(1)

Very high prices and volatility in electricity markets have been observed since September 2021. As set out by the European Union Agency for the Cooperation of Energy Regulators (ACER) in its final assessment of the EU wholesale electricity market design of April 2022, this is mainly a consequence of the high price of gas, which is used as an input to generate electricity.

(2)

The escalation of the Russian war of aggression against Ukraine, which is a Contracting Party of the Energy Community Treaty (4), and the related international sanctions since February 2022 have led to a gas crisis, have disrupted global energy markets, have exacerbated the problem of high gas prices, and have had a significant knock-on impact on electricity prices. The Russian war of aggression against Ukraine has also caused uncertainty on the supply of other commodities, such as hard coal and crude oil, used by power-generating installations. That uncertainty has resulted in a substantial additional increase in the volatility of electricity prices. The reduced availability of several nuclear reactors and the low hydropower output have further amplified the increase in electricity prices.

(3)

As a response to that situation, the Commission, in its communication of 13 October 2021 on ‘Tackling rising energy prices: a toolbox for action and support’, proposed a toolbox of measures that the Union and its Member States may use to address the immediate impact of high energy prices on household customers and businesses, including income support, tax breaks, energy savings and storage measures and to strengthen resilience to future price shocks. In its communication of 8 March 2022 on ‘REPowerEU: Joint European Action for more affordable, secure and sustainable energy’, the Commission outlined a series of additional measures to strengthen the toolbox and to respond to rising energy prices. On 23 March 2022, the Commission also established a temporary State aid framework to allow certain subsidies to soften the impact of high energy prices.

(4)

In its communication of 18 May 2022 the Commission presented its ‘REPowerEU plan’, which introduced additional measures focusing on energy savings, diversification of energy supplies, increased energy efficiency target and accelerated roll-out of renewable energy aiming to reduce the Union’s dependence on Russian fossil fuels, including a proposal to increase the Union’s 2030 target for gross final consumption of renewable energy to 45 %. Furthermore, the communication of the Commission of 18 May 2022 on ‘Short-Term Energy Market Interventions and Long-Term Improvements to the Electricity Market Design — a course for action’, in addition to setting out additional short-term measures to tackle high energy prices, identified potential areas for improving the electricity market design and announced the intention to assess those areas with a view to changing the legislative framework.

(5)

In order to address, urgently, the energy price crisis and security concerns and to tackle the price hikes for citizens, the Union adopted several legal acts, including Regulation (EU) 2022/1032 of the European Parliament and of the Council (5), which established a strong gas storage regime and Council Regulation (EU) 2022/1369 (6), which provided for effective demand reduction measures for gas and electricity, Council Regulation (EU) 2022/1854 (7), which established price limiting regimes to avoid windfall profits in both gas and electricity markets, and Council Regulation (EU) 2022/2577 (8), which established measures to accelerate the permit-granting procedures for renewable energy installations.

(6)

A well-integrated energy market, which builds on Regulations (EU) 2018/1999 (9), (EU) 2019/942 (10) and (EU) 2019/943 (11) of the European Parliament and of the Council, and Directives (EU) 2018/2001 (12), (EU) 2018/2002 (13) and (EU) 2019/944 (14) of the European Parliament and of the Council, together commonly referred to as the Clean energy for all Europeans package, adopted in 2018 and 2019 (the ‘Clean Energy Package’), allows the Union to reap the economic benefits of a single energy market in all circumstances, ensuring security of supply and sustaining the decarbonisation process to achieve the Union’s climate neutrality objective. Cross-border interconnectivity also ensures a safer, more reliable and efficient operation of power systems, and better resilience to short-term price shocks.

(7)

Strengthening the internal energy market and achieving the climate and energy transition objectives require a substantial upgrade of the Union’s electricity network to be able to host vast increases of renewable generation capacity, with weather-dependent variability in generation amounts and changing electricity flow patterns across the Union, and to be able to address new demand such as electric vehicles and heat pumps. Investment in grids, within and across borders, is crucial to the proper functioning of the internal electricity market, including security of supply. Such investment is necessary to integrate renewable energy and demand in a context where they are located further apart than in the past and, ultimately, to deliver on the Union climate and energy targets. Therefore, any reform of the Union’s electricity market should contribute to a more integrated European electricity network, with a view to ensuring that each Member State reaches a level of electricity interconnectivity in accordance with the electricity interconnection target for 2030 of at least 15 % pursuant to Article 4, point (d)(1), of Regulation (EU) 2018/1999, that that interconnection capacity is used as much as possible for cross-border trade and that the Union’s electricity network and connectivity infrastructure are built or upgraded, such as the Union projects of common interest established pursuant to Regulation (EU) 2022/869 of the European Parliament and of the Council (15). Adequate connectivity should be provided to all Union citizens and undertakings as this can result in major opportunities for them to participate in the energy transition and the digital transformation of the Union. Special consideration should be given to the outermost regions referred to in Article 349 of the Treaty on the Functioning of the European Union (TFEU), which recognises their specific constraints and provides for the adoption of specific measures in their regard.

(8)

The current electricity market design has, inter alia, helped the emergence of new and innovative products, services and measures on retail electricity markets, supporting energy efficiency and the uptake of renewable energy and enhancing choice to help consumers reduce their energy bills including through small-scale generation installations and emerging services for providing demand response. Building on and seizing the potential of the digitalisation of the energy system, such as active participation by consumers, is a key element of future electricity markets and systems in the Union. At the same time, there is a need to respect consumer choices and allow consumers to benefit from a variety of contractual offers, and to shield household customers from high prices during an energy crisis. Energy system integration is intended to be the planning and operation of the energy system as a whole, across multiple energy carriers, infrastructures and consumption sectors, by creating stronger links between them, in synergy with each other and supported by digitalisation with the objective of delivering secure, affordable, reliable and sustainable energy.

