REGULATION (EU) 2019/943 OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL

of 5 June 2019

on the internal market for electricity

(recast)

(Text with EEA relevance)

THE EUROPEAN PARLIAMENT AND THE COUNCIL OF THE EUROPEAN UNION,

Having regard to the Treaty on the Functioning of the European Union, and in particular Article 194(2) thereof,

Having regard to the proposal from the European Commission,

After transmission of the draft legislative act to the national parliaments,

Having regard to the opinion of the European Economic and Social Committee (1),

Having regard to the opinion of the Committee of the Regions (2),

Acting in accordance with the ordinary legislative procedure (3),

Whereas:

(1) Regulation (EC) No 714/2009 of the European Parliament and of the Council (4) has been substantially amended several times. Since further amendments are to be made, that Regulation should be recast in the interests of clarity.

(2) The Energy Union aims to provide final customers – household and business – with safe, secure, sustainable, competitive and affordable energy. Historically, the electricity system was dominated by vertically integrated, often publicly owned, monopolies with large centralised nuclear or fossil fuel power plants. The internal market for electricity, which has been progressively implemented since 1999, aims to deliver a real choice for all consumers in the Union new business opportunities and more cross-border trade, so as to achieve efficiency gains, competitive prices and higher standards of service, and to contribute to security of supply and sustainability. The internal market for electricity has increased competition, in particular at the wholesale level, and cross-zonal trade. It remains the foundation of an efficient energy market.

(3) The Union's energy system is in the middle of its most profound change in decades and the electricity market is at the heart of that change. The common goal of decarbonising the energy system creates new opportunities and challenges for market participants. At the same time, technological developments allow for new forms of consumer participation and cross-border cooperation.

(4) This Regulation establishes rules to ensure the functioning of the internal market for electricity and includes requirements related to the development of renewable forms of energy and environmental policy, in particular specific rules for certain types of renewable power-generating facilities, concerning balancing responsibility, dispatch and redispatching, as well as a threshold for CO2 emissions of new generation capacity where such capacity is subject to temporary measures to ensure the necessary level of resource adequacy, namely, capacity mechanisms.

(5) Electricity from renewable sources from small power-generating facilities should be granted priority dispatch either via a specific priority order in the dispatching methodology or via legal or regulatory requirements for market operators to provide this electricity on the market. Priority dispatch which has been granted in the system operation services under the same economic conditions should be considered to comply with this Regulation. In any case, priority dispatch should be deemed to be compatible with the participation in the electricity market of power-generating facilities using renewable energy sources.

(6) State interventions, often designed in an uncoordinated manner, have led to increasing distortions of the wholesale electricity market, with negative consequences for investments and cross-border trade.

(7) In the past, electricity customers were purely passive, often buying electricity at regulated prices which had no direct relation to the market. In the future, customers need to be enabled to fully participate in the market on equal footing with other market participants and need to be empowered to manage their energy consumption. To integrate the growing share of renewable energy, the future electricity system should make use of all available sources of flexibility, particularly demand side solutions and energy storage, and should make use of digitalisation through the integration of innovative technologies with the electricity system. To achieve effective decarbonisation at the lowest cost, the future electricity system also needs to encourage energy efficiency. The completion of the internal energy market through the effective integration of renewable energy can drive investments in the long term and can contribute to delivering the objectives of the Energy Union and the 2030 climate and energy framework, as set out in the Commission communication of 22 January 2014 entitled ‘A policy framework for climate and energy in the period from 2020 to 2030’, and endorsed in the conclusions adopted by the European Council at its meeting on 23 and 24 October 2014.

(8) More market integration and the change towards a more volatile electricity production requires increased efforts to coordinate national energy policies with neighbours and to use the opportunities of cross-border electricity trade.

(9) Regulatory frameworks have developed, allowing electricity to be traded across the Union. That development has been supported by the adoption of several network codes and guidelines for the integration of the electricity markets. Those network codes and guidelines contain provisions on market rules, system operation and network connection. To ensure full transparency and increase legal certainty, the main principles of market functioning and capacity allocation in the balancing, intraday, day-ahead and forward market timeframes should also be adopted pursuant to the ordinary legislative procedure and incorporated in a Union legislative single act.

(10) Article 13 of Commission Regulation (EU) 2017/2195 (5) establishes a process whereby transmission system operators are able to delegate all or part of their tasks to a third party. The delegating transmission system operators should remain responsible for ensuring compliance with this Regulation. Moreover, Member States should be able to assign tasks and obligations to a third party. Such assignment should be limited to tasks and obligations carried out at national level, such as imbalance settlement. The limitations on such assignment should not lead to unnecessary changes to existing national arrangements. However, transmission system operators should remain responsible for the tasks entrusted to them under Article 40 of Directive (EU) 2019/944 of the European Parliament and of the Council (6).

(11) With regard to balancing markets, efficient and non-distortive price formation in the procurement of balancing capacity and balancing energy requires that balancing capacity contracts do not set the price for balancing energy. This is without prejudice for the dispatching systems using an integrated scheduling process in accordance with Regulation (EU) 2017/2195.

(12) Articles 18, 30 and 32 of Regulation (EU) 2017/2195 establish that the pricing method for both standard and specific products for balancing energy should create positive incentives for market participants in keeping their own balance or helping to restore the system balance in their imbalance price area, thereby reducing system imbalances and costs to society. Such pricing approaches should strive for the economically efficient use of demand response and other balancing resources, subject to operational security limits.

(13) The integration of balancing energy markets should facilitate the efficient functioning of the intraday market in order to provide the possibility for market participants to balance themselves as closely as possible to real time, enabled by the balancing energy gate closure times provided for in Article 24 of Regulation (EU) 2017/2195. Only the imbalances remaining after the end of the intraday market should be balanced by transmission system operators in the balancing market. Article 53 of Regulation (EU) 2017/2195 also provides for the harmonisation of the imbalance settlement period at 15 minutes in the Union. That harmonisation is intended to support intraday trading and foster the development of a number of trading products with the same delivery windows.

(14) In order to enable transmission system operators to procure and use balancing capacity in an efficient, economic and market-based manner, there is a need to foster market integration. In that regard, Title IV of Regulation (EU) 2017/2195 establishes three methodologies through which transmission system operators are entitled to allocate cross-zonal capacity for the exchange of balancing capacity and the sharing of reserves, when supported on the basis of a cost-benefit analysis: the co-optimisation process, the market-based allocation process and the allocation based on an economic efficiency analysis. The co-optimisation allocation process is to be performed on a day-ahead basis. By contrast, it is possible to perform the market-based allocation process where the contracting is carried out not more than one week in advance of the provision of the balancing capacity and to perform the allocation based on an economic efficiency analysis where the contracting is done more than one week in advance of the provision of the balancing capacity, provided that the volumes allocated are limited and that an assessment is carried out annually. Once a methodology for the process of allocating cross-zonal capacity is approved by the relevant regulatory authorities, early application of that methodology by two or more transmission system operators could take place to allow them to gain experience and to allow for the smooth application of that methodology by more transmission system operators in the future. The application of such methodologies should nevertheless be harmonised by all transmission system operators in order to foster market integration.

(15) Title V of Regulation (EU) 2017/2195 established that the general objective of imbalance settlement is to ensure that balance responsible parties keep their own balance or help restore the system balance in an efficient way and to provide incentives to market participants for keeping or helping to restore the system balance. To make balancing markets and the overall energy system fit for the integration of the increasing share of variable renewable energy, imbalance prices should reflect the real-time value of energy. All market participants should be financially responsible for the imbalances they cause in the system, representing the difference between the allocated volume and the final position in the market. For demand response aggregators, the allocated volume consists of the volume of energy physically activated by the participating customers' load, based on a defined measurement and baseline methodology.

(16) Commission Regulation (EU) 2015/1222 (7) sets out detailed guidelines on cross-zonal capacity allocation and congestion management in the day-ahead and intraday markets, including the requirements for the establishment of common methodologies for determining the volumes of capacity simultaneously available between bidding zones, criteria to assess efficiency and a review process for defining bidding zones. Articles 32 and 34 of Regulation (EU) 2015/1222 set out rules on review of bidding zone configuration, Articles 41 and 54 thereof set out harmonised limits on maximum and minimum clearing prices for day-ahead and intraday timeframes, Article 59 thereof sets out rules on intraday cross-zonal gate closure times, whereas Article 74 thereof sets out rules on redispatching and countertrading cost sharing methodologies.

(17) Commission Regulation (EU) 2016/1719 (8) sets out detailed rules on cross-zonal capacity allocation in the forward markets, on the establishment of a common methodology to determine long-term cross-zonal capacity, on the establishment of a single allocation platform at European level offering long-term transmission rights, and on the possibility to return long-term transmission rights for subsequent forward capacity allocation or to transfer long-term transmission rights between market participants. Article 30 of Regulation (EU) 2016/1719 sets out rules on forward hedging products.

