System Operation European Stakeholder Committee

1. System Operation European Stakeholder Committee System Operation European Stakeholder Committee 4 June, Ljubljana

2. 1. Draft Agenda

3. Follow up actions ENTSO-E System Operation European Stakeholder Committee 4 June 2019

4. Actions and status

5. Actions and status

6. Actions and status

7. 2. Update on NC ER implementation • 2.1 Feedback on Stakeholder workshop on 7 May 2019 (1) • More than 40 participants • Positive on technicalaspects • Further expectations from Stakeholders on market-related aspects: to be managed by ESC Market (and MC)

8. 2. Update on NC ER implementation • 2.1 Feedback on Stakeholder workshop on 7 May 2019 (2) • Subjectspresentedduringworshop : • TelecommunicationGuidance • Critical Tools and Facilities – Guidance • Active Library for NC ER implementation • RSC activity for NC ER • Triggers (36(4)) and suspended activities • Settlement in case suspension of market activities • All presentations were distributed to registered participants and available on ENTSO-E website

9. 3. System Operation Guideline implementation System Operation European Stakeholder Committee 4 June 2019, Brussels

10. 3.1 Status of SO GL deliverables - planning 2019 Jean-Philippe Paul System Operation European Stakeholder Committee 4 June 2019, Brussels

11. Pan-European deliverables 2019 Remark: abbreviations are defined at the end of the presentation

12. Regional deliverables 2019 Remark: abbreviations are defined at the end of the presentation

13. Regional deliverables 2019 Remark: abbreviations are defined at the end of the presentation

14. 3.2 FCR provision by Limited Energy Reservoirs Luca Ortolano 9th System Operation European Stakeholder Committee Meeting (SO ESC) 04 June 2019

15. Methodology for cost-benefit analysis for minimum FCR activation period

16. 3.3 – Dynamic Stability Assessment / Management Knud Johansen 4th June 2019

17. Dynamic stability Assessment | SO GL requirementsQuick reminder - extract from SO GL • Articles concerned: 38, 39 in whole; 41, 45, 48, 57 partially (data exchange) • Article 38: Dynamic Stability monitoring and assessment • Imposes obligations on individual/synchronous area TSOs on monitoring and exchanging data on DS (38.1) as well as on performance and coordination of DS assessment (38.2). • Determines criteria (38.3) and sets the rules for deciding on the methods (38.6) in DS assessment. • Dynamic stability includes - frequency stability, angle stability and small signal stability aspects • Article 39: Dynamic Stability management • Imposes obligations to develop remedial actions if violations appeared (39.1), ensuring fault clearing times shorter than critical time calculated according to (39.2) and sets requirements on the common studies for identification and (if required as the outcome) (39.3.b), 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 methodology for defining a minimum inertia required to maintain operational security and to prevent violation of stability limits.

18. Activities within ENTSO-E on SO GL art. 38 & 39 • ENTSO-E TSO Workshops • 08-09/11/17 1st WS dialog on current practices - DSA and MI • 24/04/18 2nd WS aimed at first assessment and solutions in each SA • 20/09/18 3rd WS aimed at discussion and drafting of a solutions for compliance to art 39(3) • 09/04/19 4th WS aimed at discussion and drafting of a solutions for compliance to art 38(2) • ENTSO-E DSA Stakeholder Workshops • 23/05/18 1st DSA SH WS presenting current practices in each SA • 10/12/18 2nd DSA SH WS aimed at presenting the principles applied in each SA • 15/05/19 3rd DSA SH WS aimed at presenting coordination activities on DSA (38(2))in each SA Future DSA SH issues will be guided to the regular SO ESC meetings • Actions taken│in-progress • For MI - art. 39(3)(a) • All ENTSO-E Regional Groups addressed to timely deliver outcome of their studies and projects (RG CE and RG Nordic) or taking formal steps to confirm fulfillment of the requirements for the NRAs. • Results are planned to be available Sep 2019. • For DSA – art. 38(2) • DSA results are coordinated in various ways in the synchronous areas.

19. Pending questions: • Historical data / evolution of inertia for RG CE • The “simple” approach that can be applied for smaller systems like RG Ireland or RG GB or even RG Nordic system to simply sum-up all synchronous generating units for different system loading cases is quite challenging for the RG CE power system. • RG CE - SPD group has already tried and is somehow reporting the RoCoF after each forced unit outage higher than 1000 MW within along the years in order to “see” the inertia impact. • It should also be understood where the real risk within the RG CE power system is – namely during system split with respect to frequency stability etc., consequently we will have to focus on that much more as on a currently and for more that 10-20 years ahead simple overall inertia number for the RG CE power system. • Other pending questions • Will be included in the response procedure at the regular SO ESC meetings