(9)

In the context of the energy crisis, the current electricity market design has revealed a number of shortcomings and unexpected consequences linked to the impact of high and volatile fossil fuel prices on short-term electricity markets, which expose households and undertakings to significant price spikes and resulting effects on their electricity bills.

(10)

A faster deployment of renewable energy and clean flexible technologies constitutes the most sustainable and cost-effective way of structurally reducing the demand for fossil fuels for electricity generation and enabling direct consumption of electricity through the electrification of energy demand and energy system integration. Due to their low operational costs, renewable sources can have a positive impact on electricity prices across the Union and reduce the consumption of fossil fuels.

(11)

The changes to the electricity market design should ensure that the benefits from increasing renewable power deployment, and the energy transition as a whole, are brought to consumers, including the most vulnerable ones, and ultimately shield them from energy crises and avoid more household customers falling into an energy poverty trap. Those changes should mitigate the impact of high fossil fuel prices, in particular that of gas, on electricity prices, aiming to allow household customers and undertakings to reap the benefits of affordable and secure energy from sustainable renewable and low carbon sources in the longer term, as well as of energy efficient solutions in reducing overall energy costs, which may reduce the need for power grid and generation capacity expansion.

(12)

The reform of the electricity market design aims to achieve affordable and competitive electricity prices for all consumers. As such, that reform should benefit not only household customers but also the competitiveness of the Union’s industries by facilitating the investment in clean technology that they require to meet their net zero transition paths. The energy transition in the Union needs to be supported by a strong clean technology manufacturing basis. Those reforms will support the affordable electrification of industry and the Union’s position as a global leader in terms of research and innovation in clean energy technologies.

(13)

Well-functioning and efficient short-term markets are a key tool for the integration of renewable energy and flexibility sources into the electricity market and enable energy system integration in a cost-effective manner.

(14)

Intraday markets are particularly important for the integration of variable renewable energy sources in the electricity system at the least cost as they give the possibility to market participants to trade shortages or surplus of electricity closer to the time of delivery. Since variable renewable energy generators are only able to accurately estimate their production close to the delivery time, it is crucial for them to maximise trading opportunities via access to a liquid market as close as possible to the time of delivery of the electricity. The gate closure time of the cross-zonal intraday market should therefore be shortened and set closer to real time in order to maximise the opportunities for market participants to trade shortages and surplus of electricity and contribute to better integrating variable renewable energy sources into the electricity system. Where that change creates security of supply risks and to allow for a cost-efficient transition to the shorter cross-zonal gate closure time, the transmission system operators should have the possibility to request a derogation, on the basis of an impact assessment and subject to approval by the regulatory authority concerned, in order to obtain an extension of the implementation timeline. That request should include an action plan with concrete steps towards the implementation of the new intraday cross-zonal gate closure time.

(15)

It is therefore important for the intraday markets to adapt to the participation of variable renewable energy technologies such as solar and wind energy as well as to the participation of demand response and energy storage. The liquidity of the intraday markets should be improved with the sharing of the order books between market operators within a bidding zone, also when the cross-zonal capacities are set to zero or after the gate closure time of the intraday market. In order to ensure that order books are shared between nominated electricity market operators (NEMOs) in the day-ahead and intraday market coupling time frames, NEMOs should submit all orders for day-ahead and intraday products, and products with the same characteristics to the single day-ahead and intraday coupling and should not organise the trading of day-ahead or intraday products, or products with the same characteristics outside the single day-ahead and intraday coupling. To address the inherent risk of discrimination in the trading of day-ahead and intraday products inside and outside the single day-ahead and intraday coupling, and the consequent draining of liquidity in the Union’s coupled electricity markets, that obligation should apply to NEMOs, to undertakings which directly or indirectly exercise control over a NEMO, and to undertakings which are directly or indirectly controlled by a NEMO. To improve the transparency on the markets, the market participants should provide, where applicable, information by generation units without prejudice to the presentation of bids in accordance with the relevant framework in each Member State.

(16)

In addition, short-term electricity markets should ensure that small-scale flexibility service providers can participate by lowering the minimum bid size.

(17)

To ensure the efficient integration of electricity generated from variable renewable energy sources and to reduce the need for fossil-fuel based electricity generation in situations of regional or Union-wide electricity price crisis, it should be possible for Member States to request system operators to propose the procurement of a peak-shaving product enabling additional demand response in order to contribute to decreasing consumption in the electricity system. The proposal for a peak-shaving product should be assessed by the regulatory authority concerned as regards achieving a reduction of electricity demand and a reduction of the impact on wholesale electricity price during peak hours. As the peak-shaving product aims to reduce and shift the electricity consumption and in order to avoid increasing of greenhouse gas emissions, the activation of the peak-shaving product should not imply starting fossil fuel-based generation located behind the metering point. As the peak-shaving product is intended to be applied only in limited situations of regional or Union-wide electricity price crisis, its procurement may take place up to one week ahead of releasing additional demand response capacities. System operators should be able to activate the peak-shaving product before or within the day-ahead market time frame. Alternatively, it should be possible for the peak-shaving product to be activated automatically based on a pre-defined electricity price. In order to verify volumes of reduction of electricity consumption, the system operator should use a baseline reflecting the expected electricity consumption without the activation of the peak-shaving product, and should, after consulting market participants, develop a baseline methodology. That methodology should be approved by the regulatory authority concerned. ACER should assess the impact of using peak-shaving products on the Union electricity market, taking into account the need for peak-shaving products not to unduly distort the functioning of the electricity markets or to cause a redirection of demand response towards peak-shaving products, and should be able to issue recommendations to regulatory authorities to be taken into account in their assessment at national level. Furthermore, ACER should assess the impact of developing peak-shaving products on the Union electricity market under normal circumstances. On the basis of that assessment, the Commission should be able, where appropriate, to submit a legislative proposal to amend Regulation (EU) 2019/943 in order to introduce peak-shaving products outside electricity price crisis situations.

