TITLE 1 — DATA FOR OPERATIONAL SECURITY ANALYSIS IN OPERATIONAL PLANNING
General provisions regarding individual and common grid models
1. 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):
(a)
year-ahead, in accordance with Articles 66, 67 and 68;
(b)
where applicable, week-ahead, in accordance with Article 69;
(c)
day-ahead, in accordance with Article 70; and
(d)
intraday, in accordance with Article 70.
2. The individual grid models shall include the structural information and data set out in Article 41.
3. 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).
Year-ahead scenarios
1. 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:
(a)
electricity demand;
(b)
the conditions related to the contribution of renewable energy sources;
(c)
determined import/export positions, including agreed reference values allowing the merging task;
(d)
the generation pattern, with a fully available production park;
(e)
the year-ahead grid development.
2. When developing the common list of scenarios, TSOs shall take into account the following elements:
(a)
the typical cross-border exchange patterns for different levels of consumption and of renewable energy sources and conventional generation;
(b)
the probability of occurrence of the scenarios;
(c)
the potential deviations from operational security limits for each scenario;
(d)
the amount of power generated and consumed by the power generating facilities and demand facilities connected to distribution systems.
3. Where TSOs do not succeed in establishing the common list of scenarios referred to in paragraph 1, they shall use the following default scenarios:
(a)
Winter Peak, 3rd Wednesday of January current year, 10:30 CET;
(b)
Winter Valley, 2nd Sunday of January current year, 03:30 CET;
(c)
Spring Peak, 3rd Wednesday of April current year, 10:30 CET;
(d)
Spring Valley, 2nd Sunday of April current year, 03:30 CET;
(e)
Summer Peak, 3rd Wednesday of July previous year, 10:30 CET;
(f)
Summer Valley, 2nd Sunday of July previous year, 03:30 CET;
(g)
Autumn Peak, 3rd Wednesday of October previous year, 10:30 CET;
(h)
Autumn Valley, 2nd Sunday of October previous year, 03:30 CET.
4. 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.
Year-ahead individual grid models
1. 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).
2. When defining its year-ahead individual grid model, each TSO shall:
(a)
agree with the neighbouring TSOs upon the estimated power flow on HVDC systems linking their control areas;
(b)
balance for each scenario the sum of:
(i)
net exchanges on AC lines;
(ii)
estimated power flows on HVDC systems;
(iii)
load, including an estimation of losses; and
(iv)
generation.
3. 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:
(a)
be consistent with the structural data provided in accordance with the requirements of Articles 41, 43, 45 and 48;
(b)
be consistent with the scenarios developed in accordance with Article 65; and
(c)
distinguish the type of primary energy source.
Year-ahead common grid models
1. 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:
(a)
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;
(b)
quality control of the individual and common grid models to be implemented in order to ensure their completeness and consistency; and
(c)
correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (b).
2. 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.
Updates of year-ahead individual and common grid models
1. 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.
2. 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).
Week-ahead individual and common grid models
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).
2. 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.
3. 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.
Methodology for building day-ahead and intraday common grid models
1. 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:
(a)
definition of timestamps;
(b)
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;
(c)
quality control of individual grid models and the common grid model to be implemented to ensure their completeness and consistency;
(d)
correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (c); and
(e)
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.
2. 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.
3. When creating the day-ahead or intraday individual grid models referred to in paragraph 2, each TSO shall include:
(a)
up-to-date load and generation forecasts;
(b)
the available results of the day-ahead and intraday market processes;
(c)
the available results of the scheduling tasks described in Title 6 of Part III;
(d)
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;
(e)
up-to-date topology of the transmission system.
4. 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.
5. 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).
6. 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.
Quality control for grid models
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:
(a)
the coherence of the connection status of interconnectors;
(b)
that voltage values are within the usual operational values for those transmission system elements having influence on other control areas;
(c)
the coherence of transitory admissible overloads of interconnectors; and
(d)
that active power and reactive power injections or withdrawals are compatible with usual operational values.
TITLE 2 — OPERATIONAL SECURITY ANALYSIS
Operational security analysis in operational planning
1. Each TSO shall perform coordinated operational security analyses for at least the following time-frames:
(a)
year-ahead;
(b)
week-ahead, when applicable in accordance with Article 69;
(c)
day-ahead; and
(d)
intraday.
