Commission Regulation (EU) 2017/1485 of 2 August 2017 establishing a guideline on electricity transmission system operation (Text with EEA relevance. )

• CELEX: Regulation (EU) 2017/1485
• Articles: 200

Article 1 Subject matter

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

(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.

Article 2 Scope

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

(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  ( 3 ) ;

(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  ( 4 ) ;

(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  ( 5 ) .

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

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

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

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

Article 3 Definitions

1.   For the purposes of this Regulation, the definitions in Article 2 of Regulation (EC) No 714/2009, Article 2 of Commission Regulation (EU) 2015/1222  ( 6 ) , Article 2 of Commission Regulation (EU) 2016/631, Article 2 of Commission Regulation (EU) 2016/1388, Article 2 of Commission Regulation (EU) 2016/1447, Article 2 of Commission Regulation (EU) 2016/1719  ( 7 ) , Article 2 of Commission Regulation (EU) No 543/2013  ( 8 ) on submission and publication of data in electricity markets and Article 2 of Directive 2009/72/EC of the European Parliament and of the Council  ( 9 ) shall apply.

2.   In addition, the following definitions shall apply:

(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.

Article 4 Objectives and regulatory aspects

1.   This Regulation aims at:

(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.

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

(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.

Article 5 Terms and conditions or methodologies of TSOs

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

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

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

(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.

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

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

(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.

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

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

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

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

Article 6 Approval of terms and conditions or methodologies of TSOs

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

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

(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.

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

(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).

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

(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).

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

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

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

8.   Where the regulatory authorities have not been able to reach an agreement within the period referred to in paragraph 7 or upon their joint request, the Agency shall adopt a decision concerning the submitted proposals for terms and conditions or methodologies within 6 months, in accordance with Article 8(1) of Regulation (EC) No 713/2009.

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

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

Article 7 Amendments to the terms and conditions or methodologies of TSOs

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

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

3.   Where the competent regulatory authorities have not been able to reach an agreement on terms and conditions or methodologies pursuant to paragraphs 2 and 3 of Article 6 within the two-month deadline, or upon their joint request, the Agency shall adopt a decision concerning the amended terms and conditions or methodologies within 6 months, in accordance with Article 8(1) of Regulation (EC) No 713/2009. If the relevant TSOs fail to submit a proposal for amended terms and conditions or methodologies, the procedure provided for in Article 5(7) shall apply.

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

Article 8 Publication on internet

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

2.   The publication shall also concern:

(a)

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

Article 9 Recovery of costs

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

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

Article 10 Stakeholder involvement

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

Article 11 Public consultation

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

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

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

Article 12 Confidentiality obligations

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

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

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

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

Article 13 Agreements with TSOs not bound by this Regulation

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

Article 14 Monitoring

1.   ENTSO for Electricity shall monitor the implementation of this Regulation in accordance with Article 8(8) of Regulation (EC) No 714/2009. Monitoring shall cover at least the following matters:

(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.

2.   The Agency, in cooperation with ENTSO for Electricity, shall produce within 12 months from the entry into force of this Regulation a list of the relevant information to be communicated by ENTSO for Electricity to the Agency in accordance with Articles 8(9) and 9(1) of Regulation (EC) No 714/2009. The list of relevant information may be subject to updates. ENTSO for Electricity shall maintain a comprehensive, standardised format, digital data archive of the information required by the Agency.

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

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

Article 15 Annual report on operational security indicators

1.   By 30 September, ENTSO for Electricity shall publish an annual report based on the incidents classification scale adopted in accordance with Article 8(3)(a) of Regulation (EC) No 714/2009. The Agency may provide its opinion on the format and contents of that annual report, including the geographical scope of the incidents reported, the electrical interdependencies between the TSOs' control areas and any relevant historical information.

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

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

(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.

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

(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.

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

Article 16 Annual report on load-frequency control

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

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

(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.

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

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

Article 17 Annual report on regional coordination assessment

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

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

(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.

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

Article 18 Classification of system states

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

(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.

2.   A transmission system shall be in the alert state when:

(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.

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

(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.

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

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

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

Article 19 Monitoring and determination of system states by TSOs

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

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

(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.

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

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

(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.

Article 20 Remedial actions in system operation

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

2.   The remedial actions used by TSOs in system operation in accordance with paragraph 1 and with Articles 21 to 23 of this Regulation shall be consistent with the remedial actions taken into account in capacity calculation in accordance with Article 25 of Regulation (EU) 2015/1222.

Article 21 Principles and criteria applicable to remedial actions

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

(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).

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

(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.

Article 22 Categories of remedial actions

1.   Each TSO shall use the following categories of remedial actions:

(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.

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

Article 23 Preparation, activation and coordination of remedial actions

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

(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.

2.   When preparing and activating a remedial action, including redispatching or countertrading pursuant to Articles 25 and 35 of Regulation (EU) 2015/1222, or a procedure of a TSO's system defence plan which affects other TSOs, the relevant TSO shall assess, in coordination with the TSOs concerned, the impact of such remedial action or measure within and outside of its control area, in accordance with Article 75(1), Article 76(1)(b) and Article 78(1), (2) and (4) and shall provide the TSOs concerned with the information about this impact.

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

4.   When preparing and activating remedial actions each TSO shall, if its transmission system is not in normal or alert state, coordinate to the extent possible such remedial actions with the affected transmission-connected SGUs and DSOs to maintain the operational security and the integrity of the transmission system.

When a TSO activates a remedial action each impacted transmission-connected significant grid user and DSO shall execute the instructions given by the TSO

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

Article 24 Availability of TSO's means, tools and facilities

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

(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.

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

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

Article 25 Operational security limits

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

(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.

