EUROPEAN COMMISSION

Brussels, 30.11.2016

SWD(2016) 410 final

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

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Table of contents

1.    Introduction    

1.1.    Background and scope of the market design initiative    

1.1.1.    Context of the initiative    

1.1.1.1.    The gradual process of creating an internal electricity market    

1.1.1.2.    The Union's policy concerning climate change    

1.1.1.3.    Paradigm shift in the electricity sector    

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

1.1.2.    Scope of the initiative    

1.1.2.1.    Current relevant legislative framework    

1.1.2.2.    Policy development subsequent to the Third Package    

1.1.2.3.    Scope and summary of the initiative    

1.1.3.    Organisation and timing    

1.1.3.1.    Follow up on the Third Package    

1.1.3.2.    Consultation and expertise    

1.2.    Interlinkages with parallel initiatives    

1.2.1.    The Renewable Energy Package comprising the new Renewable Energy Directive and bioenergy sustainability policy for 2030 ('RED II')    

1.2.2.    Commission guidance on regional cooperation    

1.2.3.    The Energy Union governance initiative    

1.2.4.    The Energy Efficiency legislation ('EE') and the related Energy Performance of Buildings Directive ('EPBD') including the proposals for their amendment.    

1.2.5.    The Commission Regulation establishing a Guideline on Electricity Balancing ('Balancing Guideline')    

1.2.6.    Other relevant instruments    

2.    Problem Description    

2.1.    Problem Area I: Market design not fit for an increasing share of variable decentralized generation and technological developments    

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

2.1.2.    Driver 2: Exemptions from fundamental market principles    

2.1.3.    Driver 3: Consumers do not actively engage in the market and demand response potential remains largely untapped    

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

2.2.    Problem Area II: Uncertainty about sufficient future generation investments and uncoordinated capacity markets    

2.2.1.    Driver 1: Lack of adequate investment signals due to regulatory failures and imperfections in the electricity market    

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

2.3.    Problem Area III: Member States do not take sufficient account of what happens across their borders when preparing for and managing electricity crisis situations    

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

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

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

2.4.    Problem Area IV: The slow deployment of new services, low levels of service and questionable market performance on retail markets    

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

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

2.4.3.    Driver 3: Low levels of consumer engagement    

2.5.    What is the EU dimension of the problem?    

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

2.6.1.    The projected development of the current regulatory framework    

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

2.7.    Issues identified in the evaluation of the Third Package    

3.    Subsidiarity    

3.1.    The EU's right to act    

3.2.    Why could Member States not achieve the objectives of the proposed action sufficiently by themselves?    

3.3.    Added-value of action at EU-level    

4.    Objectives    

4.1.    Objectives and sub-objectives of the present initiative    

4.2.    Consistency of objectives with other EU policies    

5.    Policy options    

5.1.    Options to address Problem Area I (Market design not fit for an increasing share of variable decentralized generation and technological developments)    

5.1.1.    Overview of the policy options    

5.1.2.    Option 0: Baseline Scenario – Current Market Arrangements    

5.1.3.    Option 0+: Non-regulatory approach    

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

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

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

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

5.1.5.    Option 2: Fully Integrated EU market    

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

5.1.7.    Summary of specific measures comprising each Option    

5.2.    Options to address Problem Area II (Uncertainty about sufficient future generation investments and uncoordinated capacity markets)    

5.2.1.    Overview of the policy options    

5.2.2.    Option 0: Baseline Scenario – Current Market Arrangements    

5.2.3.    Option 0+: Non-regulatory approach    

5.2.4.    Option 1: Improved energy market - no CMs    

5.2.5.    Option 2: Improved energy market – CMs only when needed, based on a common EU-wide adequacy assessment)    

5.2.6.    Option 3: Improved energy market - CMs only when needed, based on a common EU-wide adequacy assessment, plus cross-border participation    

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

5.2.8.    Discarded Options    

5.2.9.    Summary of specific measures comprising each Option    

5.3.    Options to address Problem Area III (When preparing or managing crisis situations, Member States tend to disregard the situation across their borders)    

5.3.1.    Overview of the policy options    

5.3.2.    Option 0: Baseline scenario – Purely national approach to electricity crises    

5.3.3.    Option 0+: Non-regulatory approach    

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

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

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

5.3.7.    Discarded Options    

5.3.8.    Summary of specific measures comprising each Option    

5.4.    Options to address Problem Area IV (Slow deployment and low levels of services and poor market performance)    

5.4.1.    Overview of the policy options    

5.4.2.    Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer engagement and poor data flows    

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

5.4.4.    Option 1: Flexible legislation addressing all problem drivers    

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

5.4.6.    Summary of specific measures comprising each Option    

6.    Assessment of the impacts of the various policy options    

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    

6.1.1.    Methodological Approach    

6.1.1.1.    Impacts Assessed    

6.1.1.2.    Modelling and use of studies    

6.1.1.3.    Summary of Main Impacts    

6.1.1.4.    Overview of Baseline (Current Market Arrangements)    

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

6.1.2.1.    Economic impacts    

6.1.2.2.    Who would be affected and how    

6.1.2.3.    Administrative impact on businesses and public authorities    

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

6.1.3.1.    Economic Impacts    

6.1.3.2.    Who would be affected and how    

6.1.3.3.    Administrative impact on businesses and public authorities    

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

6.1.4.1.    Economic Impacts    

6.1.4.2.    Who would be affected and how    

6.1.4.3.    Impact on businesses and public authorities    

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

6.1.5.1.    Economic Impacts    

6.1.5.2.    Who would be affected and how    

6.1.5.3.    Impact on businesses and public authorities    

6.1.6.    Environmental impacts of options related to Problem Area I    

6.1.7.    Summary of modelling results for Problem Area I    

6.2.    Impact Assessment for Problem Area II (Uncertainty about future generation investments and fragmented capacity mechanisms)    

6.2.1.    Methodological Approach    

6.2.1.1.    Impacts Assessed    

6.2.1.2.    Modelling    

6.2.1.3.    Overview of Baseline (Current Market Arrangements)    

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

6.2.2.1.    Economic Impacts    

6.2.2.2.    Who would be affected and how    

6.2.2.3.    Administrative impact on businesses and public authorities    

6.2.3.    Impacts of Policy Option 2 (Improved energy markets – CMs only when needed, based on a common EU-wide adequacy assessment)    

6.2.3.1.    Economic Impacts    

6.2.3.2.    Who would be affected and how    

6.2.3.3.    Impact on businesses and public authorities    

6.2.4.    Impacts of Policy Option 3 (Improved energy market – CMs only when needed, plus cross-border participation)    

6.2.4.1.    Economic Impacts    

6.2.4.2.    Who would be affected and how    

6.2.4.3.    Impact on businesses and public authorities    

6.2.5.    Environmental impacts of options related to Problem Area II    

6.2.6.    Overview of modelling results for Problem Area II    

6.2.6.1.    Improved Energy Market as a no-regret option    

6.2.6.2.    Comparison of Options 1 to 3    

6.2.6.3.    Delivering the necessary investments    

6.2.6.4.    Level and volatility of wholesale prices    

6.3.    Impact Assessment for problem Area III (reinforce coordination between Member States for preventing and managing crisis situations)    

6.3.1.    Methodological Approach    

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

6.3.2.1.    Economic impacts    

6.3.2.2.    Who would be affected and how    

6.3.2.3.    Impact on businesses and public authorities    

6.3.3.    Impacts of Policy Option 2 (Common minimum rules to be implemented by Member States plus regional co-operation)    

6.3.3.1.    Economic impacts    

6.3.3.2.    Who would be affected and how    

6.3.3.3.    Impact on businesses and public authorities    

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

6.3.4.1.    Economic impacts    

6.3.4.2.    Who would be affected and how    

6.3.4.3.    Impact on businesses and public authorities    

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

6.4.1.    Methodological Approach    

6.4.2.    Impacts of Policy Option 0+ (Non-regulatory approach to improving competition and consumer engagement)    

6.4.2.1.    Economic Impacts    

6.4.2.2.    Who would be affected and how    

6.4.2.3.    Impact on businesses and public authorities    

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

6.4.3.1.    Economic Impacts    

6.4.3.2.    Who would be affected and how    

6.4.3.3.    Impact on businesses and public authorities    

6.4.4.    Impacts of Policy Option 2 (Harmonization and extensive safeguards for consumers addressing all problem drivers)    

6.4.4.1.    Economic Impacts    

6.4.4.2.    Who would be affected and how    

6.4.4.3.    Impact on businesses and public authorities    

6.4.5.    Environmental impacts    

6.4.6.    Impacts on fundamental rights regarding data protection    

6.5.    Social impacts    

7.    Comparison of the options    

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    

7.2.    Comparison of Options for facilitating investments in the right amount and in the right type of resources for the EU    

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    

7.4.    Comparison of options for addressing the causes and symptoms of weak competition in the energy retail market    

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

7.5.1.    Synergies    

7.5.2.    Trade-offs    

7.5.3.    Sequencing of measures    

8.    Monitoring and evaluation    

8.1.    Future monitoring and evaluation plan    

8.2.    Annual reporting by ACER and evaluation by the Commission    

8.2.1.    Annual reporting by ACER    

8.2.2.    Evaluation by the Commission    

8.3.    Monitoring by the Electricity Coordination Group    

8.4.    Operational objectives    

8.5.    Monitoring indicators and benchmarks    

9.    Glossary and Acronyms    

1.Introduction

1.1.Background and scope of the market design initiative

1.1.1.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 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 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 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 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 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 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.

… 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.

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.

1.1.2.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 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 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.

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 .

1.1.3.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 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:

1.2.1.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.

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.

1.2.2.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).

1.2.3.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.

1.2.4.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.

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.

1.2.5.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 initiatives are fully coherent. Indeed, the implementation of the guidelines on electricity balancing is part of the baseline for the present impact assessment 38 .

1.2.6.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.Problem Description

2.1.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 .

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.

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 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.

2.1.1.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 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 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.

2.1.2.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.

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.

2.1.3.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.

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)

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.

Figure 2: Theoretical potential of demand response per appliance

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 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:

-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.

Table 3: Participation of explicit Demand Response in different markets

Source: Impact Assessment support Study on downstream flexibility, demand response and smart metering, COWI, 2016

2.1.4.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 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.

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 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 .

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 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.

2.2.1.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 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 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 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.

2.2.2.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

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 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.

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 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".

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.

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 weather conditions 88 , climate change (giving rise to extreme and unpredictable weather conditions, which already today constitute a major challenge to electricity systems) 89 , fuel shortage 90 and a growing exposure to cybercrime and terrorist attacks in Europe. Already in 2014 a series of cyberattacks by the so-called "Energetic Bear" targeted several energy companies in Europe and US, highlighting the increasing vulnerability of the energy sector 91 .

Where crisis situations occur, they often have a cross-border effect. Even where incidents start locally, they may rapidly proliferate across borders. Thus, a black-out in Italy in 2003 due to a tree flashover affected the electricity systems of its neighbouring states as well, and in 2006 the tripping of an electricity line by a cruise ship in Germany affected 15 million people and had an impact on the entire continental power system 92 .

Crisis situations may also affect several Member States at the same time as it was the case during the prolonged cold spell in February 2012 93 , which led to a series of uncoordinated emergency measures across Europe. Given the increasing interconnectivity of the EU's electricity systems and linkage of electricity markets, the risk of electricity crisis situations simultaneously affecting several Member States are set to further rise 94 .

It should be noted that risks of cross-border electricity incidents do not stop at the European Union's borders, given increasing links between the electricity systems of EU Member States and those of some of its neighbours (e.g., synchronisation with Western Balkans, common infrastructure projects between e.g., Italy-Montenegro, Romania-Moldova, Poland-Ukraine).

Given the key role of electricity to society, electricity crisis situations entail serious costs – both economically and for the society at large 95 .

Both when preparing for and dealing with crisis situations, Member States take very different approaches and tend to focus on their national territories and customers only, ignoring the possible assistance of and the impact on neighbouring countries and customers. This entails serious risks for security of supply and can also lead to undue interferences with the internal energy market.

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

First, whilst most Member States have plans to prevent and deal with electricity crisis situations, the content and scope of these plans varies considerably and plans tend to focus on the national situation only 96 . Cross-border cooperation in the planning phase is scarce and where it takes place at all, it is often limited to cooperation at the level of TSOs 97 . This is largely due to a regulatory failure: the existing EU legal framework does not prescribe a common approach, and rules and structures for cross-border co-operation are almost entirely absent 98 . Cross-border cooperation is also hindered by divergent national rules. Cooperation with Member States outside the EU is even more limited.

Further, where crisis situations do arise, Member States also tend to react on the basis of their own national set of rules, and without taking much account of the cross-border context. Evidence shows, for instance, that Member States have different concepts of what an emergency situation is and entails 99 , and who should do what and when in such situations. In particular, there is considerable uncertainty and divergence as regards what public authorities can do in emergency situations 100 . 

The fact that Member States tend to adopt national, 'going alone' approaches when preparing for and managing crisis situations stands in strong contrast with the reality of today's interconnected electricity market, where the likelihood of crisis situations affecting several Member States at the same time, is on the rise.

Where crisis situations stretch across borders (or have the potential of doing so), joint action is needed, as well as clear rules on who does what, and when, in a cross-border context. Uncoordinated actions and decisions in one Member State (for instance on what to do to prevent a further deterioration of a crisis situations or on where to shed load, when and to whom), can have serious negative effects:

For instance, as to date, several Member States still legally foresee 'export bans' (curtailing interconnectors) in times of crisis 101 . This undermines the proper functioning of markets and can seriously aggravate security of supply problems in neigbouring Member States, who might no longer be able to ensure that electricity is delivered to those that need it most. The reverse situation is also true: where in a crisis situation an interconnected state does not restrict its own electricity consumption, it risks propagating the crisis situation beyond its own borders.

The dangers related to a purely national, inward-looking management of electricity crisis situations, are illustrated by an incident that occurred during a prolonged cold spell in February 2012 102 . Confronted with a situation of unexpected shortage, one Member State decided to resort to an export ban in an effort to protect its national consumption. This aggravated however problems in other, neighbouring Member States, who in turn also resorted to export bans. The ensuring cascade of export bans seriously imperiled security of supply in an entire region of Europe 103 .

Purely national approaches to crisis prevention and management can also lead to premature (and therefore unnecessary) market interventions, such as for instance a premature recourse to an emergency extra reserve capacity, or to a demand interruption scheme.

Finally, different approaches to crisis prevention and management might also lead to cases of 'under-protection. For instance, where Member States do not take the measures needed to prevent (e.g., cyber-incidents), the entire region or even synchronous area is likely to suffer. A similar problem might arise if Member States do not take the measures necessary to protect assets that are critical from a security of supply perspective against possible take-overs by foreign entities, in circumstances in which such take-overs could lead to any undue political influence. Experience with recent take-overs (or planned take-overs) of certain strategic energy assets in Europe shows that such risks are serious, notably where the buyer is controlled by a third country. At this stage however, Member States address this issue from a purely national perspective, based on national rules, 104 without taking necessarily account of the wider European implications possible problems could have. This could lead to situations wherein some Member States take foreign ownership risks too lightly, whilst other Member States might overreact. 105  

Evidence shows that in an inter-connected market, stronger co-operation on how to prevent and manage crisis situations brings clear benefits: it leads to a better security of supply overall, at a lesser cost. The recent METIS results 106 point in this direction, as well as experiences with a few voluntary arrangements in place in parts of Europe 107 .

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

Today, national plans to prepare for crisis situations are not always public, nor shared across Member States 108 . It is not clear who will act in crisis situations, and what the roles are of the different actors (governments, TSOs, DSOs, NRAs). This makes any cross-border co-operation in times of crisis very difficult 109 .

In addition, Member States do not systematically inform each other or the Commission when they see crisis situations emerge. In fact, whilst ENTSO-E's seasonal outlooks 110 already point at the likelihood of upcoming crisis situations in Europe, Member States affected by such crisis situations do not systematically communicate on actions they intend to take, nor on the possible effect of such actions on the functioning of the internal market or the electricity situation in neighbouring Member States. In fact, in spite of the fact that Member States are legally obliged to notify the Commission in case they take 'safeguard measures', such notifications have been very rare, and tend to take place ex post (e.g., Poland in 2015) 111 .

Likewise, there is no systematic exchange of information on how past crisis situations have been handled.

Such lack of information-sharing and transparency limits the capacity of reaction of potential Member States affected, may lead to premature interventions in the market, and reduces the possible benefits that cooperation can bring.

In addition, even though the Electricity Coordination Group could be used as a tool to discuss how to prevent and mitigate crisis situations 112 , this does not happen in practice, in the absence of clear and proper roles given to the group, and clear obligations on Member States to report on how they address electricity crisis situations, both ex ante (before incidents occur) and ex post.

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

Whilst all Member States identify and assess risks that can affect security of supply, there are many different understandings of what constitutes a 'risk' and methods for assessing and addressing such risks vary considerably.

