LegalizeRegulation (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.)
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 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 (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;
(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
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.
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.
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.
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.
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.
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.
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
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
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.
Article 7b
Dedicated measurement device
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 (3). Where such data are used for research purposes, information shall be aggregated and anonymised.
Article 8
Trade on day-ahead and intraday markets
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.
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.
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
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;
(c) possible changes to the nature of long-term transmission rights;
(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 (4);
(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.
Article 10
Technical bidding limits
Article 11
Value of lost load
Article 12
Dispatching of generation and demand response
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 (9) and point (a)(2) of Article 4 of Regulation (EU) 2018/1999 of the European Parliament and of the Council (10) 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.
Article 13
Redispatching
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;
(c) ensure that their networks are sufficiently flexible so that they are able to manage them.
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
Article 15
Action plans
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.
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.
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
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.
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.
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.
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
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.
SECTION 2
Network charges and congestion income
Article 18
Charges for access to networks, use of networks and reinforcement
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.
Tariff methodologies shall:
(a) reflect the fixed costs of transmission system operators and distribution system operators and shall consider both capital and operational expenditure to provide appropriate incentives to transmission system operators and distribution system operators over both the short and long term including anticipatory investment, in order to increase efficiencies including energy efficiency;
(b) foster market integration, the integration of renewable energy and security of supply;
(c) support the use of flexibility services and enable the use of flexible connections;
(d) promote efficient and timely investment, including solutions to optimise the existing grid;
(e) facilitate energy storage, demand response and related research activities;
(f) contribute to the achievement of the objectives set out in the integrated national energy and climate plans, reduce the environmental impact and promote public acceptance; and
(g) facilitate innovation in the interest of consumers in areas such as digitalisation, flexibility services and interconnection, in particular to develop the required infrastructure to reach the minimum electricity interconnection target for 2030 laid down in Article 4, point (d)(1), of Regulation (EU) 2018/1999.
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.
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 be determined after consulting relevant stakeholders, to ensure transparency in the setting and structure of tariffs, including anticipatory investment, that are in line with relevant Union and national energy objectives and taking into account the acceleration areas as established in accordance with Directive (EU) 2018/2001;
(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;
(i) incentives for efficient investment in networks, including resources providing flexibility and flexible connection agreements.
ACER shall update the best practice report at least once every two years.
Article 19
Congestion income
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;
(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 investment that is relevant to reducing interconnector congestion; or
(c) compensating offshore renewable electricity generation plant operators in an offshore bidding zone directly connected to two or more bidding zones where access to interconnected markets has been reduced in such a way that it results in the offshore renewable electricity generation plant operator not being able to export its electricity generation capability to the market and, where relevant, in a corresponding price decrease in the offshore bidding zone compared to without-capacity reductions.
The compensation referred to in point (c) of the first subparagraph shall apply where, in the validated capacity calculation results, one or more transmission system operators either have not made available the capacity agreed in connection agreements on the interconnector or have not made available the capacity on the critical network elements pursuant to the capacity calculation rules laid down in Article 16(8), or both. The transmission system operators which are responsible for the reduction of access to interconnected markets shall be responsible for the compensation to offshore renewable electricity generation plant operators. On an annual basis, that compensation shall not exceed the total congestion income generated on interconnectors between the bidding zones concerned.
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.
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 IIIa
SPECIFIC INVESTMENT INCENTIVES TO ACHIEVE THE UNION’S DECARBONISATION OBJECTIVES
Article 19a
Power purchase agreements
Article 19b
Voluntary templates for PPAs and monitoring of PPAs
Where the assessment concludes that there is a need to develop and issue such voluntary templates for PPAs, ACER, together with the NEMOs, and after consulting the relevant stakeholders, shall develop such templates, taking into account the following:
(a) the use of those contract templates shall be voluntary for the contracting parties;
(b) the contract templates shall, inter alia: (i) offer a variety of contract durations; (ii) provide a variety of price formulas; (iii) consider the offtaker’s load profile and the generator’s generation profile.
