(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.
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.)
Modified by
- Regulation (EU) 2022/869 of the European Parliament and of the Councilof 30 May 2022on guidelines for trans-European energy infrastructure, amending Regulations (EC) No 715/2009, (EU) 2019/942 and (EU) 2019/943 and Directives 2009/73/EC and (EU) 2019/944, and repealing Regulation (EU) No 347/2013, 32022R0869, June 3, 2022
- Regulation (EU) 2024/1747 of the European Parliament and of the Councilof 13 June 2024amending Regulations (EU) 2019/942 and (EU) 2019/943 as regards improving the Union’s electricity market design(Text with EEA relevance), 32024R1747, June 26, 2024
(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 Directive 2012/27/EU of the European Parliament and of the Council of 25 October 2012 on energy efficiency, amending Directives 2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and 2006/32/EC (OJ L 315, 14.11.2012, p. 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 Regulation (EU) No 1227/2011 of the European Parliament and of the Council of 25 October 2011 on wholesale energy market integrity and transparency (OJ L 326, 8.12.2011, p. 1 ).(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.
(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.
(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 .
(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.
(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.
(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.
(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.
(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 .
(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.
(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.
(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 Regulation (EU) 2018/1999 of the European Parliament and of the Council of 11 December 2018 on the Governance of the Energy Union and Climate Action, amending Regulations (EC) No 663/2009 and (EC) No 715/2009 of the European Parliament and of the Council, Directives 94/22/EC, 98/70/EC, 2009/31/EC, 2009/73/EC, 2010/31/EU, 2012/27/EU and 2013/30/EU of the European Parliament and of the Council, Council Directives 2009/119/EC and (EU) 2015/652 and repealing Regulation (EU) No 525/2013 of the European Parliament and of the Council (OJ L 328, 21.12.2018, p. 1 ).(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.
(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) 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 Directive (EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 on the promotion of the use of energy from renewable sources (OJ L 328, 21.12.2018, p. 82 ).Regulation (EU) 2018/1999 of the European Parliament and of the Council of 11 December 2018 on the Governance of the Energy Union and Climate Action, amending Regulations (EC) No 663/2009 and (EC) No 715/2009 of the European Parliament and of the Council, Directives 94/22/EC, 98/70/EC, 2009/31/EC, 2009/73/EC, 2010/31/EU, 2012/27/EU and 2013/30/EU of the European Parliament and of the Council, Council Directives 2009/119/EC and (EU) 2015/652 and repealing Regulation (EU) No 525/2013 of the European Parliament and of the Council (OJ L 328, 21.12.2018, p. 1 ).(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.
(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).
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(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.
(a) wind energy; (b) solar energy; (c) geothermal energy; (d) hydropower without reservoir; (e) nuclear energy.
(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.
(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.
(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 OJ L 282, 19.10.2016, p. 4 .
(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.
(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.
(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.
(a) be temporary; (b) not create undue market distortions and not limit cross-zonal trade; (c) not go beyond what is necessary to address the adequacy concerns referred to in Article 20; (d) select capacity providers by means of a transparent, non-discriminatory and competitive process; (e) provide incentives for capacity providers to be available in times of expected system stress; (f) ensure that the remuneration is determined through the competitive process; (g) set out the technical conditions for the participation of capacity providers in advance of the selection process; (h) be open to participation of all resources that are capable of providing the required technical performance, including energy storage and demand side management; (i) apply appropriate penalties to capacity providers that are not available in times of system stress.
(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.
(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.
(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 before4 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.
(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.
(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.
(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.
(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.
(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.
(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.
(a) the Member State of the prospective seat of the regional coordination centres and the participating transmission system operators; (b) the organisational, financial and operational arrangements necessary to ensure the efficient, secure and reliable operation of the interconnected transmission system; (c) an implementation plan for the entry into operation of the regional coordination centres; (d) the statutes and rules of procedure of the regional coordination centres; (e) a description of cooperative processes in accordance with Article 38; (f) a description of the arrangements concerning the liability of the regional coordination centres in accordance with Article 47; (g) where two regional coordination centres are maintained on a rotational basis in accordance with Article 36(2), a description of the arrangements to provide clear responsibilities to those regional coordination centres and procedures on the execution of their tasks.