Different risks are assessed in different ways 113 , by different people 114 , and in different time horizons 115 .

There is also no common agreement on what indicators to use to assess security of supply overall 116 .

In the absence of a common approach to risk identification and assessment, it is difficult to get an exact picture of what risks are likely to occur, in a cross-border context. This, in turn, seriously hampers the possibility for relevant actors – TSOs, NRAs, Member States – to prevent and manage crisis situations in a cross-border context.

2.4.Problem Area IV: The slow deployment of new services, low levels of service and questionable market performance on retail markets

Retail markets for energy in most parts of the EU suffer from persistently low levels of competition and consumer engagement. In addition, whilst information technology now offers the possibility of greatly improving the consumer experience and making the market more contestable, realising these benefits could be hampered by the lack of a data-management framework that unlocks the full benefits of smart energy management to all market actors – incumbents and new entrants alike.

These closely inter-related issues result in the slow deployment of innovative products that would help to make the electricity system function better in today's changing context, as well as excessive prices for some end-consumers and/or poor levels of service.

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

Competition on retail markets is multifaceted, and recent trends in several indicators suggest that it can be improved in many Member States.

The price of energy for end consumer can be broken down into three main components: i) energy, ii) network and iii) taxes and levies. The energy component typically includes cost elements such as the wholesale price of the commodity and various costs of the supply companies, including their operating costs and profit margins. The network component mainly consists of transmission and distribution tariffs. It might also include further cost elements such as ancillary services. The taxes & levies component includes a wide range of cost elements that significantly vary from country to country. Levies are typically designated to specific technology, market or socially bound policies, while taxes are general fiscal instruments feeding into the state budget. On average in the EU in 2015 energy made up 36% of the final household consumer price, the network component 26%, and taxes and levies 38%.

In spite of falling prices on wholesale markets (analysed earlier), overall electricity prices for household consumers rose steadily between 2008 and 2015 at an annual rate of around 3%. This trend was largely driven by increased network charges, taxes and levies 118 , the various causes of which have been touched upon in the preceeding sections: the over reliance of RES E assets on government support due to barriers to fully participating in all markets; inflexible distribution networks that increase the cost of integrating RES E; and fragmented balancing markets that increase the costs of ancillary services, amongst others.

However, a proxy for mark-ups 119 on the energy component of consumer bills in several Member States also seem to be higher than could be expected, posing questions about the extent of price competition. Indeed, whereas there has been a significant reduction in wholesale prices between 2008 and 2015, the nominal level of the energy component of household electricity bills actually increased in 13 Member States during this period 120 . In these countries, the fall in wholesale prices has not translated into a reduction in the energy component of retail prices despite the fact that this is the part of the energy bill (representing around 36% of average household prices) where energy suppliers should be able to compete.

Figure 5: Relationship between the wholesale price and the energy component of the retail price in household segments in countries with non-regulated retail prices from 2008 to 2014 for electricity and from 2012 to 2014 in gas (EUR/MWh) 

Source: ACER Database, Eurostat, NRAs and European power exchanges data (2014) and ACER calculations. Note: Gas data are available only for the period 2012-2014.

Abnormally low mark-ups are equally problematic as they make it difficult or impossible for a new supplier to compete against an incumbent. A reasonable mark-up is necessary for a new entrant to cover consumer acquisition and retention costs which are higher than those of the incumbent who usually retains the most loyal (‘sticky’) customers. Mark-ups that are too low and low levels of competition can be observed in several markets with regulated prices (developed further on the next page) 121 .

As for non-price competition, whilst sampling data from European capitals suggest that 'choice' for consumers in European capitals widened in recent years, a closer inspection reveals that this has largely been driven by just two products – 'green' and dual-fuel (electricity + gas) tariffs 122 . The offer and uptake of other, more innovative consumer products, such as aggregation services or dynamic price tariffs linked to wholesale markets 123 , remains limited.

Facilitating competition can be seen as means of improving consumer satisfaction. However, the data indicate that there is clearly scope for improvement in this dimension, too. According to the 2016 edition of the Commission's Consumer Scoreboard – a comprehensive study measuring consumer conditions – electricity services rank 26th and gas services 14th among the 29 markets for services across the EU. Indeed, the total detriment to EU electricity consumers 124 has recently been quantified at over EUR 5 billion annually 125 . Both markets can therefore be considered low performing from the consumer standpoint.

High levels of market concentration also suggest that competition could be improved: The cumulative market share of the three largest household suppliers (CR3) is greater than 70% in 21 out of 28 Member States for electricity and in 20 out of 28 Member States for gas. CR3 values above 70% are indicative of possible competition problems.

Also significant is the fact that some form of non-targeted price regulation for electricity and/or gas still exists in 17 out of 28 Member States 126 . The regulation of electricity and gas prices may result in an environment that strongly impairs healthy competition, particularly in terms of the level of customer service, or the development and provision of innovative new services that consumers would be willing to pay extra for. Reliance on the government to set prices can result in consumer disengagement. In addition, regulatory intervention in price setting can have a direct impact on suppliers' ability to offer products that are differentiated in terms of pricing-related aspects – dynamic price tariffs that reflect the minute-by-minute fluctuations on wholesale markets, for example.

When justifying price regulation Member States cite the need to protect the vulnerable and energy poor along with the need to protect all customers against the risk of market abuse. Around 10.2% of the EU population might be affected by the problem of energy poverty, based on a proxy indicator measuring "the inability to keep home adequately warm" 127 . If energy prices continue to increase, it is likely that energy poverty across the EU will increase and therefore more pressure to maintain energy price regulation.

Under the existing provisions in the Electricity and Gas Directive, Member States have to address energy poverty where identified. The evaluation of the provisions found important shortcomings stemming from the unclarity of the term energy poverty, particularly in relation to consumer vulnerability, and the lack of transparency with regards to the number of households suffering from energy poverty across Member States.

Addressing the issue of energy poverty through blanket price regulation can be disproportionate as it affects all consumers big or small, rich or poor. It can also lead to a chicken-and-egg problem whereby price regulation leads to distortions to the market and low competition, which are in turn used to justify the continuation of price regulation. Resolving this impasse would allow one of the most fundamental aspects of the market – the price mechanism – to function properly.

ACER's Retail Competition Index – a composite indicator that draws upon many of the abovementioned statistics, as well as others 128 – was developed to achieve a full picture of retail market competitiveness which is not dependent on a single indicator. It illustrates the disparities in retail markets that still exist between Member States, and clearly suggests that competition can be improved in a number of them (see Graph 3).

Figure 6: ACER Retail Competition Index (ARCI) for electricity household markets in 2014

Source: ACER

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

High levels of information asymmetry (between incumbents and potential entrants) and high transaction costs impede competition and the provision of high levels of service on retail markets for energy.

For example, studies from NRAs cite discriminatory access to information on potential customers as a key barrier for new entrants to EU retail energy markets ( Box 1   below ). As most DSOs are also energy suppliers, safeguards are necessary to prevent them using privileged access to consumer data – especially smart metering data – to gain a competitive advantage in their supply operations.

In addition, "unjustified" or "incorrect" invoices are one of the largest sources of electricity and gas consumer complaints reported to the Commission 129 – an issue that can be largely resolved if accurate metering information were made quickly and readily available to suppliers and consumers.

Information technology could directly address these issues, making the market more contestable, facilitating the development of new services and improving the customer experience around day-to-day operations such as billing and switching. Although 80% of EU consumers should have smart meters by 2020, the experience from Member States that have already rolled them out indicates that robust rules are necessary to ensure the full benefits of smart metering data are realised, and that data privacy is respected. Such rules, however, are not fully developed in the existing EU legislation, and the diverse interests of market actors who may be involved in data handling mean that they are unlikely to emerge without regulatory intervention.

Box 1: Data management as a market entry barrier 130

2.4.3.Driver 3: Low levels of consumer engagement

Consumer engagement is essential for the proper functioning of the market. As such, it is closely inter related with competition (Driver 1). However, consumers are also put-off from engaging in the market by behavioural biases and bounded rationality that make it harder for them to take the decision to search for, and to switch to, the best offer.

In particular, three key barriers to consumer engagement have been identified. First, the broad variety of fees that consumers may be charged when they switch diminishes the (perceived) financial gains of moving to a cheaper tariff in what is already a marginal decision for many consumers. The evidence suggests around 20% of electricity consumers in the EU currently face a fee of between EUR 5 and EUR 90 associated with switching suppliers. A portion of those fees – affecting around 4% of consumers – may be illegal under existing EU legislation (see Section 2.6.2).

Secondly, whereas online comparison websites play an important role in helping consumers to make an informed decision about switching suppliers, recent reports of unscrupulous practices have damaged consumer trust in them. Identified issues include the default presentation of deals by some websites, the use of misleading language, and a lack of transparency about commission arrangements. Indeed, a third of respondents to a recent EU survey somewhat or strongly agreed that they did not trust comparison websites because they were not impartial and independenct. 131

And thirdly, consumer groups report that consumers have difficulties understanding their energy bills and comparing offers in spite of existing EU legislation aiming to facilitate this. There is a broad divergence in national requirements around billing and consumer satisfaction with their bills varies significantly between different Member States. Whereas energy bills are the foremost means through which suppliers communicate with their customers, consumers' inability to correctly answer simple questions about their own electricity use reveals that bills are not effective in providing information that could facilitate effective consumer choice. 132 Addressing this will be increasingly important with the shift to more varied consumer products.

2.5.What is the EU dimension of the problem?

The EU's electricity market is strongly integrated physically, economically and from a regulatory point of view. The discretion of Member States to act individually has been substantially reduced by the resulting interdependencies and, in fact, can create significant externalities if not adequately framed within an EU-wide context.

RES E deployment is expected to increase in all Member States. The need to spur the emergence of a more flexible electricity system thus exists EU-wide. Moreover, as the EU electricity system is both physically and economically integrated, non-coordinated action is likely to increase the costs of RES E integration.

The same applies to CMs where the externalities of non-coordinated action are one of the underlying reasons for the proposed measures. It is true that not all Member States have enacted CMs, however the benefits of a more coordinated approach will benefit all Member States. Member States that have implemented a CM will be able to lower their costs by increased cross-border competition whereas the avoidance of negative spill-over effects will benefit all Member States regardless as to whether they enacted a CM or not.

In an integrated electricity market, considering the prevention and management of electricity crisis a purely national issue leads to serious problems. Where crisis situations occur, they often have a cross-border effect, and can entail serious adverse consequences for the EU as a whole. Evidence shows that non-coordinated approaches to preventing and managing electricity crisis may seriously distort the internal electricity market and put at risk the security of supply of neighbouring Member States.

Well designed and implemented consumer policies with a European dimension can enable consumers to make informed choices that reward them through healthy competition, and support the European goal of sustainable and resource-efficient growth, whilst taking account of the needs of all consumers. Increasing confidence and ensuring that unfair trading practices do not bring a competitive advantage will also have a positive impact in terms of stimulating growth. The consumer-related measures undertaken as part of this initiative therefore play an essential role in the establishment and functioning of the internal market.

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

2.6.1.The projected development of the current regulatory framework

In the absence of additional measures, the electricity market would continue to be governed by the Third Package and the Electricity Security of Supply Directive. Various network codes may still be adopted and implemented 133 , such as the draft Network Code on Emergency and Restoration and the Balancing Guideline. Whilst these network codes will help address some of the issues identified above, they will not offer a sufficient remedy on their own.

Solving the above-identified problems requires measures that cannot be addressed in the current legal framework. As the network codes constitute secondary implementing legislation designed to amend non-essential elements of the Third Package by supplementing it, their scope is confined to the same limits drawn by the Third Package and hence, developing new network codes cannot be expected to provide for adequate solutions either.

In view of the fact that the proposals in essence develop new areas for which currently no clear legal basis exist in the Third Package or in the Electricity Security of Supply Directive, stronger enforcement is not an option either (with some limited exceptions, which are further developed below).

Member States have developed forms of voluntary collaboration that attempt to address some of the problems identified. However, these initiatives cannot be expected to resolve all problems and with the same effectiveness as EU action (See also EU value added).

Regarding security of supply in particular, both the evaluation and the results of the public consultation clearly show that Directive 2009/89 is outdated. It does not take account of the current, fast evolving situation of the electricity market. And it offers no framework for coordinating national policies in the area of security of electricity supply.

With regards to consumer issues, the Commission may develop guidance to tackle implementation issues caused by difficulties in interpreting the existing legislation. In particular, it may issue an interpretative note on the existing provisions in the Electricity and Gas Directives covering switching-related fees, as well as further guidance on how the dozen or so consumer Directives relevant to comparison tools should be applied.

On energy poverty, the Commission will already set up the EU Energy Poverty Observatory using funds already secured from the European Parliament. However, the extent to which the Observatory continues to share good practices and improve data gathering is uncertain, as continued funding is not secured beyond the first year of operation. Moreover, the impact of this measure may be limited as the current legislation does not require Member States to measure energy poverty and hence to address it.

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

Both this and the impact assessment for the parallel RED II initiative come to the conclusion that the electricity market, provided that it is improved, together with projected CO2 prices, may deliver investments in most mature low-carbon technologies such as solar PV and onshore wind by 2030. However, in the absence of a market optimised for increasing levels of renewable penetration, achieving the 2030 objectives will only be possible at significantly higher costs.

In the absence of a better defined framework for government interventions, the current trend of non-coordinated implementation of national resource adequacy measures risks proliferating, undermining the efficiency of the market to deliver efficient production and investment decisions and defragmenting its regulatory framework.

In fact, in the absence of measures that will improve investment incentives and efficient market functioning, it is likely that more Member States will have to take recourse to means other than the market to secure sufficient investments for resource adequacy purposes, setting in motion a negative spiral in which government interventions increase the need for the subsequent one.

Failing to integrate all participants in the market means that their decisions will not be guided by market signals, entailing the risks that their investment and production decisions will be sub-optimal from a welfare perspective, if not distort markets.

In addition, in the absence of a clear framework for co-ordinated action between Member States when it comes to preventing and managing crisis situations, the EU's electricity system risks being increasingly exposed to risks of serious incidents, without the EU or its Member States having any means to properly tackle them. There is a real risk that Member States will continue to do as they see fit in crisis situations, thus undermining the proper functioning of the internal electricity market.

Regarding active consumer engagement, Member States have committed to deploying smart meters to around two thirds of the population while access to innovative services such as demand response or in the area of self generation remains limited in many Member States. Individual action by Member States would perpetuate current differences in the Union regarding consumer awareness, choice and access to dynamic prices, demand response and integrated smart services. Consumer-friendly functionalities would be taken up partially and the flexibility consumers can provide to the electricty system would remain largely untapped.

With regards to consumer protection and engagement, enforcement could help diminish the illegal switching-related costs currently faced by an estimated 4% of all EU electricity consumers. And some Member States may also voluntarily cease or reduce excessive regulatory interventions in price-setting as their retail markets mature. However, shortcomings in the existing legislation will greatly limit the Commission's ability to tackle these and other consumer-related problem drivers more effectively.

The issue of energy poverty is likely to remain relevant. Pressure on energy prices may continue as a result of the efforts to decarbonise the energy system. If energy prices grow faster than household income, more and more households will find it difficult to pay their energy bills. This may have a knock-on effect on Member States willingness to lift price regulation which will ultimately impact suppliers' ability to innovate, competition and consumer welfare. Thus, the greater the importance of enhanced transparency to estimate the number of energy poor households.

And whilst many Member States may seek to ensure the neutral, expedient, and secure management of consumer data, it is highly likely that national requirements will vary significantly, leading to an uneven playing field for new suppliers and energy service companies in the EU. Here, the only credible approach to effectively tackling the potential conflicts of interest among market actors is a legislative one.

2.7.Issues identified in the evaluation of the Third Package

A retrospective evaluation was carried out in parallel with the present impact assessment and has been added as Annex VI. Its main conclusions are:

-That the initiative of the Third Package to further increase competition and to remove obstacles to cross-border competition in electricity markets has generally been effective and that active enforcement of the legislation has led to positive results for electricity markets and consumers. Markets are in general less concentrated and more integrated than in 2009. As regards retail markets, the set of new consumer rights introduced by the Third Energy Package have clearly improved the position of consumer in energy markets.

-However, the success of the rules of the Third Package in developing the internal electricity market further to the benefit of customers remains limited in a number of fields concerning wholesale and retail electricity markets.

-Moreover, while the principles of the Third Package achieved its main purposes (e.g. more supplier competition), new developments in electricity markets such as the increase of RES E, the increase of state interventions into the electricity markets and the changes taking place on the technological side have led to significant changes in the market functioning in the last five years and have dampened the positive effect of the reforms for customers. There is a gap in the existing legislation regarding how to deal with these developments.

The conclusions of the evalution are also reflected in section 3 of each of the Annexes 1.1 throught to 7.6 to the present impact assessment.