(18) Commission Regulation (EU) 2016/631 (9) sets out the requirements for grid connection of power-generating facilities to the interconnected system, in particular with respect to synchronous power-generating modules, power park modules and offshore power park modules. Those requirements help to ensure fair conditions of competition in the internal electricity market, to ensure system security and the integration of electricity from renewable sources, and to facilitate Union-wide trade in electricity. Articles 66 and 67 of Regulation (EU) 2016/631 set out rules for emerging technologies in electricity generation.

(19) Bidding zones reflecting supply and demand distribution are a cornerstone of market-based electricity trading and are a prerequisite for reaching the full potential of capacity allocation methods including the flow-based approach. Bidding zones therefore should be defined in a manner to ensure market liquidity, efficient congestion management and overall market efficiency. When a review of an existing bidding zone configuration is launched by a single regulatory authority or transmission system operator with the approval of its competent regulatory authority, for the bidding zones inside the transmission system operator's control area, if the bidding zone configuration has negligible impact on neighbouring transmission system operators' control areas, including interconnectors, and the review of bidding zone configuration is necessary to improve efficiency, to maximise cross-border trading opportunities or to maintain operational security, the transmission system operator in the relevant control area and the competent regulatory authority should be, respectively, the only transmission system operator and the only regulatory authority participating in the review. The relevant transmission system operator and the competent regulatory authority should give the neighbouring transmission system operators prior notice of the review and the results of the review should be published. It should be possible to launch a regional bidding zone review following the technical report on congestion in line with Article 14 of this Regulation or in accordance with existing procedures laid down in Regulation (EU) 2015/1222.

(20) When regional coordination centres carry out a capacity calculation, they should maximise capacity considering non-costly remedial actions and respecting the operational security limits of transmission system operators in the Capacity Calculation Region. Where the calculation does not result in capacity equal to or above the minimum capacities set out in this Regulation, regional coordination centres should consider all available costly remedial actions to further increase capacity up to the minimum capacities, including redispatching potential within and between the capacity calculation regions, while respecting the operational security limits of transmission system operators of the Capacity Calculation Regions. Transmission system operators should report accurately and transparently on all aspects of capacity calculation in accordance with this Regulation and should ensure that all information sent to regional coordination centres is accurate and fit for purpose.

(21) When performing capacity calculation, regional coordination centres should calculate cross-zonal capacities using data from transmission system operators which respects the operational security limits of the transmission system operators' respective control areas. Transmission system operators should be able to deviate from coordinated capacity calculation where its implementation would result in a violation of the operational security limits of network elements in their control area. Those deviations should be carefully monitored and transparently reported to prevent abuse and ensure that the volume of interconnection capacity to be made available to market participants is not limited in order to solve congestion inside a bidding zone. Where an action plan is in place, the action plan should take account of deviations and address their cause.

(22) Core market principles should set out that electricity prices are to be determined through demand and supply. Those prices should indicate when electricity is needed, thereby providing market-based incentives for investments into flexibility sources such as flexible generation, interconnection, demand response or energy storage.

(23) While decarbonisation of the electricity sector, with energy from renewable sources becoming a major part of the market, is one of the goals of the Energy Union, it is crucial that the market removes existing barriers to cross-border trade and encourages investments into supporting infrastructure, for example, more flexible generation, interconnection, demand response and energy storage. To support this shift to variable and distributed generation, and to ensure that energy market principles are the basis for the Union's electricity markets of the future, a renewed focus on short-term markets and scarcity pricing is essential.

(24) Short-term markets improve liquidity and competition by enabling more resources to participate fully in the market, especially those resources that are more flexible. Effective scarcity pricing will encourage market participants to react to market signals and to be available when the market most needs them and ensures that they can recover their costs in the wholesale market. It is therefore critical to ensure that administrative and implicit price caps are removed in order to allow for scarcity pricing. When fully embedded in the market structure, short-term markets and scarcity pricing contribute to the removal of other market distortive measures, such as capacity mechanisms, in order to ensure security of supply. At the same time, scarcity pricing without price caps on the wholesale market should not jeopardize the possibility of offering reliable and stable prices to final customers, in particular household customers, small and medium-sized enterprises (SMEs) and industrial customers.

(25) Without prejudice to Articles 107, 108 and 109 of the Treaty on the Functioning of the European Union (TFEU), derogations from fundamental market principles such as balancing responsibility, market-based dispatch, or redispatch reduce flexibility signals and act as barriers to the development of solutions such as energy storage, demand response or aggregation. While derogations are still necessary to avoid an unnecessary administrative burden to certain market participants, in particular household customers and SMEs, broad derogations covering entire technologies are not consistent with the aim of achieving efficient market-based decarbonisation processes and should thus be replaced by more targeted measures.

(26) A precondition for effective competition in the internal market for electricity is non-discriminatory, transparent and adequate charges for network use including interconnecting lines in the transmission system.

(27) Uncoordinated curtailments of interconnector capacities increasingly limit the exchange of electricity between Member States and have become a serious obstacle to the development of a functioning internal market for electricity. The maximum level of capacity of interconnectors and the critical network elements should therefore be made available, complying with the safety standards of secure network operation including respecting the security standard for contingencies (N-1). However, there are some limitations to setting the capacity level in a meshed grid. Clear minimum levels of available capacity for cross-zonal trade need to be put in place in order to reduce the effects of loop flows and internal congestions on cross-zonal trade and to give a predictable capacity value for market participants. Where the flow-based approach is used, that minimum capacity should determine the minimum share of the capacity of a cross-zonal or an internal critical network element respecting operational security limits to be used as an input for coordinated capacity calculation under Regulation (EU) 2015/1222, taking into account contingencies. The total remaining share of capacity may be used for reliability margins, loop flows and internal flows. Furthermore, in the case of foreseeable problems for ensuring grid security, derogations should be possible for a limited transitional phase. Such derogations should be accompanied by a methodology and projects providing for a long-term solution.

(28) The transmission capacity to which the 70 % minimum capacity criterion shall apply in the net transmission capacity (NTC) approach is the maximum transmission of active power which respects operational security limits and takes into account contingencies. The coordinated calculation of this capacity also takes into account that electricity flows are distributed unevenly between individual components and is not just adding capacities of interconnecting lines. This capacity does not take into account the reliability margin, loop flows or internal flows which are taken into account within the remaining 30 %.

(29) It is important to avoid distortion of competition resulting from the differing safety, operational and planning standards used by transmission system operators in Member States. Moreover, there should be transparency for market participants concerning available transfer capacities and the security, planning and operational standards that affect the available transfer capacities.

(30) To efficiently steer necessary investments, prices also need to provide signals where electricity is most needed. In a zonal electricity system, correct locational signals require a coherent, objective and reliable determination of bidding zones via a transparent process. In order to ensure efficient operation and planning of the Union electricity network and to provide effective price signals for new generation capacity, demand response and transmission infrastructure, bidding zones should reflect structural congestion. In particular, cross-zonal capacity should not be reduced in order to resolve internal congestion.

(31) To reflect the divergent principles of optimising bidding zones without jeopardising liquid markets and grid investments two options should be provided for in order to address congestion. Member States should be able to choose between a reconfiguration of their bidding zone or measures such as grid reinforcement and grid optimisation. The starting point for such a decision should be the identification of long-term structural congestions by the transmission system operator or operators of a Member State, by a report by the European Network of Transmission System Operators for Electricity (the ‘ENTSO for Electricity’) on congestion or by a bidding zone review. Member States should first try to find a common solution on how to best address congestion. In the course of doing so Member States might adopt multinational or national action plans to address congestion. For Member States which adopt an action plan to address congestion, a phase-in period in the form of a linear trajectory for the opening of interconnectors should apply. At the end of the implementation of such an action plan, Member States should have a possibility to choose whether to opt for a reconfiguration of the bidding zone(s) or whether to opt for addressing remaining congestion through remedial actions for which they bear the costs. In the latter case their bidding zone should not be reconfigured against the will of that Member State, provided that the minimum capacity is reached. The minimum level of capacity that should be used in coordinated capacity calculation should be a percentage of the capacity of a critical network element, as defined following the selection process under Regulation (EU) 2015/1222, after, or, in the case of a flow-based approach, while, respecting the operational security limits in contingency situations. A Commission decision on the configuration of a bidding zone should be possible as a measure of last resort and should only amend the configuration of a bidding zone in those Member States which have opted to split the bidding zone or which have not reached the minimum level of the capacity.

(32) Efficient decarbonisation of the electricity system via market integration requires systematically abolishing barriers to cross-border trade to overcome market fragmentation and to allow Union energy customers to fully benefit from the advantages of integrated electricity markets and competition.

(33) This Regulation should lay down basic principles with regard to tarification and capacity allocation, while providing for the adoption of guidelines detailing further relevant principles and methodologies, in order to allow rapid adaptation to changed circumstances.

(34) The management of congestion problems should provide correct economic signals to transmission system operators and market participants and should be based on market mechanisms.

(35) In an open, competitive market, transmission system operators should be compensated for costs incurred as a result of hosting cross-border flows of electricity on their networks by the operators of the transmission systems from which cross-border flows originate and the systems where those flows end.

