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For the purpose of safeguarding operational security, frequency quality and the efficient use of the interconnected system and resources, this Regulation lays down detailed guidelines on:

requirements and principles concerning operational security;

rules and responsibilities for the coordination and data exchange between TSOs, between TSOs and DSOs, and between TSOs or DSOs and SGUs, in operational planning and in close to real-time operation;

rules for training and certification of system operator employees;

requirements on outage coordination;

requirements for scheduling between the TSOs' control areas; and

rules aiming at the establishment of a Union framework for load-frequency control and reserves.

The rules and requirements set out in this Regulation shall apply to the following SGUs:

existing and new power generating modules that are, or would be, classified as type B, C and D in accordance with the criteria set out in Article 5 of Commission NCRGCGR ( 3 ) ;

existing and new transmission-connected demand facilities;

existing and new transmission-connected closed distribution systems;

existing and new demand facilities, closed distribution systems and third parties if they provide demand response directly to the TSO in accordance with the criteria in Article 27 of Commission NCDCR ( 4 ) ;

providers of redispatching of power generating modules or demand facilities by means of aggregation and providers of active power reserve in accordance with Title 8 of Part IV of this Regulation; and

existing and new high voltage direct current (‘HVDC’) systems in accordance with the criteria in Article 3(1) of Commission Regulation 2016/1447 ( 5 ) .

This Regulation shall apply to all transmission systems, distribution systems and interconnections in the Union and regional security coordinators, except transmission systems and distribution systems or parts of the transmission systems and distribution systems located in islands of Member States of which the systems are not operated synchronously with Continental Europe (‘CE’), Great Britain (‘GB’), Nordic, Ireland and Northern Ireland (‘IE/NI’) or Baltic synchronous area.

Where more than one TSO exists in a Member State, this Regulation shall apply to all TSOs in a Member State. Where a TSO does not have a function relevant to one or more obligations under this Regulation, Member States may, under the national regulatory regime, provide that the responsibility of a TSO to comply with one or some or all obligations under this Regulation is assigned to one or more specific TSOs.

The TSOs of Lithuania, Latvia and Estonia are, as long as and to the extent that they are operating in a synchronous mode in a synchronous area where not all countries are bound by Union legislation, exempted from the application of the provisions listed in Annex I to this Regulation, unless otherwise foreseen in a cooperation agreement with third country TSOs setting the basis for their cooperation concerning secure system operation pursuant to Article 13.

Where the requirements under this Regulation are to be established by a relevant system operator that is not a TSO, Member States may provide that instead the TSO be responsible for establishing the relevant requirements.

For the purposes of this Regulation, the definitions in Article 2 of Regulation 2009/714, Article 2 of Commission GCACMR ( 6 ) , Article 2 of Commission NCRGCGR, Article 2 of Commission NCDCR, Article 2 of Commission Regulation 2016/1447, Article 2 of Commission GFCAR ( 7 ) , Article 2 of Commission SPDIEMR ( 8 ) on submission and publication of data in electricity markets and Article 2 of CRIMIED of the European Parliament and of the Council ( 9 ) shall apply.

In addition, the following definitions shall apply:

‘operational security’ means the transmission system's capability to retain a normal state or to return to a normal state as soon as possible, and which is characterised by operational security limits;

‘constraint’ means a situation in which there is a need to prepare and activate a remedial action in order to respect operational security limits;

‘N-situation’ means the situation where no transmission system element is unavailable due to occurrence of a contingency;

‘contingency list’ means the list of contingencies to be simulated in order to test the compliance with the operational security limits;

‘normal state’ means a situation in which the system is within operational security limits in the N-situation and after the occurrence of any contingency from the contingency list, taking into account the effect of the available remedial actions;

‘frequency containment reserves’ or ‘FCR’ means the active power reserves available to contain system frequency after the occurrence of an imbalance;

‘frequency restoration reserves’ or ‘FRR’ means the active power reserves available to restore system frequency to the nominal frequency and, for a synchronous area consisting of more than one LFC area, to restore power balance to the scheduled value;

‘replacement reserves’ or ‘RR’ means the active power reserves available to restore or support the required level of FRR to be prepared for additional system imbalances, including generation reserves;

‘reserve provider’ means a legal entity with a legal or contractual obligation to supply FCR, FRR or RR from at least one reserve providing unit or reserve providing group;

‘reserve providing unit’ means a single or an aggregation of power generating modules and/or demand units connected to a common connection point fulfilling the requirements to provide FCR, FRR or RR;

‘reserve providing group’ means an aggregation of power generating modules, demand units and/or reserve providing units connected to more than one connection point fulfilling the requirements to provide FCR, FRR or RR;

‘load-frequency control area’ or ‘LFC area’ means a part of a synchronous area or an entire synchronous area, physically demarcated by points of measurement at interconnectors to other LFC areas, operated by one or more TSOs fulfilling the obligations of load-frequency control;

‘time to restore frequency’ means the maximum expected time after the occurrence of an instantaneous power imbalance smaller than or equal to the reference incident in which the system frequency returns to the frequency restoration range for synchronous areas with only one LFC area and in the case of synchronous areas with more than one LFC area, the maximum expected time after the occurrence of an instantaneous power imbalance of an LFC area within which the imbalance is compensated;

‘(N-1) criterion’ means the rule according to which the elements remaining in operation within a TSO's control area after occurrence of a contingency are capable of accommodating the new operational situation without violating operational security limits;

‘(N-1) situation’ means the situation in the transmission system in which one contingency from the contingency list occurred;

‘active power reserve’ means the balancing reserves available for maintaining the frequency;

‘alert state’ means the system state in which the system is within operational security limits, but a contingency from the contingency list has been detected and in case of its occurrence the available remedial actions are not sufficient to keep the normal state;

‘load-frequency control block’ or ‘LFC block’ means a part of a synchronous area or an entire synchronous area, physically demarcated by points of measurement at interconnectors to other LFC blocks, consisting of one or more LFC areas, operated by one or more TSOs fulfilling the obligations of load-frequency control;

‘area control error’ or ‘ACE’ means the sum of the power control error (‘ΔP’), that is the real-time difference between the measured actual real time power interchange value (‘P’) and the control program (‘P0’) of a specific LFC area or LFC block and the frequency control error (‘K*Δf’), that is the product of the K-factor and the frequency deviation of that specific LFC area or LFC block, where the area control error equals ΔP+K*Δf;

‘control program’ means a sequence of set-point values for the netted power interchange of a LFC area or LFC block over alternating current (‘AC’) interconnectors;

‘voltage control’ means the manual or automatic control actions at the generation node, at the end nodes of the AC lines or HVDC systems, on transformers, or other means, designed to maintain the set voltage level or the set value of reactive power;

‘blackout state’ means the system state in which the operation of part or all of the transmission system is terminated;

‘internal contingency’ means a contingency within the TSO's control area, including interconnectors;

‘external contingency’ means a contingency outside the TSO's control area and excluding interconnectors, with an influence factor higher than the contingency influence threshold;

‘influence factor’ means the numerical value used to quantify the greatest effect of the outage of a transmission system element located outside of the TSO's control area excluding interconnectors, in terms of a change in power flows or voltage caused by that outage, on any transmission system element. The higher is the value the greater the effect;

‘contingency influence threshold’ means a numerical limit value against which the influence factors are checked and the occurrence of a contingency located outside of the TSO's control area with an influence factor higher than the contingency influence threshold is considered to have a significant impact on the TSO's control area including interconnectors;

‘contingency analysis’ means a computer based simulation of contingencies from the contingency list;

‘critical fault clearing time’ means the maximum fault duration for which the transmission system retains stability of operation;

‘fault’ means all types of short-circuits (single-, double- and triple-phase, with and without earth contact), a broken conductor, interrupted circuit, or an intermittent connection, resulting in the permanent non-availability of the affected transmission system element;

‘transmission system element’ means any component of the transmission system;

‘disturbance’ means an unplanned event that may cause the transmission system to divert from the normal state;

‘dynamic stability’ is a common term including the rotor angle stability, frequency stability and voltage stability;

‘dynamic stability assessment’ means the operational security assessment in terms of dynamic stability;

‘frequency stability’ means the ability of the transmission system to maintain frequency stable in the N-situation and after being subjected to a disturbance;

‘voltage stability’ means the ability of a transmission system to maintain acceptable voltages at all nodes in the transmission system in the N-situation and after being subjected to a disturbance;

‘system state’ means the operational state of the transmission system in relation to the operational security limits which can be normal state, alert state, emergency state, blackout state and restoration state;

‘emergency state’ means the system state in which one or more operational security limits are violated;

‘restoration state’ means the system state in which the objective of all activities in the transmission system is to re-establish the system operation and maintain operational security after the blackout state or the emergency state;

‘exceptional contingency’ means the simultaneous occurrence of multiple contingencies with a common cause;

‘frequency deviation’ means the difference between the actual and the nominal frequency of the synchronous area which can be negative or positive;

‘system frequency’ means the electric frequency of the system that can be measured in all parts of the synchronous area under the assumption of a coherent value for the system in the timeframe of seconds, with only minor differences between different measurement locations;

‘frequency restoration process’ or ‘FRP’ means a process that aims at restoring frequency to the nominal frequency and, for synchronous areas consisting of more than one LFC area, a process that aims at restoring the power balance to the scheduled value;

‘frequency restoration control error’ or ‘FRCE’ means the control error for the FRP which is equal to the ACE of a LFC area or equal to the frequency deviation where the LFC area geographically corresponds to the synchronous area;

‘schedule’ means a reference set of values representing the generation, consumption or exchange of electricity for a given time period;

‘K-factor of an LFC area or LFC block’ means a value expressed in megawatts per hertz (‘MW/Hz’), which is as close as practical to, or greater than the sum of the auto-control of generation, self-regulation of load and of the contribution of frequency containment reserve relative to the maximum steady-state frequency deviation;

‘local state’ means the qualification of an alert, emergency or blackout state when there is no risk of extension of the consequences outside of the control area including interconnectors connected to this control area;

‘maximum steady-state frequency deviation’ means the maximum expected frequency deviation after the occurrence of an imbalance equal to or less than the reference incident at which the system frequency is designed to be stabilised;

‘observability area’ means a TSO's own transmission system and the relevant parts of distribution systems and neighbouring TSOs' transmission systems, on which the TSO implements real-time monitoring and modelling to maintain operational security in its control area including interconnectors;

‘neighbouring TSOs’ means the TSOs directly connected via at least one AC or DC interconnector;

‘operational security analysis’ means the entire scope of the computer based, manual and automatic activities performed in order to assess the operational security of the transmission system and to evaluate the remedial actions needed to maintain operational security;

‘operational security indicators’ means indicators used by TSOs to monitor the operational security in terms of system states as well as faults and disturbances influencing operational security;

‘operational security ranking’ means the ranking used by TSOs to monitor the operational security on the basis of the operational security indicators;

‘operational tests’ means the tests carried out by a TSO or DSO for maintenance, development of system operation practices and training and to acquire information on transmission system behaviour under abnormal system conditions and the tests carried out by significant grid users for similar purposes on their facilities;

‘ordinary contingency’ means the occurrence of a contingency of a single branch or injection;

‘out-of-range contingency’ means the simultaneous occurrence of multiple contingencies without a common cause, or a loss of power generating modules with a total loss of generation capacity exceeding the reference incident;

‘ramping rate’ means the rate of change of active power by a power generating module, demand facility or HVDC system;

‘reactive power reserve’ means the reactive power which is available for maintaining voltage;

‘reference incident’ means the maximum positive or negative power deviation occurring instantaneously between generation and demand in a synchronous area, considered in the FCR dimensioning;

‘rotor angle stability’ means the ability of synchronous machines to remain in synchronism under N-situation and after being subject to a disturbance;

‘security plan’ means the plan containing a risk assessment of critical TSO's assets to major physical- and cyber-threat scenarios with an assessment of the potential impacts;

‘stability limits’ means the permitted boundaries for the operation of the transmission system in terms of respecting the limits of voltage stability, rotor angle stability and frequency stability;

‘wide area state’ means the qualification of an alert state, emergency state or blackout state when there is a risk of propagation to the interconnected transmission systems;

‘system defence plan’ means the technical and organisational measures to be undertaken to prevent the propagation or deterioration of a disturbance in the transmission system, in order to avoid a wide area state disturbance and blackout state;

‘topology’ means the data concerning the connectivity of the different transmission system or distribution system elements in a substation and includes the electrical configuration and the position of circuit breakers and isolators;