2. When performing a coordinated operational security analysis, the TSO shall apply the methodology adopted pursuant to Article 75.
3. 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.
4. 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.
5. 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.
Year-ahead up to and including week-ahead operational security analysis
1. Each TSO shall perform year-ahead and, where applicable, week-ahead operational security analyses in order to detect at least the following constraints:
(a)
power flows and voltages exceeding operational security limits;
(b)
violations of stability limits of the transmission system identified in accordance with Article 38(2) and (6); and
(c)
violations of short-circuit thresholds of the transmission system.
2. 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.
Day-ahead, intraday and close to real-time operational security analysis
1. 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.
2. 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.
3. When performing close to real-time operational security analysis in its observability area, each TSO shall use state estimation.
Methodology for coordinating operational security analysis
1. 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:
(a)
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;
(b)
principles for common risk assessment, covering at least, for the contingencies referred to in Article 33:
(i)
associated probability;
(ii)
transitory admissible overloads; and
(iii)
impact of contingencies;
(c)
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;
(d)
requirements on coordination and information exchange between regional security coordinators in relation to the tasks listed in Article 77(3);
(e)
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.
2. 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:
(a)
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;
(b)
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
(c)
requirement to ensure an adequate representation of the connected elements in the TSO's observability area.
3. 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.
4. 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:
(a)
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;
(b)
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;
(c)
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.
5. 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:
(a)
the consistency in the definition of exceptional contingencies;
(b)
the evaluation of the probability and impact of exceptional contingencies; and
(c)
the consideration of exceptional contingencies in a TSO's contingency list when their probability exceeds a common threshold.
6. 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:
(a)
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
(b)
minimum frequency of generation and demand forecast updates, depending on their variability and the installed capacity of non-dispatchable generation.
Proposal for regional operational security coordination
1. 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:
(a)
conditions and frequency of intraday coordination of operational security analysis and updates to the common grid model by the regional security coordinator;
(b)
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:
(i)
the procedure for exchanging the information of the available remedial actions, between relevant TSOs and the regional security coordinator;
(ii)
the classification of constraints and the remedial actions in accordance with Article 22;
(iii)
the identification of the most effective and economically efficient remedial actions in case of operational security violations referred to in Article 22;
(iv)
the preparation and activation of remedial actions in accordance with Article 23(2);
(v)
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.
2. 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.
Organisation for regional operational security coordination
1. 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:
(a)
the appointment of the regional security coordinator(s) that will perform the tasks in paragraph 3 for that capacity calculation region;
(b)
rules concerning the governance and operation of regional security coordinator(s), ensuring equitable treatment of all member TSOs;
(c)
where the TSOs propose to appoint more than one regional security coordinator in accordance with subparagraph (a):
(i)
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;
(ii)
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;
(iii)
an effective coordination and decision making process to resolve conflicting positions between regional security coordinators within the capacity calculation region.
2. When developing the proposal for common provisions concerning the organisation of regional operational security coordination in paragraph 1, the following requirements shall be met:
(a)
each TSO shall be covered by at least one regional security coordinator;
(b)
all TSOs shall ensure that the total number of regional security coordinators across the Union is not higher than six.
3. The TSOs of each capacity calculation region shall propose the delegation of the following tasks in accordance with paragraph 1:
(a)
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;
(b)
building of common grid model in accordance with Article 79;
(c)
regional outage coordination in accordance with Article 80, in order to support TSOs fulfil their obligations in Articles 98 and 100;
(d)
regional adequacy assessment in accordance with Article 81 in order to support TSOs fulfil their obligations under Article 107.
4. 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..
5. 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.
Regional operational security coordination
1. 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:
(a)
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);
(b)
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
(c)
the operational security limits established in accordance with Article 25.
2. Each regional security coordinator shall:
(a)
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;
(b)
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.
3. 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.
4. 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.
Common grid model building
1. 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).
2. 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.
3. 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.
4. 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.
5. 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.
Regional outage coordination
1. The outage coordination regions within which the TSOs shall proceed to outage coordination shall be at least equal to the capacity calculation regions.
