is a lack of adequate
assessment of the actual need for capacity mechanisms. It also appears that some
capacity mechanisms in place could be better targeted and more cost effective. It
emphasizes the need to design capacity mechanisms with transparent and open
rules of participation and a capacity product that does not undermine the
functioning of the electricity market, taking into account cross-border participation.
1.1.2.3.Scope and summary of the initiative
In line with the Union's policy on climate change and energy, the proposed initiative aims
at deepening energy markets and setting a framework governing security of supply policies
that enables the transition towards a low carbon electricity production.
20
21
22
23
24
25
26
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
on
13.04.2016
at:
:
http://ec.europa.eu/competition/sectors/energy/capacity_mechanism_report_en.pdf
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The transition towards a low carbon electricity sector as well as technical progress will
have profound implications on the manner in which the electricity sector is organised and
the roles of market actors and consumers, not all of which can be foreseen with accuracy
today. As it cannot be predicted how the electricity markets and progress of innovation
will look like in a few decades from now, the proposed initiative constitutes a next step in
a wider and longer evolutionary process that will guide the EU's electricity markets
towards the future. The initiative will consequently not address the challenges that might
arise when operating a fully decarbonised power system.
27
This initiative also aims at improving consumer protection and engagement for both
electricity and gas consumers
28
.
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
29
for partial
transposition of the Electricity Directive have been closed as the Member States achieved
full transposition in the course of the proceedings.
In addition to ensuring compliance of national rules with the Third Package, the
Commission has carried out assessments to identify and resolve problems concerning
incorrect transposition or bad application of the Third Package. On this basis, the
Commission has opened EU Pilot cases against a number of Member States. As of 7th July
2016, 8 of these EU Pilot cases have resulted in infringement procedures where,
inter alia,
the violation of the EU electricity market rules is at stake.
In January 2014 the Directorate General for Energy of the European Commission ('DG
ENER') launched a public consultation on retail markets for energy.
Whilst preparing the single market progress report (COM(2014) 634 final), published on
13 October 2014, DG ENER decided to study a number of changes to the current
legislation.
The Commission (DG ENER) started in 2015 the preparatory work for the present impact
assessment to assess policy options related to the internal energy market for electricity and
27
28
29
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)
30
.
In April 2015, the Commission (DG Competition) launched a sector inquiry into national
capacity mechanisms. The Commission interim report and the accompanying Commission
staff working document, adopted on 13 April 2016 have provided a significant input for
the proposed initiative. This will be further completed by the final report.
1.1.3.2.Consultation and expertise
The Commission has conducted a number of wide public consultations on the different
policy areas covered by the present Impact assessment which took place between 2014 and
2016. In addition to the public consultations, it has organised a number of targeted
consultations with stakeholders throughout 2015 and 2016
31
.
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
32
.
In parallel, the Commission has also conducted a number of studies mainly or specifically
for this impact assessment
33
.
1.2.
Interlinkages with parallel initiatives
The proposed initiatives are strongly linked to other energy and climate related legislative
proposals brought forward in parallel with the present initiative equally aimed at delivering
upon the five dimensions of the Energy Union, namely energy security, solidarity and trust,
a fully integrated European energy market, energy efficiency contributing to moderation
of demand, decarbonisation, research, innovation and competitiveness. These other energy
related legislative proposals include:
The Renewable Energy Package comprising the new Renewable Energy Directive
and bioenergy sustainability policy for 2030 ('RED
II')
The RED II covers a number of measures deemed necessary to attain the EU binding
objective of reaching a level of at least 27% RES in final energy consumption by 2030
across the electricity, heating and cooling, and transport sectors. As regards electricity in
particular, the Renewables Directive proposes a framework for the design of support
schemes for renewable electricity, a framework for renewable self-consumption and
renewable energy communities, as well as various measures to reduce administrative costs
and burden.
30
31
32
33
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
34
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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
34
.
The issue is explored in more detail in section 6.2 of the present impact assessment and, in
particular, the RED II impact assessment.
34
See Box 7 and Annex IV for more information
35
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Commission guidance on regional cooperation
The forthcoming guidance on regional cooperation may set out general principles for
regional cooperation across all five dimensions of the Energy Union, described how these
principles are being addressed in this initiative and other legislative proposal for
Renewables and Energy Union governance, and will offer suggestions on how regional co-
operation, where it applies, can be made to work in practice.
The present initiative seeks to improve market functioning, and calls for a more regional
approach to system operation and security of supply. The guidance document should help
Member States best achieve regional co-operation, including in areas where the present
initiative mandates effective co-operation (e.g. the initiative calls on Member States to
prepare risk preparedness plans in a regional context, cf. infra).
The Energy Union governance initiative
The Energy Union governance initiative aims at ensuring a coordinated and coherent
implementation of the Energy Union Strategy across its five dimensions with emphasis on
the EU's energy and climate targets for 2030. This is established through a coherent
combination of EU-level and national action, a strengthened political process and with
reduced administrative burden.
