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Document 02017R1485-20210315
Commission Regulation (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation (Text with EEA relevance)Text with EEA relevance
Consolidated text: Commission Regulation (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation (Text with EEA relevance)Text with EEA relevance
Commission Regulation (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation (Text with EEA relevance)Text with EEA relevance
02017R1485 — EN — 15.03.2021 — 001.001
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COMMISSION REGULATION (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation (OJ L 220 25.8.2017, p. 1) |
Amended by:
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Official Journal |
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COMMISSION IMPLEMENTING REGULATION (EU) 2021/280 of 22 February 2021 |
L 62 |
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23.2.2021 |
COMMISSION REGULATION (EU) 2017/1485
of 2 August 2017
establishing a guideline on electricity transmission system operation
(Text with EEA relevance)
PART I
GENERAL PROVISIONS
Article 1
Subject matter
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.
Article 2
Scope
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 Regulation (EU) 2016/631 ( 1 );
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 Regulation (EU) 2016/1388 ( 2 );
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 (EU) 2016/1447 ( 3 ).
Article 3
Definitions
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.
Article 4
Objectives and regulatory aspects
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.
Article 5
Terms and conditions or methodologies of TSOs
Where TSOs deciding on proposals for terms and conditions or methodologies listed in Article 6(2) are not able to reach an agreement, they shall decide by qualified majority voting. A 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.
Where TSOs deciding on proposals for terms and conditions or methodologies in accordance with Article 6(3) are not able to reach an agreement and where the regions concerned are composed of more than five Member States, they shall decide by qualified majority voting. 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.
Article 6
Approval of terms and conditions or methodologies of TSOs
The proposals for the following terms and conditions or methodologies and any amendments thereof shall be subject to approval by the Agency, 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 and any amendments thereof 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 and any amendments thereof 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).
Article 7
Amendments to the terms and conditions or methodologies of TSOs
Article 8
Publication of terms and conditions or methodologies on the internet
The publication shall also concern:
enhancements of network operation tools in accordance with Article 55(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).
Article 9
Recovery of costs
Article 10
Stakeholder involvement
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.
Article 11
Public consultation
Article 12
Confidentiality obligations
Article 13
Agreements with TSOs not bound by 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.
Article 14
Monitoring
ENTSO for Electricity shall monitor the implementation of this Regulation in accordance with Article 8(8) of Regulation (EC) No 714/2009. 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.
Article 15
Annual report on operational security indicators
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.
Article 16
Annual report on load-frequency control
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.
Article 17
Annual report on regional coordination assessment
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.
PART II
OPERATIONAL SECURITY
TITLE 1
OPERATIONAL SECURITY REQUIREMENTS
CHAPTER 1
System states, remedial actions and operational security limits
Article 18
Classification of system states
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.
Article 19
Monitoring and determination of system states by TSOs
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.
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.
Article 20
Remedial actions in system operation
Article 21
Principles and criteria applicable to remedial actions
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.
Article 22
Categories of remedial actions
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 Regulation (EU) 2015/1222;
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 (EC) No 714/2009, 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.
Article 23
Preparation, activation and coordination of remedial actions
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 a TSO activates a remedial action each impacted transmission-connected significant grid user and DSO shall execute the instructions given by the TSO
Article 24
Availability of TSO's means, tools and facilities
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.
Article 25
Operational security limits
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.
Article 26
Security plan for critical infrastructure protection
CHAPTER 2
Voltage control and reactive power management
Article 27
Obligations of all TSOs regarding voltage limits
Article 28
Obligations of SGUs concerning voltage control and reactive power management in system operation
Article 29
Obligations of all TSOs concerning voltage control and reactive power management in system operation
CHAPTER 3
Short-circuit current management
Article 30
Short-circuit current
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.
Article 31
Short-circuit current calculation and related measures
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.
CHAPTER 4
Power flow management
Article 32
Power flow limits
CHAPTER 5
Contingency analysis and handling
Article 33
Contingency lists
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.
Article 34
Contingency analysis
Article 35
Contingency handling
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.
CHAPTER 6
Protection
Article 36
General requirements on protection
Article 37
Special protection schemes
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.
Article 38
Dynamic stability monitoring and assessment
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 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.
Article 39
Dynamic stability management
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).
TITLE 2
DATA EXCHANGE
CHAPTER 1
General requirements on data exchange
Article 40
Organisation, roles, responsibilities and quality of data exchange
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.
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 Regulation (EU) 2015/1222. 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.
CHAPTER 2
Data exchange between TSOs
Article 41
Structural and forecast data exchange
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 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.
Article 42
Real-time data exchange
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.
CHAPTER 3
Data exchange between TSOs and DSOs within the TSO's control area
Article 43
Structural data exchange
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).
Article 44
Real-time data exchange
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.
CHAPTER 4
Data exchange between TSOs, owners of interconnectors or other lines and power generating modules connected to the transmission system
Article 45
Structural data exchange
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.
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.
Article 46
Scheduled data exchange
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.
Article 47
Real-time data exchange
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.
CHAPTER 5
Data exchange between TSOs, DSOs and distribution-connected power generating modules
Article 48
Structural data exchange
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 Regulation (EU) 2016/631; and
voltage level and location of each power generating module.
Article 49
Scheduled data exchange
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.
Article 50
Real-time data exchange
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.
Article 51
Data exchange between TSOs and DSOs concerning significant power generating modules
CHAPTER 6
Data exchange between TSOs and demand facilities
Article 52
Data exchange between TSOs and transmission-connected demand facilities
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.
Article 53
Data exchange between TSOs and distribution-connected demand facilities or third parties participating in demand response
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 Regulation (EU) 2016/1388, 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.
TITLE 3
COMPLIANCE
CHAPTER 1
Roles and responsibilities
Article 54
Responsibility of the SGUs
Article 55
Tasks of TSOs regarding system operation
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 (EC) No 714/2009 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.
CHAPTER 2
Operational testing
Article 56
Purpose and responsibilities
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 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.
Article 57
Performing operational tests and analysis
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.
TITLE 4
TRAINING
Article 58
Training program
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.
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 (EC) No 714/2009;
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.
Article 59
Training conditions
Article 60
Training coordinators and trainers
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.
