EN Official Journal of the European Union L 197/24

COMMISSION REGULATION (EU) 2015/1222

of 24 July 2015

establishing a guideline on capacity allocation and congestion management

(Text with EEA relevance)

THE EUROPEAN COMMISSION,

Having regard to the Treaty on the Functioning of the European Union,

Having regard to Regulation (EC) No 714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the network for cross-border exchanges in electricity and repealing Regulation (EC) No 1228/2003 (1) and in particular Article 18(3)(b) and (5),

Whereas:

(1) The urgent completion of a fully functioning and interconnected internal energy market is crucial to the objectives of maintaining security of energy supply, increasing competitiveness and ensuring that all consumers can purchase energy at affordable prices. A well-functioning internal market in electricity should provide producers with appropriate incentives for investing in new power generation, including in electricity from renewable energy sources, paying special attention to the most isolated Member States and regions in the Union's energy market. A well-functioning market should also provide consumers with adequate measures to promote more efficient use of energy, which presupposes a secure supply of energy.

(2) Security of energy supply is an essential element of public security and is therefore inherently connected to the efficient functioning of the internal market in electricity and the integration of the isolated electricity markets of Member States. Electricity can reach the citizens of the Union only through the network. Functioning electricity markets and, in particular, the networks and other assets associated with electricity supply are essential to public security, to economic competitiveness and to the well-being of the citizens of the Union.

(3) Regulation (EC) No 714/2009 sets out non-discriminatory rules for access conditions to the network for cross-border exchanges in electricity and, in particular, rules on capacity allocation and congestion management for interconnections and transmission systems affecting cross-border electricity flows. In order to move towards a genuinely integrated electricity market, the current rules on capacity allocation, congestion management and trade in electricity should be further harmonised. This Regulation therefore sets out minimum harmonised rules for the ultimately single day-ahead and intraday coupling, in order to provide a clear legal framework for an efficient and modern capacity allocation and congestion management system, facilitating Union-wide trade in electricity, allowing more efficient use of the network and increasing competition, for the benefit of consumers.

(4) To implement single day-ahead and intraday coupling, the available cross-border capacity needs to be calculated in a coordinated manner by the Transmission System Operators (hereinafter ‘TSOs’). For this purpose, they should establish a common grid model including estimates on generation, load and network status for each hour. The available capacity should normally be calculated according to the so-called flow-based calculation method, a method that takes into account that electricity can flow via different paths and optimises the available capacity in highly interdependent grids. The available cross-border capacity should be one of the key inputs into the further calculation process, in which all Union bids and offers, collected by power exchanges, are matched, taking into account available cross-border capacity in an economically optimal manner. Single day-ahead and intraday coupling ensures that power usually flows from low- price to high- price areas.

(5) The market coupling operator (hereinafter ‘MCO’) uses a specific algorithm to match bids and offers in an optimal manner. The results of the calculation should be made available to all power exchanges on a non-discriminatory basis. Based on the results of the calculation by the MCO, the power exchanges should inform their clients of the successful bids and offers. The energy should then be transferred across the network according to the results of the MCO's calculation. The process for single day-ahead and intraday coupling is similar, with the exception that the intraday coupling should use a continuous process throughout the day and not one single calculation as in day-ahead coupling.

(6) Capacity calculation for the day-ahead and intraday market time-frames should be coordinated at least at regional level to ensure that capacity calculation is reliable and that optimal capacity is made available to the market. Common regional capacity calculation methodologies should be established to define inputs, calculation approach and validation requirements. Information on available capacity should be updated in a timely manner based on latest information through an efficient capacity calculation process.

(7) There are two permissible approaches when calculating cross-zonal capacity: flow-based or based on coordinated net transmission capacity. The flow-based approach should be used as a primary approach for day-ahead and intraday capacity calculation where cross-zonal capacity between bidding zones is highly interdependent. The flow-based approach should only be introduced after market participants have been consulted and given sufficient preparation time to allow for a smooth transition. The coordinated net transmission capacity approach should only be applied in regions where cross-zonal capacity is less interdependent and it can be shown that the flow-based approach would not bring added value.

(8) A common grid model for single day-ahead and intraday coupling purposes representing the European interconnected system should be established to calculate cross-zonal capacity in a coordinated way. The common grid model should include a model of the transmission system with the location of generation units and loads relevant to calculating cross-zonal capacity. The provision of accurate and timely information by each TSO is essential to the creation of the common grid model.

(9) Each TSO should be required to prepare an individual grid model of its system and send it to TSOs responsible for merging them into a common grid model. The individual grid models should include information from generation and load units.

(10) TSOs should use a common set of remedial actions such as countertrading or redispatching to deal with both internal and cross-zonal congestion. In order to facilitate more efficient capacity allocation and to avoid unnecessary curtailments of cross-border capacities, TSOs should coordinate the use of remedial actions in capacity calculation.

(11) Bidding zones reflecting supply and demand distribution are a cornerstone of market-based electricity trading and are a prerequisite for reaching the full potential of capacity allocation methods including the flow based method. Bidding zones therefore should be defined in a manner to ensure efficient congestion management and overall market efficiency. Bidding zones can be subsequently modified by splitting, merging or adjusting the zone borders. The bidding zones should be identical for all market time-frames. The review process of bidding zone configurations provided for in this Regulation will play an important role in the identification of structural bottlenecks and will allow for more efficient bidding zone delineation.

(12) TSOs should implement coordinated redispatching of cross-border relevance or countertrading at regional level or above regional level. Redispatching of cross-border relevance or countertrading should be coordinated with redispatching or countertrading internal to the control area.

(13) Capacity should be allocated in the day-ahead and intraday market time-frames using implicit allocation methods, in particular methods which allocate electricity and capacity together. In the case of single day-ahead coupling, this method should be implicit auction and in the case of single intraday coupling it should be continuous implicit allocation. The method of implicit auction should rely on effective and timely interfaces between TSOs, power exchanges and a series of other parties to ensure capacity is allocated and congestion managed in an efficient manner.

(14) For efficiency reasons and in order to implement single day-ahead and intraday coupling as soon as possible, single day-ahead and intraday coupling should make use of existing market operators and already implemented solutions where appropriate, without precluding competition from new operators.

(15) The Commission, in cooperation with the Agency for the Cooperation of Energy Regulators (hereinafter the ‘Agency’) may create or appoint a single regulated entity to perform common MCO functions relating to the market operation of single day-ahead and intraday coupling.

(16) The development of more liquid intraday markets which give parties the ability to balance their positions closer to real time should help to integrate renewable energy sources into the Union electricity market and thus, in turn, facilitate renewable energy policy objectives.

(17) Day-ahead and intraday cross-zonal capacity should be firm to allow effective cross-border allocation.

(18) In order for the implicit auctions to take place Union-wide, it is necessary to ensure Union-wide price coupling process. This process should respect transmission capacity and allocation constraints and should be designed in a manner that allows for its application or extension across the entire Union and for the development of future new product types.

(19) Power exchanges collect bids and offers within different time-frames which serve as a necessary input for capacity calculation in the single day-ahead and intraday coupling process. Hence, the rules for the trading of electricity provided for in this Regulation require an institutional framework for power exchanges. Common requirements for the designation of nominated electricity market operators (hereinafter NEMOs) and for their tasks should facilitate the achievement of the aims of Regulation (EC) No 714/2009 and allow single day-ahead and intraday coupling to take due account of the internal market.

(20) Establishing single day-ahead and intraday coupling process requires cooperation between potentially competing power exchanges in order to establish common market coupling functions. That is why oversight and compliance with competition rules is of utmost importance regarding these common functions.

(21) Despite the creation of a reliable algorithm to match bids and offers and appropriate back-up processes, there may be situations where the price coupling process is unable to produce results. Consequently, it is necessary to provide for fallback solutions at a national and regional level to ensure capacity can still be allocated.

(22) Reliable pricing of transmission capacity should be introduced for the intraday market time-frame, reflecting congestion if capacity is scarce.

(23) Any costs incurred efficiently to guarantee firmness of capacity and to set up processes to comply with this Regulation should be recovered via network tariffs or appropriate mechanisms in a timely manner. NEMOs, including in performing MCO functions should be entitled to recover their incurred costs if they are efficiently incurred, reasonable and proportionate.

(24) Rules for sharing the common costs of single day-ahead coupling and single intraday coupling between NEMOs and TSOs from different Member States should be agreed before the implementation process starts in order to avoid delays and disputes due to cost sharing.

(25) The cooperation between TSOs, NEMOs and regulatory authorities is necessary in order to promote the completion and efficient functioning of the internal market in electricity and to ensure the optimal management, coordinated operation and sound technical development of the electricity transmission system in the Union. TSOs, NEMOs and regulatory authorities should exploit synergies arising from capacity allocation and congestion management projects contributing to the development of the internal market in electricity. They should draw on the experience gained, respect the decisions made, and use solutions developed as part of those projects.

(26) In order to ensure the close cooperation among TSOs, NEMOs and regulatory authorities, a robust, reliable and non-discriminatory Union governance framework for single day-ahead and intraday coupling should be established.

(27) The objective of this Regulation, namely the establishment of single day-ahead and intraday coupling, cannot be successfully achieved without a certain set of harmonised rules for capacity calculation, congestion management and trading of electricity.

