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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.)

Type Regulation

Publication 2019-06-14

Last updated 2024-07-16

State In force

Department Council of the European Union, European Parliament

Source EUR-Lex

articles 82

Reform history JSON API

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 the objective to achieve climate neutrality by 2050 at the latest, in particular the climate and energy framework for 2030 by enabling market signals to be delivered for increased efficiency, higher share of renewable energy, security of supply, flexibility, system integration through multiple energy carriers, 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, enable the development of forward electricity markets to allow suppliers and consumers to hedge or protect themselves against the risk of future volatility in electricity prices, empower and protect consumers, ensure competitiveness on the global market, enhance security of supply and flexibility through demand response, energy storage and other non-fossil flexibility solutions, ensure energy efficiency, facilitate aggregation of distributed demand and supply, and enable market and sectoral integration and market-based remuneration of electricity generated from renewable energy;

(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;

(e) support long-term investment in renewable energy generation, flexibility and grids to enable consumers to make their energy bills affordable and less dependent from fluctuations of short-term electricity market prices, in particular fossil fuel prices in the medium to long-term;

(f) lay down a framework for the adoption of measures to address electricity price crises.

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 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 ([^E0001]);

(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 ([^E0002]);

(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;

(72) ‘peak hour’ means an hour where, on the basis of the forecasts of transmission system operators and, where applicable, NEMOs, the gross electricity consumption or the gross consumption of electricity generated from sources other than renewable sources or the day-ahead wholesale electricity price is expected to be the highest, taking cross-zonal exchanges into account;

(73) ‘peak shaving’ means the ability of market participants to reduce electricity consumption from the grid at peak hours at the request of the system operator;

(74) ‘peak-shaving product’ means a market-based product by means of which market participants can provide peak shaving to system operators;

(75) ‘regional virtual hub’ means a non-physical region covering more than one bidding zone for which a reference price is set on the basis of a methodology;

(76) ‘two-way contract for difference’ means a contract between a power-generating facility operator and a counterpart, usually a public entity, that provides both minimum remuneration protection and a limit to excess remuneration;

(77) ‘power purchase agreement’ or ‘PPA’ means a contract under which a natural or legal person agrees to purchase electricity from an electricity producer on a market basis;

(78) ‘dedicated measurement device’ means a device linked to or embedded in an asset that provides demand response or flexibility services on the electricity market or to system operators;

(79) ‘flexibility’ means the ability of an electricity system to adjust to the variability of generation and consumption patterns and to grid availability, across relevant market timeframes.

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

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.

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.

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.

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

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.

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.

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.

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.

The imbalances shall be settled at a price that reflects the real-time value of energy.

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.

The dimensioning of reserve capacity shall be performed by the transmission system operators and shall be facilitated at regional level.

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.

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;

(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

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 by ACER pursuant to Articles 4 and 8 of Regulation (EU) 2019/942 and shall be subject to transparency obligations and effective supervision against market manipulation as laid down in the relevant provisions of Regulation (EU) No 1227/2011.

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 and intra-zonal trade in a non-discriminatory manner and as close as possible to real time across and within all bidding zones;

(ca) be organised in such a way as to ensure the sharing of liquidity between all NEMOs, at all times, both for cross-zonal and for intra-zonal trade. For the day-ahead market, from one hour before the gate closure time until the latest point in time where day-ahead trade is allowed, NEMOs shall submit all orders for day-ahead products and products with the same characteristics to the single day-ahead coupling on the one hand and shall not organise trading with day-ahead products or products with the same characteristics outside the single day-ahead coupling on the other. For the intraday market, from the single intraday coupling gate opening time until the latest point in time when intraday trading is allowed in a given bidding zone, NEMOs shall submit all orders for intraday products and products with same characteristics to the single intraday coupling on the one hand and shall not organise trading with intraday products or products with same characteristics outside the intraday coupling on the other. Those obligations shall apply to NEMOs, to undertakings which directly or indirectly exercise control over a NEMO, and to undertakings which are directly or indirectly controlled by a NEMO;

(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 and, where applicable, provide information by generation units 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 7a

Peak-shaving product

Where a regional or Union-wide electricity price crisis is declared in accordance with Article 66a of Directive (EU) 2019/944, Member States may request system operators to propose the procurement of peak-shaving products in order to achieve a reduction of electricity demand during peak hours. Such procurement shall be limited to the duration set out in the implementing decision adopted pursuant to Article 66a(1) of Directive (EU) 2019/944.