With these objectives in mind, the draft Regulation is based on two pillars:
-
Streamlining and integration of existing planning, reporting and monitoring
obligations in the energy and climate fields, in order to reduce unnecessary
administrative burden;
A political process between Member States and the Commission with close
involvement of other EU institutions to support the achievement of the Energy
Union objectives, including notably the 2030 targets for greenhouse gas emission
reductions, renewable energy and energy efficiency.
-
In relation to this initiative the governance initiative will also streamline reporting
obligations by Member States and the Commission that are presently enshrined in the Third
Package.
The Energy Efficiency legislation ('EE')
35
and the related Energy Performance of
Buildings Directive ('EPBD')
36
including the proposals for their amendment.
In general terms, energy efficiency measures interact with the present initiative as they
affect the level and structure of electricity demand. In addition, energy efficiency measures
can alleviate energy poverty and consumer vulnerability. Besides consumer income and
energy prices, energy efficiency is one of the major drivers of energy poverty.
35
36
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.
36
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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
37
because these relate to incentivising
flexibility in the market and participation of consumers in the market, both core subjects
of the present initiative. This logic is reinforced by the fact that the Third Package already
contains related provisions on demand response.
The Commission Regulation establishing a Guideline on Electricity Balancing
('Balancing Guideline')
The Balancing Guideline constitutes an implementing act that will be adopted using the
Electricity Regulation as a legal basis. The Balancing Guideline is closely related to the
present initiative. This is because efficient, integrated balancing markets are an important
building block for the consistent functioning of wholesale markets which in turn are needed
for a cost effective integration of RES E into the electricity market.
The Balancing Guideline aims at harmonising certain aspects of the EU's balancing
markets, with a focus on optimising the cross-border usage that TSOs make of the
balancing reserves that each have decided to contract individually, such as harmonisation
of the pricing methodology for balancing; standardisation of balancing products and merit-
order activation of balancing energy.
The present initiative seeks in contrast to focus on a more integrated approach to deciding
and contracting of the balancing reserves, as opposed to their usage, which touches upon
the optimal allocation of the cross-border transmission capacities and a regional approach
to balancing reserves.
Thus, the Balancing Guideline deals principally with exchanges of balancing energy
whereas the present initiative focusses on the exchange and sharing of balancing capacity.
The latter issue is much more political than the exchange of balancing energy and closely
related to other questions dealt with in the present initiative, such as regional TSO
cooperation or the reservation of transmission capacities. The assessments of the two
37
In a manner that will preserve DG Energy's ability to continue infringing Member States that have not
correctly implemented what is now Article 15(8) of the Energy Efficiency Directive.
37
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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
38
.
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.
2.1.
P
ROBLEM
D
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%
39
.
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%
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)
22
422
Total RES E (TWh)
Variable RES E in RES E
5%
Variable RES E in total net generation
1%
Source: PRIMES; based on EUCO27 scenario
2005
72
467
16%
2%
2010
171
683
25%
5%
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
38
39
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.
38
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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
40
times smaller than of a conventional power station, the number of
power producing units and operators will increase significantly. Consequently, the
transition towards more renewables implies that more and more power will be generated
in a decentralised way. Market roles and responsibilities will have to be adapted.
Finally, these new installations will not necessarily be located next to consumption centres
but where there are favourable natural resources. This can create grid congestion and local
oversupply.
The transition towards a low carbon electricity production poses a number of challenges
for the cost-effective organisation and operation of Europe's power system and its
electricity markets. The existing market framework was designed in an era in which large-
scale, centralised power stations, primarily fired by fossil fuels, supplied passive customers
at any time with as much electricity as they wanted in a geographically limited area
typically a Member State. This framework is not fit for taking up large amounts of variable,
often decentralised electricity generation nor for actively involving more consumers in
electricity markets.
The main underlying drivers are: (i) the inefficient organisation of short-term electricity
markets and balancing markets, (ii) exemptions from fundamental market principles, (iii)
consumers that do not actively engage in the market, (iv) consumers do not actively engage
in the market and demand response potential remains largely untapped; and (v) distribution
networks that are not actively managed and grid users are poorly incentivised.
40
The largest solar PV park in the EU is the 300 MW Cestas Park in France,
http://www.pv-
magazine.com/news/details/beitrag/frances-300-mw-cestas-solar-plant-
inaugurated_100022247/#axzz4Cxalbrhc.
The largest wind farm is the offshore farm "London array"
with 630 MW distributed over 175 turbines. By comparison, the largest nuclear power plant in Europe
is the Gravelines plant in France, with a net capacity of 5460MW. The largest coal-fired power station
in Europe is the Polish Bełchatów plant with a capacity of 5420 MW.
39
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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
41
.
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
42
. Efficient and liquid markets with robust price signals are
crucial to guide these decisions
43
.
The fact that the production patterns from weather dependent RES E can only be predicted
with acceptable accuracy within hours, creates challenges for market parties and for system
operation. In the absence of efficient and liquid short-term electricity wholesale markets,
system operators have to take actions to balance the system and manage network
41
42
43
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".
