(a) requirements and principles concerning operational security; (b) 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; (c) rules for training and certification of system operator employees; (d) requirements on outage coordination; (e) requirements for scheduling between the TSOs' control areas; and (f) rules aiming at the establishment of a Union framework for load-frequency control and reserves.
Commission Regulation (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation (Text with EEA relevance. )
Modified by
- Commission Implementing Regulation (EU) 2021/280of 22 February 2021amending Regulations (EU) 2015/1222, (EU) 2016/1719, (EU) 2017/2195 and (EU) 2017/1485 in order to align them with Regulation (EU) 2019/943(Text with EEA relevance), 32021R0280, February 23, 2021
(a) 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 Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on requirements for grid connection of generators (OJ L 112, 27.4.2016, p. 1 ).(b) existing and new transmission-connected demand facilities; (c) existing and new transmission-connected closed distribution systems; (d) 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 Commission Regulation (EU) 2016/1388 of 17 August 2016 establishing a Network Code on Demand Connection (OJ L 223, 18.8.2016, p. 10 ).(e) 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 (f) existing and new high voltage direct current ("HVDC") systems in accordance with the criteria in Article 3(1) of Commission Regulation (EU) 2016/1447 Commission Regulation (EU) 2016/1447 of 26 August 2016 establishing a network code on requirements for grid connection of high voltage direct current systems and direct current-connected power park modules (OJ L 241, 8.9.2016, p. 1 ).
(1) "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; (2) "constraint" means a situation in which there is a need to prepare and activate a remedial action in order to respect operational security limits; (3) "N-situation" means the situation where no transmission system element is unavailable due to occurrence of a contingency; (4) "contingency list" means the list of contingencies to be simulated in order to test the compliance with the operational security limits; (5) "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; (6) "frequency containment reserves" or "FCR" means the active power reserves available to contain system frequency after the occurrence of an imbalance; (7) "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; (8) "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; (9) "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; (10) "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; (11) "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; (12) "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; (13) "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; (14) "(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; (15) "(N-1) situation" means the situation in the transmission system in which one contingency from the contingency list occurred; (16) "active power reserve" means the balancing reserves available for maintaining the frequency; (17) "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; (18) "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; (19) "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; (20) "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; (21) "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; (22) "blackout state" means the system state in which the operation of part or all of the transmission system is terminated; (23) "internal contingency" means a contingency within the TSO's control area, including interconnectors; (24) "external contingency" means a contingency outside the TSO's control area and excluding interconnectors, with an influence factor higher than the contingency influence threshold; (25) "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; (26) "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; (27) "contingency analysis" means a computer based simulation of contingencies from the contingency list; (28) "critical fault clearing time" means the maximum fault duration for which the transmission system retains stability of operation; (29) "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; (30) "transmission system element" means any component of the transmission system; (31) "disturbance" means an unplanned event that may cause the transmission system to divert from the normal state; (32) "dynamic stability" is a common term including the rotor angle stability, frequency stability and voltage stability; (33) "dynamic stability assessment" means the operational security assessment in terms of dynamic stability; (34) "frequency stability" means the ability of the transmission system to maintain frequency stable in the N-situation and after being subjected to a disturbance; (35) "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; (36) "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; (37) "emergency state" means the system state in which one or more operational security limits are violated; (38) "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; (39) "exceptional contingency" means the simultaneous occurrence of multiple contingencies with a common cause; (40) "frequency deviation" means the difference between the actual and the nominal frequency of the synchronous area which can be negative or positive; (41) "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; (42) "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; (43) "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; (44) "schedule" means a reference set of values representing the generation, consumption or exchange of electricity for a given time period; (45) "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; (46) "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; (47) "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; (48) "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; (49) "neighbouring TSOs" means the TSOs directly connected via at least one AC or DC interconnector; (50) "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; (51) "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; (52) "operational security ranking" means the ranking used by TSOs to monitor the operational security on the basis of the operational security indicators; (53) "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; (54) "ordinary contingency" means the occurrence of a contingency of a single branch or injection; (55) "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; (56) "ramping rate" means the rate of change of active power by a power generating module, demand facility or HVDC system; (57) "reactive power reserve" means the reactive power which is available for maintaining voltage; (58) "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; (59) "rotor angle stability" means the ability of synchronous machines to remain in synchronism under N-situation and after being subject to a disturbance; (60) "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; (61) "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; (62) "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; (63) "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; (64) "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; (65) "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; (66) "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; (67) "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; (68) "adequacy" means the ability of in-feeds into an area to meet the load in that area; (69) "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; (70) "availability plan" means the combination of all planned availability statuses of a relevant asset for a given time period; (71) "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; (72) "close to real-time" means the time lapse of not more than 15 minutes between the last intraday gate closure and real-time; (73) "consumption schedule" means a schedule representing the consumption of a demand facility or of a group of demand facilities; (74) "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; (75) "external commercial trade schedule" means a schedule representing the commercial exchange of electricity between market participants in different scheduling areas; (76) "external TSO schedule" means a schedule representing the exchange of electricity between TSOs in different scheduling areas; (77) "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; (78) "generation schedule" means a schedule representing the electricity generation of a power generating module or of a group of power generating modules; (79) "internal commercial trade schedule" means a schedule representing the commercial exchange of electricity within a scheduling area between different market participants; (80) "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; (81) "netted area AC position" means the netted aggregation of all AC external schedules of an area; (82) "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; (83) "relevant demand facility" means a demand facility which participates in the outage coordination and the availability status of which influences cross-border operational security; (84) "relevant asset" means any relevant demand facility, relevant power generating module, or relevant grid element partaking in the outage coordination; (85) "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; (86) "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; (87) "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; (88) "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; (89) "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; (90) "scheduling agent" means the entity or entities with the task of providing schedules from market participants to TSOs, or where applicable third parties; (91) "scheduling area" means an area within which the TSOs' obligations regarding scheduling apply due to operational or organisational needs; (92) "week-ahead" means the week prior to the calendar week of operation; (93) "year-ahead" means the year prior to the calendar year of operation; (94) "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; (95) "reserve capacity" means the amount of FCR, FRR or RR that needs to be available to the TSO; (96) "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; (97) "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; (98) "alert state trigger time" means the time before alert state becomes active; (99) "automatic FRR" means FRR that can be activated by an automatic control device; (100) "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; (101) "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; (102) "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; (103) "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; (104) "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; (105) "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; (106) "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; (107) "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; (108) "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; (109) "dimensioning incident" means the highest expected instantaneously occurring active power imbalance within a LFC block in both positive and negative direction; (110) "electrical time deviation" means the time discrepancy between synchronous time and coordinated universal time ("UTC"); (111) "FCR full activation frequency deviation" means the rated value of frequency deviation at which the FCR in a synchronous area is fully activated; (112) "FCR full activation time" means the time period between the occurrence of the reference incident and the corresponding full activation of the FCR; (113) "FCR obligation" means the part of all of the FCR that falls under the responsibility of a TSO; (114) "frequency containment process" or "FCP" means a process that aims at stabilising the system frequency by compensating imbalances by means of appropriate reserves; (115) "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; (116) "frequency quality defining parameter" means the main system frequency variables that define the principles of frequency quality; (117) "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; (118) "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; (119) "frequency quality evaluation data" means the set of data that allows the calculation of the frequency quality evaluation criteria; (120) "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; (121) "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; (122) "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; (123) "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; (124) "frequency restoration power interchange" means the power which is interchanged between LFC areas within the cross-border FRR activation process; (125) "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; (126) "FRR availability requirements" means a set of requirements defined by the TSOs of a LFC block regarding the availability of FRR; (127) "FRR dimensioning rules" means the specifications of the FRR dimensioning process of a LFC block; (128) "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; (129) "imbalance netting power interchange" means the power which is interchanged between LFC areas within the imbalance netting process; (130) "initial FCR obligation" means the amount of FCR allocated to a TSO on the basis of a sharing key; (131) "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; (132) "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; (133) "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; (134) "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; (135) "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; (136) "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; (137) "replacement power interchange" means the power which is interchanged between LFC areas within the cross-border RR activation process; (138) "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; (139) "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; (140) "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; (141) "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; (142) "process activation structure" means the structure to categorise the processes concerning the different types of active power reserves in terms of purpose and activation; (143) "manual FRR full activation time" means the time period between the setpoint change and the corresponding activation or deactivation of manual FRR; (144) "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; (145) "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; (146) "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; (147) "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; (148) "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; (149) "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; (150) "reserve connecting TSO" means the TSO responsible for the monitoring area to which a reserve providing unit or reserve providing group is connected; (151) "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; (152) "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; (153) "RR availability requirements" means a set of requirements defined by the TSOs of a LFC block regarding the availability of RR; (154) "RR dimensioning rules" means the specifications of the RR dimensioning process of a LFC block; (155) "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; (156) "standard frequency deviation" means the absolute value of the frequency deviation that limits the standard frequency range; (157) "steady state frequency deviation" means the absolute value of frequency deviation after occurrence of an imbalance, once the system frequency has been stabilised; (158) "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; (159) "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.
(a) determining common operational security requirements and principles; (b) determining common interconnected system operational planning principles; (c) determining common load-frequency control processes and control structures; (d) ensuring the conditions for maintaining operational security throughout the Union; (e) ensuring the conditions for maintaining a frequency quality level of all synchronous areas throughout the Union; (f) promoting the coordination of system operation and operational planning; (g) ensuring and enhancing the transparency and reliability of information on transmission system operation; (h) contributing to the efficient operation and development of the electricity transmission system and electricity sector in the Union.
(a) apply the principles of proportionality and non-discrimination; (b) ensure transparency; (c) apply the principle of optimisation between the highest overall efficiency and lowest total costs for all parties involved; (d) ensure TSOs make use of market-based mechanisms as far as possible, to ensure network security and stability; (e) respect the responsibility assigned to the relevant TSO in order to ensure system security, including as required by national legislation; (f) consult with relevant DSOs and take account of potential impacts on their system; and (g) take into consideration agreed European standards and technical specifications.
(a) TSOs representing at least 55 % of the Member States; and (b) TSOs representing Member States comprising at least 65 % of the population of the Union.