(36) Payments and receipts resulting from compensation between transmission system operators should be taken into account when setting national network tariffs.

(37) The actual amount payable for cross-border access to the system can vary considerably, depending on the transmission system operator involved and as a result of differences in the structure of the tarification systems applied in Member States. A certain degree of harmonisation is therefore necessary in order to avoid distortions of trade.

(38) There should be rules on the use of revenues from congestion-management procedures, unless the specific nature of the interconnector concerned justifies an exemption from those rules.

(39) To provide for a level playing field between all market participants, network tariffs should be applied in a way which does not positively or negatively discriminate between production connected at the distribution level and production connected at the transmission level. Network tariffs should not discriminate against energy storage, and should not create disincentives for participation in demand response or represent an obstacle to improving energy efficiency.

(40) In order to increase transparency and comparability in tariff-setting where binding harmonisation is not seen as adequate, a best practices report on tariff methodologies should be issued by the European Agency for the Cooperation of Energy Regulators (‘ACER’) established by Regulation (EU) 2019/942 of the European Parliament and of the Council (10).

(41) To better ensure optimal investment in the trans-European grid and to better address the challenge where viable interconnection projects cannot be built for lack of prioritisation at national level, the use of congestion rents should be reconsidered and contribute to guarantee availability and maintain or increase interconnection capacities.

(42) In order to ensure optimal management of the electricity transmission network and to allow trading and supplying electricity across borders in the Union, the ENTSO for Electricity, should be established. The tasks of the ENTSO for Electricity should be carried out in accordance with Union's competition rules which remain applicable to the decisions of the ENTSO for Electricity. The tasks of the ENTSO for Electricity should be well-defined and its working method should ensure efficiency and transparency. The network codes prepared by the ENTSO for Electricity are not intended to replace the necessary national network codes for non-cross-border issues. Given that more effective progress may be achieved through an approach at regional level, transmission system operators should set up regional structures within the overall cooperation structure, whilst ensuring that results at regional level are compatible with network codes and non-binding ten-year network development plans at Union level. Member States should promote cooperation and monitor the effectiveness of the network at regional level. Cooperation at regional level should be compatible with progress towards a competitive and efficient internal market for electricity.

(43) The ENTSO for Electricity should carry out a robust medium to long-term European resource adequacy assessment to provide an objective basis for the assessment of adequacy concerns. The resource adequacy concern that capacity mechanisms address should be based on the European resource adequacy assessment. That assessment may be complemented by national assessments.

(44) The methodology for the long-term resource adequacy assessment (from ten-year-ahead to year-ahead) set out in this Regulation has a different purpose than the seasonal adequacy assessments (six months ahead) as set out in Article 9 of Regulation (EU) 2019/941 of the European Parliament and of the Council (11). Medium to long-term assessments are mainly used to identify adequacy concerns and to assess the need for capacity mechanisms whereas seasonal adequacy assessments are used to alert to short-term risks that might occur in the following six months that are likely to result in a significant deterioration of the electricity supply situation. In addition, regional coordination centres also carry out regional adequacy assessments on electricity transmission system operation. Those are very short-term adequacy assessments (from week-ahead to day-ahead) used in the context of system operation.

(45) Before introducing capacity mechanisms, Member States should assess the regulatory distortions contributing to the related resource adequacy concern. Member States should be required to adopt measures to eliminate the identified distortions, and should adopt a timeline for their implementation. Capacity mechanisms should only be introduced to address the adequacy problems that cannot be solved through the removal of such distortions.

(46) Member States intending to introduce capacity mechanisms should derive resource adequacy targets on the basis of a transparent and verifiable process. Member States should have the freedom to set their own desired level of security of supply.

(47) Pursuant to Article 108 TFEU, the Commission has exclusive competence to assess the compatibility with the internal market of State aid measures which the Member States may put in place. That assessment is to be carried out on the basis of Article 107(3) TFEU and in accordance with the relevant provisions and guidelines which the Commission may adopt to that effect. This Regulation is without prejudice to the Commission's exclusive competence conferred by TFEU.

(48) Capacity mechanisms that are in place should be reviewed in light of this Regulation.

(49) Detailed rules for facilitating effective cross-border participation in capacity mechanisms should be laid down in this Regulation. Transmission system operators should facilitate the cross-border participation of interested producers in capacity mechanisms in other Member States. Therefore, they should calculate capacities up to which cross-border participation would be possible, should enable participation and should check availabilities. Regulatory authorities should enforce the cross-border rules in the Member States.

(50) Capacity mechanisms should not result in overcompensation, while at the same time they should ensure security of supply. In that regard, capacity mechanisms other than strategic reserves should be constructed to ensure that the price paid for availability automatically tends to zero when the level of capacity which would be profitable on the energy market in the absence of a capacity mechanism is expected to be adequate to meet the level of capacity demanded.

(51) To support Member States and regions facing social, industrial and economic challenges due to the energy transition, the Commission has set up a coal and carbon-intensive regions initiative. In that context, the Commission should assist Member States, including with targeted financial support to enable a ‘just transition’ in those regions, where available.

(52) In view of the differences between national energy systems and the technical limitations of existing electricity networks, the best approach to achieving progress in market integration is often at a regional level. Regional cooperation between transmission system operators should thus be strengthened. In order to ensure efficient cooperation, a new regulatory framework should provide for stronger regional governance and regulatory oversight, including by strengthening ACER's decision-making power with respect to cross-border issues. It is possible that closer cooperation of Member States is also needed in crisis situations, to increase security of supply and to limit market distortions.

(53) Coordination between transmission system operators at regional level has been formalised with the mandatory participation of transmission system operators in regional security coordinators. The regional coordination of transmission system operators should be further developed with an enhanced institutional framework via the establishment of regional coordination centres. The establishment of regional coordination centres should take into account existing or planned regional coordination initiatives and should support the increasingly integrated operation of electricity systems across the Union, thereby ensuring their efficient and secure performance. For that reason, it is necessary to ensure that the coordination of transmission system operators through regional coordination centres takes place across the Union. Where transmission system operators of a given region are not yet coordinated by an existing or a planned regional coordination centre, the transmission system operators in that region should establish or designate a regional coordination centre.

(54) The geographical scope of regional coordination centres should allow them to contribute effectively to the coordination of the operations of transmission system operators across regions and should lead to enhanced system security and market efficiency. Regional coordination centres should have the flexibility to carry out their tasks in the region in the way which is best adapted to the nature of the individual tasks entrusted to them.

(55) Regional coordination centres should carry out tasks where their regionalisation brings added value compared to tasks performed at national level. The tasks of regional coordination centres should cover the tasks carried out by regional security coordinators pursuant to the Commission Regulation (EU) 2017/1485 (12) as well as additional system operation, market operation and risk preparedness tasks. The tasks carried out by regional coordination centres should not include real-time operation of the electricity system.

(56) In performing their tasks, regional coordination centres should contribute to the achievement of the 2030 and 2050 objectives set out in the climate and energy policy framework.

(57) Regional coordination centres should primarily act in the interest of system and market operation of the region. Hence, regional coordination centres should be entrusted with the powers necessary to coordinate the actions to be taken by transmission system operators of the system operation region for certain functions and with an enhanced advisory role for the remaining functions.

(58) The human, technical, physical and financial resources of regional coordination centres should not exceed what is strictly necessary for the fulfilment of their tasks.

(59) The ENTSO for Electricity should ensure that the activities of regional coordination centres are coordinated across regional boundaries.

(60) In order to increase efficiencies in the electricity distribution networks in the Union and to ensure close cooperation with transmission system operators and the ENTSO for Electricity, an entity of distribution system operators in the Union (EU DSO entity) should be established. The tasks of the EU DSO entity should be well-defined and its working method should ensure efficiency, transparency and representativeness among Union distribution system operators. The EU DSO entity should closely cooperate with the ENTSO for Electricity on the preparation and implementation of the network codes where applicable and should work on providing guidance on the integration inter alia of distributed generation and energy storage in distribution networks or other areas which relate to the management of distribution networks. The EU DSO entity should also take due account of the specificities inherent to distribution systems connected downstream with electricity systems on islands which are not connected with other electricity systems by means of interconnectors.

(61) Increased cooperation and coordination among transmission system operators is required to create network codes for providing and managing effective and transparent access to the transmission networks across borders, and to ensure coordinated and sufficiently forward-looking planning and sound technical evolution of the transmission system in the Union, including the creation of interconnection capacities, with due regard to the environment. Those network codes should be in line with non-binding framework guidelines, which are developed by ACER. ACER should have a role in reviewing, based on matters of fact, draft network codes, including their compliance with those framework guidelines, and it should be enabled to recommend them for adoption by the Commission. ACER should assess proposed amendments to the network codes and it should be enabled to recommend them for adoption by the Commission. Transmission system operators should operate their networks in accordance with those network codes.

