02019R0943 — EN — 23.06.2022 — 001.001

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►B 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) (OJ L 158 14.6.2019, p. 54)

Amended by:









▼B

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)







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 ( 1 );

(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 ( 2 );

(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 ( 3 ) and point (a)(2) of Article 4 of Regulation (EU) 2018/1999 of the European Parliament and of the Council ( 4 ) 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 ( 5 ) 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 operators shall assess for the previous 12 months whether the available cross-border capacity has reached the linear trajectory or, from 1 January 2026, the minimum capacities provided for in Article 16(8) have been achieved. They shall submit their assessments to ACER and to the relevant regulatory authorities. Before drafting the report, each transmission system operator shall submit its contribution to the report, including all the relevant data, to its regulatory authority for approval.

5. For those Member States for which the assessments referred to in paragraph 4 demonstrate that a transmission system operator has not complied with the linear trajectory, the relevant Member States shall, within six months of receipt of the assessment report referred to in paragraph 4, decide unanimously whether to amend or maintain the bidding zone configuration within and between those Member States. In their decision, the relevant Member States should take account of any comments submitted by other Member States. The relevant Member States' decision shall be substantiated and shall be notified to the Commission and to ACER.

The relevant Member States shall notify the Commission immediately if they fail to reach a unanimous decision within the timeframe laid down. Within six months of receipt of such notification, the Commission, as a last resort and after consulting ACER and the relevant stakeholders shall adopt a decision whether to amend or maintain the bidding zone configuration in and between those Member States.

6. Six months before the expiry of the action plan, the Member State with identified structural congestion shall decide whether to address remaining congestion by amending its bidding zone or whether to address remaining internal congestion with remedial actions for which it shall cover the costs.

7. Where no action plan is established within six months of identification of structural congestion pursuant to Article 14(7), the relevant transmission system operators shall, within 12 months of identification of such structural congestion, assess whether the available cross-border capacity has reached the minimum capacities provided for in Article 16(8) during the previous 12 months and shall submit an assessment report to the relevant regulatory authorities and to ACER.

Before drafting the report, each transmission system operator shall send its contribution to the report, including all relevant data, to its national regulatory authority for approval. Where the assessment demonstrates that a transmission system operator has not complied with the minimum capacity, the decision-making process laid down in paragraph 5 of this Article shall apply.

Article 16

General principles of capacity allocation and congestion management

1. Network congestion problems shall be addressed with non-discriminatory market-based solutions which give efficient economic signals to the market participants and transmission system operators involved. Network congestion problems shall be solved by means of non-transaction-based methods, namely methods that do not involve a selection between the contracts of individual market participants. When taking operational measures to ensure that its transmission system remains in the normal state, the transmission system operator shall take into account the effect of those measures on neighbouring control areas and coordinate such measures with other affected transmission system operators as provided for in Regulation (EU) 2015/1222.

2. Transaction curtailment procedures shall be used only in emergency situations, namely where the transmission system operator must act in an expeditious manner and redispatching or countertrading is not possible. Any such procedure shall be applied in a non-discriminatory manner. Except in cases of force majeure, market participants that have been allocated capacity shall be compensated for any such curtailment.

3. Regional coordination centres shall carry out coordinated capacity calculation in accordance with paragraphs 4 and 8 of this Article, as provided for in point (a) of Article 37(1) and in Article 42(1).

Regional coordination centres shall calculate cross-zonal capacities respecting operational security limits using data from transmission system operators including data on the technical availability of remedial actions, not including load shedding. Where regional coordination centres conclude that those available remedial actions in the capacity calculation region or between capacity calculation regions are not sufficient to reach the linear trajectory pursuant to Article 15(2) or the minimum capacities provided for in paragraph 8 of this Article while respecting operational security limits, they may, as a measure of last resort, set out coordinated actions reducing the cross-zonal capacities accordingly. Transmission system operators may deviate from coordinated actions in respect of coordinated capacity calculation and coordinated security analysis only in accordance with Article 42(2).