(a) carrying out the coordinated capacity calculation in accordance with the methodologies developed pursuant to the forward capacity allocation guideline established by Regulation (EU) 2016/1719, the capacity allocation and congestion management guideline established by Regulation (EU) 2015/1222 and the electricity balancing guideline established by Regulation (EU) 2017/2195; (b) carrying out the coordinated security analysis in accordance with the methodologies developed pursuant to the system operation guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009; (c) creating common grid models in accordance with the methodologies and procedures developed pursuant to the system operation guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009; (d) supporting the consistency assessment of transmission system operators' defence plans and restoration plans in accordance with the procedure set out in the emergency and restoration network code adopted on the basis of Article 6(11) of Regulation (EC) No 714/2009; (e) carrying out regional week ahead to at least day-ahead system adequacy forecasts and preparation of risk reducing actions in accordance with the methodology set out in Article 8 of Regulation (EU) 2019/941 and the procedures set out in the system operation guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009; (f) carrying out regional outage planning coordination in accordance with the procedures and methodologies set out in the system operation guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009; (g) training and certification of staff working for regional coordination centres; (h) supporting the coordination and optimisation of regional restoration as requested by transmission system operators; (i) carrying out post-operation and post-disturbances analysis and reporting; (j) regional sizing of reserve capacity; (k) facilitating the regional procurement of balancing capacity; (l) supporting transmission system operators, at their request, in the optimisation of inter-transmission system operators settlements; (m) carrying out tasks related to the identification of regional electricity crisis scenarios if and to the extent they are delegated to the regional coordination centres pursuant to Article 6(1) of Regulation (EU) 2019/941; (n) carrying out tasks related to the seasonal adequacy assessments if and to the extent that they are delegated to the regional coordination centres pursuant to Article 9(2) of Regulation (EU) 2019/941; (o) calculating the value for the maximum entry capacity available for the participation of foreign capacity in capacity mechanisms for the purposes of issuing a recommendation pursuant to Article 26(7); (p) carrying out tasks related to supporting transmission system operators in the identification of needs for new transmission capacity, for upgrade of existing transmission capacity or their alternatives, to be submitted to the regional groups established pursuant to Regulation (EU) No 347/2013 and included in the ten-year network development plan referred to in Article 51 of Directive (EU) 2019/944.
(a) working arrangements to address planning and operational aspects relevant to the tasks referred to in Article 37; (b) a procedure for sharing analysis and consulting on regional coordination centres' proposals with the transmission system operators in the system operation region and relevant stakeholders and with other regional coordination centres, in an efficient and inclusive manner, in the exercise of the operational duties and tasks, in accordance with Article 40; (c) a procedure for the adoption of coordinated actions and recommendations in accordance with Article 42.
(a) drafting and endorsing the statutes and rules of procedure of regional coordination centres; (b) deciding upon and implementing the organisational structure; (c) preparing and endorsing the annual budget; (d) developing and endorsing the cooperative processes in accordance with Article 38.
(a) the powers, duties and responsibilities of the personnel; (b) the relationship and reporting lines between different parts and processes of the organisation.
(a) their operational performance; (b) the coordinated actions and recommendations issued, the extent to which the coordinated actions and recommendations have been implemented by the transmission system operators and the outcome achieved; (c) the effectiveness and efficiency of each of the tasks for which they are responsible and, where applicable, the rotation of those tasks.
(a) build on national investment plans, taking into account regional investment plans as referred to in Article 34(1) of this Regulation, and, if appropriate, Union aspects of network planning as set out in Regulation (EU) No 347/2013; it shall be subject to a cost-benefit analysis using the methodology established as set out in Article 11 of that Regulation; (b) regarding cross-border interconnections, also build on the reasonable needs of different system users and integrate long-term commitments from investors referred to in Articles 44 and 51 of Directive (EU) 2019/944; and (c) identify investment gaps, in particular with respect to cross-border capacities.