(62) Experience with the development and adoption of network codes has shown that it is useful to streamline the development procedure by clarifying that ACER has the right to revise draft electricity network codes before submitting them to the Commission.

(63) To ensure the smooth functioning of the internal market for electricity, provision should be made for procedures which allow the adoption of decisions and guidelines with regard, inter alia, to tarification and capacity allocation by the Commission whilst ensuring the involvement of regulatory authorities in that process, where appropriate through their association at Union level. Regulatory authorities, together with other relevant authorities in the Member States, have an important role to play in contributing to the proper functioning of the internal market for electricity.

(64) All market participants have an interest in the work expected of the ENTSO for Electricity. An effective consultation process is therefore essential and existing structures that are set up to facilitate and streamline the consultation process, such as via regulatory authorities or ACER, should play an important role.

(65) In order to ensure greater transparency regarding the entire electricity transmission network in the Union, the ENTSO for Electricity should draw up, publish and regularly update a non-binding Union-wide ten-year network development plan. Viable electricity transmission networks and necessary regional interconnections, relevant from a commercial or security of supply point of view, should be included in that network development plan.

(66) Investments in major new infrastructure should be promoted strongly while ensuring the proper functioning of the internal market for electricity. In order to enhance the positive effect of exempted direct current interconnectors on competition and security of supply, market interest during the project-planning phase should be tested and congestion-management rules should be adopted. Where direct current interconnectors are located in the territory of more than one Member State, ACER should handle as a last resort the exemption request in order to take better account of its cross-border implications and to facilitate its administrative handling. Moreover, given the exceptional risk profile of constructing those exempt major infrastructure projects, undertakings with supply and production interests should be able to benefit from a temporary derogation from the full unbundling rules for the projects concerned. Exemptions granted under Regulation (EC) No 1228/2003 of the European Parliament and of the Council (13) continue to apply until the scheduled expiry date as decided in the granted exemption decision. Offshore electricity infrastructure with dual functionality (so-called ‘offshore hybrid assets’) combining transport of offshore wind energy to shore and interconnectors, should also be eligible for exemption such as under the rules applicable to new direct current interconnectors. Where necessary, the regulatory framework should duly consider the specific situation of those assets to overcome barriers to the realisation of societally cost-efficient offshore hybrid assets.

(67) To enhance trust in the market, its participants need to be sure that those engaging in abusive behaviour can be subject to effective, proportionate and dissuasive penalties. The competent authorities should be given the competence to investigate effectively allegations of market abuse. To that end, it is necessary that competent authorities have access to data that provides information on operational decisions made by suppliers. In the electricity market, many relevant decisions are made by the producers, which should keep information in relation to those decisions available to and easily accessible by the competent authorities for a set period. The competent authorities should, furthermore, regularly monitor whether the transmission system operators comply with the rules. Small producers with no real ability to distort the market should be exempt from that obligation.

(68) The Member States and the competent authorities should be required to provide relevant information to the Commission. Such information should be treated confidentially by the Commission. Where necessary, the Commission should have an opportunity to request relevant information directly from undertakings concerned, provided that the competent authorities are informed.

(69) Member States should lay down rules on penalties applicable to infringements of the provisions of this Regulation and ensure that they are implemented. Those penalties should be effective, proportionate and dissuasive.

(70) Member States, the Energy Community Contracting Parties and other third countries which apply this Regulation or are part of the synchronous area of Continental Europe should closely cooperate on all matters concerning the development of an integrated electricity trading region and should take no measures that endanger the further integration of electricity markets or security of supply of Member States and Contracting Parties.

(71) At the time of the adoption of Regulation (EC) No 714/2009, only few rules for the internal market for electricity existed at Union level. Since then, the Union internal market has become more complex due to the fundamental change the markets are undergoing in particular regarding deployment of variable renewable electricity production. The network codes and guidelines have therefore become extensive and comprehensive and encompass both technical and general issues.

(72) In order to ensure the minimum degree of harmonisation required for effective market functioning, the power to adopt acts in accordance with Article 290 of TFEU should be delegated to the Commission in respect of non-essential elements of certain specific areas which are fundamental for market integration. Those acts should include the adoption and amendment of certain network codes and guidelines where they supplement this Regulation, the regional cooperation of transmission system operators and regulatory authorities, financial compensations between transmission system operators, as well as the application of exemption provisions for new interconnectors. It is of particular importance that the Commission carry out appropriate consultations during its preparatory work, including at expert level, and that those consultations be conducted in accordance with the principles laid down in the Interinstitutional Agreement of 13 April 2016 (14) on Better Law-Making. In particular, to ensure equal participation in the preparation of delegated acts, the European Parliament and the Council receive all documents at the same time as Member States' experts, and their experts systematically have access to meetings of Commission expert groups dealing with the preparation of delegated acts.

(73) In order to ensure uniform conditions for the implementation of this Regulation, implementing powers in accordance with Article 291 of TFEU should be conferred on the Commission. Those powers should be exercised in accordance with Regulation (EU) No 182/2011 of the European Parliament and of the Council (15). The examination procedure should be used for the adoption of those implementing acts.

(74) Since the objective of this Regulation, namely the provision of a harmonised framework for cross-border exchanges of electricity, cannot be sufficiently achieved by the Member States but can rather, by reason of its scale and effects, 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 in order to achieve that objective.

(75) For reasons of coherence and legal certainty, no provision in this Regulation should prevent the application of the derogations emerging from Article 66 of Directive (EU) 2019/944,

HAVE ADOPTED THIS REGULATION:

CHAPTER I

SUBJECT MATTER, SCOPE AND DEFINITIONS

Article 1 Subject matter and scope This Regulation aims to: (a) set the basis for an efficient achievement of the objectives of the Energy Union and in particular the climate and energy framework for 2030 by enabling market signals to be delivered for increased efficiency, higher share of renewable energy sources, security of supply, flexibility, sustainability, decarbonisation and innovation; (b) set fundamental principles for well-functioning, integrated electricity markets, which allow all resource providers and electricity customers non-discriminatory market access, empower consumers, ensure competitiveness on the global market as well as demand response, energy storage and energy efficiency, and facilitate aggregation of distributed demand and supply, and enable market and sectoral integration and market-based remuneration of electricity generated from renewable sources; (c) set fair rules for cross-border exchanges in electricity, thus enhancing competition within the internal market for electricity, taking into account the particular characteristics of national and regional markets, including the establishment of a compensation mechanism for cross-border flows of electricity, the setting of harmonised principles on cross-border transmission charges and the allocation of available capacities of interconnections between national transmission systems; (d) facilitate the emergence of a well-functioning and transparent wholesale market, contributing to a high level of security of electricity supply, and provide for mechanisms to harmonise the rules for cross-border exchanges in electricity.