(a) TSOs representing at least 72 % of the Member States concerned; and (b) TSOs representing Member States comprising at least 65 % of the population of the concerned region.
(a) key organizational requirements, roles and responsibilities in relation to data exchange related to operational security in accordance with Article 40(6); (b) methodology for building the common grid models in accordance with Article 67(1) and Article 70; (c) methodology for coordinating operational security analysis in accordance with Article 75.
(a) methodology for each synchronous area for the definition of minimum inertia in accordance with Article 39(3)(b); (b) common provisions for each capacity calculation region for regional operational security coordination in accordance with Article 76; (c) methodology, at least per synchronous area, for assessing the relevance of assets for outage coordination in accordance with Article 84; (d) methodologies, conditions and values included in the synchronous area operational agreements in Article 118 concerning: (i) the frequency quality defining parameters and the frequency quality target parameter in accordance with Article 127; (ii) the dimensioning rules for FCR in accordance with Article 153; (iii) the additional properties of the FCR in accordance with Article 154(2); (iv) for the GB and IE/NI synchronous areas, the measures to ensure the recovery of energy reservoirs in accordance with Article 156(6)(b); (v) for the CE and Nordic synchronous areas, the minimum activation period to be ensured by FCR providers in accordance with Article 156(10); (vi) for the CE and Nordic synchronous areas, the assumptions and methodology for a cost-benefit analysis in accordance with Article 156(11); (vii) for synchronous areas other than CE and if applicable, the limits for the exchange of FCR between TSOs in accordance with Article 163(2); (viii) 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); (ix) 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); (x) 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);
(e) methodologies and conditions included in the LFC block operational agreements in Article 119, concerning: (i) ramping restrictions for active power output in accordance with Article 137(3) and (4); (ii) coordination actions aiming to reduce FRCE as defined in Article 152(14); (iii) 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); (iv) the FRR dimensioning rules in accordance with Article 157(1);
(f) mitigation measures per synchronous area or LFC block in accordance with Article 138; (g) common proposal per synchronous area for the determination of LFC blocks in accordance with Article 141(2).
(a) 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; (b) scope of data exchange with DSOs and significant grid users in accordance with Article 40(5); (c) additional requirements for FCR providing groups in accordance with Article 154(3); (d) exclusion of FCR providing groups from the provision of FCR in accordance with Article 154(4); (e) 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); (f) FRR technical requirements defined by the TSO in accordance with Article 158(3); (g) rejection of FRR providing groups from the provision of FRR in accordance with Article 159(7); (h) technical requirements for the connection of RR providing units and RR providing groups defined by the TSO in accordance with Article 161(3); and (i) rejection of RR providing groups from the provision of RR in accordance with Article 162(6).
(a) enhancements of network operation tools in accordance with Article 55(e); (b) FRCE target parameters in accordance with Article 128; (c) ramping restrictions on synchronous area level in accordance with Article 137(1); (d) ramping restrictions on LFC block level in accordance with Article 137(3); (e) measures taken in the alert state due to there being insufficient active power reserves in accordance with Article 152(11); and (f) request of the reserve connecting TSO to an FCR provider to make the information available in real time in accordance with Article 154(11).
(a) operational security indicators in accordance with Article 15; (b) load-frequency control in accordance with Article 16; (c) regional coordination assessment in accordance with Article 17; (d) identification of any divergences in the national implementation of this Regulation for the terms and conditions or methodologies listed in Article 6(3); (e) 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); (f) 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 (g) identification of any difficulties concerning cooperation on secure system operation with third country TSOs.
(a) number of tripped transmission system elements per year per TSO; (b) number of tripped power generation facilities per year per TSO; (c) energy not supplied per year due to unscheduled disconnection of demand facilities per TSO; (d) time duration and number of instances of being in the alert and emergency states per TSO; (e) time duration and number of events within which there was a lack of reserves identified per TSO; (f) time duration and number of voltage deviations exceeding the ranges from Tables 1 and 2 of Annex II per TSO; (g) number of minutes outside the standard frequency range and number of minutes outside the 50 % of maximum steady state frequency deviation per synchronous area; (h) number of system-split separations or local blackout states; and (i) number of blackouts involving two or more TSOs.
(a) number of events in which an incident contained in the contingency list led to a degradation of the system operation state; (b) 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; (c) number of events in which there was a degradation in system operation conditions due to an exceptional contingency; (d) 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 (e) number of events leading to a degradation in system operation conditions due to lack of active power reserves.
(a) the identification of the LFC blocks, LFC areas and monitoring areas in the Member State; (b) 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; (c) the identification of the synchronous areas each Member State belongs to; (d) 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; (e) 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 (f) 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.
(a) the number of events, average duration and reasons for the failure to fulfil its functions; (b) 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; (c) the number of instances where TSOs refuse to implement the remedial actions recommended by the regional security coordinator and the reasons thereof; (d) the number of outage incompatibilities detected in accordance with Article 80; and (e) a description of the cases where the lack of regional adequacy has been assessed and a description of mitigation actions set in place.
(a) voltage and power flows are within the operational security limits defined in accordance with Article 25; (b) frequency meets the following criteria: (i) the steady state system frequency deviation is within the standard frequency range; or (ii) 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;
(c) 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; (d) 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) voltage and power flows are within the operational security limits defined in accordance with Article 25; and (b) 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 (c) frequency meets the following criteria: (i) the absolute value of the steady state system frequency deviation is not larger than the maximum steady state frequency deviation; and (ii) 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
(d) 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) there is at least one a violation of a TSO's operational security limits defined in accordance with Article 25; (b) frequency does not meet the criteria for the normal state and for the alert state defined in accordance with paragraphs 1 and 2; (c) at least one measure of the TSO's system defence plan is activated; (d) 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) loss of more than 50 % of demand in the concerned TSO's control area; (b) total absence of voltage for at least three minutes in the concerned TSO's control area, leading to the triggering of restoration plans.
(a) active and reactive power flows; (b) busbar voltages; (c) frequency and frequency restoration control error of its LFC area; (d) active and reactive power reserves; and (e) generation and load.
(a) 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 (b) provide with additional information on its transmission system elements which are part of the observability area of other TSOs, to those TSOs.
(a) 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; (b) 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).
(a) activate the most effective and economically efficient remedial actions; (b) 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; (c) consider the risks of failures in applying the available remedial actions and their impact on operational security such as: (i) the risks of failure or short-circuit caused by topology changes; (ii) the risks of outages caused by active or reactive power changes on power generating modules or demand facilities; and (iii) the risks of malfunction caused by equipment behaviour;
(d) give preference to remedial actions which make available the largest cross-zonal capacity for capacity allocation, while satisfying all operational security limits.
(a) modify the duration of a planned outage or return to service transmission system elements to achieve the operational availability of those transmission system elements; (b) actively impact power flows by means of: (i) tap changes of the power transformers; (ii) tap changes of the phase-shifting transformers; (iii) modifying topologies;
(c) control voltage and manage reactive power by means of: (i) tap changes of the power transformers; (ii) switching of the capacitors and reactors; (iii) switching of the power-electronics-based devices used for voltage and reactive power management; (iv) 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; (v) requesting the change of reactive power output or voltage setpoint of the transmission-connected synchronous power generating modules; (vi) requesting the change of reactive power output of the converters of transmission-connected non-synchronous power generating modules;
(d) re-calculate day-ahead and intraday cross-zonal capacities in accordance with Regulation (EU) 2015/1222; (e) redispatch transmission or distribution-connected system users within the TSO's control area, between two or more TSOs; (f) countertrade between two or more bidding zones; (g) adjust active power flows through HVDC systems; (h) activate frequency deviation management procedures; (i) 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 (j) where applicable, include the normal or alert state, manually controlled load-shedding.
(a) the monitoring and determination of system states in accordance with Article 19; (b) the contingency analysis in real-time operation in accordance with Article 34; and (c) the contingency analysis in operational planning in accordance with Article 72.
(a) facilities for monitoring the system state of the transmission system, including state estimation applications and facilities for load-frequency control; (b) means to control the switching of circuit breakers, coupler circuit breakers, transformer tap changers and other equipment which serve to control transmission system elements; (c) means to communicate with the control rooms of other TSOs and RSCs; (d) tools for operational security analysis; and (e) tools and communication means necessary for TSOs to facilitate cross-border market operations.
(a) voltage limits in accordance with Article 27; (b) short-circuit current limits according to Article 30; and (c) current limits in terms of thermal rating including the transitory admissible overloads.
(a) the maximum short-circuit current at which the rated capability of circuit breakers and other equipment is exceeded; and (b) the minimum short-circuit current for the correct operation of protection equipment.
(a) use the most accurate and high quality available data; (b) take into account international standards; and (c) 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.
(a) each TSO shall classify contingencies for its own control area; (b) 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 (c) 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.
(a) during switching sequences; (b) during the time period required to prepare and activate remedial actions.
(a) ensure that each special protection scheme acts selectively, reliably and effectively; (b) 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; (c) verify that the special protection scheme has a comparable reliability to the protection systems used for the primary protection of transmission system elements; (d) operate the transmission system with the special protection scheme within the operational security limits determined in accordance with Article 25; and (e) 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.
(a) the scope of the coordinated dynamic stability assessment, at least in terms of a common grid model; (b) the set of data to be exchanged between concerned TSOs in order to perform the coordinated dynamic stability assessment; (c) a list of commonly agreed scenarios concerning the coordinated dynamic stability assessment; and (d) a list of commonly agreed contingencies or disturbances whose impact shall be assessed through the coordinated dynamic stability assessment.
(a) 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; (b) 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 (c) 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.
(a) 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; (b) 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 (c) 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).
(a) generation; (b) consumption; (c) schedules; (d) balance positions; (e) planned outages and substation topologies; and (f) forecasts.
(a) structural data in accordance with Article 48; (b) scheduling and forecast data in accordance with Article 49; (c) real-time data in accordance with Articles 44, 47 and 50; and (d) provisions in accordance with Articles 51, 52 and 53.
(a) 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; (b) 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; (c) 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; (d) 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; (e) 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; (f) 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 (g) the format for the reporting of the data and information established pursuant to this Title.