3.Subsidiarity

3.1.The EU's right to act

In order to create an internal energy market, the EU has adopted three consecutive packages of measures between 1996 and 2009 aiming at the integration and liberalisation of the national electricity and gas markets and addressing a wide range of elements such as market access, the improvement of the level playing field, transparency, increased rights for consumers, stronger independence of regulatory authorities, etc. In February 2011, the European Council set the objective of completing the internal energy market by 2014 and of developing interconnections to put an end to any isolation of Member States from the European gas and electricity grids by 2015. In June 2016, the European Council called for Single Market strategies, including on energy, and action plans to be proposed by the Commission and to be completed and implemented by 2018.

Article 194 of the Treaty on the Functioning of the European Union ('TFEU') consolidated and clarified the competences of the EU in the field of energy. According to Article 194 TFEU, the main aims of the EU’s energy policy are to: ensure the functioning of the energy market; ensure security of energy supply in the Union; promote energy efficiency and energy saving and the development of new and renewable forms of energy; and promote the interconnection of energy networks.

The planned measures of the present intiative further progress towards the objective of improving the conditions for competition by improving the level playing field, while at the same time adjusting to the decarbonisation targets and enhancing the solidarity between Member States in relation to security of supply.

Therefore, Article 194 TFEU is the legal basis of the current proposal.

3.2.Why could Member States not achieve the objectives of the proposed action sufficiently by themselves?

The section below provides a high-level summary of the necessity of EU action, based on the four problem areas identified in section 2.

The issue of subsidiarity is also discussed in section 6 of Annexes 1.1 to 7.6 to the present impact assessment.

As regards the issue concerning a market design that is not fit for taking up large amounts of variable, decentralised electricity generation and allowing for new technical developments, it is important to note that EU action is necessary to ensure that national markets are comparable in order to improve the functioning of the internal electricity market and enable maximum cross-border trading to happen. EU-action is also necessary in order to enhance the transparency in the functioning of the electricity markets and avoid discrimination between market parties. Moreover, a number of the measures proposed to address this issue (e.g., measures for the common sizing and procurement of balancing reserves) require full cooperation of neighbouring TSOs and NRAs, and hence individual Member States might not be able to deliver a workable system or might only provide suboptimal solutions. Moreover, existing provisions under the Third Package are arguably not sufficiently clear and robust and their implementation of such rules has highlighted areas with room for improvement and hence EU action will be necessary to address the identified shortcomings.

With specific respect to DSOs, distribution grids will have to integrate even greater amounts of RES E generation in the future, and so ensuring all DSOs can efficiently manage their networks will help to reduce distribution costs and thereby support the achievement of EU RES targets. In addition, widely divergent distribution tariff regimes may affect the development of the internal energy market as they affect the conditions under which RES E generation or other resources can access the grid and participate in the national and cross-border energy markets. EU action in these areas would thereby facilitate the deployment of RES E and create a level playing field for flexibility services such as demand response by ensuring a coherent approach by Member States based on common principles. Developing this through independent Member State action would not be feasible given the heterogeneity of current national networks and regulations.

Concerning the uncertainty about future investments in generation capacity and uncoordinated government interventions, the measures in the proposed initiative aim at improving the functioning of the electricity markets and at improving the coordination between Member States for capacity mechanisms. The necessity of EU action derives from the fact that as regards the measures for improving the functioning of the electricity markets, these are already covered by EU legislation, although not sufficiently clearly, and therefore an amendment to such measures to address the distortions and deficiencies identified would require EU action. For the measures concerning the improvement of the coordination between Member States for capacity mechanisms, given that the aim is to address the shortcomings identified from resource adequacy assessments carried out at national level and to develop the cross-border participation in capacity mechanisms, the EU is best placed to provide for a harmonised framework.

In relation to the problem that Member States do not take into account of what happens across their borders when preparing for and managing electricity crisis situations, the necessity of EU action is based on the evidence that uncoordinated national approaches not only lead to the adoption of suboptimal measures but that they also make the impacts of a crisis more accute. Given the interdependency between the electricity systems of Member States, the risk of a blackout is not confined to national boundaries and could directly or indirectly affect several Member States. Therefore, the actions concerning preparedness and mitigation of crisis situations cannot be defined only nationally, given the potential impact on the level of security of supply of a neighboring Member State and/or on the availability of measures to tackle scarcity situations.

Regarding the slow deployment of new services, low quality of services and increasing mark-ups on retail markets, there is a clear need for EU action to ensure convergence of national rules, which is a precondition for the development of cross-border activity in the retail markets. Moreover, national regulations have in some instances led to distortions, weakening the internal energy market. Such distortions can be observed in relation to the protection of vulnerable and energy poor consumers which is a policy area characterised by a great variety in types of public internvention across Member States, both in terms of the definitions used and in terms of the levels of protection established. In that case EU action is justified not only to ensure customer protection and enhanced transparency but also to improve the functioning of the internal market through a more cohesive approach across all markets.

3.3.Added-value of action at EU-level

The initiative aims at amending existing EU legislation and at creating new frameworks for cross-border cooperation, which can legally and practically only be achieved at the European level.

National policy interventions in the electricity sector have direct impact on neighbouring Member States. This even more than in the past as the increasing cross-border trade, the spread of decentralised generation and more enhanced consumer participation increases spill-over effects. No state can effectively act alone and the externalities of unilateral action have become more important.

To illustrate, uncoordinated national policies for distribution tariffs may distort the internal market for distributed resources such as distributed generation or storage, as such resources will increasingly participate in energy markets and provide ancillary services to the system, including across borders. Furthermore, the lack of appropriate incentives for DSOs may slow down the integration of RES E, and the uptake of innovative technologies and energy services. EU action therefore has significant added value by ensuring a coherent approach in all Member States.

It is true that certain Member States collaborate on a voluntarily basis in order to address certain of the identified problems (e.g. Pentalateral Energy Forum –PLEF-, CEEE). However, these fora are characterised by different levels of ambition and effectiveness and are held-back by the fact that no means exist to enforce agreements on market design related arrangements. Moreover, even if one would presume that they would be fully effective in these regards, they geographically cover only part of the EU electricity market.

It should be added that clear synergies exist between the present initiative and other EU policy objectives, notably the EU's climate policies and other policy objectives in the energy field. Indeed, a well-functioning market is the base upon which the ETS can most efficiently deliver its goals and will permit a cost effective integration of RES E in the EU's electricity markets.

Consequently, the objectives of this initiative cannot be achieved only by Member States themselves and this is where action at EU-level provides an added value.

4.Objectives

4.1.Objectives and sub-objectives of the present initiative

4.2.Consistency of objectives with other EU policies

The consistency of the present initiative with various parallel initiatives in the energy policy area was already explored in section 1.2.

The ETS constitutes a cornerstone of the European Union's policy to combat climate change and its key tool for reducing industrial and electricity sector greenhouse gas emissions cost-effectively. To achieve the at least 40% greenhouse gas emission reduction target, the sectors covered by the ETS, which includes electricity generation, have to reduce their emissions by 43% compared to 2005. The ETS interacts with the electricity markets as it places a price on emissions of CO2, which is proportional to the emissions' intensity of electricity production. This can be taken into account for both operational decisions as well as for investment decisions, in which price expectations for the future will also play a larger role due to the long-term nature of investments in the electricity sector. (By contrast, decommissioning decisions may be primarily driven by short-term considerations relating primarily to operational costs and revenues). The ETS thus functions by affecting production and investment decision of electricity market actors 134 . It follows that an ETS can only function if its is complemented by an efficient electricity market is. The objectives of the ETS and the present proposals are hence complementary to one another and mutually reinforcing.

The Effort Sharing Decision establishes binding annual greenhouse gas emissions for Member States for the period 2013-2020 in sectors not covered by the ETS and forms part of the climate and energy package. As part of the 2030 climate and energy framework, a similar binding emission reduction framework is proposed for the period 2021-2030. Reducing greenhouse gas emissions by 30% in effort sharing sectors below 2005 levels can have an indirect impact on the projection for the demand of electricity in 2030 and this has been taken into account in the Impact Assessment by using the EUCO27 scenario in the baseline against which the impacts of the present initiative is being assessed.

The Communication on the decarbonisation of transport in 2030 aims at setting out a strategy covering several legislative and non-regulatory initiatives covering the transport sector which will be subsequently proposed to contribute to meeting the agreed 2030 greenhouse gas reduction targets. The decarbonisation of transport in 2030 has an impact on the projection for the demand of electricity in 2030, primarily via the electrification of transport, and this has been taken into account in the Impact Assessment by using the EUCO27 scenario in the baseline against which the impacts of the present initiative is being assessed. The efficient integration of electric vehicles into the electricity system requires incentivising their charging to take place at times of low electricity demand and/or high supply. The present initiative aims at enabling and rewarding consumers to manage their consumption, including when charging their electric vehicles, actively via demand response thus enabling smart charging. In essence, electric vehicles will thus become part of the supply of flexibility to the electricity system.

EU's competition instruments and, in particular, the EU state aid rules are applicable to the energy sector. They have been clarified in the Guidelines on State aid for environmental protection and energy 2014-2020 135 . These EEAG aim at supporting Member States in reaching their 2020 targets while addressing the market distortions that may result from subsidies granted to RES. To this end, the EEAG promote a gradual move to market-based support for RES E. They also include provisions on aid to energy infrastructure and rules on aid to secure adequate electricity capacity, allowing Member States to introduce CMs when there is a real risk of insufficient electricity generation capacity. The objectives and the rules of the EEAG are set to avoid undue competition distortions from national support provided in the energy sector. The proposed initiative to strenghten efficient, integrated and functioning electricity markets is complementary to this framework.

The existing EEAG already go a considerable way in guiding CMs. The present initiaitve intends to complement this framework. For instance:

-The EEAG require that state intervention in support of resource adequacy must be necessary. The MDI impact assessment 136 thus explores options for creating a robust framework for assessing the EU's adequacy situation which could give a good sense how much intermittent renewables can contribute to security of supply or to what extent Member States can rely on supplies from their neighbours. Today, Member States introduce capacity mechanisms based on national reports which assess these factors very differently and underestimate the contribution of RES E or foreign supplies to a Member States' security of supply. Therefore a genuine and high quality assessment which will help assessing real needs and question unfounded national claims.

-The EEAG already require that national capacity markets are open to foreign resources. However, organising effective foreign participation in national mechanism requires active contributions of several parties. The MDI impact assessment 137 explores options for defining clear roles and responsibilities to capacity providers, transmission system operators and regulators so that foreign participation becomes effective and that investment incentives are not distorted across the borders.

The proposed changes on the new performance based remuneration framework for DSOs would also support the Digital Single Market Strategy in the sense that those would provide further incentives to enable cross sector synergies in electronic communication infrastructure deployment allowing win win solutions for the cost efficient and timely smartening of grids and high speed connectivity for EU citizens, also decreasing the digital divide and providing the backbone for digital products and services which have the potential to support all aspects of the lives of EU citizens, and drive Europe's economic recovery. The proposed measures would complement from the energy regulatory side the measures already introduced with Directive 2014/61/EU which aims at reducing the cost of high speed broadband infrastructure deployment partly via cross sector synergies.

The proposed measures do in general have no interaction with the fundamental rights laid down in the Charter of Fundamental Rights, with the exception of the processing of personal data and improvement of consumer protection. These elements are discussed in more detail in section 6.4.6, Annex 7.1 and Annex 7.3.

The New Skills Agenda for Europe focuses on skills as an elevator to people's employability and prosperity, in line with the objective of a "social triple-A" for Europe. It will promote life-long investment in people, from vocational training and higher education through to digital and high-tech expertise and the life skills needed for citizens' active engagement in changing workplaces and societies. The energy transition will bring significant shifts in employment and skill sets required for employees active in the energy sector as traditional means of generation will be replaced by RES E. This transition is however primarily driven by EE and RED II related measures as well as national choices as to the generation mix. More relevant for the present initiative are the measures aiming at inducing the development of the retail markets from electricity supply markets towards including more service oriented product offerings facilitating the participation of consumers in the electricity market.

As regards consumer rights, the Unfair Commercial Practices Directive is the overarching piece of EU legislation regulating unfair commercial practices in business-to-consumer transactions. It applies to all commercial practices that occur before (i.e. during advertising or marketing), during and after a business-to-consumer transaction has taken place. Where sector-specific EU law is in place and its provisions overlap with the provisions of the UCPD, the corresponding provisions of the sector-specific EU rules prevail, so no contradictions exist.

Research, Innovation and Competitiveness being Energy Union's 5th dimension, cuts across all its elements. The Strategic Energy Technology Plan implements the energy union's fifth dimension, promotes research and innovation for low carbon technologies, contributing to the transformation of the EU's energy system and creating jobs, growth and global export opportunities in the fast-growing clean-technology sector. Technological developments create opportunities for citizens to turn from being passive consumers of electricity into prosumers that actively manage their consumption, storage and production of electricity and participate in the market and allow for the increasing penetration of distributed resources. A new Research, Innovation and competitiveness strategy, encompassing energy, transport and industrial competitiveness aspects is expected to be presented in the months to come. This strategy builds on the achievements of the SET Plan and further addresses the R&I challenges particularly towards industrialisation of innovative low carbon technologies.

The present initiative is fully coherent as it seeks to remove barriers for the participation of consumers, for bringing new resources to the market and seeks to improve price formation with a view to create the conditions for new business models to emerge and for innovative products to be absorbed by the market.

5.Policy options

A fully functioning European wide electricity market is the best means to ensure that electricity can be delivered to consumers in the most cost-efficient way at any time. To continue fulfilling that purpose, the electricity market needs to be able to adapt to the significant increase of variable renewable electricity production, integrate new enabling technologies such as smart grids, smart metering, smart-home, self-generation and storage equipment, empower citizens to take ownership of the energy transition and assure security of electricity supply at least costs. Market mechanisms may need to be complemented by initiatives which help preventing and managing electricity crisis situations.

Any EU action aimed at strengthening the market should build on the gradual liberalisation of the EU energy markets resulting from the three Energy Packages described earlier in this document.

The following policy options have been considered to address the problems of today's electricity market and to meet the broad energy policy objective of ensuring low carbon electricity supply to European customers at least costs. In assessing all possible options to achieve this broad objective, the following approach was taken:

-Identification of the main areas where initiatives might be needed to achieve the main objectives of a new electricity market design. These Problem Areas are set out in Box 2 below: "Overview of Problem Areas".

-To address each Problem Area a set of high level options was identified (set-out in the following paragraphs). Each of these high level options groups options for specific measures.

-A bottom-up assessment was performed for each specific measure, comparing a number of options in order to select the preferred approach. The assessments of the specific measures can be found in the Annexes to the present impact assessment.

To help the reader, a table matching the assumed measures for each high level option is included at the end of each problem area with references to the Annexes.

Box 2: Overview of Problem Areas

5.1.Options to address Problem Area I (Market design not fit for an increasing share of variable decentralized generation and technological developments)

5.1.1.Overview of the policy options

With a significant part of the produced electricity coming from variable renewable sources and distributed resources, new challenges will be arising in terms of security of supply and electricity price volatility. The options examined here aim to address these challenges in the most cost-effective way for the whole European electricity system. These system cost savings will be passed on to consumers by way of lower network charges. They will also make it easier for RES E assets to earn a higher fraction of its revenues through the market.

Two possible paths were identified: the path of enhancing current market rules in order to increase the flexibility of the system, retaining to a certain extent the national operation of the systems (with more or less coordination assumed depending on the related sub-options) and the path of moving to a fully integrated approach.

Box 3: Overview of the Policy Options for Problem Area I

Each policy option consists of a package of measures which address the drivers of the problem. In the following sub-sections, the high level policy options and the packages of measures they contain are described. Details on the individual measures are included in the Annexes. It is then explained if any of those options are to be discarded at this stage, prior to assessment, or whether other options were considered but were discarded from the outset. The section is closed by a table summarising all specific measures included in each option and references to the Annexes where each measure is described and asessed in more detail.

The relevant Annexes addressing the policy options below in more detail are: 1.1 to 3.4.

5.1.2.Option 0: Baseline Scenario – Current Market Arrangements

Under this option no new legislation is adopted, but there is some effort to implement existing legislation including via the adoption of so-called network codes or guidelines. The network codes, provided for in Article 6 and the guidelines provided for in Article 18 of the Electricity Regulation specify technical rules on the operation of European electricty markets 138 . They are, as such, only designed to amend non-essential elements of the Electricity Regulation and can only be adopted in areas specifically mentioned in the above mentioned Articles. 139

Under these limitiations, network codes/guidelines are not the suitable instrument to achieve all objectives of this initiative. For instance, whereas the implementation of the Guideline on Capacity Allocation and Congestion Management ('CACM Guideline') will bring a certain degree of harmonisation of cross-border intraday markets, gate closure times and products for the intraday, as well as a market clearing, there is no guarantee that the local market will adapt to reflect the cross-border approach and practices (auctions / continuous trading) and local intraday markets across Europe will continue to remain non-harmonised. This means that the EU-wide intraday market coupling envisaged by the CACM Guideline will not be able to reach its full potential.