‘transitory admissible overloads’ means the temporary overloads of transmission system elements which are allowed for a limited period and which do not cause physical damage to the transmission system elements as long as the defined duration and thresholds are respected;

‘virtual tie-line’ means an additional input of the controllers of the involved LFC areas that has the same effect as a measuring value of a physical interconnector and allows exchange of electric energy between the respective areas;

‘flexible alternating current transmission systems’ or ‘FACTS’ means equipment for the alternating current transmission of electric power, aiming at enhanced controllability and increased active power transfer capability;

‘adequacy’ means the ability of in-feeds into an area to meet the load in that area;

‘aggregated netted external schedule’ means a schedule representing the netted aggregation of all external TSO schedules and external commercial trade schedules between two scheduling areas or between a scheduling area and a group of other scheduling areas;

‘availability plan’ means the combination of all planned availability statuses of a relevant asset for a given time period;

‘availability status’ means the capability of a power generating module, grid element or demand facility to provide a service for a given time period, regardless of whether or not it is in operation;

‘close to real-time’ means the time lapse of not more than 15 minutes between the last intraday gate closure and real-time;

‘consumption schedule’ means a schedule representing the consumption of a demand facility or of a group of demand facilities;

‘ENTSO for Electricity operational planning data environment’ means the set of application programs and equipment developed in order to allow the storage, exchange and management of the data used for operational planning processes between TSOs;

‘external commercial trade schedule’ means a schedule representing the commercial exchange of electricity between market participants in different scheduling areas;

‘external TSO schedule’ means a schedule representing the exchange of electricity between TSOs in different scheduling areas;

‘forced outage’ means the unplanned removal from service of a relevant asset for any urgent reason that is not under the operational control of the operator of the concerned relevant asset;

‘generation schedule’ means a schedule representing the electricity generation of a power generating module or of a group of power generating modules;

‘internal commercial trade schedule’ means a schedule representing the commercial exchange of electricity within a scheduling area between different market participants;

‘internal relevant asset’ means a relevant asset which is part of a TSO's control area or a relevant asset located in a distribution system, including a closed distribution system, which is connected directly or indirectly to that TSO's control area;

‘netted area AC position’ means the netted aggregation of all AC external schedules of an area;

‘outage coordination region’ means a combination of control areas for which TSOs define procedures to monitor and where necessary coordinate the availability status of relevant assets in all time-frames;

‘relevant demand facility’ means a demand facility which participates in the outage coordination and the availability status of which influences cross-border operational security;

‘relevant asset’ means any relevant demand facility, relevant power generating module, or relevant grid element partaking in the outage coordination;

‘relevant grid element’ means any component of a transmission system, including interconnectors, or of a distribution system, including a closed distribution system, such as a single line, a single circuit, a single transformer, a single phase-shifting transformer, or a voltage compensation installation, which participates in the outage coordination and the availability status of which influences cross-border operational security;

‘outage planning incompatibility’ means the state in which a combination of the availability status of one or more relevant grid elements, relevant power generating modules, and/or relevant demand facilities and the best estimate of the forecasted electricity grid situation leads to violation of operational security limits taking into account remedial actions without costs which are at the TSO's disposal;

‘outage planning agent’ means an entity with the task of planning the availability status of a relevant power generating module, a relevant demand facility or a relevant grid element;

‘relevant power generating module’ means a power generating module which participates in the outage coordination and the availability status of which influences cross-border operational security;

‘regional security coordinator’ (‘RSC’) means the entity or entities, owned or controlled by TSOs, in one or more capacity calculation regions performing tasks related to TSO regional coordination;

‘scheduling agent’ means the entity or entities with the task of providing schedules from market participants to TSOs, or where applicable third parties;

‘scheduling area’ means an area within which the TSOs' obligations regarding scheduling apply due to operational or organisational needs;

‘week-ahead’ means the week prior to the calendar week of operation;

‘year-ahead’ means the year prior to the calendar year of operation;

‘affected TSO’ means a TSO for which information on the exchange of reserves and/or sharing of reserves and/or imbalance netting process and/or cross-border activation process is needed for the analysis and maintenance of operational security;

‘reserve capacity’ means the amount of FCR, FRR or RR that needs to be available to the TSO;

‘exchange of reserves’ means the possibility of a TSO to access reserve capacity connected to another LFC area, LFC block, or synchronous area to fulfil its reserve requirements resulting from its own reserve dimensioning process of either FCR, FRR or RR and where that reserve capacity is exclusively for that TSO, and is not taken into account by any other TSO to fulfil its reserve requirements resulting from their respective reserve dimensioning processes;

‘sharing of reserves’ means a mechanism in which more than one TSO takes the same reserve capacity, being FCR, FRR or RR, into account to fulfil their respective reserve requirements resulting from their reserve dimensioning processes;

‘alert state trigger time’ means the time before alert state becomes active;

‘automatic FRR’ means FRR that can be activated by an automatic control device;

‘automatic FRR activation delay’ means the period of time between the setting of a new setpoint value by the frequency restoration controller and the start of physical automatic FRR delivery;

‘automatic FRR full activation time’ means the time period between the setting of a new setpoint value by the frequency restoration controller and the corresponding activation or deactivation of automatic FRR;

‘average FRCE data’ means the set of data consisting of the average value of the recorded instantaneous FRCE of a LFC area or a LFC block within a given measured period time;

‘control capability providing TSO’ means the TSO that shall trigger the activation of its reserve capacity for a control capability receiving TSO under the conditions of an agreement for sharing reserves;

‘control capability receiving TSO’ means the TSO calculating reserve capacity by taking into account reserve capacity which is accessible through a control capability providing TSO under the conditions of an agreement for sharing reserves;

‘criteria application process’ means the process of calculating the target parameters for the synchronous area, the LFC block and the LFC area based on the data obtained in the data collection and delivery process;

‘data collection and delivery process’ means the process of collection of the set of data necessary in order to perform the frequency quality evaluation criteria;

‘cross-border FRR activation process’ means a process agreed between the TSOs participating in the process that allows for activation of FRR connected in a different LFC area by correcting the input of the involved FRPs accordingly;

‘cross-border RR activation process’ means a process agreed between the TSOs participating in the process that allows for activation of RR connected in a different LFC area by correcting the input of the involved RRP accordingly;

‘dimensioning incident’ means the highest expected instantaneously occurring active power imbalance within a LFC block in both positive and negative direction;

‘electrical time deviation’ means the time discrepancy between synchronous time and coordinated universal time (‘UTC’);

‘FCR full activation frequency deviation’ means the rated value of frequency deviation at which the FCR in a synchronous area is fully activated;

‘FCR full activation time’ means the time period between the occurrence of the reference incident and the corresponding full activation of the FCR;

‘FCR obligation’ means the part of all of the FCR that falls under the responsibility of a TSO;

‘frequency containment process’ or ‘FCP’ means a process that aims at stabilising the system frequency by compensating imbalances by means of appropriate reserves;

‘frequency coupling process’ means a process agreed between all TSOs of two synchronous areas that allows linking the activation of FCR by an adaptation of HVDC flows between the synchronous areas;

‘frequency quality defining parameter’ means the main system frequency variables that define the principles of frequency quality;

‘frequency quality target parameter’ means the main system frequency target on which the behaviour of FCR, FRR and RR activation processes is evaluated in normal state;

‘frequency quality evaluation criteria’ means a set of calculations using system frequency measurements that allows the evaluation of the quality of the system frequency against the frequency quality target parameters;

‘frequency quality evaluation data’ means the set of data that allows the calculation of the frequency quality evaluation criteria;

‘frequency recovery range’ means the system frequency range to which the system frequency is expected to return in the GB and IE/NI synchronous areas, after the occurrence of an imbalance equal to or smaller than the reference incident, within the time to recover frequency;

‘time to recover frequency’ means, for the synchronous areas GB and IE/NI, the maximum expected time after the occurrence of an imbalance smaller than or equal to the reference incident in which the system frequency returns to the maximum steady state frequency deviation;

‘frequency restoration range’ means the system frequency range to which the system frequency is expected to return in the GB, IE/NI and Nordic synchronous areas, after the occurrence of an imbalance equal to or smaller than the reference incident within the time to restore frequency;

‘FRCE target parameters’ means the main target LFC block variables on the basis of which the dimensioning criteria for FRR and RR of the LFC block are determined and evaluated and which are used to reflect the LFC block behaviour in normal operation;

‘frequency restoration power interchange’ means the power which is interchanged between LFC areas within the cross-border FRR activation process;

‘frequency setpoint’ means the frequency target value used in the FRP, defined as the sum of the nominal system frequency and an offset value needed to reduce an electrical time deviation;

‘FRR availability requirements’ means a set of requirements defined by the TSOs of a LFC block regarding the availability of FRR;

‘FRR dimensioning rules’ means the specifications of the FRR dimensioning process of a LFC block;

‘imbalance netting process’ means a process agreed between TSOs that allows avoiding the simultaneous activation of FRR in opposite directions, taking into account the respective FRCEs as well as the activated FRR and by correcting the input of the involved FRPs accordingly;

‘imbalance netting power interchange’ means the power which is interchanged between LFC areas within the imbalance netting process;

‘initial FCR obligation’ means the amount of FCR allocated to a TSO on the basis of a sharing key;

‘instantaneous frequency data’ means a set of data measurements of the overall system frequency for the synchronous area with a measurement period equal to or shorter than one second used for system frequency quality evaluation purposes;

‘instantaneous frequency deviation’ means a set of data measurements of the overall system frequency deviations for the synchronous area with a measurement period equal to or shorter than one second used for system frequency quality evaluation purposes;

‘instantaneous FRCE data’ means a set of data of the FRCE of a LFC block with a measurement period equal to or shorter than 10 seconds used for system frequency quality evaluation purposes;

‘level 1 FRCE range’ means the first range used for system frequency quality evaluation purposes on LFC block level within which the FRCE should be kept for a specified percentage of the time;

‘level 2 FRCE range’ means the second range used for system frequency quality evaluation purposes on LFC block level within which the FRCE should be kept for a specified percentage of the time;

‘LFC block operational agreement’ means a multi-party agreement between all TSOs of a LFC block if the LFC block is operated by more than one TSO and means a LFC block operational methodology to be adopted unilaterally by the relevant TSO if the LFC block is operated by only one TSO;

‘replacement power interchange’ means the power which is interchanged between LFC areas within the cross-border RR activation process;

‘LFC block imbalances’ means the sum of the FRCE, FRR activation and RR activation within the LFC block and the imbalance netting power interchange, the frequency restoration power interchange and the replacement power interchange of this LFC block with other LFC blocks;

‘LFC block monitor’ means a TSO responsible for collecting the frequency quality evaluation criteria data and applying the frequency quality evaluation criteria for the LFC block;

‘load-frequency control structure’ means the basic structure considering all relevant aspects of load-frequency control in particular concerning respective responsibilities and obligations as well as types and purposes of active power reserves;

‘process responsibility structure’ means the structure to determine responsibilities and obligations with respect to active power reserves based on the control structure of the synchronous area;

‘process activation structure’ means the structure to categorise the processes concerning the different types of active power reserves in terms of purpose and activation;

‘manual FRR full activation time’ means the time period between the setpoint change and the corresponding activation or deactivation of manual FRR;

‘maximum instantaneous frequency deviation’ means the maximum expected absolute value of an instantaneous frequency deviation after the occurrence of an imbalance equal to or smaller than the reference incident, beyond which emergency measures are activated;

‘monitoring area’ means a part of the synchronous area or the entire synchronous area, physically demarcated by points of measurement at interconnectors to other monitoring areas, operated by one or more TSOs fulfilling the obligations of a monitoring area;

‘prequalification’ means the process to verify the compliance of a reserve providing unit or a reserve providing group with the requirements set by the TSO;

‘ramping period’ means a period of time defined by a fixed starting point and a length of time during which the input and/or output of active power will be increased or decreased;

‘reserve instructing TSO’ means the TSO responsible for the instruction of the reserve providing unit or the reserve providing group to activate FRR and/or RR;

‘reserve connecting DSO’ means the DSO responsible for the distribution network to which a reserve providing unit or reserve providing group, providing reserves to a TSO, is connected;

‘reserve connecting TSO’ means the TSO responsible for the monitoring area to which a reserve providing unit or reserve providing group is connected;

‘reserve receiving TSO’ means the TSO involved in an exchange with a reserve connecting TSO and/or a reserve providing unit or a reserve providing group connected to another monitoring or LFC area;

‘reserve replacement process’ or ‘RRP’ means a process to restore the activated FRR and, additionally for GB and IE/NI, to restore the activated FCR;

‘RR availability requirements’ means a set of requirements defined by the TSOs of a LFC block regarding the availability of RR;

‘RR dimensioning rules’ means the specifications of the RR dimensioning process of a LFC block;

‘standard frequency range’ means a defined symmetrical interval around the nominal frequency within which the system frequency of a synchronous area is supposed to be operated;

‘standard frequency deviation’ means the absolute value of the frequency deviation that limits the standard frequency range;

‘steady state frequency deviation’ means the absolute value of frequency deviation after occurrence of an imbalance, once the system frequency has been stabilised;

‘synchronous area monitor’ means a TSO responsible for collecting the frequency quality evaluation criteria data and applying the frequency quality evaluation criteria for the synchronous area;

‘time control process’ means a process for time control, where time control is a control action carried out to return the electrical time deviation between synchronous time and UTC time to zero.