40
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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
44
. As way
of illustration, in 2014, in the intraday timeframe, only five markets in Europe had a ratio
of traded energy to demand of greater than 1%
45
. Further, progress remains in connecting
('coupling') national intraday markets in the same way as day-ahead markets. This can lead
to a low level of cross-border competition in intraday markets. In 2014 only 4.1% of
available interconnection capacity at the intraday stage was used, compared to 40% at day-
ahead.
Improving liquidity of intraday markets requires addressing various issues, including
removing the barriers that today exist for trading power across borders as well as providing
proper incentives to rebalance portfolios by trading until short notice before markets close.
In addition, technical rules of the market (i.e. products, bid sizes, gate closure times) are
often not defined with renewables or demand response in mind creating
de facto
barriers
for its participation.
Specific issues include a variation in commitment periods across Europe, with some
Member States choosing 15-minute and other Member States choosing 60-minute
products, and the time to which market participants can trade, which can be as short as 5
minutes or, in some instances, upto several hours before real time. There is also a difference
in how markets are organised: in continuously traded markets, transactions are concluded
throughout the trading period every time there is a match between bids and offers.
Transactions are concluded differently in auction markets, where previously collected bids
and offers are all matched at once at the end of the trading period.
The last market-based measure to net out imbalances between injections and withdrawals
of electricity is the balancing market. As such, the balancing market is not solely a
44
45
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
41
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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
46
. Furthermore, cross-border
integration and liquidity of short-term markets has improved over the last years, with
further progress expected over the coming years, such as through the progressive
penetration of storage, and following the present proposal. Thus, the underlying reasons
for the exemption of RES E from this principle have to be revisited.
46
ENTSO-E provided figures that following the introduction of balancing responsibility in one Member
States, the average hourly imbalance of PV installations improved from 11.2 % in 2010 to 7.0 % in
March 2016, and the average hourly imbalance of wind improved from 11.1 % to 7.4 % over the same
period.
42
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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.
43
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R&D results
47
:
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
48
and storage equipment
that allow consumers
even smaller commercial and residential consumers
to generate
their own electricity, store it, and manage their consumption more easily than ever. While
more and more consumers have access to smart meters and distributed renewable energy
resources such as roof-top solar panels, heat pumps and batteries, a minor share manages
their consumption and these resources actively.
Large-scale industrial consumers already are active participants in electricity markets.
However, the vast majority of other consumers neither has the ability nor the incentive to
take consumption, production and investment decisions based on price signals that reflect
the actual value of electricity and grid infrastructure. The metering and billing of
consumers does not allow them to react to prices within the time frames in which wholesale
markets operate. And even where technically possible, many electricity suppliers appear
reluctant to offer consumer tariffs that enable this. This leads to the
overconsumption/underproduction of electricity at times when it is scarce and the
underutilisation/overproduction of electricity at times when it is abundant.
Indeed, current markets do not enable us to reap the full benefits of technological progress
in terms of reducing transaction costs, reducing information asymmetries, and (thereby)
reducing barriers to market participation for smaller commercial and residential
consumers.
Periods of abundance and scarcity will increasingly be driven by high levels of RES E
generation. To deal with an increased share of variable renewables generation in an
efficient way, flexibility is key. Traditionally, almost all flexibility was provided in the
electricity systems by controlling the supply side. However, it is now possible to provide
demand side flexibility cost effectively. New technological developments such as smart
metering systems, home automation, etc. but also new flexible loads such as heat pumps
and electric vehicles allow for the reduction of demand peaks and, hence, significantly
reduce system costs.
47
48
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
0
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.
45
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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
0
4000
8000
12000
16000
MW
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
46
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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:
47
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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
0
0
0
49
566
0
810
1689
860
1527
30
48
4131
7
0
Austria
Yes
Yes
Belgium
Yes
Yes
Yes
Bulgaria
No
No
Croatia
No
No
Cyprus
No market
No market
Czech Republic
Yes
Yes
Denmark
Yes
Yes
Estonia
Yes
No
Finland
Yes
Yes
Yes
France
Yes
Yes
Yes
Germany
Yes
Yes
Yes
Greece
No (2015)
No
Hungary
Yes
Yes
Ireland
Yes
Yes
Yes
Italy
Yes
No
Yes
Latvia
Yes
No
Yes
Lithuania
unclear
No
Luxembourg
No information
No information
Malta
No market
No market
Netherlands
Yes
Yes
170
Poland
Yes
Yes
No
228
Portugal
Yes
No
40
Romania
Yes
Yes
79
Slovakia
Yes
Yes
40
Slovenia
No
Yes
21
Spain
Yes
No
Yes
2083
Sweden
Yes
Yes
Yes
666
UK
Yes
Yes
Yes
1792
Total
15628
Source: Impact Assessment support Study on downstream flexibility, demand response and smart metering,
COWI, 2016
R&D results:
VSync demonstrated that PV or wind generation, if equipped with a technology as
demonstrated in the VSync project, can replace the inertia that large power plants possess that is needed to
reduce frequency variations. Therefore, such technologies could in principle be used to provide balancing
services to the TSO.