(a) participation in the work of the EU DSO entity is limited to registered members with the possibility of delegation within the membership; (b) strategic decisions regarding the activities of the EU DSO entity as well as policy guidelines for the board of directors are adopted by the general assembly; (c) decisions of the general assembly are adopted according with the following rules: (i) each member disposes of a number of votes proportional to the number of that member's customers; (ii) 65 % of the votes attributed to the members are cast; and (iii) the decision is adopted by a majority of 55 % of the members;
(d) decisions of the general assembly are rejected according with the following rules: (i) each member disposes of a number of votes proportional to the number of that member's customers; (ii) 35 % of the votes attributed to the members are cast; and (iii) the decision is rejected by at least 25 % of the members;
(e) the board of directors is elected by the general assembly for a mandate of a maximum of four years; (f) the board of directors nominates the President and the three Vice-Presidents from among the members of the board; (g) cooperation between transmission system operators and distribution system operators pursuant to Articles 56 and 57 is led by the board of directors; (h) decisions of the board of directors are adopted by an absolute majority; (i) on the basis of a proposal by the board of directors, the secretary general is appointed by the general assembly from among its members for a mandate of four years, renewable once; (j) on the basis of a proposal by the board of directors, Expert Groups are appointed by the general assembly and do not exceed 30 members, with the possibility of one-third of the members coming from outside the membership of EU DSO; in addition, one "country" expert group shall be established and shall consist of one representative of distribution system operators from each Member State.
(a) the board of directors is composed of the President of the Board and 27 members' representatives, of which: (i) nine are representatives of members with more than 1 million grid users; (ii) nine are representatives of members with more than 100000 and less than 1 million grid users; and(iii) nine are representatives of members with less than 100000 grid users;
(b) representatives of existing DSO associations are permitted to participate as observers at the meetings of the board of directors; (c) the board of directors are not permitted to consist of more than three representatives of members who are based in the same Member State or in the same industrial group; (d) each Vice-President of the Board is nominated among representatives of members in each category described in point (a); (e) representatives of members who are based in one Member State or the same industrial group do not constitute the majority of the participants in the Expert Group; (f) the board of directors establishes a Strategic Advisory group that provides its opinion to the board of directors and the Expert Groups and consists of representatives of the European DSO associations and representatives of those Member States which are not represented in the board of directors.
(a) promoting operation and planning of distribution networks in coordination with the operation and planning of transmission networks; (b) facilitating the integration of renewable energy resources, distributed generation and other resources embedded in the distribution network such as energy storage; (c) facilitating demand side flexibility and response and distribution grid users' access to markets; (d) contributing to the digitalisation of distribution systems including deployment of smart grids and intelligent metering systems; (e) supporting the development of data management, cyber security and data protection in cooperation with relevant authorities and regulated entities; (f) participating in the development of network codes which are relevant to the operation and planning of distribution grids and the coordinated operation of the transmission networks and distribution networks pursuant to Article 59.
(a) cooperate with the ENTSO for Electricity on the monitoring of implementation of the network codes and guidelines adopted pursuant to this Regulation which are relevant to the operation and planning of distribution grids and the coordinated operation of the transmission networks and distribution networks; (b) cooperate with the ENTSO for Electricity and adopt best practices on the coordinated operation and planning of transmission and distribution systems including issues such as exchange of data between operators and coordination of distributed energy resources; (c) work on identifying best practices on the areas identified in paragraph 1 and for the introduction of energy efficiency improvements in the distribution network; (d) adopt an annual work programme and an annual report; (e) operate in accordance with competition law and ensure neutrality.