20. Article 39 Minimum inertia requirements - status RG Continental Europe In the RG CE system inertia challenge is only relevant in case of a system split which is covered by NC ER Implementation proposal The required study to identify the need of a minimum inertia will be prepared by RG CE SPD. Existing SPD studies can be used to prove, that a minimum inertia is not required for ordinary and exceptional contingencies in RG CE. This study will also point out, that requirements on minimum inertia have to be discussed as part of the defense plan (NC ER) SO GL Article 39(3) All TSOs of a synchronous area shall conduct a common study to identify whether a minimum required inertia needs to be established, taking into account costs and benefits and potential alternatives. If this study determines that a minimum inertia requirement is needed, the TSOs shall develop a methodology how to determine a minimum required inertia. RG Nordic Tools developed for monitor the inertia in real time - a part of the NOIS system Bottom-up approach Based on breaker state and power measurements Visualized in each RG Nordic control room Further reading Nordic report Future system inertia

21. RG CE – approach on DSA – 38(2) Each TSO develops an individual DSA concept for their control area and involves neighbouring TSOs if necessary To avoid false conclusions system design settings are based on a single-bus model • Allows analysing multiple scenarios Work in progress to improve the nodal dynamic nodal model with more details on generating technology • Based on generic information • Developed for a single scenario • A properly tuned nodal model enables analysis of specific incidents but requires retuning for each scenario • On-going work to ensure interoperability between simulation tools RG Continental Europe 32 TSOs in 28 countries

22. RG Nordic – approach on DSA - 38(2) DSA is already a part of the transmission capacity calculation and operational planning A coordinated methodology will be gradually introduced and included Nordic System Operation Agreement Examples of present coordination activities: • Nordic load flow model updated regularly • Dynamic models will be included in CGM in the future • Coordination of EPC settings of HVDC-links Off-line studies already implemented: • Nordic planning model (PSS/E) • Svk and SN use also Aristo In future close to real-time DSA becomes possible: • Common grid model will include dynamic models • Many of dynamic models in Nordic planning model will need to be reviewed in order to fit into the CGM methodology.

23. RG IE/NI – approach on DSA - 38(2) Wind Dynamic Security Assessment Tool (WSAT) performs dynamic stability assessments on an All-Island basis. On-Line security assessments are performed every 5 minutes (24/7 – 365). On-Line security assessments include voltage, frequency and rotor-angle stability. Small-signal stability analysis are performed off-line. One single All-Island dynamic model is shared between both System Operators. Special Protection Schemes (SPS) are integrated in the model. Contingencies include loss of largest generation units and HVDC interconnectors, system separation and network faults on an All-Island basis. Requirements for performing studies and TSO co-ordination are fulfilled

24. RG GB – approach on DSA - 38(2)

25. B A C K U P

26. References related to Network Code Implementation from subgroup System Protection and Dynamics (SPD) Subgroup SPD supported NC implementation in Continental Europe with studies related to Effect of Inertia on System Stability Frequency Measurement Requirements Overfrequency Control Schemes DSA Applications

27. SO GL art. 38 Dynamic stability monitoring and assessment • Each TSO shall monitor the dynamic stability of the transmission system by studies conducted offline in accordance with paragraph 6. Each TSO shall exchange the relevant data for monitoring the dynamic stability of the transmission system with the other TSOs of its synchronous area. • Each TSO shall perform a dynamic stability assessment at least once a year to identify the stability limits and possible stability problems in its transmission system. All TSOs of each synchronous area shall coordinate the dynamic stability assessments, which shall cover all or parts of the synchronous area. • When performing coordinated dynamic stability assessments, concerned TSOs shall determine: • the scope of the coordinated dynamic stability assessment, at least in terms of a common grid model; • the set of data to be exchanged between concerned TSOs in order to perform the coordinated dynamic stability assessment; • a list of commonly agreed scenarios concerning the coordinated dynamic stability assessment; and • a list of commonly agreed contingencies or disturbances whose impact shall be assessed through the coordinated dynamic stability assessment. • In case of stability problems due to poorly damped inter-area oscillations affecting several TSOs within a synchronous area, each TSO shall participate in a coordinated dynamic stability assessment at the synchronous area level as soon as practicable and provide the data necessary for that assessment. Such assessment shall be initiated and conducted by the concerned TSOs or by ENTSO for Electricity. • When a TSO identifies a potential influence on voltage, rotor angle or frequency stability in relation with other interconnected transmission systems, the TSOs concerned shall coordinate the methods used in the dynamic stability assessment, providing the necessary data, planning of joint remedial actions aiming at improving the stability, including the cooperation procedures between the TSOs. • In deciding the methods used in the dynamic stability assessment, each TSO shall apply the following rules: • if, with respect to the contingency list, steady-state limits are reached before stability limits, the TSO shall base the dynamic stability assessment only on the offline stability studies carried out in the longer term operational planning phase; • if, under planned outage conditions, with respect to the contingency list, steady-state limits and stability limits are close to each other or stability limits are reached before steady-state limits, the TSO shall perform a dynamic stability assessment in the day-ahead operational planning phase while those conditions remain. The TSO shall plan remedial actions to be used in real-time operation if necessary; and • if the transmission system is in the N-situation with respect to the contingency list and stability limits are reached before steady-state limits, the TSO shall perform a dynamic stability assessment in all phases of operational planning and re-assess the stability limits as soon as possible after a significant change in the N-situation is detected.