EvolvDSO has identified and worked-out the details of future roles for actors active in the management of
power systems at the distribution level. The project identifies ways in which flexibility of resources
connected at distribution level could be revealed, valorised, contracted and exploited by various actors of the
power system. It identified roles that could be fulfilled by DSOs and by market parties and asks that these
are clarified
Several European demonstration projects such as ECOGRID-EU, Integral, EEPOS, V-Sync and S3C have
provided evidence that demand response is sufficiently mature from a technical point of view, while stressing
the need to removing market related barriers to its deployment.
In particular, Integral and ECOGRID-EU show that valuing flexibility through price signals is possible and
easy, that local assets can participate and earn money in the wholesale market, and that the economic viability
depends on the value of flexibility. Integral also demonstrated that flexibility of a household's energy
consumption (and hence the ability to provide demand response) was higher than initially expected, probably
due to the automated response that did not require active consumer participation. ECOGRID-EU showed
that a customer with manual control gave a 60 kW total peak load reduction while automated or semi-
automated customers gave an average peak reduction of 583 kW
.
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RES E and flexible electricity systems
Demand response, like other measures that improve the degree of flexibility in the system,
have an connection to the ability of RES E to finance itself in the market, through what is
often referred to as the 'merit order effect'.
49
During windy and sunny days the additional
electricity supply reduces the prices. Because the drop is larger with more installed
capacity, the market value of variable renewable electricity falls with higher penetration
rate, translating into a gap to the average market value of all electricity generators over a
given period. Inflexible markets where demand and generation are non-responsive to price
signals (including through measures such as priority dispatch or 'must-run' obligations)
render this effect more pronounced. This effect is already visible today in certain Member
States, and in the absence of measures, can be expected to become even more relevant as
renewables penetration increases further.
At the one hand, this implies that as renewables are further gaining market shares in the
coming decade, the regulatory framework should not only incentivise the deployment of
renewables where costs are low (e.g. due to abundant wind or solar resources), but also
where and when the value of the produced electricity is the highest. On the other hand, by
improving the market framework in which RES E operates by rendering it more flexible,
unnecesarry erosion of the value of RES E assets can be prevented.
Reference is made to the box in Section 6.2.6.3 and Section 6.2.6.4 for further information.
Driver 4: Distribution networks are not actively managed and grid users are poorly
incentivised
Most of the time, the present regulatory framework does not provide appropiate tools to
distribution network operators to actively manage the electricity flows in their networks.
It also does not provide incentives to customers connected to distribution grids to use the
network more efficiently. Because smaller consumers have historically participated in the
broader electricity system only to a limited extent, currently no framework exists that puts
such incentives in place. This has led to fears over the impact that the deployment of
distributed resources could have at system-level (e.g. that the costs of upgrading the
network to integrate them would outweigh their combined benefits in other terms).
Moreover, the regulatory framework for DSOs, which most of the times is based on cost-
plus regulation, does not provide proper incentives for investing in innovative solutions
which promote energy efficiency or demand-response and fails to recognise the use of
flexibility as an alternative to grid expansion.
With RES E being a source of electricity generation that is often decentralised in nature,
DSOs are gradually being transformed from passive network operators primarily
concerned with passing-on electricity from the transmission grid to end-consumers, to
network operators that, not unlike TSOs, actively have to manage their grids. At the same
49
See Hirth, Lion,
"The Market Value of Variable Renewables",
Energy Policy, Volume 38, 2013, p.
218-236). The merit order effect is occasionally also referred to as the 'cannibalisation effect'.
50
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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
50
.
According to EvolvDSO, flexibility procurement and activation by DSOs are not addressed in the regulatory
framework in most Member States: they are not excluded in principle but not incentivised either and, because
they are not explicitly addressed, this creates uncertainty for the DSO to apply them.
The REServices study has analysed the possible services that wind and solar PV energy can provide to the
grid in theory but concludes that they are not able to (in the Member States analysed) due to the way the
market rules are defined.
The project SuSTAINABLE demonstrated that intelligent management supported by more reliable load and
weather forecast can optimise the operation of the grid. The results show that using the distributed flexibility
provided by demand-side response can bring an increase of RES E penetration while, at the same time, avoid
investments in network reinforcement, and this leads to a decrease in the investment costs of distribution
lines and substations.
The BRIDGE project recommended that products for ancillary services should be consistent and
standardized from transmission and down to the local level in the distribution network. Such harmonization
will facilitate the participation of demand-side response and small-scale RES in the markets for these
services, and thereby increase the availability of the services, enable cross-border exchanges and lower
system costs.