Article 61
Certification of system operator employees in charge of real-time operation
Article 62
Common language for communication between the system operator employees in charge of real time operation
Article 63
Cooperation between TSOs on training
PART III
OPERATIONAL PLANNING
TITLE 1
DATA FOR OPERATIONAL SECURITY ANALYSIS IN OPERATIONAL PLANNING
Article 64
General provisions regarding individual and common grid models
To perform operational security analysis pursuant to Title 2 of this Part, each TSO shall prepare individual grid models in accordance with the methodologies established in application of Article 17 of Regulation (EU) 2015/1222 and Article 18 of Regulation (EU) 2016/1719 for each of the following time-frames, applying the data format established pursuant to Article 114(2):
year-ahead, in accordance with Articles 66, 67 and 68;
where applicable, week-ahead, in accordance with Article 69;
day-ahead, in accordance with Article 70; and
intraday, in accordance with Article 70.
Article 65
Year-ahead scenarios
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.
Article 66
Year-ahead individual grid models
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.
Article 67
Year-ahead common grid models
By 6 months after entry into force of this Regulation, all TSOs shall jointly develop a proposal for the methodology for building the year-ahead common grid models from the individual grid models established in accordance with Article 66(1) and for saving them. The methodology shall take into account, and complement where necessary, the operational conditions of the common grid model methodology developed in accordance with Article 17 of Regulation (EU) 2015/1222 and Article 18 of Regulation (EU) 2016/1719, as regards the following elements:
deadlines for gathering the year-ahead individual grid models, for merging them into a common grid model and for saving the individual and common grid models;
quality control of the individual and common grid models to be implemented in order to ensure their completeness and consistency; and
correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (b).
Article 68
Updates of year-ahead individual and common grid models
Article 69
Week-ahead individual and common grid models
Article 70
Methodology for building day-ahead and intraday common grid models
By 6 months after entry into force of this Regulation, all TSOs shall jointly develop a proposal for the methodology for building the day-ahead and intraday common grid models from the individual grid models and for saving them. That methodology shall take into account, and complement where necessary, the operational conditions of the common grid model methodology developed in accordance with Article 17 of Regulation (EU) 2015/1222, as regards the following elements:
definition of timestamps;
deadlines for gathering the individual grid models, for merging them into a common grid model and for saving individual and common grid models. The deadlines shall be compatible with the regional processes established for preparing and activating remedial actions;
quality control of individual grid models and the common grid model to be implemented to ensure their completeness and consistency;
correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (c); and
handling additional information related to operational arrangements, such as protection setpoints or system protection schemes, single line diagrams and configuration of substations in order to manage operational security.
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.
Article 71
Quality control for grid models
When defining the quality controls in accordance with Articles 67(1)(b) and 70(1)(c), all TSOs shall jointly determine controls aimed at least to check:
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.
TITLE 2
OPERATIONAL SECURITY ANALYSIS
Article 72
Operational security analysis in operational planning
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.
Article 73
Year-ahead up to and including week-ahead operational security analysis
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.
Article 74
Day-ahead, intraday and close to real-time operational security analysis
Article 75
Methodology for coordinating operational security analysis
By 12 months after entry into force of this Regulation, all TSOs shall jointly develop a proposal for a methodology for coordinating operational security analysis. That methodology shall aim at the standardisation of operational security analysis at least per synchronous area and shall include at least:
methods for assessing the influence of transmission system elements and SGUs located outside of a TSO's control area in order to identify those elements included in the TSO's observability area and the contingency influence thresholds above which contingencies of those elements constitute external contingencies;
principles for common risk assessment, covering at least, for the contingencies referred to in Article 33:
associated probability;
transitory admissible overloads; and
impact of contingencies;
principles for assessing and dealing with uncertainties of generation and load, taking into account a reliability margin in line with Article 22 of Regulation (EU) 2015/1222;
requirements on coordination and information exchange between regional security coordinators in relation to the tasks listed in Article 77(3);
role of ENTSO for Electricity in the governance of common tools, data quality rules improvement, monitoring of the methodology for coordinated operational security analysis and of the common provisions for regional operational security coordination in each capacity calculation region.
The methods referred to in point (a) of paragraph 1 shall allow the identification of all elements of a TSO's observability area, being grid elements of other TSOs or transmission-connected DSOs, power generating modules or demand facilities. Those methods shall take into account the following transmission system elements and SGUs' characteristics:
connectivity status or electrical values (such as voltages, power flows, rotor angle) which significantly influence the accuracy of the results of the state estimation for the TSO's control area, above common thresholds;
connectivity status or electrical values (such as voltages, power flows, rotor angle) which significantly influence the accuracy of the results of the TSO's operational security analysis, above common thresholds; and
requirement to ensure an adequate representation of the connected elements in the TSO's observability area.
The 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.
Article 76
Proposal for regional operational security coordination
By 3 months after the approval of the methodology for coordinating operational security analysis in Article 75(1), all TSOs of each capacity calculation region shall jointly develop a proposal for common provisions for regional operational security coordination, to be applied by the regional security coordinators and the TSOs of the capacity calculation region. The proposal shall respect the methodologies for coordinating operational security analysis developed in accordance with Article 75(1) and complement where necessary the methodologies developed in accordance with Articles 35 and 74 of Regulation (EU) 2015/1222. The proposal shall determine:
conditions and frequency of intraday coordination of operational security analysis and updates to the common grid model by the regional security coordinator;
the methodology for the preparation of remedial actions managed in a coordinated way, considering their cross-border relevance as determined in accordance with Article 35 of Regulation (EU) 2015/1222, taking into account the requirements in Articles 20 to 23 and determining at least:
the procedure for exchanging the information of the available remedial actions, between relevant TSOs and the regional security coordinator;
the classification of constraints and the remedial actions in accordance with Article 22;
the identification of the most effective and economically efficient remedial actions in case of operational security violations referred to in Article 22;
the preparation and activation of remedial actions in accordance with Article 23(2);
the sharing of the costs of remedial actions referred to in Article 22, complementing where necessary the common methodology developed in accordance with Article 74 of Regulation (EU) 2015/1222. As a general principle, costs of non-cross-border relevant congestions shall be borne by the TSO responsible for the given control area and costs of relieving cross-border-relevant congestions shall be covered by TSOs responsible for the control areas in proportion to the aggravating impact of energy exchange between given control areas on the congested grid element.