(18)

In order to be able to actively participate in the electricity markets and to provide flexibility, consumers are progressively equipped with smart meters. However, in a number of Member States the roll-out of smart metering systems is still slow so it is imperative that Member States improve the conditions for the installation of smart metering systems, with the objective of reaching a full coverage as soon as possible. However, transmission system operators, distribution system operators and relevant market participants, including independent aggregators, should be able to use, upon the consent of the final customer, data from dedicated measurement devices, in accordance with Articles 23 and 24 of Directive (EU) 2019/944 and other relevant Union law, including data protection and privacy law, in particular Regulation (EU) 2016/679 of the European Parliament and of the Council (16). In addition, only in those cases where smart metering systems are not yet installed and in cases where smart metering systems do not provide for the sufficient level of data granularity, transmission system operators and distribution system operators, upon the consent of the final customer, should use data from dedicated measurement devices for the observability and settlement of flexibility services such as demand response and energy storage. Enabling the use of data from dedicated measurement devices for observability and settlement should facilitate the active participation of the final customers in the market and the development of their demand response. The use of data from those dedicated measurement devices should comply with quality requirements relating to the data.

(19)

This Regulation establishes a legal basis for the processing of personal data in accordance with Regulation (EU) 2016/679. Member States should ensure that all principles and obligations relating to processing of personal data laid down in Regulation (EU) 2016/679 are met, including on data minimisation. Where the objective of this Regulation can be achieved without the processing of personal data, data controllers should rely on anonymised and aggregated data.

(20)

Consumers and suppliers need effective and efficient forward markets to cover their long-term price exposure and decrease their dependence on short-term prices. To ensure that energy customers across the Union are able to fully benefit from the advantages of integrated electricity markets and competition across the Union, the Commission should assess the impact of possible measures to improve the functioning of the Union’s electricity forward markets such as the frequency of allocation, the maturity and the nature of long-term transmission rights, ways to strengthen the secondary market and the possible introduction of regional virtual hubs.

(21)

The part of the assessment related to the possible introduction of regional virtual hubs should, inter alia, cover the implications regarding pre-existing intergovernmental agreements related to cross-border joint ownership of power plants. If introduced, regional virtual hubs would reflect the aggregated price of multiple bidding zones and provide a reference price, which should be used by market operators to offer forward hedging products. To that extent, regional virtual hubs should not be understood as entities arranging or executing transactions. The regional virtual hubs, by providing a reference price index, would enable the pooling of liquidity and provide additional hedging opportunities to market participants. In order to ensure uniform conditions for the implementation of this Regulation, implementing powers should be conferred on the Commission to further specify, where necessary, measures and tools on the design of the Union’s electricity forward markets, including as regards the introduction of regional virtual hubs. Those powers should be exercised in accordance with Regulation (EU) No 182/2011 of the European Parliament and of the Council (17).

(22)

To enhance the possibilities of market participants for hedging, the role of the single allocation platform established in accordance with Commission Regulation (EU) 2016/1719 (18) should be expanded. The single allocation platform should act as an entity offering allocation and facilitating the trading of financial long-term transmission rights on behalf of the transmission system operators between the different bidding zones and, where relevant, the regional virtual hubs.

(23)

Network tariffs should incentivise transmission system operators and distribution system operators to use flexibility services through further developing innovative solutions to optimise the existing grid and to procure flexibility services, in particular demand response or energy storage. To that end, network tariffs should be designed to take into account the operational and capital expenditures of system operators or an efficient combination of both so that they can operate the electricity system cost-efficiently. The requirement for cost-reflectiveness should not restrict the opportunity to redistribute costs efficiently where locational- or time-variant network charges are applied. This would further contribute to integrating energy from renewable sources at the least cost for the electricity system and enable final customers to value their flexibility solutions. Regulatory authorities will play a central role in ensuring that sufficient investment is provided for the necessary grid development, expansion and reinforcement. Regulatory authorities should promote public acceptance and the use of anticipatory investment, encouraging the acceleration of grid development to meet the accelerated deployment of renewable generation, including, where appropriate, in designated renewables acceleration areas and smart electrified demand.

(24)