Article 19c
Measures at Union level to contribute to the achievement of the additional share of energy from renewable sources
The Commission shall assess whether measures at Union level can contribute to the achievement of the Member States collective endeavour of an additional 2,5 % share of energy from renewable sources in the Union’s gross final consumption of energy in 2030 pursuant to Directive (EU) 2018/2001, complementing national measures. The Commission shall analyse the possibility to use the Union renewable energy financing mechanism established pursuant to Article 33 of Regulation (EU) 2018/1999 to organise Union-level renewable energy auctions in line with the relevant regulatory framework.
Article 19d
Direct price support schemes in the form of two-way contracts for difference for investment
The first subparagraph shall apply to contracts under direct price support schemes for investment in new generation concluded on or after 17 July 2027, or, in the case of offshore hybrid asset projects connected to two or more bidding zones, 17 July 2029.
The participation of market participants in direct price support schemes in the form of two-way contracts for difference and in equivalent schemes with the same effects shall be voluntary.
All direct price support schemes in the form of two-way contracts for difference and equivalent schemes with the same effects shall be designed to:
(a) preserve incentives for the power-generating facility to operate and participate efficiently in the electricity markets, in particular to reflect market circumstances;
(b) prevent any distortive effect of the support scheme on the operation, dispatch and maintenance decisions of the power-generating facility or on bidding behaviour in day-ahead, intraday, ancillary services and balancing markets;
(c) ensure that the level of the minimum remuneration protection and of the upward limit to excess remuneration are aligned with the cost of the new investment and the market revenues, to guarantee the long-term economic viability of the power-generating facility while avoiding overcompensation;
(d) avoid undue distortions to competition and trade in the internal market, in particular by determining remuneration amounts through an open, clear, transparent and non-discriminatory competitive bidding process; where no such competitive bidding process can be conducted, two-way contracts for difference or equivalent schemes with the same effects, and the applicable strike prices, shall be designed to ensure that the distribution of revenues to undertakings does not create undue distortions to competition and trade in the internal market;
(e) avoid distortions to competition and trade in the internal market resulting from the distribution of revenues to undertakings;
(f) include penalty clauses applicable in the case of undue unilateral early termination of the contract.
Paragraph 1 shall apply to investment in new generation of electricity from the following sources:
(a) wind energy;
(b) solar energy;
(c) geothermal energy;
(d) hydropower without reservoir;
(e) nuclear energy.
Notwithstanding the first subparagraph, the revenues, or the equivalent in financial value of those revenues, may also be used to finance the costs of the direct price support schemes or investment to reduce electricity costs for final customers.
The distribution of revenues to final customers shall be designed to maintain incentives to reduce their consumption or shift it to periods when electricity prices are low and not to undermine competition between electricity suppliers.
Article 19e
Assessment of flexibility needs
The report referred to in the first subparagraph shall:
(a) be consistent with the European resource adequacy assessment and national resource adequacy assessments conducted pursuant to Articles 23 and 24;
(b) be based on the data and analyses provided by the transmission system operators and distribution system operators of each Member State pursuant to paragraph 3 and using the common methodology pursuant to paragraph 4 and, where duly justified, additional data and analysis.
Where the Member State has designated a transmission system operator or another entity for the purpose of adopting the report referred to in the first subparagraph, the regulatory authority shall approve or amend the report.
The report referred to in paragraph 1 shall at least:
(a) evaluate the different types of flexibility needs, at least on a seasonal, daily and hourly basis, to integrate electricity generated from renewable sources in the electricity system, inter alia, different assumptions in respect to electricity market prices, generation and demand;
(b) consider the potential of non-fossil flexibility resources such as demand response and energy storage, including aggregation and interconnection, to fulfil the flexibility needs, both at transmission and distribution levels;
(c) evaluate the barriers for flexibility in the market and propose relevant mitigation measures and incentives, including the removal of regulatory barriers and possible improvements to markets and system operation services or products;
(d) evaluate the contribution of digitalisation of electricity transmission and distribution networks; and
(e) take into account sources of flexibility that are expected to be available in other Member States.