This Regulation aims at:

determining common operational security requirements and principles;

determining common interconnected system operational planning principles;

determining common load-frequency control processes and control structures;

ensuring the conditions for maintaining operational security throughout the Union;

ensuring the conditions for maintaining a frequency quality level of all synchronous areas throughout the Union;

promoting the coordination of system operation and operational planning;

ensuring and enhancing the transparency and reliability of information on transmission system operation;

contributing to the efficient operation and development of the electricity transmission system and electricity sector in the Union.

When applying this Regulation, Member States, competent authorities, and system operators shall:

apply the principles of proportionality and non-discrimination;

ensure transparency;

apply the principle of optimisation between the highest overall efficiency and lowest total costs for all parties involved;

ensure TSOs make use of market-based mechanisms as far as possible, to ensure network security and stability;

respect the responsibility assigned to the relevant TSO in order to ensure system security, including as required by national legislation;

consult with relevant DSOs and take account of potential impacts on their system; and

take into consideration agreed European standards and technical specifications.

TSOs shall develop the terms and conditions or methodologies required by this Regulation and submit them for approval to the competent regulatory authorities in accordance with Article 6(2) and (3) or for approval to the entity designated by the Member State in accordance with Article 6(4) within the respective deadlines set out in this Regulation.

Where a proposal for terms and conditions or methodologies pursuant to this Regulation needs to be developed and agreed by more than one TSO, the participating TSOs shall closely cooperate. TSOs, with the assistance of ENTSO for Electricity, shall regularly inform the regulatory authorities and the Agency about the progress of developing those terms and conditions or methodologies.

Where no consensus is reached among TSOs deciding on proposals for terms and conditions or methodologies in accordance with Article 6(2), they shall decide by qualified majority. The qualified majority for proposals in accordance with Article 6(2) shall require a majority of:

TSOs representing at least 55 % of the Member States; and

TSOs representing Member States comprising at least 65 % of the population of the Union.

A blocking minority for decisions in accordance with Article 6(2) must include TSOs representing at least four Member States, failing of which the qualified majority shall be deemed attained.

Where the regions concerned are composed of more than five Member States and no consensus is reached among TSOs deciding on proposals for terms and conditions or methodologies in accordance with Article 6(3) they shall decide by qualified majority. A qualified majority for proposals in accordance with Article 6(3) shall require a majority of:

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

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

A blocking minority for decisions in accordance with Article 6(3) must include at least a minimum number of TSOs representing more than 35 % of the population of the participating Member States, plus TSOs representing at least one additional Member State concerned, failing of which the qualified majority shall be deemed attained.

TSOs deciding on proposals for terms and conditions or methodologies in accordance with Article 6(3) in relation to regions composed of five Member States or less shall decide on the basis of a consensus.

For TSO decisions under paragraphs 3 and 4, one vote shall be attributed per Member State. If there is more than one TSO in the territory of a Member State, the Member State shall allocate the voting powers among the TSOs.

Where TSOs fail to submit a proposal for terms and conditions or methodologies to the regulatory authorities in accordance with Article 6(2) and (3) or to the entities designated by the Member States in accordance with Article 6(4) within the deadlines defined in this Regulation, they shall provide the competent regulatory authorities and the Agency with the relevant drafts of the terms and conditions or methodologies, and explain why an agreement has not been reached. The Agency shall inform the Commission and shall, in cooperation with the competent regulatory authorities, at the Commission's request, investigate the reasons for the failure and inform the Commission thereof. The Commission shall take the appropriate steps to make possible the adoption of the required terms and conditions or methodologies within 4 months from the receipt of the Agency's information.

Each regulatory authority shall approve the terms and conditions or methodologies developed by TSOs under paragraphs 2 and 3. The entity designated by the Member State shall approve the terms and conditions or methodologies developed by TSOs under paragraph 4. The designated entity shall be the regulatory authority unless otherwise provided by the Member State.

The proposals for the following terms and conditions or methodologies shall be subject to approval by all regulatory authorities of the Union, on which a Member State may provide an opinion to the concerned regulatory authority:

key organizational requirements, roles and responsibilities in relation to data exchange related to operational security in accordance with Article 40(6);

methodology for building the common grid models in accordance with Article 67(1) and Article 70;

methodology for coordinating operational security analysis in accordance with Article 75.

The proposals for the following terms and conditions or methodologies shall be subject to approval by all regulatory authorities of the concerned region, on which a Member State may provide an opinion to the concerned regulatory authority:

methodology for each synchronous area for the definition of minimum inertia in accordance with Article 39(3) (b);

common provisions for each capacity calculation region for regional operational security coordination in accordance with Article 76;

methodology, at least per synchronous area, for assessing the relevance of assets for outage coordination in accordance with Article 84;

methodologies, conditions and values included in the synchronous area operational agreements in Article 118 concerning:

the frequency quality defining parameters and the frequency quality target parameter in accordance with Article 127;

the dimensioning rules for FCR in accordance with Article 153;

the additional properties of the FCR in accordance with Article 154(2);

for the GB and IE/NI synchronous areas, the measures to ensure the recovery of energy reservoirs in accordance with Article 156(6) (b);

for the CE and Nordic synchronous areas, the minimum activation period to be ensured by FCR providers in accordance with Article 156(10);

for the CE and Nordic synchronous areas, the assumptions and methodology for a cost-benefit analysis in accordance with Article 156(11);

for synchronous areas other than CE and if applicable, the limits for the exchange of FCR between TSOs in accordance with Article 163(2);

for the GB and IE/NI synchronous areas, the methodology to determine the minimum provision of reserve capacity on FCR between synchronous areas, defined in accordance with Article 174(2) (b);

limits on the amount of exchange of FRR between synchronous areas defined in accordance with Article 176(1) and limits on the amount of sharing of FRR between synchronous areas defined in accordance with Article 177(1);

limits on the amount of exchange of RR between synchronous areas defined in accordance with Article 178(1) and limits on the amount of sharing of RR between synchronous areas defined in accordance with Article 179(1);

methodologies and conditions included in the LFC block operational agreements in Article 119, concerning:

ramping restrictions for active power output in accordance with Article 137(3) and (4);

coordination actions aiming to reduce FRCE as defined in Article 152(14);

measures to reduce FRCE by requiring changes in the active power production or consumption of power generating modules and demand units in accordance with Article 152(16);

the FRR dimensioning rules in accordance with Article 157(1);

mitigation measures per synchronous area or LFC block in accordance with Article 138;

common proposal per synchronous area for the determination of LFC blocks in accordance with Article 141(2).

Unless determined otherwise by the Member State, the following terms and conditions or methodologies shall be subject to individual approval by the entity designated in accordance with paragraph 1 by the Member State:

for the GB and IE/NI synchronous areas, the proposal of each TSO specifying the level of demand loss at which the transmission system shall be in the blackout state;

scope of data exchange with DSOs and significant grid users in accordance with Article 40(5);

additional requirements for FCR providing groups in accordance with Article 154(3);

exclusion of FCR providing groups from the provision of FCR in accordance with Article 154(4);

for the CE and Nordic synchronous areas, the proposal concerning the interim minimum activation period to be ensured by FCR providers as proposed by the TSO in accordance with Article 156(9);

FRR technical requirements defined by the TSO in accordance with Article 158(3);

rejection of FRR providing groups from the provision of FRR in accordance with Article 159(7);

technical requirements for the connection of RR providing units and RR providing groups defined by the TSO in accordance with Article 161(3); and

rejection of RR providing groups from the provision of RR in accordance with Article 162(6).

Where an individual relevant system operator or TSO is required or permitted under this Regulation to specify or agree on requirements that are not subject to paragraph 4, Member States may require prior approval by the competent regulatory authority of these requirements.

The proposal for terms and conditions or methodologies shall include a proposed timescale for their implementation and a description of their expected impact on the objectives of this Regulation. Proposals on terms and conditions or methodologies subject to the approval by several or all regulatory authorities shall be submitted to the Agency at the same time that they are submitted to regulatory authorities. Upon request by the competent regulatory authorities, the Agency shall issue an opinion within 3 months on the proposals for terms and conditions or methodologies.

Where the approval of the terms and conditions or methodologies requires a decision by more than one regulatory authority, the competent regulatory authorities shall consult and closely cooperate and coordinate with each other in order to reach an agreement. Where the Agency issues an opinion, the competent regulatory authorities shall take that opinion into account. Regulatory authorities shall take decisions concerning the submitted terms and conditions or methodologies in accordance with paragraphs (2) and (3), within 6 months following the receipt of the terms and conditions or methodologies by the regulatory authority or, where applicable, by the last regulatory authority concerned.

Where the regulatory authorities have not been able to reach an agreement within the period referred to in paragraph 7 or upon their joint request, the Agency shall adopt a decision concerning the submitted proposals for terms and conditions or methodologies within 6 months, in accordance with Article 8(1) of EACERR.

Where the approval of the terms and conditions or methodologies requires a decision by a single designated entity in accordance with paragraph 4, the designated entity shall reach a decision within 6 months following the receipt of the terms and conditions or methodologies.

Any party can complain against a relevant system operator or TSO in relation to that relevant system operator's or TSO's obligations or decisions under this Regulation and may refer the complaint to the regulatory authority which, acting as dispute settlement authority, shall issue a decision within 2 months after receipt of the complaint. That period may be extended by a further 2 months where additional information is sought by the regulatory authority. That extended period may be further extended with the agreement of the complainant. The regulatory authority's decision shall be binding unless and until overruled on appeal.

Where one or several regulatory authorities require an amendment in order to approve the terms and conditions or methodologies submitted in accordance with paragraphs 2 and 3 of Article 6, the relevant TSOs shall submit a proposal for amended terms and conditions or methodologies for approval within 2 months following the requirement from the regulatory authorities. The competent regulatory authorities shall decide on the amended terms and conditions or methodologies within 2 months following their submission.

Where a designated entity requires an amendment in order to approve the terms and conditions or methodologies submitted in accordance with Article 6(4), the relevant TSO shall submit a proposal for amended terms and conditions or methodologies for approval within 2 months following the requirement from the designated entity. The designated entity shall decide on the amended terms and conditions or methodologies within 2 months following their submission.

Where the competent regulatory authorities have not been able to reach an agreement on terms and conditions or methodologies pursuant to paragraphs 2 and 3 of Article 6 within the two-month deadline, or upon their joint request, the Agency shall adopt a decision concerning the amended terms and conditions or methodologies within 6 months, in accordance with Article 8(1) of EACERR. If the relevant TSOs fail to submit a proposal for amended terms and conditions or methodologies, the procedure provided for in Article 5(7) shall apply.

TSOs responsible for developing a proposal for terms and conditions or methodologies or regulatory authorities or designated entities responsible for their adoption in accordance with paragraphs 2, 3 and 4 of Article 6 may request amendments of those terms and conditions or methodologies. Proposals for amendment to the terms and conditions or methodologies shall be submitted to consultation if applicable in accordance with the procedure set out in Article 11 and approved in accordance with the procedure set out in Articles 5 and 6.

TSOs responsible for specifying the terms and conditions or methodologies in accordance with this Regulation shall publish them on the internet following approval by the competent regulatory authorities or, where no such approval is required, following their specification, except where such information is considered confidential in accordance with Article 12.