Tests in the project PlanGridEV with controllable loads (demand response, electric vehicles) performed in a
large variety of grid constellations have shown that peak loads could be reduced (up to 50%) and more
renewable electricity could be transported over the grid compared to scenarios with traditional distribution
grid scenarios. As a result, critical power supply situations can be avoided, and grids, consequently, do not
call for reinforcement
Both MetaPV and EvolvDSO suggest that a DSO makes a multiannual investment plan that takes into
account flexibility it can purchase from connected demand-side response or self-producers and consumers
(MetaPV suggests to do this through a cost-based analysis)
MetaPV also demonstrated that remotely controllable inverters connecting PV-panels to the distribution grid
can offer congestion management services to the distribution grid (in the form of voltage control obtained
via reactive power modulation). This increases the capacity of the distribution grid to integrate intermittent
RES by 50%, at less than 10% of
the costs of ‘traditional’ investments in hardware such as copper.
2.2.
Problem Area II: Uncertainty about sufficient future generation investments
and uncoordinated capacity markets
In light of the 2030 objectives, considerable new investment in electricity generation
capacity will be required. The power sector is likely to play a central role in the energy
transition. First, it has been the main sector experiencing decarbonisation since the last
50
A list of the research and development projects mentioned in this box and their findings relevant to the
present impact assessment is provided in Annex 8.
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decade and its challenges still remain high. Second, in the near future, the power sector is
expected to support the economy in reducing its dependence on fossil fuels, notably in the
transport and heating and cooling sectors.
Generation capacity in the EU increased sharply from 2009 onwards due to the addition of
new renewables technologies to the already existing capacity. The composition of the
capacity mix progressively changed. Nuclear capacity started declining in recent years
(2010-2013) due to phasing out decisions in some Member States. Other conventional
capacity showed a decline in 2012-2013 as well
51
.
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
52
, 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
53
.
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
-
2
Biomass-waste fired
2,626
3,438
Geothermal heat
100
90
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
3
4,157
110
13,391
5,333
362
3,427
1
57,054
2015-2020
6,291
38,957
2,239
28,553
7,870
295
11,779
182
17,151
2,610
75
2,505
-
62,399
2020-2025
11,011
25,217
354
14,059
10,581
223
465
-
3,355
870
33
1,987
-
39,583
2025-2030
14,312
21,911
633
14,219
6,728
332
433
-
3,274
192
9
2,641
-
39,497
51
52
53
See on this and for further information,
European Commission, Investment perspectives in electricity
markets,
Institutional
Paper
003,
July
2015,
page
8.
http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf.
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
54
.
Figure 3 on pan-European wholesale market prices
Source: Platts and European power exchanges
Prices declined for a number of reasons
55
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
56
, and (iii) an
54
55
56
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
57
, 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
58
, (ii) over-investments in
thermal plants
59
, (iii) the increasing proportion of renewables with low marginal costs
driven by EU policies, (iv) barriers to decommission capacity
60
, and (v) continuing
improvement in the field of coupling national electricity markets
61
, leading to an increased
sharing of resources among Member States
62
.
As a result, for most regions in Europe current electricity wholesale prices do not indicate
the need for new investments into generation capacity. There are, however, doubts whether
the market, as currently designed, would be able to produce investment signals in case
generation capacities were needed. Independently of current overcapacities of most regions
in Europe, a number of Member States anticipate inadequate generation capacity in future
years and introduce capacity mechanisms at national level.
57
58
59
60
61
62
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
63
. 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
64
. For generators who operate on the market these payments
represent an additional income next to their earnings on the wholesale markets for energy.
Capacity payments, thus, represent additional support to maintain and/or develop capacity.
Irrespective whether generators are expected to earn their investments solely on the
'energy-only' market or whether they can also rely on additional payments for capacity,
wholesale power prices are central to provide the right signals for efficient market
63
64
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).
55
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operations. For the EU-target model
65
to function properly, prices need to be able to
properly reflect market conditions
66
.
Price signals and long-term confidence that costs can be recovered in reasonable payback
times are essential ingredients for well-functioning market. In a market which is not
distorted by external interventions, the variability of the spot price on the wholesale
market, plays a role in signalling the need of investment in new resources. In the absence
of the right short- and long-term price signals, it is more likely that inappropriate
investment or divestment decisions are taken, i.e. too-late decisions or technology choices
that turn out to be inefficient in the long run. Price differentials between different bidding
zones should determine where generation and demand should ideally be located,
67
.
In 2013 the Commission published an assessment identifying reasons why the market may
fail to deliver sufficient new investment to ensure generation adequacy
68
. 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
69
, resulting in more
65
66
67
68
69
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
32
and
following.
(http://ec.europa.eu/economy_finance/publications/eeip/pdf/ip003_en.pdf
See also SWD(2013) 438 "Generation
Adequacy in the internal electricity market - guidance on public
interventions",
Section 3 .
Cost structures vary according to the underlying technology deployed. In general, wind and solar
technologies have very low operational costs whereas the opposite is true for biomass fuelled generation.