Article 77
Organisation for regional operational security coordination
The proposal of all TSOs of a capacity calculation region for common provisions for regional operational security coordination pursuant to Article 76(1) shall also include common provisions concerning the organisation of regional operational security coordination, including at least:
the appointment of the regional security coordinator(s) that will perform the tasks in paragraph 3 for that capacity calculation region;
rules concerning the governance and operation of regional security coordinator(s), ensuring equitable treatment of all member TSOs;
where the TSOs propose to appoint more than one regional security coordinator in accordance with subparagraph (a):
a proposal for a coherent allocation of the tasks between the regional security coordinators who will be active in that capacity calculation region. The proposal shall take full account of the need to coordinate the different tasks allocated to the regional security coordinators;
an assessment demonstrating that the proposed setup of regional security coordinators and allocation of tasks is efficient, effective and consistent with the regional coordinated capacity calculation established pursuant to Articles 20 and 21 of Regulation (EU) 2015/1222;
an effective coordination and decision making process to resolve conflicting positions between regional security coordinators within the capacity calculation region.
When developing the proposal for common provisions concerning the organisation of regional operational security coordination in paragraph 1, the following requirements shall be met:
each TSO shall be covered by at least one regional security coordinator;
all TSOs shall ensure that the total number of regional security coordinators across the Union is not higher than six.
The TSOs of each capacity calculation region shall propose the delegation of the following tasks in accordance with paragraph 1:
regional operational security coordination in accordance with Article 78 in order to support TSOs fulfil their obligations for the year-ahead, day-ahead and intraday time-frames in Article 34(3) and Articles 72 and 74;
building of common grid model in accordance with Article 79;
regional outage coordination in accordance with Article 80, in order to support TSOs fulfil their obligations in Articles 98 and 100;
regional adequacy assessment in accordance with Article 81 in order to support TSOs fulfil their obligations under Article 107.
Article 78
Regional operational security coordination
Each TSO shall provide the regional security coordinator with all the information and data required to perform the coordinated regional operational security assessment, including at least:
the updated contingency list, established according to the criteria defined in the methodology for coordinating operational security analysis adopted in accordance with Article 75(1);
the updated list of possible remedial actions, among the categories listed in Article 22, and their anticipated costs provided in accordance with Article 35 of Regulation (EU) 2015/1222 if a remedial action includes redispatching or countertrading, aimed at contributing to relieve any constraint identified in the region; and
the operational security limits established in accordance with Article 25.
Each regional security coordinator shall:
perform the coordinated regional operational security assessment in accordance with Article 76 on the basis of the common grid models established in accordance with Article 79, the contingency list and the operational security limits provided by each TSOs in paragraph 1. It shall deliver the results of the coordinated regional operational security assessment at least to all TSOs of the capacity calculation region. Where it detects a constraint, it shall recommend to the relevant TSOs the most effective and economically efficient remedial actions and may also recommend remedial actions other than those provided by the TSOs. This recommendation for remedial actions shall be accompanied by explanations as to its rationale;
coordinate the preparation of remedial actions with and among TSOs in accordance with Article 76(1)(b), to enable TSOs achieve a coordinated activation of remedial actions in real-time.
Article 79
Common grid model building
Article 80
Regional outage coordination
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.
Article 81
Regional adequacy assessment
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.
TITLE 3
OUTAGE COORDINATION
CHAPTER 1
Outage coordination regions, relevant assets
Article 82
Outage coordination objective
Each TSO shall, with the support of the regional security coordinator for the instances specified in this Regulation, perform outage coordination in accordance with the principles of this Title in order to monitor the availability status of the relevant assets and coordinate the availability plans to ensure the operational security of the transmission system.
Article 83
Regional coordination
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.
Article 84
Methodology for assessing the relevance of assets for outage coordination
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.
Article 85
Lists of relevant power generating modules and relevant demand facilities
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.
Article 86
Update of the lists of relevant power generating modules and relevant demand facilities
Article 87
Lists of relevant grid elements
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.
Article 88
Update of the list of relevant grid elements
Article 89
Appointment of outage planning agents
Article 90
Treatment of relevant assets located in a distribution system or in a closed distribution system
CHAPTER 2
Development and update of availability plans of relevant assets
Article 91
Variations to deadlines for the year-ahead outage coordination
All TSOs within a synchronous area may jointly agree to adopt and implement a time-frame for the year-ahead outage coordination that deviates from the time-frame defined in Articles 94, 97 and 99, provided that the outage coordination of other synchronous areas is not impacted.
Article 92
General provisions on availability plans
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.
Article 93
Long-term indicative availability plans
Article 94
Provision of year-ahead availability plan proposals
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.
Article 95
Year-ahead coordination of the availability status of relevant assets for which the outage planning agent is not a TSO taking part in an outage coordination region, nor a DSO or a CDSO
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.
Article 96
Year-ahead coordination of the availability status of relevant assets for which the outage planning agent is a TSO taking part in an outage coordination region, a DSO or a CDSO
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 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.
Article 97
Provision of preliminary year-ahead availability plans
Article 98
Validation of year-ahead availability plans within outage coordination regions
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.
Article 99
Final year-ahead availability plans
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.
Article 100
Updates to the final year-ahead availability plans
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.
CHAPTER 3
Execution of availability plans
Article 101
Management of the ‘testing’ status of relevant assets
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.
Article 102
Procedure for handling forced outages
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.
Article 103
Real-time execution of the availability plans
TITLE 4
ADEQUACY
Article 104
Forecast for control area adequacy analysis
Each TSO shall make any forecast used for control area adequacy analyses pursuant to Articles 105 and 107 available to all other TSOs through the ENTSO for Electricity operational planning data environment.
Article 105
Control area adequacy analysis
When performing a control area adequacy analysis pursuant to paragraph 1, each TSO shall:
use the latest availability plans and the latest available data for:
the capabilities of power generating modules provided pursuant to Article 43(5) and Articles 45 and 51;
cross-zonal capacity;
possible demand response provided pursuant to Articles 52 and 53;
take into account the contributions of generation from renewable energy sources and load;
assess the probability and expected duration of an absence of adequacy and the expected energy not supplied as a result of such absence.