The publication shall also concern:

enhancements of network operation tools in accordance with Article 55(1) (e);

FRCE target parameters in accordance with Article 128;

ramping restrictions on synchronous area level in accordance with Article 137(1);

ramping restrictions on LFC block level in accordance with Article 137(3);

measures taken in the alert state due to there being insufficient active power reserves in accordance with Article 152(11); and

request of the reserve connecting TSO to an FCR provider to make the information available in real time in accordance with Article 154(11).

The costs borne by system operators subject to network tariff regulation and stemming from the obligations laid down in this Regulation shall be assessed by the relevant regulatory authorities. Costs assessed as reasonable, efficient and proportionate shall be recovered through network tariffs or other appropriate mechanisms.

If requested by the relevant regulatory authorities, system operators referred to in paragraph 1 shall, within 3 months of the request, provide the information necessary to facilitate assessment of the costs incurred.

The Agency, in close cooperation with ENTSO for Electricity, shall organise stakeholder involvement regarding secure system operation and other aspects of the implementation of this Regulation. Such involvement shall include regular meetings with stakeholders to identify problems and propose improvements related to the secure system operation.

TSOs responsible for submitting proposals for terms and conditions or methodologies or their amendments in accordance with this Regulation shall consult stakeholders, including the relevant authorities of each Member State, on the draft proposals for terms and conditions or methodologies listed in Article 6(2) and (3). The consultation shall last for a period of not less than 1 month.

The proposals for terms and conditions or methodologies submitted by the TSOs at Union level shall be published and submitted to public consultation at Union level. Proposals submitted by the TSOs at regional level shall be submitted to public consultation at least at regional level. Parties submitting proposals at bilateral or at multilateral level shall carry out a public consultation at least in the Member States concerned.

The TSOs responsible for developing the proposal for terms and conditions or methodologies shall duly take into account the views of stakeholders resulting from the consultations prior to its submission for regulatory approval. In all cases, a sound justification for including or not including the views resulting from the consultation shall be provided together with the submission of the proposal and published in a timely manner before, or simultaneously with the publication of the proposal for terms and conditions or methodologies.

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

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

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

Without prejudice to cases covered by national or Union legislation, regulatory authorities, bodies or persons who receive confidential information pursuant to this Regulation may use it only for the purpose of carrying out their duties under this Regulation.

Where a synchronous area encompasses both union and third country TSOs, within 18 months after entry into force of this Regulation, all Union TSOs in that synchronous area shall endeavour to conclude with the third country TSOs not bound by this Regulation an agreement setting the basis for their cooperation concerning secure system operation and setting out arrangements for the compliance of the third country TSOs with the obligations set in this Regulation.

ENTSO for Electricity shall monitor the implementation of this Regulation in accordance with Article 8(8) of Regulation 2009/714. Monitoring shall cover at least the following matters:

operational security indicators in accordance with Article 15;

load-frequency control in accordance with Article 16;

regional coordination assessment in accordance with Article 17;

identification of any divergences in the national implementation of this Regulation for the terms and conditions or methodologies listed in Article 6(3);

identification of any additional improvements of tools and services in accordance with subparagraphs (a) and (b) of Article 55, beyond the improvements identified by the TSOs in accordance with Article 55(e);

identification of any necessary improvements in the annual report on incidents classification scale in accordance with Article 15, which are necessary in order to support sustainable and long-term operational security; and

identification of any difficulties concerning cooperation on secure system operation with third country TSOs.

The Agency, in cooperation with ENTSO for Electricity, shall produce within 12 months from the entry into force of this Regulation a list of the relevant information to be communicated by ENTSO for Electricity to the Agency in accordance with Articles 8(9) and 9(1) of Regulation 2009/714. The list of relevant information may be subject to updates. ENTSO for Electricity shall maintain a comprehensive, standardised format, digital data archive of the information required by the Agency.

Relevant TSOs shall submit to ENTSO for Electricity the information required to perform the tasks referred to in paragraphs 1 and 2.

Based on a request of the regulatory authority, DSOs shall provide TSOs with the information under paragraph 2 unless that information is already available to the regulatory authorities, TSOs, the Agency or ENTSO for Electricity in relation to their respective implementation monitoring tasks, with the objective of avoiding duplication of information.

By 30 September, ENTSO for Electricity shall publish an annual report based on the incidents classification scale adopted in accordance with Article 8(3) (a) of Regulation 2009/714. The Agency may provide its opinion on the format and contents of that annual report, including the geographical scope of the incidents reported, the electrical interdependencies between the TSOs' control areas and any relevant historical information.

The TSOs of each Member State shall provide ENTSO for Electricity, by 1 March, with the necessary data and information for the preparation of the annual reports based on the incident classification scale referred to in paragraph 1. The data provided by the TSOs shall cover the preceding year.

The annual reports referred to in paragraph 1 shall contain at least the following operational security indicators relevant to operational security:

number of tripped transmission system elements per year per TSO;

number of tripped power generation facilities per year per TSO;

energy not supplied per year due to unscheduled disconnection of demand facilities per TSO;

time duration and number of instances of being in the alert and emergency states per TSO;

time duration and number of events within which there was a lack of reserves identified per TSO;

time duration and number of voltage deviations exceeding the ranges from Tables 1 and 2 of Annex II per TSO;

number of minutes outside the standard frequency range and number of minutes outside the 50 % of maximum steady state frequency deviation per synchronous area;

number of system-split separations or local blackout states; and

number of blackouts involving two or more TSOs.

The annual report referred to in paragraph 1 shall contain the following operational security indicators relevant to operational planning:

number of events in which an incident contained in the contingency list led to a degradation of the system operation state;

number of the events referred to in point (a) in which a degradation of system operation conditions occurred as a result of unexpected discrepancies from load or generation forecasts;

number of events in which there was a degradation in system operation conditions due to an exceptional contingency;

number of the events referred to in point (c) in which a degradation of system operation conditions occurred as a result of unexpected discrepancies from load or generation forecasts; and

number of events leading to a degradation in system operation conditions due to lack of active power reserves.

The annual reports shall contain explanations of the reasons for incidents at the operational security ranking scales 2 and 3 as per the incidents classification scale adopted by ENTSO for Electricity. Those explanations shall be based on an investigation of the incidents by TSOs which process shall be set out in the incidents classification scale. TSOs shall inform the respective regulatory authorities about an investigation in due time before it is launched. Regulatory authorities and the Agency may be involved in the investigation upon their request.

By 30 September, ENTSO for Electricity shall publish an annual report on load-frequency control based on the information provided by the TSOs in accordance with paragraph 2. The annual report on load-frequency control shall include the information listed in paragraph 2 for each Member State.

Starting from 14 September 2018, the TSOs of each Member State shall notify to ENTSO for Electricity, by 1 March every year, the following information for the previous year:

the identification of the LFC blocks, LFC areas and monitoring areas in the Member State;

the identification of LFC blocks that are not in the Member State and that contain LFC areas and monitoring areas that are in the Member State;

the identification of the synchronous areas each Member State belongs to;

the data related to the frequency quality evaluation criteria for each synchronous area and each LFC block in subparagraphs (a), (b) and (c) covering each month of at least 2 previous calendar years;

the FCR obligation and the initial FCR obligation of each TSO operating within the Member State covering each month of at least 2 previous calendar years; and

a description and date of implementation of any mitigation measures and ramping requirements to alleviate deterministic frequency deviations taken in the previous calendar year in accordance with Articles 137 and 138, in which TSOs of the Member State were involved.

The data provided by the TSOs shall cover the preceding year. The information concerning synchronous areas, LFC blocks, LFC areas and monitoring areas in subparagraphs (a), (b) and (c) shall be reported once. Where these areas change, this information shall be reported by 1 March of the following year.

Where appropriate, all TSOs of a synchronous area or LFC block shall cooperate in collecting the data listed in paragraph 2.

By 30 September, ENTSO for Electricity shall publish an annual report on regional coordination assessment based on the annual reports on regional coordination assessment provided by the regional security coordinators in accordance with paragraph 2, assess any interoperability issues and propose changes aiming at improving effectiveness and efficiency in the system operation coordination.

By 1 March, each regional security coordinator shall prepare an annual report and submit it to ENTSO for Electricity providing the following information for the tasks it performs:

the number of events, average duration and reasons for the failure to fulfil its functions;

the statistics regarding constraints, including their duration, location and number of occurrences together with the associated remedial actions activated and their cost in case they have been incurred;

the number of instances where TSOs refuse to implement the remedial actions recommended by the regional security coordinator and the reasons thereof;

the number of outage incompatibilities detected in accordance with Article 80; and

a description of the cases where the lack of regional adequacy has been assessed and a description of mitigation actions set in place.

The data provided to ENTSO for Electricity by the regional security coordinators shall cover the preceding year.

A transmission system shall be in the normal state when all of the following conditions are fulfilled:

voltage and power flows are within the operational security limits defined in accordance with Article 25;

frequency meets the following criteria:

the steady state system frequency deviation is within the standard frequency range; or

the absolute value of the steady state system frequency deviation is not larger than the maximum steady state frequency deviation and the system frequency limits established for the alert state are not fulfilled;

active and reactive power reserves are sufficient to withstand contingencies from the contingency list defined in accordance with Article 33 without violating operational security limits;

operation of the concerned TSO's control area is and will remain within operational security limits after the activation of remedial actions following the occurrence of a contingency from the contingency list defined in accordance with Article 33.

A transmission system shall be in the alert state when:

voltage and power flows are within the operational security limits defined in accordance with Article 25; and

the TSO's reserve capacity is reduced by more than 20 % for longer than 30 minutes and there are no means to compensate for that reduction in real-time system operation; or

frequency meets the following criteria:

the absolute value of the steady state system frequency deviation is not larger than the maximum steady state frequency deviation; and

the absolute value of the steady state system frequency deviation has continuously exceeded 50 % of the maximum steady state frequency deviation for a time period longer than the alert state trigger time or the standard frequency range for a time period longer than time to restore frequency; or

at least one contingency from the contingency list defined in accordance with Article 33 leads to a violation of the TSO's operational security limits, even after the activation of remedial actions.

A transmission system shall be in the emergency state when at least one of the following conditions is fulfilled:

there is at least one a violation of a TSO's operational security limits defined in accordance with Article 25;

frequency does not meet the criteria for the normal state and for the alert state defined in accordance with paragraphs 1 and 2;

at least one measure of the TSO's system defence plan is activated;

there is a failure in the functioning of tools, means and facilities defined in accordance with Article 24(1), resulting in the unavailability of those tools, means and facilities for longer than 30 minutes.

A transmission system shall be in the blackout state when at least one of the following conditions is fulfilled:

loss of more than 50 % of demand in the concerned TSO's control area;

total absence of voltage for at least three minutes in the concerned TSO's control area, leading to the triggering of restoration plans.

A TSO of GB and IE/NI synchronous areas may develop a proposal specifying the level of demand loss at which the transmission system shall be in the blackout state. The TSOs of GB and IE/NI synchronous areas shall notify this instance to ENTSO for Electricity.

A transmission system shall be in the restoration state when a TSO, being in the emergency or blackout state, has started to activate measures of its restoration plan.

Each TSO shall, in real-time operation, determine the system state of its transmission system.

Each TSO shall monitor the following transmission system parameters in real-time in its control area, based on real-time telemetry measurements or on calculated values from its observability area, taking into account the structural and real-time data in accordance with Article 42:

active and reactive power flows;

busbar voltages;

frequency and frequency restoration control error of its LFC area;

active and reactive power reserves; and

generation and load.

In order to specify the system state, each TSO shall perform contingency analysis at least once every 15 minutes, monitoring the transmission system's parameters defined in accordance with paragraph 2, against the operational security limits defined in accordance with Article 25 and the criteria for system states defined in accordance with Article 18. Each TSO shall also monitor the level of available reserves against the reserve capacity. When carrying out the contingency analysis, each TSO shall take into account the effect of remedial actions and the measures of the system defence plan.

If its transmission system is not in normal state and if that system state is qualified as a wide area state the TSO shall:

inform all TSOs about the system state of its transmission system via an IT tool for the exchange of real-time data at pan-European level; and

provide with additional information on its transmission system elements which are part of the observability area of other TSOs, to those TSOs.

Each TSO shall endeavour to ensure that its transmission system remains in the normal state and shall be responsible for managing operational security violations. To achieve that objective, each TSO shall design, prepare and activate remedial actions taking into account their availability, the time and resources needed for their activation and any conditions external to the transmission system which are relevant for each remedial action.

The remedial actions used by TSOs in system operation in accordance with paragraph 1 and with Articles 21 to 23 of this Regulation shall be consistent with the remedial actions taken into account in capacity calculation in accordance with Article 25 of GCACMR.