(a) the regular topology of substations and other relevant data, by voltage level; (b) technical data on transmission lines; (c) technical data on transformers connecting the DSOs, SGUs which are demand facilities and generators' block-transformers of SGUs which are power generating facilities; (d) the maximum and minimum active and reactive power of SGUs which are power generating modules; (e) technical data on phase-shifting transformers; (f) technical data on HVDC systems; (g) technical data on reactors, capacitors and static volt-ampere reactive (VAR) compensators; and (h) operational security limits defined by each TSO according to Article 25.
(a) the topology of the 220 kV and higher voltage transmission systems within its control area; (b) a model or an equivalent of the transmission system with voltage below 220 kV with significant impact on its own transmission system; (c) the thermal limits of the transmission system elements; and (d) 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.
(a) data concerning SGUs which are power generating modules relating to, but not limited to: (i) electrical parameters of the alternator suitable for the dynamic stability assessment, including total inertia; (ii) protection models; (iii) alternator and prime mover; (iv) step-up transformer description; (v) minimum and maximum reactive power; (vi) voltage models and speed controller models; and (vii) prime movers models and excitation system models suitable for large disturbances;
(b) 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 (c) 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.
(a) frequency; (b) frequency restoration control error; (c) measured active power interchanges between LFC areas; (d) aggregated generation infeed; (e) system state in accordance with Article 18; (f) setpoint of the load-frequency controller; and (g) power interexchange via virtual tie-lines.
(a) actual substation topology; (b) active and reactive power in line bay, including transmission, distribution and lines connecting SGUs; (c) active and reactive power in transformer bay, including transmission, distribution and SGUs connecting transformers; (d) active and reactive power in power generating facility bay; (e) regulating positions of transformers, including phase-shifting transformers; (f) measured or estimated busbar voltage; (g) reactive power in reactor and capacitor bay or from a static VAR compensator; and (h) restrictions on active and reactive power supply capabilities with respect to the observability area.
(a) substations by voltage; (b) lines that connect the substations referred to in point (a); (c) transformers from the substations referred to in point (a); (d) SGUs; and (e) reactors and capacitors connected to the substations referred to in point (a).
(a) the actual substation topology; (b) the active and reactive power in line bay; (c) the active and reactive power in transformer bay; (d) the active and reactive power injection in power generating facility bay; (e) the tap positions of transformers connected to the transmission system; (f) the busbar voltages; (g) the reactive power in reactor and capacitor bay; (h) the best available data for aggregated generation per primary energy source in the DSO area; and (i) the best available data for aggregated demand in the DSO area.
(a) general data of the power generating module, including installed capacity and primary energy source; (b) turbine and power generating facility data including time for cold and warm start; (c) data for short-circuit current calculation; (d) power generating facility transformer data; (e) FCR data of power generating modules offering or providing that service, in accordance with Article 154; (f) FRR data of power generating modules offering or providing that service, in accordance with Article 158; (g) RR data of power generating modules that offer or provide that service in accordance with Article 161; (h) data necessary for restoration of the transmission system; (i) data and models necessary for performing dynamic simulation; (j) protection data; (k) 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; (l) voltage and reactive power control capability.
(a) general data of the power generating module, including installed capacity and primary energy source; (b) data for short-circuit current calculation; (c) FCR data according to the definition and requirements of the Article 173 for power generating modules offering or providing that service; (d) FRR data for power generating modules that offer or provide that service; (e) RR data for power generating modules that offer or provide that service; (f) protection data; (g) reactive power control capability; (h) 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; (i) data necessary for performing dynamic stability assessment according to Article 38.
(a) nameplate data of the installation; (b) transformers data; (c) data on filters and filter banks; (d) reactive power compensation data; (e) active power control capability; (f) reactive power and voltage control capability; (g) active or reactive operational mode prioritization, if existing; (h) frequency response capability; (i) dynamic models for dynamic simulation; (j) protection data; and (k) fault-ride-through capability.
(a) nameplate data of the installation; (b) electrical parameters; (c) associated protections.
(a) active power output and active power reserves amount and availability, on a day-ahead and intra-day basis; (b) without any delay, any scheduled unavailability or active power restriction; (c) any forecasted restriction in the reactive power control capability; and (d) 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.
(a) active power schedule and availability on a day-ahead and intra-day basis; (b) without delay its scheduled unavailability or active power restriction; and (c) any forecast restriction in the reactive power or voltage control capability.
(a) position of the circuit breakers at the connection point or another point of interaction agreed with the TSO; (b) active and reactive power at the connection point or another point of interaction agreed with the TSO; and (c) in the case of power generating facility with consumption other than auxiliary consumption net active and reactive power.
(a) position of the circuit breakers; (b) operational status; and (c) active and reactive power.
(a) general data of the power generating module, including installed capacity and primary energy source or fuel type; (b) FCR data according to the definition and requirements of Article 173 for power generating facilities offering or providing the FCR service; (c) FRR data for power generating facilities offering or providing the FRR service; (d) RR data for power generating modules offering or providing the RR service; (e) protection data; (f) reactive power control capability; (g) capability of remote access to the circuit breaker; (h) data necessary for performing dynamic simulation according to the provisions in Regulation (EU) 2016/631; and (i) voltage level and location of each power generating module.
(a) its scheduled unavailability, scheduled active power restriction and its forecasted scheduled active power output at the connection point; (b) any forecasted restriction in the reactive power control capability; and (c) 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.
(a) status of the switching devices and circuit breakers at the connection point; and (b) active and reactive power flows, current, and voltage at the connection point.
(a) electrical data of the transformers connected to the transmission system; (b) characteristics of the load of the demand facility; and (c) characteristics of the reactive power control.
(a) scheduled active and forecasted reactive power consumption on a day-ahead and intraday basis, including any changes of those schedules or forecast; (b) any forecasted restriction in the reactive power control capability; (c) in case of participation in demand response, a schedule of its structural minimum and maximum power range to be curtailed; and (d) 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.
(a) active and reactive power at the connection point; and (b) the minimum and maximum power range to be curtailed.
(a) 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; (b) a forecast of unrestricted active power available for demand response and any planned demand response; (c) real-time active and reactive power at the connection point; and (d) a confirmation that the estimations of the actual values of demand response are applied.
(a) 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; (b) 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; (c) real-time active and reactive power; and (d) a confirmation that the estimations of the actual values of demand response are applied.
(a) develop and implement network operation tools that are relevant for its control area and related to real-time operation and operational planning; (b) develop and deploy tools and solutions for the prevention and remedy of disturbances; (c) use services provided by third parties, through procurement when applicable, such as redispatching or countertrading, congestion management services, generation reserves and other ancillary services; (d) 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 (e) 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.
(a) 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; (b) 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; (c) 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; (d) 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.
(a) the TSO to ensure correct functioning of transmission system elements; (b) the DSO and SGUs to ensure correct functioning of distribution systems and of the SGUs' facilities; (c) the TSO, DSO or SGU to maintain existing and develop new operational practices; (d) the TSO to ensure fulfilment of ancillary services; (e) 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: (i) controlled application of frequency or voltage variations aimed at gathering information on transmission system and elements' behaviour; and (ii) tests of operational practices in emergency state and restoration state.
(a) incorporated into the training and certification process of the employees in charge of real-time operation; (b) used as inputs to the research and development process of ENTSO for Electricity; and (c) used to improve operational practices including also those in emergency and restoration state.
(a) all documentation and equipment certificates to be provided by the SGU; (b) details of the technical data of the SGU facility with relevance for the system operation; (c) requirements for models for dynamic stability assessment; and (d) studies by the SGU demonstrating expected outcome of the dynamic stability assessment, where applicable.
(a) 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; (b) 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; (c) a training program for its employees in charge of balancing.
(a) a description of the transmission system elements; (b) operation of the transmission system in all system states including restoration; (c) use of the on-the-job systems and processes; (d) coordination of inter-TSO operations and market arrangements; (e) recognition of and response to exceptional operational situations; (f) relevant areas of electrical power engineering; (g) relevant aspects of the Union internal electricity market; (h) relevant aspects of the network codes or guidelines adopted according to Articles 6 and 18 of Regulation (EC) No 714/2009; (i) safety and security of persons, nuclear and other equipment in transmission system operation; (j) 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; (k) joint training with transmission-connected DSOs and SGUs, where appropriate; (l) behavioural skills with particular focus on stress management, human acting in critical situation, responsibility and motivation skills; and (m) operational planning practices and tools, including those used with the relevant regional security coordinators in the operational planning.
(a) the qualifications and selection process for TSO employees to be trained; (b) the training required for certification of the system operator employees in charge of real-time operation; (c) the processes, including relevant documentation, for the initial and the rolling training programs; (d) the process for certification of system operator employees in charge of real-time operation; and (e) the process for extension of a training period and certification period for the system operator employees in charge of real-time operation.
(a) year-ahead, in accordance with Articles 66, 67 and 68; (b) where applicable, week-ahead, in accordance with Article 69; (c) day-ahead, in accordance with Article 70; and (d) intraday, in accordance with Article 70.
(a) electricity demand; (b) the conditions related to the contribution of renewable energy sources; (c) determined import/export positions, including agreed reference values allowing the merging task; (d) the generation pattern, with a fully available production park; (e) the year-ahead grid development.
(a) the typical cross-border exchange patterns for different levels of consumption and of renewable energy sources and conventional generation; (b) the probability of occurrence of the scenarios; (c) the potential deviations from operational security limits for each scenario; (d) the amount of power generated and consumed by the power generating facilities and demand facilities connected to distribution systems.
(a) Winter Peak, 3rd Wednesday of January current year, 10:30 CET; (b) Winter Valley, 2nd Sunday of January current year, 03:30 CET; (c) Spring Peak, 3rd Wednesday of April current year, 10:30 CET; (d) Spring Valley, 2nd Sunday of April current year, 03:30 CET; (e) Summer Peak, 3rd Wednesday of July previous year, 10:30 CET; (f) Summer Valley, 2nd Sunday of July previous year, 03:30 CET; (g) Autumn Peak, 3rd Wednesday of October previous year, 10:30 CET; (h) Autumn Valley, 2nd Sunday of October previous year, 03:30 CET.
(a) agree with the neighbouring TSOs upon the estimated power flow on HVDC systems linking their control areas; (b) balance for each scenario the sum of: (i) net exchanges on AC lines; (ii) estimated power flows on HVDC systems; (iii) load, including an estimation of losses; and (iv) generation.