Article 106
Control area adequacy up to and including week-ahead
Article 107
Control area adequacy in day-ahead and intraday
Each TSO shall perform a control area adequacy analysis in a day-ahead and intraday time-frame on the basis of:
schedules referred to in Article 111;
forecasted load;
forecasted generation from renewable energy sources;
active power reserves in accordance with the data provided pursuant to Article 46(1)(a);
control area import and export capacities consistent with cross-zonal capacities calculated where applicable in accordance with Article 14 of Regulation (EU) 2015/1222;
capabilities of power generating modules in accordance with the data provided pursuant to Article 43(4) and Articles 45 and 51 and their availability statuses; and
capabilities of demand facilities with demand response in accordance with the data provided pursuant to Articles 52 and 53 and their availability statuses.
Each TSO shall evaluate:
the minimum level of import and the maximum level of export compatible with its control area adequacy;
the expected duration of a potential absence of adequacy; and
the amount of energy not supplied in the absence of adequacy.
TITLE 5
ANCILLARY SERVICES
Article 108
Ancillary services
With regard to active power and reactive power services, and in coordination with other TSOs where appropriate, each TSO shall:
design, set up and manage the procurement of ancillary services;
monitor, on the basis of data provided pursuant to Title 2 of Part II, whether the level and location of available ancillary services allows ensuring operational security; and
use all available economically efficient and feasible means to procure the necessary level of ancillary services.
Article 109
Reactive power ancillary services
In order to increase the efficiency of operation of its transmission system elements, each TSO shall monitor:
the available reactive power capacities of power generating facilities;
the available reactive power capacities of transmission-connected demand facilities;
the available reactive power capacities of DSOs;
the available transmission-connected equipment dedicated to providing reactive power; and
the ratios of active power and reactive power at the interface between the transmission system and transmission-connected distribution systems.
Where the level of reactive power ancillary services is not sufficient for maintaining operational security, each TSO shall:
inform neighbouring TSOs; and
prepare and activate remedial actions pursuant to Article 23.
TITLE 6
SCHEDULING
Article 110
Establishment of scheduling processes
Article 111
Notification of schedules within scheduling areas
Each scheduling agent, except scheduling agents of shipping agents, shall submit to the TSO operating the scheduling area, if requested by the TSO, and, where applicable, to third party, the following schedules:
generation schedules;
consumption schedules;
internal commercial trade schedules; and
external commercial trade schedules.
Each scheduling agent of a shipping agent or, where applicable, a central counterparty shall submit to the TSO operating a scheduling area covered by market coupling, if requested by the concerned TSO, and where applicable to third party, the following schedules:
external commercial trade schedules as:
multilateral exchanges between the scheduling area and a group of other scheduling areas;
bilateral exchanges between the scheduling area and another scheduling area;
internal commercial trade schedules between the shipping agent and central counter parties;
internal commercial trade schedules between the shipping agent and other shipping agents.
Article 112
Coherence of schedules
Article 113
Provision of information to other TSOs
At the request of another TSO, the requested TSO shall calculate and provide:
aggregated netted external schedules; and
netted area AC position, where the scheduling area is interconnected to other scheduling areas via AC transmission links.
When required for the creation of common grid models, in accordance with Article 70(1), each TSO operating a scheduling area shall provide any requesting TSO with:
generation schedules; and
consumption schedules.
TITLE 7
ENTSO FOR ELECTRICITY OPERATIONAL PLANNING DATA ENVIRONMENT
Article 114
General provisions for ENTSO for Electricity operational planning data environment
Article 115
Individual grid models, common grid models and operational security analysis
For the year-ahead time-frame, the following information shall be available on the ENTSO for Electricity operational planning data environment:
year-ahead individual grid model per TSO and per scenario determined in accordance with Article 66; and
year-ahead common grid model per scenario defined in accordance with Article 67.
For the day-ahead and intraday time-frames, the following information shall be available on the ENTSO for Electricity operational planning data environment:
day-ahead and intraday individual grid models per TSO and according to the time resolution defined pursuant to Article 70(1);
scheduled exchanges at the relevant time instances per scheduling area or per scheduling area border, whichever is deemed relevant by the TSOs, and per HVDC system linking scheduling areas;
day-ahead and intraday common grid models according to the time resolution defined pursuant to Article 70(1); and
a list of prepared and agreed remedial actions identified to cope with constraints having cross-border relevance.
Article 116
Outage coordination
Article 117
System adequacy
The information referred to in paragraph 1 shall include at least:
the season-ahead system adequacy data provided by each TSO;
the season-ahead pan-European system adequacy analysis report;
forecasts used for adequacy in line with Article 104; and
information about a lack of adequacy in line with Article 105(4).