Offshore renewable energy sources, such as offshore wind, ocean energy and floating photovoltaic, will play an instrumental role in building a power system largely based on renewable energy sources and in ensuring climate neutrality by 2050. There are, however, substantial obstacles to their wider and efficient deployment preventing the massive scale up needed to achieve those objectives. Similar obstacles could arise for other offshore technologies in the future. In order to reduce investment risk for offshore project developers, instruments such as power purchase agreements (PPAs) or two-way contracts for difference could be used to facilitate the development of offshore projects. For offshore hybrid projects connected to more than one market in an offshore bidding zone, there is an additional risk associated with the unique topographical situation related to market access. To reduce the risks for such projects, transmission system operators should compensate where, in the validated capacity calculation results, they either have not made available the capacity agreed in the connection agreements on the interconnector or have not made available the capacity on the critical network elements pursuant to the capacity calculation rules laid down in Article 16(8) of Regulation (EU) 2019/943, or both. Transmission system operators should pay no compensation if, in the validated capacity calculation results, they have made available the capacity of the interconnector at or above the connection agreement requirements as well as the capacity on critical network elements in accordance with the rules laid down in Article 16(8) of Regulation (EU) 2019/943. In the respective connection agreement with the offshore renewable electricity generation plant operator, transmission system operators should strive to give the total agreed capacity as firm, not flexible, and in line with the framework for connection agreements established in Directive (EU) 2019/944. Member States should be informed sufficiently in advance about the connection agreement. Compensation should be payable either if the available transmission capacities are reduced to the extent that the full amount of electricity generation that the offshore renewable electricity generation plant would have otherwise been able to export cannot be delivered to the surrounding markets, or where, despite being able to export, there is a corresponding price decrease in the offshore bidding zone due to capacity reductions as compared to without-capacity reductions, or both. The compensation should be paid from congestion income. It should apply where one or more transmission system operators have not made sufficient capacity available to export the electricity generation capability on their respective interconnector up to the capacity agreed in the connection agreement, and should be provided by those transmission system operators. In the interest of regional fairness, if the insufficient capacity is due to other transmission system operators having not made available the capacity on their critical network elements, pursuant to the capacity calculation rules laid down in Article 16(8) of Regulation (EU) 2019/943, the costs of compensation should be shared proportionately between those transmission system operators in line with the polluter pays principle. In addition, any compensation not covered by that proportionate sharing may be divided between the relevant parties in the Member States involved in the offshore hybrid project as part of their cost sharing arrangements. That compensation should not result in overcompensation and is intended to balance the reduced revenues of offshore renewable electricity generation plant operators due to reduced access to interconnected markets. It should be related only to the production capability available to the market, which may be weather dependent and which excludes the outage and maintenance operations of the offshore project. The compensation in the case of a lack of access to the transmission network should not be interpreted as constituting priority dispatch and should be aligned with the principles of non-discrimination and maximisation of cross-border capacities for trade pursuant to Article 16(4) of Regulation (EU) 2019/943. Moreover, there should be no double-compensation for the same risk covered under that provision, for example if the risk is already covered under a contract for difference or another relevant support scheme. Details of that compensation mechanism and the methodology for the implementation to be developed including the conditions under which the measure may expire, such as the existence of sufficient demand within the offshore bidding zone, for example a large electrolyser, or direct access to a sufficient number of markets for the risk to disappear, are intended to be further elaborated in an implementing act including, where relevant, through amendments to Commission Regulation (EU) 2015/1222 (19).

(25)

In the day-ahead wholesale market, the power plants with lower marginal costs are dispatched first, but the price received by all market participants is set by the last power plant needed to cover the demand, which is the power plant with the highest marginal costs, when the markets clear. In that context, the energy crisis has shown that a surge in the price of gas and hard coal can lead to exceptional and lasting increases of the prices at which the gas and coal-fired generation facilities bid in the day-ahead wholesale market. That in turn has led to exceptionally high prices in the day-ahead market across the Union, as gas and coal-fired generation facilities are often the plants with the highest marginal costs needed to meet the demand for electricity.

(26)

Given the role of the price in the day-ahead market as a reference for the price in other wholesale electricity markets, and the fact that all market participants receive the clearing price, the technologies with significantly lower marginal costs have consistently recorded high revenues.

(27)

To reach the Union’s decarbonisation targets and the objectives set out in the REPowerEU plan to become more energy independent, the Union needs to accelerate the deployment of renewable energy at a much faster pace. In view of the investment needs required to achieve those goals, the market should ensure that a long-term price signal is established.

(28)

In that framework, Member States should strive to create the right market conditions for long-term market-based instruments, such as PPAs. PPAs are bilateral purchase agreements between producers and buyers of electricity that are concluded on a voluntary basis and are based on market price conditions without regulatory interventions in price-setting. PPAs provide long-term price stability for the customer and the necessary certainty for the producer to take the investment decision. Nevertheless, only few Member States have active PPA markets and buyers are typically limited to large companies, including because PPAs face a set of barriers, in particular the difficulty to cover the risk of payment default from the buyer in those long-term agreements. Member States should take into consideration the need to create a dynamic PPA market when setting the policies to achieve the energy decarbonisation objectives laid down in their integrated national energy and climate plans. When designing measures directly affecting PPAs, Member States should respect possible legitimate expectations and take into account the effects of those measures on existing and future PPAs.

(29)

In accordance with Directive (EU) 2018/2001, Member States are to assess the regulatory and administrative barriers to long-term renewables PPAs, and to remove unjustified barriers and disproportionate or discriminatory procedures or charges, and to promote the uptake of such agreements. In addition, Member States are to describe policies and measures facilitating the uptake of renewables PPAs in their integrated national energy and climate plans. Without prejudice to that obligation to report on the regulatory context affecting the PPA market, Member States should ensure that instruments to reduce the financial risks associated to the buyer defaulting on its long-term payment obligations in the framework of PPAs are accessible to customers that face entry barriers to the PPA market and that are not in financial difficulty. Member States should be able to decide to set up a guarantee scheme at market prices where private guarantees are not accessible or insufficiently accessible. Where a Member State sets up such a guarantee scheme, it should include provisions to avoid lowering the liquidity in the electricity markets, such as by using financial PPAs. Member States could decide to facilitate the aggregation of demand for PPAs from customers that individually face entry barriers to the PPA market, but they should, collectively, be able to provide an attractive offer for PPAs to producers. Member States should not provide support to PPAs for the purchase of electricity generated from fossil fuels. Member States should be able to limit themselves to supporting only guarantee schemes that support new renewable energy generation, in line with their decarbonisation policies, in particular where the market for renewables PPAs is not sufficiently developed. While the default approach should be non-discrimination between consumers, Member States could decide to target those instruments to specific categories of consumers, applying objective and non-discriminatory criteria. In that framework, Member States should ensure appropriate coordination, including with facilities provided at Union level, for example by the European Investment Bank (EIB).

(30)

Member States have at their disposal several instruments to support the development of PPA markets when designing and allocating public support. Allowing renewable energy project developers participating in a public support tender to reserve a share of the generation for sale through a PPA would contribute to nurture and grow PPA markets. In addition, as part of those tenders’ evaluation, Member States should endeavour to apply criteria to incentivise the access to the PPA market for actors that face entry barriers, such as small enterprises and medium-sized enterprises, giving preference to bidders presenting a signed PPA or a commitment to sign a PPA for part of the project’s generation from one or several potential buyers that face difficulties to access the PPA market.