(a) be consistent with the structural data provided in accordance with the requirements of Articles 41, 43, 45 and 48; (b) be consistent with the scenarios developed in accordance with Article 65; and (c) distinguish the type of primary energy source.
(a) deadlines for gathering the year-ahead individual grid models, for merging them into a common grid model and for saving the individual and common grid models; (b) quality control of the individual and common grid models to be implemented in order to ensure their completeness and consistency; and (c) correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (b).
(a) definition of timestamps; (b) deadlines for gathering the individual grid models, for merging them into a common grid model and for saving individual and common grid models. The deadlines shall be compatible with the regional processes established for preparing and activating remedial actions; (c) quality control of individual grid models and the common grid model to be implemented to ensure their completeness and consistency; (d) correction and improvement of individual and common grid models, implementing at least the quality controls referred to in point (c); and (e) handling additional information related to operational arrangements, such as protection setpoints or system protection schemes, single line diagrams and configuration of substations in order to manage operational security.
(a) up-to-date load and generation forecasts; (b) the available results of the day-ahead and intraday market processes; (c) the available results of the scheduling tasks described in Title 6 of Part III; (d) for power generating facilities connected to distribution systems, aggregated active power output differentiated on the basis of the type of primary energy source, in line with data provided in accordance with Articles 40, 43, 44, 48, 49 and 50; (e) up-to-date topology of the transmission system.
(a) the coherence of the connection status of interconnectors; (b) that voltage values are within the usual operational values for those transmission system elements having influence on other control areas; (c) the coherence of transitory admissible overloads of interconnectors; and (d) that active power and reactive power injections or withdrawals are compatible with usual operational values.
(a) year-ahead; (b) week-ahead, when applicable in accordance with Article 69; (c) day-ahead; and (d) intraday.
(a) power flows and voltages exceeding operational security limits; (b) violations of stability limits of the transmission system identified in accordance with Article 38(2) and (6); and (c) violations of short-circuit thresholds of the transmission system.
(a) methods for assessing the influence of transmission system elements and SGUs located outside of a TSO's control area in order to identify those elements included in the TSO's observability area and the contingency influence thresholds above which contingencies of those elements constitute external contingencies; (b) principles for common risk assessment, covering at least, for the contingencies referred to in Article 33: (i) associated probability; (ii) transitory admissible overloads; and (iii) impact of contingencies;
(c) principles for assessing and dealing with uncertainties of generation and load, taking into account a reliability margin in line with Article 22 of Regulation (EU) 2015/1222; (d) requirements on coordination and information exchange between regional security coordinators in relation to the tasks listed in Article 77(3); (e) role of ENTSO for Electricity in the governance of common tools, data quality rules improvement, monitoring of the methodology for coordinated operational security analysis and of the common provisions for regional operational security coordination in each capacity calculation region.
(a) connectivity status or electrical values (such as voltages, power flows, rotor angle) which significantly influence the accuracy of the results of the state estimation for the TSO's control area, above common thresholds; (b) connectivity status or electrical values (such as voltages, power flows, rotor angle) which significantly influence the accuracy of the results of the TSO's operational security analysis, above common thresholds; and (c) requirement to ensure an adequate representation of the connected elements in the TSO's observability area.
(a) each element has an influence factor on electrical values, such as voltages, power flows, rotor angle, in the TSO's control area greater than common contingency influence thresholds, meaning that the outage of this element can significantly influence the results of the TSO's contingency analysis; (b) the choice of the contingency influence thresholds shall minimize the risk that the occurrence of a contingency identified in another TSO's control area and not in the TSO's external contingency list could lead to a TSO's system behaviour deemed not acceptable for any element of its internal contingency list, such as an emergency state; (c) the assessment of such a risk shall be based on situations representative of the various conditions which can be expected, characterised by variables such as generation level and pattern, exchange levels, asset outages.
(a) the consistency in the definition of exceptional contingencies; (b) the evaluation of the probability and impact of exceptional contingencies; and (c) the consideration of exceptional contingencies in a TSO's contingency list when their probability exceeds a common threshold.
(a) harmonised conditions where one TSO shall update its operational security analysis. The conditions shall take into account relevant aspects such as the time horizon of the generation and demand forecasts, the level of change of forecasted values within the TSO's control area or within the control area of other TSOs, location of generation and demand, the previous results of its operational security analysis; and (b) minimum frequency of generation and demand forecast updates, depending on their variability and the installed capacity of non-dispatchable generation.
(a) conditions and frequency of intraday coordination of operational security analysis and updates to the common grid model by the regional security coordinator; (b) the methodology for the preparation of remedial actions managed in a coordinated way, considering their cross-border relevance as determined in accordance with Article 35 of Regulation (EU) 2015/1222, taking into account the requirements in Articles 20 to 23 and determining at least: (i) the procedure for exchanging the information of the available remedial actions, between relevant TSOs and the regional security coordinator; (ii) the classification of constraints and the remedial actions in accordance with Article 22; (iii) the identification of the most effective and economically efficient remedial actions in case of operational security violations referred to in Article 22; (iv) the preparation and activation of remedial actions in accordance with Article 23(2); (v) the sharing of the costs of remedial actions referred to in Article 22, complementing where necessary the common methodology developed in accordance with Article 74 of Regulation (EU) 2015/1222. As a general principle, costs of non-cross-border relevant congestions shall be borne by the TSO responsible for the given control area and costs of relieving cross-border-relevant congestions shall be covered by TSOs responsible for the control areas in proportion to the aggravating impact of energy exchange between given control areas on the congested grid element.
(a) the appointment of the regional security coordinator(s) that will perform the tasks in paragraph 3 for that capacity calculation region; (b) rules concerning the governance and operation of regional security coordinator(s), ensuring equitable treatment of all member TSOs; (c) where the TSOs propose to appoint more than one regional security coordinator in accordance with subparagraph (a): (i) a proposal for a coherent allocation of the tasks between the regional security coordinators who will be active in that capacity calculation region. The proposal shall take full account of the need to coordinate the different tasks allocated to the regional security coordinators; (ii) an assessment demonstrating that the proposed setup of regional security coordinators and allocation of tasks is efficient, effective and consistent with the regional coordinated capacity calculation established pursuant to Articles 20 and 21 of Regulation (EU) 2015/1222; (iii) an effective coordination and decision making process to resolve conflicting positions between regional security coordinators within the capacity calculation region.
(a) each TSO shall be covered by at least one regional security coordinator; (b) all TSOs shall ensure that the total number of regional security coordinators across the Union is not higher than six.
(a) regional operational security coordination in accordance with Article 78 in order to support TSOs fulfil their obligations for the year-ahead, day-ahead and intraday time-frames in Article 34(3) and Articles 72 and 74; (b) building of common grid model in accordance with Article 79; (c) regional outage coordination in accordance with Article 80, in order to support TSOs fulfil their obligations in Articles 98 and 100; (d) regional adequacy assessment in accordance with Article 81 in order to support TSOs fulfil their obligations under Article 107.
(a) the updated contingency list, established according to the criteria defined in the methodology for coordinating operational security analysis adopted in accordance with Article 75(1); (b) the updated list of possible remedial actions, among the categories listed in Article 22, and their anticipated costs provided in accordance with Article 35 of Regulation (EU) 2015/1222 if a remedial action includes redispatching or countertrading, aimed at contributing to relieve any constraint identified in the region; and (c) the operational security limits established in accordance with Article 25.
(a) perform the coordinated regional operational security assessment in accordance with Article 76 on the basis of the common grid models established in accordance with Article 79, the contingency list and the operational security limits provided by each TSOs in paragraph 1. It shall deliver the results of the coordinated regional operational security assessment at least to all TSOs of the capacity calculation region. Where it detects a constraint, it shall recommend to the relevant TSOs the most effective and economically efficient remedial actions and may also recommend remedial actions other than those provided by the TSOs. This recommendation for remedial actions shall be accompanied by explanations as to its rationale; (b) coordinate the preparation of remedial actions with and among TSOs in accordance with Article 76(1)(b), to enable TSOs achieve a coordinated activation of remedial actions in real-time.
(a) the availability plans of its internal relevant assets, stored on the ENTSO for Electricity operational planning data environment; (b) the most recent availability plans for all non-relevant assets of its control area which are: (i) capable of influencing the results of the outage planning incompatibility analysis; (ii) modelled in the individual grid models which are used for the outage incompatibility assessment;
(c) scenarios on which the outage planning incompatibilities have to be investigated and used to build the corresponding common grid models derived from the common grid models for different time-frames established in accordance with Articles 67 and 79.
(a) the expected total load and available resources of demand response; (b) the availability of power generation modules; and (c) the operational security limits.
(a) frequency, scope and type of coordination for, at least, the year-ahead and week-ahead time-frames; (b) provisions concerning the use of the assessments carried out by the regional security coordinator in accordance with Article 80; (c) practical arrangements for the validation of the year-ahead relevant grid element availability plans, as required by Article 98.
(a) quantitative aspects based on the evaluation of changes of electrical values such as voltages, power flows, rotor angle on at least one grid element of a TSO's control area, due to the change of availability status of a potential relevant asset located in another control area. That evaluation shall take place on the basis of year-ahead common grid models; (b) thresholds on the sensitivity of the electrical values referred to in point (a), against which to assess the relevance of an asset. Those thresholds shall be harmonised at least per synchronous area; (c) capacity of potential relevant power generating modules or demand facilities to qualify as SGUs; (d) qualitative aspects such as, but not limited to, the size and proximity to the borders of a control area of potential relevant power generating modules, demand facilities or grid elements; (e) systematic relevance of all grid elements located in a transmission system or in a distribution system which connect different control areas; and (f) systematic relevance of all critical network elements.
(a) inform the owner of the relevant power generating module or relevant demand facility about its inclusion in the list; (b) inform DSOs about the relevant power generating modules and the relevant demand facilities which are connected to their distribution system; and (c) inform CDSOs about the relevant power generating modules and the relevant demand facilities which are connected to their closed distribution system.
(a) inform the owner of the relevant grid element about its inclusion in the list; (b) inform DSOs about the relevant grid elements which are connected to their distribution system; and (c) inform CDSOs about the relevant grid elements which are connected to their closed distribution system.