The Balancing Guideline is expected to bring certain improvements to the balancing market, namely the common merit order list for activation of balancing energy, the standardisation of balancing products and the harmonisation of the pricing methodology for balancing. Nonetheless, other important areas like balancing capacity procurement rules, frequency, geographical scope and sizing will not be affected by this regulation.

Priority dispatch rules, must-run priorities and other technology specific rules related to the scheduling and operation of the system do not change at all with the adoption of network codes. The same applies for the possibility for demand and distributed resources to access the markets, and to compete on a level playing field with thermal generation. The baseline assumes that demand response exists only in countries where it currently has access to the market, with only industrial consumers being able to participate.

Overall, this option assumes that the future situation will remain more or less the same as today, except from some specific measures included in the network codes (as above). The baseline does not consider explicitly any type of existing support schemes for power generation plants, neither in the form of RES E subsidies nor in the form of CMs 140 .

5.1.3.Option 0+: Non-regulatory approach

 Whilst systematically considered 143 , no such option could be identified 144 .

Stronger enforcement provides little scope for improving the level playing field among resources. To the extent the lack of a level playing field is due to the variety of provisions in national law, a clear and transparent EU framework is a prerequisite for any improvement. If the lack of a level playing field is due to exemptions in the EU regulatory framework, stronger enforcement of these would actually be counter productive. In this regard, the Evaluation report indicates that the rules of the Third Energy Package appear to be insufficient to cope with the challenges facing the European electricity system. 145  

Moreover, voluntary cooperation has resulted in significant developments in the market and a lot of benefits. However, it it unlikely to provide for appropriate levels of harmonisation or certainty to the market and legislation is needed in this area to address the issues in a consistent way.

The current EU regulatory framework contains very limited rules on balancing and intraday markets in a manner that allow to strengthening these short-term markets. In particular, the Third Package does not address regional sizing and procurement of balancing reserves nor contain rules allowing achieving a larger degree of harmonisation of intraday trading arrangements.

Given that the existence of Regional Security Coordinators ('RSCs') depends on the implementation of the System Operation Guideline, RSCs may only be fully operational around mid-2019. Hence, stronger enforcement is currently not a possible option. Any progress beyond the framework in the System Operation Guideline and the application of other network codes would depend on the voluntary initiatives of TSOs. However, these voluntary initiatives would be limited due to constraints deriving from differing national legal frameworks.

As to demand response, stronger enforcement of existing provisions in the electricity and energy efficiency directives are unlikely to untap the potential of flexibility. This is because the existing provisions give Member States a high degree of freedom that has proven not to be specific enough to ensure a full removal of existing market barriers.

Evidence suggests that voluntary cooperation will not result in progress in this area, as there has been to date already significant opportunity to effect the necessary changes voluntarily.

In the case of DSOs the current EU regulatory framework does not provide a clear set of rules when it comes to additional tools that DSOs can employ to improve their efficiency in terms of costs and quality of service provided to system users. Moreover, the current framework does not address the role of DSOs in activities which are expected to have a key impact in the development of the market (e.g. data management).

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

Electricity production from wind and sun is more variable and less predictable than electricity production from conventional sources of energy. Due to this, there will be times when renewables cover a very large share of electricity demand and times when they only cover a minor share of it. The large scale integration of such variable electricity production thus requires a more flexible electricity system, one which matches the variable production.

Options to deliver the desired flexibility may comprise:

a.Abolishing (i) those measures that enhance the inflexibility of the current system, namely priority dispatch for certain technologies (e.g. RES E, CHP, indigenous fuels) and "must-runs" of conventional generation, (Creating a level playing field) and (ii) barriers preventing demand response from participating in the energy and reserve markets;

b.In addition to the measures under a), better integrating short-term markets, harmonizing their gate closure times and bringing them closer to real-time, in order to take advantage of the diversity of generation resources and demand across the EU and to improve the estimation and signalling of actual flexibility needs (Strengthening the short-term markets);

c.In addition to the measures under a) and b), pulling all flexible distributed resources concerning generation, demand and storage, into the market via proper incentives and a market framework better adapted to them, based on active aggregators, roll-out of smart-metering and time-of-use supply tariffs linked to the wholesale prices. 146

The sub-options described above reflect a different degree of ambition to change the market, as well as the different views expressed among stakeholders on how strong the proposed interventions should be. Sub-option 1(a) (level playing field) retains a more national status of the markets, Sub-option 1(b) (strengthening short-term markets) moves also to more regionally coordinated markets, while Sub-option 1(c) (demand response/distributed resources) makes an additional step towards a more decentralised electricity market and system.

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

The first group of measures aims at removing market distortions resulting from manifold different regulatory rules for generation from different sources. Creating a level playing field among all generation modes and restoring the economic merit order curve is an important prerequisite for a well-functioning electricity market with prices that reflect properly actual demand and supply conditions. For this reason the measures described here are an integral part of all sub-options under Option 1.

The measures considered under this option would mainly target the removal of existing market distortions and create a level playing field among technologies and resources. This could involve abolishing rules that artificially limit or favour the access of certain technologies to the electricity market (such as so-called "must-run" provisions, rules on priority dispatch and access and any other rules discriminating between resources 149 ). Industrial consumers would become active in the wholesale markets, both for energy and reserves, in all Member States. All market participants would become balance responsible, bearing financial responsibility for the imbalances caused and thus being incentivized to reduce the risk of such imbalances. Dispatch and redispatch decisions would be based on using the most efficient resources available, curtailment should be a measure of last resort which is limited to situations in which no market-based resources are available (including storage and demand response), and only subject to transparent rules.

Therefore, all resources would be remunerated in the market on equal terms. This would not mean that all resources earn the same revenues, but that different resources face the same prices for equal services. In most cases the TSO should follow the merit order, allowing the market to define the dispatch of available resources, using the inherent flexibility of resources to the maximum potential (e.g. by significantly reducing must-run generation, creating incentives for the use of heat storage combined with CHP and the use of biomass generation in periods of peak demand rather than as baseload, and using demand response or storage where it is more efficient than generation). Where resources are used on the basis of merit order (thus on the basis of the marginal cost for using a particular resource at a given point in time) 150 , supply costs are reduced.

Imposing additional obligations increases the risk and hence the financing costs of some technologies such as RES E. Part of this risk will be hedged through the more liquid intraday and balancing markets resulting from the full implementation of the Network Codes, in combination with the increased participation of resources due to the removal of must-run and priority dispatch provisions. These obligations should be also accompanied by measures that reduce their costs of compliance, such as the introduction of transparent curtailment rules. Additionally, exemptions from certain regulatory provisions may, in some cases, be required. This can e.g. be the case for emerging technologies, which, although they are not yet competitive, need to reach a minimum number of running hours to gather experience. For certain generators, particularly small RES E (e.g. rooftop solar), exemptions can be furthermore justified to avoid excessive administrative efforts related to being active on the wholesale markets.

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

Sub-option 1(b) (strengthening short-term markets) includes the measures described under 1(a) (level playing field ) and a set of additional measures, further enhancing the measures foreseen in the CACM and EB Guidelines (and are assumed as part of the baseline). As explained above, variable RES E have fundamentally different generation characteristics compared to traditional fuel based generation (e.g. variability, only short-term predictability). An important additional step would therefore be to have more liquid and better integrated short-term markets, going beyond what the implementation of technical implementing legislation ("Network Codes") will achieve, setting the ground for renewable energy producers to better access energy wholesale markets and to compete on an equal footing with conventional energy producers. Short-term markets will also allow Member States to share their resources across all "time frames" (forward trading, day-ahead, intraday and balancing), taking advantage of the fact that peaks and weather conditions across Europe do not occur at the same time.

Also, the closer to real time electricity is traded (supply and demand matched), the less the need for costly TSO interventions to maintain a stable electricity system. Although TSOs would have less time to react to deviations and unexpected events and forecast errors, the liquid, better interconnected balancing markets, together with the regional procurement of balancing reserves, would be expected to provide them with adequate and more efficient resources in order to manage the grid and facilitate RES E integration.

In order to support these actions and mainly in order to be able to optimally exploit interconnections along all "time frames", a number of measures are assumed to be taken: gate closure times could be brought closer to real-time to provide maximum opportunity for the market to balance its positions before it becomes a TSO responsibility and some harmonisation would be brought to trading products for intraday markets in order to further incentivize cross-border participation of market parties. The sizing of balancing reserves and their procurement would be harmonized in larger balancing zones, allowing to reap benefits of cross-border exchange of reserves and use of the most efficient reserves available.

At the same time, the integration of national electricity systems, from the market and operational perspectives, requires the enhancement of cooperation between TSOs. The creation of a number of regional operational centres ('ROCs'), with an enlarged scope of functions, an optimised geographical coverage compared to the existing regional security coordinators and with an enhanced advisory role for all functions, including the possibility to entrust them decision-making responsibilities for a number of relevant issues, could contribute to better TSO cooperation at regional level. 157 Measures on enhanced cooperation between TSOs could be accompanied by an increased level of cooperation between regulators and governments. 158

All these options would be expected to strongly incentivize participation in the intraday and balancing markets, further increasing their liquidity, while at the same time minimizing TSOs' interventions.

5.1.4.3.Sub-option 1(c): Pulling demand response and distributed resources into the market 166

Sub-option 1(c) (demand response/distributed resources) includes the measures described under 1(a) (level playing field) and 1(b) (strengthening short-term markets), as well as a set of additional measures, aiming at using the full potential of demand response, storage and distributed generation. The previous options would introduce a level playing field for all resources and improve the short-term market framework. They would, however, not include any measure intending to pull all the additional available potential from distributed resources into the market. Such resources are most importantly demand response, distributed RES E and storage. 167

A significant part of the current costs for the electricity system stem from the new challenges of variable generation for the system, notably the increased need to deal with supply peaks and unexpected generation gaps. As the elecricity grid requires a constant balance of demand and supply, grid operators need to take costly measures. Demand response, distributed RES E and storage can play an important role to reduce these costs.

The measures considered under Option 1(c) bring demand response from all consumer groups, including residential and commercial consumers 168 , and storage as additional resources into the market, especially to the balancing market. This would even further increase the flexibility of the electricity system and the resources for the TSOs to manage it. At the same time it should lead to much more efficient operation of the whole energy system.

This option would include more in particular:

Enabling consumers to directly react to price signals on electricity markets both in terms of consumption and production, by giving consumers access to a fit-for-purpose smart metering system, enabling suppliers to measure and settle electricity consumption close to real time, as well as requiring suppliers to offer consumers electricity supply contracts with prices linked dynamically to the wholesale spot market that will enable consumers to directly react to price signals on electricity markets both in terms of consumption and production.

Box 4: Benefits and risks of dynamic electricity pricing contracts

Aggregators are companies that act as intermediaries between the electricity system and distinct agents in the electricity system, mainly small, individual resoures but that exist in large numbers, and which are usually located in the distribution grid (consumers, prosumers and producers). 169 Developing a comprehensive framework for demand, supply and storage aggregators would facilitate their participation in the market and thus increase flexibility in the energy system and complement large generation connected to the transmission grid. 170 Larger storage facilities can be connected at distribution or transmission level, and provide services on a peer basis with other providers.

In order to pull all available resources into the market, it is also important to enable and incentivise DSOs, without compromising their neutrality as system operators, to manage their networks in a flexible and cost-efficient way, This could be achieved by establishing a performance-based remuneration framework for DSOs that would reward them for innovating and improving overall efficiency of their networks through synergies with other actors, making full use of energy storage, and/or investing in electronic communication infrastructure. This would be enabled by the deployment of intelligent infrastructure and by ensuring coherence with other Commission policies in the field of the Digital Single Market and the General Data Protection Regulation 171 .

Measures under this option would also include defining the conditions under which DSOs may acquire flexibility services without distorting the markets for such services, and putting in place distribution tariff structures that send accurate price signals to all grid users. Such initiative would be aimed at facilitating the integration of the increasing amounts of variable RES E generation that will be connected directly to distribution grids in the future.

5.1.5.Option 2: Fully Integrated EU market

This option considers measures that would aim to deliver a single truly pan-European electricity market via relatively far-reaching changes to the current regulatory framework, aiming at the full integration of electricity markets and system operation, and at mobilising all available flexibility of the EU-wide system.

For a fully integrated EU market, one would need to significantly change the current regulatory approach of the internal market. The current EU wholesale market design of the Third Package provides for a coordination framework between grid operators and national regulators and sets some rules for certain issues which are relevant for cross-border exchange of electricity (e.g. coordinated electricity trading and grid operation measures). However, under the Third Package, regulatory decisions are in principle left to Member States, the 28 national regulators and the 42 European grid operators if not otherwise provided in the Third Package.

Leaving scope for national decision-making on trading and system operation may lead to inefficiencies due to unsufficiently coordinated and contradicting decisions. A more centralised regulatory approach could therefore be considered to achieve more integrated EU markets.

Under this option, procurement of balancing reserves would be performed directly at EU level, instead of a regional level. For system operation, this could mean shifting from a system of separate national TSOs to an integrated system managed by a single European Independent System Operator ("EU ISO"). System operation (including real time operation) and planning functions could be performed by this EU ISO, which would be competent for the whole Union. 177  

In order to optimally deal with congestion between countries and to let the market transmit the right price signals, this option would entail to move from zonal to nodal pricing 178 . The values of available transmission capacities would be calculated centrally and could be closely coordinated across market regions, thereby taking advantage of all information available among the TSOs in different grid arreas and also taking into account the interrelationship between different interconnectors. As a result, it is assumed that more interconnector capacity is made available to the market(s) and resources are expected to be utilized more efficiently across regions.

In general, Option 2 would not only entail coordination, approximation and harmonisation of selected topics relevant for national market and grid operation rules, but also to apply the same rules and specifications for products and services across the EU, including centrally fixed rules for electricity trading, for common EU-wide procurement of reserves and central system planning and operation. Such centralised integrated market would also provide for mandatory smart meter roll-out and a full EU framework for incentive-based demand response to better exploited demand reponse. Under Option 2, also distribution tariff structures would be harmonised, stronger unbundling rules for DSOs be created as well as harmonised renumeration methodologies that ensure DSOs' incentives to invest in innovative and efficient technologies.

ACER would need to gain significant competences and take over most NRAs' responsibilities directly or indirectly related to cross-border and EU-level issues. ENTSO-E would need to be formally separated from its members' interest and take up more competences. 179  

Such measures, intended to optimise the cost-efficiency and flexibility of the European electricity system, would involve going significantly beyond the measures described under Option 1, requiring also particularly far-reaching institutional changes.

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

Each set of proposed measures under Options 1(a) to 1(c), as well as (2), will necessitate a different degree of reinforcement of the institutional framework of the EU's electricity markets. Since the harmonisation of regulatory aspects (e.g. gate closure times, rules for the curtailment of cross-border capacities, bidding zones etc.) often has different economic impacts in different Member States, an institutional framework is needed to find the necessary compromises. Experience has shown that it will generally be more difficult to achieve ambitious harmonisation goals with an institutional framework that grants veto rights to each national regulator or TSO (i.e. in cooperative institutions applying unanimous decision-making). An alignment or harmonisation of aspects concerning the electricity market design is therefore more likely to happen with an institutional framework which applies (qualified) majority decision-making or which replaces the decision-making by 28 different regulators/TSOs by a central body which takes the decision in the European interest 180 .

A robust institutional framework constitutes a pre-requisite for the integration and proper functioning of the EU market. For this reason, it is necessary that the institutional framework reflects the realities of the electricity system and the resulting need for regional cooperation as well as that it addresses existing and anticipated regulatory gaps in the energy market.

In order to effectively establish a level playing field between all potential market participants and resources (Sub-option 1(a) (level playing field)), it is necessary to reinforce ACER's competences at EU level in order to address regulatory gaps already identified in the implementation of the Third Package and ensure the oversight over entities and functions with relevance at EU level.

When markets and market regulation achieve a regional dimension (Sub-option 1(b)(strenghening short-term markets)), the institutional framework needs to be adapted accordingly, if it is to remain efficient and effective. Currently, the EU institutional framework is based on the complementarity of regulation at national and EU law. Hence, the regulatory framework would then need to be reinforced to address the need for additional regional cooperation. In this regard, ACER's competences and NRAs' cooperation at regional level should be enhanced, corresponding to increased regional TSO cooperation and to the implementation of network codes and guidelines at regional level. The mandate of ENTSO-E could be clarified to strengthen its obligation to take a European / internal market perspective and to emphasize its transparency and monitoring obligations. The role of power exchanges in cross-border electricity issues should be acknowledged and they should be involved in all regulatory procedures relevant for them. Finally the use of congestion income should be altered, increasing the proportion spent on investments that maintain or increase interconnection, thus creating the basis for the regional co-operation through a strongly interconnected system 181 .