By 3 months after the entry into operation of the regional coordination centres pursuant to Article 35(2) of this Regulation and every three months thereafter, the regional coordination centres shall submit a report to the relevant regulatory authorities and to ACER on any reduction of capacity or deviation from coordinated actions pursuant to the second subparagraph and shall assess the incidences and make recommendations, if necessary, on how to avoid such deviations in the future. If ACER concludes that the prerequisites for a deviation pursuant to this paragraph are not fulfilled or are of a structural nature, ACER shall submit an opinion to the relevant regulatory authorities and to the Commission. The competent regulatory authorities shall take appropriate action against transmission system operators or regional coordination centres pursuant to Article 59 or 62 of Directive (EU) 2019/944 if the prerequisites for a deviation pursuant to this paragraph were not fulfilled.

Deviations of a structural nature shall be addressed in an action plan referred to in Article 14(7) or in an update of an existing action plan.

4. The maximum level of capacity of the interconnections and the transmission networks affected by cross-border capacity shall be made available to market participants complying with the safety standards of secure network operation. Counter-trading and redispatch, including cross-border redispatch, shall be used to maximise available capacities to reach the minimum capacity provided for in paragraph 8. A coordinated and non-discriminatory process for cross-border remedial actions shall be applied to enable such maximisation, following the implementation of a redispatching and counter-trading cost-sharing methodology.

5. Capacity shall be allocated by means of explicit capacity auctions or implicit auctions including both capacity and energy. Both methods may coexist on the same interconnection. For intraday trade, continuous trading, which may be complemented by auctions, shall be used.

6. In the case of congestion, the valid highest value bids for network capacity, whether implicit or explicit, offering the highest value for the scarce transmission capacity in a given timeframe, shall be successful. Other than in the case of new interconnectors which benefit from an exemption under Article 7 of Regulation (EC) No 1228/2003, Article 17 of Regulation (EC) No 714/2009 or Article 63 of this Regulation, establishing reserve prices in capacity-allocation methods shall be prohibited.

7. Capacity shall be freely tradable on a secondary basis, provided that the transmission system operator is informed sufficiently in advance. Where a transmission system operator refuses any secondary trade (transaction), this shall be clearly and transparently communicated and explained to all the market participants by that transmission system operator and notified to the regulatory authority.

8. Transmission system operators shall not limit the volume of interconnection capacity to be made available to market participants as a means of solving congestion inside their own bidding zone or as a means of managing flows resulting from transactions internal to bidding zones. Without prejudice to the application of the derogations under paragraphs 3 and 9 of this Article and to the application of Article 15(2), this paragraph shall be considered to be complied with where the following minimum levels of available capacity for cross-zonal trade are reached: (a) for borders using a coordinated net transmission capacity approach, the minimum capacity shall be 70 % of the transmission capacity respecting operational security limits after deduction of contingencies, as determined in accordance with the capacity allocation and congestion management guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009; (b) for borders using a flow-based approach, the minimum capacity shall be a margin set in the capacity calculation process as available for flows induced by cross-zonal exchange. The margin shall be 70 % of the capacity respecting operational security limits of internal and cross-zonal critical network elements, taking into account contingencies, as determined in accordance with the capacity allocation and congestion management guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009.

The total amount of 30 % can be used for the reliability margins, loop flows and internal flows on each critical network element.

9. At the request of the transmission system operators in a capacity calculation region, the relevant regulatory authorities may grant a derogation from paragraph 8 on foreseeable grounds where necessary for maintaining operational security. Such derogations, which shall not relate to the curtailment of capacities already allocated pursuant to paragraph 2, shall be granted for no more than one-year at a time, or, provided that the extent of the derogation decreases significantly after the first year, up to a maximum of two years. The extent of such derogations shall be strictly limited to what is necessary to maintain operational security and they shall avoid discrimination between internal and cross-zonal exchanges.

Before granting a derogation, the relevant regulatory authority shall consult the regulatory authorities of other Member States forming part of the affected capacity calculation regions. Where a regulatory authority disagrees with the proposed derogation, ACER shall decide whether it should be granted pursuant to point (a) of Article 6(10) of Regulation (EU) 2019/942. The justification and reasons for the derogation shall be published.

Where a derogation is granted, the relevant transmission system operators shall develop and publish a methodology and projects that shall provide a long-term solution to the issue that the derogation seeks to address. The derogation shall expire when the time limit for the derogation is reached or when the solution is applied, whichever is earlier.