PART IV
LOAD-FREQUENCY CONTROL AND RESERVES
TITLE 1
OPERATIONAL AGREEMENTS
Article 118
Synchronous area operational agreements
By 12 months after entry into force of this Regulation, all TSOs of each synchronous area shall jointly develop common proposals for:
the dimensioning rules for FCR in accordance with Article 153;
additional properties of FCR in accordance with Article 154(2);
the frequency quality defining parameters and the frequency quality target parameters in accordance with Article 127;
for the Continental Europe (‘CE’) and Nordic synchronous areas, the frequency restoration control error target parameters for each LFC block in accordance with Article 128;
the methodology to assess the risk and the evolution of the risk of exhaustion of FCR of the synchronous area in accordance with Article 131(2);
the synchronous area monitor in accordance with Article 133;
the calculation of the control program from the netted area AC position with a common ramping period for ACE calculation for a synchronous area with more than one LFC area in accordance with Article 136;
if applicable, restrictions for the active power output of HVDC interconnectors between synchronous areas in accordance with Article 137;
the LFC structure in accordance with Article 139;
if applicable, the methodology to reduce the electrical time deviation in accordance with Article 181;
whenever the synchronous area is operated by more than one TSO, the specific allocation of responsibilities between TSOs in accordance with Article 141;
operational procedures in case of exhausted FCR in accordance with Article 152(7);
for the GB and IE/NI synchronous areas, measures to ensure the recovery of energy reservoirs in accordance with to Article 156(6)(b);
operational procedures to reduce the system frequency deviation to restore the system state to normal state and to limit the risk of entering into the emergency state in accordance with Article 152(10);
the roles and responsibilities of the TSOs implementing an imbalance netting process, a cross-border FRR activation process or a cross-border RR activation process in accordance with Article 149(2);
requirements concerning the availability, reliability and redundancy of the technical infrastructure in accordance with Article 151(2);
common rules for the operation in normal state and alert state in accordance with Article 152(6) and the actions referred to in Article 152(15);
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);
if applicable, for synchronous areas other than CE, limits for the exchange of FCR between the TSOs in accordance with Article 163(2);
the roles and responsibilities of the reserve connecting TSO, the reserve receiving TSO and the affected TSO as regards the exchange of FRR and RR defined in accordance with Article 165(1);
the roles and responsibilities of the control capability providing TSO, the control capability receiving TSO and the affected TSO for the sharing of FRR and RR defined in accordance with Article 166(1);
the roles and responsibilities of the reserve connecting TSO, the reserve receiving TSO and the affected TSO for the exchange of reserves between synchronous areas, and of the control capability providing TSO, the control capability receiving TSO and the affected TSO for the sharing of reserves between synchronous areas defined in accordance with Article 171(2);
the methodology to determine limits on the amount of sharing of FCR between synchronous areas defined in accordance with Article 174(2);
for the GB and IE/NI synchronous areas, the methodology to determine the minimum provision of reserve capacity on FCR in accordance with Article 174(2)(b);
the methodology to determine limits on the amount of exchange of FRR between synchronous areas defined in accordance with Article 176(1) and the methodology to determine limits on the amount of sharing of FRR between synchronous areas defined in accordance with Article 177(1); and
the methodology to determine limits on the amount of exchange of RR between synchronous areas defined in accordance with Article 178(1) and the methodology to determine limits on the amount of sharing of RR between synchronous areas defined in accordance with Article 179(1).
Article 119
LFC block operational agreements
By 12 months after entry into force of this Regulation, all TSOs of each LFC block shall jointly develop common proposals for:
where the LFC block consists of more than one LFC area, FRCE target parameters for each LFC area defined in accordance with Article 128(4);
LFC block monitor in accordance with Article 134(1);
ramping restrictions for active power output in accordance with Article 137(3) and (4);
where the LFC block is operated by more than one TSO, the specific allocation of responsibilities between TSOs within the LFC block in accordance with Article 141(9);
if applicable, appointment of the TSO responsible for the tasks in Article 145(6);
additional requirements for the availability, reliability and redundancy of technical infrastructure defined in accordance with Article 151(3);
operational procedures in case of exhausted FRR or RR in accordance with Article 152(8);
the FRR dimensioning rules defined in accordance with Article 157(1);
the RR dimensioning rules defined in accordance with Article 160(2);
where the LFC block is operated by more than one TSO, the specific allocation of responsibilities defined in accordance with Article 157(3), and, if applicable, the specific allocation of responsibilities defined in accordance Article 160(6);
the escalation procedure defined in accordance with Article 157(4) and, if applicable, the escalation procedure defined in accordance with Article 160(7);
the FRR availability requirements, the requirements on the control quality defined in accordance with Article 158(2), and if applicable, the RR availability requirements and the requirements on the control quality defined in accordance with Article 161(2);
if applicable, any limits on the exchange of FCR between the LFC areas of the different LFC blocks within the CE synchronous area and the exchange of FRR or RR between the LFC areas of an LFC block of a synchronous area consisting of more than one LFC block defined in accordance with Article 163(2), Article 167 and Article 169(2);
the roles and the responsibilities of the reserve connecting TSO, the reserve receiving TSO and of the affected TSO for the exchange of FRR and/or RR with TSOs of other LFC blocks defined in accordance with Article 165(6);
the roles and the responsibilities of the control capability providing TSO, the control capability receiving TSO and of the affected TSO for the sharing of FRR and RR defined in accordance with Article 166(7);
roles and the responsibilities of the control capability providing TSO, the control capability receiving TSO and of the affected TSO for the sharing of FRR and RR between synchronous areas in accordance with Article 175(2);
coordination actions aiming to reduce the FRCE as defined in Article 152(14); and
measures to reduce the FRCE by requiring changes in the active power production or consumption of power generating modules and demand units in accordance with Article 152(16).
Article 120
LFC area operational agreement
By 12 months after entry into force of this Regulation, all TSOs of each LFC area shall establish an LFC area operational agreement that shall include at least:
the specific allocation of responsibilities between TSOs within the LFC area in accordance with Article 141(8);
the appointment of the TSO responsible for the implementation and operation of the frequency restoration process in accordance with Article 143(4).
Article 121
Monitoring area operational agreement
By 12 months after entry into force of this Regulation, all TSOs of each monitoring area shall establish a monitoring area operational agreement that shall include at least the allocation of responsibilities between TSOs within the same monitoring area in accordance with Article 141(7).
Article 122
Imbalance netting agreement
All TSOs participating in the same imbalance netting process shall establish an imbalance netting agreement that shall at least include the roles and responsibilities of the TSOs in accordance with Article 149(3).
Article 123
Cross-border FRR activation agreement
All TSOs participating in the same cross-border FRR activation process shall establish a cross-border FRR activation agreement that shall include at least the roles and responsibilities of the TSOs in accordance with Article 149(3).
Article 124
Cross-border RR activation agreement
All TSOs participating in the same cross-border RR activation process shall establish a cross-border RR activation agreement that shall include at least the roles and responsibilities of the TSOs in accordance with Article 149(3).
Article 125
Sharing agreement
All TSOs participating in the same sharing process of FCR, FRR or RR shall establish a sharing agreement that shall include at least:
in case of sharing FRR or RR within a synchronous area, the roles and responsibilities of the control capability receiving TSO and of the control capability providing TSO and the affected TSOs in accordance with Article 165(3); or
in case of sharing reserves between synchronous areas, the roles and responsibilities of the control capability receiving TSO and of the control capability providing TSO in accordance with Article 171(4) and the procedures in case the sharing of reserves between synchronous areas is not executed in real-time in accordance with Article 171(9).