In order to facilitate distributed resources to participate in the market (Sub-option 1(c) demand response/distributed resources), DSOs must become more active at European level and have increased responsibilities and tasks, similar to those of the TSOs. Their role should be formalised into a European organisation with an efficient working structure to render their participation effective and independent. In particular, whereas DSOs are currently represented at EU level by four associations (Eurelectric, Geode, CEDEC and EDSO), none of these has the necessary characteristics to represent the sector by engaging in tasks that might include the codification of formal EU market rules: Either they or their members are listed as lobbyists on the EU Transparency Register, none of their memberships is representative of all EU DSOs, and none has the explicit mandate to represent EU DSOs in such activities.

Finally, Option 2 requires significantly restructuring the institutional framework, going beyond addressing the regulatory gaps and moving towards more centralised institutional structures with additional power and responsibilities, particularly for ACER and ENTSO-E.

5.1.7.Summary of specific measures comprising each Option

The following table summarizes the specific measures comprising each package of measures, as well the corresponding specific measure option considered under each high level option 184 . The detailed presentation and assessment of each measure can be found in the indicated Annex.

Table 6: Summary of Specific Measures investigated for Problem Area I

5.2.Options to address Problem Area II (Uncertainty about sufficient future generation investments and uncoordinated capacity markets)

5.2.1.Overview of the policy options

A number of Member States anticipate inadequate generation capacity in future years and plan to introduce or have already introduced unilateraly, unaligned capacity mechanisms. Capacity mechanisms remunerate the guaranteed availability of electricity resources (e.g. generation or demand response) rather than paying for electricity actually delivered. The current regulatory market design does provide for rules on capacity mechanisms 185 . While it does not prohibit nor encourage capacity mechanisms, the Third Package is, in principle, built on the concept of an "energy-only" market, in which generators are remunerated mainly based on the energy delivered 186 . Undistorted cross-border markets should provide for the necessary investment signals to ensure stable generation at all times. Price signals should drive production and investment decisions, whereas price differentials between different bidding zones should determine where facilities should ideally be located, provided that all assets are treated equally in terms of the risks and costs to which they are exposed and the opportunities for earning revenues from producing electricity i.e. they operate within a level playing field.

Several Options will be considered to address the concerns regarding investment certainty and fragmented approaches to CMs:

Box 5: Overview of the Policy Options for Problem Area II

Each policy option consists of a package of measures which act upon the drivers of the problem. Some of the options differ according to whether generators can only rely on energy market payments or whether they receive additional remuneration from CMs. Option 1 (Improved energy-only markets) would be based on additional measures to further strengthen the internal electricity market (complementing the measures described above in options 1(a) (level playing field), 1(b) (strengthening short-term markets) and (c) (demand response/distributed resources) presented in Problem Area I). Under this option, CMs would no longer be allowed. Option 2 and 3 would also include the proposed measures to strengthen the internal energy market as presented in Option 1, but also propose possible measures to better align national CMs. The possibility to set up a mandatory EU-wide CM is described in Option 4.

The following sub-sections describe the policy options and the packages of measures they comprise. It then explains which options can be discarded at this stage, prior to assessment, as well as present other options that were considered but were discarded from the beginning. A table summarising all specific measures for each option is provided at the end of this section.

The relevant Annexes addressing the policy options below are: 4.1 to 5.2.

5.2.2.Option 0: Baseline Scenario – Current Market Arrangements

Under the baseline scenario, price formation on electricity wholesale markets is constrained, e.g. through price caps. Prices may not be able to reach levels which truly reflect the value of energy when the demand and supply balance is tight and, hence, electricity is scarce. Therefore price signals from wholesale markets would, in times of scarcity, be distorted and revenue streams of generators cannot properly reflect their value to the system. This affects, in particular, the remuneration of assets that can provide flexibility to the electricity system, regardless to whether this concerns flexible generation capacity, electricity storage or demand response.

At this stage most electricity markets in Europe face generation overcapacities. In this situation, price caps do in practice not matter – scarcity prices cannot be expected anyway. However, once old capacities will have exited the market and the power mix has adjusted (see in this regard the analyses presented in section 6.2.6.3), true price formation would be essential to produce signals for new investments. This could not happen as long as price caps exist.

Price signals are also not aligned with structural congestion in the transmission grid, thus not revealing the locations where investments would relieve congestion and production decisions. TSOs then can only operate sub-optimally the existing network and need to take frequent congestion management measures. Although the CACM Guideline provides a process for reviewing price or bidding zones, the current process lends itself to maintaining the status quo (mostly price zones along Member State borders), making this the most plausible assumption for the baseline. This is because there are likely to be competing interests at stake. In particular, some Member States are unlikely to want to amend bidding zones where it would create price differentials within their borders; it is sometimes considered to be right for all consumers to pay the same price within a Member State, and for all producers to receive the same price. The current legislation does not, therefore, provide for the socially optimal solution to be agreed. 187

Based on perceived or real resource adequacy concerns, several Member States take actions concerning the introduction of national resource adequacy measures or the imposition of regulatory barriers to decommissioning. These measures are usually based on national resource adequacy assessments and projections, which may substantially differ depending on the underlying assumptions made and the extent to which foreign capacities as well as demand side flexibility are taken into account in calculations. Some of these concerns and projections are a result of the current market arrangements.

The Commission's current tool to assess whether government interventions in support of resource adequacy are legitimate is state aid scrutiny. The EEAG require among others a proof that the measure is necessary, technological neutral and allows for explicit cross-border participation. However, the EEAG do not clarify how an effective cross-border CM regime could be deployed.

The baseline is common with the one presented in 5.1.2, with only two differences: (a) presence of price caps based on current practices and (b) existence of structural congestion in the transmission grid.

5.2.3.Option 0+: Non-regulatory approach

Whilst systematically considered 188 , no such policy option could be identified.

This option would entail relying on existing legislation to improve the current market arrangements. The likelihood of seeing any meaningful change as a result of this process is minimal. Existing provisions under EU legislation are arguably not sufficiently clear and robust. In this regard, the Evaluation report indicates that the rules of the Third Energy Package appear to be insufficient to cope with the challenges facing the European electricity system. 189 In addition, certain areas, like resource adequacy, are not addressed in the Third Package. Consequently, the Evaluation report concludes that the Third Package does not not ensure sufficient incentives for private investments in the new generation capacities and network because of the minor attention in it to effective short-term markets and prices which would reflect actual scarcity. 190  

Voluntary cooperation has resulted in significant developments and a lot of benefits (e.g., the PLEF, whereby some Member States have voluntarily decided to cooperate and deliver a regional resource adequacy assessment). However it may not provide for appropriate levels of harmonisation across all Member States and certainty to the market and legislation is needed in this area to address the issues in a consistent way.

5.2.4.Option 1: Improved energy market - no CMs

Option 1 assumes that European electricity markets, if sufficiently interconnected and undistorted, can provide for the necessary price signals to incentivise investments into new generation. Wholesale markets would be strengthened by a set of specific measures aiming at improving price signals so as to deliver the necessary investments based only on price signals. CMs, whether at national, regional or European level would not be justifiable to secure electricity supplies under this option as the market should be incentivising investments.

Even if such price signals concern the spot price on the wholesale market corresponding to the day-ahead market, these prices are the reference for the forward market and would thus have a long-term effect. Having as a starting point the reformed market design as described in section 5.1.4.3 191 , it is additionaly assumed that no administrative mechanisms directly affecting investments and price signals are allowed to be in place, in the form of CMs or (below Value of Lost Load 192 or 'VoLL') price caps. In the case of the latter this would be effected by ensuring that any technical limits imposed by power exchanges are merely that, and are raised in the event they are reached, and, in order to provide maximum investor confidence, an end-date, after which such limits must not be below VoLL.

The strengthened short and long-term markets and the participation of distributed generation offer the necessary flexibility required to integrate variable RES E into the market. Combined with the removal of (below VoLL) price caps, 193 the market should be able to drive investments towards the needed flexible assets, such as storage and demand response, and sufficient generating capacity. Furthermore, proper incentives are introduced aiming to unlock the flexibility that can be provided by existing assets, such as demand response and storage.

At the same time price signals could drive the geographical location of new investments and production decisions, via price zones aligned with structural congestion in the transmission grid. The location of the price zone borders would be decided through a robust regulatory decision-making process. Price differentials between these price zones should help determine where investments are needed and make the best use of natural resources (particularly important for RES E, but also for interconnectors) and, for those assets already deployed, which one will be producing. Such locational prices would also provide efficient signals for the location of demand – for example new energy intensive industries would choose to locate in areas where there is excess generation and therefore low prices. 194 Measures would also be taken to further restrict the practice of limiting cross-border capacity in order to deal with internal network contraints and, finally, measures would be taken to minimise, in the long-term, the most significant investment and operational distortions on generators arising as a result of network charges. 195

5.2.5.Option 2: Improved energy market – CMs only when needed, based on a common EU-wide adequacy assessment) 198

This Option includes the measures to strenghten the internal energy market (as described in Option 1 above), i.e. every Member State is assumed to have in place a well-functioning energy market.

In addition to Option 1 however, Member States would be allowed to implement national CMs, but only under certain conditions. Additional measures are proposed in order to avoid negative consequences of uncoordinated CMs for the functioning of the internal market, building on the EEAG' state aid Guidelines and the Sector Inquiry on CMs.

To address the problem of diverging and purely national assessments of the needs for CMs, ENTSO-E would be required under this option to propose a methodology for an EU-wide resource adequacy assessment. The upgraded methodology should be based on transparent and common assumptions 199 and ENTSO-E would carry out the assessment anually. The prerequisite for a Member State to implement a CM or prohibit capacity from exiting the market would be that ENTSO-E's assessment indicated a lack of generation capacity and where markets cannot be expected to close the gap. This would avoid that back-up capacities are developed based on a purely national perspective (i.e. national adequacy assessments, using different methodologies and not taking into account the generation potential across borders).

When proposing or applying CMs, Member States would need to introduce resource adequacy targets, which can be diverging (as an expression of their diverging preference for resource adequacy). The standards should be expressed in a unique format to become comparable across the EU – as Expected Energy Non Served ('EENS'), and it should be derived following a methodology provided by ENTSO-E which takes into account the value that average customers in each bidding zone put on electricity supplies (Value of Lost Load – 'VoLL').

5.2.6.Option 3: Improved energy market - CMs only when needed, based on a common EU-wide adequacy assessment, plus cross-border participation 202

Option 3 includes the measures to strenghten the internal energy market as described in Option 1 above. It also includes the requirement for national CMs to be justified by a European adequacy assessment (see Option 2). In addition, Option 3 would however provide for design rules for better compatibility between national CMs, also building on the EEAG state aid guidelines and the Sector Inquiry on CMs notably in order to facilitate cross-border participation ('blue-print') .

To date, in order to comply with EEAG, Member States have to individually organise, for each of their borders separately, the necessary cross-border arrangements involving a multitude of parties (e.g. resource providers, regulators, TSOs).

This option would provide a harmonised cross-border participation scheme across the EU by setting out procedures including roles and responsibilities for the involved parties (e.g. resource providers, regulators, TSOs).

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

Under this option based on regional or EU-wide resource adequacy assessments, entire regions or ultimately all EU Member States would be required to roll-out CMs on a mandatory basis. The design of the CMs would follow a EU 'blue print' (i.e. a set of design requirements for CMs), with the required resource adequacy target to be set at regional or EU level. This approach would assess and address adequacy concerns at a regional or EU level. Decisions on whether to introduce CMs or not would no longer be left with individual Member States, but an EU-wide CM would be created, as a mandatory additional layer to the "energy-only" market. Differences between Member States (e.g. whether all areas within larger regions actually face adequacy challenges, or network congestions) would not justify exception from the obligation to introduce a CM.

5.2.8.Discarded Options

Option 0+ will not be further analysed as no means were identified to implement it.

Option 4 does not consider the significant regional differences when it comes to resource adequacy. The EU-wide or region-wide roll-out would disregard existing congestions in the European network and it would consequently over- or underestimate the resource adequacy in single bidding zones/ Member States belonging to a wider region. As a result CMs might need to be introduced in bidding zones/Member States that do not face any adequacy concerns. Alternatively, emerging resource adequacy problems in certain bidding zones/Member States might not be identified and addressed appropriately. In addition, as a number of Member States rely on energy-only markets to provide for the necessary investments in their power systems it would not be appropriate to force them to adopt CMs.

5.2.9.Summary of specific measures comprising each Option

The following table summarizes the specific measures comprising each package of measures, as well the corresponding specific measure option considered under each high level option 205 . The detailed presentation and assessment of each measure can be found in the indicated Annex.

Table 7: Summary of Specific Measures Examined for Problem Area II

5.3.Options to address Problem Area III (When preparing or managing crisis situations, Member States tend to disregard the situation across their borders)

5.3.1.Overview of the policy options

With the intention to meet the objectives set out in the previous section, the Commission services have identified several policy options ranging from an enhanced implementation of the existing legislation to the full harmonization and decision making at regional level. Option 0 represents the baseline or the measures currently in place. Each policy option consists of a package of measures combining existing tools, possible updated and improved tools and new tools which act upon the drivers of the problem. This section finalizes with a table summarising all specific measures comprising each option.

The relevant Annex addressing the policy options below is Annex 6.

Table 8: Overview of the Policy Options for Problem Area III

5.3.2.Option 0: Baseline scenario – Purely national approach to electricity crises

Under the baseline scenario, Member States would continue identifying and addressing possible crisis situations based on a national approach, in accordance with their own national rules and requirements.

There would be no rules or structures facilitating and guaranteeing a proper identification of cross-border crisis situations 206 and ensuring that Member States take the necessary action to deal with them, in co-operation with one another. Whilst some co-operation between Member states could take place (e.g., between the Nordic countries as well as within the context of the PLEF 207 ), in practice such cooperation would remain entirely voluntary, and might be hampered in practice by different national rules and procedures, and a lack of appropriate structures at regional and EU level.

Innovative tools 208 have been also developed for TSOs in the area of the system security in the last years, improving monitoring, prediction and managing secure interconnected power systems and preventing, in particular, cascading failures 209 . In addition, the recently adopted network codes and guidelines bring a certain degree of harmonisation on how to deal with electricity systems in different states (normal state, alert state, emergency state, black-out and restoration) and should bring more clarity as to how TSOs should act in crisis situations, and as to how they should co-operate with one another. However, network codes and guidelines focus on technical issues and co-operation between TSOs (in implementation of the current legal framework). They do not offer a framework ensuring a proper co-ordination and co-operation between Member States on how to prepare for and handle electricity crisis situations, in particular in situations of simultaneous scarcity. 210  

For instance, political decisions such as where to curtail, to whom and when, would still be taken nationally, by reference to very different national rules and regulations. In addition, any cross-border assistance in times of crisis would be hampered by a lack of common principles and rules governing co-operation, assistance and cost compensation. Finally, risks would still assessed and adressed on the basis of very different methods, and from a national perspective only.

5.3.3.Option 0+: Non-regulatory approach

As current legislative framework established by the SoS Directive set general principles rather than requires Member States to take concrete measures, better implementation and enforcement actions will be of no avail.

In fact, as the progress report of 2010 shows 212 , the SoS Directive has been implemented across Europe, but such implementation did not result in better co-ordinated or clearer national policies regarding risk preparedness.

In addition, the evaluation of the SoS Directive has revealed the existence of numerous deficiencies in the current legal framework 213 . It highlights the ineffectiveness of the SoS Directive in achieving the objectives pursued, notably contributing to a better security of supply in Europe. Whilst some of its provisions have been overtaken by subsequent legislation (notably the Third Package and the TEN-E Regulation), there are still regulatory gaps notably when it comes to preventing and managing crisis situations.

The evaluation also reveals that the SoS Directive intervention is no longer relevant today as it does not match the current needs on security of supply. As electricity systems are increasingly interlinked, purely national approaches to preventing and managing crisis situations can no longer be considered appropriate. It also concludes that its added value has been very limited as it created a general framework but left it by and large to Member States to define their own security of supply standard. Whilst electricity markets are increasingly intertwined within Europe, there is still no common European framework governing the prevention and mitigation of electricity crisis situations. National authorities tend to decide, one-sidedly, on the degree of security they deem desirable, on how to assess risks (including emerging ones, such as cyber-security) and on what measures to take to prevent or mitigate them.

The recently adopted network codes and guidelines offer some improvements at the technical level, but do not address the main problems identified.

In addition, today voluntary cooperation in prevention and crisis management is scarce across Europe and where it takes place at all, it is often limited to cooperation at the level of TSOs. It is true that certain Member States collaborate on a voluntary basis in order to addresss certain of the problems identified (e.g. Nord-BER, PLEF). However, these initiatives have different levels of ambition and effectiveness, and they geografically cover only part of the EU electricity market. Therefore, voluntary cooperation will not be an effective tool to solve the problems identified timely in the whole EU.