10. Market participants shall inform the transmission system operators concerned within a reasonable period in advance of the relevant operational period whether they intend to use allocated capacity. Any allocated capacity that is not going to be used shall be made available again to the market, in an open, transparent and non-discriminatory manner.

11. As far as technically possible, transmission system operators shall net the capacity requirements of any power flows in opposite directions over the congested interconnection line in order to use that line to its maximum capacity. Having full regard to network security, transactions that relieve the congestion shall not be refused.

12. The financial consequences of a failure to honour obligations associated with the allocation of capacity shall be attributed to the transmission system operators or NEMOs who are responsible for such a failure. Where market participants fail to use the capacity that they have committed to use, or, in the case of explicitly auctioned capacity, fail to trade capacity on a secondary basis or give the capacity back in due time, those market participants shall lose the rights to such capacity and shall pay a cost-reflective charge. Any cost-reflective charges for the failure to use capacity shall be justified and proportionate. If a transmission system operator does not fulfil its obligation of providing firm transmission capacity, it shall be liable to compensate the market participant for the loss of capacity rights. Consequential losses shall not be taken into account for that purpose. The key concepts and methods for the determination of liabilities that accrue upon failure to honour obligations shall be set out in advance in respect of the financial consequences, and shall be subject to review by the relevant regulatory authority.

13. When allocating costs of remedial actions between transmission system operators, regulatory authorities shall analyse to what extent flows resulting from transactions internal to bidding zones contribute to the congestion between two bidding zones observed, and allocate the costs based on the contribution to the congestion to the transmission system operators of the bidding zones creating such flows except for costs induced by flows resulting from transactions internal to bidding zones that are below the level that could be expected without structural congestion in a bidding zone.

That level shall be jointly analysed and defined by all transmission system operators in a capacity calculation region for each individual bidding zone border, and shall be subject to the approval of all regulatory authorities in the capacity calculation region.

Article 17

Allocation of cross-zonal capacity across timeframes

1. Transmission system operators shall recalculate available cross-zonal capacity at least after day-ahead gate closure times and after intraday cross-zonal gate closure times. Transmission system operators shall allocate the available cross-zonal capacity plus any remaining cross-zonal capacity not previously allocated and any cross-zonal capacity released by physical transmission right holders from previous allocations in the following cross-zonal capacity allocation process.

2. Transmission system operators shall propose an appropriate structure for the allocation of cross-zonal capacity across timeframes, including day-ahead, intraday and balancing. That allocation structure shall be subject to review by the relevant regulatory authorities. In drawing up their proposal, the transmission system operators shall take into account: (a) the characteristics of the markets; (b) the operational conditions of the electricity system, such as the implications of netting firmly declared schedules; (c) the level of harmonisation of the percentages allocated to different timeframes and the timeframes adopted for the different cross-zonal capacity allocation mechanisms that are already in place.

3. Where cross-zonal capacity is available after the intraday cross-zonal gate closure time, transmission system operators shall use the cross-zonal capacity for the exchange of balancing energy or for the operation of the imbalance netting process.

4. Where cross-zonal capacity is allocated for the exchange of balancing capacity or sharing of reserves pursuant to Article 6(8) of this Regulation, transmission system operators shall use the methodologies developed in the guideline on electricity balancing adopted on the basis of Article 6(11) of Regulation (EC) No 714/2009.

5. Transmission system operators shall not increase the reliability margin calculated pursuant to Regulation (EU) 2015/1222 due to the exchange of balancing capacity or sharing of reserves.







SECTION 2

Network charges and congestion income

Article 18

Charges for access to networks, use of networks and reinforcement

1. Charges applied by network operators for access to networks, including charges for connection to the networks, charges for use of networks, and, where applicable, charges for related network reinforcements, shall be cost-reflective, transparent, take into account the need for network security and flexibility and reflect actual costs incurred insofar as they correspond to those of an efficient and structurally comparable network operator and are applied in a non-discriminatory manner. Those charges shall not include unrelated costs supporting unrelated policy objectives.

Without prejudice to Article 15(1) and (6) of Directive 2012/27/EU and the criteria in Annex XI to that Directive the method used to determine the network charges shall neutrally support overall system efficiency over the long run through price signals to customers and producers and in particular be applied in a way which does not discriminate positively or negatively between production connected at the distribution level and production connected at the transmission level. The network charges shall not discriminate either positively or negatively against energy storage or aggregation and shall not create disincentives for self-generation, self-consumption or for participation in demand response. Without prejudice to paragraph 3 of this Article, those charges shall not be distance-related.