(a) ensure that they provide the minimum degree of harmonisation required to achieve the aims of this Regulation; (b) take into account regional specificities, where appropriate; (c) not go beyond what is necessary for the purposes of point (a); and (d) be without prejudice to the Member States' right to establish national network codes which do not affect cross-zonal trade.
(a) network security and reliability rules including rules for technical transmission reserve capacity for operational network security as well as interoperability rules implementing Articles 34 to 47 and Article 57 of this Regulation and Article 40 of Directive (EU) 2019/944, including rules on system states, remedial actions and operational security limits, voltage control and reactive power management, short-circuit current management, power flow management, contingency analysis and handling, protection equipment and schemes, data exchange, compliance, training, operational planning and security analysis, regional operational security coordination, outage coordination, availability plans of relevant assets, adequacy analysis, ancillary services, scheduling, and operational planning data environments; (b) capacity-allocation and congestion- management rules pursuant to Articles 7 to 10, 13 to 17, 19 and 35 to 37 of this Regulation and Article 6 of Directive (EU) 2019/944, including rules on day-ahead, intraday and forward capacity calculation methodologies and processes, grid models, bidding zone configuration, redispatching and countertrading, trading algorithms, single day-ahead and intraday coupling, different governance options, the firmness of allocated cross-zonal capacity, congestion income distribution, the details and specific features of the tools referred to in Article 9(3) of this Regulation by reference to the elements specified in paragraphs (4) and (5) thereof, the allocation and facilitation of trading of financial long-term transmission rights by the single allocation platform as well as the frequency, maturity and specific nature of such long-term transmission rights, cross-zonal transmission risk hedging, nomination procedures, and capacity allocation and congestion management cost recovery, and methodology for compensating offshore renewable electricity plant operators for capacity reductions; (c) rules implementing Articles 5, 6 and 17 in relation to trading related to technical and operational provision of network access services and system balancing, including rules on network-related reserve power, including functions and responsibilities, platforms for the exchange of balancing energy, gate closure times, requirements for standard and specific balancing products, procurement of balancing services, allocation of cross-zonal capacity for the exchange of balancing services or sharing of reserves, settlement of balancing energy, settlement of exchanges of energy between system operators, imbalance settlement and settlement of balancing capacity, load frequency control, frequency quality defining and target parameters, frequency containment reserves, frequency restoration reserves, replacement reserves, exchange and sharing of reserves, cross-border activation processes of reserves, time-control processes and transparency of information; (d) rules implementing Articles 36, 40 and 54 of Directive (EU) 2019/944 in relation to non-discriminatory, transparent provision of non-frequency ancillary services,, including rules on steady state voltage control, inertia, fast reactive current injection, inertia for grid stability, short circuit current, black-start capability and island operation capability; (e) rules implementing Article 57 of this Regulation and Articles 17, 31, 32, 36, 40 and 54 of Directive (EU) 2019/944 in relation to demand response, including rules on aggregation, energy storage, and demand curtailment rules.
(a) network connection rules including rules on the connection of transmission-connected demand facilities, transmission-connected distribution facilities and distribution systems, connection of demand units used to provide demand response, requirements for grid connection of generators and other system users, requirements for high-voltage direct current grid connection, requirements for direct current-connected power park modules and remote-end high-voltage direct current converter stations, and operational notification procedures for grid connection; (b) data exchange, settlement and transparency rules, including in particular rules on transfer capacities for relevant time horizons, estimates and actual values on the allocation and use of transfer capacities, forecast and actual demand of facilities and aggregation thereof including unavailability of facilities, forecast and actual generation of generation units and aggregation thereof including unavailability of units, availability and use of networks, congestion management measures and balancing market data. Rules should include ways in which the information is published, the timing of publication, the entities responsible for handling; (c) third-party access rules; (d) operational emergency and restauration procedures in an emergency including system defence plans, restoration plans, market interactions, information exchange and communication and tools and facilities; (e) sector-specific rules for cyber security aspects of cross-border electricity flows, including rules on common minimum requirements, planning, monitoring, reporting and crisis management.