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

Under Option 1, Member States would have to respect a set of common rules and principles regarding crisis prevention and management, agreed at the European level ('minimum harmonisation'). In particular, Member States would be obliged to develop national Risk Preparedness Plans ('Plan') with the aim to avoid or better tackle crisis situations. Plans could be prepared by TSOs, but need to be endorsed at the political level. Plans should be based on an assessment of the most relevant crisis scenarios originated by rare/extreme risks. Such assesment would be carried out in a national context (as is the case today), but would have to based on a common set of rules. In particular, Member States would be required, for instance, to consider at least the following risks: a) rare/extreme natural hazards, b) accidental hazards which go beyond N-1, c) consequential hazards such as fuel shortage, d) malicious attacks (terrorist attacks, cyberattacks).

Plans would have to respect a set of common minimum requirements. They would need to set out who does what to prevent and to manage crisis situations, including in a situation of a crisis affecting more than one countrry at the same time. More specifically on cybersecurity, Member States would need to set out in the Plans how they will prevent and manage cyberattack situations. This would be combined with soft guidance on cybersecurity in the energy sector, based on the NIS Directive 214 . Member States would also be required to set out how they ensure that assets that are important from a security of supply perspective, are protected against undue influences in case ownership control changes.

Plans should be adopted by relevant governments / ministries, following an inclusive process, and (at least some parts of the Plans) should be rendered public. Plans should be updated on a regular basis.

In addition, under Option 1 there would be new common rules and principles governing crisis management, in replacement of the current Article 42 of the Electricity Directive, which allows Member States to take 'safeguard measures' in crisis situations. All crisis management actions (whether taken at the level of the TSOs or at the level of governments) would need to respect three principles:

-'Market comes first': Non-market measures (such as obligatory demand reduction schemes) should only be introduced as a means of last resort, when duly justified, and should be temporary in nature. Use of such measures should not undermine market and system functioning;

-'Duty to offer assistance': Member States would be obliged to address electricity crisis situations, in particular situations of a simultaneous crisis, in a spirit of co-operation and solidarity. This means agreeing in advance on practical solutions on e.g. where to shed load and how much in cross-border crisis situations, subject to financial compension (which is also to be agreed upon in advance).

-'Transparency and information exchange': Member States should inform each other and the Commission without undue delay when they see a crisis situation coming (e.g., as a result of a seasonal outlook pointing at upcoming problems) or when being in a crisis situation. They should also be transparent about measures taken and their effect, both when taking them and afterwards.

The main benefits this option would bring is better preparedness, due to the fact that a common approach is followed across Europe, thus excluding the risk that some Member States being 'under-prepare'. In addition, better preparedness is likely to reduce the chances of premature market interventions, where Member States act in a transparent manner and on the basis of a clear set of rules. By imposing obligations to cooperate and lend assistance, Member States are also less likely to 'over-protect' themselves against possible crisis situations, which in turn will contribute to more security of supply at a lesser cost. Since a 'minimum' harmonisation approach would be followed, Member States would have still room to take account of national specificities, where needed and appropriate.

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

Option 2 would build on Option 1. It would include all common rules included in Option 1 (i.e., define a set of minimum obligations Member States would need to respect). In addition, it would put in place rules and tools to ensure that effective cross-border co-operation takes place, in a regional and EU context. Given the interlinked nature of EU's electricity systems, enhanced regional co-operation brings clear benefits when it comes to preventing and managing crisis situations.

First, under Option 2, there would be a systematic assessment of rare/ extreme risks at the regional level. The identification of crisis scenarios would be carried out by ENTSO-E, who would carry out such assessments in a regional context. To achieve this, ENTSO-E would be able to delegate all or part of its tasks to the ROCs. This regional approach would ensure that the risks originating across borders, including scenarios of a possible simultaneous crisis, are taken into account. The crisis scenarios identified by ENTSO-E would be also discussed in the Electricity Coordination Group, to ensure that a coherent and transparent approach is followed across Europe. For cybersecurity, building on Option 1, the Commission would propose the development of a network code/guidelines which would ensure a minimum level of harmonization in the energy sector throughout the EU 216 . 

The Risk Preparedness Plans would contain two parts – a part reflecting national measures and a part reflecting measures to be pre-agreed in a regional context. The latter part includes in particular preparatory measures such as simulations of simultaneous crisis situations in neighbouring Member States ("stress tests" in regional context organised by ENTSO-E who can delegate all or part of its tasks to the ROCs); procedures for cooperation with other Member States in different crisis scenarios, as well as agreements on how to deal with simultaneous electricity crisis situations. Through such regional agreements, Member States would be required to define in advance, in a regional context, how information will be shared, how they will ensure that markets can work as long as possible, and what kind of assistance will be offered accross borders, For instance, Member States would be required to agree in advance in which situations and according to what priorities customers would be curtailed in simultaneous crisis situations. The regional coordination of plans would build trust and confidence between Member States, which is crucial in times of crisis. It would also allow optimising scarce resources in times of crisis, whilst ensuring that markets can work as long as possible.

The regional parts of the Plans should be pre-agreed in a regional context. Such regionally co-ordinated plans would help ensure that increased TSO cooperation is effectively matched by a more structured cooperation between Member States. 217 For this reason, Member States would be called upon to co-operate and agree in the context of the same regional settings as are used for the ROCs. Effective regional co-operation and agreements would help ensure that electricity crisis situations are dealt with in the most effective manner, whilst respecting the needs of electricity consumers and systems at large.

To facilitate cross-border cooperation, Member States should designate one 'competent authority', belonging either to the national administration or to the NRA.

Additionally, ENTSO-E would be required to develop a common method for carrying out short-term risk assessments, to be used in the context of seasonal outlooks and weekly risk assessments by TSOs. 

To allow for a precise monitoring, ex-ante and ex-post, of how well Member States' systems perform in the area of security of supply, harmonised security of supply indicators would be introduced, as well as obligation on Member States to inform the Electricity Coordination Group and the Commission on crisis situations, their impact and the measures taken. This would enhance transparency, comparability and mutual trust in neighbours.

Further, in this option, the role of the Electricity Coordination Group 218 would be reinforced, so that it can act as an effective forum to monitor security of supply in Europe and oversee the way (possible) electricity crisis situations are dealt with. For instance, the Group would be asked to review the cross-border crisis scenario's developed by ENTSO-E and to review ex ante risk preparedness plans put in place by Member States. The Group could issue recommendations and develop best practice. Overall, the reinforcement of its tasks and powers would contribute to enhance cooperation and to build trust and confidence among Member States.

Figure 7: Overview of measures in Option 2

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

Building on Option 2, under Option 3 the risk preparedness plans would be developed on regional level. This would allow a harmonised response to potential crisis situations in each region. On cybersecurity, Option 3 would go one step further and nominate a dedicated body (agency) to deal with cybersecurity in the energy sector. The creation of the agency would guarantee full harmonisation on risk preparedness, communication, coordination and a coordinated cross-border reaction on cyberincidents.

Crisis would have to be managed according to the regional plans agreed among Member States. The Commission would determine the key elements of the regional plans such as: commonly agreed regional load-shedding plans, rules on customer categorisation, a harmonised definition of protected customers at regional level or specific rules on crisis information exchanges in the region.

Regarding crisis handling, under Option 3, a detailed 'emergency rulebook' would be put in place, containing an exhaustive list of measures that can be taken by Member States in crisis situations, with detailed indications as regards what measures can be taken, in what circumstances and when.

5.3.7.Discarded Options

Option 0+ was disregarded as no means for enhanced implementing of the existing acquis were identified.

5.3.8.Summary of specific measures comprising each Option

The following table summarizes the specific measures to be taken under each option  228 . A more detailed discussion can be found in annex.

5.4.Options to address Problem Area IV (Slow deployment and low levels of services and poor market performance)

5.4.1.Overview of the policy options

To recap, the drivers in this Problem Area are:

-Low levels of competition on retail markets;

-Low levels of consumer engagement;

-Market failures that prevent effective data flow between market actors.

Each policy option consists of a package of measures that addresses the problem drivers in a different way and to a different extent. They aim to tackle the existing competition and technical barriers to the emergence of new services, better levels of service, and lower consumer prices, whilst ensuring the protection of energy poor consumers.

Box 5: Overview of the Policy Options for Problem Area IV

In the following sub-sections the policy options and the packages of measures they comprise are described. This section is closed by a table summarising all specific measures comprising each option.

The relevant annexes addressing the policy options below are: 7.1 to 7.6.

5.4.2.Option 0: Baseline Scenario - Non-competitive retail markets with poor consumer engagement and poor data flows

Under this option no new legislation is adopted, there are no further efforts to clarify the existing legislation through guidance, and no additional work through non-regulatory means to address the problem drivers. It assumes that the future situation will remain more or less the same as today.

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

Under this option, the problem drivers are addressed to the greatest extent possible without resorting to new legislation. This means strengthening enforcement to tackle cases of the non-transposition or incorrect application of existing legislation, new Commission guidance to tackle implementation issues related to difficulties in interpreting the existing legislation, and examining new soft law provisions to address gaps in the legislation itself.

To improve competition, bilateral consultations are held with Member States to progressively phase out price regulation, starting with prices below costs. Should it be clear that Member State interventions in price setting are not proportionate, justified by the general economic interest or not compliant with any other condition specified in the current EU acquis 229 , then enforcement action is taken under the existing acquis and recent Court judgements, which require these criteria. Section 7.1.1 of the Evaluation argues that the regulation of electricity and gas prices limits consumer choice, restricts competition, and discourages investment.

To improve consumer engagement, the Commission issues an interpretative note on the existing provisions in the Electricity and Gas Directives covering switching-related fees. Section 7.1.1 and Annex IV of the Evaluation show that the current framework remains both complex and open to interpretation with regard to the nature and scope of certain key obligations.

The Commission works to ensure the dissemination and uptake of the key cross-sectorial principles for comparison tools. Enforcement action follows. Nevertheless, Section 7.3.5 and Annex V of the Evaluation show that the relevance of the existing legislation is challenged by the fact that it is not adapted to reflect new ways of consumer-market interaction, such as through comparison tools.

The Commission also develops a Recommendation on energy bills that builds upon the recommendations prepared by the Citizen's Energy Forum's Working Group on e-Billing and Personal Energy Data Management 230 .  Section 7.1.1 and Annex V of the Evaluation show that there is poor consumer satisfaction with energy bills, and poor awareness of information conveyed in bills. This suggests that there may still be scope to improve the comparability and clarity of billing information.

Finally, to better protect energy poor and vulnerable consumers 231 , the Commission establishes the EU Energy Poverty Observatory which will contribute to the sharing of good practices and strengthens enforcement around existing requirements for National Regulatory Authorities to monitor disconnection rates – an area identified as lacking in the Evaluation (Section 7.1.1 and Annex III).

However, no action is taken to address the market failures that prevent effective data flow between market actors. As this involves tackling possible conflicts of interest among market actors, non-regulatory measures were not deemed appropriate to credibly addressing this problem driver. Section 7.3.6 and Annex IX of the Evaluation show that the current legislation was not designed to address currently known challenges in managing large, commercially valuable consumption data flows.

By tackling regulatory interventions in price setting, this option would enable suppliers to profitably develop value-added products, thus fostering innovation in energy retail markets. It would also promote the consumer-driven uptake of such innovative products by addressing switching fees, unreliable comparison tools and unclear bills – each a key barrier to consumer engagement.

5.4.4.Option 1: Flexible legislation addressing all problem drivers

Under this option, all problem drivers are addressed through new legislation that provides Member States leeway to adapt their laws to the conditions in national markets.

To improve competition, Member States progressively phase out blanket price regulation by a deadline specified in new EU legislation, starting with prices below costs. Transitional, targeted price regulation for vulnerable consumers is permitted (e.g. in the form of social tariffs), allowing a case-by-case assessment of the proportionality of exemptions to price regulation that takes into account the social and economic particularities in Member States.

To both improve competition and reduce transaction costs in the market, consumer data management rules that can be applied independently of the national data-management model are put in place. These include criteria and measures to ensure the impartiality of market actors involved in data handling, as well as the implementation of standardised, national data formats to facilitate data access. These measures aim at eliminating barriers to entry associated with data access, and helping all market actors provide a higher level of service to consumers through the efficiencies that information technology offers.

To increase consumer engagement, the use of contract termination fees is restricted. Such fees are only permissible for the early termination of fixed-term contracts, and they must be cost-reflective. Consumer confidence in comparison websites is fostered through national authorities implementing a certification tool for the most useful and reliable websites in their markets. In addition, high-level principles ensure that energy bills are clear, easy to understand, and free from unnecessary information, whilst leaving Member States some scope to tailor billing format and content to national requirements. Certain information elements in bills would be mandatory and would need to be prominently displayed to facilitate the comparison of offers and switching. 232

Finally, to better protect energy poor and vulnerable consumers, an improved, principle-based EU legal framework to support Member State action on vulnerable and energy poor consumers is put in place. A generic adaptable, definition of energy poverty based on household income and energy expenditure is included in the legislation for the first time. Member States would measure and report energy poverty with reference to household income and energy expenditure, and NRAs would publish the number of disconnections due to non-payment – figures they should already be collecting under the current legislation. These actions are taken cumulatively, on top of the non-regulatory measures on energy poverty described in Section 5.4.3.

These measures build upon the existing provisions on energy poverty in the Electricity and Gas Directives which state that Member States must adress energy poverty where it is identified. They offer the necessary clarity about the meaning of energy poverty, as well as, the transparency with regards to the number of household in energy poverty. Better monitoring of energy poverty across the EU will, on one hand, help Member States to be more alert about the number of households falling into energy poverty, and on the other hand, peer pressure will also encourage Member States to put in place measures to reduce energy poverty. Since currently available data can be used to measure energy poverty, the administrative cost is limited 233 . Likewise, the actions proposed do not condition Member States on their primary competence of social policy, hence, respecting the principle of subsidiarity.

Taken together, this option would strongly promote innovation on retail markets by ensuring that new entrants and energy service companies receive non-discriminatory access to consumer data – access that will allow these market actors to develop and offer the value-added products that (integrated) incumbents have not. A firm commitment to phase out blanket price regulation would enable suppliers in many Member States to differentiate their offers to consumers through non-price competition. And by tackling financial barriers to switching, improving the availability of comparison tools and helping consumers understand important information in their bills; this option would increase consumer engagement with the market and the selective pressure for new services.

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

Under this option, all problem drivers are addressed through new legislation that aims to provide maximum safeguards for consumers and the extensive harmonisation of Member State action throughout the EU.

To improve competition, Member States progressively phase out all blanket price regulation, starting with prices below costs, by a deadline specified in new EU legislation, as per Option 1 (flexible legislation). However, exemptions to price regulation are defined at the EU level in terms of either: a) a price threshold to be defined based on principles ensuring coverage of the cost incurred by the energy undertakings above which Member States may set retail prices; and/or b) a consumption threshold below which household may benefit from a regulated tariff.

To both improve competition and reduce transaction costs in the market, a standard consumer data handling model is enforced. This assigns the responsibility for data handling to a neutral market actor, such as a TSO or independent third-party, eliminating all possibility of conflicts of interest. Nationally standardised formats are devised to facilitate data access to all market actors concerned, including cross-border access.

To increase consumer engagement, all switching-related fees are banned, including contract termination fees. NRAs establish comparison websites to ensure consumers have access to at least one neutral comparison resource, alongside private sector offerings. In addition, the format and content of energy bills is partially harmonized through the inclusion of a standard 'comparability box' that prescriptively presents key information in exactly the same way in every EU bill.

Finally, to better protect energy poor and vulnerable consumers, a uniform EU framework to monitor energy poverty and reduce disconnections is put in place. A specific, harmonised definition of energy poverty is included in EU legislation referring to households that fall below the poverty line after meeting their required energy needs. In order to measure energy poverty, Member States survey the energy efficiency of their national housing stock and calculate the amount of energy, and costs, required to make all housing comfortable. These survey results are reported to the Commission.

In addition, a host of preventive measures on disconnections are put in place: (i) Member States are to give all customers at least two months (approximately 40 working days) notice before a disconnection from the first unpaid bill; (ii) before a disconnection, all customers receive information on sources of support, and are offered the possibility to delay payments or restructure their debts; and (iii) the disconnection of vulnerable consumers is prohibited in winter. 234 These actions are taken cumulatively, on top of the non-regulatory measures on energy poverty described in Sections 5.4.3.

As with Option 1 (Flexible legislation), this option would strongly promote innovation on retail markets through non-discriminatory access to consumer data, a firm commitment to phase out blanket price regulation, and by tackling barriers to consumer engagement. However, any negative impacts to competition resulting from the stronger, and more costly, safeguards for the vulnerable and energy poor may also reduce the availability of new services. In addition, Member States may be better suited to design disconnection safeguard schemes to ensure that synergies between general national social service provisions and disconnection safeguards are achieved.