2. Tariff methodologies shall reflect the fixed costs of transmission system operators and distribution system operators and shall provide appropriate incentives to transmission system operators and distribution system operators over both the short and long run, in order to increase efficiencies, including energy efficiency, to foster market integration and security of supply, to support efficient investments, to support related research activities, and to facilitate innovation in interest of consumers in areas such as digitalisation, flexibility services and interconnection.

3. Where appropriate, the level of the tariffs applied to producers or final customers, or both shall provide locational signals at Union level, and take into account the amount of network losses and congestion caused, and investment costs for infrastructure.

4. When setting the charges for network access, the following shall be taken into account: (a) payments and receipts resulting from the inter-transmission system operator compensation mechanism; (b) actual payments made and received as well as payments expected for future periods, estimated on the basis of previous periods.

5. Setting the charges for network access under this Article shall be without prejudice to charges resulting from congestion management referred to in Article 16.

6. There shall be no specific network charge on individual transactions for cross-zonal trading of electricity.

7. Distribution tariffs shall be cost-reflective taking into account the use of the distribution network by system users including active customers. Distribution tariffs may contain network connection capacity elements and may be differentiated based on system users' consumption or generation profiles. Where Member States have implemented the deployment of smart metering systems, regulatory authorities shall consider time-differentiated network tariffs when fixing or approving transmission tariffs and distribution tariffs or their methodologies in accordance with Article 59 of (EU) 2019/944 and, where appropriate, time-differentiated network tariffs may be introduced to reflect the use of the network, in a transparent, cost efficient and foreseeable way for the final customer.

8. Distribution tariff methodologies shall provide incentives to distribution system operators for the most cost-efficient operation and development of their networks including through the procurement of services. For that purpose regulatory authorities shall recognise relevant costs as eligible, shall include those costs in distribution tariffs, and may introduce performance targets in order to provide incentives to distribution system operators to increase efficiencies in their networks, including through energy efficiency, flexibility and the development of smart grids and intelligent metering systems.

9. By 5 October 2019 in order to mitigate the risk of market fragmentation ACER shall provide a best practice report on transmission and distribution tariff methodologies while taking account of national specificities. That best practice report shall address at least: (a) the ratio of tariffs applied to producers and tariffs applied to final customers; (b) the costs to be recovered by tariffs; (c) time-differentiated network tariffs; (d) locational signals; (e) the relationship between transmission tariffs and distribution tariffs; (f) methods to ensure transparency in the setting and structure of tariffs; (g) groups of network users subject to tariffs including, where applicable, the characteristics of those groups, forms of consumption, and any tariff exemptions; (h) losses in high, medium and low-voltage grids.

ACER shall update the best practice report at least once every two years.

10. Regulatory authorities shall duly take the best practice report into consideration when fixing or approving transmission tariffs and distribution tariffs or their methodologies in accordance with Article 59 of Directive (EU) 2019/944.

Article 19

Congestion income

1. Congestion-management procedures associated with a pre-specified timeframe may generate revenue only in the event of congestion which arises for that timeframe, except in the case of new interconnectors which benefit from an exemption under Article 63 of this Regulation, Article 17 of Regulation (EC) No 714/2009 or Article 7 of Regulation (EC) No 1228/2003. The procedure for the distribution of those revenues shall be subject to review by the regulatory authorities and shall neither distort the allocation process in favour of any party requesting capacity or energy nor provide a disincentive to reduce congestion.

2. The following objectives shall have priority with the respect to the allocation of any revenues resulting from the allocation of cross-zonal capacity: (a) guaranteeing the actual availability of the allocated capacity including firmness compensation; or (b) maintaining or increasing cross-zonal capacities through optimisation of the usage of existing interconnectors by means of coordinated remedial actions, where applicable, or covering costs resulting from network investments that are relevant to reduce interconnector congestion.

3. Where the priority objectives set out in paragraph 2 have been adequately fulfilled, the revenues may be used as income to be taken into account by the regulatory authorities when approving the methodology for calculating network tariffs or fixing network tariffs, or both. The residual revenues shall be placed on a separate internal account line until such a time as it can be spent for the purposes set out in paragraph 2.