Article 2 Definitions The following definitions apply: (1) ‘interconnector’ means a transmission line which crosses or spans a border between Member States and which connects the national transmission systems of the Member States; (2) ‘regulatory authority’ means a regulatory authority designated by each Member State pursuant to Article 57(1) of Directive (EU) 2019/944; (3) ‘cross-border flow’ means a physical flow of electricity on a transmission network of a Member State that results from the impact of the activity of producers, customers, or both, outside that Member State on its transmission network; (4) ‘congestion’ means a situation in which all requests from market participants to trade between network areas cannot be accommodated because they would significantly affect the physical flows on network elements which cannot accommodate those flows; (5) ‘new interconnector’ means an interconnector not completed by 4 August 2003; (6) ‘structural congestion’ means congestion in the transmission system that is capable of being unambiguously defined, is predictable, is geographically stable over time, and frequently reoccurs under normal electricity system conditions; (7) ‘market operator’ means an entity that provides a service whereby the offers to sell electricity are matched with bids to buy electricity; (8) ‘nominated electricity market operator’ or ‘NEMO’ means a market operator designated by the competent authority to carry out tasks related to single day-ahead or single intraday coupling; (9) ‘value of lost load’ means an estimation in euro/MWh, of the maximum electricity price that customers are willing to pay to avoid an outage; (10) ‘balancing’ means all actions and processes, in all timelines, through which transmission system operators ensure, in an ongoing manner, maintenance of the system frequency within a predefined stability range and compliance with the amount of reserves needed with respect to the required quality; (11) ‘balancing energy’ means energy used by transmission system operators to carry out balancing; (12) ‘balancing service provider’ means a market participant providing either or both balancing energy and balancing capacity to transmission system operators; (13) ‘balancing capacity’ means a volume of capacity that a balancing service provider has agreed to hold and in respect to which the balancing service provider has agreed to submit bids for a corresponding volume of balancing energy to the transmission system operator for the duration of the contract; (14) ‘balance responsible party’ means a market participant or its chosen representative responsible for its imbalances in the electricity market; (15) ‘imbalance settlement period’ means the time unit for which the imbalance of the balance responsible parties is calculated; (16) ‘imbalance price’ means the price, be it positive, zero or negative, in each imbalance settlement period for an imbalance in each direction; (17) ‘imbalance price area’ means the area in which an imbalance price is calculated; (18) ‘prequalification process’ means the process to verify the compliance of a provider of balancing capacity with the requirements set by the transmission system operators; (19) ‘reserve capacity’ means the amount of frequency containment reserves, frequency restoration reserves or replacement reserves that needs to be available to the transmission system operator; (20) ‘priority dispatch’ means, with regard to the self-dispatch model, the dispatch of power plants on the basis of criteria which are different from the economic order of bids and, with regard to the central dispatch model, the dispatch of power plants on the basis of criteria which are different from the economic order of bids and from network constraints, giving priority to the dispatch of particular generation technologies; (21) ‘capacity calculation region’ means the geographic area in which the coordinated capacity calculation is applied; (22) ‘capacity mechanism’ means a temporary measure to ensure the achievement of the necessary level of resource adequacy by remunerating resources for their availability, excluding measures relating to ancillary services or congestion management; (23) ‘high-efficiency cogeneration’ means cogeneration which meets the criteria laid down in Annex II to Directive 2012/27/EU of the European Parliament and of the Council (16); (24) ‘demonstration project’ means a project which demonstrates a technology as a first of its kind in the Union and represents a significant innovation that goes well beyond the state of the art; (25) ‘market participant’ means a natural or legal person who buys, sells or generates electricity, who is engaged in aggregation or who is an operator of demand response or energy storage services, including through the placing of orders to trade, in one or more electricity markets, including in balancing energy markets; (26) ‘redispatching’ means a measure, including curtailment, that is activated by one or more transmission system operators or distribution system operators by altering the generation, load pattern, or both, in order to change physical flows in the electricity system and relieve a physical congestion or otherwise ensure system security; (27) ‘countertrading’ means a cross-zonal exchange initiated by system operators between two bidding zones to relieve physical congestion; (28) ‘power-generating facility’ means a facility that converts primary energy into electrical energy and which consists of one or more power-generating modules connected to a network; (29) ‘central dispatching model’ means a scheduling and dispatching model where the generation schedules and consumption schedules as well as dispatching of power-generating facilities and demand facilities, in reference to dispatchable facilities, are determined by a transmission system operator within an integrated scheduling process; (30) ‘self-dispatch model’ means a scheduling and dispatching model where the generation schedules and consumption schedules as well as dispatching of power-generating facilities and demand facilities are determined by the scheduling agents of those facilities; (31) ‘standard balancing product’ means a harmonised balancing product defined by all transmission system operators for the exchange of balancing services; (32) ‘specific balancing product’ means a balancing product different from a standard balancing product; (33) ‘delegated operator’ means an entity to whom specific tasks or obligations entrusted to a transmission system operator or nominated electricity market operator under this Regulation or other Union legal acts have been delegated by that transmission system operator or NEMO or have been assigned by a Member State or regulatory authority; (34) ‘customer’ means a customer as defined in point (1) of Article 2 of Directive (EU) 2019/944; (35) ‘final customer’ means final customer as defined in point (3) of Article 2 of Directive (EU) 2019/944; (36) ‘wholesale customer’ means a wholesale customer as defined in point (2) of Article 2 of Directive (EU) 2019/944; (37) ‘household customer’ means household customer as defined in point (4) of Article 2 of Directive (EU) 2019/944; (38) ‘small enterprise’ means small enterprise as defined in point (7) of Article 2 of Directive (EU) 2019/944; (39) ‘active customer’ means active customer as defined in point (8) of Article 2 of Directive (EU) 2019/944; (40) ‘electricity markets’ means electricity markets as defined in point (9) of Article 2 of Directive (EU) 2019/944; (41) ‘supply’ means supply as defined in point (12) of Article 2 of Directive (EU) 2019/944; (42) ‘electricity supply contract’ means electricity supply contract as defined in point (13) of Article 2 of Directive (EU) 2019/944; (43) ‘aggregation’ means aggregation as defined in point (18) of Article 2 of Directive (EU) 2019/944; (44) ‘demand response’ means demand response as defined in point (20) of Article 2 of Directive (EU) 2019/944; (45) ‘smart metering system’ means smart metering system as defined in point (23) of Article 2 of Directive (EU) 2019/944; (46) ‘interoperability’ means interoperability as defined in point (24) of Article 2 of Directive (EU) 2019/944; (47) ‘distribution’ means distribution as defined in point (28) of Article 2 of Directive (EU) 2019/944; (48) ‘distribution system operator’ means distribution system operator as defined in point (29) of Article 2 of Directive (EU) 2019/944; (49) ‘energy efficiency’ means energy efficiency as defined in point (30) of Article 2 of Directive (EU) 2019/944; (50) ‘energy from renewable sources’ or ‘renewable energy’ means energy from renewable sources as defined in point (31) of Article 2 of Directive (EU) 2019/944; (51) ‘distributed generation’ means distributed generation as defined in point (32) of Article 2 of Directive (EU) 2019/944; (52) ‘transmission’ means transmission as defined in point (34) of Article 2 of Directive (EU) 2019/944; (53) ‘transmission system operator’ means transmission system operator as defined in point (35) of Article 2 of Directive (EU) 2019/944; (54) ‘system user’ means system user as defined in point (36) of Article 2 of Directive (EU) 2019/944; (55) ‘generation’ means generation as defined in point (37) of Article 2 of Directive (EU) 2019/944; (56) ‘producer’ means producer as defined in point (38) of Article 2 of Directive (EU) 2019/944; (57) ‘interconnected system’ means interconnected system as defined in point (40) of Article 2 of Directive (EU) 2019/944; (58) ‘small isolated system’ means small isolated system as defined in point (42) of Article 2 of Directive (EU) 2019/944; (59) ‘small connected system’ means small connected system as defined in point (43) of Article 2 of Directive (EU) 2019/944; (60) ‘ancillary service’ means ancillary service as defined in point (48) of Article 2 of Directive (EU) 2019/944; (61) ‘non-frequency ancillary service’ means non-frequency ancillary service as defined in point (49) of Article 2 of Directive (EU) 2019/944; (62) ‘energy storage’ means energy storage as defined in point (59) of Article 2 of Directive (EU) 2019/944; (63) ‘regional coordination centre’ means regional coordination centre established pursuant to Article 35 of this Regulation; (64) ‘wholesale energy market’ means wholesale energy market as defined in point (6) of Article 2 of Regulation (EU) No 1227/2011 of the European Parliament and of the Council (17); (65) ‘bidding zone’ means the largest geographical area within which market participants are able to exchange energy without capacity allocation; (66) ‘capacity allocation’ means the attribution of cross-zonal capacity; (67) ‘control area’ means a coherent part of the interconnected system, operated by a single system operator and shall include connected physical loads and/or generation units if any; (68) ‘coordinated net transmission capacity’ means a capacity calculation method based on the principle of assessing and defining ex ante a maximum energy exchange between adjacent bidding zones; (69) ‘critical network element’ means a network element either within a bidding zone or between bidding zones taken into account in the capacity calculation process, limiting the amount of power that can be exchanged; (70) ‘cross-zonal capacity’ means the capability of the interconnected system to accommodate energy transfer between bidding zones; (71) ‘generation unit’ means a single electricity generator belonging to a production unit.

CHAPTER II

GENERAL RULES FOR THE ELECTRICITY MARKET

Article 3 Principles regarding the operation of electricity markets Member States, regulatory authorities, transmission system operators, distribution system operators, market operators and delegated operators shall ensure that electricity markets are operated in accordance with the following principles: (a) prices shall be formed on the basis of demand and supply; (b) market rules shall encourage free price formation and shall avoid actions which prevent price formation on the basis of demand and supply; (c) market rules shall facilitate the development of more flexible generation, sustainable low carbon generation, and more flexible demand; (d) customers shall be enabled to benefit from market opportunities and increased competition on retail markets and shall be empowered to act as market participants in the energy market and the energy transition; (e) market participation of final customers and small enterprises shall be enabled by aggregation of generation from multiple power-generating facilities or load from multiple demand response facilities to provide joint offers on the electricity market and be jointly operated in the electricity system, in accordance with Union competition law; (f) market rules shall enable the decarbonisation of the electricity system and thus the economy, including by enabling the integration of electricity from renewable energy sources and by providing incentives for energy efficiency; (g) market rules shall deliver appropriate investment incentives for generation, in particular for long-term investments in a decarbonised and sustainable electricity system, energy storage, energy efficiency and demand response to meet market needs, and shall facilitate fair competition thus ensuring security of supply; (h) barriers to cross-border electricity flows between bidding zones or Member States and cross-border transactions on electricity markets and related services markets shall be progressively removed; (i) market rules shall provide for regional cooperation where effective; (j) safe and sustainable generation, energy storage and demand response shall participate on equal footing in the market, under the requirements provided for in the Union law; (k) all producers shall be directly or indirectly responsible for selling the electricity they generate; (l) market rules shall allow for the development of demonstration projects into sustainable, secure and low-carbon energy sources, technologies or systems which are to be realised and used to the benefit of society; (m) market rules shall enable the efficient dispatch of generation assets, energy storage and demand response; (n) market rules shall allow for entry and exit of electricity generation, energy storage and electricity supply undertakings based on those undertakings' assessment of the economic and financial viability of their operations; (o) in order to allow market participants to be protected against price volatility risks on a market basis, and mitigate uncertainty on future returns on investment, long-term hedging products shall be tradable on exchanges in a transparent manner and long-term electricity supply contracts shall be negotiable over the counter, subject to compliance with Union competition law; (p) market rules shall facilitate trade of products across the Union and. regulatory changes shall take into account effects on both short-term and long-term forward and futures markets and products; (q) market participants shall have a right to obtain access to the transmission networks and distribution networks on objective, transparent and non-discriminatory terms.