5.4.6.Summary of specific measures comprising each Option

The following table summarizes the specific measures comprising each package of measures, as well the corresponding specific measure option considered under each high level option. 235 The detailed presentation and assessment of each measure can be found in the indicated Annex.    

Table 9: Summary of Specific Measures Examined for Problem Area IV

6.Assessment of the impacts of the various policy options

This section assesses the impacts of the options under each Problem Area. The analysis focuses on the broad impacts of those options. The impacts of the specific measures included in each option are assessed in more detail in separate annexes attached to this impact assessment.

Each option was assessed both quantitatively and qualitatively, in an effort to capture at the highest possible detail the impacts of the underlying measures within each option. When reliable quantitative analysis or information was not available, the assessment could only be performed qualitatively, based on specific criteria.

6.1.Assessment of economic impacts for Problem Area I (Market design not fit for an increasing share of variable decentralized generation and technological developments

6.1.1.Methodological Approach

6.1.1.1.Impacts Assessed

The market design options are examined on the basis of their effectiveness in addressing the identified problems and achieving the desired objectives, while at the same time facilitating the delivery of the 2030 climate and energy targets 236 in a cost-efficient and secure way for the whole of Europe.

As the examined measures focus on the better functioning of the electricity markets 237 , economic impacts are in particular analysed with respect to competition, cost-efficiency, better utilization of resources, as well as impacts on security of electricity supply.

The effect of the measures on the wholesale markets will induce indirect social impacts and have limited effect on innovation and research. The effects of energy market related polices on employment are primarily associated with the policy measures seeking to secure the achievement of the 2030 decarbonisation objectives 238 . They will therefore not be assessed in-depth for all options.

Some indirect environmental impacts are also expected, due to the different types of fuel used for power generation, as a well-functioning flexible electricity market would incentivize the increase of low carbon generation.

Other significant impacts, direct or indirect, are not expected for the examined options, unless specifically noted.

The assessment is presented individually for each option, with qualitative analysis and interpretation of quantitative results. Summary tables reporting the modelling results for all options are included in section 6.1.6.

6.1.1.2.Modelling and use of studies

For most of the quantitative analysis, the METIS 239 modelling software was used to underpin the findings on the impact of the different options. METIS is a modular energy modelling software covering with high granularity (geographical, time) the whole European power system and markets. Simulations adopted a Member State-level spatial granularity and an hourly temporal resolution for year 2030 (8760 consecutive time-steps per year), capturing also the uncertainty related to demand and RES E power generation.

For consistency with all parallel European Commission work on the 2030 Energy and Climate Framework, in the Red II, EE and Effort Sharing Regulation impact assessments, METIS was set-up (calibrated) such as to reflect as close as possible 240 the year 2030 projection of the power sector in the PRIMES EUCO27 scenario. The PRIMES EUCO27 scenario 241 , built on the EU Reference Scenario 2016, ensures a cost-efficient achievement of at least 40% GHG reduction (including agreed split of reductions between ETS and non-ETS), 27% RES and 27% EE target.

A stand-alone analysis of the impact of potential policies promoting downstream price and incentive based demand response, at all customer segments (industrial, commercial, residential), has also been undertaken (detailed information hereon can be found in Annex 3.1). The options analysed looked at how to reach the full potential of demand response in order to reduce overall system costs, considering (i) both price and incentive based demand response, and their combination, as well as (ii) the level of access of demand service providers to the market (access rules and incentives), and (iii) customers' ability to react (by means of access to required technologies-smart metering, tariff structures and knowledge) for engaging in price based demand response. The analysis focused on the assessment of the theoretical potential of demand response, based on the nature of the electricity use/ability to shift demand by different clusters of consumers, its current level, and how the different options are likely to increase the share of the theoretical potential being realised, as well as in the estimation of associated cost and benefits.

6.1.1.3.Summary of Main Impacts

Figure 8 below summarizes the annual quantified benefits of the assessed options for 2030 242 , as presented in detail in sections 6.1.2 to 6.1.5. It illustrates the significant benefits of the measures under Options 1 to adapt the market design, with annual savings in 2030 of EUR 5.9 billion only for Sub-option 1(a) (level playing field), EUR 8.6 billion for 1(b) (strengthening short-term markets) and EUR 9.5 billion for Sub-option 1(c) (demand response/distributed resources). For Option 2 (fully integrated market) the calculated benefits would amount to EUR 10.6 billion.

Figure 8: Annual cost savings for Problem Area I in 2030 by option

Source: METIS

6.1.1.4.Overview of Baseline 243 (Current Market Arrangements) 244

Under the baseline, the power system in 2030 relies heavily for energy on RES E generators, as well as conventional generation which is to a large degree inflexible. In particular, the share of RES E in electricity generation has almost reached 50%, thus being equal to the share of all other conventional generation together (i.e. gas, coal, lignite, nuclear, oil). The share of variable generation (solar and wind) in total generation approaches 30% across Europe. Concerning conventional generation, nuclear holds a 22% share, coal and lignite a 15% share, and natural gas 13%. The respective shares tend to differentiate across EU regions, based on the particularities of each region (Figure 9).

Figure 9: Shares of Electricity Generation per Region 245 in EU in the Baseline

Source: METIS

A number of rules affecting dispatch remain in place, most notably priority dispatch 246 for RES E and that certain technologies are considered as must-run 247 , reflecting current practices and nominations in the market. In fact special dispatch rules concern 60% of total installed capacity (752 GW on a total of 1,247 GW).

Figure 10: Projected Generation Capacity in 2030 per Member State in GW 248

Source: METIS

Another factor reducing the flexibility of the European power system is the limited allocation of interconnection capacity during intraday and balancing time frames, as well as the varying gate closures and products, which in practice reduce the opportunities for trading in the short-term markets and thus their liquidity.

Reserves are procured on a national level and in many cases in infrequent intervals 249 , with corresponding services mainly provided by (large) thermal generators and only in some Member States by industrial consumers.

Demand response, storage (excl. hydro) and distributed generation have very limited participation in the market. In most cases available products are not customized for these resources, minimum thresholds exist for participating in the market, etc. At the same time, a large part of the generation, mainly RES E, are not balance responsible and do not have a strong incentive to perform accurate forecasts and declare accurate schedules in the day-ahead market (the share of variable generation is about 42% of total generation capacity). As a consequence, the observed imbalances are large, leading to increased needs for frequency reserves.

The deficiencies of the current regulatory framework create significant inflexibility to the system operation; the inflexibility in turn increases further the need for reserves (notably so-called replacement reserves) 250 . Close to real-time, the TSOs can mainly rely either on units providing replacement reserves or on very flexible (and expensive) units to avoid loss of load (peakers). In this context, in METIS replacement reserves provide than 600 GWh of electricity in the baseline, mainly in Poland and South East Europe. The same applies for RES E curtailment, as curtailment is the only alternative to the encountered stress of the system and the lack of available flexible resources: 13.0 TWh of RES E is found to be curtailed on an annual basis, mainly in the Iberian Peninsula (8.3 TWh) and UK/Ireland (4.1 TWh).

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

6.1.2.1.Economic impacts

The restoration of the economic merit order curve in the wholesale electricity market has a direct and significant positive impact to the cost-efficient operation of the power system, leading to tangible reductions of the costs consumers. It would also allow to feed in (and remunerate from the market) more RES E (notably from wind and solar) to the system.

With special rules concerning unit dispatching eliminated (i.e. must-runs, priority dispatch), the TSOs are able to schedule and re-dispatch units more efficiently. As a result (in conjunction with the other measures under this option):

-total costs of the power system are reduced by 7%;

-the activation of replacement reserves is reduced by about 500 GWh;

-RES E curtailments (e.g. wind and solar) decline by 4.7 TWh 251 ; and,

-the occurrence of negative prices is completely eliminated 252 .

Figure 11 - which presents the merit order 253 at a given hour - illustrates how preferential dispatch rules for certain technologies shift the merit order to the right, resulting in price decreases but at the same time in an increase of the overall costs for the system. The example shown for biomass priority dispatch is also applicable for must-runs and priority dispatch of other (expensive) technologies. Restoring the economic merit order thus reduces the overall costs for the power system at times where these technologies would be out-of-the-money, while increasing the electricity price during these hours.

Figure 11: Merit order effect of priority dispatch

Source: METIS 

Focusing on priority dispatch, which was found to be the main distortion for the day-ahead market scheduling for the modelling 254 , the biggest impacts on generation would be observed in Denmark, UK and Finland, where biomass holds a large share of generation capacity. The removal of priority of dispatch would have a considerable effect on expensive biomass production 255 , which in most cases is dispatched out of the merit order. It can also be expected that the share of CHP generation would be negatively affected, due to the relatively inflexible character of CHP production 256 . On the other hand, removing priority dispatch rules would benefit variable RES E which could expand its production (due to the reduction in curtailments). More importantly, variable RES E producers could significantly increase their revenues due to the increase of the wholesale prices (partly due to the elimination of negative prices) 257 . Overall, the removal of priority dispatch and must-runs helps better integrating variable RES E generation and leads to significant system costs reductions and thus cost savings for consumers.

Figure 12: Effect of removal of special dispatch rules to negative prices

Source: METIS

The above also leads to an increase of the share of Combined Cycle Gas Turbines ('CCGTs') in power generation 258 . RES E generation enters the market merit order, thus catering for more efficient price formation in the day-ahead and intraday markets. The removal of priority dispatch will offer access on equal terms to all resources. Moreover, it will more than double the competitive segment of the market, which in the baseline was only 40% of the market.

As more resources participate under the same competitive rules in the markets, markets would become more competitive 259 . This implies an increase in wholesale prices as they will now reflect the actual marginal cost of generation instead of one technically lowered via rules affecting dispatch 260 . As a result, this will lead to a much more cost-efficient operation of the power system, and consequently to a 7% decrease of its total cost.

Finally, the extension of balance responsibility to all generating and consuming entities, offers a strong incentive for variable RES E and other balance responsible parties to improve their forecasting, bid more accurately in the day-ahead market and be more active in the intraday markets. This leads to smaller imbalances and a lower requirement for reserve procurement by the TSOs. In particular the needs for mFRR are reduced by around 30%. This, combined with the capability of the demand response to also participate 261  in the reserve procurement and balancing markets, leads to a more cost-efficient reserve procurement process.

6.1.2.2.Who would be affected and how

Abolishing priority dispatch and priority access would mainly affect RES E producers using biofuels and CHP 262 and operators that benefit from priority dispatch when producing using indigenous resources fuels (if their marginal costs are substantial). For low marginal cost, variable generators, such as wind and solar power plants, the impact is actually positive, which will be amplified by measures to enable RES E access to ancillary services markets.

In any event, all generators will benefit from increased transparency and legal certainty on redispatch and curtailment rules. For TSOs, the removal of priority dispatch and priority access would also facilitate grid operation.

Introducing balancing responsibilities (with exemption possibilities for emerging technologies 263 and or small installations 264 ) will mainly impact generators currently exempted or partly shielded from balancing responsibility. Accordingly, this measure will mean they have to increase their efforts to remain in balance (e.g. through better use of weather forecasts) though at the costs of being exposed to financial risks.

6.1.2.3.Administrative impact on businesses and public authorities

The removal of priority dispatch, priority access and ensuring compliance with the balancing rules would give rise to administrative impacts for RES E (and CHP) generators, in particular for operators of very small installations. This administrative impact can however be significantly reduced by facilitating aggregation, allowing the joint operation and management of a large number of small plants (as discussed in more detail under Option 1(c)).

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

6.1.3.1.Economic Impacts

Strengthening short-term electricity markets improves market coupling across time-frames, leads to a more efficient utilization of interconnector capacity and reduces the amount of required reserves, as well as their cost.

The efficiency of the intraday markets is improved due to the harmonization of their market specifications, including the transition to continuous trade and harmonisation of gate closures, as well as by an improved allocation of interconnector capacity across time-frames. Harmonising intraday markets across Europe 265 allows to further reduce RES E curtailment by 460 GWh and the utilisation of replacement reserves by 100 GWh. Note that curtailment is not only reduced in countries where implicit auctions were not implemented in Option 1(a) (level playing field), but in already implicitly coupled regions too. Thus, extending the coupled area also benefits already coupled countries such as Germany, since it can export more of its variable RES generation. The effects are illustrated in Figure 13.

Figure 13: Positive impacts of harmonising intraday markets across Europe 266  

Source: METIS

By improving the methodologies for reserve dimensioning and procurement of balancing reserves, the need for balancing reserves is further reduced compared to Option 1(a). Certain improvement comes from the separation of the bids and prices for up and down regulation in order to reflect their true underlying marginal costs, which may be different both for generation and load 267 . The separate provision of downwards reserves greatly improves the efficiency of the system, as now thermal plants are not forced to be online to provide such reserves. Another means is via the procurement of reserves on a day-ahead basis, thus their sizing being able to reflect the hourly needs for these services, while at the same time allowing the most efficient resources at a given hour to be procured as reserves by the TSO.

The reduction in the reserve needs though is mainly achieved by the regional reserve dimensioning and more efficient exchange and sharing of balancing capacity among TSOs, as the generation and consumption patterns differs between Member States according to the generation mix, renewable energy sources and differences in energy consumption. Thus, the 79.6 GW of reserve needs (FCR + FRR) in Option 0, is reduced to 65.8 GW in Option 1(a) (level playing field) and to only 42.3 GW in Option 1(b) (strengthening short-term markets) (a reduction of 47% compared to the baseline).

It is important to note that the reduction in FRR 268 is stronger in the well-interconnected regions (about 50% reduction), namely Central Europe, the Nordics and South / South East Europe, while the benefits for UK/Ireland and Spain/Portugal are smaller due to their limited interconnection (about 20% reduction). In order to achieve these reductions from the sharing of reserves, the Member States need to ensure that sufficient interconnection capacity is reserved for this purpose, in order to ensure that despite the lower reserve requirements, the national ability to balance the system remains the same 269 . The amount of capacity that needs to be reserved for this purpose is on average approximately 6% 270 of the Net Transfer Capacities ('NTCs'), with actual values varying significantly per interconnector and per hour of the day.

Similarly, different market areas have different access to flexible resources and such flexible resources are vital to the cost-efficient integration of renewable electricity generation. TSOs may not only procure smaller volumes of reserves but providers of relatively cheap flexibility resources may supply a larger volume thereof. Hence, overall balancing market payments are reduced, while at the same time more interconnection capacity can be given to the market by reducing transmission reliability margins ('TRMs').

An interesting observation coming from the assessment is the increased generation by baseload thermal plants, compared to more flexible thermal plants. In particular, the electricity generation of nuclear, CCGTs, coal and lignite plants increases by 10%, while the generation of gas and oil peakers reduces by 50% compared to the baseline 271 . The reason is that by sharing resources between countries and decreasing reserve needs, the baseload plants do not need to retain part of their capacity on stand-by for supplying reserves and thus can increase the quantities of energy they generate. At the same time, though, flexible plants end up competing for reduced amounts of reserve needs, thus their revenues are significantly reduced compared to Option 0 (baseline) and Option 1(a) (level playing field)/ Therefore, better interconnecting markets and making them more flexible serves as a second option for bringing more flexibility into the system, complementary to but also competing with flexible generation plants.

Enhancing TSO regional coordination through the establishment of regional operational centres and by optimising market, operational, risk preparedness and network functions from the national to the regional level will entail significant efficiency gains and increase social welfare. 272 For example, the regional sizing and procurement of reserves via ROCs could lead to benefits of EUR 3.4 billion compared to benefits of EUR 1.8 billion from national sizing and procurement of reserves based on daily probabilistic methodologies. 273 Significant welfare benefits would, inter alia, derive from the more efficient use of infrastructure and from a decrease of financial losses that would otherwise result from the disconnection of demand in case of generation shortages.

6.1.3.2.Who would be affected and how

Improving short-term markets will affect all generation operators to a certain extent but it will in particular improve the ability of variable RES E operators to participate in the market.

Improving intraday and balancing markets would impact the work of the TSOs and Power Exchanges, because of their involvement in the operation of these markets. On the one hand this will require operating the system and organising trade within shorter timeframes. On the other hand, the shorter timeframe will allow TSOs to benefit from significant efficiencies and to reduce the risk of system problems. TSOs will also be affected through the need to collaborate closer with neighbouring TSOs through ROCs and through the changes to the balancing markets which they operate. This has the positive effect of requiring TSOs to consider systematically the impact of their actions on their neighbouring TSOs.

6.1.3.3.Administrative impact on businesses and public authorities

The administrative impact on businesses is marginal as compared with the baseline.

Power exchanges and TSOs would have to review and adapt their business practises to facilitate the changes to the market functioning as envisaged under this option. Notably, changes will have to be made to trading arrangements for intraday and balancing products. TSOs would collaborate through ROCs, which will have to be set up. The setting up of the ROCs can be estimated to cost between 9.9 and 35.6 million Euros per entity, depending on the functions and degree of responsibilities attributed to the ROCs. 274

Whereas these costs are not insignificant, these costs of several million Euros (which would be covered and compensated by grid fees) are minor when compared with the benefits this option will bring.