(a) details of the procedure for determining which transmission system operators are liable to pay compensation for cross-border flows including as regards the split between the operators of national transmission systems from which cross-border flows originate and the systems where those flows end, in accordance with Article 49(2); (b) details of the payment procedure to be followed, including the determination of the first period for which compensation is to be paid, in accordance with the second subparagraph of Article 49(3); (c) details of methodologies for determining the cross-border flows hosted for which compensation is to be paid under Article 49, in terms of both quantity and type of flows, and the designation of the magnitudes of such flows as originating or ending in transmission systems of individual Member States, in accordance with Article 49(5); (d) details of the methodology for determining the costs and benefits incurred as a result of hosting cross-border flows, in accordance with Article 49(6); (e) details of the treatment of electricity flows originating or ending in countries outside the European Economic Area in the context of the inter-transmission system operator compensation mechanism; and (f) arrangements for the participation of national systems which are interconnected through direct current lines, in accordance with Article 49.
(a) details of rules for the trading of electricity implementing Article 6 of Directive (EU) 2019/944 and Articles 5 to 10, 13 to 17, 35, 36 and 37 of this Regulation; (b) details of investment incentive rules for interconnector capacity including locational signals implementing Article 19.
(a) the investment enhances competition in electricity supply; (b) the level of risk attached to the investment is such that the investment would not take place unless an exemption is granted; (c) the interconnector is owned by a natural or legal person which is separate, at least in terms of its legal form, from the system operators in whose systems that interconnector is to be built; (d) charges are levied on users of that interconnector; (e) since the partial market opening referred to in Article 19 of Directive 96/92/EC of the European Parliament and of the Council Directive 96/92/EC of the European Parliament and of the Council of 19 December 1996 concerning common rules for the internal market in electricity (OJ L 27, 30.1.1997, p. 20 ).(f) an exemption would not be to the detriment of competition or the effective functioning of the internal market for electricity, or the efficient functioning of the regulated system to which the interconnector is linked.
(a) where the regulatory authorities concerned have not been able to reach an agreement within six months from the date on which the last of those regulatory authorities received the exemption request; or (b) upon a joint request from the regulatory authorities concerned.
(a) the detailed reasons on the basis of which the exemption was granted or refused, including the financial information justifying the need for the exemption; (b) the analysis undertaken of the effect on competition and the effective functioning of the internal market for electricity resulting from the grant of the exemption; (c) the reasons for the time period and the share of the total capacity of the interconnector in question for which the exemption is granted; and (d) the result of the consultation of the regulatory authorities concerned.
(a) taking due account of the legitimate expectations of the parties and of the economic balance achieved in the original exemption decision, there has been a material change in any of the facts on which the decision was based; (b) the undertakings concerned act contrary to their commitments; or (c) the decision was based on incomplete, incorrect or misleading information, which was provided by the parties.
(a) the Member State can demonstrate that there are substantial problems for the operation of small isolated systems and small connected systems; (b) outermost regions within the meaning of Article 349 TFEU cannot be interconnected with the Union's energy market for evident physical reasons.
(a) the Member State has carried out, on or after 4 July 2019 , a competitive bidding process pursuant to Article 22 and for a delivery period after1 July 2025 , which aims to maximise the participation of capacity providers which meet the requirements in Article 22(4);(b) the amount of capacity offered in the competitive bidding process referred to in point (a) of this paragraph is not sufficient to address the adequacy concern as identified pursuant to Article 20(1) for the delivery period covered by that bidding process; (c) the generation capacity that emits more than 550 g of CO 2 of fossil fuel origin per kWh of electricity is committed or receives payments or commitments for future payments for a period not exceeding one year, and for a delivery period which does not exceed the duration of the derogation, and is procured through an additional procurement process which complies with all requirements of Article 22 except for those laid down in paragraph 4, point (b) of that Article and only for the amount of capacity that is needed to solve the adequacy concern referred to in point (b) of this paragraph.