(31)

To contribute to the transparency and development of PPA markets at Union and Member State level, ACER should publish an annual assessment on those markets, assess the need to develop and issue voluntary templates for PPAs and develop them if the assessment concludes there is such a need.

(32)

Member States should pay particular attention to cross-border PPAs and remove unjustified barriers specifically related to them, allowing consumers in Member States with limited capacity to access power generated in other regions without discrimination.

(33)

Where, based on the relevant assessment, the Commission concludes that Member States require support in the removal of barriers in PPA markets, it should be able to draw up specific guidance. The main focus of such guidance should be the removal of barriers preventing the expansion of PPA markets, including cross-border PPAs. Such barriers can take many forms, from regulatory barriers, in particular disproportionate or discriminatory procedures or charges, to the role of guarantees of origin or the treatment of PPAs in the access of potential offtakers to financing solutions.

(34)

Regulation (EU) 2018/1999 provides for the use of the Union renewable energy financing mechanism as a tool to facilitate the achievement of the Union's binding target of renewable energy in 2030. Pursuant to Directive (EU) 2018/2001 as amended by Directive (EU) 2023/2413 of the European Parliament and of the Council (20), Member States are to collectively endeavour to increase the share of energy from renewable sources in the Union’s gross final consumption of energy in 2030 to 45 % in addition to the binding Union target of 42,5 %. Therefore, the Commission should assess whether measures at Union level could contribute to the achievement of the additional 2,5 % share of energy from renewable sources in the Union’s gross final consumption of energy, complementing national measures. In that context, the Commission should analyse the possibility to use the Union renewable energy financing mechanism to organise Union-level renewable energy auctions in line with the relevant regulatory framework.

(35)

Where Member States decide to support publicly financed investment by direct price support schemes in new low carbon, non-fossil fuel power-generating facilities to achieve the Union’s decarbonisation objectives, those schemes should be structured as two-way contracts for difference or equivalent schemes with the same effects such as to include, in addition to a revenue guarantee, an upward limitation of the market revenues of the generation assets concerned. Whereas the obligation pursuant to this Regulation should apply only to support for investment in new power-generating facilities, Member States should be able to decide to grant support schemes in the form of two-way contracts for difference or equivalent schemes with the same effects also for new investment aiming to substantially repower existing power-generating facilities, or to substantially increase the capacity or prolonging the lifetime of such facilities.

(36)

To ensure legal certainty and predictability, the obligation to structure direct support schemes by means of two-way contracts for difference or equivalent schemes with the same effects should apply only to contracts under direct price support schemes for investment in new power-generating facilities concluded on or after 17 July 2027. That transitional period should be five years for offshore hybrid assets connected to two or more bidding zones due to the complexity of such projects.

(37)

The participation of market participants in direct price support schemes in the form of two-way contracts for difference or equivalent schemes with the same effects should be voluntary.

(38)

The obligation to use two-way contracts for difference or equivalent schemes with the same effects is without prejudice to Article 6(1) of Directive (EU) 2018/2001.

(39)

While Directive (EU) 2024/1711 of the European Parliament and of the Council (21) amends Article 4(3), second subparagraph, of Directive (EU) 2018/2001, the other provisions of Article 4 of that Directive, which set out design principles for the support schemes for energy from renewable sources, remain applicable.

(40)

Two-way contracts for difference or equivalent schemes with the same effects would ensure that revenues of producers stemming from new investment in electricity generation which benefit from public support become more independent from the volatile prices of fossil fuels-based generation which typically sets the price in the day-ahead market.

(41)

Design principles as laid down in this Regulation should apply to direct price support schemes in the form of two-way contracts for difference or equivalent schemes with the same effects. In the assessment of such two-way contracts for difference or equivalent schemes with the same effects under State aid rules, the Commission should check compliance of those contracts or schemes with Union law which is intrinsically linked to State aid rules, such as the design principles for two-way contracts for difference or equivalent schemes with the same effects as laid down in this Regulation. The design of those two-way contracts for difference or equivalent schemes with the same effects should preserve the incentives for the power-generating facility to operate and participate efficiently in the electricity markets, in particular to reflect market circumstances. In its assessment, the Commission should ensure that the design of two-way contracts for difference or equivalent schemes with the same effects does not lead to undue distortions to competition and trade in the internal market. The Commission should, in particular, ensure that the distribution of revenues to undertakings does not distort the level playing field in the internal market in particular where no competitive bidding process can be applied. Two-way contracts for difference or equivalent schemes with the same effects could vary in duration and could include inter alia injection-based contracts for difference with one or several strike prices, a floor price, or capability or yardstick contracts for difference. The obligation to use two-way contracts for difference or equivalent schemes with the same effects does not apply to support schemes not directly linked to electricity generation, such as energy storage, and which do not use direct price support, such as investment aid in the form of upfront grants, tax measures or green certificates. To incentivise the counterparties to fulfil their contractual obligations, two-way contracts for difference or equivalent schemes with the same effects should include penalty clauses applicable in the case of undue unilateral early termination of the contract.

(42)

However, to the extent that the limitation to set out direct price support schemes in the form of two-way contracts for difference or equivalent schemes with the same effects narrows down the types of direct price support schemes that Member States are able to adopt as regards renewable energy sources, it should be limited to low carbon, non-fossil fuel technologies, with low and stable operational costs and to technologies which typically do not provide flexibility to the electricity system, while excluding technologies that are at early stages of their market deployment. This is necessary to ensure that the economic viability of generation technologies with high marginal costs is not jeopardised and to maintain the incentives of the technologies which can offer flexibility to the electricity system to bid in the electricity market based on their opportunity costs. In addition, the limitation to set out direct price support schemes in the form of two-way contracts for difference or equivalent schemes with the same effects should not apply to emerging technologies for which other types of direct price support schemes may be better placed to incentivise their uptake. The limitation should be without prejudice to the possible exemption for small-scale renewables installations and demonstration projects pursuant to Directive (EU) 2018/2001 and consider the specificities of renewable energy communities in accordance with that Directive. In view of the need to provide regulatory certainty for the producers, the obligation for Member States to apply direct price support schemes for the production of electricity in the form of two-way contracts for difference or equivalent schemes with the same effects should apply only to investment in new power-generating facilities using the sources specified in this recital.