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

6.1.4.1.Economic Impacts

The series of measures assumed in this Option include (i) the adaptation of balancing products closer to what distributed resources like demand response, variable RES and small scale storage can provide, (ii) the facilitation of the participation of distributed resources in the market mainly via aggregators and (iii) stronger incentives for the roll-out of smart-meters. These measures significantly improve the efficiency of the market and the reduce costs.

The market set-up under Option 1(c) provides the opportunity to variable RES E to better manage their imbalances due to forecast errors at lower cost (due to more competitive prices), but also to receive additional revenues for any flexibility they can provide to the market. Similarly, demand is offered the incentives and capability to respond to market prices and thus complete existing electricity markets. This can be achieved by either shifting load from hours of peak demand to hours with low demand (e.g. via storage or changing consumption partterns) or by simply adjusting consumption (when load cannot be shifted or is not really needed)  275 .

Available data coming from a standalone analysis 276 performed on the impact of potential policies promoting downstream price- and incentive-based demand response, at all customer segments (industrial, commercial, residential), show that demand response can be of great service, and deliver net benefits to the system as a whole while engaging all consumer segments. More in particular, it has been demonstrated that demand response schemes can lead to a reduction of the peak demand and thereby of the required backup capacity in both the transmission and distribution networks. This also translates into lower investment needs.

The analysis has shown that in a business as usual scenario (reflected in Option 0) demand response can account for approximately 34 GW, of which 19 GW will come from incentive and 15GW from price based demand response. With a supporting policy framework in place, as in Option 1(c), demand response can account for approximately 57 GW in 2030, of which 39 GW will come from incentive and 18 GW from price based demand response.

Allowing small-scale producers, storage and consumers to participate in the market, e.g., through aggregated bids, creates incentives for demand side response and flexible solutions, pulls the above potential in the market and creates a more dynamic market. New flexible resources are made available for reserve procurement and balancing market. These resources bring significant short-term and mid-term flexibility 277 to the system, contributing to the more efficient handling of scarcity situations and integrating variable RES E. This abundance of available resources significantly reduces the cost of the power system and, most importantly, the load payments to EUR 253 billion, from EUR 278 billion in the baseline and EUR 293 billion in Option 1(a).

These reported savings 278 are mainly a result of a significant shift in the provision of reserves from thermal plants to demand side response (incl. storage) and wind. For example, while in Option 1(b) (strengthening short-term markets), gas was providing about 20 GW of reserves, hydro 19 GW and coal 3 GW, under Option 1(c) demand response partly replaces the above plants by providing 5 GW of reserves. In particular demand response and small scale storage (electric vehicles and heating storage) become the main providers of upward synchronized reserves, providing 33% of corresponding needs 279 . Wind provides an additional 90 MW of upwards synchronized reserves and 330 MW of downward synchronized reserves.

6.1.4.2.Who would be affected and how

The new provisions opening up the markets to aggregated loads and demand response will bring business opportunities for aggregators, new energy service providers, and suppliers who choose to expand their portfolio of services, but will also affect generators who are likely to face reduced turnover from lower peak prices and from providing reserves.

Furthermore, demand side flexibility, along with access to real time data coming from smart metering, will help the network operators optimise their network investments and cost-effectively manage their systems. In the case of TSOs, it also allows for the better calculation of settlements and balancing penalties based on real consumption data. On the other hand, suppliers may face higher imbalances and resulting penalties as their customers change consumption patterns.

Finally, end consumers are expected to benefit from more competition, access to wider choice, and the possibility to actively engage in price based and incentive based demand response, and hence from reduced energy bills. Even those end users who choose not to participate in demand response schemes could still profit from lower wholesale prices that result from demand response, assuming that the respective price reductions are passed on to consumers.

Box 6: The possibility of large-scale grid disconnection

6.1.4.3.Impact on businesses and public authorities

The measures proposed to enable the uptake of demand response are designed to reduce market barriers for new entrants and provide them with a stable operating framework. This is particularly important for start-ups and small and medium-sized enterprises ('SMEs') who typically offer innovative energy services and products. However, these measures may introduce an additional administrative impact for Member States and their competent authorities that will be required to clearly define in such a new setting: (i) roles and responsibilities of aggregators, as well as (ii) arrangements for consumers' entitlement to participate in price based demand response schemes, including their access to the enabling smart metering infrastructure. At the same time, access to smart metering will support consumer engagement, with better informed and more selective consumers also making it easier for NRAs to ensure proper functioning of the national (retail) energy markets 280 .

Moreover, thanks to the wider deployment of smart metering, the distribution system operators will be in a position to lighten, and improve, some of their administrative processes (linked to meter reading, billing, dis/re-connection, switching, identification of system problems, commercial losses), and offer increased customer services 281 . Similarly, transmission system operators will optimise their settlement and balancing penalty calculations, as they can make use of real time data coming from smart metering 282 .

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

6.1.5.1.Economic Impacts

By creating a centralised, fully integrated European market with market design features and procedures in place in order to deal with grid constraints and increase the available interconnection capacity offered to the market (e.g. due to the further reduction of security margins and the implementation of flow based market coupling across time-frames), the European power system can be operated even more efficiently than in the options above.

Benefits coming from the further improvements in the dimensioning and procurement of balancing reserves, now on a European level, as well as the better utilization of interconnectors by the EU Independent System Operator, lead to further reductions of the total costs compared to Option 1(c) by 1.5%. Reserve needs are further reduced by 30% compared to Option 1(c) and 63% compared to the baseline, although downwards reserves, which have a low procurement cost, are mainly procured on a national level, in order to use interconnectors mainly for exchanging electricity instead of reserving it for potential assistance to/from the neighbours.

The results indicate that although the economic benefits of moving from a national to a regional approach (Option 1(b) (strengthening short-term markets)) are significant, the move towards a more integrated European approach (Option 2) has a less significant economic value-added, as most of the benefits have already been harvested by moving towards a regional approach. On the other hand this result is also subject to the limitations of the modelling, not being able to capture the positive impacts from the more efficient operation of the network (since METIS does not include detailed network modelling).

6.1.5.2.Who would be affected and how

Under this option, TSOs, DSOs, power exchanges, electricity undertakings in general as well as Member States and competent authorities would be subject to far-reaching organisational changes (e.g. EU ISO and EU Regulator instead of national TSOs and regulators), and bound by fully harmonised rules setting out the full integration of the EU electricity market. This increases the likelihood that these rules may be difficult to implement in specific countries. This could lead to high resource requirements amongst these stakeholders, public authorities and Member States, that may be ultimately borne by consumers.

6.1.5.3.Impact on businesses and public authorities

The creation of a fully integrated European electricity market can be considered the most efficient of all the options and could, in the long run, avoid frictions from coordination and provide for a high quality electricity system with a high degree of security of supply. Under this option, it could be argued that in the long run the impact on stakeholders (e.g., TSOs, DSOs, power exchanges, electricity undertakings, etc.) may be reduced, since the integration of the electricity market would ensure a high degree of consistency.

However, this option would entail significant changes compared to the current state of the art of the electricity systems across the EU. It would be necessary to build new entities, processes and methods without being able to draw upon established practice (e.g., for the establishment of an EU ISO). Hence, there is a risk that this would lead to disruptions and would require a significant amount of time to become operational.

This option would also reduce the scope to take into account regional specificities and to draw upon established regional actors. This option would reduce the scope to develop rules at the regional level between the parties involved in organising the cross-border trade and system operation. This is because the key framework as well as the institutional structure would already be set out at the pan-European level.

In light of the above, it should be noted that the political and administrative effort required under this option would be considerable.

6.1.6.Environmental impacts of options related to Problem Area I

The measures proposed in this Problem Area aim to improve the cost-efficiency and the flexibility of the power system. By doing so, climate-friendly variable RES E can be better integrated in the market; resources are used more efficiently, and unnecessary fuel-based generation (e.g. backup generation needed because of missing rules for cross-border short-term markets) can be avoided by better using the aggregation potential of the internal market. Using the full potential of demand response has also a positive effect on the environment. If consumption can be shifted more easily to off-peak times, less backup generation from fuel-based plants is needed.

On the other hand, the removal of privileged rules for certain production forms may lead to a shift from some RES E production (i.e. biomass) to other generation types which will not only be wind and solar, but also fossil fuel-based. Therefore, although direct CO2 emissions from the power sector decrease while moving from Option 1(a) to Option 1(c), from 615 Mt CO2 to 600 Mt C02, METIS results show an increase when moving from the baseline to Option 1(a) by 60 Mt CO2. The analysis of the impact on emissions is, however, complex 283 .

The removal of priority dispatch from biomass (as well as from any other resource, including must-run generation) is pivotal in restoring the economic merit order in the power markets and significantly increasing their economic efficiency. Such a measure would discontinue the use of expensive biomass as baseload generation, replacing it by the marginal technologies (mainly coal and gas). Expensive biomass would then mainly be used in the power sector as a flexible generation technology, as well as for providing reserves.

The replacement of biomass by gas and coal could lead in the short-term to increasing emissions. The environmental impacts of the market design measures cannot though be examined in isolation from all other complementary energy and climate policies. At the EU level, the reduction in greenhouse gas emissions within the sectors covered by the EU ETS is guaranteed by the declining cap which in turn ensures that the emissions reductions objective is met cost-effectively. In the event of an increase in emissions from certain changes in the power sector mix, the corresponding increase in demand for allowances would raise the carbon price leading to an increase in abatement through other means, whether this is through a fuel switch in power generation elsewhere or an emissions reduction in other ETS sectors. Due to the binding limit on overall emissions a reduction in the use of biomass would therefore eventually result in the same amount of GHG emissions over time, with a different fuel mix at a lower total system cost.

The main effects of removing priority dispatch for biomass are therefore:

-only cheaper fractions of biomass are being used (such as waste streams), while the more expensive one is being used as flexible dispatchable generation, rather than subsidised baseload;

-overall higher CO2 prices and lower generation costs, and higher wholesale electricity prices (but most likely lower retail prices, as no subsidies will need to be recuperated outside the wholesale market).

-more favourable conditions for gas, with more operating hours;

The possible increase in emissions in the power sector is in reality the effect of current energy policies for RES E (and specifically the incentives given by the subsidization of biomass) and not of electricity market related policies. By removing the distortions currently present in the electricity markets, the market is able to give clearer signals on the interactions between climate and energy policies and help identify the right balance between cost and resource efficiency and emissions reduction.

6.1.7.Summary of modelling results for Problem Area I

The analysis shows that although today electricity markets function much better than in the past, there are still significant gains to be harvested. Restoring the merit order and creating a level-playing field for all technologies can reduce the operational cost 284 from EUR 83.4 billion in Option 0 to EUR 77.5 billion in Option 1(a). Another EUR 2.7 billion can be saved by further strengthening and linking the short-term markets; EUR 0.9 billion by better integrating demand response and RES E into the market; and EUR 1.1 billion from fully integrating EU markets. Overall, the measures under Option 1(c) can lead to cost reductions up to 11.4% compared to the baseline, while the additional measures under Option 2 would raise this to 12.7%.

When considering the above results, three important points need to be made. First of all the cost saving estimates for each option are directly related to the volume of traded energy (and reserves) they concern. Option 1(a) (level playing field) affects all market frames, but most notably the day-ahead, where the largest volume of trades takes place. Options 1(b) (strengthening short-term markets) and Option 2 (fully integrated markets) focus on interconnections (for all market time frames), intraday and balancing; traded volumes there are only a fraction of the ones of the day-ahead. Option 1(c) (demand response/distributed resources) concerns mainly the balancing and reserve markets 285 . Secondly, the effect of the measures on the intraday and balancing traded volumes is much greater, but more difficult to quantify, as it is bi-directional (upwards and downwards compared to the day-ahead scheduled energy) and complementary to the day ahead market 286 . Finally the proposed blocks of measures were deemed as the most efficient ones, but also were found to have limited impact on the reported results 287 .

Apart from the cost savings, which relate only to the generation side costs, it is important to also examine the final cost of the wholesale market for the consumers, referred to below as 'Load Payments' (see Glossary). With the removal of all special rules affecting dispatch, the wholesale price begins reflecting the actual marginal value of electricity and thus increases; this affects also the Load Payments which increase by 5%. Subsequent Options though bring more resources into the market, better utilizing the interconnections and further improving the cost-efficiency of the market, gradually reducing the Load payments by 6% in Option 1(b) (strengthening short-term markets), 9% for Option 1(c) (demand response/distributed resources) and 11.5% for Option 2 (fully integrated market) compared to the baseline. The above are equivalent to a reduction of the wholesale market cost for the consumer 288 from 78 EUR/MWh in the baseline to 71 EUR/MWh for Option 1(c) and 70 EUR/MWh for Option 2.

Table 10: Monetary Impacts (in billion EUR) of the assessed Options (for EU28+NO+CH in 2030)

Source: METIS

The monetary impacts described in Table 10 are very closely linked to the impacts of the measures on the wholesale prices. In Option 1(a) (level playing field) the increase of the competitive segment of the market from 40% (due to priority dispatch and must-runs) to 100% is the main driver for a more cost-efficient operation of the system, with no negative prices observed in the performed model runs, leading in the end to higher day-ahead prices. In parallel the reserve prices are generally lowered, due to the reduction of the inflexibility in the system. Only mFRR upwards prices increase, as these services are now primarily offered by peaking units.

In Options 1(b) (strengthening short-term markets) the trends reverse, as more resources enter the market, thus lowering day-ahead prices. The better utilized interconnection capacity and the improved functioning of the reserve markets allows baseload plants to produce more electricity in the day-ahead, while the more flexible (and expensive) plants become the main providers of reserves. As a consequence, balancing prices tend to increase (together with intraday prices). Subsequently, the introduction of demand response and the provision of reserves by RES E in Option 1(c) (pulling demand response and distributed resourced into the market) further lower wholesale prices (as more resources enter the market), with the exception of downwards reserve prices which increase 290 . Finally the impacts of Option 2 (fully integrated markets) are similar to the ones of Option 1(b) (strengthening short-term markets).

Table 11: Impacts (EUR/MWh) to Average Annual Wholesale Prices (for EU28 in 2030)

Source: METIS

An interesting aspect to examine is the distributional impact of the various options on the generator surplus (i.e. revenues above cost) and consumer surplus (i.e. cost below VoLL). It is important to note that this should not be interpreted as an investment or "missing money" analysis, since the modelling used here is static (based on the same set of capacities across the options). The issue of investments is analysed in Section 6.2.6.3, using a dynamic investment model (PRIMES/OM).

With the day-ahead prices significantly affected by the measures, so does generator surplus (i.e. revenues above cost). The distributional impacts on the market players though are concentrated on thermal generators, with competitive RES E generators even increasing their day-ahead revenues (not considering the additional revenues from the other markets).

Although in the baseline thermal generation seems to be making reasonable revenues, sufficient in many cases to cover fixed costs – especially for gas units – the improvements in the market design introduced in Options 1(b) (strengthening short-term markets), 1(c) (demand response/distributed resources) and 2 (fully integrated markets) lead to a significant decrease of their revenues, turning their operation to loss-making. Note, this result is a large extent due to the static modelling approach followed here and the increased competition in the market, as a result of bringing more resources into it and better utilising interconnections (thus better sharing national resources across EU). With the power generation capacities remaining constant across Options, this leads to a market with increasing resources participating (to the point of oversupply) and more intense competition, thus shrinking revenues.

Table 12: Generator Surplus 292 (in EUR/kW) for different plant categories (for EU28 in 2030)

Source: METIS

Similarly, the introduced measures have certain consequences on the generation production, although these tend to be relatively limited. Summarizing what has already been discussed in the dedicated assessment of each option, and presented in Table 13:

-The main impact on the electricity generation patterns appears in Option 1(a), when dispatch begins reflecting the economic merit order. Most notably, biomass generation is replaced mainly by gas and coal generation.

-Otherwise, generation patterns remain relatively stable across Options, except for some shifting of gas generation to nuclear in Option 1(b) (strengthening short-term markets). This comes as a result of the more efficient interconnection allocation and procurement of reserves, which leads to the utilisation of nuclear and lignite plants mainly for producing energy, while the more expensive gas plants are used more for reserves and balancing.

-RES E curtailment and activation of replacement reserves is steadily reduced across all options, as all measures introduce more and more flexibility to the system. In fact replacement reserves are no longer needed in Option 2.

-Procurement of Balancing Reserves also decreases substantially, from 79.6 GW in the baseline to only 29.6 GW in Option 2. The gradual drop in the required reserves is an outcome of the specific measures assumed in each case and explained in more detail in the assessment of the respective options.

Table 13: System Operation Results (for EU28+NO+CH in 2030)