(a) an assessment of the impact of the derogation in terms of greenhouse gas emissions, and on the transition towards renewable energy, increased flexibility, energy storage, electromobility and demand response; (b) a plan with milestones to transition away from the participation of generation capacity referred to in paragraph 2b in capacity mechanisms by the date of the expiry of the derogation, including a plan to procure the necessary replacement capacity in line with the indicative national trajectory for the overall share of renewable energy and an assessment of the investment barriers causing the lack of sufficient bids in the competitive bidding procedure referred to in paragraph 2c, point (a).
(a) the effectiveness of the current structure and functioning of the short-term electricity markets, including in crisis or emergency situations, and, more generally, the potential inefficiencies concerning the internal electricity market and the different options for the introduction of possible remedies and tools to be applied in crisis or emergency situations in view of the experience at international level and of the evolution and new developments in the internal electricity market; (b) the suitability of the current Union legal and financing framework on distribution grids to achieve the Union’s renewable and internal energy market objectives. (c) in accordance with Article 19a, the potential and viability of the establishment of one or several Union market platforms for PPAs, to be used on a voluntary basis, including the interaction of those potential platforms with other existing electricity market platforms and the pooling of demand for PPAs through aggregation.
(a) identify potential incompatibilities; (b) propose mitigation actions.
(a) pursue the general objective to maintain operational security in the most cost effective manner; (b) be performed at the day-ahead or intraday timeframe, or both; (c) calculate the overall amount of required reserve capacity for the system operation region; (d) determine minimum reserve capacity requirements for each type of reserve capacity; (e) take into account possible substitutions between different types of reserve capacity with the aim to minimise the costs of procurement; (f) set out the necessary requirements for the geographical distribution of required reserve capacity, if any.
(a) be performed at the day-ahead or intraday timeframe, or both; (b) take into account possible substitutions between different types of reserve capacity with the aim to minimise the costs of procurement; (c) take into account the volumes of required reserve capacity that are expected to be provided by balancing energy bids, which are not submitted based on a contract for balancing capacity.
(a) be performed at the day-ahead or intraday timeframe, or both; (b) take into account possible substitutions between different types of reserve capacity with the aim to minimise the costs of procurement.
(a) verify the underlying assumptions and forecasts; (b) detect possible cross-regional lack of adequacy situations.
(a) assess outage planning compatibility using all transmission system operators' year-ahead availability plans; (b) provide the transmission system operators in the system operation region with a list of detected planning incompatibilities and the solutions it proposes to solve the incompatibilities.
| Regulation (EU) No 347/2013 of the European Parliament and of the Council of | |
| Commission Regulation (EU) No 543/2013 of | Points 5.5 to 5.9 of Annex I |
| Regulation (EC) No 714/2009 | This Regulation |
|---|---|
| — | Article 1(a) |
| — | Article 1(b) |