(43)

Due to the upward limitation of the market revenues, direct price support schemes in the form of two-way contracts for difference or equivalent schemes with the same effects should provide an additional source of revenue for Member States in periods of high energy prices. To further mitigate the impact of high electricity prices on the energy bills of consumers, Member States should ensure that any revenues collected from producers subject to direct price support schemes in the form of two-way contracts for difference or equivalent schemes with the same effects, or the equivalent in financial value of those revenues, are passed on to final customers, including household customers, small enterprises and medium-sized enterprises and energy intensive undertakings. When distributing the revenues to household customers, Member States should in particular be able to favour vulnerable customers and customers affected by energy poverty. In light of the wider benefits for electricity customers resulting from investment in renewable energy, energy efficiency, and low carbon energy deployment, it should also be possible for Member States to use the revenues from two-way contract for difference or equivalent schemes with the same effects, or the equivalent in financial value of those revenues, to finance investment to reduce electricity costs for final customers and, including as regards specific economic activities such as investment in distribution grid development, renewable energy sources and electric vehicle charging infrastructure. It should also be possible for Member States to use such revenues, or the equivalent in financial value of those revenues, to finance the costs of the direct price support schemes. The redistribution of revenues should be done in a way that ensures that customers are still to some extent exposed to the price signal, so that they reduce their consumption when the prices are high, or shift it to periods of lower prices, which are typically periods with a higher share of production of electricity from renewable energy sources. In particular, Member States should be able to consider the consumption in off-peak hours in order to preserve incentives to flexibility. Member States should ensure that the level playing field and competition between the different suppliers is not affected by the redistribution of revenues to the final electricity consumers. Those principles should not be compulsory for revenues generated by contracts under direct price support schemes concluded before the date of application of the obligation to use two-way contracts for difference or equivalent schemes with the same effects. It is possible for Member States to distribute revenues from two-way contracts for difference or equivalent schemes with the same effects without that distribution constituting a retail price regulation pursuant to Article 5 of Directive (EU) 2019/944.

(44)

Furthermore, Member States should ensure that the direct price support schemes or equivalent schemes with the same effects, irrespective of their form, do not undermine the efficient, competitive and liquid functioning of the electricity markets, preserving the incentives of producers to react to market signals, including stop generating when electricity prices are below their operational costs, and of final customers to reduce consumption when electricity prices are high. Member States should ensure that support schemes do not constitute a barrier for the development of commercial contracts such as PPAs.

(45)

Therefore, two-way contracts for difference or equivalent schemes with the same effects and PPAs play complementary roles in advancing the energy transition and bringing the benefits of renewable energy and low carbon energy to consumers. Subject to the requirements introduced by this Regulation, Member States should be free to decide which instruments they use to achieve their decarbonisation objectives. Through PPAs, private investors contribute to additional renewable energy and low carbon energy deployment while locking low and stable electricity prices over the long-term. Likewise, through two-way contracts for difference or equivalent schemes with the same effects, the same objective is achieved by public entities on behalf of consumers. Both instruments are necessary to achieve the Union’s decarbonisation targets through renewable energy and low carbon energy deployment, while bringing forward the benefits of low-cost electricity generation for consumers.

(46)

The accelerated deployment of renewable energy sources necessitates a growing availability of flexibility solutions to ensure their integration to the grid and to enable the electricity system and grid to adjust to the variability of electricity generation and consumption across different time horizons. In order to foster non-fossil flexibility, the regulatory authority or another authority or entity designated by a Member State should periodically assess the need for flexibility at national level in the electricity system on the basis of the input of transmission system operators and distribution system operators and a common European methodology that is subject to public consultation and approval by ACER. The assessment of the flexibility needs of the electricity system should take into account all existing and planned investment, including existing assets that are not yet connected to the grid, with regard to sources of flexibility such as flexible electricity generation, interconnectors, demand response, energy storage or the production of renewable fuels, because of the need to decarbonise the energy system. ACER should periodically assess the national reports and draw up a report at Union level providing recommendations on issues of cross-border relevance. On the basis of the national flexibility needs report, Member States should define an indicative national objective for non-fossil flexibility, including the respective specific contributions of both demand side response and energy storage to that objective, which should also be reflected in their integrated national energy and climate plans in accordance with Regulation (EU) 2018/1999. In light of those plans, the Commission should be able to draw up a Union strategy on flexibility with a particular focus on demand response and energy storage, which is consistent with the Union’s 2030 targets for energy and climate and the 2050 climate-neutrality objective. The Commission should be able to issue a legislative proposal to accompany that Union strategy.

(47)

To achieve the indicative national objective for non-fossil flexibility, including the respective specific contributions of demand response and energy storage, and where flexibility needs are not being addressed by the removal of market barriers and existing investment, Member States should be able to apply non-fossil flexibility support schemes consisting of payments for the available capacity of non-fossil flexibility. Furthermore, Member States that already apply a capacity mechanism should consider to promote the participation of non-fossil flexibility such as demand response and energy storage by redesigning criteria or features without prejudice to the application of Article 22 of Regulation (EU) 2019/943. Member States that already apply a capacity mechanism should also be able to apply non-fossil flexibility support schemes if those schemes are necessary to achieve the indicative national objective for non-fossil flexibility, in particular while adapting their capacity mechanisms to further promote the participation of non-fossil flexibility such as demand response and energy storage. Those schemes should cover new investment in non-fossil flexibility, including investment in existing assets, including those aimed at further developing demand response flexibility.