Each TSO shall apply the following principles when activating and coordinating remedial actions in accordance with Article 23:

for operational security violations which do not need to be managed in a coordinated way, a TSO shall design, prepare and activate remedial actions to restore the system to the normal state and to prevent the propagation of the alert or emergency state outside of the TSO's control area from the categories defined in Article 22;

for operational security violations which need to be managed in a coordinated way, a TSO shall design, prepare and activate remedial actions in coordination with other concerned TSOs, following the methodology for the preparation of remedial actions in a coordinated way under Article 76(1) (b) and taking into account the recommendation of a regional security coordinator in accordance with Article 78(4).

When selecting the appropriate remedial actions, each TSO shall apply the following criteria:

activate the most effective and economically efficient remedial actions;

activate remedial actions as close as possible to real-time taking into account the expected time of activation and the urgency of the system operation situation they intend to resolve;

consider the risks of failures in applying the available remedial actions and their impact on operational security such as:

the risks of failure or short-circuit caused by topology changes;

the risks of outages caused by active or reactive power changes on power generating modules or demand facilities; and

the risks of malfunction caused by equipment behaviour;

give preference to remedial actions which make available the largest cross-zonal capacity for capacity allocation, while satisfying all operational security limits.

Each TSO shall use the following categories of remedial actions:

modify the duration of a planned outage or return to service transmission system elements to achieve the operational availability of those transmission system elements;

actively impact power flows by means of:

tap changes of the power transformers;

tap changes of the phase-shifting transformers;

modifying topologies;

control voltage and manage reactive power by means of:

tap changes of the power transformers;

switching of the capacitors and reactors;

switching of the power-electronics-based devices used for voltage and reactive power management;

instructing transmission-connected DSOs and significant grid users to block automatic voltage and reactive power control of transformers or to activate on their facilities the remedial actions set out in points (i) to (iii) if voltage deterioration jeopardises operational security or threatens to lead to a voltage collapse in a transmission system;

requesting the change of reactive power output or voltage setpoint of the transmission-connected synchronous power generating modules;

requesting the change of reactive power output of the converters of transmission-connected non-synchronous power generating modules;

re-calculate day-ahead and intraday cross-zonal capacities in accordance with GCACMR;

redispatch transmission or distribution-connected system users within the TSO's control area, between two or more TSOs;

countertrade between two or more bidding zones;

adjust active power flows through HVDC systems;

activate frequency deviation management procedures;

curtail, pursuant to Article 16(2) of Regulation 2009/714, the already allocated cross-zonal capacity in an emergency situation where using that capacity endangers operational security, all TSOs at a given interconnector agree to such adjustment, and re-dispatching or countertrading is not possible; and

where applicable, include the normal or alert state, manually controlled load-shedding.

Where necessary and justified in order to maintain operational security, each TSO may prepare and activate additional remedial actions. The TSO shall report and justify those instances to the relevant regulatory authority and, where applicable, the Member State, at least once every year, after the activation of the additional remedial actions. The relevant reports and justifications shall also be published. The European Commission or the Agency may request the relevant regulatory authority to provide additional information concerning the activation of additional remedial actions in those instances where they affect a neighbouring transmission system.

Each TSO shall prepare and activate remedial actions in accordance with the criteria set out in Article 21(2) to prevent the system state from deteriorating on the basis of the following elements:

the monitoring and determination of system states in accordance with Article 19;

the contingency analysis in real-time operation in accordance with Article 34; and

the contingency analysis in operational planning in accordance with Article 72.

When preparing and activating a remedial action, including redispatching or countertrading pursuant to Articles 25 and 35 of GCACMR, or a procedure of a TSO's system defence plan which affects other TSOs, the relevant TSO shall assess, in coordination with the TSOs concerned, the impact of such remedial action or measure within and outside of its control area, in accordance with Article 75(1), Article 76(1)(b) and Article 78(1), (2) and (4) and shall provide the TSOs concerned with the information about this impact.

When preparing and activating remedial actions which have an impact on the transmission-connected SGUs and DSOs, each TSO shall, if its transmission system is in normal or alert state, assess the impact of such remedial actions in coordination with the affected SGUs and DSOs and select remedial actions that contribute to maintaining normal state and secure operation of all involved parties. Each affected SGU and DSO shall provide to the TSO all necessary information for this coordination.

When preparing and activating remedial actions each TSO shall, if its transmission system is not in normal or alert state, coordinate to the extent possible such remedial actions with the affected transmission-connected SGUs and DSOs to maintain the operational security and the integrity of the transmission system.
When a TSO activates a remedial action each impacted transmission-connected significant grid user and DSO shall execute the instructions given by the TSO

Where constraints have only consequences on the local state within the TSO's control area and the operational security violation does not need to be managed in a coordinated way, the TSO responsible for its management may decide not to activate remedial actions with costs to relieve them.

Each TSO shall ensure the availability, reliability and redundancy of the following items:

facilities for monitoring the system state of the transmission system, including state estimation applications and facilities for load-frequency control;

means to control the switching of circuit breakers, coupler circuit breakers, transformer tap changers and other equipment which serve to control transmission system elements;

means to communicate with the control rooms of other TSOs and RSCs;

tools for operational security analysis; and

tools and communication means necessary for TSOs to facilitate cross-border market operations.

Where the TSO's tools, means and facilities referred to in paragraph 1 affect the transmission-connected DSOs or SGUs involved in supplying balancing services, ancillary services or in system defence or restoration or in delivery of real-time operational data according to Articles 44, 47, 50, 51 and 52, the relevant TSO and those DSOs and SGUs shall cooperate and coordinate to specify and ensure the availability, reliability and redundancy of these tools, means and facilities.

Within 18 months from the entry into force of this Regulation each TSO shall adopt a business continuity plan detailing its responses to a loss of critical tools, means and facilities, containing provisions for their maintenance, replacement and development. Each TSO shall review at least annually its business continuity plan and update it as necessary and in any case following any significant change of the critical tools, means and facilities or of the relevant system operation conditions. The TSO shall share parts of the business continuity plan which affect DSOs and SGUs with the DSOs and SGUs concerned.

Each TSO shall specify the operational security limits for each element of its transmission system, taking into account at least the following physical characteristics:

voltage limits in accordance with Article 27;

short-circuit current limits according to Article 30; and

current limits in terms of thermal rating including the transitory admissible overloads.

When defining the operational security limits, each TSO shall take into account the capabilities of SGUs to prevent that voltage ranges and frequency limits in normal and alert states lead to their disconnection.

In case of changes of one of its transmission system elements, each TSO shall validate and where necessary update the operational security limits.

For each interconnector each TSO shall agree with the neighbouring TSO on common operational security limits in accordance with paragraph 1.

Each TSO shall specify, taking into account Article 5 of Council Directive 2008/114 ( 10 ) , a confidential security plan containing a risk assessment of assets owned or operated by the TSO, covering major physical or cyber threat scenarios determined by the Member State.

The security plan shall consider potential impacts to the European interconnected transmission systems, and include organizational and physical measures aiming at mitigating the identified risks.

Each TSO shall regularly review the security plan to address changes of threat scenarios and reflect the evolution of the transmission system.

In accordance with Article 18, each TSO shall endeavour to ensure that during the normal state the voltage remains in steady-state at the connection points of the transmission system within the ranges specified in the Tables 1 and 2 of Annex II.

If the relevant TSO in Spain requires in accordance with Article 16(2) of NCRGCGR that power generating modules connected to nominal voltages between 300 and 400 kV stay connected in the voltage range from 1,05 to 1,0875 per unit for an unlimited time, that additional voltage range shall be considered by the relevant TSO in Spain when complying with paragraph 1.

Each TSO shall define the voltage base for the per unit values' notation.

Each TSO shall endeavour to ensure that, during the normal state and after the occurrence of a contingency, the voltage remains, within wider voltage ranges for limited times of operation if there is agreement about those wider voltage ranges with transmission-connected DSOs, power generating facility owners in accordance with Article 16(2) of NCRGCGR or HVDC system owners in accordance with Article 18 of Regulation 2016/1447.

Each TSO shall agree, with the transmission-connected DSOs and the transmission-connected significant grid users, about voltage ranges at the connection points below 110 kV if those voltage ranges are relevant for maintaining operational security limits. Each TSO shall endeavour to ensure that the voltage remains within the agreed range during the normal state and after the occurrence of a contingency.

By 3 months after entry into force of this Regulation, all SGUs which are transmission-connected power generating modules not subject to Article 16 of NCRGCGR, or which are HVDC systems not subject to Article 18 of Regulation 2016/1447, shall inform their TSO about their capabilities compared to the voltage requirements in Article 16 of NCRGCGR or in Article 18 of Regulation 2016/1447, declaring their voltage capabilities and the time they can withstand without disconnection.

SGUs which are demand facilities subject to the requirements of Article 3 of NCDCR shall not disconnect due to a disturbance within the voltage ranges referred to in Article 27. By 3 months after entry into force of this Regulation, SGUs which are transmission-connected demand facilities and which are not subject to Article 3 of NCDCR shall inform their TSO about their capabilities in relation to the voltage requirements defined in Annex II of NCDCR declaring their voltage capabilities and the time they can withstand without disconnection.

Each SGU which is a transmission-connected demand facility shall maintain the reactive power setpoints, power factor ranges and voltage setpoints for voltage control in the range agreed with its TSO in accordance with Article 27.

If voltage at a connection point to the transmission system is outside the ranges defined in Tables 1 and 2 of Annex II to this Regulation, each TSO shall apply voltage control and reactive power management remedial actions in accordance with Article 22(1) (c) of this Regulation in order to restore voltage at the connection point within the range specified in Annex II and within time range specified in Article 16 of NCRGCGR and Article 13 of NCDCR.

Each TSO shall take into account in its operational security analysis the voltage values at which transmission-connected SGUs not subject to the requirements of NCRGCGR or NCDCR may disconnect.

Each TSO shall ensure reactive power reserve, with adequate volume and time response, in order to keep the voltages within its control area and on interconnectors within the ranges set out in Annex II.

TSOs interconnected by AC interconnectors shall jointly specify the adequate voltage control regime in order to ensure that the common operational security limits established in accordance with Article 25(4) are respected.

Each TSO shall agree with each transmission-connected DSO on the reactive power setpoints, power factor ranges and voltage setpoints for voltage control at the connection point between the TSO and the DSO in accordance with Article 15 of NCDCR. To ensure that those parameters are maintained, each transmission-connected DSO shall use its reactive power resources and have the right to give voltage control instructions to distribution-connected SGUs.

Each TSO shall be entitled to use all available transmission-connected reactive power capabilities within its control area for effective reactive power management and maintaining the voltage ranges set out in Tables 1 and 2 of Annex II of this Regulation.

Each TSO shall, directly or indirectly in coordination with the transmission-connected DSO where applicable, operate reactive power resources within its control area, including the blocking of automatic voltage/reactive power control of transformers, voltage reduction and low voltage demand disconnection, in order to maintain operational security limits and to prevent a voltage collapse of the transmission system.

Each TSO shall determine the voltage control actions in coordination with the transmission-connected SGUs and DSOs and with neighbouring TSOs.

When relevant for the voltage control and reactive power management of the transmission system, a TSO may require, in coordination with a DSO, a distribution-connected SGU to follow voltage control instructions.

Each TSO shall determine:

the maximum short-circuit current at which the rated capability of circuit breakers and other equipment is exceeded; and

the minimum short-circuit current for the correct operation of protection equipment.

Each TSO shall perform short-circuit current calculations in order to evaluate the impact of neighbouring TSOs and transmission-connected SGUs and transmission-connected distribution systems including closed distribution systems on the short-circuit current levels in transmission system. Where a transmission-connected distribution system including closed distribution system has an impact on short-circuit current levels, it shall be included in the transmission system short-circuit current calculations.

While performing short-circuit current calculations, each TSO shall:

use the most accurate and high quality available data;

take into account international standards; and

consider as the basis of the maximum short-circuit current calculation such operational conditions, which provide the highest possible level of short-circuit current, including the short-circuit current from other transmission systems and distribution systems including closed distribution systems.

Each TSO shall apply operational or other measures to prevent deviation from the maximum and minimum short-circuit current limits referred to in Article 30, at all time-frames and for all protection equipment. If such a deviation occurs, each TSO shall activate remedial actions or apply other measures to ensure that the limits referred to in Article 30 are re-established. A deviation from those limits is allowed only during switching sequences.