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frequent periods with low wholesale prices. The variability of RES E production moreover
decreases the number and predictability of the periods when conventional electricity
generators are used, thereby increasing the risk profile and risk premiums of all
investments in electricity resources
70
. Whereas market participants are used to hedging
risks, and market trading arrangements are adapting to allow more risks to be covered, the
risk profile of investments will become more pronounced. This increases the need to ensure
that prices reflect the real value of electricity to ensure plants can cover their full costs,
even if they are operating less frequently.
The current market arrangements are constructed around the notion of price zones
delimited by network constraints. The price differences between such zones should drive
investments to be located where they relieve congestion by rewarding investments in areas
typified by high prices. The congestion rents collected by network operators to transport
electricity from low to high price zones are meant to be used to relieve congestion by
maintaining and constructing interconnection capacity.
However, today the delineation of price zones in practice does not reflect actual
congestion, but national borders. This prevents the establishment of prices that reflect local
supply and demand, which leads to the phenomenom of loop flows, which can reduce the
interconection capacity made available for cross-border trading and leads to expensive out-
of-market redispatching and significant distortions to prices and investment signals in
neighbouring bidding zones. To illustrate this, ACER has estimated, in their Market
Monitoring Report
71
, that reductions in cross-border capacity due to loop flows resulted in
a welfare loss of EUR 445 million in 2014. Further, the costs of re-dispatch and
countertrading to deal with inaccurate dispatch can be high. In 2015 the total cost for
redispatching within the German-Austria-Luxembourg bidding zone was approximately
EUR 930 million
72
. There is also evidence that cross-border capacity is being limited in
order to deal with internal contraints, again limiting cross-border trading opportunities.
The impacts of this can be significant. For example, when looking at the capacity between
Germany and the Nordic power system, the Swedish regulatory authority noted significant
capacity limitations, concluding that these were mostly due to internal contraints, and
found that losses amounted to a total of EUR 20 million per annum in Norway and
Sweden
73
.
A further issue that can potentially distort investment is that of network charges on
generators. This includes charges for use of the network, both at distribution-level and
transmission-level (tariffs), as well as the charges applied to generators for their connection
(connection charges). There is significant variation across the EU on the structure of these
charges, which are set at Member State-level. For instance, some Member States do not
70
71
72
73
Generators' expectations about future returns on their investments in generation capacity are affected
not only by the expected level of electricity prices, but also by several other sources of uncertainty, such
as increasing price volatility. The increasing weight of intermittent renewable technologies makes prices
more volatile and shortens the periods of operation during which conventional technologies are able to
recoup their fixed costs. In such circumstances, even slight variations in the level, frequency and duration
of scarcity prices have a significant impact on the expected returns on investments, increasing the risk
associated to investing in flexible conventional generation technologies.
"Market
Monitoring report 2014"
(2015) ACER, Section 4.3.2 on unscheduled flows and loop flows.
ENTSO-E Transparency Platform, at https://transparency.entsoe.eu/
"Capacity limitations between the Nordic countries and Germany"
Swedish Energy Markets
Inspectorate (2015)
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apply any tariffs to generators, others apply them based on connected capacity and others
based on the amount of electricity produced. Some include locational signals within the
tariff, some do not. With regards to connection charges, some calculate them based only
on the direct costs of accessing the system (shallow) and others include wider costs, such
as those of any grid reinforecement required (deep). Such variations can serve to distort
both investment and dispatch signals.
Driver 2: Uncoordinated state interventions to deal with real or perceived capacity
problems
The uncertainty on whether the market will bring forward sufficient investment, or keep
existing assets in the market, has, in a number of Member States, fuelled concerns about
system adequacy, i.e. the ability of the electricity system to serve demand at all times.
Certain Member States have reacted by introducing CMs designed to support investment
in the capacity that they deem necessary to ensure a secure and acceptable level of system
adequacy.
These measures often take the form of either dedicated generation assets kept in reserve or
a system of market wide payments to generators for availability when needed.
Figure 4: Capacity Mechanisms in Europe
2015
Strategic reserves for DK2
region from 2016-2018 (and
potentially from 2019-2020)
Strategic reserve (since 2007)
Capacity auction
(since 2014 - first delivery in
2018/19)
Capacity payment
(since 2007)
considering reliably options
Capacity requirements
(certification started 1 April
2015)
Capacity payment (since 2008)
Tendering for capacity
considered but no plans
Strategic reserve
(since 2004 ) - gradual phase-
out 2020 and considering a
permanent market system
after 2020
Debate pending
Strategic reserve
(from 2016 on, for 2 years,
with possible extension for 2
years)
Strategic reserve
(since 1 November 2014)
Reliability option
(first auction end 2016, first
delivery contracted capacity is
expected in 2021)
New Capacity Mechanism
under assessment by COMP
(Capacity payments from 2006
to 2014)
Capacity Payment (Since 2010
partially suspended between
May 2011 and December 2014)
No CM (energy only market)
CM proposed/under consideration
CM operational
Source:
"Market
Monitoring Report 2014"
(2015) ACER.