(28) However, single day-ahead and intraday coupling should only be implemented stepwise, as the regulatory framework for electricity trade and the physical structure of the transmission grid are characterised by significant differences between Member States and regions. The introduction of single day-ahead and intraday coupling therefore requires a successive alignment of the existing methodologies on capacity calculation, allocation and congestion management. Single intraday and day-ahead coupling may therefore be introduced at a regional level as an intermediate step where necessary.

(29) Single day-ahead and intraday coupling require the introduction of harmonised maximum and minimum clearing prices that contribute to the strengthening of investment conditions for secure capacity and long-term security of supply both within and between Member States.

(30) Given the exceptionally high degree of complexity and detail of the terms and conditions or methodologies needed to fully apply single day-ahead and intraday coupling, certain detailed terms and conditions or methodologies should be developed by TSOs and NEMOs and approved by the regulatory authorities. However the development of certain terms and conditions or methodologies by TSOs and power exchanges and their subsequent approval by regulatory authorities must not delay the completion of the internal electricity market. Thus, it is necessary to include specific provisions on cooperation between TSOs, NEMOs and regulatory authorities.

(31) In line with Article 8 of Regulation (EC) No 713/2009 of the European Parliament and of the Council (2), the Agency should take a decision if the competent national regulatory authorities are not able to reach an agreement on common terms and conditions or methodologies.

(32) This Regulation has been developed in close cooperation with ACER, the ENTSO for Electricity and stakeholders, in order to adopt effective, balanced and proportionate rules in a transparent and participative manner. In accordance with Article 18(3) of Regulation (EC) No 714/2009, the Commission will consult ACER, the ENTSO for Electricity and other relevant stakeholders, notably NEMOs, before proposing any amendment to this regulation.

(33) This Regulation supplements Annex I of Regulation (EC) No 714/2009, in accordance with the principles set out in Article 16 of that Regulation.

(34) Due to the significant challenges in introducing single day-ahead and intraday coupling into the current market of Ireland and Northern Ireland, it is undergoing a process of major redesign. Additional time is, therefore, needed for the implementation of parts of this Regulation, with a number of transitional arrangements being put in place.

(35) The measures provided for in this Regulation are in accordance with the opinion of the Committee referred to in Article 23(1) of Regulation (EC) No 714/2009.

HAS ADOPTED THIS REGULATION:

TITLE I

GENERAL PROVISIONS

Article 1

Subject matter and scope

1. This Regulation lays down detailed guidelines on cross-zonal capacity allocation and congestion management in the day-ahead and intraday markets, including the requirements for the establishment of common methodologies for determining the volumes of capacity simultaneously available between bidding zones, criteria to assess efficiency and a review process for defining bidding zones.

2. This Regulation shall apply to all transmission systems and interconnections in the Union except the transmission systems on islands which are not connected with other transmission systems via interconnections.

3. In Member States where more than one transmission system operator exists, this Regulation shall apply to all transmission system operators within that Member State. Where a transmission system operator does not have a function relevant to one or more obligations under this Regulation, Member States may provide that the responsibility for complying with those obligations is assigned to one or more different, specific transmission system operators.

4. The Union single day-ahead and intraday coupling may be opened to market operators and TSOs operating in Switzerland on the condition that the national law in that country implements the main provisions of Union electricity market legislation and that there is an intergovernmental agreement on electricity cooperation between the Union and Switzerland.

5. Subject to the conditions in paragraph 4 above being fulfilled, participation by Switzerland in day-ahead coupling and single intraday coupling shall be decided by the Commission based on an opinion given by the Agency. The rights and responsibilities of Swiss NEMOs and TSOs joining single day-ahead coupling shall be consistent with the rights and responsibilities of NEMOs and TSOs operating in the Union to allow a smooth functioning of the single day-ahead and intraday coupling systems implemented at Union level and a level-playing field for all stakeholders.

Article 2

Definitions

For the purposes of this Regulation, the definitions in Article 2 of Regulation (EC) No 714/2009, Article 2 of Commission Regulation (EU) No 543/2013 (3) and Article 2 of Directive 2009/72/EC of the European Parliament and of the Council (4) shall apply.

In addition, the following definitions shall apply:

1. ‘individual grid model’ means a data set describing power system characteristics (generation, load and grid topology) and related rules to change these characteristics during capacity calculation, prepared by the responsible TSOs, to be merged with other individual grid model components in order to create the common grid model;

2. ‘common grid model’ means a Union-wide data set agreed between various TSOs describing the main characteristic of the power system (generation, loads and grid topology) and rules for changing these characteristics during the capacity calculation process;

3. ‘capacity calculation region’ means the geographic area in which coordinated capacity calculation is applied;

4. ‘scenario’ means the forecasted status of the power system for a given time-frame;

5. ‘net position’ means the netted sum of electricity exports and imports for each market time unit for a bidding zone;

6. ‘allocation constraints’ means the constraints to be respected during capacity allocation to maintain the transmission system within operational security limits and have not been translated into cross-zonal capacity or that are needed to increase the efficiency of capacity allocation;

7. ‘operational security limits’ means the acceptable operating boundaries for secure grid operation such as thermal limits, voltage limits, short-circuit current limits, frequency and dynamic stability limits;

8. ‘coordinated net transmission capacity approach’ means the capacity calculation method based on the principle of assessing and defining ex ante a maximum energy exchange between adjacent bidding zones;

9. ‘flow-based approach’ means a capacity calculation method in which energy exchanges between bidding zones are limited by power transfer distribution factors and available margins on critical network elements;

10. ‘contingency’ means the identified and possible or already occurred fault of an element, including not only the transmission system elements, but also significant grid users and distribution network elements if relevant for the transmission system operational security;

11. ‘coordinated capacity calculator’ means the entity or entities with the task of calculating transmission capacity, at regional level or above;

12. ‘generation shift key’ means a method of translating a net position change of a given bidding zone into estimated specific injection increases or decreases in the common grid model;

13. ‘remedial action’ means any measure applied by a TSO or several TSOs, manually or automatically, in order to maintain operational security;

14. ‘reliability margin’ means the reduction of cross-zonal capacity to cover the uncertainties within capacity calculation;

15. ‘market time’ means central European summer time or central European time, whichever is in effect;

16. ‘congestion income’ means the revenues received as a result of capacity allocation;

17. ‘market congestion’ means a situation in which the economic surplus for single day-ahead or intraday coupling has been limited by cross-zonal capacity or allocation constraints;

18. ‘physical congestion’ means any network situation where forecasted or realised power flows violate the thermal limits of the elements of the grid and voltage stability or the angle stability limits of the power system;

19. ‘structural congestion’ means congestion in the transmission system that can be unambiguously defined, is predictable, is geographically stable over time and is frequently reoccurring under normal power system conditions;

20. ‘matching’ means the trading mode through which sell orders are assigned to appropriate buy orders to ensure the maximisation of economic surplus for single day-ahead or intraday coupling;

21. ‘order’ means an intention to purchase or sell energy or capacity expressed by a market participant subject to specified execution conditions;

22. ‘matched orders’ means all buy and sell orders matched by the price coupling algorithm or the continuous trade matching algorithm;

23. ‘nominated electricity market operator (NEMO)’ means an entity designated by the competent authority to perform tasks related to single day-ahead or single intraday coupling;

24. ‘shared order book’ means a module in the continuous intraday coupling system collecting all matchable orders from the NEMOs participating in single intraday coupling and performing continuous matching of those orders;

25. ‘trade’ means one or more matched orders;

26. ‘single day-ahead coupling’ means the auctioning process where collected orders are matched and cross-zonal capacity is allocated simultaneously for different bidding zones in the day-ahead market;

27. ‘single intraday coupling’ means the continuous process where collected orders are matched and cross-zonal capacity is allocated simultaneously for different bidding zones in the intraday market;

28. ‘price coupling algorithm’ means the algorithm used in single day-ahead coupling for simultaneously matching orders and allocating cross-zonal capacities;

29. ‘continuous trading matching algorithm’ means the algorithm used in single intraday coupling for matching orders and allocating cross-zonal capacities continuously;

30. ‘market coupling operator (MCO) function’ means the task of matching orders from the day-ahead and intraday markets for different bidding zones and simultaneously allocating cross-zonal capacities;

31. ‘clearing price’ means the price determined by matching the highest accepted selling order and the lowest accepted buying order in the electricity market;

32. ‘scheduled exchange’ means an electricity transfer scheduled between geographic areas, for each market time unit and for a given direction;

33. ‘scheduled exchange calculator’ means the entity or entities with the task of calculating scheduled exchanges;

34. ‘day-ahead market time-frame’ means the time-frame of the electricity market until the day-ahead market gate closure time, where, for each market time unit, products are traded the day prior to delivery;

35. ‘day-ahead firmness deadline’ means the point in time after which cross-zonal capacity becomes firm;

36. ‘day-ahead market gate closure time’ means the point in time until which orders are accepted in the day-ahead market;

37. ‘intraday market time-frame’ means the time-frame of the electricity market after intraday cross-zonal gate opening time and before intraday cross-zonal gate closure time, where for each market time unit, products are traded prior to the delivery of the traded products;

38. ‘intraday cross-zonal gate opening time’ means the point in time when cross-zonal capacity between bidding zones is released for a given market time unit and a given bidding zone border;

39. ‘intraday cross-zonal gate closure time’ means the point in time where cross-zonal capacity allocation is no longer permitted for a given market time unit;

40. ‘capacity management module’ means a system containing up-to-date information on available cross-zonal capacity for the purpose of allocating intra-day cross-zonal capacity;