Each TSO shall maintain power flows within the operational security limits defined when the system is in normal state and after the occurrence of a contingency from the contingency list referred to in Article 33(1).

In the (N-1)-situation, in the normal state each TSO shall maintain power flows within the transitory admissible overloads referred to in Article 25(1) (c), having prepared remedial actions to be applied and executed within the time-frame allowed for transitory admissible overloads.

Each TSO shall establish a contingency list, including the internal and external contingencies of its observability area, by assessing whether any of those contingencies endangers the operational security of the TSO's control area. The contingency list shall include both ordinary contingencies and exceptional contingencies identified by application of the methodology developed pursuant to Article 75.

To establish a contingency list, each TSO shall classify each contingency on the basis of whether it is ordinary, exceptional or out-of-range, taking into account the probability of occurrence and the following principles:

each TSO shall classify contingencies for its own control area;

when operational or weather conditions significantly increase the probability of an exceptional contingency, each TSO shall include that exceptional contingency in its contingency list; and

in order to account for exceptional contingencies with high impact on its own or neighbouring transmission systems, each TSO shall include such exceptional contingencies in its contingency list.

Each transmission-connected DSO and SGU which is a power generating facility shall deliver all information relevant for contingency analysis as requested by the TSO, including forecast and real-time data, with possible data aggregation in accordance with Article 50(2).

Each TSO shall coordinate its contingency analysis in terms of coherent contingency lists at least with the TSOs from its observability area, in accordance with the Article 75.

Each TSO shall inform the TSOs in its observability area about the external contingencies included in its contingency list.

Each TSO shall inform, sufficiently in advance, the TSOs concerned in its observability area of any intended topological changes on its transmission system elements which are included as external contingencies in the contingency lists of the TSOs concerned.

Each TSO shall ensure that the real-time data is sufficiently accurate to allow the convergence of load-flow calculations which are performed in the contingency analysis.

Each TSO shall perform contingency analysis in its observability area in order to identify the contingencies which endanger or may endanger the operational security of its control area and to identify the remedial actions that may be necessary to address the contingencies, including mitigation of the impact of exceptional contingencies.

Each TSO shall ensure that potential violations of the operational security limits in its control area which are identified by the contingency analysis do not endanger the operational security of its transmission system or of interconnected transmission systems.

Each TSO shall perform contingency analysis based on the forecast of operational data and on real-time operational data from its observability area. The starting point for the contingency analysis in the N-Situation shall be the relevant topology of the transmission system which shall include planned outages in the operational planning phases.

Each TSO shall assess the risks associated with the contingencies after simulating each contingency from its contingency list and after assessing whether it can maintain its transmission system within the operational security limits in the (N-1) situation.

When a TSO assesses that the risks associated with a contingency are so significant that it might not be able to prepare and activate remedial actions in a timely manner to prevent non-compliance with the (N-1) criterion or that there is a risk of propagation of a disturbance to the interconnected transmission system, the TSO shall prepare and activate remedial actions to achieve compliance with the (N-1) criterion as soon as possible.

In case of an (N-1) situation caused by a disturbance, each TSO shall activate a remedial action in order to ensure that the transmission system is restored to a normal state as soon as possible and that this (N-1) situation becomes the new N-Situation.

A TSO shall not be required to comply with the (N-1) criterion in the following situations:

during switching sequences;

during the time period required to prepare and activate remedial actions.

Unless a Member State determines otherwise, a TSO shall not be required to comply with the (N-1) criterion as long as there are only local consequences within the TSO's control area.

Each TSO shall operate its transmission system with the protection and backup protection equipment in order to automatically prevent the propagation of disturbances that could endanger the operational security of its own transmission system and of the interconnected system.

At least once every 5 years, each TSO shall review its protection strategy and concepts and update them where necessary to ensure the correct functioning of the protection equipment and the maintenance of operational security.

After a protection operation which had an impact outside a TSO's control area including interconnectors, that TSO shall assess whether the protection equipment in its control area worked as planned and shall undertake corrective actions if necessary.

Each TSO shall specify setpoints for the protection equipment of its transmission system that ensure reliable, fast and selective fault clearing, including backup protection for fault clearing in case of malfunction of the primary protection system.

Before protection and backup protection equipment entry into service or following any modifications, each TSO shall agree with the neighbouring TSOs on the definition of protection setpoints for the interconnectors and shall coordinate with those TSOs before changing the settings.

Where a TSO uses a special protection scheme, it shall:

ensure that each special protection scheme acts selectively, reliably and effectively;

evaluate, when designing a special protection scheme, the consequences for the transmission system in the event of its incorrect functioning, taking into account the impact on TSOs concerned;

verify that the special protection scheme has a comparable reliability to the protection systems used for the primary protection of transmission system elements;

operate the transmission system with the special protection scheme within the operational security limits determined in accordance with Article 25; and

coordinate special protection scheme functions, activation principles and setpoints with neighbouring TSOs and affected transmission-connected DSOs, including closed distribution systems and affected transmission-connected SGUs.

Each TSO shall monitor the dynamic stability of the transmission system by studies conducted offline in accordance with paragraph 6. Each TSO shall exchange the relevant data for monitoring the dynamic stability of the transmission system with the other TSOs of its synchronous area.

Each TSO shall perform a dynamic stability assessment at least once a year to identify the stability limits and possible stability problems in its transmission system. All TSOs of each synchronous area shall coordinate the dynamic stability assessments, which shall cover all or parts of the synchronous area.

When performing coordinated dynamic stability assessments, concerned TSOs shall determine:

the scope of the coordinated dynamic stability assessment, at least in terms of a common grid model;

the set of data to be exchanged between concerned TSOs in order to perform the coordinated dynamic stability assessment;

a list of commonly agreed scenarios concerning the coordinated dynamic stability assessment; and

a list of commonly agreed contingencies or disturbances whose impact shall be assessed through the coordinated dynamic stability assessment.

In case of stability problems due to poorly damped inter-area oscillations affecting several TSOs within a synchronous area, each TSO shall participate in a coordinated dynamic stability assessment at the synchronous area level as soon as practicable and provide the data necessary for that assessment. Such assessment shall be initiated and conducted by the concerned TSOs or by ENTSO for Electricity.

When a TSO identifies a potential influence on voltage, rotor angle or frequency stability in relation with other interconnected transmission systems, the TSOs concerned shall coordinate the methods used in the dynamic stability assessment, providing the necessary data, planning of joint remedial actions aiming at improving the stability, including the cooperation procedures between the TSOs.

In deciding the methods used in the dynamic stability assessment, each TSO shall apply the following rules:

if, with respect to the contingency list, steady-state limits are reached before stability limits, the TSO shall base the dynamic stability assessment only on the offline stability studies carried out in the longer term operational planning phase;

if, under planned outage conditions, with respect to the contingency list, steady-state limits and stability limits are close to each other or stability limits are reached before steady-state limits, the TSO shall perform a dynamic stability assessment in the day-ahead operational planning phase while those conditions remain. The TSO shall plan remedial actions to be used in real-time operation if necessary; and

if the transmission system is in the N-situation with respect to the contingency list and stability limits are reached before steady-state limits, the TSO shall perform a dynamic stability assessment in all phases of operational planning and re-assess the stability limits as soon as possible after a significant change in the N-situation is detected.

Where the dynamic stability assessment indicates that there is a violation of stability limits, the TSOs in whose control area the violation has appeared shall design, prepare and activate remedial actions to keep the transmission system stable. Those remedial actions may involve SGUs.

Each TSO shall ensure that the fault clearing times for faults that may lead to wide area state transmission system instability are shorter than the critical fault clearing time calculated by the TSO in its dynamic stability assessment carried out in accordance with Article 38.

In relation to the requirements on minimum inertia which are relevant for frequency stability at the synchronous area level:

all TSOs of that synchronous area shall conduct, not later than 2 years after entry into force of this Regulation, a common study per synchronous area to identify whether the minimum required inertia needs to be established, taking into account the costs and benefits as well as potential alternatives. All TSOs shall notify their studies to their regulatory authorities. All TSOs shall conduct a periodic review and shall update those studies every 2 years;

where the studies referred to in point (a) demonstrate the need to define minimum required inertia, all TSOs from the concerned synchronous area shall jointly develop a methodology for the definition of minimum inertia required to maintain operational security and to prevent violation of stability limits. That methodology shall respect the principles of efficiency and proportionality, be developed within 6 months after the completion of the studies referred to in point (a) and shall be updated within 6 months after the studies are updated and become available; and

each TSO shall deploy in real-time operation the minimum inertia in its own control area, according to the methodology defined and the results obtained in accordance with paragraph (b).

The exchange and provision of data and information pursuant to this Title shall reflect, to the extent possible, the real and forecasted situation of the transmission system.

Each TSO shall be responsible for providing and using high quality data and information.

Each TSO shall gather the following information about its observability area and shall exchange this data with all other TSOs to the extent that it is necessary for carrying out the operational security analysis in accordance with Article 72:

generation;

consumption;

schedules;

balance positions;

planned outages and substation topologies; and

forecasts.

Each TSO shall represent the information in paragraph (3) as injections and withdrawals at each node of the TSO's individual grid model referred to in Article 64.

In coordination with the DSOs and SGUs, each TSO shall determine the applicability and scope of the data exchange based on the following categories:

structural data in accordance with Article 48;

scheduling and forecast data in accordance with Article 49;

real-time data in accordance with Articles 44, 47 and 50; and

provisions in accordance with Articles 51, 52 and 53.

By 6 months after entry into force of this Regulation, all TSOs shall jointly agree on key organisational requirements, roles and responsibilities in relation to data exchange. Those organisational requirements, roles and responsibilities 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 GCACMR. They shall apply to all data exchange provisions in this Title and shall include organisational requirements, roles and responsibilities for the following elements:

obligations for TSOs to communicate without delay to all neighbouring TSOs any changes in the protection settings, thermal limits and technical capacities at the interconnectors between their control areas;

obligations for DSOs directly connected to the transmission system to inform the TSOs they are connected to, within the agreed timescales, of any changes in the data and information pursuant to this Title;

obligations for the adjacent DSOs and/or between the downstream DSO and upstream DSO to inform each other within agreed timescales of any changes in the data and information pursuant to this Title;

obligations for SGUs to inform their TSO or DSO, within agreed timescales, about any relevant changes in the data and information established pursuant to this Title;

detailed contents of the data and information established pursuant to this Title, including main principles, type of data, communication means, format and standards to be applied, timing and responsibilities;

the time stamping and frequency of delivery of the data and information to be provided by DSOs and SGUs, to be used by TSOs in the different timescales. The frequency of information exchanges for real-time data, scheduled data and update of structural data shall be defined; and

the format for the reporting of the data and information established pursuant to this Title.

The organisational requirements, roles and responsibilities shall be published by ENTSO for Electricity.

By 18 months after entry into force of this Regulation, each TSO shall agree with the relevant DSOs on effective, efficient and proportional processes for providing and managing data exchanges between them, including, where required for efficient network operation, the provision of data related to distribution systems and SGUs. Without prejudice to the provisions of paragraph 6(g), each TSO shall agree with the relevant DSOs on the format for the data exchange.

Transmission-connected SGUs shall have access to the data related to their commissioned network installations at the connection point.

Each TSO shall agree with the transmission-connected DSOs on the scope of additional information to be exchanged between them concerning commissioned network installations.

DSOs with a connection point to a transmission system shall be entitled to receive the relevant structural, scheduled and real-time information from the relevant TSOs and to gather the relevant structural, scheduled and real-time information from the neighbouring DSOs. Neighbouring DSOs shall determine, in a coordinated manner, the scope of information that may be exchanged.

Neighbouring TSOs shall exchange at least the following structural information related to the observability area:

the regular topology of substations and other relevant data, by voltage level;

technical data on transmission lines;

technical data on transformers connecting the DSOs, SGUs which are demand facilities and generators' block-transformers of SGUs which are power generating facilities;

the maximum and minimum active and reactive power of SGUs which are power generating modules;

technical data on phase-shifting transformers;

technical data on HVDC systems;

technical data on reactors, capacitors and static volt-ampere reactive (VAR) compensators; and

operational security limits defined by each TSO according to Article 25.

To coordinate the protection of their transmission systems, neighbouring TSOs shall exchange the protection setpoints of the lines for which the contingencies are included as external contingencies in their contingency lists.