The ENTSO for Electricity and the EU DSO entity shall coordinate the work of transmission system operators and distribution system operators as regards the data and analyses to be provided in accordance with paragraph 3. In particular, they shall:
(a) define the type and format of data that transmission system operators and distribution system operators are to provide to the regulatory authorities or another authority or entity designated pursuant to paragraph 1;
(b) develop a methodology for the analysis by transmission system operators and distribution system operators of the flexibility needs, taking into account at least: (i) all available sources of flexibility in a cost-efficient manner in the different timeframes, including in other Member States; (ii) planned investment in interconnection and flexibility at transmission and distribution level; and (iii) the need to decarbonise the electricity system in order to meet the Union’s 2030 targets for energy and climate, as defined in Article 2, point (11), of Regulation (EU) 2018/1999, and its 2050 climate neutrality objective laid down in Article 2 of Regulation (EU) 2021/1119, in compliance with the Paris Agreement adopted under the United Nations Framework Convention on Climate Change (12).
The methodology referred to in point (b) of the first subparagraph shall contain guiding criteria on how to assess the capability of the different sources of flexibility to cover the flexibility needs.
Among the issues of cross-border relevance, ACER shall assess:
(a) how better to integrate the flexibility needs analysis referred to in paragraph 1 of this Article with the methodology for the European resource adequacy assessment in accordance with Article 23 and the methodology for the Union-wide ten year network development plan, ensuring consistency between them;
(b) the estimated flexibility needs in the electricity system at Union level and its projected economically available potential for a period of the next 5 to 10 years taking into account the national reports;
(c) the potential introduction of further measure to unleash flexibility potential in the electricity markets and system operation.
The results of the analysis referred to in the second subparagraph, point (a) may be taken into account in further revisions of the methodologies referred to in that point in accordance with the relevant Union legal acts.
The European Scientific Advisory Board on Climate Change may, on its own initiative, provide input to ACER on how to ensure compliance with the Union’s 2030 targets for energy and climate and its 2050 climate neutrality objective.
Article 19f
Indicative national objective for non-fossil flexibility
No later than six months after the submission of the report pursuant to Article 19e(1) of this Regulation, each Member State shall define, on the basis of that report, an indicative national objective for non-fossil flexibility, including the respective specific contributions of both demand response and energy storage to that objective. Member States may achieve that objective by realising the identified potential of non-fossil flexibility, via the removal of identified market barriers or via the non-fossil flexibility support schemes referred to in Article 19g of this Regulation. That indicative national objective, including the respective specific contributions of demand response and energy storage to that objective, as well as measures to achieve it shall also be reflected in Member States’ integrated national energy and climate plans as regards the dimension ‘Internal Energy Market’ in accordance with Articles 3, 4 and 7 of Regulation (EU) 2018/1999 and in their integrated national energy and climate progress reports in accordance with Article 17 of that Regulation. Member States may define provisional indicative national objectives until the report is adopted pursuant to Article 19e(1) of this Regulation.
Following the assessment carried out in accordance with Article 9 of Regulation (EU) 2018/1999, the Commission, after receiving the national indicative objective defined and communicated by the Member States in accordance with paragraph 1 of this Article, shall submit a report to the European Parliament and to the Council assessing the national reports.
On the basis of the conclusions of the report elaborated with the first information communicated by Member States, the Commission may draw up a Union strategy on flexibility, with a particular focus on demand response and energy storage, to facilitate their deployment, which is consistent with the Union’s 2030 targets for energy and climate and the 2050 climate-neutrality objective. That Union strategy on flexibility may be accompanied, where appropriate, by a legislative proposal.