(a) "available" where the relevant asset is capable of and ready for providing service regardless of whether it is or it is not in operation; (b) "unavailable" where the relevant asset is not capable of or ready for providing service; (c) "testing" where the capability of the relevant asset for providing service is being tested.
(a) between first connection and final commissioning of the relevant asset; and (b) directly following maintenance of the relevant asset.
(a) the reason for the "unavailable" status of a relevant asset; (b) where such conditions are identified, the conditions to be fulfilled before applying the "unavailable" status of a relevant asset in real-time; (c) the time required to restore a relevant asset back to service where necessary in order to maintain operational security.
(a) following the order in which the requests were received; and (b) applying the procedure established in accordance with Article 100.
(a) inform each affected outage planning agent of the conditions it shall fulfil to mitigate the detected outage planning incompatibilities; (b) the TSO may request that one or more outage planning agents submit an alternative availability plan fulfilling the conditions referred to in point (a); and (c) the TSO shall repeat the assessment pursuant to paragraph 1 to determine whether any outage planning incompatibilities remain.
(a) take into account the impact reported by the affected outage planning agents as well as the DSO or CDSO where relevant; (b) limit the changes in the alternative availability plan to what is strictly necessary to mitigate the outage planning incompatibilities; and (c) notify its regulatory authority, the affected DSOs and CDSOs if any, and the affected outage planning agents about the alternative availability plan, including the reasons for developing it, as well as the impact reported by the affected outage planning agents and, where relevant, the DSOs or CDSOs.
(a) minimize the impact on the market while preserving operational security; and (b) use as a basis the availability plans submitted and developed in accordance with Article 94.
(a) take the necessary actions to plan the "unavailable" status while ensuring operational security, taking into account the impact reported to the TSO by affected outage planning agents; (b) notify the actions referred to in point (a) to all affected parties; and (c) notify the relevant regulatory authorities, the affected DSOs or CDSOs if any and the affected outage planning agents of the actions taken, including the rationale for such actions, the impact reported by affected outage planning agents and the DSOs or CDSOs where relevant.
(a) force to "available" status all the "unavailable" or "testing" statuses for the relevant assets involved in an outage planning incompatibility during the period concerned; and (b) notify to the relevant regulatory authorities, the affected DSOs or CDSOs, if any, and the affected outage planning agents of the actions taken including the rationale for such actions, the impact reported by affected outage planning agents and the DSOs or CDSOs where relevant.
(a) finalise the year-ahead outage coordination of internal relevant assets; and (b) finalise the year-ahead availability plans for internal relevant assets and store them on the ENTSO for Electricity operational planning data environment.
(a) the recipient TSO shall acknowledge the request and assess as soon as reasonably practicable whether the amendment leads to outage planning incompatibilities; (b) where outage planning incompatibilities are detected, the involved TSOs of the outage coordination region shall jointly identify a solution in coordination with the outage planning agents concerned and, if relevant, the DSOs and CDSOs, using the means at their disposal; (c) where no outage planning incompatibility has been detected or if no outage planning incompatibility remains, the recipient TSO shall validate the requested amendment, and the TSOs concerned shall consequently notify all affected parties and update the final year-ahead availability plan on the ENTSO for Electricity operational planning data environment; and (d) where no solution is found for outage planning incompatibilities the recipient TSO shall reject the requested amendment.
(a) the requesting TSO shall prepare a proposal for amendment to the year-ahead availability plan, including an assessment of whether it could lead to outage planning incompatibilities and shall submit its proposal to all other TSOs of its outage coordination region(s); (b) where outage planning incompatibilities are detected, the involved TSOs of the outage coordination region shall jointly identify a solution in coordination with the concerned outage planning agents and, if relevant, the DSOs and the CDSOs, using the means at their disposal; (c) where no outage planning incompatibility has been detected or if a solution to an outage planning incompatibility is found, the concerned TSOs shall validate the requested amendment and consequently they shall notify all affected parties and update the final year-ahead availability plan on the ENTSO for Electricity operational planning data environment; (d) where no solution to outage planning incompatibilities are found, the requesting TSO shall retract the procedure for amendment.
(a) a detailed test plan; (b) an indicative generation or consumption schedule if the concerned relevant asset is a relevant power generating module or a relevant demand facility; and (c) changes to the topology of the transmission system or distribution system if the concerned relevant asset is a relevant grid element.
(a) the reason for the forced outage; (b) the expected duration of the forced outage; and (c) where applicable, the impact of the forced outage on the availability status of other relevant assets for which it is the outage planning agent.
(a) use the latest availability plans and the latest available data for: (i) the capabilities of power generating modules provided pursuant to Article 43(5) and Articles 45 and 51; (ii) cross-zonal capacity; (iii) possible demand response provided pursuant to Articles 52 and 53;
(b) take into account the contributions of generation from renewable energy sources and load; (c) assess the probability and expected duration of an absence of adequacy and the expected energy not supplied as a result of such absence.
(a) schedules referred to in Article 111; (b) forecasted load; (c) forecasted generation from renewable energy sources; (d) active power reserves in accordance with the data provided pursuant to Article 46(1)(a); (e) control area import and export capacities consistent with cross-zonal capacities calculated where applicable in accordance with Article 14 of Regulation (EU) 2015/1222; (f) 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 (g) capabilities of demand facilities with demand response in accordance with the data provided pursuant to Articles 52 and 53 and their availability statuses.
(a) the minimum level of import and the maximum level of export compatible with its control area adequacy; (b) the expected duration of a potential absence of adequacy; and (c) the amount of energy not supplied in the absence of adequacy.
(a) design, set up and manage the procurement of ancillary services; (b) 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 (c) use all available economically efficient and feasible means to procure the necessary level of ancillary services.
(a) the available reactive power capacities of power generating facilities; (b) the available reactive power capacities of transmission-connected demand facilities; (c) the available reactive power capacities of DSOs; (d) the available transmission-connected equipment dedicated to providing reactive power; and (e) the ratios of active power and reactive power at the interface between the transmission system and transmission-connected distribution systems.
(a) inform neighbouring TSOs; and (b) prepare and activate remedial actions pursuant to Article 23.
(a) generation schedules; (b) consumption schedules; (c) internal commercial trade schedules; and (d) external commercial trade schedules.
(a) external commercial trade schedules as: (i) multilateral exchanges between the scheduling area and a group of other scheduling areas; (ii) bilateral exchanges between the scheduling area and another scheduling area;
(b) internal commercial trade schedules between the shipping agent and central counter parties; (c) internal commercial trade schedules between the shipping agent and other shipping agents.
(a) aggregated netted external schedules; and (b) netted area AC position, where the scheduling area is interconnected to other scheduling areas via AC transmission links.
(a) generation schedules; and (b) consumption schedules.
(a) year-ahead individual grid model per TSO and per scenario determined in accordance with Article 66; and (b) year-ahead common grid model per scenario defined in accordance with Article 67.
(a) day-ahead and intraday individual grid models per TSO and according to the time resolution defined pursuant to Article 70(1); (b) 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; (c) day-ahead and intraday common grid models according to the time resolution defined pursuant to Article 70(1); and (d) a list of prepared and agreed remedial actions identified to cope with constraints having cross-border relevance.
(a) the season-ahead system adequacy data provided by each TSO; (b) the season-ahead pan-European system adequacy analysis report; (c) forecasts used for adequacy in line with Article 104; and (d) information about a lack of adequacy in line with Article 105(4).
(a) the dimensioning rules for FCR in accordance with Article 153; (b) additional properties of FCR in accordance with Article 154(2); (c) the frequency quality defining parameters and the frequency quality target parameters in accordance with Article 127; (d) 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; (e) 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); (f) the synchronous area monitor in accordance with Article 133; (g) 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; (h) if applicable, restrictions for the active power output of HVDC interconnectors between synchronous areas in accordance with Article 137; (i) the LFC structure in accordance with Article 139; (j) if applicable, the methodology to reduce the electrical time deviation in accordance with Article 181; (k) whenever the synchronous area is operated by more than one TSO, the specific allocation of responsibilities between TSOs in accordance with Article 141; (l) operational procedures in case of exhausted FCR in accordance with Article 152(7); (m) for the GB and IE/NI synchronous areas, measures to ensure the recovery of energy reservoirs in accordance with to Article 156(6)(b); (n) 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); (o) 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); (p) requirements concerning the availability, reliability and redundancy of the technical infrastructure in accordance with Article 151(2); (q) 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); (r) for the CE and Nordic synchronous areas, the minimum activation period to be ensured by FCR providers in accordance with Article 156(10); (s) for the CE and Nordic synchronous areas, the assumptions and methodology for a cost-benefit analysis in accordance with Article 156(11); (t) if applicable, for synchronous areas other than CE, limits for the exchange of FCR between the TSOs in accordance with Article 163(2); (u) 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); (v) 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); (w) 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); (x) the methodology to determine limits on the amount of sharing of FCR between synchronous areas defined in accordance with Article 174(2); (y) 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); (z) 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 (aa) 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).
(a) 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); (b) LFC block monitor in accordance with Article 134(1); (c) ramping restrictions for active power output in accordance with Article 137(3) and (4); (d) 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); (e) if applicable, appointment of the TSO responsible for the tasks in Article 145(6); (f) additional requirements for the availability, reliability and redundancy of technical infrastructure defined in accordance with Article 151(3); (g) operational procedures in case of exhausted FRR or RR in accordance with Article 152(8); (h) the FRR dimensioning rules defined in accordance with Article 157(1); (i) the RR dimensioning rules defined in accordance with Article 160(2); (j) 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); (k) the escalation procedure defined in accordance with Article 157(4) and, if applicable, the escalation procedure defined in accordance with Article 160(7); (l) 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); (m) 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); (n) 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); (o) 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); (p) 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); (q) coordination actions aiming to reduce the FRCE as defined in Article 152(14); and (r) 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).
(a) the specific allocation of responsibilities between TSOs within the LFC area in accordance with Article 141(8); (b) the appointment of the TSO responsible for the implementation and operation of the frequency restoration process in accordance with Article 143(4).
(a) 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 (b) 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).
(a) 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 (b) 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).