Article 4 Just transition The Commission shall support Member States that put in place a national strategy for the progressive reduction of existing coal and other solid fossil fuel generation and mining capacity through all available means to enable a just transition in regions affected by structural change. The Commission shall assist Member States in addressing the social and economic impacts of the clean energy transition. The Commission shall work in close partnership with the stakeholders in coal and carbon-intensive regions, shall facilitate the access to and use of available funds and programmes, and shall encourage the exchange of good practices, including discussions on industrial roadmaps and reskilling needs.

Article 5 Balance responsibility 1. All market participants shall be responsible for the imbalances they cause in the system (‘balance responsibility’). To that end, market participants shall either be balance responsible parties or shall contractually delegate their responsibility to a balance responsible party of their choice. Each balance responsible party shall be financially responsible for its imbalances and shall strive to be balanced or shall help the electricity system to be balanced. 2. Member States may provide derogations from balance responsibility only for: (a) demonstration projects for innovative technologies, subject to approval by the regulatory authority, provided that those derogations are limited to the time and extent necessary for achieving the demonstration purposes; (b) power-generating facilities using renewable energy sources with an installed electricity capacity of less than 400 kW; (c) installations benefitting from support approved by the Commission under Union State aid rules pursuant to Articles 107, 108 and 109 TFEU, and commissioned before 4 July 2019. Member States may, without prejudice to Articles 107 and 108 TFEU, provide incentives to market participants which are fully or partly exempted from balancing responsibility to accept full balancing responsibility. 3. When a Member State provides a derogation in accordance with paragraph 2, it shall ensure that the financial responsibility for imbalances is fulfilled by another market participant. 4. For power-generating facilities commissioned from 1 January 2026, point (b) of paragraph 2 shall apply only to generating installations using renewable energy sources with an installed electricity capacity of less than 200 kW.

Article 6 Balancing market 1. Balancing markets, including prequalification processes, shall be organised in such a way as to: (a) ensure effective non-discrimination between market participants taking account of the different technical needs of the electricity system and the different technical capabilities of generation sources, energy storage and demand response; (b) ensure that services are defined in a transparent and technologically neutral manner and are procured in a transparent, market-based manner; (c) ensure non-discriminatory access to all market participants, individually or through aggregation, including for electricity generated from variable renewable energy sources, demand response and energy storage; (d) respect the need to accommodate the increasing share of variable generation, increased demand responsiveness and the advent of new technologies. 2. The price of balancing energy shall not be pre-determined in contracts for balancing capacity. Procurement processes shall be transparent in accordance with Article 40(4) of Directive (EU) 2019/944, while protecting the confidentiality of commercially sensitive information. 3. Balancing markets shall ensure operational security whilst allowing for maximum use and efficient allocation of cross-zonal capacity across timeframes in accordance with Article 17. 4. The settlement of balancing energy for standard balancing products and specific balancing products shall be based on marginal pricing (pay-as-cleared) unless all regulatory authorities approve an alternative pricing method on the basis of a joint proposal by all transmission system operators following an analysis demonstrating that that alternative pricing method is more efficient. Market participants shall be allowed to bid as close to real time as possible, and balancing energy gate closure times shall not be before the intraday cross-zonal gate closure time. Transmission system operators applying a central dispatching model may establish additional rules in accordance with the guideline on electricity balancing adopted on the basis of Article 6(11) of Regulation (EC) No 714/2009. 5. The imbalances shall be settled at a price that reflects the real-time value of energy. 6. Each imbalance price area shall be equal to a bidding zone, except in the case of a central dispatching model where an imbalance price area may constitute a part of a bidding zone. 7. The dimensioning of reserve capacity shall be performed by the transmission system operators and shall be facilitated at regional level. 8. The procurement of balancing capacity shall be performed by the transmission system operator and may be facilitated at a regional level. Reservation of cross-border capacity to that end may be limited. The procurement of balancing capacity shall be market-based and organised in such a way as to be non-discriminatory between market participants in the prequalification process in accordance with Article 40(4) of Directive (EU) 2019/944 whether market participants participate individually or through aggregation. Procurement of balancing capacity shall be based on a primary market unless and to the extent that the regulatory authority has provided for a derogation to allow the use of other forms of market-based procurement on the grounds of a lack of competition in the market for balancing services. Derogations from the obligation to base the procurement of balancing capacity on use of primary markets shall be reviewed every three years. 9. The procurement of upward balancing capacity and downward balancing capacity shall be carried out separately, unless the regulatory authority approves a derogation from this principle on the basis that this would result in higher economic efficiency as demonstrated by an evaluation performed by the transmission system operator. Contracts for balancing capacity shall not be concluded more than one day before the provision of the balancing capacity and the contracting period shall be no longer than one day, unless and to the extent that the regulatory authority has approved the earlier contracting or longer contracting periods to ensure the security of supply or to improve economic efficiency. Where a derogation is granted, for at least 40 % of the standard balancing products and a minimum of 30 % of all products used for balancing capacity, contracts for the balancing capacity shall be concluded for no more than one day before the provision of the balancing capacity and the contracting period shall be no longer than one day. The contracting of the remaining part of the balancing capacity shall be performed for a maximum of one month in advance of the provision of balancing capacity and shall have a maximum contractual period of one month. 10. At the request of the transmission system operator, the regulatory authority may decide to extend the contractual period of the remaining part of balancing capacity referred to in paragraph 9 to a maximum period of twelve months provided that such a decision is limited in time, and the positive effects in terms of lowering of costs for final customers exceed the negative impacts on the market. The request shall include: (a) the specific period during which the exemption would apply; (b) the specific volume of balancing capacity to which the exemption would apply; (c) an analysis of the impact of the exemption on the participation of balancing resources; and (d) a justification for the exemption demonstrating that such an exemption would lead to lower costs to final customers. 11. Notwithstanding paragraph 10, from 1 January 2026 contract periods shall not be longer than six months. 12. By 1 January 2028, regulatory authorities shall report to the Commission and ACER on the share of the total capacity covered by contracts with a duration or a procurement period of longer than one day. 13. Transmission system operators or their delegated operators shall publish, as close to real time as possible but with a delay after delivery of no more than 30 minutes, the current system balance of their scheduling areas, the estimated imbalance prices and the estimated balancing energy prices. 14. Transmission system operators may, where standard balancing products are not sufficient to ensure operational security or where some balancing resources cannot participate in the balancing market through standard balancing products, propose, and the regulatory authorities may approve, derogations from paragraphs 2 and 4 for specific balancing products which are activated locally without exchanging them with other transmission system operators. Proposals for derogations shall include a description of measures proposed to minimise the use of specific products, subject to economic efficiency, a demonstration that the specific products do not create significant inefficiencies and distortions in the balancing market either inside or outside the scheduling area, as well as, where applicable, the rules and information for the process for converting the balancing energy bids from specific balancing products into balancing energy bids from standard balancing products.

Article 7 Day-ahead and intraday markets 1. Transmission system operators and NEMOs shall jointly organise the management of the integrated day-ahead and intraday markets in accordance with Regulation (EU) 2015/1222. Transmission system operators and NEMOs shall cooperate at Union level or, where more appropriate, at a regional level in order to maximise the efficiency and effectiveness of Union electricity day-ahead and intraday trading. The obligation to cooperate shall be without prejudice to the application of Union competition law. In their functions relating to electricity trading, transmission system operators and NEMOs shall be subject to regulatory oversight by the regulatory authorities pursuant to Article 59 of Directive (EU) 2019/944 and ACER pursuant to Articles 4 and 8 of Regulation (EU) 2019/942. 2. Day-ahead and intraday markets shall: (a) be organised in such a way as to be non-discriminatory; (b) maximise the ability of all market participants to manage imbalances; (c) maximise the opportunities for all market participants to participate in cross-zonal trade in as close as possible to real time across all bidding zones; (d) provide prices that reflect market fundamentals, including the real time value of energy, on which market participants are able to rely when agreeing on longer-term hedging products; (e) ensure operational security while allowing for maximum use of transmission capacity; (f) be transparent while at the same time protecting the confidentiality of commercially sensitive information and ensuring trading occurs in an anonymous manner; (g) make no distinction between trades made within a bidding zone and across bidding zones; and (h) be organised in such a way as to ensure that all markets participants are able to access the market individually or through aggregation.