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

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

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

Article 26 Security plan for critical infrastructure protection

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

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

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

Article 27 Obligations of all TSOs regarding voltage limits

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

2.   If the relevant TSO in Spain requires in accordance with Article 16(2) of Regulation (EU) 2016/631 that power generating modules connected to nominal voltages between 300 and 400 kV stay connected in the voltage range from 1,05 to 1,0875 per unit for an unlimited time, that additional voltage range shall be considered by the relevant TSO in Spain when complying with paragraph 1.

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

4.   Each TSO shall endeavour to ensure that, during the normal state and after the occurrence of a contingency, the voltage remains, within wider voltage ranges for limited times of operation if there is agreement about those wider voltage ranges with transmission-connected DSOs, power generating facility owners in accordance with Article 16(2) of Regulation (EU) 2016/631 or HVDC system owners in accordance with Article 18 of Regulation (EU) 2016/1447.

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

Article 28 Obligations of SGUs concerning voltage control and reactive power management in system operation

1.   By 3 months after entry into force of this Regulation, all SGUs which are transmission-connected power generating modules not subject to Article 16 of Regulation (EU) 2016/631, or which are HVDC systems not subject to Article 18 of Regulation (EU) 2016/1447, shall inform their TSO about their capabilities compared to the voltage requirements in Article 16 of Regulation (EU) 2016/631 or in Article 18 of Regulation (EU) 2016/1447, declaring their voltage capabilities and the time they can withstand without disconnection.

2.   SGUs which are demand facilities subject to the requirements of Article 3 of Regulation (EU) 2016/1388 shall not disconnect due to a disturbance within the voltage ranges referred to in Article 27. By 3 months after entry into force of this Regulation, SGUs which are transmission-connected demand facilities and which are not subject to Article 3 of Regulation (EU) 2016/1388 shall inform their TSO about their capabilities in relation to the voltage requirements defined in Annex II of Regulation (EU) 2016/1388 declaring their voltage capabilities and the time they can withstand without disconnection.

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

Article 29 Obligations of all TSOs concerning voltage control and reactive power management in system operation

1.   If voltage at a connection point to the transmission system is outside the ranges defined in Tables 1 and 2 of Annex II to this Regulation, each TSO shall apply voltage control and reactive power management remedial actions in accordance with Article 22(1)(c) of this Regulation in order to restore voltage at the connection point within the range specified in Annex II and within time range specified in Article 16 of Regulation (EU) 2016/631 and Article 13 of Regulation (EU) 2016/1388.

2.   Each TSO shall take into account in its operational security analysis the voltage values at which transmission-connected SGUs not subject to the requirements of Regulation (EU) 2016/631 or Regulation (EU) 2016/1388 may disconnect.

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

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

5.   Each TSO shall agree with each transmission-connected DSO on the reactive power setpoints, power factor ranges and voltage setpoints for voltage control at the connection point between the TSO and the DSO in accordance with Article 15 of Regulation (EU) 2016/1388. To ensure that those parameters are maintained, each transmission-connected DSO shall use its reactive power resources and have the right to give voltage control instructions to distribution-connected SGUs.

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

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

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

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

Article 30 Short-circuit current

Each TSO shall determine:

(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.

Article 31 Short-circuit current calculation and related measures

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

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

(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.

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

Article 32 Power flow limits

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

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

Article 33 Contingency lists

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

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

(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.

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

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

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

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

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

Article 34 Contingency analysis

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

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

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

Article 35 Contingency handling

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

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

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

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

(a)

during switching sequences;

(b)

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

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

Article 36 General requirements on protection

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

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

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

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

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

Article 37 Special protection schemes

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

(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.

Article 38 Dynamic stability monitoring and assessment

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

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

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

(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.

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

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

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

(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.

Article 39 Dynamic stability management

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

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

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

(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).

Article 40 Organisation, roles, responsibilities and quality of data exchange

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

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

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

(a)

generation;

(b)

consumption;

(c)

schedules;

(d)

balance positions;

(e)

planned outages and substation topologies; and

(f)

forecasts.

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

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

(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.

6.   By 6 months after entry into force of this Regulation, all TSOs shall jointly agree on key organisational requirements, roles and responsibilities in relation to data exchange. Those organisational requirements, roles and responsibilities shall take into account and complement where necessary the operational conditions of the generation and load data methodology developed in accordance with Article 16 of Regulation (EU) 2015/1222. They shall apply to all data exchange provisions in this Title and shall include organisational requirements, roles and responsibilities for the following elements:

(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.

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

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

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

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

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

Article 41 Structural and forecast data exchange

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

(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.

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

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

(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.

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

(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.

Article 42 Real-time data exchange

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

(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.

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

(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.

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

Article 43 Structural data exchange

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

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

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

(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).

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

5.   At least once a year, each transmission-connected DSO shall provide the TSO, per primary energy sources, the total aggregated generating capacity of the type A power generating modules subject to requirements of Regulation (EU) 2016/631 and the best possible estimates of generating capacity of type A power generating modules not subject to or derogated from Regulation (EU) 2016/631, connected to its distribution system, and the related information concerning their frequency behaviour.

Article 44 Real-time data exchange

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

(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.

Article 45 Structural data exchange

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

(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.

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

(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.

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

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

(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.

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

(a)

nameplate data of the installation;

(b)

electrical parameters;

(c)

associated protections.

Article 46 Scheduled data exchange

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

(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.

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

(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.

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

Article 47 Real-time data exchange

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

(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.

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

(a)

position of the circuit breakers;

(b)

operational status; and

(c)

active and reactive power.

Article 48 Structural data exchange

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

(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.

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

Article 49 Scheduled data exchange

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

(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.

Article 50 Real-time data exchange

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

(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.

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