(a) the nominal frequency for all synchronous areas; (b) the standard frequency range for all synchronous areas; (c) the maximum instantaneous frequency deviation for all synchronous areas; (d) the maximum steady-state frequency deviation for all synchronous areas; (e) the time to restore frequency for all synchronous areas; (f) the time to recover frequency for the GB and IE/NI synchronous areas; (g) the frequency restoration range for the GB, IE/NI and Nordic synchronous areas; (h) the frequency recovery range for the GB and IE/NI synchronous areas; and (i) the alert state trigger time for all synchronous areas.
(a) the alert state trigger time; (b) the maximum number of minutes outside the standard frequency range.
(a) time to restore frequency; (b) the alert state trigger time; and (c) the maximum number of minutes outside the standard frequency range.
(a) 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: (i) the system's size, based on the consumption and generation of the synchronous area and the inertia of the synchronous area; (ii) the reference incident; (iii) grid structure and/or network topology; (iv) load and generation behaviour; (v) 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; (vi) 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 (vii) the technical capabilities of power generating modules and demand units;
(b) 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.
(a) 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 (b) 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.
(a) 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; (b) 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.
(a) the collection of frequency quality evaluation data; and (b) the calculation of frequency quality evaluation criteria.
(a) for the synchronous area: (i) the instantaneous frequency data; and (ii) the instantaneous frequency deviation data;
(b) for each LFC block of the synchronous area, the instantaneous FRCE data.
(a) 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: (i) the mean value; (ii) the standard deviation; (iii) the 1-,5-,10-, 90-,95- and 99-percentile; (iv) 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; (v) 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; (vi) 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; (vii) 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;
(b) 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: (i) 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: the mean value, the standard deviation, the 1-,5-,10-, 90-,95- and 99-percentile, the number of time intervals in which the average value of the FRCE was outside the Level 1 FRCE range, distinguishing between negative and positive FRCE, and the number of time intervals in which the average value of the FRCE was outside the Level 2 FRCE range, distinguishing between negative and positive FRCE;
(ii) 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;
(c) 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.
(a) measurements of the system frequency; (b) calculation of the frequency quality evaluation data; and (c) delivery of the frequency quality evaluation data for the criteria application process.
(a) the time-stamped active power setpoint for real-time and future operation; and (b) the time-stamped total active power output.
(a) obligations on ramping periods and/or maximum ramping rates for power generating modules and/or demand units; (b) obligations on individual ramping starting times for power generating modules and/or demand units within the LFC block; and (c) coordination of the ramping between power generating modules, demand units and active power consumption within the LFC block.
(a) 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 (b) develop mitigation measures to ensure that the targets for the synchronous area or for the LFC block can be met in the future.
(a) a process activation structure in accordance with Article 140; and (b) a process responsibility structure in accordance with Article 141.
(a) a FCP pursuant to Article 142; (b) a FRP pursuant to Article 143; and (c) for the CE synchronous area, a time control process pursuant to Article 181.
(a) a RRP pursuant to Article 144; (b) an imbalance netting process in accordance with Article 146; (c) a cross-border FRR activation process in accordance with Article 147; (d) a cross-border RR activation process in accordance with Article 148; and (e) for synchronous areas other than CE, a time control process pursuant to Article 181.
(a) the size and the total inertia, including synthetic inertia, of the synchronous area; (b) the grid structure and/or network topology; and (c) the load, generation and HVDC behaviour.
(a) a monitoring area corresponds to or is part of only one LFC area; (b) a LFC area corresponds to or is part of only one LFC block; (c) a LFC block corresponds to or is part of only one synchronous area; and (d) each network element is part of only one monitoring area, only one LFC area and only one LFC block.
(a) continuously monitor the FRCE of the LFC area; (b) implement and operate a FRP for the LFC area; (c) endeavour to fulfil the FRCE target parameters of the LFC area as defined in Article 128; and (d) have the right to implement one or several of the processes referred to in Article 140(2).
(a) endeavour to fulfil the FRCE target parameters of the LFC block as defined in Article 128; and (b) comply with the FRR dimensioning rules in accordance with Article 157 and the RR dimensioning rules in accordance with Article 160.
(a) implement and operate a FCP for the synchronous area; (b) comply with FCR dimensioning rules in accordance with Article 153; and (c) endeavour to fulfil the frequency quality target parameters in accordance with Article 127.
(a) regulate the FRCE towards zero within the time to restore frequency; (b) for the CE and Nordic synchronous areas, to progressively replace the activated FCR by activation of FRR in accordance with Article 145.
(a) the ACE of an LFC area, where there is more than one LFC area in a synchronous area; or (b) the frequency deviation, where one LFC area corresponds to the LFC block and the synchronous area.
(a) the total interconnector and virtual tie-line active power flow; and (b) the control program in accordance with Article 136.
(a) progressively restore the activated FRR; (b) support FRR activation; (c) for the GB and IE/NI synchronous areas, to progressively restore the activated FCR and FRR.
(a) be an automatic control device designed to reduce the FRCE to zero; (b) have proportional-integral behaviour; (c) have a control algorithm which prevents the integral term of a proportional-integral controller from accumulating the control error and overshooting; and (d) have functionalities for extraordinary operational modes for the alert and emergency states.
(a) calculate and monitor the FRCE of the whole LFC block; and (b) 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.
(a) the stability of the FCP of the synchronous area or synchronous areas involved in the imbalance netting process; (b) the stability of the FRP and the RRP of each LFC area operated by participating or affected TSOs; and (c) operational security.
(a) by defining an active power flow over a virtual tie-line which shall be part of the FRCE calculation; (b) by adjusting the active power flows over HVDC interconnectors.
(a) the stability of the FCP of the synchronous area or synchronous areas involved in the cross-border FRR activation process; (b) the stability of the FRP and the RRP of each LFC area operated by participating or affected TSOs; and (c) operational security.
(a) defining an active power flow over a virtual tie-line which shall be part of the FRCE calculation where FRR activation is automated; (b) adjusting a control program or defining an active power flow over a virtual tie-line between LFC areas where FRR activation is manual; or (c) adjusting the active power flows over HVDC interconnectors.
(a) the stability of the FCP of the synchronous area or synchronous areas involved in the cross-border RR activation process; (b) the stability of the FRP and the RRP of each LFC area operated by participating or affected TSOs; and (c) the operational security.
(a) determining an active power flow over a virtual tie-line which shall be part of the FRCE calculation; (b) adjusting a control program; or (c) adjusting active power flows over HVDC interconnectors.
(a) the provision of all input data necessary for: (i) the calculation of the power interchange with respect to the operational security limits; and (ii) the performance of real-time operational security analysis by participating and affected TSOs;
(b) the responsibility of calculating the power interchange; and (c) the implementation of operational procedures to ensure the operational security.
(a) the TSOs involved; (b) the expected amount of power interchange due to the imbalance netting process, cross-border FRR activation process or cross-border RR activation process; (c) the reserve type and maximum amount of exchange or sharing of reserves; and (d) the timeframe of exchange or sharing of reserves.
(a) 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 (b) 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.
(a) the accuracy, resolution, availability and redundancy of active power flow and virtual tie-line measurements; (b) the availability and redundancy of digital control systems; (c) the availability and redundancy of communication infrastructure; and (d) communication protocols.
(a) ensure a sufficient quality and availability of the FRCE calculation; (b) perform real-time quality monitoring of the FRCE calculation; (c) take action in case of FRCE miscalculation; and (d) 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.
(a) the system state of the transmission system in accordance with Article 18; and (b) the real-time measurement data of the FRCE of the LFC blocks and LFC areas of the synchronous area.
(a) shall inform the other TSOs of the LFC block; and (b) 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.
(a) 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); (b) the size of the reference incident shall be determined in accordance with the following conditions: (i) for the CE synchronous area, the reference incident shall be 3000 MW in positive direction and3000 MW in negative direction;(ii) 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;
(c) 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 (d) 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.
(a) the activation of FCR shall not be artificially delayed and begin as soon as possible after a frequency deviation; (b) in case of a frequency deviation equal to or larger than 200 mHz, at least 50 % of the full FCR capacity shall be delivered at the latest after 15 seconds; (c) in case of a frequency deviation equal to or larger than 200 mHz, 100 % of the full FCR capacity shall be delivered at the latest after 30 seconds; (d) in case of a frequency deviation equal to or larger than 200 mHz, the activation of the full FCR capacity shall rise at least linearly from 15 to 30 seconds; and (e) in case of a frequency deviation smaller than 200 mHz the related activated FCR capacity shall be at least proportional with the same time behaviour referred to in points (a) to (d).
(a) time-stamped status indicating if FCR is on or off; (b) time-stamped active power data needed to verify FCR activation, including time-stamped instantaneous active power; (c) droop of the governor for type C and type D power generating modules as defined in Article 5 of Regulation (EU) 2016/631 acting as FCR providing units, or its equivalent parameter for FCR providing groups consisting of type A and/or type B power generating modules as defined in Article 5 of Regulation (EU) 2016/631, and/or demand units with demand response active power control as defined in Article 28 of Regulation (EU) 2016/1388.
(a) at least once every 5 years; (b) in case the technical or availability requirements or the equipment have changed; and (c) in case of modernisation of the equipment related to FCR activation.
(a) the reserve capacity on FCR divided by the maximum steady-state frequency deviation; (b) the auto-control of generation; (c) the self-regulation of load, taking into account the contribution in accordance with Articles 27 and 28 of Regulation (EU) 2016/1388; (d) the frequency response of HVDC interconnectors referred to in Article 172; and (e) the LFSM and FSM activation in accordance with Articles 13 and 15 of Regulation (EU) 2016/631.
(a) the initial FCR obligations; (b) auto-control of generation; (c) the self-regulation of load; (d) frequency coupling via HVDC between synchronous areas; (e) exchange of FCR.
(a) limiting the share of the FCR provided per FCR providing unit to 5 % of the reserve capacity of FCR required for each of the whole CE and Nordic synchronous areas; (b) excluding the FCR provided by the unit defining the reference incident of the synchronous area from the dimensioning process for GB, IE/NI and Nordic synchronous areas; and (c) replacing the FCR which is made unavailable due to a forced outage or the unavailability of an FCR providing unit or FCR providing group as soon as technically possible and in accordance with the conditions that shall be defined by the reserve connecting TSO.