Article 126
Exchange agreement
All TSOs participating in the same exchange of FCR, FRR or RR shall establish an exchange agreement that shall include at least:
in case of exchange of FRR or RR within a synchronous area, the roles and responsibilities of the reserve connecting and reserve receiving TSOs in accordance with to Article 165(3); or
in case of exchange of reserves between synchronous areas, the roles and responsibilities of the reserve connecting and reserve receiving TSOs in accordance with Article 171(4) and the procedures in case the exchange of reserves between synchronous areas is not executed in real-time in accordance with Article 171(9).
TITLE 2
FREQUENCY QUALITY
Article 127
Frequency quality defining and target parameters
The frequency quality defining parameters shall be:
the nominal frequency for all synchronous areas;
the standard frequency range for all synchronous areas;
the maximum instantaneous frequency deviation for all synchronous areas;
the maximum steady-state frequency deviation for all synchronous areas;
the time to restore frequency for all synchronous areas;
the time to recover frequency for the GB and IE/NI synchronous areas;
the frequency restoration range for the GB, IE/NI and Nordic synchronous areas;
the frequency recovery range for the GB and IE/NI synchronous areas; and
the alert state trigger time for all synchronous areas.
All TSOs of CE and Nordic synchronous areas shall have the right to propose in the synchronous area operational agreement values different from those set out in Tables 1 and 2 of Annex III regarding:
the alert state trigger time;
the maximum number of minutes outside the standard frequency range.
All TSOs of the GB and IE/NI synchronous areas shall have the right to propose in the synchronous area operational agreement values different from those set out in Tables 1 and 2 of Annex III regarding:
time to restore frequency;
the alert state trigger time; and
the maximum number of minutes outside the standard frequency range.
The proposal for modification of the values pursuant to paragraph 6 and 7 shall be based on an assessment of the recorded values of the system frequency for a period of at least 1 year and the synchronous area development and it shall meet the following conditions:
the proposed modification of the frequency quality defining parameters in Table 1 of Annex III or the frequency quality target parameter in Table 2 of Annex III takes into account:
the system's size, based on the consumption and generation of the synchronous area and the inertia of the synchronous area;
the reference incident;
grid structure and/or network topology;
load and generation behaviour;
the number and response of power generating modules with limited frequency sensitive mode — over frequency and limited frequency sensitive mode — under frequency as defined in Article 13(2) and Article 15(2)(c) of Regulation (EU) 2016/631;
the number and response of demand units operating with activated demand response system frequency control or demand response very fast active power control as defined in Articles 29 and 30 of Regulation (EU) 2016/1388; and
the technical capabilities of power generating modules and demand units;
all TSOs of the synchronous area shall conduct a public consultation concerning the impact on stakeholders of the proposed modification of the frequency quality defining parameters in Table 1 of Annex III or the frequency quality target parameter in Table 2 of Annex III.
Article 128
FRCE target parameters
All TSOs of the CE and Nordic synchronous areas shall endeavour to comply with the following FRCE target parameters for each LFC block of the synchronous area:
the number of time intervals per year outside the Level 1 FRCE range within a time interval equal to the time to restore frequency shall be less than 30 % of the time intervals of the year; and
the number of time intervals per year outside the Level 2 FRCE range within a time interval equal to the time to restore frequency shall be less than 5 % of the time intervals of the year.
All TSOs of the GB and IE/NI synchronous areas shall endeavour to comply with the following FRCE target parameters of a synchronous area:
the maximum number of time intervals outside the Level 1 FRCE range shall be less than or equal to the value in the Table of Annex IV as a percentage of the time intervals per year;
the maximum number of time intervals outside the Level 2 FRCE range shall be less than or equal to the value in the Table of Annex IV as a percentage of the time intervals per year.
Article 129
Criteria application process
The criteria application process shall comprise:
the collection of frequency quality evaluation data; and
the calculation of frequency quality evaluation criteria.
Article 130
Frequency quality evaluation data
The frequency quality evaluation data shall be:
for the synchronous area:
the instantaneous frequency data; and
the instantaneous frequency deviation data;
for each LFC block of the synchronous area, the instantaneous FRCE data.
Article 131
Frequency quality evaluation criteria
The frequency quality evaluation criteria shall comprise:
for the synchronous area during operation in normal state or alert state as determined by Article 18(1) and (2), on a monthly basis, for the instantaneous frequency data:
the mean value;
the standard deviation;
the 1-,5-,10-, 90-,95- and 99-percentile;
the total time in which the absolute value of the instantaneous frequency deviation was larger than the standard frequency deviation, distinguishing between negative and positive instantaneous frequency deviations;
the total time in which the absolute value of the instantaneous frequency deviation was larger than the maximum instantaneous frequency deviation, distinguishing between negative and positive instantaneous frequency deviations;
the number of events in which the absolute value of the instantaneous frequency deviation of the synchronous area exceeded 200 % of the standard frequency deviation and the instantaneous frequency deviation was not returned to 50 % of the standard frequency deviation for the CE synchronous area and to the frequency restoration range for the GB, IE/NI and Nordic synchronous areas, within the time to restore frequency. The data shall distinguish between negative and positive frequency deviations;
for the GB and IE/NI synchronous areas, the number of events for which the absolute value of the instantaneous frequency deviation was outside of the frequency recovery range and was not returned to the frequency recovery range within the time to recover frequency, distinguishing between negative and positive frequency deviations;
for each LFC block of the CE or Nordic synchronous areas during operation in normal state or alert state in accordance with Article 18(1) and (2), on a monthly basis:
for a data-set containing the average values of the FRCE of the LFC block over time intervals equal to the time to restore frequency:
for a data-set containing the average values of the FRCE of the LFC block over time intervals with a length of one minute: the number of events on a monthly basis for which the FRCE exceeded 60 % of the reserve capacity on FRR and was not returned to 15 % of the reserve capacity on FRR within the time to restore frequency, distinguishing between negative and positive FRCE;
for the LFC blocks of the GB or IE/NI synchronous area, during operation in normal state or alert state in accordance with Article 18(1) and (2), on a monthly basis and for a data-set containing the average values of the FRCE of the LFC block over time intervals with a length of one minute: the number of events for which the absolute value of the FRCE exceeded the maximum steady-state frequency deviation and the FRCE was not returned to 10 % of the maximum steady-state frequency deviation within the time to restore frequency, distinguishing between negative and positive FRCE.
