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;

power-generating facilities using renewable energy sources with an installed electricity capacity of less than 400 kW;

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.

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;

ensure that services are defined in a transparent and technologically neutral manner and are procured in a transparent, market-based manner;

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;

respect the need to accommodate the increasing share of variable generation, increased demand responsiveness and the advent of new technologies.

the specific period during which the exemption would apply;

the specific volume of balancing capacity to which the exemption would apply;

an analysis of the impact of the exemption on the participation of balancing resources; and

a justification for the exemption demonstrating that such an exemption would lead to lower costs to final customers.

be organised in such a way as to be non-discriminatory;

maximise the ability of all market participants to manage imbalances;

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;

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;

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;

ensure operational security while allowing for maximum use of transmission capacity;

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;

make no distinction between trades made within a bidding zone and across bidding zones; and

be organised in such a way as to ensure that all markets participants are able to access the market individually or through aggregation.

the dimensioning of the peak-shaving product shall:

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;

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;

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

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

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

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;

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.

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

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 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

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.

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

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

possible changes to the nature of long-term transmission rights;

ways to strengthen the secondary market; and

the possible introduction of regional virtual hubs for the forward markets.

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;

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 );

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;

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

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;

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;

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

power-generating facilities that use renewable energy sources and have an installed electricity capacity of less than 400 kW; or

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.

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;

redispatching rules and congestion management are transparent to all market participants;

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 %;

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

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.

no market-based alternative is available;

all available market-based resources have been used;

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

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 level of development and effectiveness of market-based redispatching mechanisms for power generating, energy storage and demand response facilities;

the reasons, volumes in MWh and type of generation source subject to redispatching;

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.

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;

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;

ensure that their networks are sufficiently flexible so that they are able to manage them.

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;

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;

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;

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.

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;

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.

preserve incentives for the power-generating facility to operate and participate efficiently in the electricity markets, in particular to reflect market circumstances;

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;

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;

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;

avoid distortions to competition and trade in the internal market resulting from the distribution of revenues to undertakings;

include penalty clauses applicable in the case of undue unilateral early termination of the contract.

wind energy;

solar energy;

geothermal energy;

hydropower without reservoir;

nuclear energy.

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;

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;

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;

evaluate the contribution of digitalisation of electricity transmission and distribution networks; and

take into account sources of flexibility that are expected to be available in other Member States.

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;

develop a methodology for the analysis by transmission system operators and distribution system operators of the flexibility needs, taking into account at least:

removing regulatory distortions;

removing price caps in accordance with Article 10;

introducing a shortage pricing function for balancing energy as referred to in Article 44(3) of Regulation (EU) 2017/2195;

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;

enabling self-generation, energy storage, demand side measures and energy efficiency by adopting measures to eliminate any identified regulatory distortions;

ensuring cost-efficient and market-based procurement of balancing and ancillary services;

removing regulated prices where required by Article 5 of Directive (EU) 2019/944.

not create undue market distortions and not limit cross-zonal trade;

not go beyond what is necessary to address the adequacy concerns referred to in Article 20;

select capacity providers by means of a transparent, non-discriminatory and competitive process;

provide incentives for capacity providers to be available in times of expected system stress;

ensure that the remuneration is determined through the competitive process;

set out the technical conditions for the participation of capacity providers in advance of the selection process;

be open to participation of all resources that are capable of providing the required technical performance, including energy storage and demand side management;

apply appropriate penalties to capacity providers that are not available in times of system stress.

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;

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;

the output of the strategic reserve following dispatch is to be attributed to balance responsible parties through the imbalance settlement mechanism;

the resources taking part in the strategic reserve are not to receive remuneration from the wholesale electricity markets or from the balancing markets;

the resources in the strategic reserve are to be held outside the market for at least the duration of the contractual period.

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;

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;

ensure that capacity obligations are transferable between eligible capacity providers.

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;

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.

is carried out on each bidding zone level covering at least all Member States;

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;

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;

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;

anticipates the likely impact of the measures referred in Article 20(3);

includes variants without existing or planned capacity mechanisms and, where applicable, variants with such mechanisms;

is based on a market model using the flow-based approach, where applicable;

applies probabilistic calculations;

applies a single modelling tool;

includes at least the following indicators referred to in Article 25:

identifies the sources of possible resource adequacy concerns, in particular whether it is a network constraint, a resource constraint, or both;

takes into account real network development;

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.

the value of lost load;

the cost of new entry for generation, or demand response; and

the reliability standard referred to in Article 25.

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;

carry out availability checks;

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 methodology for calculating the maximum entry capacity for cross-border participation as referred to in paragraph 7;

a methodology for sharing the revenues referred to in paragraph 9;

common rules for the carrying out of availability checks referred to in point (b) of paragraph 10;

common rules for determining when a non-availability payment is due;

terms of the operation of the registry as referred to in point (a) of paragraph 10;

common rules for identifying capacity eligible to participate in the capacity mechanism as referred to in point (a) of paragraph 10.