(a) experiences gathered with different timeframes and shares of emerging technologies in different LFC blocks; (b) the impact of a defined time period on the total cost of FCR reserves in the synchronous area; (c) the impact of a defined time period on system stability risks, in particular through prolonged or repeated frequency events; (d) the impact on system stability risks and total cost of FCR in case of increasing total volume of FCR; (e) the impact of technological developments on costs of availability periods for FCR from its FCR providing units or groups with limited energy reservoirs.
(a) for the GB and IE/NI synchronous areas, the FCR provider shall use the methods specified in the synchronous area operational agreement; (b) for the CE and Nordic synchronous areas, the FCR provider shall ensure the recovery of the energy reservoirs as soon as possible, within 2 hours after the end of the alert state.
(a) all TSOs of a LFC block in the CE and Nordic synchronous areas shall determine the required reserve capacity of FRR of the LFC block based on consecutive historical records comprising at least the historical LFC block imbalance values. The sampling of those historical records shall cover at least the time to restore frequency. The time period considered for those records shall be representative and include at least one full year period ending not earlier than 6 months before the calculation date; (b) all TSOs of a LFC block in the CE and Nordic synchronous areas shall determine the reserve capacity on FRR of the LFC block sufficient to respect the current FRCE target parameters in Article 128 for the time period referred to in point (a) based at least on a probabilistic methodology. In using that probabilistic methodology, the TSOs shall take into account the restrictions defined in the agreements for the sharing or exchange of reserves due to possible violations of operational security and the FRR availability requirements. All TSOs of a LFC block shall take into account any expected significant changes to the distribution of LFC block imbalances or take into account other relevant influencing factors relative to the time period considered; (c) all TSOs of a LFC block shall determine the ratio of automatic FRR, manual FRR, the automatic FRR full activation time and manual FRR full activation time in order to comply with the requirement of paragraph (b). For that purpose, the automatic FRR full activation time of a LFC block and the manual FRR full activation time of the LFC block shall not be more than the time to restore frequency; (d) the TSOs of a LFC block shall determine the size of the reference incident which shall be the largest imbalance that may result from an instantaneous change of active power of a single power generating module, single demand facility, or single HVDC interconnector or from a tripping of an AC line within the LFC block; (e) all TSOs of a LFC block shall determine the positive reserve capacity on FRR, which shall not be less than the positive dimensioning incident of the LFC block; (f) all TSOs of a LFC block shall determine the negative reserve capacity on FRR, which shall not be less than the negative dimensioning incident of the LFC block; (g) all TSOs of a LFC block shall determine the reserve capacity on FRR of a LFC block, any possible geographical limitations for its distribution within the LFC block and any possible geographical limitations for any exchange of reserves or sharing of reserves with other LFC blocks to comply with the operational security limits; (h) all TSOs of a LFC block shall ensure that the positive reserve capacity on FRR or a combination of reserve capacity on FRR and RR is sufficient to cover the positive LFC block imbalances for at least 99 % of the time, based on the historical records referred to in point (a); (i) all TSOs of a LFC block shall ensure that the negative reserve capacity on FRR or a combination of reserve capacity on FRR and RR is sufficient to cover the negative LFC block imbalances for at least 99 % of the time, based on the historical record referred to in point (a); (j) all TSOs of a LFC block may reduce the positive reserve capacity on FRR of the LFC block resulting from the FRR dimensioning process by concluding a FRR sharing agreement with other LFC blocks in accordance with provisions in Title 8. The following requirements shall apply to that sharing agreement: (i) for the CE and Nordic synchronous areas, the reduction of the positive reserve capacity on FRR of a LFC block shall be limited to the difference, if positive, between the size of the positive dimensioning incident and the reserve capacity on FRR required to cover the positive LFC block imbalances during 99 % of the time, based on the historical records referred to in point (a). The reduction of the positive reserve capacity shall not exceed 30 % of the size of the positive dimensioning incident; (ii) for the GB and IE/NI synchronous areas, the positive reserve capacity on FRR and the risk of non-delivery due to sharing shall be assessed continually by the TSOs of the LFC block;
(k) all TSOs of a LFC block may reduce the negative reserve capacity on FRR of the LFC block, resulting from the FRR dimensioning process by concluding a FRR sharing agreement with other LFC blocks in accordance with the provisions of Title 8. The following requirements shall apply to that sharing agreement: (i) for the CE and Nordic synchronous areas, the reduction of the negative reserve capacity on FRR of a LFC block shall be limited to the difference, if positive, between the size of the negative dimensioning incident and the reserve capacity on FRR required to cover the negative LFC block imbalances during 99 % of the time, based on the historical records referred to in point (a); (ii) for the GB and IE/NI synchronous areas, the negative reserve capacity on FRR and the risk of non-delivery due to sharing shall be assessed continually by the TSOs of the LFC block.
(a) each FRR providing unit and each FRR providing group shall be connected to only one reserve connecting TSO; (b) a FRR providing unit or FRR providing group shall activate FRR in accordance with the setpoint received from the reserve instructing TSO; (c) the reserve instructing TSO shall be the reserve connecting TSO or a TSO designated by the reserve connecting TSO in an FRR exchange agreement pursuant to Article 165(3) or 171(4); (d) a FRR providing unit or FRR providing group for automatic FRR shall have an automatic FRR activation delay not exceeding 30 seconds; (e) a FRR provider shall ensure that the FRR activation of the FRR providing units within a reserve providing group can be monitored. For that purpose, the FRR provider shall be capable of supplying to the reserve connecting TSO and the reserve instructing TSO real-time measurements of the connection point or another point of interaction agreed with the reserve connecting TSO concerning: (i) time-stamped scheduled active power output; (ii) time-stamped instantaneous active power for: each FRR providing unit, each FRR providing group, and each power generating module or demand unit of a FRR providing group with a maximum active power output larger than or equal to 1,5 MW;
(f) a FRR providing unit or FRR providing group for automatic FRR shall be capable of activating its complete automatic reserve capacity on FRR within the automatic FRR full activation time; (g) a FRR providing unit or FRR providing group for manual FRR shall be capable of activating its complete manual reserve capacity on FRR within the manual FRR full activation time; (h) a FRR provider shall fulfil the FRR availability requirements; and (i) a FRR providing unit or FRR providing group shall fulfil the ramping rate requirements of the LFC block.
(a) ensure that its FRR providing units and FRR providing groups fulfil the FRR technical minimum requirements, the FRR availability requirements and the ramping rate requirements in paragraphs 1 to 3; and (b) inform its reserve instructing TSO about a reduction of the actual availability of its FRR providing unit or its FRR providing group or a part of its FRR providing group as soon as possible.
(a) at least once every 5 years; and (b) where the technical or availability requirements or the equipment have changed.
(a) for the Nordic and CE synchronous areas there shall be sufficient positive reserve capacity on RR to restore the required amount of positive FRR. For the GB and IE/NI synchronous areas there shall be sufficient positive reserve capacity on RR to restore the required amount of positive FCR and positive FRR; (b) for the Nordic and CE synchronous areas, there shall be sufficient negative reserve capacity on RR to restore the required amount of negative FRR. For the GB and IE/NI synchronous areas, there shall be sufficient negative reserve capacity on RR to restore the required amount of negative FCR and negative FRR; (c) there shall be sufficient reserve capacity on RR, where this is taken into account to dimension the reserve capacity on FRR in order to respect the FRCE quality target for the period of time concerned; and (d) compliance with the operational security within a LFC block to determine the reserve capacity on RR.
(a) guarantee that it can still meet its FRCE target parameters set out in Article 128; (b) ensure that operational security is not endangered; and (c) ensure that the reduction of the positive reserve capacity on RR does not exceed the remaining positive reserve capacity on RR of the LFC block.
(a) guarantee that it can still meet its FRCE target parameters set out in Article 128; (b) ensure that operational security is not endangered; and (c) ensure that the reduction of the negative reserve capacity on RR does not exceed the remaining negative reserve capacity on RR of the LFC block.
(a) connection to only one reserve connecting TSO; (b) RR activation according to the setpoint received from the reserve instructing TSO; (c) the reserve instructing TSO shall be the reserve connecting TSO or a TSO that shall be designated by the reserve connecting TSO in the RR exchange agreement pursuant to Article 165(3) or 171(4); (d) activation of complete reserve capacity on RR within the activation time defined by the instructing TSO; (e) de-activation of RR according to the setpoint received from the reserve instructing TSO; (f) a RR provider shall ensure that the RR activation of the RR providing units within a reserve providing group can be monitored. For that purpose, the RR provider shall be capable of supplying to the reserve connecting TSO and the reserve instructing TSO real-time measurements of the connection point or another point of interaction agreed with the reserve connecting TSO concerning: (i) the time-stamped scheduled active power output, for each RR providing unit and group and for each power generating module or demand unit of a RR providing group with a maximum active power output larger than or equal to 1,5 MW; (ii) the time-stamped instantaneous active power, for each RR providing unit and group, and for each power generating module or demand unit of a RR providing group with a maximum active power output larger than or equal to 1,5 MW;
(g) fulfilment of the RR availability requirements.
(a) ensure that its RR providing units and RR providing groups fulfil the RR technical minimum requirements and the RR availability requirements referred to in paragraphs 1 to 3; and (b) inform its reserve instructing TSO about a reduction of the actual availability or a forced outage of its RR providing unit or its RR providing group or a part of its RR providing group as soon as possible.
(a) at least once every 5 years; and (b) where the technical or availability requirements or the equipment have changed.
(a) the responsibility of the reserve instructing TSO for the reserve capacity on FRR and RR subject to the exchange of FRR/RR; (b) the amount of the reserve capacity on FRR and RR subject to the exchange of FRR/RR; (c) the implementation of the cross-border FRR/RR activation process in accordance with Articles 147 and 148; (d) FRR/RR technical minimum requirements related to the cross-border FRR/RR activation process where the reserve connecting TSO is not the reserve instructing TSO; (e) the implementation of the FRR/RR prequalification for the reserve capacity on FRR and RR subject to exchange in accordance with Articles 159 and 162; (f) the responsibility to monitor the fulfilment of the FRR/RR technical requirements and FRR/RR availability requirements for the reserve capacity on FRR and RR subject to exchange in accordance with Articles 158(5) and 161(5); and (g) procedures to ensure that the exchange of FRR/RR does not lead to power flows which violate the operational security limits.