To coordinate their operational security analysis and to establish the common grid model in accordance with Articles 67, 68, 69 and 70, each TSO shall exchange, with at least all other TSOs from the same synchronous area, at least the following data:

the topology of the 220 kV and higher voltage transmission systems within its control area;

a model or an equivalent of the transmission system with voltage below 220 kV with significant impact on its own transmission system;

the thermal limits of the transmission system elements; and

a realistic and accurate forecasted aggregate amount of injection and withdrawal, per primary energy source, at each node of the transmission system, for different time-frames.

To coordinate the dynamic stability assessments pursuant to Article 38(2) and (4), and to carry them out, each TSO shall exchange with the other TSOs of the same synchronous area or of its relevant part the following data:

data concerning SGUs which are power generating modules relating to, but not limited to:

electrical parameters of the alternator suitable for the dynamic stability assessment, including total inertia;

protection models;

alternator and prime mover;

step-up transformer description;

minimum and maximum reactive power;

voltage models and speed controller models; and

prime movers models and excitation system models suitable for large disturbances;

the data on type of regulation and voltage regulation range concerning tap changers, including the description of existing on-load tap changers, and the data on type of regulation and voltage regulation range concerning step-up and network transformers; and

the data concerning HVDC systems and FACTS devices on the dynamic models of the system or the device and its associated regulation suitable for large disturbances.

In accordance with Articles 18 and 19, each TSO shall exchange with the other TSOs of the same synchronous area the following data on the system state of its transmission system using the IT tool for real-time data exchange at pan-European level as provided by ENTSO for Electricity:

frequency;

frequency restoration control error;

measured active power interchanges between LFC areas;

aggregated generation infeed;

system state in accordance with Article 18;

setpoint of the load-frequency controller; and

power interexchange via virtual tie-lines.

Each TSO shall exchange with the other TSOs in its observability area the following data about its transmission system using real-time data exchanges between the TSOs' supervisory control and data acquisition (SCADA) systems and energy management systems:

actual substation topology;

active and reactive power in line bay, including transmission, distribution and lines connecting SGUs;

active and reactive power in transformer bay, including transmission, distribution and SGUs connecting transformers;

active and reactive power in power generating facility bay;

regulating positions of transformers, including phase-shifting transformers;

measured or estimated busbar voltage;

reactive power in reactor and capacitor bay or from a static VAR compensator; and

restrictions on active and reactive power supply capabilities with respect to the observability area.

Each TSO shall have the right to request all TSOs from its observability area to provide real-time snapshots of state estimated data from that TSO's control area if that is relevant for the operational security of the transmission system of the requesting TSO.

Each TSO shall determine the observability area of the transmission-connected distribution systems which is needed for the TSO to determine the system state accurately and efficiently, based on the methodology developed in accordance with Article 75.

If a TSO considers that a non-transmission-connected distribution system has a significant influence in terms of voltage, power flows or other electrical parameters for the representation of the transmission system's behaviour, such distribution system shall be defined by the TSO as being part of the observability area in accordance with Article 75.

The structural information related to the observability area referred to in paragraphs 1 and 2 provided by each DSO to the TSO shall include at least:

substations by voltage;

lines that connect the substations referred to in point (a);

transformers from the substations referred to in point (a);

SGUs; and

reactors and capacitors connected to the substations referred to in point (a).

Each transmission-connected DSO shall provide the TSO with an update of the structural information in accordance with paragraph 3 at least every 6 months.

At least once a year, each transmission-connected DSO shall provide the TSO, per primary energy sources, the total aggregated generating capacity of the type A power generating modules subject to requirements of NCRGCGR and the best possible estimates of generating capacity of type A power generating modules not subject to or derogated from NCRGCGR, connected to its distribution system, and the related information concerning their frequency behaviour.

Unless otherwise provided by the TSO, each DSO shall provide its TSO, in real-time, the information related to the observability area of the TSO as referred to in Article 43(1) and (2), including:

the actual substation topology;

the active and reactive power in line bay;

the active and reactive power in transformer bay;

the active and reactive power injection in power generating facility bay;

the tap positions of transformers connected to the transmission system;

the busbar voltages;

the reactive power in reactor and capacitor bay;

the best available data for aggregated generation per primary energy source in the DSO area; and

the best available data for aggregated demand in the DSO area.

Each SGU which is a power generating facility owner of a type D power generating module connected to the transmission system shall provide the TSO with at least the following data:

general data of the power generating module, including installed capacity and primary energy source;

turbine and power generating facility data including time for cold and warm start;

data for short-circuit current calculation;

power generating facility transformer data;

FCR data of power generating modules offering or providing that service, in accordance with Article 154;

FRR data of power generating modules offering or providing that service, in accordance with Article 158;

RR data of power generating modules that offer or provide that service in accordance with Article 161;

data necessary for restoration of the transmission system;

data and models necessary for performing dynamic simulation;

protection data;

data necessary for determining the costs of remedial actions in accordance with Article 78(1) (b); where a TSO makes use of market based mechanisms in line with Article 4(2) (d), the provision of prices to be paid by the TSO shall be considered sufficient;

voltage and reactive power control capability.

Each SGU which is a power generating facility owner of a type B or a type C power generating module connected to the transmission system shall provide the TSO with at least the following data:

general data of the power generating module, including installed capacity and primary energy source;

data for short-circuit current calculation;

FCR data according to the definition and requirements of the Article 173 for power generating modules offering or providing that service;

FRR data for power generating modules that offer or provide that service;

RR data for power generating modules that offer or provide that service;

protection data;

reactive power control capability;

data necessary for determining the costs of remedial actions in accordance with Article 78(1) (b); where a TSO makes use of market based mechanisms in line with Article 4(2) (d), the provision of prices to be paid by the TSO shall be considered sufficient;

data necessary for performing dynamic stability assessment according to Article 38.

A TSO may request the power generating facility owner of a power generating module connected to the transmission system to provide further data where appropriate for operational security analysis in accordance with Title 2 of Part III.

Each HVDC system owner or interconnector owner shall provide the TSO with the following data regarding the HVDC system or interconnector:

nameplate data of the installation;

transformers data;

data on filters and filter banks;

reactive power compensation data;

active power control capability;

reactive power and voltage control capability;

active or reactive operational mode prioritization, if existing;

frequency response capability;

dynamic models for dynamic simulation;

protection data; and

fault-ride-through capability.

Each AC interconnector owner shall provide the TSO with at least the following data:

nameplate data of the installation;

electrical parameters;

associated protections.

Each SGU which is a power generating facility owner of a type B, C or D power generating module connected to the transmission system shall provide the TSO with at least the following data:

active power output and active power reserves amount and availability, on a day-ahead and intra-day basis;

without any delay, any scheduled unavailability or active power restriction;

any forecasted restriction in the reactive power control capability; and

as an exception to points (a) and (b), in regions with a central dispatch system, data requested by the TSO for the preparation of its active power output schedule.

Each HVDC system operator shall provide the TSOs with at least the following data:

active power schedule and availability on a day-ahead and intra-day basis;

without delay its scheduled unavailability or active power restriction; and

any forecast restriction in the reactive power or voltage control capability.

Each AC interconnector or line operator shall provide its scheduled unavailability or active power restriction data to the TSOs.

Unless otherwise provided by the TSO, each significant grid user which is a power generating facility owner of type B, C or D power generating module shall provide the TSO, in real-time, at least the following data:

position of the circuit breakers at the connection point or another point of interaction agreed with the TSO;

active and reactive power at the connection point or another point of interaction agreed with the TSO; and

in the case of power generating facility with consumption other than auxiliary consumption net active and reactive power.

Unless otherwise provided by the TSO, each HVDC system or AC interconnector owner shall provide, in real-time, at least the following data regarding the connection point of the HVDC system or AC interconnector to the TSOs:

position of the circuit breakers;

operational status; and

active and reactive power.

Unless otherwise provided by the TSO, each power generating facility owner of a power generating module which is a SGU pursuant to Article 2(1)(a) and by aggregation of the SGUs pursuant to Article 2(1)(e) connected to the distribution system shall provide at least the following data to the TSO and to the DSO to which it has a connection point:

general data of the power generating module, including installed capacity and primary energy source or fuel type;

FCR data according to the definition and requirements of Article 173 for power generating facilities offering or providing the FCR service;

FRR data for power generating facilities offering or providing the FRR service;

RR data for power generating modules offering or providing the RR service;

protection data;

reactive power control capability;

capability of remote access to the circuit breaker;

data necessary for performing dynamic simulation according to the provisions in NCRGCGR; and

voltage level and location of each power generating module.

Each power generating facility owner of a power generating module which is a SGU in accordance with Article 2(1) (a) and (e) shall inform the TSO and the DSO to which it has a connection point, within the agreed time and not later than the first commissioning or any changes to the existing installation, about any change in the scope and the contents of the data listed in paragraph 1.

Unless otherwise provided by the TSO, each power generating facility owner of a power generating module which is a SGU in accordance with Article 2(1)(a) and 2(1)(e) connected to the distribution system shall provide the TSO and the DSO to which it has the connection point, with at least the following data:

its scheduled unavailability, scheduled active power restriction and its forecasted scheduled active power output at the connection point;

any forecasted restriction in the reactive power control capability; and

as an exception to paragraphs (a) and (b), in regions with a central dispatch system, data requested by the TSO for the preparation of its active power output schedule.

Unless otherwise provided by the TSO, each power generating facility owner of a power generating module which is a SGU in accordance with Article 2(1)(a) and (e) connected to the distribution system shall provide the TSO and the DSO to which it has the connection point, in real-time, at least the following data:

status of the switching devices and circuit breakers at the connection point; and

active and reactive power flows, current, and voltage at the connection point.

Each TSO shall define in coordination with the responsible DSOs which SGUs may be exempted from providing the real-time data listed in paragraph 1 directly to the TSO. In such cases, the responsible TSOs and DSOs shall agree on the aggregated real-time data of the SGUs concerned to be delivered to the TSO.

Unless otherwise provided by the TSO, each DSO shall provide to its TSO the information specified in Articles 48, 49 and 50 with the frequency and level of detail requested by the TSO.

Each TSO shall make available to the DSO, to whose distribution system SGUs are connected, the information specified in Articles 48, 49 and 50 as requested by the DSO.

A TSO may request further data from a power generating facility owner of a power generating module which is a SGU in accordance with Article 2(1) (a) and (e) connected to the distribution system, if it is necessary for the operational security analysis and for the validation of models.

Unless otherwise provided by the TSO, each transmission-connected demand facility owner shall provide the following structural data to the TSO:

electrical data of the transformers connected to the transmission system;

characteristics of the load of the demand facility; and

characteristics of the reactive power control.

Unless otherwise provided by the TSO, each transmission-connected demand facility owner shall provide the following data to the TSO:

scheduled active and forecasted reactive power consumption on a day-ahead and intraday basis, including any changes of those schedules or forecast;

any forecasted restriction in the reactive power control capability;

in case of participation in demand response, a schedule of its structural minimum and maximum power range to be curtailed; and

by exception to point (a), in regions with a central dispatch system, the data requested by the TSO for the preparation of its active power output schedule.

Unless otherwise provided by the TSO, each transmission-connected demand facility owner shall provide the following data to the TSO in real-time:

active and reactive power at the connection point; and

the minimum and maximum power range to be curtailed.

Each transmission-connected demand facility owner shall describe to its TSO its behaviour at the voltage ranges referred to in Article 27.

Unless otherwise provided by the TSO, each SGU which is a distribution-connected demand facility and which participates in demand response other than through a third party shall provide the following scheduled and real-time data to the TSO and to the DSO:

structural minimum and maximum active power available for demand response and the maximum and minimum duration of any potential usage of this power for demand response;

a forecast of unrestricted active power available for demand response and any planned demand response;

real-time active and reactive power at the connection point; and

a confirmation that the estimations of the actual values of demand response are applied.

Unless otherwise provided by the TSO, each SGU which is a third party participating in demand response as defined in Article 27 of NCDCR, shall provide the TSO and the DSO at the day-ahead and close to real-time and on behalf of all of its distribution-connected demand facilities, with the following data:

structural minimum and maximum active power available for demand response and the maximum and minimum duration of any potential activation of demand response in a specific geographical area defined by the TSO and DSO;

a forecast of unrestricted active power available for the demand response and any planned level of demand response in a specific geographical area defined by the TSO and DSO;

real-time active and reactive power; and

a confirmation that the estimations of the actual values of demand response are applied.