These initiatives by Member States are based on non-aligned perceptions and expectations
as to the degree the electricity system can serve electricity demand at all times and a
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reluctance to rely on the contribution the EU system as a whole can make to the adequacy
of the system of a given Member State.
74
As reflected in the Interim Report of the Sector Enquiry
75
led by DG Competition, many
existing CMs have been designed without a proper assessment of whether a security of
supply problem existed in the relevant market. Many Member States have not adequately
established what should be their appropriate level of supply security (as expressed by their
'reliability standard') before putting in place a CM.
Methods of assessing resource adequacy vary widely between Member States
76
, which
make comparison and cooperation across borders difficult. Many resource adequacy
assessments take a purely national perspective and may substantially differ depending on
the underlying assumptions made and the extent to which foreign capacities
77
as well as
demand side flexibility
78
are taken into account. This, in turn, means some Member States
force consumers to over-pay for 'extra' capacities they do not really need.
74
75
76
77
78
Indeed, a majority of Member States expect reliability problems due to resource adequacy in the future
even though such problems have been extremely rare in the past five years. Such issues have only arisen
in Italy on the Islands of Sardinia and Sicily which are not connected to the grid on the mainland.
See also SWD(2016) 119 final
"Interim report of the Sector Inquiry on Capacity Mechanisms",
http://ec.europa.eu/competition/sectors/energy/state_aid_to_secure_electricity_supply_en.html
For more details, see annex 5.1. See also
"Generation adequacy methodologies review",
(2016), JRC
Science for Policy Report and CEER (2014), "Assessment
of electricity generation adequacy in
European countries".
According to the CEER report,
"the extent to which current generation adequacy reports take the
benefits of interconnectors into account varies a lot: 4 reports still model an isolated system (Norway,
Estonia, Romania, and Sweden); 2 reports use both interconnected and isolated modelling (France and
Belgium); 3 report methodologies are being modified to include an interconnection modelling; 9 reports
simulate an interconnected system (UK, the Netherlands, Czech republic, Lithuania, Finland, Belgium
and Ireland, while France and Italy use both methods)."
According to the CEER report,
"only 3 countries include demand response as a separate factor in their
load forecast methodology i.e. the UK, France and Spain. In Norway and Finland, the contribution from
demand response is not included as separate factor, but peak load estimation is based on actual load
curves which include the effect of demand response. Sweden does not consider demand response, and
do not assume that consumers respond to peak load in their analysis."
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Table 5: Deterministic vs probabilistic approaches to adequacy assessments
Source: European Commission based on replies to sector inquiry, see below for a description of capacity
margin, LOLP, LOLE, and EENS
79
The introduction of CMs fundamentally change wholesale electricity markets because
generators and other capacity providers are no longer paid only for the electricity they
generated but also for their availability. Worse however is that CMs when introduced in
an uncoordinated manner can be inefficient and distort cross-border trade on wholesale
electricity markets.
In the short-term, CMs may lead to distortions if their design affects natural price formation
in the energy market (e.g. bidding behaviour of generators) and therefore alter production
decisions (operation of power generating plants) and cross-border competition. For
instance, a possible distortion is when generators in a market applying a CM, receive
(capacity) payments which are determined in a way that affects their electricity generation
bids into the market, while in a neighbouring "energy-only" market generators do not. This
may tilt the playing field for generators on either sides of the border. Another example
might be if strategic reserves (a particular form of CMs) are dispatched 'too-early' impeding
the market's ability to establish equilibrium between supply and demand. This can cause
or contribute to a 'missing money' problem as strategic reserves would outcompete existing
(or future) generators who, at least partly, rely on scarcity rents to cover their costs.
CMs may also influence investment decisions (investment in plants and their locations),
with potential impacts in the long term. If contributions from cross-border capacity are not
appropriately taken into account, they may lead to over-procurement of capacity in
countries implementing CMs, with a detrimental impact on consumers.
CMs may also cause a number of competition concerns. In this respect, the Sector Inquiry
identifies substantial issues in relation to the design of CMs in a number of Member States.
First, many CMs do not allow all potential capacity providers or technologies to
79
See annex 5.1 for the definition of the different methodologies.
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participate, which may unnecessarily limit competition among suppliers or raise the price
paid for the capacity
80
.
Second, capacity mechanisms are also likely to lead to over-compensation of the capacity
providers
often to the benefit of the incumbents
if they are badly designed and non-
competitive. In many Member States the price paid for capacity is not determined through
a competitive process but set by the Member State or negotiated bilaterally between the
Member State and the capacity provider. This creates a serious risk of overpayment
81
.
Third, the inquiry revealed that capacity providers from other Member States (foreign
capacity) are rarely allowed to directly or indirectly participate in national CMs
82
. This
leads to market distortions as additional revenues from CMs remain reserved to national
companies. This is particularly problematic in case of dominant national incumbents
whose dominant position may even be strengthened by a national CM.