Article 8 Trade on day-ahead and intraday markets 1. NEMOs shall allow market participants to trade energy as close to real time as possible and at least up to the intraday cross-zonal gate closure time. 2. NEMOs shall provide market participants with the opportunity to trade in energy in time intervals which are at least as short as the imbalance settlement period for both day-ahead and intraday markets. 3. NEMOs shall provide products for trading in day-ahead and intraday markets which are sufficiently small in size, with minimum bid sizes of 500 kW or less, to allow for the effective participation of demand-side response, energy storage and small-scale renewables including direct participation by customers. 4. By 1 January 2021, the imbalance settlement period shall be 15 minutes in all scheduling areas, unless regulatory authorities have granted a derogation or an exemption. Derogations may be granted only until 31 December 2024. From 1 January 2025, the imbalance settlement period shall not exceed 30 minutes where an exemption has been granted by all the regulatory authorities within a synchronous area.

Article 9 Forward markets 1. In accordance with Regulation (EU) 2016/1719, transmission system operators shall issue long-term transmission rights or have equivalent measures in place to allow for market participants, including owners of power-generating facilities using renewable energy sources, to hedge price risks across bidding zone borders, unless an assessment of the forward market on the bidding zone borders performed by the competent regulatory authorities shows that there are sufficient hedging opportunities in the concerned bidding zones. 2. Long-term transmission rights shall be allocated in a transparent, market based and non-discriminatory manner through a single allocation platform. 3. Subject to compliance with Union competition law, market operators shall be free to develop forward hedging products, including long-term forward hedging products, to provide market participants, including owners of power-generating facilities using renewable energy sources, with appropriate possibilities for hedging financial risks against price fluctuations. Member States shall not require that such hedging activity be limited to trades within a Member State or bidding zone.

Article 10 Technical bidding limits 1. There shall be neither a maximum nor a minimum limit to the wholesale electricity price. This provision shall apply, inter alia, to bidding and clearing in all timeframes and shall include balancing energy and imbalance prices, without prejudice to the technical price limits which may be applied in the balancing timeframe and in the day-ahead and intraday timeframes in accordance with paragraph 2. 2. NEMOs may apply harmonised limits on maximum and minimum clearing prices for day-ahead and intraday timeframes. Those limits shall be sufficiently high so as not to unnecessarily restrict trade, shall be harmonised for the internal market and shall take into account the maximum value of lost load. NEMOs shall implement a transparent mechanism to adjust automatically the technical bidding limits in due time in the event that the set limits are expected to be reached. The adjusted higher limits shall remain applicable until further increases under that mechanism are required. 3. Transmission system operators shall not take any measures for the purpose of changing wholesale prices. 4. Regulatory authorities or, where a Member State has designated another competent authority for that purpose, such designated competent authorities, shall identify policies and measures applied within their territory that could contribute to indirectly restricting wholesale price formation, including limiting bids relating to the activation of balancing energy, capacity mechanisms, measures by the transmission system operators, measures intended to challenge market outcomes, or to prevent the abuse of dominant positions or inefficiently defined bidding zones. 5. Where a regulatory authority or designated competent authority has identified a policy or measure which could serve to restrict wholesale price formation it shall take all appropriate actions to eliminate or, if not possible, to mitigate the impact of that policy or measure on bidding behaviour. Member States shall provide a report to the Commission by 5 January 2020 detailing the measures and actions they have taken or intend to take.

Article 11 Value of lost load 1. By 5 July 2020 where required for the purpose of setting a reliability standard in accordance with Article 25 regulatory authorities or, where a Member State has designated another competent authority for that purpose, such designated competent authorities shall determine a single estimate of the value of lost load for their territory. That estimate shall be made publically available. Regulatory authorities or other designated competent authorities may determine different estimates per bidding zone if they have more than one bidding zone in their territory. Where a bidding zone consists of territories of more than one Member State, the concerned regulatory authorities or other designated competent authorities shall determine a single estimate of the value of lost load for that bidding zone. In determining the single estimate of the value of lost load, regulatory authorities or other designated competent authorities shall apply the methodology referred to in Article 23(6). 2. Regulatory authorities and designated competent authorities shall update their estimate of the value of lost load at least every five years, or earlier where they observe a significant change.

Article 12 Dispatching of generation and demand response 1. The dispatching of power-generating facilities and demand response shall be non-discriminatory, transparent and, unless otherwise provided under paragraphs 2 to 6, market based. 2. Without prejudice to Articles 107, 108 and 109 TFEU, Member States shall ensure that when dispatching electricity generating installations, system operators shall give priority to generating installations using renewable energy sources to the extent permitted by the secure operation of the national electricity system, based on transparent and non-discriminatory criteria and where such power-generating facilities are either: (a) power-generating facilities that use renewable energy sources and have an installed electricity capacity of less than 400 kW; or (b) demonstration projects for innovative technologies, subject to approval by the regulatory authority, provided that such priority is limited to the time and extent necessary for achieving the demonstration purposes. 3. A Member State may decide not to apply priority dispatch to power-generating facilities as referred to in point (a) of paragraph 2 with a start of operation at least six months after that decision, or to apply a lower minimum capacity than that set out under point (a) of paragraph 2, provided that: (a) it has well-functioning intraday and other wholesale and balancing markets and that those markets are fully accessible to all market participants in accordance with this Regulation; (b) redispatching rules and congestion management are transparent to all market participants; (c) the national contribution of the Member State towards the Union's binding overall target for share of energy from renewable sources under Article 3(2) of Directive (EU) 2018/2001 of the European Parliament and of the Council (18) and point (a)(2) of Article 4 of Regulation (EU) 2018/1999 of the European Parliament and of the Council (19) is at least equal to the corresponding result of the formula set out in Annex II to Regulation (EU) 2018/1999 and the Member State's share of energy from renewable sources is not below its reference points under point (a)(2) of Article 4 of Regulation (EU) 2018/1999, or alternatively, the Member State's share of energy from renewable sources in gross final electricity consumption is at least 50 %; (d) the Member State has notified the planned derogation to the Commission setting out in detail how the conditions set out under points (a), (b) and (c) are fulfilled; and (e) the Member State has published the planned derogation, including the detailed reasoning for the granting of that derogation, taking due account of the protection of commercially sensitive information where required. Any derogation shall avoid retroactive changes that affect generating installations already benefiting from priority dispatch, notwithstanding any agreement between a Member State and the operator of a generating installation on a voluntary basis. Without prejudice to Articles 107, 108 and 109 TFEU, Member States may provide incentives to installations eligible for priority dispatch to voluntarily give up priority dispatch. 4. Without prejudice to Articles 107, 108 and 109 TFEU, Member States may provide for priority dispatch for electricity generated in power-generating facilities using high-efficiency cogeneration with an installed electricity capacity of less than 400 kW. 5. For power-generating facilities commissioned as from 1 January 2026, point (a) of paragraph 2 shall apply only to power-generating facilities that use renewable energy sources and have an installed electricity capacity of less than 200 kW. 6. Without prejudice to contracts concluded before 4 July 2019, power-generating facilities that use renewable energy sources or high-efficiency cogeneration and were commissioned before 4 July 2019 and, when commissioned, were subject to priority dispatch under Article 15(5) of Directive 2012/27/EU or Article 16(2) of Directive 2009/28/EC of the European Parliament and of the Council (20) shall continue to benefit from priority dispatch. Priority dispatch shall no longer apply to such power-generating facilities from the date on which the power-generating facility becomes subject to significant modifications, which shall be deemed to be the case at least where a new connection agreement is required or where the generation capacity of the power-generating facility is increased. 7. Priority dispatch shall not endanger the secure operation of the electricity system, shall not be used as a justification for curtailment of cross-zonal capacities beyond what is provided for in Article 16 and shall be based on transparent and non-discriminatory criteria.