Article 132
Data collection and delivery process
The data collection and delivery process shall comprise the following:
measurements of the system frequency;
calculation of the frequency quality evaluation data; and
delivery of the frequency quality evaluation data for the criteria application process.
Article 133
Synchronous area monitor
Article 134
LFC block monitor
Article 135
Information on load and generation behaviour
In accordance with Article 40, each connecting TSO shall have the right to request the information necessary from SGUs to monitor the load and generation behaviour related to imbalances. That information may include:
the time-stamped active power setpoint for real-time and future operation; and
the time-stamped total active power output.
Article 136
Ramping period within the synchronous area
All TSOs of each synchronous area with more than one LFC area shall specify in the synchronous area operational agreement a common ramping period of aggregated netted schedules between the LFC areas in the synchronous area. The calculation of the control program from the netted area AC position for ACE calculation shall be performed with the common ramping period.
Article 137
Ramping restrictions for active power output
All TSOs of an LFC block shall have the right to determine in the LFC block operational agreement the following measures to support the fulfilment of the FRCE target parameter of the LFC block and to alleviate deterministic frequency deviations, taking into account the technological restrictions of power generating modules and demand units:
obligations on ramping periods and/or maximum ramping rates for power generating modules and/or demand units;
obligations on individual ramping starting times for power generating modules and/or demand units within the LFC block; and
coordination of the ramping between power generating modules, demand units and active power consumption within the LFC block.
Article 138
Mitigation
Where the values calculated for the period of one calendar year concerning the frequency quality target parameters or the FRCE target parameters are outside the targets set for the synchronous area or for the LFC block, all TSOs of the relevant synchronous area or of the relevant LFC block shall:
analyse whether the frequency quality target parameters or the FRCE target parameters will remain outside the targets set for the synchronous area or for the LFC block and in case of a justified risk that this may happen, analyse the causes and develop recommendations; and
develop mitigation measures to ensure that the targets for the synchronous area or for the LFC block can be met in the future.
TITLE 3
LOAD-FREQUENCY CONTROL STRUCTURE
Article 139
Basic structure
The load-frequency control structure of each synchronous area shall include:
a process activation structure in accordance with Article 140; and
a process responsibility structure in accordance with Article 141.
Article 140
Process activation structure
The process activation structure shall include:
a FCP pursuant to Article 142;
a FRP pursuant to Article 143; and
for the CE synchronous area, a time control process pursuant to Article 181.
The process activation structure may include:
a RRP pursuant to Article 144;
an imbalance netting process in accordance with Article 146;
a cross-border FRR activation process in accordance with Article 147;
a cross-border RR activation process in accordance with Article 148; and
for synchronous areas other than CE, a time control process pursuant to Article 181.
Article 141
Process responsibility structure
When specifying the process responsibility structure, all TSOs of each synchronous area shall take into account at least the following criteria:
the size and the total inertia, including synthetic inertia, of the synchronous area;
the grid structure and/or network topology; and
the load, generation and HVDC behaviour.
By 4 months after entry into force of this Regulation, all TSOs of a synchronous area shall jointly develop a common proposal regarding the determination of the LFC blocks, which shall comply with the following requirements:
a monitoring area corresponds to or is part of only one LFC area;
a LFC area corresponds to or is part of only one LFC block;
a LFC block corresponds to or is part of only one synchronous area; and
each network element is part of only one monitoring area, only one LFC area and only one LFC block.
All TSOs of each LFC area shall:
continuously monitor the FRCE of the LFC area;
implement and operate a FRP for the LFC area;
endeavour to fulfil the FRCE target parameters of the LFC area as defined in Article 128; and
have the right to implement one or several of the processes referred to in Article 140(2).
All TSOs of each LFC block shall:
endeavour to fulfil the FRCE target parameters of the LFC block as defined in Article 128; and
comply with the FRR dimensioning rules in accordance with Article 157 and the RR dimensioning rules in accordance with Article 160.
All TSOs of each synchronous area shall:
implement and operate a FCP for the synchronous area;
comply with FCR dimensioning rules in accordance with Article 153; and
endeavour to fulfil the frequency quality target parameters in accordance with Article 127.
Article 142
Frequency containment process
Article 143
Frequency restoration process
The control target of the FRP shall be to:
regulate the FRCE towards zero within the time to restore frequency;
for the CE and Nordic synchronous areas, to progressively replace the activated FCR by activation of FRR in accordance with Article 145.
The FRCE is:
the ACE of an LFC area, where there is more than one LFC area in a synchronous area; or
the frequency deviation, where one LFC area corresponds to the LFC block and the synchronous area.
The ACE of a LFC area shall be calculated as the sum of the product of the K-Factor of the LFC area with the frequency deviation plus de subtraction of:
the total interconnector and virtual tie-line active power flow; and
the control program in accordance with Article 136.
Article 144
Reserve replacement process
The control target of the RRP shall be to fulfil at least one of the following goals by activation of RR:
progressively restore the activated FRR;
support FRR activation;
for the GB and IE/NI synchronous areas, to progressively restore the activated FCR and FRR.
Article 145
Automatic and manual frequency restoration process
The aFRP shall be operated in a closed-loop manner where the FRCE is an input and the setpoint for automatic FRR activation is an output. The setpoint for automatic FRR activation shall be calculated by a single frequency restoration controller operated by a TSO within its LFC area. For the CE and Nordic synchronous areas, the frequency restoration controller shall:
be an automatic control device designed to reduce the FRCE to zero;
have proportional-integral behaviour;
have a control algorithm which prevents the integral term of a proportional-integral controller from accumulating the control error and overshooting; and
have functionalities for extraordinary operational modes for the alert and emergency states.
In addition to the aFRP implementation in the LFC areas, all TSOs of an LFC block which consists of more than one LFC area shall have the right to appoint one TSO of the LFC block in the LFC block operational agreement to:
calculate and monitor the FRCE of the whole LFC block; and
take the FRCE of the whole LFC block into account for the calculation of the setpoint value for aFRR activation in accordance with Article 143(3) in addition to the FRCE of its LFC area.