(a) the amount of reserve capacity on FRR and RR subject to the sharing of FRR/RR; (b) the implementation of the cross-border FRR/RR activation process in accordance with Articles 147 and 148; (c) procedures to ensure that the activation of the reserve capacity on FRR and RR subject to the sharing of FRR/RR does not lead to power flows that violate the operational security limits.
(a) the reserve instructing TSO for the reserve capacity on FRR and RR subject to the sharing of FRR/RR; or (b) the TSO having access to its reserve capacity on FRR and RR subject to the sharing of FRR/RR through an implemented cross-border FRR/RR activation process as part of an FRR/RR exchange agreement.
(a) restrictions to provide frequency restoration or adjust the control program related to operational security; and (b) partial or full usage of the reserve capacity on FRR and RR by the control capability providing TSO.
(a) the responsibility of the reserve instructing TSO for the reserve capacity of the reserve exchange; (b) the amount of the reserve capacity subject to the exchange of reserves; (c) the implementation of the cross-border FRR/RR activation process in accordance with Articles 147 and 148; (d) the implementation of the prequalification for the reserve capacity subject to the exchange of reserves in accordance with Articles 155, 159 and 162; (e) the responsibility to monitor compliance with the technical requirements and availability requirements of the reserve capacity subject to the exchange of reserves pursuant to Articles 158(5) and 161(5); and (f) procedures to ensure that the exchange of reserves does not lead to power flows that violate the operational security limits.
(a) the amount of reserve capacity subject to the sharing of reserves; (b) the implementation of the cross-border FRR/RR activation process in accordance with Articles 147 and 148; and (c) the procedures to ensure that the sharing of reserves does not lead to power flows that violate the operational security limits.
(a) the interactions across all timescales, including planning and activation; (b) the MW/Hz sensitivity factor, linearity/dynamic or static/step response function of each HVDC interconnector connecting synchronous areas; and (c) the share/interaction of these functions across multiple HVDC paths between the synchronous areas.
(a) the operational impact between the synchronous areas; (b) the stability of the FCP of the synchronous area; (c) the ability of the TSOs of the synchronous area to comply with the frequency quality target parameters defined in accordance with Article 127; and (d) the operational security.
(a) for the CE and Nordic synchronous area, all TSOs shall ensure that the sum of FCR provided within the synchronous area and from other synchronous areas as part of exchange of FCR covers at least the reference incident; (b) for the GB and IE/NI synchronous areas, all TSOs shall specify a methodology to determine the minimum provision of reserve capacity on FCR in the synchronous area.
(a) the reserve instructing TSO for the reserve capacity on FRR and RR subject to the sharing of FRR or RR; or (b) the TSO having access to its reserve capacity on FRR and RR subject to the sharing of FRR/RR through an implemented cross-border FRR/RR activation process as part of a FRR/RR exchange agreement.
(a) the operational impact between the synchronous areas; (b) the stability of the FRP of the synchronous area; (c) the ability of TSOs of the synchronous area to comply with the frequency quality target parameters defined in accordance with Article 127 and the FRCE target parameters defined in accordance with Article 128; and (d) the operational security.
(a) the operational impact between the synchronous areas; (b) the stability of the FRP of the synchronous area; (c) the maximum reduction of FRR that can be taken into account in the FRR dimensioning in accordance with Article 157 as a result of the FRR sharing; (d) the ability of the synchronous area to comply with the frequency quality target parameters defined in accordance with Article 127 and the FRCE target parameters defined in accordance with Article 128; and (e) the operational security.
(a) the operational impact between the synchronous areas; (b) the stability of the RRP of the synchronous area; (c) the ability of the synchronous area to comply with the frequency quality target parameters defined in accordance with Article 127 and the FRCE target parameters defined in accordance with Article 128; and (d) the operational security.
(a) the operational impact between the synchronous areas; (b) the stability of the RRP of the synchronous area; (c) the maximum reduction of RR that can be taken into account in the RR dimensioning rules in accordance with Article 160 as a result of the RR sharing; (d) the ability of the TSOs of the synchronous area to comply with the frequency quality target parameters defined in accordance with Article 127 and the ability of the LFC blocks to comply with the FRCE error target parameters defined in accordance with Article 128; and (e) the operational security.
(a) the time ranges within which TSOs shall endeavour to maintain the electrical time deviation; (b) the frequency setpoint adjustments to return electrical time deviation to zero; and (c) the actions to increase or decrease the average system frequency by means of active power reserves.
(a) monitor the electrical time deviation; (b) calculate the frequency setpoint adjustments; and (c) coordinate the actions of the time control process.
(a) voltage levels and connection points of the reserve providing units or groups; (b) the type of active power reserves; (c) the maximum reserve capacity provided by the reserve providing units or groups at each connection point; and (d) the maximum rate of change of active power for the reserve providing units or groups.
(a) the values of the frequency quality evaluation criteria calculated for the synchronous area and for each LFC block within the synchronous area in accordance with Article 133(3); and (b) the measurement resolution, measurement accuracy and calculation method specified in accordance with Article 132;
(a) information on the process activation structure of the synchronous area, including at least information on the monitoring areas, LFC areas and LFC blocks defined and their respective TSOs; and (b) information on the process responsibility structure of the synchronous area, including at least information on the processes developed in accordance with Article 140(1) and (2).
(a) the identity of the LFC blocks where there is an agreement for the sharing of FRR or RR; and (b) the share of FRR and RR reduced due to each agreement for the sharing of FRR or RR.
(a) the amount of shared reserve capacity on FCR between TSOs that entered into agreements for the sharing of FCR; and (b) the effects of the sharing of FCR on the reserve capacity on FCR of the involved TSOs.
(1) Article 16 subparagraphs (d), (e) and (f) of paragraph 2; (2) Article 38(2); (3) Article 39(3); (4) Article 118; (5) Article 119; (6) Article 125; (7) Article 126; (8) Article 127 paragraphs 1(i), 3, 4, 5, and 9; (9) Article 128, paragraphs 4 and 7; (10) Article 130(1)(b); (11) Article 131 (12) Article 132(2); (13) from Article 133 to Article 140; (14) Article 141 paragraphs 1, 2, 4(c), 5, 6, 9, 10 and 11; (15) Article 142; (16) Article 143(3); (17) Article 145 paragraphs 1, 2, 3, 4 and 6; (18) Article 149(3); (19) Article 150; (20) Article 151(2); (21) from Article 152 to Article 181; (22) Article 184(2); (23) Article 185; (24) Article 186(1); (25) Article 187; (26) Article 188 paragraphs 1 and 2; and (27) Article 189(1).
| Synchronous area | Voltage range |
|---|---|
| Continental Europe | 0,90 pu-1,118 pu |
| Nordic | 0,90 pu-1,05 pu |
| Great Britain | 0,90 pu-1,10 pu |
| Ireland and Northern Ireland | 0,90 pu-1,118 pu |
| Baltic | 0,90 pu-1,118 pu |
| Synchronous area | Voltage range |
|---|---|
| Continental Europe | 0,90 pu-1,05 pu |
| Nordic | 0,90 pu-1,05 pu |
| Great Britain | 0,90 pu-1,05 pu |
| Ireland and Northern Ireland | 0,90 pu-1,05 pu |
| Baltic | 0,90 pu-1,097 pu |
| CE | GB | IE/NI | Nordic | |
|---|---|---|---|---|
| standard frequency range | ± 50 mHz | ± 200 mHz | ± 200 mHz | ± 100 mHz |
| maximum instantaneous frequency deviation | 800 mHz | 800 mHz | ||
| maximum steady-state frequency deviation | 200 mHz | 500 mHz | 500 mHz | 500 mHz |
| time to recover frequency | not used | 1 minute | 1 minute | not used |
| frequency recovery range | not used | ± 500 mHz | ± 500 mHz | not used |
| time to restore frequency | 15 minutes | 15 minutes | 15 minutes | 15 minutes |
| frequency restoration range | not used | ± 200 mHz | ± 200 mHz | ± 100 mHz |
| alert state trigger time | 5 minutes | 10 minutes | 10 minutes | 5 minutes |
| CE | GB | IE/NI | Nordic | |
|---|---|---|---|---|
| maximum number of minutes outside the standard frequency range |
| GB | IE/NI | |
|---|---|---|
| Level 1 | 3 % | 3 % |
| Level 2 | 1 % | 1 % |
| Minimum accuracy of frequency measurement | CE, GB, IE/NI and Nordic | 10 mHz or the industrial standard if better |
|---|---|---|
| Maximum combined effect of inherent frequency response insensitivity and possible intentional frequency response dead band of the governor of the FCR providing units or FCR providing groups. | CE | 10 mHz |
| GB | 15 mHz | |
| IE/NI | 15 mHz | |
| Nordic | 10 mHz | |
| FCR full activation time | CE | 30 s |
| GB | 10 s | |
| IE/NI | 15 s | |
| Nordic | 30 s if system frequency is outside standard frequency range | |
| FCR full activation frequency deviation. | CE | ± 200 mHz |
| GB | ± 500 mHz | |
| IE/NI | Dynamic FCR ± 500 mHz | |
| Static FCR ± | ||
| Nordic | ± 500 mHz |
| Synchronous area | Exchange of FCR allowed between: | Limits for the exchange of FCR |
|---|---|---|
| CE synchronous area | TSOs of adjacent LFC blocks |
|
| TSOs of the LFC areas of the same LFC block |
| |
| Other synchronous areas | TSOs of the synchronous area |
|
| Synchronous area | Exchange of FRR allowed between | Limits for the exchange of FRR |
|---|---|---|
| All synchronous areas consisting of more than one LFC block | TSOs of different LFC blocks |
|
| TSOs of the LFC areas of the same LFC block |
|
| Synchronous area | Exchange of RR allowed between | Limits for the exchange of RR |
|---|---|---|
| All synchronous areas consisting of more than one LFC block | TSOs of different LFC blocks |
|
| TSOs of the LFC areas of the same LFC block |
|