Where a request is made pursuant to paragraph 1, system operators shall, after consulting stakeholders, submit a proposal setting out the dimensioning and conditions for the procurement and activation of the peak-shaving product to the regulatory authority of the Member State concerned for its approval.

The regulatory authority concerned shall assess the proposal for a peak-shaving product referred to in paragraph 2 as regards achieving a reduction of electricity demand and the impact on wholesale electricity price during peak hours. That assessment shall take into account the need for the peak-shaving product not to unduly distort the functioning of the electricity markets, and not to cause a redirection of demand response services towards peak-shaving products. On the basis of that assessment, the regulatory authority may request the system operator to amend its proposal.

The proposal for a peak-shaving product referred to in paragraph 2 shall comply with the following requirements:

(a) the dimensioning of the peak-shaving product shall:
(i) be based on an analysis of the need for an additional service to ensure security of supply without endangering grid stability, of its impact on the market and of its expected costs and benefits;
(ii) take into account the forecast of demand, the forecast of electricity generated from renewable energy, the forecast of other sources of flexibility in the system, such as energy storage, and the wholesale price impact of the avoided dispatch; and
(iii) be limited to ensure that forecasted costs do not exceed the expected benefits of the peak-shaving product;

(b) the procurement of a peak-shaving product shall be based on objective, transparent, market-based and non-discriminatory criteria, shall be limited to demand response and shall not exclude participating assets from accessing other markets;

(c) the procurement of the peak-shaving product shall take place using competitive bidding, which can be continuous, with selection based on the lowest cost of meeting pre-defined technical and environmental criteria and shall allow the effective participation of consumers, directly or through aggregation;

(d) the minimum bid size shall not be higher than 100 kW, including through aggregation;

(e) contracts for a peak-shaving product shall not be concluded more than a week before its activation;

(f) the activation of the peak-shaving product shall not reduce cross-zonal capacity;

(g) the activation of the peak-shaving product shall take place before or within the day-ahead market time frame and may be done on the basis of a pre-defined electricity price;

(h) the activation of the peak-shaving product shall not imply starting fossil fuel-based generation located behind the metering point, in order to avoid increasing greenhouse gas emissions.

The actual reduction of consumption resulting from the activation of a peak-shaving product shall be measured against a baseline, reflecting the expected electricity consumption without the activation of the peak-shaving product. Where a system operator procures a peak-shaving product, that operator shall develop a baseline methodology after consulting market participants, shall, where relevant, take into account the implementing acts adopted pursuant to Article 59(1), point (e), and shall submit it to the regulatory authority concerned for its approval.

The regulatory authority concerned shall approve the proposal of the system operators seeking to procure a peak-shaving product and the baseline methodology submitted in accordance with paragraphs 2 and 5 or shall request the system operators to amend the proposal or the baseline methodology where that proposal or that methodology does not meet the requirements laid down in paragraphs 2, 4 and 5.

By six months after the end of a regional or Union-wide electricity price crisis as referred to in paragraph 1, ACER shall, after consulting stakeholders, assess the impact of using peak-shaving products on the Union electricity market. That assessment shall take into account the need for peak-shaving products not to unduly distort the functioning of the electricity markets, and not to cause a redirection of demand response services towards peak-shaving products. ACER may issue recommendations that regulatory authorities shall take into account in their assessment pursuant to paragraph 3.

By 30 June 2025, ACER shall, after consulting stakeholders, assess the impact of developing peak-shaving products on the Union electricity market under normal market circumstances. That assessment shall take into account the need for peak-shaving products not to unduly distort the functioning of the electricity markets, and not to cause a redirection of demand response services towards peak-shaving products. On the basis of that assessment, the Commission may submit a legislative proposal to amend this Regulation in order to introduce peak-shaving products outside regional or Union-wide electricity price crisis situations.