Article 146
Imbalance netting process
TSOs shall implement the imbalance netting process in a way which does not affect:
the stability of the FCP of the synchronous area or synchronous areas involved in the imbalance netting process;
the stability of the FRP and the RRP of each LFC area operated by participating or affected TSOs; and
operational security.
TSOs shall implement the imbalance netting power interchange between LFC areas of a synchronous area in at least one of the following ways:
by defining an active power flow over a virtual tie-line which shall be part of the FRCE calculation;
by adjusting the active power flows over HVDC interconnectors.
Article 147
Cross-border FRR activation process
TSOs shall implement the cross-border FRR activation process in a way which does not affect:
the stability of the FCP of the synchronous area or synchronous areas involved in the cross-border FRR activation process;
the stability of the FRP and the RRP of each LFC area operated by participating or affected TSOs; and
operational security.
TSOs shall implement the frequency restoration power interchange between LFC areas of the same synchronous area through one of the following actions:
defining an active power flow over a virtual tie-line which shall be part of the FRCE calculation where FRR activation is automated;
adjusting a control program or defining an active power flow over a virtual tie-line between LFC areas where FRR activation is manual; or
adjusting the active power flows over HVDC interconnectors.
Article 148
Cross-border RR activation process
TSOs shall implement the cross-border RR activation process in a way which does not affect:
the stability of the FCP of the synchronous area or synchronous areas involved in the cross-border RR activation process;
the stability of the FRP and the RRP of each LFC area operated by participating or affected TSOs; and
the operational security.
TSOs shall implement the control program between LFC areas of the same synchronous area by carrying out at least one of the following actions:
determining an active power flow over a virtual tie-line which shall be part of the FRCE calculation;
adjusting a control program; or
adjusting active power flows over HVDC interconnectors.
Article 149
General requirements for cross-border control processes
All TSOs participating in the same imbalance netting process, in the same cross-border FRR activation process or in the same cross-border RR activation process shall specify in the respective agreements, the roles and responsibilities of all TSOs including:
the provision of all input data necessary for:
the calculation of the power interchange with respect to the operational security limits; and
the performance of real-time operational security analysis by participating and affected TSOs;
the responsibility of calculating the power interchange; and
the implementation of operational procedures to ensure the operational security.
Article 150
TSO notification
TSOs who intend to exercise the right to implement an imbalance netting process, a cross-border FRR activation process, a cross-border RR activation process, an exchange of reserves or a sharing of reserves shall, 3 months before exercising such right, notify all other TSOs of the same synchronous area about:
the TSOs involved;
the expected amount of power interchange due to the imbalance netting process, cross-border FRR activation process or cross-border RR activation process;
the reserve type and maximum amount of exchange or sharing of reserves; and
the timeframe of exchange or sharing of reserves.
The affected TSO shall have the right to:
require the provision of real-time values of imbalance netting power interchange, frequency restoration power interchange and control program necessary for real-time operational security analysis; and
require the implementation of an operational procedure enabling the affected TSO to set limits for the imbalance netting power interchange, frequency restoration power interchange and control program between the respective LFC areas based on operational security analysis in real-time.
Article 151
Infrastructure
All TSOs of a synchronous area shall specify, in the synchronous area operational agreement, minimum requirements for the availability, reliability and redundancy of the technical infrastructure referred to in paragraph 1 including:
the accuracy, resolution, availability and redundancy of active power flow and virtual tie-line measurements;
the availability and redundancy of digital control systems;
the availability and redundancy of communication infrastructure; and
communication protocols.
Each TSO of a LFC area shall:
ensure a sufficient quality and availability of the FRCE calculation;
perform real-time quality monitoring of the FRCE calculation;
take action in case of FRCE miscalculation; and
where the FRCE is determined by the ACE, perform an ex-post quality monitoring of the FRCE calculation by comparing FRCE to reference values at least on an annual basis.
TITLE 4
OPERATION OF LOAD-FREQUENCY CONTROL
Article 152
System states related to system frequency
All TSOs of each synchronous area shall specify a real-time data exchange in accordance with Article 42 which shall include:
the system state of the transmission system in accordance with Article 18; and
the real-time measurement data of the FRCE of the LFC blocks and LFC areas of the synchronous area.
The LFC block monitor shall be responsible for identifying any violation of the limits in paragraphs 12 and 13 and:
shall inform the other TSOs of the LFC block; and
together with the TSOs of the LFC block shall implement coordinated actions to reduce the FRCE which shall be specified in the LFC block operational agreement.
TITLE 5
FREQUENCY CONTAINMENT RESERVES
Article 153
FCR dimensioning
All TSOs of each synchronous area shall specify dimensioning rules in the synchronous area operational agreement in accordance with the following criteria:
the reserve capacity for FCR required for the synchronous area shall cover at least the reference incident and, for the CE and Nordic synchronous areas, the results of the probabilistic dimensioning approach for FCR carried out pursuant to point (c);
the size of the reference incident shall be determined in accordance with the following conditions:
for the CE synchronous area, the reference incident shall be 3 000 MW in positive direction and 3 000 MW in negative direction;
for the GB, IE/NI, and Nordic synchronous areas, the reference incident shall be the largest imbalance that may result from an instantaneous change of active power such as that of a single power generating module, single demand facility, or single HVDC interconnector or from a tripping of an AC line, or it shall be the maximum instantaneous loss of active power consumption due to the tripping of one or two connection points. The reference incident shall be determined separately for positive and negative direction;
for the CE and Nordic synchronous areas, all TSOs of the synchronous area shall have the right to define a probabilistic dimensioning approach for FCR taking into account the pattern of load, generation and inertia, including synthetic inertia as well as the available means to deploy minimum inertia in real-time in accordance with the methodology referred to in Article 39, with the aim of reducing the probability of insufficient FCR to below or equal to once in 20 years; and
the shares of the reserve capacity on FCR required for each TSO as initial FCR obligation shall be based on the sum of the net generation and consumption of its control area divided by the sum of net generation and consumption of the synchronous area over a period of 1 year.
Article 154
FCR technical minimum requirements
Each TSO of the CE synchronous area shall ensure that the combined reaction of FCR of a LFC area comply with the following requirements:
the