Article 13 Redispatching 1. The redispatching of generation and redispatching of demand response shall be based on objective, transparent and non-discriminatory criteria. It shall be open to all generation technologies, all energy storage and all demand response, including those located in other Member States unless technically not feasible. 2. The resources that are redispatched shall be selected from among generating facilities, energy storage or demand response using market-based mechanisms and shall be financially compensated. Balancing energy bids used for redispatching shall not set the balancing energy price. 3. Non-market-based redispatching of generation, energy storage and demand response may only be used where: (a) no market-based alternative is available; (b) all available market-based resources have been used; (c) the number of available power generating, energy storage or demand response facilities is too low to ensure effective competition in the area where suitable facilities for the provision of the service are located; or (d) the current grid situation leads to congestion in such a regular and predictable way that market-based redispatching would lead to regular strategic bidding which would increase the level of internal congestion and the Member State concerned either has adopted an action plan to address this congestion or ensures that minimum available capacity for cross-zonal trade is in accordance with Article 16(8). 4. The transmission system operators and distribution system operators shall report at least annually to the competent regulatory authority, on: (a) the level of development and effectiveness of market-based redispatching mechanisms for power generating, energy storage and demand response facilities; (b) the reasons, volumes in MWh and type of generation source subject to redispatching; (c) the measures taken to reduce the need for the downward redispatching of generating installations using renewable energy sources or high-efficiency cogeneration in the future including investments in digitalisation of the grid infrastructure and in services that increase flexibility. The regulatory authority shall submit the report to ACER and shall publish a summary of the data referred to in points (a), (b) and (c) of the first subparagraph together with recommendations for improvement where necessary. 5. Subject to requirements relating to the maintenance of the reliability and safety of the grid, based on transparent and non-discriminatory criteria established by the regulatory authorities, transmission system operators and distribution system operators shall: (a) guarantee the capability of transmission networks and distribution networks to transmit electricity produced from renewable energy sources or high-efficiency cogeneration with minimum possible redispatching, which shall not prevent network planning from taking into account limited redispatching where the transmission system operator or distribution system operator is able to demonstrate in a transparent way that doing so is more economically efficient and does not exceed 5 % of the annual generated electricity in installations which use renewable energy sources and which are directly connected to their respective grid, unless otherwise provided by a Member State in which electricity from power-generating facilities using renewable energy sources or high-efficiency cogeneration represents more than 50 % of the annual gross final consumption of electricity; (b) take appropriate grid-related and market-related operational measures in order to minimise the downward redispatching of electricity produced from renewable energy sources or from high-efficiency cogeneration; (c) ensure that their networks are sufficiently flexible so that they are able to manage them. 6. Where non-market-based downward redispatching is used, the following principles shall apply: (a) power-generating facilities using renewable energy sources shall only be subject to downward redispatching if no other alternative exists or if other solutions would result in significantly disproportionate costs or severe risks to network security; (b) electricity generated in a high-efficiency cogeneration process shall only be subject to downward redispatching if, other than downward redispatching of power-generating facilities using renewable energy sources, no other alternative exists or if other solutions would result in disproportionate costs or severe risks to network security; (c) self-generated electricity from generating installations using renewable energy sources or high-efficiency cogeneration which is not fed into the transmission or distribution network shall not be subject to downward redispatching unless no other solution would resolve network security issues; (d) downward redispatching under points (a), (b) and (c)shall be duly and transparently justified. The justification shall be included in the report under paragraph 3. 7. Where non-market based redispatching is used, it shall be subject to financial compensation by the system operator requesting the redispatching to the operator of the redispatched generation, energy storage or demand response facility except in the case of producers that have accepted a connection agreement under which there is no guarantee of firm delivery of energy. Such financial compensation shall be at least equal to the higher of the following elements or a combination of both if applying only the higher would lead to an unjustifiably low or an unjustifiably high compensation: (a) additional operating cost caused by the redispatching, such as additional fuel costs in the case of upward redispatching, or backup heat provision in the case of downward redispatching of power-generating facilities using high-efficiency cogeneration; (b) net revenues from the sale of electricity on the day-ahead market that the power-generating, energy storage or demand response facility would have generated without the redispatching request; where financial support is granted to power-generating, energy storage or demand response facilities based on the electricity volume generated or consumed, financial support that would have been received without the redispatching request shall be deemed to be part of the net revenues.

CHAPTER III

NETWORK ACCESS AND CONGESTION MANAGEMENT

SECTION 1

Capacity Allocation

Article 14 Bidding zone review 1. Member States shall take all appropriate measures to address congestions. Bidding zone borders shall be based on long-term, structural congestions in the transmission network. Bidding zones shall not contain such structural congestions unless they have no impact on neighbouring bidding zones, or, as a temporary exemption, their impact on neighbouring bidding zones is mitigated through the use of remedial actions and those structural congestions do not lead to reductions of cross-zonal trading capacity in accordance with the requirements of Article 16. The configuration of bidding zones in the Union shall be designed in such a way as to maximise economic efficiency and to maximise cross-zonal trading opportunities in accordance with Article 16, while maintaining security of supply. 2. Every three years, the ENTSO for Electricity shall report on structural congestions and other major physical congestions between and within bidding zones, including the location and frequency of such congestions, in accordance with the capacity allocation and congestion management guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009. That report shall contain an assessment of whether the cross-zonal trade capacity reached the linear trajectory pursuant to Article 15 or the minimum capacity pursuant to Article 16 of this Regulation. 3. In order to ensure an optimal configuration of bidding zones, a bidding zone review shall be carried out. That review shall identify all structural congestions and shall include an analysis of different configurations of bidding zones in a coordinated manner with the involvement of affected stakeholders from all relevant Member States, in accordance with the capacity allocation and congestion management guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009. Current bidding zones shall be assessed on the basis of their ability to create a reliable market environment, including for flexible generation and load capacity, which is crucial to avoiding grid bottlenecks, balancing electricity demand and supply, securing the long-term security of investments in network infrastructure. 4. For the purposes of this Article and of Article 15 of this Regulation, relevant Member States, transmission system operators or regulatory authorities are those Member States, transmission system operators or regulatory authorities participating in the review of the bidding zone configuration and also to those in the same capacity calculation region pursuant to the capacity allocation and congestion management guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009. 5. By 5 October 2019 all relevant transmission system operators shall submit a proposal for the methodology and assumptions that are to be used in the bidding zone review process and for the alternative bidding zone configurations to be considered to the relevant regulatory authorities for approval. The relevant regulatory authorities shall take a unanimous decision on the proposal within 3 months of submission of the proposal. Where the regulatory authorities are unable to reach a unanimous decision on the proposal within that time frame, ACER shall, within an additional three months, decide on the methodology and assumptions and the alternative bidding zone configurations to be considered. The methodology shall be based on structural congestions which are not expected to be overcome within the following three years, taking due account of tangible progress on infrastructure development projects that are expected to be realised within the following three years. 6. On the basis of the methodology and assumptions approved pursuant to paragraph 5, the transmission system operators participating in the bidding zone review shall submit a joint proposal to the relevant Member States or their designated competent authorities to amend or maintain the bidding zone configuration no later than 12 months after approval of the methodology and assumptions pursuant to paragraph 5. Other Member States, Energy Community Contracting Parties or other third countries sharing the same synchronous area with any relevant Member State may submit comments. 7. Where structural congestion has been identified in the report pursuant to paragraph 2 of this Article or in the bidding zone review pursuant to this Article or by one or more transmission system operators in their control areas in a report approved by the competent regulatory authority, the Member State with identified structural congestion shall, in cooperation with its transmission system operators, decide, within six months of receipt of the report, either to establish national or multinational action plans pursuant to Article 15, or to review and amend its bidding zone configuration. Those decisions shall be immediately notified to the Commission and to ACER. 8. For those Member States that have opted to amend the bidding zone configuration pursuant to paragraph 7, the relevant Member States shall reach a unanimous decision within six months of the notification referred to in paragraph 7. Other Member States may submit comments to the relevant Member States, who should take account of those comments when reaching their decision. The decision shall be reasoned and shall be notified to the Commission and ACER. In the event that the relevant Member States fail to reach a unanimous decision within those six months, they shall immediately notify the Commission thereof. As a measure of last resort, the Commission after consulting ACER shall adopt a decision whether to amend or maintain the bidding zone configuration in and between those Member States by six months after receipt of such a notification. 9. Member States and the Commission shall consult relevant stakeholders before adopting a decision under this Article. 10. Any decision adopted under this Article shall specify the date of implementation of any changes. That implementation date shall balance the need for expeditiousness with practical considerations, including forward trade of electricity. The decision may establish appropriate transitional arrangements. 11. Where further bidding zone reviews are launched under the capacity allocation and congestion management guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009, this Article shall apply.

Article 15 Action plans 1. Following the adoption of a decision pursuant to Article 14(7), the Member State with identified structural congestion shall develop an action plan in cooperation with its regulatory authority. That action plan shall contain a concrete timetable for adopting measures to reduce the structural congestions identified within four years of the adoption of the decision pursuant to Article 14(7). 2. Irrespective of the concrete progress of the action plan, Member States shall ensure that without prejudice to derogations granted under Article 16(9) or deviations under Article 16(3), the cross-zonal trade capacity is increased on an annual basis until the minimum capacity provided for in Article 16(8) is reached. That minimum capacity shall be reached by 31 December 2025. Those annual increases shall be achieved by means of a linear trajectory. The starting point of that trajectory shall be either the capacity allocated at the border or on a critical network element in the year before adoption of the action plan or the average during the three years before adoption of the action plan, whichever is higher. Member States shall ensure that, during the implementation of their action plans the capacity made available for cross-zonal trade to be compliant with Article 16(8) is at least equal to the values of the linear trajectory, including by use of remedial actions in the capacity calculation region. 3. The cost of the remedial actions necessary to achieve the linear trajectory referred to in paragraph 2 or make available cross-zonal capacity at the borders or on critical network elements concerned by the action plan shall be borne by the Member State or Member States implementing the action plan. 4. On an annual basis, during the implementation of the action plan and within six months of its expiry, the relevant transmission system operat