Article 19g
Non-fossil flexibility support schemes
Article 19h
Design principles for non-fossil flexibility support schemes
Non-fossil flexibility support schemes applied by Member States in accordance with Article 19g(1) shall:
(a) not go beyond what is necessary to achieve the indicative national objective, or where relevant the provisional indicative national objective, defined pursuant to Article 19f in a cost-effective manner;
(b) be limited to new investment in non-fossil flexibility resources such as demand side response and energy storage;
(c) endeavour to take into consideration locational criteria to ensure that investments in new capacity take place in optimal locations;
(d) not imply starting fossil fuel-based generation located behind the metering point;
(e) select capacity providers by means of an open, transparent, competitive, voluntary, non-discriminatory and cost-effective process;
(f) prevent undue distortions to the efficient functioning of electricity markets including preserving efficient operation incentives and price signals and the exposure to price variation and market risk;
(g) provide incentives for the integration in the electricity markets in a market-based and market-responsive way, while avoiding unnecessary distortions of electricity markets as well as taking into account possible system integration costs and grid congestion and stability;
(h) set out a minimum level of participation in the electricity markets in terms of activated energy, which takes into account the technical specificities of the asset delivering the flexibility;
(i) apply appropriate penalties to capacity providers which do not respect the minimum level of participation in the electricity markets referred to in point (h), or which do not follow efficient operation incentives and price signals referred to in point (f);
(j) promote the opening to the cross-border participation of those resources that are capable of providing the required technical performance, where a cost-benefit analysis is positive.
CHAPTER IV
RESOURCE ADEQUACY
Article 20
Resource adequacy in the internal market for electricity
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.
Article 21
General principles for capacity mechanisms
Article 22
Design principles for capacity mechanisms
Any capacity mechanism shall:
(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.
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.
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.
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.
Article 23
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.
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.
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.
Article 24
National resource adequacy assessments
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).
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
Article 26
Cross-border participation in capacity mechanisms
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.
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.
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.
Transmission system operators shall set the maximum entry capacity available for the participation of foreign capacity based on the recommendation of the regional coordination centre on an annual basis.
The transmission system operator where the foreign capacity is located shall:
(a) establish whether interested capacity providers can provide the technical performance as required by the capacity mechanism in which the capacity provider intends to participate, and register that capacity provider as an eligible capacity provider in a registry set up for that purpose;
(b) carry out availability checks;
(c) notify the transmission system operator in the Member State applying the capacity mechanism of the information it acquires under points (a) and (b) of this subparagraph and the second subparagraph.
The relevant capacity provider shall notify the transmission system operator of its participation in a foreign capacity mechanism without delay.
By 5 July 2020 the ENTSO for Electricity shall submit to ACER:
(a) a methodology for calculating the maximum entry capacity for cross-border participation as referred to in paragraph 7;
(b) a methodology for sharing the revenues referred to in paragraph 9;
(c) common rules for the carrying out of availability checks referred to in point (b) of paragraph 10;
(d) common rules for determining when a non-availability payment is due;
(e) terms of the operation of the registry as referred to in point (a) of paragraph 10;
(f) common rules for identifying capacity eligible to participate in the capacity mechanism as referred to in point (a) of paragraph 10.
The proposal shall be subject to prior consultation and approval by ACER in accordance with Article 27.