4. The use of revenues in accordance with point (a) or (b) of paragraph 2 shall be subject to a methodology proposed by the transmission system operators after consulting regulatory authorities and relevant stakeholders and after approval by ACER. The transmission system operators shall submit the proposed methodology to ACER by 5 July 2020 and ACER shall decide on the proposed methodology within six months of receiving it.

ACER may request transmission system operators to amend or update the methodology referred to in the first subparagraph. ACER shall decide on the amended or updated methodology not later than six months after its submission.

The methodology shall set out at least the conditions under which the revenues can be used for the purposes referred to in paragraph 2, the conditions under which those revenues may be placed on a separate internal account line for future use for those purposes, and for how long those revenues may be placed on such an account line.

5. Transmission system operators shall clearly establish, in advance, how any congestion income will be used, and shall report to the regulatory authorities on the actual use of that income. By 1 March each year, the regulatory authorities shall inform ACER and shall publish a report setting out: (a) the amount of revenue collected for the 12-month period ending on 31 December of the previous year; (b) how that revenue was used pursuant to paragraph 2, including the specific projects the income has been used for, and the amount placed on a separate account line; (c) the amount that was used when calculating network tariffs; and (d) verification that the amount referred to in point (c) complies with this Regulation and the methodology developed pursuant to paragraphs 3 and 4.

Where some of the congestion revenues are used when calculating network tariffs, the report shall set out how the transmission system operators fulfilled the priority objectives set out in paragraph 2 where applicable.







CHAPTER IV

RESOURCE ADEQUACY

Article 20

Resource adequacy in the internal market for electricity

1. Member States shall monitor resource adequacy within their territory on the basis of the European resource adequacy assessment referred to in Article 23. For the purpose of complementing the European resource adequacy assessment, Member States may also carry out national resource adequacy assessments pursuant to Article 24.

2. Where the European resource adequacy assessment referred to in Article 23 or national resource adequacy assessment referred to in Article 24 identifies a resource adequacy concern, the Member State concerned shall identify any regulatory distortions or market failures that caused or contributed to the emergence of the concern.

3. Member States with identified resource adequacy concerns shall develop and publish an implementation plan with a timeline for adopting measures to eliminate any identified regulatory distortions or market failures as a part of the State aid process. When addressing resource adequacy concerns, the Member States shall in particular take into account the principles set out in Article 3 and shall consider: (a) removing regulatory distortions; (b) removing price caps in accordance with Article 10; (c) introducing a shortage pricing function for balancing energy as referred to in Article 44(3) of Regulation (EU) 2017/2195; (d) increasing interconnection and internal grid capacity with a view to reaching at least their interconnection targets as referred in point (d)(1) of Article 4 of Regulation (EU) 2018/1999; (e) enabling self-generation, energy storage, demand side measures and energy efficiency by adopting measures to eliminate any identified regulatory distortions; (f) ensuring cost-efficient and market-based procurement of balancing and ancillary services; (g) removing regulated prices where required by Article 5 of Directive (EU) 2019/944.

4. The Member States concerned shall submit their implementation plans to the Commission for review.

5. Within four months of receipt of the implementation plan, the Commission shall issue an opinion on whether the measures are sufficient to eliminate the regulatory distortions or market failures that were identified pursuant to paragraph 2, and may invite the Member States to amend their implementation plans accordingly.

6. The Member States concerned shall monitor the application of their implementation plans and shall publish the results of the monitoring in an annual report and shall submit that report to the Commission.

7. The Commission shall issue an opinion on whether the implementation plans have been sufficiently implemented and whether the resource adequacy concern has been resolved.

8. Member States shall continue to adhere to the implementation plan after the identified resource adequacy concern has been resolved.

Article 21

General principles for capacity mechanisms

1. To eliminate residual resource adequacy concerns, Member States may, as a last resort while implementing the measures referred to in Article 20(3) of this Regulation in accordance with Article 107, 108 and 109 of the TFEU, introduce capacity mechanisms.

2. Before introducing capacity mechanisms, the Member States concerned shall conduct a comprehensive study of the possible effects of such mechanisms on the neighbouring Member States by consulting at least its neighbouring Member States to which they have a direct network connection and the stakeholders of those Member States.