Article 7b

Dedicated measurement device

Without prejudice to Article 19 of Directive (EU) 2019/944, transmission system operators, distribution system operators and relevant market participants, including independent aggregators, may use, upon the consent of the final customer, data from dedicated measurement devices for the observability and settlement of demand response and flexibility services, including from energy storage facilities.

For the purposes of this Article, the use of data from dedicated measurement devices shall comply with Articles 23 and 24 of Directive (EU) 2019/944 and other relevant Union law, including data protection and privacy law, in particular Regulation (EU) 2016/679 of the European Parliament and of the Council ([^E0003]). Where such data are used for research purposes, information shall be aggregated and anonymised.

Where a final customer does not have a smart meter installed or where the smart meter of a final customer does not deliver the necessary data to provide demand response or flexibility services, including through an independent aggregator, transmission system operators and distribution system operators shall accept the data from a dedicated measurement device, where available, for the settlement of demand response and flexibility services, including energy storage, and shall not discriminate against that final customer in their procurement of flexibility services. That obligation shall apply subject to compliance with the rules and requirements established by the Member States pursuant to paragraph 3.

Member States shall establish the rules and requirements for a dedicated measurement device data validation process to check and ensure the quality and consistency of the relevant data, and interoperability, in accordance with Articles 23 and 24 of Directive (EU) 2019/944 and other relevant Union law.

Article 8

Trade on day-ahead and intraday markets

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. From 1 January 2026, the intraday cross-zonal gate closure time shall not be more than 30 minutes ahead of real time.

1a. The regulatory authority concerned may, at the request of the transmission system operator concerned, grant a derogation from the requirement laid down in paragraph 1 until 1 January 2029. The transmission system operator shall submit the request to the regulatory authority concerned. That request shall include:

(a) an impact assessment, taking into account feedback from NEMOs and market participants concerned, demonstrating the negative impact of such a measure on the security of supply in the national electricity system, cost-efficiency, including in relation to existing balancing platforms in accordance with Regulation (EU) 2017/2195, on the integration of renewable energy and on greenhouse gas emissions; and

(b) an action plan aiming to shorten the intraday cross-zonal gate closure time to 30 minutes ahead of real time by 1 January 2029.

1b. The regulatory authority may, at the request of the transmission system operator concerned, grant a further derogation from the requirement laid down in paragraph 1 by up to two-and-a-half years from the date of expiry of the period referred to in paragraph 1a. The transmission system operator concerned shall submit the request to the regulatory authority concerned, to the ENTSO for Electricity and to ACER by 30 June 2028. That request shall include:

(a) a new impact assessment, taking into account feedback from market participants and NEMOs, justifying the need for a further derogation, based on risks to the security of supply in the national electricity system, cost-efficiency, the integration of renewable energy, and greenhouse gas emissions; and

(b) a revised action plan to shorten the intraday cross-zonal gate closure time to 30 minutes ahead of real time by the date for which extension is requested and no later than the date requested for the derogation.

ACER shall issue an opinion about the cross-border impact of a further derogation within six months of receipt of a request for such a derogation. The regulatory authority concerned shall take that opinion into account before deciding upon a request for further derogation.

1c. By 1 December 2027, the Commission shall, after consulting NEMOs, ENTSO for Electricity, ACER and relevant stakeholders, submit a report to the European Parliament and to the Council assessing the impact of the implementation of the decreasing of the cross-zonal gate closure time established pursuant to this Article, the costs and benefits, the feasibility and practical solutions towards further decreasing it in order to allow market participants to trade energy as close to real time as possible. The report shall consider the impact on the electricity system security, the cost-efficiency, the benefits to the integration of renewable energy and to the reduction of greenhouse gas emissions.

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.

NEMOs shall provide products for trading in day-ahead and intraday markets which are sufficiently small in size, with minimum bid sizes of 100 kW or less, to allow for the effective participation of demand response, energy storage and small-scale renewables including direct participation by customers, as well as through aggregation.