(48)

To support environmental protection objectives, the CO2 emission limit, set out in Article 22(4) of Regulation (EU) 2019/943, should be seen as an upper limit. Therefore, Member States could set technical performance standards and CO2 emission limits that restrict participation in capacity mechanisms to flexible, fossil-free technologies in full alignment with the communication of the Commission of 18 February 2022 on ‘Guidelines on State aid for climate, environmental protection and energy’ which encourage Member States to introduce green criteria in capacity mechanisms.

(49)

As uncoordinated capacity mechanisms can have a significant impact on the internal electricity market, the Clean Energy Package introduced a comprehensive framework to better assess the need and improve the design of capacity mechanisms. Notwithstanding the necessity to limit distortions to competition and the internal market, together with an appropriate regulatory framework, capacity mechanisms can play an important role in ensuring resource adequacy, in particular during the transition towards a carbon-free system and for insufficiently interconnected energy systems. Therefore, while capacity mechanisms should no longer be considered to be measures of last resort, their necessity and design should be periodically assessed in light of the evolving regulatory framework and market circumstances. However, the procedure for the adoption of capacity mechanisms has proved to be complex. To address potential possibilities of streamlining and simplifying the process of applying for a capacity mechanism, and to ensure that adequacy concerns can be addressed by Member States in a timely manner while providing the necessary control to prevent harm for the internal market, the Commission should, by 17 January 2025 submit a detailed report assessing such possibilities. In that context, the Commission should request that ACER amend the methodology for the European resource adequacy assessment in line with the applicable process, as appropriate. After consulting the Member States, the Commission should submit proposals with a view to, as appropriate, simplifying the process of assessing capacity mechanisms by 17 April 2025.

(50)

The connection of new generation and demand installations to the grid, in particular renewable energy plants, often faces delays in grid connection procedures. One of the reasons for such delays is the lack of available grid capacity at the location chosen by the investor, which entails a need for grid extensions or reinforcements to connect the installations to the system in a safe manner. A new requirement for electricity system operators, both at transmission and distribution levels, to publish and update information on the capacity available for new connections in their areas of operation would give investors easier access to information of grid capacity availability within the system and thereby accelerate decision-making which, in turn, would accelerate the required deployment of renewable energy. That information should be updated on a regular basis, at least every month, by transmission system operators. Transmission system operators should also publish the criteria used to determine the available grid capacities, such as existing demand and generation capacities, the assumptions made for assessing the possible further integration of additional system users, the relevant information on possible energy curtailment, and the expectation of upcoming relevant network developments.

(51)

Furthermore, to tackle the problem of lengthy reply times on requests for connection to the grid, transmission system operators should provide clear and transparent information to system users about the status and treatment of their connection requests. Transmission system operators should provide such information within three months of the date of submission of the request and should update it on a regular basis, at least quarterly.

(52)

Since Estonia, Latvia and Lithuania are not yet synchronised with the Union electricity system, they face very specific challenges when organising balancing markets and the market-based procurement of ancillary services. While progress towards synchronisation is ongoing, one of the critical prerequisites for stable synchronous system operation is the availability of sufficient balancing capacity reserves for frequency regulation. However, being dependent on the Russian synchronous area for frequency management, the Baltic States were not yet in the position to develop their own functioning balancing market. The Russian war of aggression against Ukraine has substantially increased the risk for security of supply resulting from the absence of own balancing markets. Therefore, the requirements of Article 6(9), (10) and (11) of Regulation (EU) 2019/943 and of Article 41(2) of Commission Regulation (EU) 2017/2195 (22), which are designed to apply to existing balancing markets, do not yet reflect the situation in Estonia, Latvia and Lithuania, in particular as the development of balancing market requires time and new investment in balancing capacity. Estonia, Latvia and Lithuania should therefore, by way of derogation from those requirements, be entitled to conclude longer-term financial contracts to procure balancing capacity for a transitional period.

(53)

The transitional periods for Estonia, Latvia and Lithuania should be phased out as soon as possible after the synchronisation, and should be used to develop the appropriate market instruments that offer short-term balancing reserves and other indispensable ancillary services, and should be limited to the time necessary for that process.

(54)

It is intended for the Baltic States to be synchronised with the Continental Europe Synchronous Area by one double circuit line connecting Poland and Lithuania. Upon synchronisation, the capacity of that line will have to be, in large part, reserved for reliability margins in a case of unexpected outage in the Baltic System and resulting unintended deviations. Transmission system operators should continue offering maximum capacity for cross-border trading, compliant with operational security limits and considering possible contingencies in the Polish and Lithuanian systems, including those resulting from outages of high-voltage direct current lines or disconnection of the Baltic States from the Continental Europe Synchronous Area. The specific situation of that interconnection should be taken into consideration for the calculation of the total capacity and contingencies pursuant to Article 16(8) of Regulation (EU) 2019/943.

(55)

Capacity mechanisms should be open to the participation of all resources that are capable of providing the required technical performance, which may include gas-fired power plants, provided they satisfy the emission limit set out in Article 22(4) of Regulation (EU) 2019/943 as well as any national emission threshold or other objective environmental criteria which Member States may wish to apply to speed up the transition away from fossil fuels.