2. 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).
3. Each TSO shall provide the regional security coordinator with the information necessary to detect and solve regional outage planning incompatibilities, including at least:
(a)
the availability plans of its internal relevant assets, stored on the ENTSO for Electricity operational planning data environment;
(b)
the most recent availability plans for all non-relevant assets of its control area which are:
(i)
capable of influencing the results of the outage planning incompatibility analysis;
(ii)
modelled in the individual grid models which are used for the outage incompatibility assessment;
(c)
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.
4. 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.
5. In performing their obligations under paragraph 4, each regional security coordinator shall coordinate its analyses with other regional security coordinators.
6. 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.
Regional adequacy assessment
1. Each regional security coordinator shall perform regional adequacy assessments for at least the week-ahead time-frame.
2. Each TSO shall provide the regional security coordinator with the information necessary to perform the regional adequacy assessments referred to in paragraph 1, including:
(a)
the expected total load and available resources of demand response;
(b)
the availability of power generation modules; and
(c)
the operational security limits.
3. 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.
4. When performing a regional adequacy assessment, each regional security coordinator shall coordinate with other regional security coordinators.
TITLE 3 — OUTAGE COORDINATION
CHAPTER 1 — Outage coordination regions, relevant assets
Outage coordination objective
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.
Regional coordination
1. 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:
(a)
frequency, scope and type of coordination for, at least, the year-ahead and week-ahead time-frames;
(b)
provisions concerning the use of the assessments carried out by the regional security coordinator in accordance with Article 80;
(c)
practical arrangements for the validation of the year-ahead relevant grid element availability plans, as required by Article 98.
2. 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.
3. 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.
4. 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.
5. 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.
6. 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.
Methodology for assessing the relevance of assets for outage coordination
1. 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.
2. 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:
(a)
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;
(b)
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;
(c)
capacity of potential relevant power generating modules or demand facilities to qualify as SGUs;
(d)
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;
(e)
systematic relevance of all grid elements located in a transmission system or in a distribution system which connect different control areas; and
(f)
systematic relevance of all critical network elements.
3. 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).
Lists of relevant power generating modules and relevant demand facilities
1. 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.
2. 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.
3. 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.
4. For each internal relevant asset which is a power generating module or demand facility, the TSO shall:
(a)
inform the owner of the relevant power generating module or relevant demand facility about its inclusion in the list;
(b)
inform DSOs about the relevant power generating modules and the relevant demand facilities which are connected to their distribution system; and
(c)
inform CDSOs about the relevant power generating modules and the relevant demand facilities which are connected to their closed distribution system.
Update of the lists of relevant power generating modules and relevant demand facilities
1. 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).
2. 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.
3. 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.
4. Each TSO of an outage coordination region shall inform the parties referred to in Article 85(4) about the content of the updated list.
Lists of relevant grid elements
1. 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.
2. 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).
3. 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.
4. Each TSO shall notify to its regulatory authority the list of relevant grid elements for each outage coordination region in which it participates.
5. For each internal relevant asset which is a grid element, the TSO shall:
(a)
inform the owner of the relevant grid element about its inclusion in the list;
(b)
inform DSOs about the relevant grid elements which are connected to their distribution system; and
(c)
inform CDSOs about the relevant grid elements which are connected to their closed distribution system.
Update of the list of relevant grid elements
1. 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.
2. 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.
3. All TSOs of an outage coordination region shall make the updated list available on the ENTSO for Electricity operational planning data environment.
4. Each TSO of an outage coordination region shall inform the parties referred to in Article 85(4) about the content of the updated list.
Appointment of outage planning agents
1. Each TSO shall act as the outage planning agent for each relevant grid element it operates.
2. 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.
Treatment of relevant assets located in a distribution system or in a closed distribution system
1. Each TSO shall coordinate with the DSO the outage planning of internal relevant assets connected to its distribution system.
2. Each TSO shall coordinate with the CDSO the outage planning of internal relevant assets connected to its closed distribution system.
CHAPTER 2 — Development and update of availability plans of relevant assets
Variations to deadlines for the year-ahead outage coordination
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.