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

In accordance with Regulation (EU) 2016/1719, transmission system operators shall issue long-term transmission rights or have equivalent measures in place to allow market participants, including owners of power-generating facilities using renewable energy, to hedge price risks, 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 bidding zones concerned.

Long-term transmission rights shall be allocated, on a regular basis, in a transparent, market based and non-discriminatory manner through a single allocation platform. The frequency of allocation and the maturities of the long-term cross-zonal capacity shall support the efficient functioning of the Union’s forward markets.

The design of the Union’s forward markets shall comprise the necessary tools to improve the ability of market participants to hedge price risks in the internal electricity market.

By 17 January 2026, the Commission shall, after consulting relevant stakeholders, carry out an assessment of the impact of possible measures to achieve the objective referred to in paragraph 3. That impact assessment shall, inter alia, cover:

(a) possible changes to the frequency of allocation for long-term transmission rights;

(b) possible changes to the maturities of long-term transmission rights, in particular maturities extended up to at least three years;

(d) ways to strengthen the secondary market; and

(e) the possible introduction of regional virtual hubs for the forward markets.

As regards regional virtual hubs for the forward markets, the impact assessment carried out pursuant to paragraph 4 shall cover the following:

(a) the adequate geographical scope of the regional virtual hubs, including the bidding zones that would constitute those hubs and specific situations of bidding zones belonging to two or more virtual hubs, aiming to maximise the price correlation between the reference prices and the prices of the bidding zones constituting regional virtual hubs;

(b) the level of electricity interconnectivity of Member States, in particular of those Member States below the electricity interconnection targets for 2020 and 2030 laid down in Article 4, point (d)(1), of Regulation (EU) 2018/1999 of the European Parliament and of the Council ([^E0004]);

(c) the methodology for the calculation of the reference prices for the regional virtual hubs for the forward markets, aiming to maximise the price correlation between the reference price and the prices of the bidding zones constituting a regional virtual hub;

(d) the possibility for bidding zones to form part of more than one regional virtual hub;

(e) the ways to maximise trading opportunities for hedging products referencing the regional virtual hubs for the forward markets as well as for long term transmission rights from bidding zones to regional virtual hubs;

(f) the ways to ensure that the single allocation platform referred to in paragraph 2 offers allocation and facilitates the trading of long-term transmission rights;

(g) the implications of pre-existing intergovernmental agreements and rights thereunder.

On the basis of the outcome of the impact assessment referred to in paragraph 4 of this Article, the Commission shall, by 17 July 2026, adopt an implementing act to further specify measures and tools to achieve the objectives referred to in in paragraph 3 of this Article and the precise features of those measures and tools. That implementing act shall be adopted in accordance with the examination procedure referred to Article 67(2).

The single allocation platform established in accordance with Regulation (EU) 2016/1719 shall act as an entity offering allocation and facilitating the trading of long-term transmission rights on behalf of transmission system operators. It shall have a legal form as referred to in Annex II to Directive (EU) 2017/1132 of the European Parliament and of the Council ([^E0005]).

Where a competent regulatory authority considers that there are insufficient hedging opportunities available for market participants, it may, after consulting the competent authorities designated pursuant to Article 67 of Directive 2014/65/EU of the European Parliament and of the Council ([^E0006]) where the forward markets concern financial instruments as defined in Article 4(1), point (15), of that Directive, require power exchanges or transmission system operators to implement additional measures, such as market-making activities, to improve the liquidity of the forward markets.

Subject to compliance with Union competition law and with Regulations (EU) No 648/2012 ([^E0007]) and (EU) No 600/2014 ([^E0008]) of the European Parliament and of the Council and Directive 2014/65/EU, market operators may 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 may be limited to trades within a Member State or bidding zone.

Article 10

Technical bidding limits

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.

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.

Transmission system operators shall not take any measures for the purpose of changing wholesale prices.

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.

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

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).

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

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.

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.

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 ([^E0009]) and point (a)(2) of Article 4 of Regulation (EU) 2018/1999 of the European Parliament and of the Council ([^E0010]) 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.

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.

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.

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 ([^E0011]) 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.

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

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.

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.

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).

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.

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;

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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