Article 27
Approval procedure
CHAPTER V
TRANSMISSION SYSTEM OPERATION
Article 28
European network of transmission system operators for electricity
Article 29
The ENTSO for Electricity
Article 30
Tasks of the ENTSO for Electricity
The ENTSO for Electricity shall:
(a) develop network codes in the areas set out in Article 59(1) and (2) with a view to achieving the objectives set out in Article 28;
(b) adopt and publish a non-binding Union-wide ten-year network development plan, (‘Union-wide network development plan’), biennially;
(c) prepare and adopt proposals related to the European resource adequacy assessment pursuant to Article 23 and proposals for the technical specifications for cross-border participation in capacity mechanisms pursuant to Article 26(11);
(d) adopt recommendations relating to the coordination of technical cooperation between Union and third-country transmission system operators;
(e) adopt a framework for the cooperation and coordination between regional coordination centres;
(f) adopt a proposal defining the system operation region in accordance with Article 36;
(g) cooperate with distribution system operators and the EU DSO entity;
(h) promote the digitalisation of transmission networks including deployment of smart grids, efficient real time data acquisition and intelligent metering systems;
(i) adopt common network operation tools to ensure coordination of network operation in normal and emergency conditions, including a common incident classification scale, and research plans, including the deployment of those plans through an efficient research programme. Those tools shall specify inter alia: (i) the information, including appropriate day-ahead, intraday and real-time information, useful for improving operational coordination, as well as the optimal frequency for the collection and sharing of such information; (ii) the technological platform for the exchange of information in real time and where appropriate, the technological platforms for the collection, processing and transmission of the other information referred to in point (i), as well as for the implementation of the procedures capable of increasing operational coordination between transmission system operators with a view to such coordination becoming Union-wide; (iii) how transmission system operators make available the operational information to other transmission system operators or any entity duly mandated to support them to achieve operational coordination, and to ACER; and (iv) that transmission system operators designate a contact point in charge of answering inquiries from other transmission system operators or from any entity duly mandated as referred to in point (iii), or from ACER concerning such information;
(j) adopt an annual work programme;
(k) contribute to the establishment of interoperability requirements and non-discriminatory and transparent procedures for accessing data as provided for in Article 24 of Directive (EU) 2019/944;
(l) adopt an annual report;
(m) carry out and adopt seasonal adequacy assessments pursuant to Article 9(2) of Regulation (EU) 2019/941;
(n) promote cyber security and data protection in cooperation with relevant authorities and regulated entities;
(o) take into account the development of demand response in fulfilling its tasks.
Article 31
Consultations
Article 32
Monitoring by ACER
ACER shall monitor the implementation by the ENTSO for Electricity of network codes developed under Article 59. Where the ENTSO for Electricity has failed to implement such network codes, ACER shall request the ENTSO for Electricity to provide a duly reasoned explanation as to why it has failed to do so. ACER shall inform the Commission of that explanation and provide its opinion thereon.
ACER shall monitor and analyse the implementation of the network codes and the guidelines adopted by the Commission as laid down in Article 58(1), and their effect on the harmonisation of applicable rules aimed at facilitating market integration as well as on non-discrimination, effective competition and the efficient functioning of the market, and report to the Commission.
Where it considers that the draft annual work programme or the draft Union-wide network development plan submitted by the ENTSO for Electricity does not contribute to non-discrimination, effective competition, the efficient functioning of the market or a sufficient level of cross-border interconnection open to third-party access, ACER shall provide a duly reasoned opinion as well as recommendations to the ENTSO for Electricity and to the Commission within two months of the submission.
Article 33
Costs
The costs related to the activities of the ENTSO for Electricity referred to in Articles 28 to 32 and 58 to 61 of this Regulation, and in Article 11 of Regulation (EU) No 347/2013 of the European Parliament and of the Council (14) shall be borne by the transmission system operators and shall be taken into account in the calculation of tariffs. Regulatory authorities shall approve those costs only if they are reasonable and appropriate.
Article 34
Regional cooperation of transmission system operators
The Commission is empowered to adopt delegated acts in accordance with Article 68, supplementing this Regulation, establishing the geographical area covered by each regional cooperation structure. For that purpose, the Commission shall consult the regulatory authorities, ACER and the ENTSO for Electricity.
The delegated acts referred to in this paragraph shall be without prejudice to Article 36.
Article 35
Establishment and mission of regional coordination centres
The regulatory authorities of the system operation region shall review and approve the proposal.
The proposal shall at least include the following elements:
Reading this document does not replace reading the official text published in the Official Journal of the European Union. We assume no responsibility for any inaccuracies arising from the conversion of the original to this format.
This text is published under EUR-Lex's own terms of reuse, not a Legalize or public-domain licence.
EUR-Lex
Creative Commons Attribution 4.0 International (CC BY 4.0)
© European Union, https://eur-lex.europa.eu — Source: EUR-Lex (Publications Office of the European Union). Reused under the Creative Commons Attribution 4.0 International (CC BY 4.0) licence. Only EU legislation published in the printed Official Journal of the European Union is deemed authentic; consolidated texts are reproduced here for documentation purposes and have been reformatted to Markdown.