41. ‘non-standard intraday product’ means a product for continuous intraday coupling not for constant energy delivery or for a period exceeding one market time unit with specific characteristics designed to reflect system operation practices or market needs, for example orders covering multiple market time units or products reflecting production unit start-up costs;

42. ‘central counter party’ means the entity or entities with the task of entering into contracts with market participants, by novation of the contracts resulting from the matching process, and of organising the transfer of net positions resulting from capacity allocation with other central counter parties or shipping agents;

43. ‘shipping agent’ means the entity or entities with the task of transferring net positions between different central counter parties;

44. ‘firmness’ means a guarantee that cross-zonal capacity rights will remain unchanged and that a compensation is paid if they are nevertheless changed;

45. ‘force majeure’ means any unforeseeable or unusual event or situation beyond the reasonable control of a TSO, and not due to a fault of the TSO, which cannot be avoided or overcome with reasonable foresight and diligence, which cannot be solved by measures which are from a technical, financial or economic point of view reasonably possible for the TSO, which has actually happened and is objectively verifiable, and which makes it impossible for the TSO to fulfil, temporarily or permanently, its obligations in accordance with this Regulation;

46. ‘economic surplus for the single day-ahead or intraday coupling’ means the sum of (i) the supplier surplus for the single day-ahead or intraday coupling for the relevant time period, (ii) the consumer surplus for the single day-ahead or intraday coupling, (iii) the congestion income and (iv) other related costs and benefits where these increase economic efficiency for the relevant time period, supplier and consumer surplus being the difference between the accepted orders and the clearing price per energy unit multiplied by the volume of energy of the orders.

Article 3

Objectives of capacity allocation and congestion management cooperation

This Regulation aims at:

(a) promoting effective competition in the generation, trading and supply of electricity;

(b) ensuring optimal use of the transmission infrastructure;

(c) ensuring operational security;

(d) optimising the calculation and allocation of cross-zonal capacity;

(e) ensuring fair and non-discriminatory treatment of TSOs, NEMOs, the Agency, regulatory authorities and market participants;

(f) ensuring and enhancing the transparency and reliability of information;

(g) contributing to the efficient long-term operation and development of the electricity transmission system and electricity sector in the Union;

(h) respecting the need for a fair and orderly market and fair and orderly price formation;

(i) creating a level playing field for NEMOs;

(j) providing non-discriminatory access to cross-zonal capacity.

Article 4

NEMOs designation and revocation of the designation

1. Each Member State electrically connected to a bidding zone in another Member State shall ensure that one or more NEMOs are designated by four months after the entry into force of this Regulation to perform the single day-ahead and/or intraday coupling. For that purpose, domestic and non-domestic market operators may be invited to apply to be designated as a NEMO.

2. Each Member State concerned shall ensure that at least one NEMO is designated in each bidding zone on its territory. NEMOs shall be designated for an initial term of four years. Except where Article 5(1) applies, Member States shall allow applications for designation at least annually.

3. Unless otherwise provided by Member States, regulatory authorities shall be the designating authority, responsible for NEMO designation, monitoring of compliance with the designation criteria and, in the case of national legal monopolies, the approval of NEMO fees or the methodology to calculate NEMO fees. Member States may provide that authorities other than the regulatory authorities be the designating authority. In these circumstances Member States shall ensure that the designating authority has the same rights and obligations as the regulatory authorities in order to effectively carry out its tasks.

4. The designating authority shall assess whether NEMO candidates meet the criteria set out in Article 6. Those criteria shall apply regardless of whether one or more NEMOs are appointed. When deciding upon NEMO designations, any discrimination between applicants, notably between non-domestic and domestic applicants, shall be avoided. If the designating authority is not the regulatory authority, the regulatory authority shall give an opinion on the extent to which the applicant for designation meets the designation criteria laid down in Article 6. NEMO designations shall only be refused where the designation criteria in Article 6 are not met or in accordance with Article 5(1).

5. A NEMO designated in one Member State shall have the right to offer day-ahead and intraday trading services with delivery in another Member State. The trading rules in the latter Member State shall apply without the need for designation as a NEMO in that Member State. The designating authorities shall monitor all NEMOs performing single day-ahead and/or intra-day coupling within their Member State. In accordance with Article 19 of Regulation (EC) No 714/2009 the designating authorities shall ensure compliance with this Regulation by all NEMOs performing single day-ahead and/or intra-day coupling within their Member State, regardless of where the NEMOs were designated. The authorities in charge of NEMO designation, monitoring and enforcement shall exchange all information necessary for an efficient supervision of NEMO activities.

A designated NEMO must notify the designating authority of another Member State if it proposes to perform single day-ahead or intraday coupling in that Member State two months before commencing operation.

6. By way of exception to paragraph 5 of this Article, a Member State may refuse the trading services by a NEMO designated in another Member State if:

(a) a national legal monopoly for day-ahead and intraday trading services exists in the Member State or bidding zone of the Member State where delivery takes place in accordance with Article 5(1); or

(b) the Member State where delivery takes place can establish that there are technical obstacles to delivery into that Member State of electricity purchased on day-ahead and intraday markets using NEMOs designated in another Member State linked to the need to ensure the objectives of this Regulation are met while maintaining operational security; or

(c) the trading rules in the Member State of delivery are not compatible with the delivery into that Member State of electricity purchased on the basis of day-ahead and intraday trading services provided by a NEMO designated in another Member State; or

(d) the NEMO is a national legal monopoly in accordance with Article 5 in the Member State where it is designated.

7. In case of a decision to refuse day-ahead and/or intraday trading services with delivery in another Member State, the Member State of delivery shall notify its decision to the NEMO and to the designating authority of the Member State where the NEMO is designated, as well as to the Agency and the Commission. The refusal shall be duly justified. In the cases set out in subparagraphs 6(b) and 6(c), the decision to refuse trading services with delivery in another Member State shall also set out how and by when the technical obstacles to trading can be overcome or the domestic trading rules can be made compatible with trading services with delivery in another Member State. The designating authority of the Member State refusing the trading services shall investigate the decision and publish an opinion on how to remove the obstacles to the trading services or how to make the trading services and the trading rules compatible.

8. The Member State where the NEMO has been designated shall ensure that designation is revoked if the NEMO fails to maintain compliance with the criteria in Article 6 and is not able to restore compliance within six months of being notified of such failure by the designating authority. If the regulatory authority is not responsible for designation and monitoring, they shall be consulted on the revocation. The designating authority shall also notify the designating authority of the other Member States in which that NEMO is active of its failure to maintain compliance at the same time it notifies the NEMO.

9. If a designating authority of a Member State finds that a NEMO active but not designated in its country fails to maintain compliance with the criteria in Article 6 with respect to its activities in this country, it must notify the NEMO of its non-compliance. If the NEMO does not restore compliance within three months of being notified, the designating authority can suspend the right to offer intraday and day-ahead trading services in this Member State until such time as the NEMO restores compliance. The designating authority shall notify the designating authority of the Member State in which the NEMO is designated, the Agency and the Commission.

10. The designating authority shall inform the Agency of the designation and revocation of NEMOs. The Agency shall maintain a list of designated NEMOs, their status and where they operate on its website.

Article 5

NEMOs designation in case of a national legal monopoly for trading services

1. If a national legal monopoly for day-ahead and intraday trading services which excludes the designation of more than one NEMO already exists in a Member State or Member State's bidding zone at the time of the entry into force of this Regulation, the Member State concerned must notify the Commission within two months after entry into force of this regulation and may refuse the designation of more than one NEMO per bidding zone.

If there are several applicants to be designated as the only NEMO, the Member State concerned shall designate the applicant which best meets the criteria listed in Article 6. If a Member State refuses the designation of more than one NEMO per bidding zone, the competent national authority shall fix or approve the NEMO fees for trading in the day-ahead and intraday markets, sufficiently in advance of their entry into force, or specify the methodologies used to calculate them.

In accordance with Article 4(6), the Member State concerned may also refuse cross-border trading services offered by a NEMO designated in another Member State; however, the protection of existing power exchanges in that Member State from economic disadvantages through competition is not a valid reason for refusal.

2. For the purposes of this regulation, a national legal monopoly is deemed to exist where national law expressly provides that no more than one entity within a Member State or Member State bidding zone can carry out day-ahead and intraday trading services.

3. Two years after the entry into force of this Regulation, the Commission shall forward a report to the European Parliament and the Council in accordance with Article 24 of Regulation (EC) No 714/2009 on the development of single day-ahead and intraday coupling in the Member States, with particular emphasis on the development of competition between NEMOs. On the basis of that report, and if the Commission deems that there is no justification for the continuation of national legal monopolies or for the continued refusal of a Member State to allow cross-border trading by a NEMO designated in another Member State, the Commission may consider appropriate legislative or other appropriate measures to further increase competition and trade between and within Member States. The Commission shall also include an assessment in the report evaluating the governance of single day-ahead and intraday coupling established by this Regulation, with particular emphasis on the transparency of MCO functions carried jointly by the NEMOs. On the basis of that report, and if the Commission deems that there is ambiguity in carrying out the monopolistic MCO functions and other NEMO tasks, the Commission may consider appropriate legislative or other appropriate measures to further increase transparency and efficient functioning of single day-ahead and intraday coupling.

Article 6

NEMO designation criteria

1. An applicant shall only be designated as a NEMO if it complies with all of the following requirements:

(a) it has contracted or contracts adequate resources for common, coordinated and compliant operation of single day-ahead and/or intraday coupling, including the resources necessary to fulfil the NEMO functions, financial resources, the necessary information technology, technical infrastructure and operational procedures or it shall provide proof that it is able to make these resources available within a reasonable preparatory period before taking up its tasks in accordance with Article 7;

(b) it shall be able to ensure that market participants have open access to information regarding the NEMO tasks in accordance with Article 7;

(c) it shall be cost-efficient with respect to single day-ahead and intraday coupling and shall in its internal accounting keep separate accounts for MCO functions and other activities in order to prevent cross-subsidisation;

(d) it shall have an adequate level of business separation from other market participants;

(e) if designated as a national legal monopoly for day-ahead and intraday trading services in a Member State, it shall not use the fees in Article 5(1) to finance its day-ahead or intraday activities in a Member State other than the one where these fees are collected;

(f) it shall be able to treat all market participants in a non-discriminatory way;

(g) it shall have appropriate market surveillance arrangements in place;

(h) it shall have in place appropriate transparency and confidentiality agreements with market participants and the TSOs;

(i) it shall be able to provide the necessary clearing and settlement services;

(j) it shall be able to put in place the necessary communication systems and routines for coordinating with the TSOs of the Member State.

2. The designation criteria set out in paragraph 1 shall be applied in such a way that competition between NEMOs is organised in a fair and non-discriminatory manner.

Article 7

NEMO tasks

1. NEMOs shall act as market operators in national or regional markets to perform in cooperation with TSOs single day-ahead and intraday coupling. Their tasks shall include receiving orders from market participants, having overall responsibility for matching and allocating orders in accordance with the single day-ahead and intraday coupling results, publishing prices and settling and clearing the contracts resulting from the trades according to relevant participant agreements and regulations.

With regard to single day-ahead and intraday coupling, NEMOs shall in particular be responsible for the following tasks:

(a) implementing the MCO functions set out in paragraph 2 in coordination with other NEMOs;

(b) establishing collectively the requirements for the single day-ahead and intraday coupling, requirements for MCO functions and the price coupling algorithm with respect to all matters related to electricity market functioning in accordance with paragraph 2 of this Article, and Articles 36 and 37;

(c) determining maximum and minimum prices in accordance with Articles 41 and 54;

(d) making anonymous and sharing the received order information necessary to perform the MCO functions provided for in paragraph 2 of this Article and Articles 40 and 53;

(e) assessing the results calculated by the MCO functions set out in paragraph 2 of this Article allocating the orders based on these results, validating the results as final if they are considered correct and taking responsibility for them in accordance with Articles 48 and 60;

(f) informing the market participants on the results of their orders in accordance with Articles 48 and 60;

(g) acting as central counter parties for clearing and settlement of the exchange of energy resulting from single day-ahead and intraday coupling in accordance with Article 68(3);

(h) establishing jointly with relevant NEMOs and TSOs back-up procedures for national or regional market operation in accordance with Article 36(3) if no results are available from the MCO functions in accordance with Article 39(2), taking account of fallback procedures provided for in Article 44;

(i) jointly providing single day-ahead and intraday coupling cost forecasts and cost information to competent regulatory authorities and TSOs where NEMO costs for establishing, amending and operating single day-ahead and intraday coupling are to be covered by the concerned TSOs' contribution in accordance with Articles 75 to 77 and Article 80;

(j) Where applicable, in accordance with Article 45 and 57, coordinate with TSOs to establish arrangements concerning more than one NEMO within a bidding zone and perform single day-ahead and/or intraday coupling in line with the approved arrangements.

2. NEMOs shall carry out MCO functions jointly with other NEMOs. Those functions shall include the following:

(a) developing and maintaining the algorithms, systems and procedures for single day-ahead and intraday coupling in accordance with Articles 36 and 51;

(b) processing input data on cross-zonal capacity and allocation constraints provided by coordinated capacity calculators in accordance with Articles 46 and 58;

(c) operating the price coupling and continuous trading matching algorithms in accordance with Articles 48 and 60;

(d) validating and sending single day-ahead and intraday coupling results to the NEMOs in accordance with Articles 48 and 60.

3. By eight months after the entry into force of this Regulation all NEMOs shall submit to all regulatory authorities and the Agency a plan that sets out how to jointly set up and perform the MCO functions set out in paragraph 2, including necessary draft agreements between NEMOs and with third parties. The plan shall include a detailed description and the proposed timescale for implementation, which shall not be longer than 12 months, and a description of the expected impact of the terms and conditions or methodologies on the establishment and performance of the MCO functions in paragraph 2.

4. Cooperation between NEMOs shall be strictly limited to what is necessary for the efficient and secure design, implementation and operation of single day-ahead and intraday coupling. The joint performance of MCO functions shall be based on the principle of non-discrimination and ensure that no NEMO can benefit from unjustified economic advantages through participation in MCO functions.

5. The Agency shall monitor NEMOs' progress in establishing and performing the MCO functions, in particular regarding the contractual and regulatory framework and regarding technical preparedness to fulfil the MCO functions. By 12 months after entry into force of this Regulation, the Agency shall report to the Commission whether progress in establishing and performing single day-ahead or intraday coupling is satisfactory.

The Agency may assess the effectiveness and efficiency of establishment and performance of the MCO function at any time. If that assessment demonstrates that the requirements are not fulfilled, the Agency may recommend to the Commission any further measures needed for timely effective and efficient delivery of single day-ahead and intraday coupling.

6. If NEMOs fail to submit a plan in accordance with Article 7(3) to establish the MCO functions referred to in paragraph 2 of this Article for either the intraday or the day-ahead market time-frames, the Commission may, in accordance with Article 9(4), propose an amendment to this Regulation, considering in particular appointing the ENTSO for Electricity or another entity to carry the MCO functions for single day-ahead coupling or for intraday coupling instead of the NEMOs.

Article 8

TSOs' tasks related to single day-ahead and intraday coupling

1. In Member States electrically connected to another Member State all TSOs shall participate in the single day-ahead and intraday coupling.

2. TSOs shall:

(a) jointly establish TSO requirements for the price coupling and continuous trading matching algorithms for all aspects related to capacity allocation in accordance with Article 37(1)(a);

(b) jointly validate the matching algorithms against the requirements referred to in point (a) of this paragraph in accordance with Article 37(4);

(c) establish and perform capacity calculation in accordance with Articles 14 to 30;

(d) where necessary, establish cross zonal capacity allocation and other arrangements in accordance with Articles 45 and 57;

(e) calculate and send cross zonal capacities and allocation constraints in accordance with Articles 46 and 58;

(f) verify single day-ahead coupling results in terms of validated cross-zonal capacities and allocation constraints in accordance with Articles 48(2) and 52;

(g) where required, establish scheduled exchange calculators for calculating and publishing scheduled exchanges on borders between bidding zones in accordance with Articles 49 and 56;

(h) respect the results from single day-ahead and intraday coupling calculated in accordance with Article 39 and Article 52;

(i) establish and operate fallback procedures as appropriate for capacity allocation in accordance with Article 44;

(j) propose the intraday cross-zonal gate opening and intraday cross-zonal gate closure times in accordance with Article 59;

(k) share congestion income in accordance with the methodology jointly developed in accordance with Article 73;

(l) where so agreed, act as shipping agents transferring net positions in accordance with Article 68(6).

Article 9

Adoption of terms and conditions or methodologies

1. TSOs and NEMOs shall develop the terms and conditions or methodologies required by this Regulation and submit them for approval to the competent regulatory authorities within the respective deadlines set out in this Regulation. Where a proposal for terms and conditions or methodologies pursuant to this Regulation needs to be developed and agreed by more than one TSO or NEMO, the participating TSOs and NEMOs shall closely cooperate. TSOs, with the assistance of ENTSO for Electricity, and all NEMOs shall regularly inform the competent regulatory authorities and the Agency about the progress of developing these terms and conditions or methodologies.

2. TSOs or NEMOs deciding on proposals for terms and conditions or methodologies in accordance with Article 9(6) shall decide with qualified majority if no consensus could be reached among them. The qualified majority shall be reached within each of the respective voting classes of TSOs and NEMOs. A qualified majority for proposals in accordance with Article 9(6) shall require a majority of:

(a) TSOs or NEMOs representing at least 55 % of the Member States; and

(b) TSOs or NEMOs representing Member States comprising at least 65 % of the population of the Union.

A blocking minority for decisions in accordance with Article 9(6) must include TSOs or NEMOs representing at least four Member States, failing of which the qualified majority shall be deemed attained.

For TSO decisions under Article 9(6), one vote shall be attributed per Member State. If there is more than one TSO in the territory of a Member State, the Member State shall allocate the voting powers among the TSOs.

For NEMO decisions in accordance with Article 9(6), one vote shall be attributed per Member State. Each NEMO shall have a number of votes equal to the number of Member States where it is designated. If more than one NEMO is designated in the territory of a Member State, the Member State shall allocate the voting powers among the NEMOs, taking into account their respective volume of transacted electricity in that particular Member State in the preceding financial year.

3. Except for Articles 43(1), 44, 56(1), 63 and 74(1) TSOs deciding on proposals for terms and conditions or methodologies in accordance with Article 9(7) shall decide with qualified majority if no consensus can be reached among them and where the regions concerned are composed of more than five Member States. The qualified majority shall be reached within each of the respective voting classes of TSOs and NEMOs. A qualified majority for proposals in accordance with Article 9(7), shall require a majority of:

(a) TSOs representing at least 72 % of the Member States concerned; and

(b) TSOs representing Member States comprising at least 65 % of the population of the concerned region.

A blocking minority for decisions in accordance with Article 9(7) must include at least the minimum number of TSOs representing more than 35 % of the population of the participating Member States, plus TSOs representing at least one additional Member State concerned, failing of which the qualified majority shall be deemed attained.

TSOs deciding on proposals for terms and conditions or methodologies in accordance with Article 9(7) in relation to regions composed of five Member States or less shall decide based on consensus.

For TSO decisions under Article 9(7), one vote shall be attributed per Member State. If there is more than one TSO in the territory of a Member State, the Member State shall allocate the voting powers among the TSOs.

NEMOs deciding on proposals for terms and conditions or methodologies in accordance with Article 9(7) shall decide based on consensus.

4. If TSOs or NEMOs fail to submit a proposal for terms and conditions or methodologies to the national regulatory authorities within the deadlines defined in this Regulation, they shall provide the competent regulatory authorities and the Agency with the relevant drafts of the terms and conditions or methodologies, and explain what has prevented an agreement. The Agency shall inform the Commission and shall, in cooperation with the competent regulatory authorities, at the Commission's request, investigate the reasons for the failure and inform the Commission thereof. The Commission shall take the appropriate steps to make possible the adoption of the required terms and conditions or methodologies within four months from the receipt of the Agency's information.

5. Each regulatory authority shall approve the terms and conditions or methodologies used to calculate or set out the single day-ahead and intraday coupling developed by TSOs and NEMOs. They shall be responsible for approving the terms and conditions or methodologies referred to in paragraphs 6, 7 and 8.

6. The proposals for the following terms and conditions or methodologies shall be subject to approval by all regulatory authorities:

(a) the plan on joint performance of MCO functions in accordance with Article 7(3);

(b) the capacity calculation regions in accordance with Article 15(1);

(c) the generation and load data provision methodology in accordance with Article 16(1);

(d) the common grid model methodology in accordance with Article 17(1);

(e) the proposal for a harmonised capacity calculation methodology in accordance with Article 21(4);

(f) back-up methodology in accordance with Article 36(3);

(g) the algorithm submitted by NEMOs in accordance with Article 37(5), including the TSOs' and NEMOs' sets of requirements for algorithm development in accordance with Article 37(1);

(h) products that can be taken into account by NEMOs in the single day-ahead and intraday coupling process in accordance with Articles 40 and 53;

(i) the maximum and minimum prices in accordance with Articles 41(1) and 54(2);

(j) the intraday capacity pricing methodology to be developed in accordance with Article 55(1);

(k) the intraday cross–zonal gate opening and intraday cross-zonal gate closure times in accordance with Article 59(1);

(l) the day-ahead firmness deadline in accordance with Article 69;

(m) the congestion income distribution methodology in accordance with Article 73(1);

7. The proposals for the following terms and conditions or methodologies shall be subject to approval by all regulatory authorities of the concerned region:

(a) the common capacity calculation methodology in accordance with Article 20(2);

(b) decisions on the introduction and postponement of flow-based calculation in accordance with Article 20(2) to (6) and on exemptions in accordance with Article 20(7);

(c) the methodology for coordinated redispatching and countertrading in accordance with Article 35(1);

(d) the common methodologies for the calculation of scheduled exchanges in accordance with Articles 43(1) and 56(1);

(e) the fallback procedures in accordance with Article 44;

(f) complementary regional auctions in accordance with Article 63(1);

(g) the conditions for the provision of explicit allocation in accordance with Article 64(2);

(h) the redispatching or countertrading cost sharing methodology in accordance with Article 74(1).

8. The following terms and conditions or methodologies shall be subject to individual approval by each regulatory authority or other competent authority of the Member States concerned:

(a) where applicable, NEMO designation and revocation or suspension of designation in accordance with Article 4(2), 4(8) and 4(9);

(b) if applicable, the fees or the methodologies used to calculate the fees of NEMOs relating to trading in the day-ahead and intraday markets in accordance with Article 5(1);

(c) proposals of individual TSOs for a review of the bidding zone configuration in accordance with Article 32(1)(d);

(d) where applicable, the proposal for cross-zonal capacity allocation and other arrangements in accordance with Articles 45 and 57;

(e) capacity allocation and congestion management costs in accordance with Articles 75 to 79;

(f) if applicable, cost sharing of regional costs of single day-ahead and intraday coupling in accordance with Article 80(4).

9. The proposal for terms and conditions or methodologies shall include a proposed timescale for their implementation and a description of their expected impact on the objectives of this Regulation. Proposals on terms and conditions or methodologies subject to the approval by several or all regulatory authorities shall be submitted to the Agency at the same time that they are submitted to regulatory authorities. Upon request by the competent regulatory authorities, the Agency shall issue an opinion within three months on the proposals for terms and conditions or methodologies.

10. Where the approval of the terms and conditions or methodologies requires a decision by more than one regulatory authority, the competent regulatory authorities shall consult and closely cooperate and coordinate with each other in order reach an agreement. Where applicable, the competent regulatory authorities shall take into account the opinion of the Agency. Regulatory authorities shall take decisions concerning the submitted terms and conditions or methodologies in accordance with paragraphs 6, 7 and 8, within six months following the receipt of the terms and conditions or methodologies by the regulatory authority or, where applicable, by the last regulatory authority concerned.

11. Where the regulatory authorities have not been able to reach agreement within the period referred to in paragraph 10, or upon their joint request, the Agency shall adopt a decision concerning the submitted proposals for terms and conditions or methodologies within six months, in accordance with Article 8(1) of Regulation (EC) No 713/2009.

12. In the event that one or several regulatory authorities request an amendment to approve the terms and conditions or methodologies submitted in accordance with paragraphs 6, 7 and 8, the relevant TSOs or NEMOs shall submit a proposal for amended terms and conditions or methodologies for approval within two months following the requirement from the regulatory authorities. The competent regulatory authorities shall decide on the amended terms and conditions or methodologies within two months following their submission. Where the competent regulatory authorities have not been able to reach an agreement on terms and conditions or methodologies pursuant to paragraphs (6) and (7) within the two-month deadline, or upon their joint request, the Agency shall adopt a decision concerning the amended terms and conditions or methodologies within six months, in accordance with Article 8(1) of Regulation (EC) No 713/2009. If the relevant TSOs or NEMOs fail to submit a proposal for amended terms and conditions or methodologies, the procedure provided for in paragraph 4 of this Article shall apply.

13. TSOs or NEMOs responsible for developing a proposal for terms and conditions or methodologies or regulatory authorities responsible for their adoption in accordance with paragraphs 6, 7 and 8, may request amendments of these terms and conditions or methodologies.

The proposals for amendment to the terms and conditions or methodologies shall be submitted to consultation in accordance with the procedure set out in Article 12 and approved in accordance with the procedure set out in this Article.

14. TSOs and NEMOs responsible for establishing the terms and conditions or methodologies in accordance with this Regulation shall publish them on the internet after approval by the competent regulatory authorities or, if no such approval is required, after their establishment, except where such information is considered as confidential in accordance with Article 13.

Article 10

Day-to-day management of the single day-ahead and intraday coupling

TSOs and NEMOs shall jointly organise the day-to-day management of the single day-ahead and intraday coupling. They shall meet regularly to discuss and decide on day-to-day operational issues. TSOs and NEMOs shall invite the Agency and the Commission as observers to these meetings and shall publish summary minutes of the meetings.

Article 11

Stakeholder involvement

The Agency, in close cooperation with ENTSO for Electricity, shall organise stakeholder involvement regarding single day-ahead and intraday coupling and other aspects of the implementation of this Regulation. This shall include regular meetings with stakeholders to identify problems and propose improvements notably related to the single day-ahead and intraday coupling. This shall not replace the stakeholder consultations in accordance with Article 12.

Article 12

Consultation

1. TSOs and NEMOs responsible for submitting proposals for terms and conditions or methodologies or their amendments in accordance with this Regulation shall consult stakeholders, including the relevant authorities of each Member State, on the draft proposals for terms and conditions or methodologies where explicitly set out in this Regulation. The consultation shall last for a period of not less than one month.

2. The proposals for terms and conditions or methodologies submitted by the TSOs and NEMOs at Union level shall be published and submitted to consultation at Union level. Proposals submitted by the TSOs and NEMOs at regional level shall be submitted to consultation at least at regional level. Parties submitting proposals at bilateral or at multilateral level shall consult at least the Member States concerned.

3. The entities responsible for the proposal for terms and conditions or methodologies shall duly consider the views of stakeholders resulting from the consultations undertaken in accordance with paragraph 1, prior to its submission for regulatory approval if required in accordance with Article 9 or prior to publication in all other cases. In all cases, a clear and robust justification for including or not the views resulting from the consultation shall be developed in the submission and published in a timely manner before or simultaneously with the publication of the proposal for terms and conditions or methodologies.

Article 13

Confidentiality obligations

1. Any confidential information received, exchanged or transmitted pursuant to this Regulation shall be subject to the conditions of professional secrecy laid down in paragraphs 2, 3 and 4.

2. The obligation of professional secrecy shall apply to any person subject to the provisions of this Regulation.

3. Confidential information received by the persons referred to in paragraph 2 in the course of their duties may not be divulged to any other person or authority, without prejudice to cases covered by national law, the other provisions of this Regulation or other relevant Union legislation.

4. Without prejudice to cases covered by national law, regulatory authorities, bodies or persons which receive confidential information pursuant to this Regulation may use it only for the purpose of the performance of their functions under this Regulation.

TITLE II

REQUIREMENTS FOR TERMS, CONDITIONS AND METHODOLOGIES CONCERNING CAPACITY ALLOCATION AND CONGESTION MANAGEMENT

CHAPTER 1

Capacity calculation

Section 1

General requirements

Article 14

Capacity calculation time-frames

1. All TSOs shall calculate cross-zonal capacity for at least the following time-frames:

(a) day-ahead, for the day-ahead market;

(b) intraday, for the intraday market.

2. For the day-ahead market time-frame, individual values for cross-zonal capacity for each day-ahead market time unit shall be calculated. For the intraday market time-frame, individual values for cross-zonal capacity for each remaining intraday market time unit shall be calculated.

3. For the day-ahead market time-frame, the capacity calculation shall be based on the latest available information. The information update for the day-ahead market time-frame shall not start before 15:00 market time two days before the day of delivery.

4. All TSOs in each capacity calculation region shall ensure that cross-zonal capacity is recalculated within the intraday market time-frame based on the latest available information. The frequency of this recalculation shall take into consideration efficiency and operational security.

Article 15

Capacity calculation regions

1. By three months after the entry into force of this Regulation all TSOs shall jointly develop a common proposal regarding the determination of capacity calculation regions. The proposal shall be subject to consultation in accordance with Article 12.

2. The proposal referred to in paragraph 1 shall define the bidding zone borders attributed to TSOs who are members of each capacity calculation region. The following requirements shall be met:

(a) it shall take into consideration the regions specified in point 3(2) of Annex I to Regulation (EC) No 714/2009;

(b) each bidding zone border, or two separate bidding zone borders if applicable, through which interconnection between two bidding zones exists, shall be assigned to one capacity calculation region;

(c) at least those TSOs shall be assigned to all capacity calculation regions in which they have bidding zone borders.

3. Capacity calculation regions applying a flow-based approach shall be merged into one capacity calculation region if the following cumulative conditions are fulfilled:

(a) their transmission systems are directly linked to each other;

(b) they participate in the same single day-ahead or intraday coupling area;

(c) merging them is more efficient than keeping them separate. The competent regulatory authorities may request a joint cost-benefit analysis from the TSOs concerned to assess the efficiency of the merger.

Section 2

The common grid model

Article 16

Generation and load data provision methodology

1. By 10 months after the entry into force of this Regulation all TSOs shall jointly develop a proposal for a single methodology for the delivery of the generation and load data required to establish the common grid model, which shall be subject to consultation in accordance with Article 12. The proposal shall include a justification based on the objectives of this Regulation for requiring the information.

2. The proposal for the generation and load data provision methodology shall specify which generation units and loads are required to provide information to their respective TSOs for the purposes of capacity calculation.

3. The proposal for a generation and load data provision methodology shall specify the information to be provided by generation units and loads to TSOs. The information shall at least include the following:

(a) information related to their technical characteristics;

(b) information related to the availability of generation units and loads;

(c) information related to the schedules of generation units;

(d) relevant available information relating to how generation units will be dispatched.

4. The methodology shall specify the deadlines applicable to generation units and loads for providing the information referred to in paragraph 3.

5. Each TSO shall use and share with other TSOs the information referred to in paragraph 3. The information referred to in paragraph 3(d) shall be used for capacity calculation purposes only.

6. No later than two months after the approval of the generation and load data provision methodology by all regulatory authorities, ENTSO for Electricity shall publish:

(a) a list of the entities required to provide information to the TSOs;

(b) a list of the information referred to in paragraph 3 to be provided;

(c) deadlines for providing information.

Article 17

Common grid model methodology

1. By 10 months after the entering into force of this Regulation all TSOs shall jointly develop a proposal for a common grid model methodology. The proposal shall be subject to consultation in accordance with Article 12.

2. The common grid model methodology shall enable a common grid model to be established. It shall contain at least the following items:

(a) a definition of scenarios in accordance with Article 18;

(b) a definition of individual grid models in accordance with Article 19;

(c) a description of the process for merging individual grid models to form the common grid model.

Article 18

Scenarios

1. All TSOs shall jointly develop common scenarios for each capacity calculation time-frame referred to in Article 14(1)(a) and (b). The common scenarios shall be used to describe a specific forecast situation for generation, load and grid topology for the transmission system in the common grid model.

2. One scenario per market time unit shall be developed both for the day-ahead and the intraday capacity calculation time-frames.

3. For each scenario, all TSOs shall jointly draw up common rules for determining the net position in each bidding zone and the flow for each direct current line. These common rules shall be based on the best forecast of the net position for each bidding zone and on the best forecast of the flows on each direct current line for each scenario and shall include the overall balance between load and generation for the transmission system in the Union. There shall be no undue discrimination between internal and cross-zonal exchanges when defining scenarios, in line with point 1.7 of Annex I to Regulation (EC) No 714/2009.

Article 19

Individual grid model

1. For each bidding zone and for each scenario:

(a) all TSOs in the bidding zone shall jointly provide a single individual grid model which complies with Article 18(3); or

(b) each TSO in the bidding zone shall provide an individual grid model for its control area, including interconnections, provided that the sum of net positions in the control areas, including interconnections, covering the bidding zone complies with Article 18(3).

2. Each individual grid model shall represent the best possible forecast of transmission system conditions for each scenario specified by the TSO(s) at the time when the individual grid model is created.

3. Individual grid models shall cover all network elements of the transmission system that are used in regional operational security analysis for the concerned time-frame.

4. All TSOs shall harmonise to the maximum possible extent the way in which individual grid models are built.

5. Each TSO shall provide all necessary data in the individual grid model to allow active and reactive power flow and voltage analyses in steady state.

6. Where appropriate, and upon agreement between all TSOs within a capacity calculation region, each TSO in that capacity calculation region shall exchange data between each other to enable voltage and dynamic stability analyses.

Section 3

Capacity calculation methodologies

Article 20

Introduction of flow-based capacity calculation methodology

1. For the day-ahead market time-frame and intraday market time-frame the approach used in the common capacity calculation methodologies shall be a flow-based approach, except where the requirement under paragraph 7 is met.

2. No later than 10 months after the approval of the proposal for a capacity calculation region in accordance with Article 15(1), all TSOs in each capacity calculation region shall submit a proposal for a common coordinated capacity calculation methodology within the respective region. The proposal shall be subject to consultation in accordance with Article 12. The proposal for the capacity calculation methodology within regions pursuant to this paragraph in capacity calculation regions based on the ‘North-West Europe’ (‘NWE’) and ‘Central Eastern Europe’ (‘CEE’) as defined in points (b), and (d) of point 3.2 of Annex I to Regulation (EC) No 714/2009 as well as in regions referred to in paragraph 3 and 4, shall be complemented with a common framework for coordination and compatibility of flow-based methodologies across regions to be developed in accordance with paragraph 5.

3. The TSOs from the capacity calculation region where Italy, as defined in point (c) of point 3.2 of Annex I to Regulation (EC) No 714/2009, is included, may extend the deadline without prejudice to the obligation in paragraph 1 for submitting the proposal for a common coordinated capacity calculation methodology using flow-based approach for the respective region pursuant to paragraph 2 up to six months after Switzerland joins the single day-ahead coupling. The proposal does not have to include bidding zone borders within Italy and between Italy and Greece.

4. No later than six months after at least all South East Europe Energy Community Contracting Parties participate in the single day-ahead coupling, the TSOs from at least Croatia, Romania, Bulgaria and Greece shall jointly submit a proposal to introduce a common capacity calculation methodology using the flow-based approach for the day-ahead and intraday market time-frame. The proposal shall provide for an implementation date of the common capacity calculation methodology using the flow-based approach of no longer than two years after the participation of all SEE Energy Community Contracting Parties in the single day-ahead coupling. The TSOs from Member States which have borders with other regions are encouraged to join the initiatives to implement a common flow-based capacity calculation methodology with these regions.

5. At the time when two or more adjacent capacity calculation regions in the same synchronous area implement a capacity calculation methodology using the flow-based approach for the day-ahead or the intraday market time-frame, they shall be considered as one region for this purpose and the TSOs from this region shall submit within six months a proposal for applying a common capacity calculation methodology using the flow-based approach for the day-ahead or intraday market time-frame. The proposal shall provide for an implementation date of the common cross regional capacity calculation methodology of no longer than 12 months after the implementation of the flow-based approach in these regions for the methodology for the day-ahead market time-frame, and 18 months for the methodology for the intraday time-frame. The timelines indicated in this paragraph may be adapted in accordance with paragraph 6.

The methodology in the two capacity calculation regions which have initiated developing a common capacity calculation methodology may be implemented first before developing a common capacity calculation methodology with any further capacity calculation region.

6. If the TSOs concerned are able to demonstrate that the application of common flow-based methodologies in accordance with paragraphs 4 and 5 would not yet be more efficient assuming the same level of operational security, they may jointly request the competent regulatory authorities to postpone the deadlines.

7. TSOs may jointly request the competent regulatory authorities to apply the coordinated net transmission capacity approach in regions and bidding zone borders other than those referred to in paragraphs 2 to 4, if the TSOs concerned are able to demonstrate that the application of the capacity calculation methodology using the flow-based approach would not yet be more efficient compared to the coordinated net transmission capacity approach and assuming the same level of operational security in the concerned region.

8. To enable market participants to adapt to any change in the capacity calculation approach, the TSOs concerned shall test the new approach alongside the existing approach and involve market participants for at least six months before implementing a proposal for changing their capacity calculation approach.

9. The TSOs of each capacity calculation region applying the flow-based approach shall establish and make available a tool which enables market participants to evaluate the interaction between cross-zonal capacities and cross-zonal exchanges between bidding zones.

Article 21

Capacity calculation methodology

1. The proposal for a common capacity calculation methodology for a capacity calculation region determined in accordance with Article 20(2) shall include at least the following items for each capacity calculation time-frame:

(a) methodologies for the calculation of the inputs to capacity calculation, which shall include the following parameters: (i) a methodology for determining the reliability margin in accordance with Article 22; (ii) the methodologies for determining operational security limits, contingencies relevant to capacity calculation and allocation constraints that may be applied in accordance with Article 23; (iii) the methodology for determining the generation shift keys in accordance with Article 24; (iv) the methodology for determining remedial actions to be considered in capacity calculation in accordance with Article 25.

(b) a detailed description of the capacity calculation approach which shall include the following: (i) a mathematical description of the applied capacity calculation approach with different capacity calculation inputs; (ii) rules for avoiding undue discrimination between internal and cross-zonal exchanges to ensure compliance with point 1.7 of Annex I to Regulation (EC) No 714/2009; (iii) rules for taking into account, where appropriate, previously allocated cross-zonal capacity; (iv) rules on the adjustment of power flows on critical network elements or of cross-zonal capacity due to remedial actions in accordance with Article 25; (v) for the flow-based approach, a mathematical description of the calculation of power transfer distribution factors and of the calculation of available margins on critical network elements; (vi) for the coordinated net transmission capacity approach, the rules for calculating cross-zonal capacity, including the rules for efficiently sharing the power flow capabilities of critical network elements among different bidding zone borders; (vii) where the power flows on critical network elements are influenced by cross-zonal power exchanges in different capacity calculation regions, the rules for sharing the power flow capabilities of critical network elements among different capacity calculation regions in order to accommodate these flows.

(c) a methodology for the validation of cross-zonal capacity in accordance with Article 26.

2. For the intraday capacity calculation time-frame, the capacity calculation methodology shall also state the frequency at which capacity will be reassessed in accordance with Article 14(4), giving reasons for the chosen frequency.

3. The capacity calculation methodology shall include a fallback procedure for the case where the initial capacity calculation does not lead to any results.

4. All TSOs in each capacity calculation region shall, as far as possible, use harmonised capacity calculation inputs. By 31 December 2020, all regions shall use a harmonised capacity calculation methodology which shall in particular provide for a harmonised capacity calculation methodology for the flow-based and for the coordinated net transmission capacity approach. The harmonisation of capacity calculation methodology shall be subject to an efficiency assessment concerning the harmonisation of the flow-based methodologies and the coordinated net transmission capacity methodologies that provide for the same level of operational security. All TSOs shall submit the assessment with a proposal for the transition towards a harmonised capacity calculation methodology to all regulatory authorities within 12 months after at least two capacity calculation regions have implemented common capacity calculation methodology in accordance with Article 20(5).

Article 22

Reliability margin methodology

1. The proposal for a common capacity calculation methodology shall include a methodology to determine the reliability margin. The methodology to determine the reliability margin shall consist of two steps. First, the relevant TSOs shall estimate the probability distribution of deviations between the expected power flows at the time of the capacity calculation and realised power flows in real time. Second, the reliability margin shall be calculated by deriving a value from the probability distribution.

2. The methodology to determine the reliability margin shall set out the principles for calculating the probability distribution of the deviations between the expected power flows at the time of the capacity calculation and realised power flows in real time, and specify the uncertainties to be taken into account in the calculation. To determine those uncertainties, the methodology shall in particular take into account:

(a) unintended deviations of physical electricity flows within a market time unit caused by the adjustment of electricity flows within and between control areas, to maintain a constant frequency;

(b) uncertainties which could affect capacity calculation and which could occur between the capacity calculation time-frame and real time, for the market time unit being considered.

3. In the methodology to determine the reliability margin, TSOs shall also set out common harmonised principles for deriving the reliability margin from the probability distribution.

4. On the basis of the methodology adopted in accordance with paragraph 1, TSOs shall determine the reliability margin respecting the operational security limits and taking into account uncertainties between the capacity calculation time-frame and real time, and the remedial actions available after capacity calculation.

5. For each capacity calculation time-frame, the TSOs concerned shall determine the reliability margin for critical network elements, where the flow-based approach is applied, and for cross-zonal capacity, where the coordinated net transmission capacity approach is applied.

Article 23

Methodologies for operational security limits, contingencies and allocation constraints

1. Each TSO shall respect the operational security limits and contingencies used in operational security analysis.

2. If the operational security limits and contingencies used in capacity calculation are not the same as those used in operational security analysis, TSOs shall describe in the proposal for the common capacity calculation methodology the particular method and criteria they have used to determine the operational security limits and contingencies used for capacity calculation.

3. If TSOs apply allocation constraints, they can only be determined using:

(a) constraints that are needed to maintain the transmission system within operational security limits and that cannot be transformed efficiently into maximum flows on critical network elements; or

(b) constraints intended to increase the economic surplus for single day-ahead or intraday coupling.

Article 24

Generation shift keys methodology

1. The proposal for a common capacity calculation methodology shall include a proposal for a methodology to determine a common generation shift key for each bidding zone and scenario developed in accordance with Article 18.

2. The generation shift keys shall represent the best forecast of the relation of a change in the net position of a bidding zone to a specific change of generation or load in the common grid model. That forecast shall notably take into account the information from the generation and load data provision methodology.

Article 25

Methodology for remedial actions in capacity calculation

1. Each TSO within each capacity calculation region shall individually define the available remedial actions to be taken into account in capacity calculation to meet the objectives of this Regulation.

2. Each TSO within each capacity calculation region shall coordinate with the other TSOs in that region the use of remedial actions to be taken into account in capacity calculation and their actual application in real time operation.

3. To enable remedial actions to be taken into account in capacity calculation, all TSOs in each capacity calculation region shall agree on the use of remedial actions that require the action of more than one TSO.

4. Each TSO shall ensure that remedial actions are taken into account in capacity calculation under the condition that the available remedial actions remaining after calculation, taken together with the reliability margin referred to in Article 22, are sufficient to ensure operational security.

5. Each TSO shall take into account remedial actions without costs in capacity calculation.

6. Each TSO shall ensure that the remedial actions to be taken into account in capacity calculation are the same for all capacity calculation time-frames, taking into account their technical availabilities for each capacity calculation time-frame.

Article 26

Cross-zonal capacity validation methodology

1. Each TSO shall validate and have the right to correct cross-zonal capacity relevant to the TSO's bidding zone borders or critical network elements provided by the coordinated capacity calculators in accordance with Articles 27 to 31.

2. Where a coordinated net transmission capacity approach is applied, all TSOs in the capacity calculation region shall include in the capacity calculation methodology referred to in Article 21 a rule for splitting the correction of cross-zonal capacity between the different bidding zone borders.

3. Each TSO may reduce cross-zonal capacity during the validation of cross-zonal capacity referred to in paragraph 1 for reasons of operational security.

4. Each coordinated capacity calculator shall coordinate with the neighbouring coordinated capacity calculators during capacity calculation and validation.

5. Each coordinated capacity calculator shall, every three months, report all reductions made during the validation of cross-zonal capacity in accordance with paragraph 3 to all regulatory authorities of the capacity calculation region. This report shall include the location and amount of any reduction in cross-zonal capacity and shall give reasons for the reductions.

6. All the regulatory authorities of the capacity calculation region shall decide whether to publish all or part of the report referred to in paragraph 5.

Section 4

The capacity calculation process

Article 27

General provisions

1. No later than six months after the decision on the generation and load data provision methodology referred to in Article 16 and the common grid model methodology referred to in Article 17, all TSOs shall organise the process of merging the individual grid models.

2. No later than four months after the decisions on the capacity calculation methodologies referred to in Articles 20 and 21, all the TSOs in each capacity calculation region shall jointly set up the coordinated capacity calculators and establish rules governing their operations.

3. All TSOs of each capacity calculation region shall review the quality of data submitted within the capacity calculation every second year as part of the biennial report on capacity calculation and allocation produced in accordance with Article 31.

4. Using the latest available information, all TSOs shall regularly and at least once a year review and update:

(a) the operational security limits, contingencies and allocation constraints used for capacity calculation;

(b) the probability distribution of the deviations between expected power flows at the time of capacity calculation and realised power flows in real time used for calculation of reliability margins;

(c) the remedial actions taken into account in capacity calculation;

(d) the application of the methodologies for determining generation shift keys, critical network elements and contingencies referred to in Articles 22 to 24.

Article 28

Creation of a common grid model

1. For each capacity calculation time-frame referred to in Article 14(1), each generator or load unit subject to Article 16 shall provide the data specified in the generation and load data provision methodology to the TSO responsible for the respective control area within the specified deadlines.

2. Each generator or load unit providing information pursuant to Article 16(3) shall deliver the most reliable set of estimations practicable.

3. For each capacity calculation time-frame, each TSO shall establish the individual grid model for each scenario in accordance with Article 19, in order to merge individual grid models into a common grid model.