General provisions on availability plans
1. The availability status of a relevant asset shall be one of the following:
(a)
‘available’ where the relevant asset is capable of and ready for providing service regardless of whether it is or it is not in operation;
(b)
‘unavailable’ where the relevant asset is not capable of or ready for providing service;
(c)
‘testing’ where the capability of the relevant asset for providing service is being tested.
2. The ‘testing’ status shall only apply in case of a potential impact on the transmission system and for the following time periods:
(a)
between first connection and final commissioning of the relevant asset; and
(b)
directly following maintenance of the relevant asset.
3. The availability plans shall contain at least the following information:
(a)
the reason for the ‘unavailable’ status of a relevant asset;
(b)
where such conditions are identified, the conditions to be fulfilled before applying the ‘unavailable’ status of a relevant asset in real-time;
(c)
the time required to restore a relevant asset back to service where necessary in order to maintain operational security.
4. The availability status for each relevant asset in the year-ahead time-frame shall be provided with daily resolution.
5. 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.
Long-term indicative availability plans
1. 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.
2. 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.
Provision of year-ahead availability plan proposals
1. 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.
2. 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.
3. 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:
(a)
following the order in which the requests were received; and
(b)
applying the procedure established in accordance with Article 100.
Year-ahead coordination of the availability status of relevant assets for which the outage planning agent is not a TSO taking part in an outage coordination region, nor a DSO or a CDSO
1. Each TSO shall assess on a year-ahead time-frame whether outage planning incompatibilities arise from the availability plans received pursuant to Article 94.
2. When a TSO detects outage planning incompatibilities, it shall implement the following process:
(a)
inform each affected outage planning agent of the conditions it shall fulfil to mitigate the detected outage planning incompatibilities;
(b)
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
(c)
the TSO shall repeat the assessment pursuant to paragraph 1 to determine whether any outage planning incompatibilities remain.
3. 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:
(a)
take into account the impact reported by the affected outage planning agents as well as the DSO or CDSO where relevant;
(b)
limit the changes in the alternative availability plan to what is strictly necessary to mitigate the outage planning incompatibilities; and
(c)
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.
Year-ahead coordination of the availability status of relevant assets for which the outage planning agent is a TSO taking part in an outage coordination region, a DSO or a CDSO
1. 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.
2. 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.
3. When establishing the availability status of relevant grid elements in accordance with paragraphs 1 and 2, the TSO, DSO and CDSO shall:
(a)
minimize the impact on the market while preserving operational security; and
(b)
use as a basis the availability plans submitted and developed in accordance with Article 94.
4. 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.
5. 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:
(a)
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;
(b)
notify the actions referred to in point (a) to all affected parties; and
(c)
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.
6. 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.
Provision of preliminary year-ahead availability plans
1. 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.
2. 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.
3. 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.
Validation of year-ahead availability plans within outage coordination regions
1. Each TSO shall analyse whether any outage planning incompatibility arises when taking into account all the preliminary year-ahead availability plans.
2. 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.
3. 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.
4. 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:
(a)
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
(b)
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.
5. All TSOs of the concerned outage coordination regions shall consequently update and validate the year-ahead availability plans for all relevant assets.
Final year-ahead availability plans
1. Before 1 December of each calendar year, each TSO shall:
(a)
finalise the year-ahead outage coordination of internal relevant assets; and
(b)
finalise the year-ahead availability plans for internal relevant assets and store them on the ENTSO for Electricity operational planning data environment.
2. 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.
3. 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.
4. 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.
Updates to the final year-ahead availability plans
1. 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.
2. 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.
3. In case of a request for amendment pursuant to paragraph 2, the following procedure shall be applied:
(a)
the recipient TSO shall acknowledge the request and assess as soon as reasonably practicable whether the amendment leads to outage planning incompatibilities;
(b)
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;
(c)
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
(d)
where no solution is found for outage planning incompatibilities the recipient TSO shall reject the requested amendment.
4. 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:
(a)
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);
(b)
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;
(c)
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;
(d)
where no solution to outage planning incompatibilities are found, the requesting TSO shall retract the procedure for amendment.
Source: EUR-Lex (Publications Office of the EU), © European Union, reuse permitted under Commission Decision 2011/833/EU.