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;

adopt and publish a non-binding Union-wide ten-year network development plan, (‘Union-wide network development plan’), biennially;

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);

adopt recommendations relating to the coordination of technical cooperation between Union and third-country transmission system operators;

adopt a framework for the cooperation and coordination between regional coordination centres;

adopt a proposal defining the system operation region in accordance with Article 36;

cooperate with distribution system operators and the EU DSO entity;

promote the digitalisation of transmission networks including deployment of smart grids, efficient real time data acquisition and intelligent metering systems;

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:

adopt an annual work programme;

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;

adopt an annual report;

carry out and adopt seasonal adequacy assessments pursuant to Article 9(2) of Regulation (EU) 2019/941;

promote cyber security and data protection in cooperation with relevant authorities and regulated entities;

take into account the development of demand response in fulfilling its tasks.

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;

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;

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;

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;

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;

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;

training and certification of staff working for regional coordination centres;

supporting the coordination and optimisation of regional restoration as requested by transmission system operators;

carrying out post-operation and post-disturbances analysis and reporting;

regional sizing of reserve capacity;

facilitating the regional procurement of balancing capacity;

supporting transmission system operators, at their request, in the optimisation of inter-transmission system operators settlements;

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;

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;

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);

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.

drafting and endorsing the statutes and rules of procedure of regional coordination centres;

deciding upon and implementing the organisational structure;

preparing and endorsing the annual budget;

developing and endorsing the cooperative processes in accordance with Article 38.

their operational performance;

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;

the effectiveness and efficiency of each of the tasks for which they are responsible and, where applicable, the rotation of those tasks.

participation in the work of the EU DSO entity is limited to registered members with the possibility of delegation within the membership;

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;

decisions of the general assembly are adopted according with the following rules:

decisions of the general assembly are rejected according with the following rules:

the board of directors is elected by the general assembly for a mandate of a maximum of four years;

the board of directors nominates the President and the three Vice-Presidents from among the members of the board;

cooperation between transmission system operators and distribution system operators pursuant to Articles 56 and 57 is led by the board of directors;

decisions of the board of directors are adopted by an absolute majority;

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;

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.

the board of directors is composed of the President of the Board and 27 members' representatives, of which:

representatives of existing DSO associations are permitted to participate as observers at the meetings of the board of directors;

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;

each Vice-President of the Board is nominated among representatives of members in each category described in point (a);

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;

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.

promoting operation and planning of distribution networks in coordination with the operation and planning of transmission networks;

facilitating the integration of renewable energy resources, distributed generation and other resources embedded in the distribution network such as energy storage;

facilitating demand side flexibility and response and distribution grid users' access to markets;

contributing to the digitalisation of distribution systems including deployment of smart grids and intelligent metering systems;

supporting the development of data management, cyber security and data protection in cooperation with relevant authorities and regulated entities;

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.

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;

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;

work on identifying best practices on the areas identified in paragraph 1 and for the introduction of energy efficiency improvements in the distribution network;

adopt an annual work programme and an annual report;

operate in accordance with competition law and ensure neutrality.

ensure that they provide the minimum degree of harmonisation required to achieve the aims of this Regulation;

take into account regional specificities, where appropriate;

not go beyond what is necessary for the purposes of point (a); and

be without prejudice to the Member States' right to establish national network codes which do not affect cross-zonal trade.

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;

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;

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;

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;

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.

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;

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;

third-party access rules;

operational emergency and restauration procedures in an emergency including system defence plans, restoration plans, market interactions, information exchange and communication and tools and facilities;

sector-specific rules for cyber security aspects of cross-border electricity flows, including rules on common minimum requirements, planning, monitoring, reporting and crisis management.

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);

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);

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);

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);

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

arrangements for the participation of national systems which are interconnected through direct current lines, in accordance with Article 49.

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;

details of investment incentive rules for interconnector capacity including locational signals implementing Article 19.

the investment enhances competition in electricity supply;

the level of risk attached to the investment is such that the investment would not take place unless an exemption is granted;

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;

charges are levied on users of that interconnector;

since the partial market opening referred to in Article 19 of Directive 96/92/EC of the European Parliament and of the Council ( 16 ), no part of the capital or operating costs of the interconnector has been recovered from any component of charges made for the use of transmission or distribution systems linked by the interconnector; and

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.

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

upon a joint request from the regulatory authorities concerned.

the detailed reasons on the basis of which the exemption was granted or refused, including the financial information justifying the need for the exemption;

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;

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

the result of the consultation of the regulatory authorities concerned.

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;

the undertakings concerned act contrary to their commitments; or

the decision was based on incomplete, incorrect or misleading information, which was provided by the parties.

the Member State can demonstrate that there are substantial problems for the operation of small isolated systems and small connected systems;

outermost regions within the meaning of Article 349 TFEU cannot be interconnected with the Union's energy market for evident physical reasons.

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 after 1 July 2025, which aims to maximise the participation of capacity providers which meet the requirements in Article 22(4);

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;

the generation capacity that emits more than 550 g of CO2 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.

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;

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).