| Article 1(a) | Article 1(c) |
| Article 1(b) | Article 1(d) |
| Article 2(1) | Article 2(1) |
| Article 2(2)(a) | Article 2(2) |
| Article 2(2)(b) | Article 2(3) |
| Article 2(2)(c) | Article 2(4) |
| Article 2(2)(d) | — |
| Article 2(2)(e) | — |
| Article 2(2)(f) | — |
| Article 2(2)(g) | Article 2 (5) |
| — | Article 2 (6) to (71) |
| — | Article 3 |
| — | Article 4 |
| — | Article 5 |
| — | Article 6 |
| — | Article 7 |
| — | Article 8 |
| — | Article 9 |
| — | Article 10 |
| — | Article 11 |
| — | Article 12 |
| — | Article 13 |
| — | Article 14 |
| — | Article 15 |
| Article 16(1) to (3) | Article 16(1) to (4) |
| — | Article 16(5) to (8) |
| Article 16(4) to (5) | Article 16(9) to (11) |
| — | Article 16(12) and (13) |
| — | Article 17 |
| Article 14(1) | Article 18(1) |
| — | Article 18(2) |
| Article 14(2) to (5) | Article 18(3) to (6) |
| — | Article 18(7) to (11) |
| — | Article 19(1) |
| Article 16(6) | Article 19(2) and (3) |
| — | Article 19(4) and (5) |
| — | Article 20 |
| — | Article 21 |
| — | Article 22 |
| Article 8(4) | Article 23(1) |
| — | Article 23(2) to (7) |
| — | Article 25 |
| — | Article 26 |
| — | Article 27 |
| Article 4 | Article 28(1) |
| — | Article 28(2) |
| Article 5 | Article 29 (1) to (4) |
| — | Article 29(5) |
| Article 8(2) (first sentence) | Article 30(1)(a) |
| Article 8(3)(b) | Article 30(1)(b) |
| — | Article 30(1)(c) |
| Article 8(3)(c) | Article 30 (1)(d) |
| — | Article 30 (1)(e) and (f) |
| Article 30(1) (g) and (h) | |
| Article 8 (3)(a) | Article 30(1)(i) |
| Article 8(3)(d) | Article 30(1)(j) |
| Article 30(1)(k) | |
| Article 8(3)(e) | Article 30(1)(l) |
| Article 30(1)(m) to (o) | |
| — | Article 30(2) and (3) |
| Article 8(5) | Article 30(4) |
| Article 8(9) | Article 30(5) |
| Article 10 | Article 31 |
| Article 9 | Article 32 |
| Article 11 | Article 33 |
| Article 12 | Article 34 |
| — | Article 35 |
| — | Article 36 |
| — | Article 37 |
| — | Article 38 |
| — | Article 39 |
| — | Article 40 |
| Article 41 | |
| — | Article 42 |
| — | Article 43 |
| — | Article 44 |
| — | Article 45 |
| — | Article 46 |
| — | Article 47 |
| Article 8(10) | Article 48 |
| Article 13 | Article 49 |
| Article 2(2) (final subparagraph) | Article 49(7) |
| Article 15 | Article 50(1) to (6) |
| Annex I point 5.10 | Article 50(7) |
| Article 3 | Article 51 |
| — | Article 52 |
| — | Article 53 |
| Article 54 | |
| — | Article 55 |
| — | Article 56 |
| — | Article 57 |
| — | Article 58 |
| Article 8(6) | Article 59(1)(a), (b) and (c) |
| — | Article 59(1)(d) and (e) |
| Article 59(2) | |
| Article 6(1) | Article 59(3) |
| Article 6(2) | Article 59(4) |
| Article 6(3) | Article 59(5) |
| — | Article 59(6) |
| Article 6(4) | Article 59(7) |
| Article 6(5) | Article 59(8) |
| Article 6(6) | Article 59(9) |
| Article 8(1) | Article 59(10) |
| Article 6(7) | — |
| Article 6(8) | — |
| Article 6(9) and (10) | Article 59(11) and (12) |
| Article 6(11) | Article 59(13) and (14) |
| Article 6 (12) | Article 59(15) |
| Article 8(2) | Article 59(15) |
| — | Article 60(1) |
| Article 7(1) | Article 60(2) |
| Article 7(2) | Article 60(3) |
| Article 7(3) | — |
| Article 7(4) | — |
| — | Article 61(1) |
| — | Article 61(2) |
| Article 18(1) | Article 61(3) |
| Article 18(2) | — |
| Article 18(3) | Article 61(4) |
| Article 18(4) | — |
| Article 18(4a) | Article 61(5) |
| Article 18(5) | Article 61(5) and (6) |
| Article 19 | — |
| Article 21 | Article 62 |
| Article 17 | Article 63 |
| — | Article 64 |
| Article 20 | Article 65 |
| Article 22 | Article 66 |
| Article 23 | Article 67 |
| Article 24 | — |
| — | Article 68 |
| — | Article 69 |
| Article 25 | Article 70 |
| Article 26 | Article 71 |