(56)

To support environmental protection objectives, Article 22(4) of Regulation (EU) 2019/943 sets out requirements regarding CO2 emission limits for capacity mechanisms. However, during their transition to a carbon-free system and in the aftermath to the energy crisis, Member States applying capacity mechanisms which were approved before 4 July 2019, should be able, on an exceptional basis, and as a mechanism of last resort to derogate from that CO2 emission limit for a limited period of time. Such a derogation should however be limited to existing generation capacity that started commercial production before 4 July 2019, namely before the date of entry into force of Regulation (EU) 2019/943. The request for a derogation should be accompanied by a report from the Member State concerned assessing the impact of the derogation on greenhouse gas emissions and on the energy transition. Such a report should also contain a plan with milestones to transition away from the participation of generation capacity that does not meet the CO2 emission limits in capacity mechanisms. Upon the granting of a derogation, Member States should be allowed to organise procurement processes which still have to meet all the requirements of Chapter IV of Regulation (EU) 2019/943, except for those regarding CO2 emission limits. Generation capacity that does not meet the CO2 emission limits should not be procured for a period longer than one year and for a delivery period which does not exceed the duration of the derogation. The additional procurement process open to participation of generation capacity that does not meet the CO2 emission limits should be preceded by a procurement process aiming to maximise the participation of capacity that meets the CO2 emission limits, including by letting capacity prices rising high enough to incentivise investment in such capacity.

(57)

The Commission should review this Regulation in order to ensure the resilience of the electricity market design in times of crisis and its ability to support the Union’s decarbonisation objectives, further enhance market integration and promote the necessary infrastructure investment as well as the development of a PPA market. On the basis of such review, the Commission should submit a comprehensive report to the European Parliament and to the Council, accompanied by a legislative proposal, where appropriate. In that report, the Commission should assess, in particular, the effectiveness of the current structure and functioning of the short-term electricity markets, as well as their potential inefficiencies and possible remedies and tools to be applied in crisis or emergency situations and the suitability of Union legal and financing framework on distribution grids. That report should also cover the ability to achieve the Union’s renewable and internal energy market objectives and the potential and viability of the establishment of one or several Union market platforms for PPAs.

(58)

To the extent that any of the measures provided for in this Regulation constitute State aid, the provisions concerning such measures are without prejudice to the application of Articles 107 and 108 TFEU. The Commission is competent to assess the compatibility of State aid with the internal market.

(59)

The measures provided for in this Regulation are without prejudice to the application of Regulations (EU) 2016/1011 (23) and (EU) No 648/2012 of the European Parliament and of the Council (24) and of Directive 2014/65/EU of the European Parliament and of the Council (25).

(60)

Regulations (EU) 2019/942 and (EU) 2019/943 should therefore be amended accordingly.

(61)

Since the objective of this Regulation, namely to improve the design of the integrated electricity market, in particular to prevent unduly high electricity prices, cannot be sufficiently achieved by the Member States, but can rather be better achieved at Union level, the Union may adopt measures, in accordance with the principle of subsidiarity as set out in Article 5 of the Treaty on European Union. In accordance with the principle of proportionality, as set out in that Article, this Regulation does not go beyond what is necessary to achieve that objective,

(1)

Article 2 is amended as follows:

(2)

in Article 3(2), the following subparagraph is added:

‘This paragraph shall also apply to the single allocation platform established in accordance with Regulation (EU) 2016/1719.’

(3)

in Article 4, the following paragraph is added:

(4)

Article 5 is amended as follows:

(5)

in Article 6, paragraph 9, is replaced by the following:

(6)

Article 15 is amended as follows:

(1)

Article 1 is amended as follows:

(2)

Article 2 is amended as follows:

(3)

Article 7 is amended as follows:

(4)

the following articles are inserted:

(*2)  Regulation (EU) 2016/679 of the European Parliament and of the Council of 27 April 2016 on the protection of natural persons with regard to the processing of personal data and on the free movement of such data, and repealing Directive 95/46/EC (General Data Protection Regulation) (OJ L 119, 4.5.2016, p. 1).’;"

(5)

Article 8 is amended as follows:

(6)

Article 9 is replaced by the following:

(*3)  Regulation (EU) 2018/1999 of the European Parliament and of the Council of 11 December 2018 on the Governance of the Energy Union and Climate Action, amending Regulations (EC) No 663/2009 and (EC) No 715/2009 of the European Parliament and of the Council, Directives 94/22/EC, 98/70/EC, 2009/31/EC, 2009/73/EC, 2010/31/EU, 2012/27/EU and 2013/30/EU of the European Parliament and of the Council, Council Directives 2009/119/EC and (EU) 2015/652 and repealing Regulation (EU) No 525/2013 of the European Parliament and of the Council (OJ L 328, 21.12.2018, p. 1)."

(*4)  Directive (EU) 2017/1132 of the European Parliament and of the Council of 14 June 2017 relating to certain aspects of company law (OJ L 169, 30.6.2017, p. 46)."

(*5)  Directive 2014/65/EU of the European Parliament and of the Council of 15 May 2014 on markets in financial instruments and amending Directive 2002/92/EC and Directive 2011/61/EU (OJ L 173, 12.6.2014, p. 349)."

(*6)  Regulation (EU) No 648/2012 of the European Parliament and of the Council of 4 July 2012 on OTC derivatives, central counterparties and trade repositories (OJ L 201, 27.7.2012, p. 1)."

(*7)  Regulation (EU) No 600/2014 of the European Parliament and of the Council of 15 May 2014 on markets in financial instruments and amending Regulation (EU) No 648/2012 (OJ L 173, 12.6.2014, p. 84).’;"

(7)

Article 18 is amended as follows:

(8)

in Article 19, paragraph 2 is replaced by the following:

(9)

the following chapter is inserted:

(*8)   OJ L 282, 19.10.2016, p. 4.’;"

(10)

Article 21 is amended as follows:

(11)

in Article 22(1), point (a) is deleted;

(12)

in Article 37(1), point (a) is replaced by the following:

;

(13)

in Article 50, the following paragraph is inserted:

(14)

in Article 57, the following paragraph is added:

(15)

Article 59 is amended as follows:

(16)

in Article 64, the following paragraphs are inserted:

(17)

Article 69 is amended as follows:

(18)

the following article is inserted:

(19)

in Annex I, point 1.2 is replaced by the following: