PART III

To perform operational security analysis pursuant to Title 2 of this Part, each TSO shall prepare individual grid models in accordance with the methodologies established in application of Article 17 of Regulation (EU) 2015/1222 and Article 18 of Regulation (EU) 2016/1719 for each of the following time-frames, applying the data format established pursuant to Article 114(2): year-ahead, in accordance with Articles 66, 67 and 68; where applicable, week-ahead, in accordance with Article 69; day-ahead, in accordance with Article 70; and intraday, in accordance with Article 70. The individual grid models shall include the structural information and data set out in Article 41. Each TSO shall build the individual grid models and each regional security coordinator shall contribute to building the common grid models applying the data format established pursuant to Article 114(2). All TSOs shall jointly develop a common list of year-ahead scenarios against which they assess the operation of the interconnected transmission system for the following year. Those scenarios shall allow the identification and the assessment of the influence of the interconnected transmission system on operational security. The scenarios shall include the following variables: electricity demand; the conditions related to the contribution of renewable energy sources; determined import/export positions, including agreed reference values allowing the merging task; the generation pattern, with a fully available production park; the year-ahead grid development. When developing the common list of scenarios, TSOs shall take into account the following elements: the typical cross-border exchange patterns for different levels of consumption and of renewable energy sources and conventional generation; the probability of occurrence of the scenarios; the potential deviations from operational security limits for each scenario; the amount of power generated and consumed by the power generating facilities and demand facilities connected to distribution systems. Where TSOs do not succeed in establishing the common list of scenarios referred to in paragraph 1, they shall use the following default scenarios: Winter Peak, 3rd Wednesday of January current year, 10:30 CET; Winter Valley, 2nd Sunday of January current year, 03:30 CET; Spring Peak, 3rd Wednesday of April current year, 10:30 CET; Spring Valley, 2nd Sunday of April current year, 03:30 CET; Summer Peak, 3rd Wednesday of July previous year, 10:30 CET; Summer Valley, 2nd Sunday of July previous year, 03:30 CET; Autumn Peak, 3rd Wednesday of October previous year, 10:30 CET; Autumn Valley, 2nd Sunday of October previous year, 03:30 CET. ENTSO for Electricity shall publish every year, by 15 July, the common list of scenarios established for the following year, including the description of those scenarios and the period during which these scenarios are to be used. Each TSO shall determine a year-ahead individual grid model for each of the scenarios developed pursuant to Article 65, using its best estimates of the variables defined in Article 65(1). Each TSO shall publish its year-ahead individual grid models on the ENTSO for Electricity operational planning data environment in accordance with Article 114(1). When defining its year-ahead individual grid model, each TSO shall: agree with the neighbouring TSOs upon the estimated power flow on HVDC systems linking their control areas; balance for each scenario the sum of: net exchanges on AC lines; estimated power flows on HVDC systems; load, including an estimation of losses; and generation. Each TSO shall include in its year-ahead individual grid models the aggregated power outputs for power generating facilities connected to distribution systems. Those aggregated power outputs shall: be consistent with the structural data provided in accordance with the requirements of Articles 41, 43, 45 and 48; be consistent with the scenarios developed in accordance with Article 65; and distinguish the type of primary energy source. By 6 months after entry into force of this Regulation, all TSOs shall jointly develop a proposal for the methodology for building the year-ahead common grid models from the individual grid models established in accordance with Article 66(1) and for saving them. The methodology shall take into account, and complement where necessary, the operational conditions of the common grid model methodology developed in accordance with Article 17 of Regulation (EU) 2015/1222 and Article 18 of Regulation (EU) 2016/1719, as regards the following elements: deadlines for gathering the year-ahead individual grid models, for merging them into a common grid model and for saving the individual and common grid models; quality control of the individual and common grid models to be implemented in order to ensure their completeness and consistency; and correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (b). Each TSO shall have the right to request from another TSO any information on modifications to the network topology or on operational arrangements, such as protection setpoints or system protection schemes, single line diagrams and configuration of substations or additional grid models relevant for the provision of an accurate representation of the transmission system to undertake operational security analysis. When a TSO modifies or notices a modification of its best estimates for the variables used for determining its year-ahead individual grid model established in accordance with Article 66(1), which is significant for operational security, it shall update its year-ahead individual grid model and publish it on the ENTSO for Electricity operational planning data environment. Whenever an individual grid model is updated, the year-ahead common grid model shall be updated accordingly applying the methodology determined in accordance with Article 67(1). Where two or more TSOs consider it necessary, they shall determine the most representative scenarios for coordinating the operational security analysis of their transmission system for the week-ahead time-frame and shall develop a methodology for merging the individual grid models analogous to the methodology for building the year-ahead common grid model from year-ahead individual grid models in accordance with Article 67(1). Each TSO referred to in paragraph 1 shall establish or update its week-ahead individual grid models pursuant to the scenarios determined in accordance with paragraph 1. The TSOs referred to in paragraph 1 or the third parties to which the task referred to in paragraph 1 has been delegated, shall build the week-ahead common grid models following the methodology developed in accordance with paragraph 1 and using the individual grid models established in accordance with paragraph 2. By 6 months after entry into force of this Regulation, all TSOs shall jointly develop a proposal for the methodology for building the day-ahead and intraday common grid models from the individual grid models and for saving them. That methodology shall take into account, and complement where necessary, the operational conditions of the common grid model methodology developed in accordance with Article 17 of Regulation (EU) 2015/1222, as regards the following elements: definition of timestamps; deadlines for gathering the individual grid models, for merging them into a common grid model and for saving individual and common grid models. The deadlines shall be compatible with the regional processes established for preparing and activating remedial actions; quality control of individual grid models and the common grid model to be implemented to ensure their completeness and consistency; correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (c); and handling additional information related to operational arrangements, such as protection setpoints or system protection schemes, single line diagrams and configuration of substations in order to manage operational security. Each TSO shall create day-ahead and intraday individual grid models in accordance with paragraph 1 and publish them on the ENTSO for Electricity operational planning data environment. When creating the day-ahead or intraday individual grid models referred to in paragraph 2, each TSO shall include: up-to-date load and generation forecasts; the available results of the day-ahead and intraday market processes; the available results of the scheduling tasks described in Title 6 of Part III; for power generating facilities connected to distribution systems, aggregated active power output differentiated on the basis of the type of primary energy source, in line with data provided in accordance with Articles 40, 43, 44, 48, 49 and 50; up-to-date topology of the transmission system. All remedial actions already decided shall be included in the day-ahead and intraday individual grid models and shall be clearly distinguishable from the injections and withdrawals established in accordance with Article 40(4) and the network topology without remedial actions applied. Each TSO shall assess the accuracy of the variables in paragraph 3 by comparing the variables with their actual values, taking into account the principles determined pursuant to Article 75(1)(c). If, following the assessment referred to in paragraph 5, a TSO considers that the accuracy of the variables is insufficient to evaluate operational security, it shall determine the causes of the inaccuracy. If the causes depend on the TSO's processes for establishing the individual grid models, that TSO shall review those processes to obtain more accurate results. If the causes depend on variables provided by other parties, that TSO together with those other parties shall endeavour to ensure that the variables concerned are accurate. When defining the quality controls in accordance with Articles 67(1)(b) and 70(1)(c), all TSOs shall jointly determine controls aimed at least to check: the coherence of the connection status of interconnectors; that voltage values are within the usual operational values for those transmission system elements having influence on other control areas; the coherence of transitory admissible overloads of interconnectors; and that active power and reactive power injections or withdrawals are compatible with usual operational values. Each TSO shall perform coordinated operational security analyses for at least the following time-frames: year-ahead; week-ahead, when applicable in accordance with Article 69; day-ahead; and intraday. When performing a coordinated operational security analysis, the TSO shall apply the methodology adopted pursuant to Article 75. To perform operational security analyses, each TSO shall, in the N-Situation, simulate each contingency from its contingency list established in accordance with Article 33 and verify that, in the (N-1)-situation, the operational security limits defined in accordance with Article 25 are not exceeded in its control area. Each TSO shall perform its operational security analyses using at least the common grid models established in accordance with Articles 67, 68, 70 and, where applicable, 69 and shall take into account the planned outages when carrying out those analyses. Each TSO shall share the results of its operational security analysis with at least the TSOs whose elements are included in the TSO's observability area and are affected according to that operational security analysis, in order to allow those TSOs to verify that operational security limits are respected within their control areas. Each TSO shall perform year-ahead and, where applicable, week-ahead operational security analyses in order to detect at least the following constraints: power flows and voltages exceeding operational security limits; violations of stability limits of the transmission system identified in accordance with Article 38(2) and (6); and violations of short-circuit thresholds of the transmission system. When a TSO detects a possible constraint, it shall design remedial actions in accordance with Articles 20 to 23. If remedial actions without costs are not available and the constraint is linked to the planned unavailability of some relevant assets, the constraint shall constitute an outage planning incompatibility and the TSO shall initiate outage coordination in accordance with Article 95 or 100 depending of the time of the year when this action is initiated. Each TSO shall perform day-ahead, intraday and close to real-time operational security analyses to detect possible constraints and prepare and activate the remedial actions with any other concerned TSOs and, if applicable, affected DSOs or SGUs. Each TSO shall monitor load and generation forecasts. When those forecasts indicate a significant deviation in load or generation, the TSO shall update its operational security analysis. When performing close to real-time operational security analysis in its observability area, each TSO shall use state estimation. By 12 months after entry into force of this Regulation, all TSOs shall jointly develop a proposal for a methodology for coordinating operational security analysis. That methodology shall aim at the standardisation of operational security analysis at least per synchronous area and shall include at least: methods for assessing the influence of transmission system elements and SGUs located outside of a TSO's control area in order to identify those elements included in the TSO's observability area and the contingency influence thresholds above which contingencies of those elements constitute external contingencies; principles for common risk assessment, covering at least, for the contingencies referred to in Article 33: associated probability; transitory admissible overloads; and impact of contingencies; principles for assessing and dealing with uncertainties of generation and load, taking into account a reliability margin in line with Article 22 of Regulation (EU) 2015/1222; requirements on coordination and information exchange between regional security coordinators in relation to the tasks listed in Article 77(3); role of ENTSO for Electricity in the governance of common tools, data quality rules improvement, monitoring of the methodology for coordinated operational security analysis and of the common provisions for regional operational security coordination in each capacity calculation region. The methods referred to in point (a) of paragraph 1 shall allow the identification of all elements of a TSO's observability area, being grid elements of other TSOs or transmission-connected DSOs, power generating modules or demand facilities. Those methods shall take into account the following transmission system elements and SGUs' characteristics: connectivity status or electrical values (such as voltages, power flows, rotor angle) which significantly influence the accuracy of the results of the state estimation for the TSO's control area, above common thresholds; connectivity status or electrical values (such as voltages, power flows, rotor angle) which significantly influence the accuracy of the results of the TSO's operational security analysis, above common thresholds; and requirement to ensure an adequate representation of the connected elements in the TSO's observability area. The values referred to in points (a) and (b) of paragraph 2 shall be determined through situations representative of the various conditions which can be expected, characterised by variables such as generation level and pattern, level of electricity exchanges across the borders and asset outages. The methods referred to in point (a) of paragraph 1 shall allow the identification of all elements of a TSO's external contingency list with the following characteristics: each element has an influence factor on electrical values, such as voltages, power flows, rotor angle, in the TSO's control area greater than common contingency influence thresholds, meaning that the outage of this element can significantly influence the results of the TSO's contingency analysis; the choice of the contingency influence thresholds shall minimize the risk that the occurrence of a contingency identified in another TSO's control area and not in the TSO's external contingency list could lead to a TSO's system behaviour deemed not acceptable for any element of its internal contingency list, such as an emergency state; the assessment of such a risk shall be based on situations representative of the various conditions which can be expected, characterised by variables such as generation level and pattern, exchange levels, asset outages. The principles for common risk assessment referred to in point (b) of paragraph 1 shall set out criteria for the assessment of interconnected system security. Those criteria shall be established with reference to a harmonised level of maximum accepted risk between the different TSO's security analysis. Those principles shall refer to: the consistency in the definition of exceptional contingencies; the evaluation of the probability and impact of exceptional contingencies; and the consideration of exceptional contingencies in a TSO's contingency list when their probability exceeds a common threshold. The principles for assessing and dealing with uncertainties referred to in point (c) of paragraph 1 shall provide for keeping the impact of the uncertainties regarding generation or demand below an acceptable and harmonised maximum level for each TSO's operational security analysis. Those principles shall set out: harmonised conditions where one TSO shall update its operational security analysis. The conditions shall take into account relevant aspects such as the time horizon of the generation and demand forecasts, the level of change of forecasted values within the TSO's control area or within the control area of other TSOs, location of generation and demand, the previous results of its operational security analysis; and minimum frequency of generation and demand forecast updates, depending on their variability and the installed capacity of non-dispatchable generation. By 3 months after the approval of the methodology for coordinating operational security analysis in Article 75(1), all TSOs of each capacity calculation region shall jointly develop a proposal for common provisions for regional operational security coordination, to be applied by the regional security coordinators and the TSOs of the capacity calculation region. The proposal shall respect the methodologies for coordinating operational security analysis developed in accordance with Article 75(1) and complement where necessary the methodologies developed in accordance with Articles 35 and 74 of Regulation (EU) 2015/1222. The proposal shall determine: conditions and frequency of intraday coordination of operational security analysis and updates to the common grid model by the regional security coordinator; the methodology for the preparation of remedial actions managed in a coordinated way, considering their cross-border relevance as determined in accordance with Article 35 of Regulation (EU) 2015/1222, taking into account the requirements in Articles 20 to 23 and determining at least: the procedure for exchanging the information of the available remedial actions, between relevant TSOs and the regional security coordinator; the classification of constraints and the remedial actions in accordance with Article 22; the identification of the most effective and economically efficient remedial actions in case of operational security violations referred to in Article 22; the preparation and activation of remedial actions in accordance with Article 23(2); the sharing of the costs of remedial actions referred to in Article 22, complementing where necessary the common methodology developed in accordance with Article 74 of Regulation (EU) 2015/1222. As a general principle, costs of non-cross-border relevant congestions shall be borne by the TSO responsible for the given control area and costs of relieving cross-border-relevant congestions shall be covered by TSOs responsible for the control areas in proportion to the aggravating impact of energy exchange between given control areas on the congested grid element. In determining whether congestion have cross-border relevance, the TSOs shall take into account the congestion that would appear in the absence of energy exchanges between control areas. The proposal of all TSOs of a capacity calculation region for common provisions for regional operational security coordination pursuant to Article 76(1) shall also include common provisions concerning the organisation of regional operational security coordination, including at least: the appointment of the regional security coordinator(s) that will perform the tasks in paragraph 3 for that capacity calculation region; rules concerning the governance and operation of regional security coordinator(s), ensuring equitable treatment of all member TSOs; where the TSOs propose to appoint more than one regional security coordinator in accordance with subparagraph (a): a proposal for a coherent allocation of the tasks between the regional security coordinators who will be active in that capacity calculation region. The proposal shall take full account of the need to coordinate the different tasks allocated to the regional security coordinators; an assessment demonstrating that the proposed setup of regional security coordinators and allocation of tasks is efficient, effective and consistent with the regional coordinated capacity calculation established pursuant to Articles 20 and 21 of Regulation (EU) 2015/1222; an effective coordination and decision making process to resolve conflicting positions between regional security coordinators within the capacity calculation region. When developing the proposal for common provisions concerning the organisation of regional operational security coordination in paragraph 1, the following requirements shall be met: each TSO shall be covered by at least one regional security coordinator; all TSOs shall ensure that the total number of regional security coordinators across the Union is not higher than six. The TSOs of each capacity calculation region shall propose the delegation of the following tasks in accordance with paragraph 1: regional operational security coordination in accordance with Article 78 in order to support TSOs fulfil their obligations for the year-ahead, day-ahead and intraday time-frames in Article 34(3) and Articles 72 and 74; building of common grid model in accordance with Article 79; regional outage coordination in accordance with Article 80, in order to support TSOs fulfil their obligations in Articles 98 and 100; regional adequacy assessment in accordance with Article 81 in order to support TSOs fulfil their obligations under Article 107. In executing its tasks, a regional security coordinator shall take account of data covering at least all capacity calculation regions for which it has been allocated tasks, including the observability areas of all TSOs in those capacity calculation regions.. All regional security coordinators shall coordinate the execution of their tasks in order to facilitate the fulfilment of the objectives of this Regulation. All regional security coordinators shall ensure the harmonization of processes and, where duplication is not justified by reasons of efficiency or by the need to ensure continuity of service, the creation of joint tools to ensure efficient cooperation and coordination between the regional security coordinators. Each TSO shall provide the regional security coordinator with all the information and data required to perform the coordinated regional operational security assessment, including at least: the updated contingency list, established according to the criteria defined in the methodology for coordinating operational security analysis adopted in accordance with Article 75(1); the updated list of possible remedial actions, among the categories listed in Article 22, and their anticipated costs provided in accordance with Article 35 of Regulation (EU) 2015/1222 if a remedial action includes redispatching or countertrading, aimed at contributing to relieve any constraint identified in the region; and the operational security limits established in accordance with Article 25. Each regional security coordinator shall: perform the coordinated regional operational security assessment in accordance with Article 76 on the basis of the common grid models established in accordance with Article 79, the contingency list and the operational security limits provided by each TSOs in paragraph 1. It shall deliver the results of the coordinated regional operational security assessment at least to all TSOs of the capacity calculation region. Where it detects a constraint, it shall recommend to the relevant TSOs the most effective and economically efficient remedial actions and may also recommend remedial actions other than those provided by the TSOs. This recommendation for remedial actions shall be accompanied by explanations as to its rationale; coordinate the preparation of remedial actions with and among TSOs in accordance with Article 76(1)(b), to enable TSOs achieve a coordinated activation of remedial actions in real-time. When performing the coordinated regional operational security assessment and identifying the appropriate remedial actions, each regional security coordinator shall coordinate with other regional security coordinators. When a TSO receives from the relevant regional security coordinator the results of the coordinated regional operational security assessment with a proposal for a remedial action, it shall evaluate the recommended remedial action for the elements involved in that remedial action and located in its control area. In so doing, it shall apply the provisions of Article 20. The TSO shall decide whether to implement the recommended remedial action. Where it decides not to implement the recommended remedial action, it shall provide an explanation for this decision to the RSC. Where the TSO decides to implement the recommended remedial action, it shall apply this action for the elements located in its control area provided that it is compatible with real-time conditions. Each regional security coordinator shall check the quality of the individual grid models in order to contribute to building the common grid model for each mentioned time-frame in accordance with the methodologies referred to in Articles 67(1) and 70(1). Each TSO shall make available to its regional security coordinator the individual grid model necessary to build the common grid model for each time-frame through the ENTSO for Electricity operational planning data environment. Where necessary, each regional security coordinator shall request the TSOs concerned to correct their individual grid models in order to achieve their conformity with the quality controls and for their improvement. Each TSO shall correct its individual grid models, after verifying the need for correction if applicable, on the basis of the requests of the regional security coordinator or another TSO. In accordance with the methodologies referred to in Articles 67(1) and 70(1), and in accordance with Article 28 of Regulation (EU) 2015/1222, a regional security coordinator shall be appointed by all TSOs to build the common grid model for each time-frame and store it on the ENTSO for Electricity operational planning data environment. The outage coordination regions within which the TSOs shall proceed to outage coordination shall be at least equal to the capacity calculation regions. The TSOs of two or more outage coordination regions can agree to merge them into one unique outage coordination region. In that case they shall identify the regional security coordinator performing the tasks referred to in Article 77(3). Each TSO shall provide the regional security coordinator with the information necessary to detect and solve regional outage planning incompatibilities, including at least: the availability plans of its internal relevant assets, stored on the ENTSO for Electricity operational planning data environment; the most recent availability plans for all non-relevant assets of its control area which are: capable of influencing the results of the outage planning incompatibility analysis; modelled in the individual grid models which are used for the outage incompatibility assessment; scenarios on which the outage planning incompatibilities have to be investigated and used to build the corresponding common grid models derived from the common grid models for different time-frames established in accordance with Articles 67 and 79. Each regional security coordinator shall perform regional operational security analyses on the basis of the information provided by the relevant TSOs in order to detect any outage planning incompatibility. It shall provide all TSOs of the outage coordination region with a list of detected outage planning incompatibilities and the solutions it proposes to solve those outage planning incompatibilities. In performing their obligations under paragraph 4, each regional security coordinator shall coordinate its analyses with other regional security coordinators. In performing their obligations in accordance with Article 98(3) and Article 100(4)(b), all TSOs shall take into account the results of the assessment provided by the regional security coordinator in accordance with paragraph 3 and paragraph 4. Each regional security coordinator shall perform regional adequacy assessments for at least the week-ahead time-frame. Each TSO shall provide the regional security coordinator with the information necessary to perform the regional adequacy assessments referred to in paragraph 1, including: the expected total load and available resources of demand response; the availability of power generation modules; and the operational security limits. Each regional security coordinator shall perform adequacy assessments on the basis of the information provided by the relevant TSOs with the aim of detecting situations where a lack of adequacy is expected in any of the control areas or at regional level, taking into account possible cross-border exchanges and operational security limits. It shall deliver the results together with the actions it proposes to reduce risks to the TSOs of the capacity calculation region. Those actions shall include proposals for remedial actions that allow the increase of cross-border exchanges. When performing a regional adequacy assessment, each regional security coordinator shall coordinate with other regional security coordinators. Each TSO shall, with the support of the regional security coordinator for the instances specified in this Regulation, perform outage coordination in accordance with the principles of this Title in order to monitor the availability status of the relevant assets and coordinate the availability plans to ensure the operational security of the transmission system. All TSOs of an outage coordination region shall jointly develop a regional coordination operational procedure, aimed at establishing operational aspects for the implementation of the outage coordination in each region, which includes: frequency, scope and type of coordination for, at least, the year-ahead and week-ahead time-frames; provisions concerning the use of the assessments carried out by the regional security coordinator in accordance with Article 80; practical arrangements for the validation of the year-ahead relevant grid element availability plans, as required by Article 98. Each TSO shall participate in the outage coordination of its outage coordination regions and apply the regional coordination operational procedures established in accordance with paragraph 1. If outage planning incompatibilities arise between different outage coordination regions, all TSOs and regional security coordinators of those regions shall coordinate to resolve those outage planning incompatibilities. Each TSO shall provide to the other TSOs from the same outage coordination region all relevant information at its disposal on the infrastructure projects related to the transmission system, distribution systems, closed distribution systems, power generating modules, or demand facilities that may have an impact on the operation of the control area of another TSO within the outage coordination region. Each TSO shall provide the transmission-connected DSOs located in its control area with all relevant information at its disposal on the infrastructure projects related to the transmission system that may have an impact on the operation of the distribution system of these DSOs. Each TSO shall provide the transmission-connected closed-DSOs (‘CDSOs’) located in its control area with all relevant information at its disposal on the infrastructure projects related to the transmission system that may have an impact on the operation of the closed distribution system of those CDSOs. By 12 months after entry into force of this Regulation, all TSOs shall jointly develop a methodology at least per synchronous area, for assessing the relevance for the outage coordination of power generating modules, demand facilities, and grid elements located in a transmission system or in a distribution system, including closed distribution systems. The methodology referred to in paragraph 1 shall be based on qualitative and quantitative aspects that identify the impact on a TSO's control area of the availability status of either power generating modules, demand facilities, or grid elements which are located in a transmission system or in a distribution system including a closed distribution system, and which are connected directly or indirectly to another TSO's control area and in particular on: quantitative aspects based on the evaluation of changes of electrical values such as voltages, power flows, rotor angle on at least one grid element of a TSO's control area, due to the change of availability status of a potential relevant asset located in another control area. That evaluation shall take place on the basis of year-ahead common grid models; thresholds on the sensitivity of the electrical values referred to in point (a), against which to assess the relevance of an asset. Those thresholds shall be harmonised at least per synchronous area; capacity of potential relevant power generating modules or demand facilities to qualify as SGUs; qualitative aspects such as, but not limited to, the size and proximity to the borders of a control area of potential relevant power generating modules, demand facilities or grid elements; systematic relevance of all grid elements located in a transmission system or in a distribution system which connect different control areas; and systematic relevance of all critical network elements. The methodology developed pursuant to paragraph 1 shall be consistent with the methods for assessing the influence of transmission system elements and SGUs located outside of a TSO's control area established in accordance with Article 75(1)(a). By 3 months after the approval of the methodology for assessing the relevance of assets for outage coordination in Article 84(1), all TSOs of each outage coordination region shall jointly assess the relevance of power generating modules and demand facilities for outage coordination on the basis of this methodology, and establish a single list, for each outage coordination region, of relevant power generating modules and relevant demand facilities. All TSOs of an outage coordination region shall jointly make the list of relevant power generating modules and relevant demand facilities of that outage coordination region available on the ENTSO for Electricity operational planning data environment. Each TSO shall notify to its regulatory authority the list of relevant power generating modules and relevant demand facilities for each outage coordination region in which it participates. For each internal relevant asset which is a power generating module or demand facility, the TSO shall: inform the owner of the relevant power generating module or relevant demand facility about its inclusion in the list; inform DSOs about the relevant power generating modules and the relevant demand facilities which are connected to their distribution system; and inform CDSOs about the relevant power generating modules and the relevant demand facilities which are connected to their closed distribution system. Before 1 July of each calendar year, all TSOs of each outage coordination region shall jointly re-assess the relevance of power generating modules and demand facilities for outage coordination on the basis of the methodology developed in accordance with Article 84(1). Where necessary, all TSOs of each outage coordination region shall jointly decide to update the list of relevant power generating modules and relevant demand facilities of that outage coordination region before 1 August of each calendar year. All TSOs of an outage coordination region shall make the updated list of that outage coordination region available on the ENTSO for Electricity operational planning data environment. Each TSO of an outage coordination region shall inform the parties referred to in Article 85(4) about the content of the updated list. By 3 months after the approval of the methodology for assessing the relevance of assets for outage coordination in Article 84(1), all TSOs of each outage coordination region shall jointly assess, on the basis of this methodology, the relevance for the outage coordination of grid elements located in a transmission system or in a distribution system including a closed distribution system and shall establish a single list, per outage coordination region, of relevant grid elements. The list of relevant grid elements of an outage coordination region shall contain all grid elements of a transmission system or a distribution system, including a closed distribution system located in that outage coordination region, which are identified as relevant by application of the methodology established pursuant to Article 84(1). All TSOs of an outage coordination region shall jointly make the list of relevant grid elements available on the ENTSO for Electricity operational planning data environment. Each TSO shall notify to its regulatory authority the list of relevant grid elements for each outage coordination region in which it participates. For each internal relevant asset which is a grid element, the TSO shall: inform the owner of the relevant grid element about its inclusion in the list; inform DSOs about the relevant grid elements which are connected to their distribution system; and inform CDSOs about the relevant grid elements which are connected to their closed distribution system. Before 1 July of each calendar year, all TSOs of each outage coordination region shall jointly re-assess, on the basis of the methodology established pursuant to Article 84(1), the relevance for the outage coordination of grid elements located in a transmission system or a distribution system including a closed distribution system. Where necessary, all TSOs of an outage coordination region shall jointly decide to update the list of relevant grid elements of that outage coordination region before 1 August of each calendar year. All TSOs of an outage coordination region shall make the updated list available on the ENTSO for Electricity operational planning data environment. Each TSO of an outage coordination region shall inform the parties referred to in Article 85(4) about the content of the updated list. Each TSO shall act as the outage planning agent for each relevant grid element it operates. For all other relevant assets, the owner shall appoint, or act as, the outage planning agent for the concerned relevant asset and shall inform its TSO about that appointment. Each TSO shall coordinate with the DSO the outage planning of internal relevant assets connected to its distribution system. Each TSO shall coordinate with the CDSO the outage planning of internal relevant assets connected to its closed distribution system. All TSOs within a synchronous area may jointly agree to adopt and implement a time-frame for the year-ahead outage coordination that deviates from the time-frame defined in Articles 94, 97 and 99, provided that the outage coordination of other synchronous areas is not impacted. The availability status of a relevant asset shall be one of the following: ‘available’ where the relevant asset is capable of and ready for providing service regardless of whether it is or it is not in operation; ‘unavailable’ where the relevant asset is not capable of or ready for providing service; ‘testing’ where the capability of the relevant asset for providing service is being tested. The ‘testing’ status shall only apply in case of a potential impact on the transmission system and for the following time periods: between first connection and final commissioning of the relevant asset; and directly following maintenance of the relevant asset. The availability plans shall contain at least the following information: the reason for the ‘unavailable’ status of a relevant asset; where such conditions are identified, the conditions to be fulfilled before applying the ‘unavailable’ status of a relevant asset in real-time; the time required to restore a relevant asset back to service where necessary in order to maintain operational security. The availability status for each relevant asset in the year-ahead time-frame shall be provided with daily resolution. When generation schedules and consumption schedules are submitted to the TSO pursuant to Article 111, the time resolution of the availability statuses shall be consistent with those schedules. By 2 years before the start of any year-ahead outage coordination, each TSO shall assess the corresponding indicative availability plans for internal relevant assets, provided by the outage planning agents in accordance with Articles 4, 7 and 15 of Regulation (EU) No 543/2013, and shall provide its preliminary comments including any detected outage planning incompatibilities, to all affected outage planning agents. Each TSO shall carry out the assessment concerning the indicative availability plans for internal relevant assets referred to in paragraph 1 every year until the start of the year-ahead outage coordination. Before 1 August of each calendar year, an outage planning agent other than a TSO taking part in an outage coordination region, a DSO or a CDSO, shall submit to the TSO(s) taking part in an outage coordination region, and where relevant to the DSO(s) or CDSO(s), an availability plan covering the following calendar year for each of its relevant assets. The TSO(s) referred to in paragraph 1 shall endeavour to examine the requests for amendment of an availability plan when received. Where this is not possible, it shall examine the requests for amendment of an availability plan after the year-ahead outage coordination has been finalised. The TSO(s) referred to in paragraph 1 shall examine the requests for amendment of an availability plan after the year-ahead outage coordination has been finalised: following the order in which the requests were received; and applying the procedure established in accordance with Article 100. Each TSO shall assess on a year-ahead time-frame whether outage planning incompatibilities arise from the availability plans received pursuant to Article 94. When a TSO detects outage planning incompatibilities, it shall implement the following process: inform each affected outage planning agent of the conditions it shall fulfil to mitigate the detected outage planning incompatibilities; the TSO may request that one or more outage planning agents submit an alternative availability plan fulfilling the conditions referred to in point (a); and the TSO shall repeat the assessment pursuant to paragraph 1 to determine whether any outage planning incompatibilities remain. Following a TSO's request in accordance with point (b) of paragraph 2, if the outage planning agent fails to submit an alternative availability plan aimed at mitigating all outage planning incompatibilities, the TSO shall develop an alternative availability plan which shall: take into account the impact reported by the affected outage planning agents as well as the DSO or CDSO where relevant; limit the changes in the alternative availability plan to what is strictly necessary to mitigate the outage planning incompatibilities; and notify its regulatory authority, the affected DSOs and CDSOs if any, and the affected outage planning agents about the alternative availability plan, including the reasons for developing it, as well as the impact reported by the affected outage planning agents and, where relevant, the DSOs or CDSOs. Each TSO shall plan the availability status of relevant grid elements interconnecting different control areas for which it acts as an outage planning agent in coordination with the TSOs of the same outage coordination region. Each TSO, DSO and CDSO shall plan the availability status of the relevant grid elements for which they perform duties of outage planning agents and that are not interconnecting different control areas, using as a basis the availability plans developed in accordance with paragraph 1. When establishing the availability status of relevant grid elements in accordance with paragraphs 1 and 2, the TSO, DSO and CDSO shall: minimize the impact on the market while preserving operational security; and use as a basis the availability plans submitted and developed in accordance with Article 94. Where a TSO detects an outage planning incompatibility, the TSO shall be entitled to propose a change to the availability plans of the internal relevant assets for which the outage planning agent is neither a TSO taking part in an outage coordination region, nor a DSO or a CDSO and shall identify a solution in coordination with the outage planning agents, DSOs and CDSOs concerned, using the means at its disposal. Where the ‘unavailable’ status of a relevant grid element has not been planned after taking the measures in paragraph 4 and the absence of such planning would threaten operational security, the TSO shall: take the necessary actions to plan the ‘unavailable’ status while ensuring operational security, taking into account the impact reported to the TSO by affected outage planning agents; notify the actions referred to in point (a) to all affected parties; and notify the relevant regulatory authorities, the affected DSOs or CDSOs if any and the affected outage planning agents of the actions taken, including the rationale for such actions, the impact reported by affected outage planning agents and the DSOs or CDSOs where relevant. Each TSO shall make available on the ENTSO for Electricity operational planning data environment all information at its disposal about grid-related conditions to be fulfilled and remedial actions to be prepared and activated before executing the ‘unavailable’ or ‘testing’ availability status of a relevant grid element. Before 1 November of each calendar year, each TSO shall provide to all other TSOs, via the ENTSO for Electricity operational planning data environment, the preliminary year-ahead availability plans for the following calendar year for all the internal relevant assets. Before 1 November of each calendar year, for each internal relevant asset located in a distribution system, the TSO shall provide the DSO with the preliminary year-ahead availability plan. Before 1 November of each calendar year, for every internal relevant asset located in a closed distribution system, the TSO shall provide the CDSO with the preliminary year-ahead availability plan. Each TSO shall analyse whether any outage planning incompatibility arises when taking into account all the preliminary year-ahead availability plans. In the absence of outage planning incompatibilities, all TSOs of an outage coordination region shall jointly validate the year-ahead availability plans for all relevant assets of that outage coordination region. If a TSO detects an outage planning incompatibility, the involved TSOs of the outage coordination region(s) concerned shall jointly identify a solution in coordination with the concerned outage planning agents, DSOs and CDSOs, using the means at their disposal, while respecting to the extent possible the availability plans submitted by outage planning agents, which are neither a TSO taking part in an outage coordination region, nor a DSO or a CDSO, and developed in accordance with Articles 95 and 96. Where a solution is identified, all TSOs of the concerned outage coordination region(s) shall update and validate the year-ahead availability plans for all relevant assets. Where no solution is found for an outage planning incompatibility each concerned TSO, subject to approval by the competent regulatory authority where the Member State so provides, shall: force to ‘available’ status all the ‘unavailable’ or ‘testing’ statuses for the relevant assets involved in an outage planning incompatibility during the period concerned; and notify to the relevant regulatory authorities, the affected DSOs or CDSOs, if any, and the affected outage planning agents of the actions taken including the rationale for such actions, the impact reported by affected outage planning agents and the DSOs or CDSOs where relevant. All TSOs of the concerned outage coordination regions shall consequently update and validate the year-ahead availability plans for all relevant assets. Before 1 December of each calendar year, each TSO shall: finalise the year-ahead outage coordination of internal relevant assets; and finalise the year-ahead availability plans for internal relevant assets and store them on the ENTSO for Electricity operational planning data environment. Before 1 December of each calendar year, the TSO shall provide to its outage planning agent the final year-ahead availability plan of each internal relevant asset. Before 1 December of each calendar year, the TSO shall provide to the relevant DSO the final year-ahead availability plan for each internal relevant asset located in a distribution system. Before 1 December of each calendar year, the TSO shall provide to the relevant CDSO the final year-ahead availability plan for each internal relevant asset located in a closed distribution system. An outage planning agent shall be able to launch a procedure for the amendment of the final year-ahead availability plan in the time between the finalisation of the year-ahead outage coordination and its real-time execution. The outage planning agent which is not a TSO taking part in an outage coordination region shall be able to submit to the relevant TSO(s) a request for amendment of the final year-ahead availability plan of the relevant assets under its responsibility. In case of a request for amendment pursuant to paragraph 2, the following procedure shall be applied: the recipient TSO shall acknowledge the request and assess as soon as reasonably practicable whether the amendment leads to outage planning incompatibilities; where outage planning incompatibilities are detected, the involved TSOs of the outage coordination region shall jointly identify a solution in coordination with the outage planning agents concerned and, if relevant, the DSOs and CDSOs, using the means at their disposal; where no outage planning incompatibility has been detected or if no outage planning incompatibility remains, the recipient TSO shall validate the requested amendment, and the TSOs concerned shall consequently notify all affected parties and update the final year-ahead availability plan on the ENTSO for Electricity operational planning data environment; and where no solution is found for outage planning incompatibilities the recipient TSO shall reject the requested amendment. When a TSO taking part in an outage coordination region intends to amend the final year-ahead availability plan of a relevant asset for which it acts as the outage planning agent, it shall initiate the following procedure: the requesting TSO shall prepare a proposal for amendment to the year-ahead availability plan, including an assessment of whether it could lead to outage planning incompatibilities and shall submit its proposal to all other TSOs of its outage coordination region(s); where outage planning incompatibilities are detected, the involved TSOs of the outage coordination region shall jointly identify a solution in coordination with the concerned outage planning agents and, if relevant, the DSOs and the CDSOs, using the means at their disposal; where no outage planning incompatibility has been detected or if a solution to an outage planning incompatibility is found, the concerned TSOs shall validate the requested amendment and consequently they shall notify all affected parties and update the final year-ahead availability plan on the ENTSO for Electricity operational planning data environment; where no solution to outage planning incompatibilities are found, the requesting TSO shall retract the procedure for amendment. The outage planning agent of a relevant asset the availability status of which has been declared as ‘testing’ shall provide the TSO, and, if connected to a distribution system, including closed distribution systems, the DSO or the CDSO within 1 month before the start of the ‘testing’ status, with: a detailed test plan; an indicative generation or consumption schedule if the concerned relevant asset is a relevant power generating module or a relevant demand facility; and changes to the topology of the transmission system or distribution system if the concerned relevant asset is a relevant grid element. The outage planning agent shall update the information referred to in paragraph 1 as soon as it is subject to any change. The TSO of a relevant asset the availability status of which has been declared as ‘testing’ shall provide the information received in accordance with paragraph 1 to all other TSOs of its outage coordination region(s), upon their request. Where the relevant asset referred to in paragraph 1 is a relevant grid element interconnecting two or more control areas, the TSOs of the concerned control areas shall agree on the information to be provided pursuant to paragraph 1. Each TSO shall develop a procedure to address the case where a forced outage would endanger its operational security. The procedure shall allow the TSO to ensure that the ‘available’ or ‘unavailable’ status of other relevant assets in its control area can be changed to ‘unavailable’ or ‘available’ respectively. The TSO shall follow the procedure referred to in paragraph 1 only where no agreement is reached with outage planning agents regarding solutions to forced outages. The TSO shall notify the regulatory authority accordingly. When undertaking the procedure, the TSO shall respect, to the extent possible, the technical limits of the relevant assets. An outage planning agent shall notify the forced outage of one or more of its relevant assets to the TSO and, if connected to a distribution system or to a closed distribution system, the DSO or the CDSO respectively, as soon as possible following the start of the forced outage. When notifying the forced outage, the outage planning agent shall provide the following information: the reason for the forced outage; the expected duration of the forced outage; and where applicable, the impact of the forced outage on the availability status of other relevant assets for which it is the outage planning agent. When the TSO detects that one or several forced outages referred to in paragraph 1 could lead the transmission system out of the normal state, it shall inform the affected outage planning agent(s) about the deadline at which operational security can no longer be maintained unless their relevant asset(s) in forced outage returns to ‘available’ status. The outage planning agents shall inform the TSO whether they are capable of respecting that deadline and shall provide reasoned justifications where they are unable to respect that deadline. Following any amendments to the availability plan due to forced outages and in accordance with the time-frame established in Articles 7, 10 and 15 of Regulation (EU) No 543/2013, the concerned TSO shall update the ENTSO for Electricity operational planning data environment with the most recent information. Each power generating facility owner shall ensure that all relevant power generating modules it owns and which are declared ‘available’ are ready to produce electricity pursuant to their declared technical capabilities when necessary to maintain operational security, except in case of forced outages. Each power generating facility owner shall ensure that all relevant power generating modules it owns and which are declared ‘unavailable’ do not produce electricity. Each demand facility owner shall ensure that all relevant demand facilities it owns and which are declared ‘unavailable’ do not consume electricity. Each relevant grid element owner shall ensure that all relevant grid elements it owns and which are declared ‘available’ are ready to transport electricity pursuant to their declared technical capabilities when necessary to maintain operational security, except in case of forced outages. Each relevant grid element owner shall ensure that all relevant grid elements it owns and which are declared ‘unavailable’ do not transport electricity. Where specific grid-related conditions apply for the execution of the ‘unavailable’ or ‘testing’ status of a relevant grid element in accordance with Article 96(6), the TSO, DSO or CDSO concerned shall assess the fulfilment of those conditions before the execution of that status. If those conditions are not fulfilled, it shall instruct the relevant grid element owner to not execute the ‘unavailable’ or ‘testing’ status or a part thereof. Where a TSO identifies that executing an ‘unavailable’ or ‘testing’ status of a relevant asset leads or could lead the transmission system out of normal state, it shall instruct the owner of the relevant asset when it is connected to the transmission system, or the DSO or CDSO if connected to a distribution system or to a closed distribution system, to delay the execution of that ‘unavailable’ or ‘testing’ status of that relevant asset according to its instructions and to the extent possible, while respecting the technical and safety limits. Each TSO shall make any forecast used for control area adequacy analyses pursuant to Articles 105 and 107 available to all other TSOs through the ENTSO for Electricity operational planning data environment. Each TSO shall perform control area adequacy analysis by assessing the possibility for the sum of generation within its control area and cross-border import capabilities to meet the total load within its control area under various operational scenarios, taking into account the required level of active power reserves set out in Articles 118 and 119. When performing a control area adequacy analysis pursuant to paragraph 1, each TSO shall: use the latest availability plans and the latest available data for: the capabilities of power generating modules provided pursuant to Article 43(5) and Articles 45 and 51; cross-zonal capacity; possible demand response provided pursuant to Articles 52 and 53; take into account the contributions of generation from renewable energy sources and load; assess the probability and expected duration of an absence of adequacy and the expected energy not supplied as a result of such absence. As soon as possible, following the assessment of an absence of adequacy within its control area, each TSO shall notify the absence to its regulatory authority or when explicitly foreseen in national law, another competent authority, and where applicable, any affected party. As soon as possible, following the assessment of an absence of adequacy within its control area, each TSO shall inform all TSOs through the ENTSO for Electricity operational planning data environment. Each TSO shall contribute to the pan-European annual summer and winter generation adequacy outlooks applying the methodology adopted by ENTSO for Electricity referred to in Article 8(3)(f) of Regulation (EC) No 714/2009. Twice a year, each TSO shall perform a control area adequacy analysis for the following summer and winter respectively, taking into account pan-European scenarios consistent with the pan-European annual summer and winter generation adequacy outlooks. Each TSO shall update its control area adequacy analyses if it detects any probable changes to the availability status of power generating modules, load estimations, renewable energy sources estimations or cross zonal capacities that could significantly affect the expected adequacy. Each TSO shall perform a control area adequacy analysis in a day-ahead and intraday time-frame on the basis of: schedules referred to in Article 111; forecasted load; forecasted generation from renewable energy sources; active power reserves in accordance with the data provided pursuant to Article 46(1)(a); control area import and export capacities consistent with cross-zonal capacities calculated where applicable in accordance with Article 14 of Regulation (EU) 2015/1222; capabilities of power generating modules in accordance with the data provided pursuant to Article 43(4) and Articles 45 and 51 and their availability statuses; and capabilities of demand facilities with demand response in accordance with the data provided pursuant to Articles 52 and 53 and their availability statuses. Each TSO shall evaluate: the minimum level of import and the maximum level of export compatible with its control area adequacy; the expected duration of a potential absence of adequacy; and the amount of energy not supplied in the absence of adequacy. Where, following the analysis in paragraph 1, adequacy is not fulfilled, each TSO shall notify the absence of adequacy to its regulatory authority or other competent authority. The TSO shall provide its regulatory authority or other competent authority with an analysis of the causes of the absence of adequacy and propose mitigating actions. Each TSO shall monitor the availability of ancillary services. With regard to active power and reactive power services, and in coordination with other TSOs where appropriate, each TSO shall: design, set up and manage the procurement of ancillary services; monitor, on the basis of data provided pursuant to Title 2 of Part II, whether the level and location of available ancillary services allows ensuring operational security; and use all available economically efficient and feasible means to procure the necessary level of ancillary services. Each TSO shall publish the levels of reserve capacity necessary to maintain operational security. Each TSO shall communicate the available level of active power reserves to other TSOs upon request. For each operational planning time-frame, each TSO shall assess, against their forecasts, whether its available reactive power ancillary services are sufficient to maintain the operational security of the transmission system. In order to increase the efficiency of operation of its transmission system elements, each TSO shall monitor: the available reactive power capacities of power generating facilities; the available reactive power capacities of transmission-connected demand facilities; the available reactive power capacities of DSOs; the available transmission-connected equipment dedicated to providing reactive power; and the ratios of active power and reactive power at the interface between the transmission system and transmission-connected distribution systems. Where the level of reactive power ancillary services is not sufficient for maintaining operational security, each TSO shall: inform neighbouring TSOs; and prepare and activate remedial actions pursuant to Article 23. When establishing a scheduling process TSOs shall take into account and complement where necessary the operational conditions of the generation and load data methodology developed in accordance with Article 16 of Regulation (EU) 2015/1222. Where a bidding zone covers only one control area, the geographical scope of the scheduling area is equal to the bidding zone. Where a control area covers several bidding zones, the geographical scope of the scheduling area is equal to the bidding zone. Where a bidding zone covers several control areas, TSOs within that bidding zone may jointly decide to operate a common scheduling process, otherwise, each control area within that bidding zone is considered a separate scheduling area. For each power generating facility and demand facility subject to requirements for scheduling set out in the national terms and conditions, the concerned owner shall appoint or act as a scheduling agent. Each market participant and shipping agent, subject to requirements for scheduling set out in the national terms and conditions, shall appoint or act as a scheduling agent. Each TSO operating a scheduling area shall establish arrangements necessary to process the schedules provided by scheduling agents. Where a scheduling area covers more than one control area, the TSOs responsible for the control areas shall agree about which TSO shall operate the scheduling area. Each scheduling agent, except scheduling agents of shipping agents, shall submit to the TSO operating the scheduling area, if requested by the TSO, and, where applicable, to third party, the following schedules: generation schedules; consumption schedules; internal commercial trade schedules; and external commercial trade schedules. Each scheduling agent of a shipping agent or, where applicable, a central counterparty shall submit to the TSO operating a scheduling area covered by market coupling, if requested by the concerned TSO, and where applicable to third party, the following schedules: external commercial trade schedules as: multilateral exchanges between the scheduling area and a group of other scheduling areas; bilateral exchanges between the scheduling area and another scheduling area; internal commercial trade schedules between the shipping agent and central counter parties; internal commercial trade schedules between the shipping agent and other shipping agents. Each TSO operating a scheduling area shall check whether the generation, consumption, external commercial trade schedules and external TSO schedules in its scheduling area are in sum balanced. For external TSO schedules, each TSO shall agree on the values of the schedule with the respective TSO. In the absence of an agreement, the lower value shall apply. For bilateral exchanges between two scheduling areas, each TSO shall agree on the external commercial trade schedules with the respective TSO. In the absence of an agreement about the values of the commercial trade schedules, the lower value shall apply. All TSOs operating scheduling areas shall verify that all aggregated netted external schedules between all scheduling areas within the synchronous area are balanced. If a mismatch occurs and the TSOs do not agree on the values of the aggregated netted external schedules, the lower values shall apply. Each scheduling agent of a shipping agent or, where applicable, a central counterparty shall provide TSOs, upon their request, with the values of external commercial trade schedules of each scheduling area involved in market coupling in the form of aggregated netted external schedules. Each scheduled exchange calculator shall provide to TSOs, upon their request, with the values of scheduled exchanges related to the scheduling areas involved in the market coupling in the form of aggregated netted external schedules, including bilateral exchanges between two scheduling areas. At the request of another TSO, the requested TSO shall calculate and provide: aggregated netted external schedules; and netted area AC position, where the scheduling area is interconnected to other scheduling areas via AC transmission links. When required for the creation of common grid models, in accordance with Article 70(1), each TSO operating a scheduling area shall provide any requesting TSO with: generation schedules; and consumption schedules. By 24 months after entry into force of this Regulation, ENTSO for Electricity shall, pursuant to Articles 115, 116 and 117, implement and operate an ENTSO for Electricity operational planning data environment for the storage, exchange and management of all relevant information. By 6 months after entry into force of this Regulation, all TSOs shall define a harmonised data format for data exchange, which shall be an integral part of the ENTSO for Electricity operational planning data environment. All TSOs and regional security coordinators shall have access to all information contained on the ENTSO for Electricity operational planning data environment. Until the ENTSO for Electricity operational planning data environment is implemented, all TSOs may exchange relevant data among themselves and regional security coordinators. ENTSO for Electricity shall prepare a business continuity plan to be applied in case of unavailability of its operational planning data environment. The ENTSO for Electricity operational planning data environment shall store all individual grid models and related relevant information for all the relevant time-frames set out in this Regulation, in Article 14(1) of Regulation (EU) 2015/1222 and in Article 9 of Regulation (EU) 2016/1719. The information on individual grid models contained on the ENTSO for Electricity operational planning data environment shall allow for their merging into common grid models. The common grid model established for each of the time-frames shall be made available on the ENTSO for Electricity operational planning data environment. For the year-ahead time-frame, the following information shall be available on the ENTSO for Electricity operational planning data environment: year-ahead individual grid model per TSO and per scenario determined in accordance with Article 66; and year-ahead common grid model per scenario defined in accordance with Article 67. For the day-ahead and intraday time-frames, the following information shall be available on the ENTSO for Electricity operational planning data environment: day-ahead and intraday individual grid models per TSO and according to the time resolution defined pursuant to Article 70(1); scheduled exchanges at the relevant time instances per scheduling area or per scheduling area border, whichever is deemed relevant by the TSOs, and per HVDC system linking scheduling areas; day-ahead and intraday common grid models according to the time resolution defined pursuant to Article 70(1); and a list of prepared and agreed remedial actions identified to cope with constraints having cross-border relevance. The ENTSO for Electricity operational planning data environment shall contain a module for the storage and exchange of all relevant information for outage coordination. The information referred to in paragraph 1 shall include at least availability status of relevant assets and the information about availability plans referred to in Article 92. The ENTSO for Electricity operational planning data environment shall contain a module for the storage and exchange of all relevant information for performing a coordinated adequacy analysis. The information referred to in paragraph 1 shall include at least: the season-ahead system adequacy data provided by each TSO; the season-ahead pan-European system adequacy analysis report; forecasts used for adequacy in line with Article 104; and information about a lack of adequacy in line with Article 105(4).

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Source: EUR-Lex (Cellar) · retrieved 2026-11-04 · Text as adopted (Official Journal); later amendments are not incorporated in this text.