Lastly, although there is a challenge to design penalties that avoid undermining electricity
price signals which are important for demand response and imports, where obligations are
weak and penalties for non-compliance are low, there are insufficient incentives for plants
to be reliable.
All in all, the Sector Inquiry highlights that "a
patchwork of mechanisms across the EU
risks affecting cross-border trade and distorting investment signals in favour of countries
with more ‘generous’ capacity mechanisms. Nationally determined generation adequacy
targets risk resulting in the over-procurement of capacities unless imports are fully taken
into account. Capacity mechanisms may strengthen market power if they for instance, do
not allow new or alternative providers to enter the market. Capacity mechanisms are also
likely to lead to over-compensation of the capacity providers
often to the benefit of
incumbents
if they are badly designed and non-competitive."
All of these issues can
undermine the functioning of the internal energy market and increase energy costs for
consumers.
As reflected in the Sector Inquiry, the heterogeneous development of capacity mechansims
has led to fragmented markets across the EU. The Sector Inquiry highlights that "the
different types of capacity mechanisms are not equally well suited to address problems of
security of supply in the most cost effective and least distortive way".
80
81
82
In some cases, certain capacity providers are explicitly excluded from participating or the group of
potential participants is explicitly limited to certain providers. In other cases, Member States set
requirements that have the same effect, implicitly reducing the type or number of eligible capacity
providers. Examples are size requirements, environmental standards, technical performance
requirements, availability requirements, etc.
In Spain for example, the price for an interruptibility service almost halved after a competitive auction
was introduced.
For example, Portugal, Spain and Sweden appear to take no account of imports when setting the amount
of capacity to support domestically through their CMs. In Belgium, Denmark, France and Italy, expected
imports are reflected in reduced domestic demand in the CMs. The only Member States that have
allowed the direct participation of cross-border capacity in CMs are Belgium, Germany and Ireland. For
more details, see annex 5.2.
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The Sector Inquiry concludes that capacity payment schemes are generally problematic as
they risk over-compensating capacity providers because they rely on administrative price
setting rather than competitive allocation procedures. The risk for overcompensation is
lower for market-wide and volume-based schemes and strategic reserves. What matters is
the design of the support scheme, which can make it more or less distortive.
Several stakeholders have proposed to address investment uncertainty by dedicated
regulatory provisions encouraging and clarifying the use of long-term contracts ('LTC's)
between generators and suppliers or consumers
83
. They argue that such rules could help
mitigating the investment risk for the capital-intensive investments required in the
electricity sector, facilitating access to capital in particular for low-carbon technologies at
reasonable costs.
While mandatory LTCs may involve a risk transfer to consumers unless they are certain
they will have enduring future electricity demand, such contracts may allow them to benefit
from less volatile retail prices as electricity would be purchased long time ahead of
delivery. In terms of market functioning, it has to be stressed that current EU electricity
legislation does not discourage the conclusion of long-term electricity purchase contracts.
Even absent dedicated legislation, LTCs between a buyer and seller to exchange electricity
on negotiated terms, can anyway be freely agreed on by interested parties without any need
for further intervention by governments or regulators. Tradable wholesale contracts are
already available to market parties (albeit with limited liquidity for contracts of more than
three years
84
). A dedicated framework for hedging price risks over longer terms has just
been created with the EU Guideline on Forward Trading ("FCA Guidelines"). The only
regulatory restriction to the use of LTCs may result, in exceptional situations
85
, from EU
Treaty rules on competition law (e.g. if they are used by by dominant companies to prevent
new market entry).
It may also be noted that experience has shown that regulatory encouragement of LTCs
under EU law may also entail the risk of "lock-in risk" in the fast developing electricity
markets
86
.
Options suggested to facilitate long-term contracting include (i) socialising the costs of
guaranteeing delivery of bilateral contracts (to reduce the default risk) or (ii) introducing
long-term contracts with a regulated counterparty. Both models might, however, be
considered to be capacity mechanisms and would have to be scrutinised under the relevant
State aid rules.
83
84
85
86
See e.g. submissions to the Commission's market design consultation from a limited number of
generation companies and from energy-intensive industries.
See for further information,
CEPS Special Report,
The EU power sector needs long-term price signals,
No. 135/April 2016, page 9.
It should be noted that there is extensive guidance and case practice on the interpretation of Article 81
and 82 with respect to long-term energy contracts available.
The fast changing electricity markets may require different generation solutions than today (e.g. due to
new storage technology). See also the example of guaranteeing revenues for solar power producers for
timeframes ten years ago which proved to be higher than necessary in retrospective due to technological
developments.
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2.3.
Problem Area III: Member States do not take sufficient account of what
happens across their borders when preparing for and managing electricity
crisis situations
In spite of best efforts to build an integrated and resilient power system, electricity crisis
situations may occur. Whilst most incidents are minor
87
, the likelihood of larger-scale
incidents affecting the European electricity system might well be on the rise due to extreme