Each SGU shall notify the TSO or DSO to which it has a connection point about any planned modification of its technical capabilities which could have an impact on its compliance with the requirements of this Regulation, prior to its execution.

Each SGU shall notify the TSO or DSO to which it has a connection point about any operational disturbance in its facility which could have an impact on its compliance with the requirements of this Regulation as soon as possible after its occurrence.

Each SGU shall notify the TSO or DSO to which it has a connection point of the planned test schedules and procedures to be followed for verifying the compliance of its facility with the requirements of this Regulation, in due time and prior to their launch. The TSO or DSO shall approve in advance and in a timely manner the planned test schedules and procedures and the approval shall not be unreasonably withheld. Where the SGU has a connection point to the DSO and interacts, pursuant to paragraph 2, only with the DSO, the TSO shall be entitled to request from the concerned DSO any compliance testing results, which are relevant for the operational security of its transmission system.

Upon request from the TSO or DSO, pursuant to Article 41(2) of NCRGCGR and Article 35(2) of NCDCR, the SGU shall carry out compliance tests and simulations in accordance with those Regulations at any time throughout the lifetime of its facility and in particular after any fault, modification or replacement of any equipment, which could have an impact on the facility's compliance with the requirements of this Regulation regarding the capability of the facility to achieve the values declared, the time requirements applicable to those values and the availability or contracted provision of ancillary services. Third parties providing demand response directly to the TSO, providers of redispatching of power generating modules or demand facilities by means of aggregation, and other providers of active power reserves shall ensure that the facilities in their portfolio comply with the requirements of this Regulation.

Each TSO shall be responsible for the operational security of its control area and, in particular, it shall:

develop and implement network operation tools that are relevant for its control area and related to real-time operation and operational planning;

develop and deploy tools and solutions for the prevention and remedy of disturbances;

use services provided by third parties, through procurement when applicable, such as redispatching or countertrading, congestion management services, generation reserves and other ancillary services;

comply with the incidents classification scale adopted by ENTSO for Electricity in accordance with Article 8(3) (a) of Regulation 2009/714 and submit to ENTSO for Electricity the information required to perform the tasks for producing the incidents classification scale; and

monitor on an annual basis the appropriateness of the network operation tools established pursuant to points (a) and (b) required to maintain operational security. Each TSO shall identify any appropriate improvements to those network operation tools, taking into account the annual reports prepared by ENTSO for Electricity based on the incidents classification scale in accordance with Article 15. Any identified enhancement shall be implemented subsequently by the TSO.

Each TSO and each transmission-connected DSO or SGU may perform operational testing respectively of its transmission system elements and of their facilities under simulated operational conditions and for a limited period of time. When doing so, they shall provide notification in due time and prior to the test launch and shall minimise the effect on real-time system operation. The operational testing shall aim at providing:

proof of compliance with all relevant technical and organisational operational provisions of this Regulation for a new transmission system element at its first entry into operation;

proof of compliance with all relevant technical and organisational operational provisions of this Regulation for a new facility of the SGU or of DSO at its first entry into operation;

proof of compliance with all relevant technical and organisational operational provisions of this Regulation upon any change of a transmission system element or a facility of the SGU or of the DSO, which is relevant for system operation;

assessment of possible negative effects of a failure, short-circuit or other unplanned and unexpected incident in system operation, on the transmission system element, or on the facility of the SGU or of the DSO.

The results of the operational testing referred to in paragraph 1 shall be used by a TSO, DSO or a SGU, in order for:

the TSO to ensure correct functioning of transmission system elements;

the DSO and SGUs to ensure correct functioning of distribution systems and of the SGUs' facilities;

the TSO, DSO or SGU to maintain existing and develop new operational practices;

the TSO to ensure fulfilment of ancillary services;

the TSO, DSO or SGU to acquire information about performance of transmission system elements and facilities of the SGUs and DSOs under any conditions and in compliance with all relevant operational provisions of this Regulation, in terms of:

controlled application of frequency or voltage variations aimed at gathering information on transmission system and elements' behaviour; and

tests of operational practices in emergency state and restoration state.

Each TSO shall ensure that operational testing does not endanger the operational security of its transmission system. Any operational testing may be postponed or interrupted due to unplanned system conditions, or due to safety of personnel, of the general public, of the plant or apparatus being tested, or of transmission system elements or of the facilities of the DSO or SGU.

In the event of degradation of the state of the transmission system in which the operational testing is performed, the TSO of that transmission system shall be entitled to interrupt the operational testing. If conducting a test affects another TSO and its system state is also degraded, the TSO or SGU or DSO conducting the test shall, upon being informed by the TSO concerned, immediately cease the operational test.

Each TSO shall ensure that the results of relevant operational tests carried out together with all related analyses are:

incorporated into the training and certification process of the employees in charge of real-time operation;

used as inputs to the research and development process of ENTSO for Electricity; and

used to improve operational practices including also those in emergency and restoration state.

Each TSO or DSO to which the SGU has a connection point retains the right to test a SGU's compliance with the requirements of this Regulation, the SGU's expected input or output and the SGU's contracted provision of ancillary services at any time throughout the lifetime of the facility. The procedure for those operational tests shall be notified to the SGU by the TSO or DSO in due time prior to the launch of the operational test.

The TSO or DSO to which the SGU has a connection point shall publish the list of information and documents to be provided as well as the requirements to be fulfilled by the SGU for operational testing of compliance. Such list shall cover at least the following information:

all documentation and equipment certificates to be provided by the SGU;

details of the technical data of the SGU facility with relevance for the system operation;

requirements for models for dynamic stability assessment; and

studies by the SGU demonstrating expected outcome of the dynamic stability assessment, where applicable.

Where applicable, each TSO or DSO shall publish the allocation of responsibilities of the SGU and of the TSO or DSO for operational testing of compliance.

By 18 months after entry into force of this Regulation each TSO shall develop and adopt:

an initial training program for the certification and a rolling program for the continuous training of its employees in charge of real-time operation of the transmission system;

a training program for its employees in charge of operational planning. Each TSO shall contribute to developing and adopting training programs for employees of the relevant regional security coordinators;

a training program for its employees in charge of balancing.

The TSO's training programs shall include the knowledge of the transmission system elements, the operation of the transmission system, use of the on-the-job systems and processes, inter-TSO operations, market arrangements, recognising of and responding to exceptional situations in system operation, operational planning activities and tools.

TSO employees in charge of real-time operation of transmission system shall, as a part of its initial training, undergo training on interoperability issues between transmission systems based upon operational experiences and feedback from the joint training carried out with neighbouring TSOs in accordance with Article 63. That training on interoperability issues shall include preparation and activation of coordinated remedial actions required in all system states.

Each TSO shall include in its training program for the employees in charge of real-time operation of the transmission system the frequency of the trainings and the following components:

a description of the transmission system elements;

operation of the transmission system in all system states including restoration;

use of the on-the-job systems and processes;

coordination of inter-TSO operations and market arrangements;

recognition of and response to exceptional operational situations;

relevant areas of electrical power engineering;

relevant aspects of the Union internal electricity market;

relevant aspects of the network codes or guidelines adopted according to Articles 6 and 18 of Regulation 2009/714;

safety and security of persons, nuclear and other equipment in transmission system operation;

inter-TSO cooperation and coordination in real-time operation and in operational planning at the level of main control rooms which shall be given in English unless otherwise specified;

joint training with transmission-connected DSOs and SGUs, where appropriate;

behavioural skills with particular focus on stress management, human acting in critical situation, responsibility and motivation skills; and

operational planning practices and tools, including those used with the relevant regional security coordinators in the operational planning.

The training program for employees in charge of operational planning shall include at least the aspects in points (c), (f), (g), (h), (j) and (m) of paragraph 4.

The training program for employees in charge of balancing shall include at least the aspects in points (c), (g) and (h) of paragraph 4.

Each TSO shall maintain records of employees' training programs for their period of employment. Upon request of the relevant regulatory authority, each TSO shall provide the scope and details of its training programs.

Each TSO shall review its training programs at least annually or following significant system changes. Each TSO shall update its training programs to reflect changing operational circumstances, market rules, network configuration and system characteristics, with particular focus on new technologies, changing generation and demand patterns and market evolution.

Each TSO's training programs for employees in charge of real-time operation shall include on-the-job and offline training. On-the-job training shall be carried out under the supervision of an experienced employee in charge of real-time operation. Offline training shall be carried out in an environment which simulates the control room and with network modelling details at a level appropriate to the tasks being trained for.

Each TSO shall implement training for employees in charge of real-time operation based on a comprehensive database model of their network with respective data from other networks of, at least, the observability area, at a level of detail which is sufficient to replicate inter-TSO operational issues. Training scenarios shall be based on real and simulated system conditions. Where relevant, the role of other TSOs, transmission-connected DSOs and significant grid users shall also be simulated unless they can be directly represented in joint trainings.

Each TSO shall coordinate the offline training of the employees in charge of real-time operation with the transmission-connected DSOs and SGUs regarding the impact of their facilities on real-time operation of the transmission system, in a comprehensive and proportionate manner, reflecting the up-to-date network topology and characteristics of secondary equipment. When relevant, TSOs, transmission-connected DSOs and SGUs shall run joint offline training simulations or training workshops.

The training coordinator's responsibilities shall include the designing, monitoring and updating of the training programs, as well as the determination of:

the qualifications and selection process for TSO employees to be trained;

the training required for certification of the system operator employees in charge of real-time operation;

the processes, including relevant documentation, for the initial and the rolling training programs;

the process for certification of system operator employees in charge of real-time operation; and

the process for extension of a training period and certification period for the system operator employees in charge of real-time operation.

Each TSO shall determine the skills and the level of competence of on-the-job trainers. On-the-job trainers shall have an appropriate level of operational experience following their certification.

Each TSO shall have a register of the system operator employees in charge of real-time operation who carry out the functions of on-the-job trainers and review their capability to provide practical training when deciding upon the extension of their certification.

An individual may become a system operator employee in charge of real-time operation provided he or she is trained and subsequently certified by a nominated representative from his or her TSO for the concerned tasks within the timescale defined in the training programme. A system operator employee in charge of real-time operation shall not work unsupervised in the control room unless he or she is certified.

By 18 months after entry into force of this Regulation, each TSO shall define and implement a process, including the level of competence, for the certification of the system operator employees in charge of real-time operation.

TSO employees in charge of real-time operation shall be certified following a successful formal assessment which shall comprise an oral and/or a written exam, and/or a practical assessment with pre-defined success criteria.

The TSO shall keep a copy of the issued certificate and of the formal assessment results. Upon request by the regulatory authority, the TSO shall provide a copy of the certification examination records.

Each TSO shall record the period of validity of the certification issued to any employee in charge of real-time operation.

Each TSO shall determine the maximum period of the certification, which shall not exceed 5 years but which may be extended on the basis of criteria determined by each TSO, and may take into account the participation of employees in charge of real-time operation in a continuous training programme with sufficient practical experience.

Unless otherwise agreed, the common contact language between the employees of a TSO and those of the neighbouring TSO shall be English.

Each TSO shall train its relevant system operator employees to achieve sufficient skills in the common contact languages agreed with the neighbouring TSOs.

Each TSO shall organise regular training sessions with its neighbouring TSOs to improve the knowledge of the characteristics of neighbouring transmission systems as well as the communication and coordination between employees of neighbouring TSOs in charge of real-time operation. The inter-TSO training shall include detailed knowledge of coordinated actions required under each system state.

Each TSO shall determine, in cooperation with at least the neighbouring TSO, the need and frequency for joint training sessions, including the minimum content and scope of those sessions, taking into account the level of mutual influence and operational cooperation needed. This inter-TSO training may include, but should not be limited to, joint training workshops and joint training simulator sessions.

Each TSO shall participate with other TSOs, at least once a year, in training sessions on the management of inter-TSO issues in real-time operation. The frequency shall be defined taking into account the level of mutual influence of transmission systems and the type of interconnection — DC/AC links.

Each TSO shall exchange experiences from real-time operation, including visits and the exchange of experiences between system operator employees in charge of real-time operation, with their neighbouring TSOs, with any TSO with which there is or has been inter-TSO operational interaction and with the relevant regional security coordinators.

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 GCACMR and Article 18 of GFCAR 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 GCACMR and Article 18 of GFCAR, 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 GCACMR, 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 GCACMR;

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 GCACMR. 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 GCACMR, 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 GCACMR. 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 GCACMR;

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 GCACMR 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 GCACMR, 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 SPDIEMR, 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 SPDIEMR, 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.