3. Member States shall assess whether a capacity mechanism in the form of strategic reserve is capable of addressing the resource adequacy concerns. Where this is not the case, Member States may implement a different type of capacity mechanism.

4. Member States shall not introduce capacity mechanisms where both the European resource adequacy assessment and the national resource adequacy assessment, or in the absence of a national resource adequacy assessment, the European resource adequacy assessment have not identified a resource adequacy concern.

5. Member States shall not introduce capacity mechanisms before the implementation plan as referred to in Article 20(3) has received an opinion by the Commission as referred to in Article 20(5).

6. Where a Member State applies a capacity mechanism, it shall review that capacity mechanism and shall ensure that no new contracts are concluded under that mechanism where both the European resource adequacy assessment and the national resource adequacy assessment, or in the absence of a national resource adequacy assessment, the European resource adequacy assessment have not identified a resource adequacy concern or the implementation plan as referred to in Article 20(3) has not received an opinion by the Commission as referred to in Article 20(5).

7. When designing capacity mechanisms Member States shall include a provision allowing for an efficient administrative phase-out of the capacity mechanism where no new contracts are concluded under paragraph 6 during three consecutive years.

8. Capacity mechanisms shall be temporary. They shall be approved by the Commission for no longer than 10 years. They shall be phased out or the amount of the committed capacities shall be reduced on the basis of the implementation plans referred to in Article 20. Member States shall continue to apply the implementation plan after the introduction of the capacity mechanism.

Article 22

Design principles for capacity mechanisms

1. Any capacity mechanism shall: (a) be temporary; (b) not create undue market distortions and not limit cross-zonal trade; (c) not go beyond what is necessary to address the adequacy concerns referred to in Article 20; (d) select capacity providers by means of a transparent, non-discriminatory and competitive process; (e) provide incentives for capacity providers to be available in times of expected system stress; (f) ensure that the remuneration is determined through the competitive process; (g) set out the technical conditions for the participation of capacity providers in advance of the selection process; (h) be open to participation of all resources that are capable of providing the required technical performance, including energy storage and demand side management; (i) apply appropriate penalties to capacity providers that are not available in times of system stress.

2. The design of strategic reserves shall meet the following requirements: (a) where a capacity mechanism has been designed as a strategic reserve, the resources thereof are to be dispatched only if the transmission system operators are likely to exhaust their balancing resources to establish an equilibrium between demand and supply; (b) during imbalance settlement periods where resources in the strategic reserve are dispatched, imbalances in the market are to be settled at least at the value of lost load or at a higher value than the intraday technical price limit as referred in Article 10(1), whichever is higher; (c) the output of the strategic reserve following dispatch is to be attributed to balance responsible parties through the imbalance settlement mechanism; (d) the resources taking part in the strategic reserve are not to receive remuneration from the wholesale electricity markets or from the balancing markets; (e) the resources in the strategic reserve are to be held outside the market for at least the duration of the contractual period.

The requirement referred to in point (a) of the first subparagraph shall be without prejudice to the activation of resources before actual dispatch in order to respect the ramping constraints and operating requirements of the resources. The output of the strategic reserve during activation shall not be attributed to balance groups through wholesale markets and shall not change their imbalances.

3. In addition to the requirements laid down in paragraph 1, capacity mechanisms other than strategic reserves shall: (a) be constructed so as to ensure that the price paid for availability automatically tends to zero when the level of capacity supplied is expected to be adequate to meet the level of capacity demanded; (b) remunerate the participating resources only for their availability and ensure that the remuneration does not affect decisions of the capacity provider on whether or not to generate; (c) ensure that capacity obligations are transferable between eligible capacity providers.

4. Capacity mechanisms shall incorporate the following requirements regarding CO2 emission limits: (a) from 4 July 2019 at the latest, generation capacity that started commercial production on or after that date and that emits more than 550 g of CO2 of fossil fuel origin per kWh of electricity shall not be committed or to receive payments or commitments for future payments under a capacity mechanism; (b) from 1 July 2025 at the latest, generation capacity that started commercial production before 4 July 2019 and that emits more than 550 g of CO2 of fossil fuel origin per kWh of electricity and more than 350 kg CO2 of fossil fuel origin on average per year per installed kWe shall not be committed or receive payments or commitments for future payments under a capacity mechanism.