4. Each TSO shall deliver to the TSOs responsible for merging the individual grid models into a common grid model the most reliable set of estimations practicable for each individual grid model.

5. For each capacity calculation time-frame a single, Union-wide common grid model shall be created for each scenario as set out in Article 18 by merging inputs from all TSOs applying the capacity calculation process as set out in paragraph 3 of this Article.

Article 29

Regional calculation of cross-zonal capacity

1. For each capacity calculation time-frame, each TSO shall provide the coordinated capacity calculators and all other TSOs in the capacity calculation region with the following items: operational security limits, generation shift keys, remedial actions, reliability margins, allocation constraints and previously allocated cross-zonal capacity.

2. Each coordinated capacity calculator shall perform an operational security analysis applying operational security limits by using the common grid model created for each scenario in accordance with Article 28(5).

3. When calculating cross-zonal capacity, each coordinated capacity calculator shall:

(a) use generation shift keys to calculate the impact of changes in bidding zone net positions and of flows on direct current lines;

(b) ignore those critical network elements that are not significantly influenced by the changes in bidding zone net positions according to the methodology set out in Article 21; and,

(c) ensure that all sets of bidding zone net positions and flows on direct current lines not exceeding cross-zonal capacity comply with reliability margins and operational security limits in accordance with Article 21(1)(a)(i) and (ii), and take into account previously allocated cross-zonal capacity in accordance with Article 21(1)(b)(iii).

4. Each coordinated capacity calculator shall optimise cross-zonal capacity using available remedial actions taken into account in capacity calculation in accordance with Article 21(1)(a)(iv).

5. Each coordinated capacity calculator shall apply the sharing rules established in accordance with Article 21(1)(b)(vi).

6. Each coordinated capacity calculator shall respect the mathematical description of the applied capacity calculation approach established in accordance with Article 21(1)(b)(i).

7. Each coordinated capacity calculator applying the flow-based approach shall:

(a) use data on operational security limits to calculate the maximum flows on critical network elements;

(b) use the common grid model, generation shift keys and contingencies to calculate the power transfer distribution factors;

(c) use power transfer distribution factors to calculate the flows resulting from previously allocated cross-zonal capacity in the capacity calculation region;

(d) calculate flows on critical network elements for each scenario (taking into account contingencies), and adjust them by assuming no cross-zonal power exchanges within the capacity calculation region, applying the rules for avoiding undue discrimination between internal and cross-zonal power exchanges established in accordance with Article 21(1)(b)(ii);

(e) calculate the available margins on critical network elements, taking into account contingencies, which shall equal the maximum flows reduced by adjusted flows referred to in point (d), reliability margins, and flows resulting from previously allocated cross-zonal capacity;

(f) adjust the available margins on critical network elements or power transfer distribution factors using available remedial actions to be considered in capacity calculation in accordance with Article 25.

8. Each coordinated capacity calculator applying the coordinated net transmission capacity approach shall:

(a) use the common grid model, generation shift keys and contingencies to calculate maximum power exchange on bidding zone borders, which shall equal the maximum calculated exchange between two bidding zones on either side of the bidding zone border respecting operational security limits;

(b) adjust maximum power exchange using remedial actions taken into account in capacity calculation in accordance with Article 25;

(c) adjust maximum power exchange, applying rules for avoiding undue discrimination between internal and cross-zonal exchanges in accordance with Article 21(1)(b)(ii);

(d) apply the rules set out in accordance with Article 21(1)(b)(vi) for efficiently sharing the power flow capabilities of critical network elements among different bidding zone borders;

(e) calculate cross-zonal capacity, which shall be equal to maximum power exchange adjusted for the reliability margin and previously allocated cross-zonal capacity.

9. Each coordinated capacity calculator shall cooperate with the neighbouring coordinated capacity calculators. Neighbouring TSOs shall ensure such cooperation by exchanging and confirming information on interdependency with the relevant regional coordinated capacity calculators, for the purposes of capacity calculation and validation. Neighbouring TSOs shall provide information on interdependency to the coordinated capacity calculators before capacity calculation. An assessment of the accuracy of this information and corrective measures shall be included in the biennial report drafted in accordance with Article 31, where appropriate.

10. Each coordinated capacity calculator shall set:

(a) flow-based parameters for each bidding zone within the capacity calculation region, if applying the flow-based approach; or

(b) cross-zonal capacity values for each bidding zone border within the capacity calculation region, if applying the coordinated net transmission capacity approach.

11. Each coordinated capacity calculator shall submit the cross-zonal capacity to each TSO within its capacity calculation region for validation in accordance with Article 21(1)(c).

Article 30

Validation and delivery of cross-zonal capacity

1. Each TSO shall validate the results of the regional capacity calculation for its bidding zone borders or critical network elements, in accordance with Article 26.

2. Each TSO shall send its capacity validation and allocation constraints to the relevant coordinated capacity calculators and to the other TSOs of the relevant capacity calculation regions.

3. Each coordinated capacity calculator shall provide the validated cross-zonal capacities and allocation constraints for the purposes of allocating capacity in accordance with Articles 46 and 58.

Section 5

Biennial report on capacity calculation and allocation

Article 31

Biennial report on capacity calculation and allocation

1. By two years after the entry into force of this Regulation, ENTSO for Electricity shall draft a report on capacity calculation and allocation and submit it to the Agency.

2. If the Agency requests it, in every second subsequent year ENTSO for Electricity shall draft a report on capacity calculation and allocation and submit it to the Agency.

3. For each bidding zone, bidding zone border and capacity calculation region, the report on capacity calculation and allocation shall contain at least:

(a) the capacity calculation approach used;

(b) statistical indicators on reliability margins;

(c) statistical indicators of cross-zonal capacity, including allocation constraints where appropriate for each capacity calculation time-frame;

(d) quality indicators for the information used for the capacity calculation;

(e) where appropriate, proposed measures to improve capacity calculation;

(f) for regions where the coordinated net transmission capacity approach is applied, an analysis of whether the conditions specified in Article 20(7) are still fulfilled;

(g) indicators for assessing and following in the longer term the efficiency of single day-ahead and intraday coupling, including the merging of capacity calculation regions in accordance with Article 15(3) where relevant;

(h) recommendations for further development of single day-ahead and intraday coupling, including further harmonisation of methodologies, processes and governance arrangements.

4. After consulting the Agency, all TSOs shall jointly agree on the statistical and quality indicators for the report. The Agency may require the amendment of those indicators, prior to the agreement by the TSOs or during their application.

5. The Agency shall decide whether to publish all or part of the biennial report.

CHAPTER 2

Bidding zone configuration

Article 32

Reviewing existing bidding zone configurations

1. A review of an existing bidding zone configuration may be launched by:

(a) the Agency, in accordance with Article 34(7);

(b) several regulatory authorities, pursuant to a recommendation from the Agency in accordance with Article 34;

(c) TSOs of a capacity calculation region, together with all concerned TSOs whose control areas, including interconnectors, are within the geographic area in which the bidding zone configuration shall be assessed in accordance with paragraph 2(a);

(d) one single regulatory authority or TSO with the approval of its competent regulatory authority, for the bidding zones inside the TSO's control area, if the bidding zone configuration has negligible impact on neighbouring TSOs' control areas, including interconnectors, and the review of bidding zone configuration is necessary to improve efficiency, or to maintain operational security;

(e) Member States in a capacity calculation region.

2. If a review is launched in accordance with paragraph 1(a),(b), (c) or (e), the entity launching the review shall specify:

(a) the geographic area in which bidding zone configuration shall be assessed and the neighbouring geographic areas for which impacts shall be taken into account;

(b) the participating TSOs;

(c) the participating regulatory authorities.

3. If a review is launched in accordance with paragraph 1(d), the following conditions shall apply:

(a) the geographic area in which bidding zone configuration is assessed shall be limited to the control area of the relevant TSO, including interconnectors;

(b) the TSO of the relevant control area shall be the only TSO participating in the review;

(c) the competent regulatory authority shall be the only regulatory authority participating in the review;

(d) the relevant TSO and regulatory authority, respectively, shall give the neighbouring TSOs and regulatory authorities mutually agreed prior notice of the launch of the review, giving reasons; and

(e) the conditions for the review shall be specified, and the results of the review and proposal for the relevant regulatory authorities shall be published.

4. The review process shall consist of two steps.

(a) In the first step, the TSOs participating in a review of bidding zone configuration shall develop the methodology and assumptions that will be used in the review process and propose alternative bidding zone configurations for the assessment. The proposal on methodology and assumptions and alternative bidding zone configuration shall be submitted to the participating regulatory authorities, which shall be able to require coordinated amendments within three months.

(b) In the second step, the TSOs participating in a review of bidding zone configuration shall: (i) assess and compare the current bidding zone configuration and each alternative bidding zone configuration using the criteria specified in Article 33; (ii) hold a consultation in accordance with Article 12 and a workshop regarding the alternative bidding zone configuration proposals compared to the existing bidding zone configuration, including timescales for implementation, unless the bidding zone configuration has negligible impact on neighbouring TSOs' control areas; (iii) submit a joint proposal to maintain or amend the bidding zone configuration to the participating Member States and the participating regulatory authorities within 15 months of the decision to launch a review.

(c) On receiving the joint proposal to maintain or to amend the bidding zone configuration in accordance with point (iii) above, the participating Member States or, where provided by Member States, the reg