The emission limit of 550 g CO2 of fossil fuel origin per kWh of electricity and the limit of 350 kg CO2 of fossil fuel origin on average per year per installed kWe referred to in points (a) and (b) of the first subparagraph shall be calculated on the basis of the design efficiency of the generation unit meaning the net efficiency at nominal capacity under the relevant standards provided for by the International Organization for Standardization.

By 5 January 2020, ACER shall publish an opinion providing technical guidance related to the calculation of the values referred in the first subparagraph.

5. Member States that apply capacity mechanisms on 4 July 2019 shall adapt their mechanisms to comply with Chapter 4 without prejudice to commitments or contracts concluded by 31 December 2019.

Article 23

European resource adequacy assessment

1. The European resource adequacy assessment shall identify resource adequacy concerns by assessing the overall adequacy of the electricity system to supply current and projected demands for electricity at Union level, at the level of the Member States, and at the level of individual bidding zones, where relevant. The European resource adequacy assessment shall cover each year within a period of 10 years from the date of that assessment.

2. The European resource adequacy assessment shall be conducted by the ENTSO for Electricity.

3. By 5 January 2020, the ENTSO for Electricity shall submit to the Electricity Coordination Group set up under Article 1 of Commission Decision of 15 November 2012 ( 6 ) and ACER a draft methodology for the European resource adequacy assessment based on the principles provided for in paragraph 5 of this Article.

4. Transmission system operators shall provide the ENTSO for Electricity with the data it needs to carry out the European resource adequacy assessment.

The ENTSO for Electricity shall carry out the European resource adequacy assessment on an annual basis. Producers and other market participants shall provide transmission system operators with data regarding expected utilisation of the generation resources, taking into account the availability of primary resources and appropriate scenarios of projected demand and supply.

5. The European resource adequacy assessment shall be based on a transparent methodology which shall ensure that the assessment: (a) is carried out on each bidding zone level covering at least all Member States; (b) is based on appropriate central reference scenarios of projected demand and supply including an economic assessment of the likelihood of retirement, mothballing, new-build of generation assets and measures to reach energy efficiency and electricity interconnection targets and appropriate sensitivities on extreme weather events, hydrological conditions, wholesale prices and carbon price developments; (c) contains separate scenarios reflecting the differing likelihoods of the occurrence of resource adequacy concerns which the different types of capacity mechanisms are designed to address; (d) appropriately takes account of the contribution of all resources including existing and future possibilities for generation, energy storage, sectoral integration, demand response, and import and export and their contribution to flexible system operation; (e) anticipates the likely impact of the measures referred in Article 20(3); (f) includes variants without existing or planned capacity mechanisms and, where applicable, variants with such mechanisms; (g) is based on a market model using the flow-based approach, where applicable; (h) applies probabilistic calculations; (i) applies a single modelling tool; (j) includes at least the following indicators referred to in Article 25: — ‘expected energy not served’, and — ‘loss of load expectation’; (k) identifies the sources of possible resource adequacy concerns, in particular whether it is a network constraint, a resource constraint, or both; (l) takes into account real network development; (m) ensures that the national characteristics of generation, demand flexibility and energy storage, the availability of primary resources and the level of interconnection are properly taken into consideration.

6. By 5 January 2020, the ENTSO for Electricity shall submit to ACER a draft methodology for calculating: (a) the value of lost load; (b) the cost of new entry for generation, or demand response; and (c) the reliability standard referred to in Article 25.

The methodology shall be based on transparent, objective and verifiable criteria.

7. The proposals under paragraphs 3 and 6 for the draft methodology, the scenarios, sensitivities and assumptions on which they are based, and the results of the European resource adequacy assessment under paragraph 4 shall be subject to the prior consultation of Member States, the Electricity Coordination Group and relevant stakeholders and approval by ACER under the procedure set out in Article 27.

Article 24

National resource adequacy assessments

1. National resource adequacy assessments shall have a regional scope and shall be based on the methodology referred in Article 23(3) in particular in points (b) to (m) of Article 23(5).

National resource adequacy assessments shall contain the reference central scenarios as referred to in point (b) of Article 23(5).

National resource adequacy assessments may take into account additional sensitivities to those referred in point (b) of Article 23(5). In such cases, national resource adequacy assessments may:

(a) make assumptions taking into account the particularities of national electricity demand and supply;

(b) use tools and consistent recent data that are complementary to those used by the ENTSO for Electricity for the European resource adequacy assessment.

In addition, the national resource adequacy assessments, in assessing the contribution of capacity providers located in another Member State to the security of supply of the bidding zones that they cover, shall use the methodology as provided for in point (a) of Article 26(11).

2. National resource adequacy assessments and, where applicable, the European resource adequacy assessment and the opinion of ACER pursuant to paragraph 3 shall be made publicly available.

3. Where the national resource adequacy assessment identifies an adequacy concern with regard to a bidding zone that was not identified in the European resource adequacy assessment, the national resource adequacy assessment shall include the reasons for the divergence between the two resource adequacy assessments, including details of the sensitivities used and the underlying assumptions. Member States shall publish that assessment and submit it to ACER.

Within two months of the date of the receipt of the report, ACER shall provide an opinion on whether the differences between the national resource adequacy assessment and the European resource adequacy assessment are justified.

The body that is responsible for the national resource adequacy assessment shall take due account of ACER's opinion, and where necessary shall amend its assessment. Where it decides not to take ACER's opinion fully into account, the body that is responsible for the national resource adequacy assessment shall publish a report with detailed reasons.

Article 25

Reliability standard

1. When applying capacity mechanisms Member States shall have a reliability standard in place. A reliability standard shall indicate the necessary level of security of supply of the Member State in a transparent manner. In the case of cross-border bidding zones, such reliability standards shall be established jointly by the relevant authorities.

2. The reliability standard shall be set by the Member State or by a competent authority designated by the Member State, following a proposal by the regulatory authority. The reliability standard shall be based on the methodology set out in Article 23(6).

3. The reliability standard shall be calculated using at least the value of lost load and the cost of new entry over a given timeframe and shall be expressed as ‘expected energy not served’ and ‘loss of load expectation’.

4. When applying capacity mechanisms, the parameters determining the amount of capacity procured in the capacity mechanism shall be approved by the Member State or by a competent authority designated by the Member State, on the basis of a proposal of the regulatory authority.

Article 26

Cross-border participation in capacity mechanisms

1. Capacity mechanisms other than strategic reserves and where technically feasible, strategic reserves shall be open to direct cross-border participation of capacity providers located in another Member State, subject to the conditions laid down in this Article.

2. Member States shall ensure that foreign capacity capable of providing equivalent technical performance to domestic capacities has the opportunity to participate in the same competitive process as domestic capacity. In the case of capacity mechanisms in operation on 4 July 2019, Member States may allow interconnectors to participate directly in the same competitive process as foreign capacity for a maximum of four years from 4 July 2019 or two years after the date of approval of the methodologies referred to in paragraph 11, whichever is earlier.

Member States may require foreign capacity to be located in a Member State that has a direct network connection with the Member State applying the mechanism.

3. Member States shall not prevent capacity which is located in their territory from participating in capacity mechanisms of other Member States.

4. Cross-border participation in capacity mechanisms shall not change, alter or otherwise affect cross-zonal schedules or physical flows between Member States. Those schedules and flows shall be determined solely by the outcome of capacity allocation pursuant to Article 16.

5. Capacity providers shall be able to participate in more than one capacity mechanism.

Where capacity providers participate in more than one capacity mechanism for the same delivery period, they shall participate up to the expected availability of interconnection and the likely concurrence of system stress between the system where the mechanism is applied and the system in which the foreign capacity is located, in accordance with the methodology referred to in point (a) of paragraph 11.

6. Capacity providers shall be required to make non-availability payments where their capacity is not available.

Where capacity providers participate in more than one capacity mechanism for the same delivery period, they shall be required to make multiple non-availability payments where they are unable to fulfil multiple commitments.

7. For the purposes of providing a recommendation to transmission system operators, regional coordination centres established pursuant to Article 35 shall calculate on an annual basis the maximum entry capacity available for the participation of foreign capacity. That calculation shall take into account the expected availability of interconnection and the likely concurrence of system stress in the system where the mechanism is applied and the system in which the foreign capacity is located. Such a calculation shall be required for each bidding zone border.

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