28. SO GL art. 39 Dynamic stability management Where the dynamic stability assessment indicates that there is a violation of stability limits, the TSOs in whose control area the violation has appeared shall design, prepare and activate remedial actions to keep the transmission system stable. Those remedial actions may involve SGUs. Each TSO shall ensure that the fault clearing times for faults that may lead to wide area state transmission system instability are shorter than the critical fault clearing time calculated by the TSO in its dynamic stability assessment carried out in accordance with Article 38. In relation to the requirements on minimum inertia which are relevant for frequency stability at the synchronous area level: all TSOs of that synchronous area shall conduct, not later than 2 years after entry into force of this Regulation, a common study per synchronous area to identify whether the minimum required inertia needs to be established, taking into account the costs and benefits as well as potential alternatives. All TSOs shall notify their studies to their regulatory authorities. All TSOs shall conduct a periodic review and shall update those studies every 2 years; where the studies referred to in point (a) demonstrate the need to define minimum required inertia, all TSOs from the concerned synchronous area shall jointly develop a methodology for the definition of minimum inertia required to maintain operational security and to prevent violation of stability limits. That methodology shall respect the principles of efficiency and proportionality, be developed within 6 months after the completion of the studies referred to in point (a) and shall be updated within 6 months after the studies are updated and become available; and each TSO shall deploy in real-time operation the minimum inertia in its own control area, according to the methodology defined and the results obtained in accordance with paragraph (b).

29. 3.4 Common grid model methodology- Feedback System Operation Coordination Group Knut Eggenberger 4th June 2019

30. CGM-related methodologies: Formal approval of the consolidated versions (1) • Formal requirement in order for the consolidated versions to be legally binding (and replace existing versions): • TSOs request an amendment under the applicable Network Codes (Guidelines) • Standard procedure applies: "all TSOs" vote #1, public consultation, revision, "all TSOs" vote #2 ... • Tour de table poll at 21 March 2019 SO ESC suggests that other stakeholders are also in favour of formal approval • However, TSOs' original project plan (aiming for submission of proposal by November 2019) needs to be revised:  • Legal issues associated with the delays in the implementation of the CGM process ==> NRAs have indicated that regulatory approval of the consolidated CGM-related methodologies shall not be sought before the CGM process is close to becoming operational. • Status of material specifically relating to the week-ahead time frame: NRAs indicated that they prefer to check that this material is not subject to approval indeed

31. CGM-related methodologies: Formal approval of the consolidated versions (2) Revised approach • Given the delay, as the drafting team continues to consolidate the CGM-related methodologies (also including a CGMM for the week-ahead time frame), it shall endeavour to reduce the uncertainties (risks) related to the regulatory approval process as much as possible. Specifically, the drafting team shall, in discussion with NRAs, resolve any outstanding open issues to ensure that the contents of the methodologies - as currently approved - is not modified.  • When the CGM process is close to becoming operational, the drafting team shall provide an updated assessment of the aforementioned uncertainties (risks) and a proposal on how to proceed. Transfer of decision on approval of consolidated methodologies to ACER • Recast ACER Regulation not expected to materially affect the work to be done. • Practical arrangements (e.g., possible change in the drafting team's contacts (the shadow drafting team)) currently under discussion. Scope for stakeholder involvement • The drafting team also plans to make use of the delay in order to update stakeholders (using the ESC(s) as a forum) • Agenda slot requested at the 11 September 2019 meeting of the SO ESC for a more substantive presentation

32. B A C K U P

33. BACKUP slides on CGM-related methodologies Some basic facts & figures on the CGM-related methodologies have been presented at the 21 March 2019 meeting of the SO ESC. These slides are not included in the body of the slide deck again, but provided for reference in the present backup. Any remaining questions should be addressed to methodologies@cgm-program.eu

34. Consolidation of CGM-related methodologies Approval status of CGM-related methodologies • Content almost identical • Principal differences: Art. 3 (Scenarios), Art. 4 (IGMs), Art. 22 (CGM Process) • Terminology not 100% consistent • Content almost identical • Terminology not 100% consistent • CGMMs approved: • CGMM-v1-plus (pursuant to Regulation 2015/1222) • CGMM-v2-plus (pursuant to Regulation 2016/1719) • CGMM-v3 (pursuant to Regulation 2017/1485) • GLDPMs approved: • GLDPM-v1 (pursuant to Regulation 2015/1222) • GLDPM-v2 (pursuant to Regulation 2016/1719)

35. CGM-related methodologies: remaining tasks • Consolidation: • NRAs and TSOs agree: a single consolidated version of the CGMMs (and GLDPMs) would be very helpful • 1 document instead of 3 (2) easier to handle; terminology could be made 100% consistent • NRAs' legal experts: such a document could be legally binding and could replace the existing versions • CGMM for the week-ahead time frame: • RSCs and TSOs have expressed interest in a CGMM for the week-ahead time frame • Principal applications: CGS (Critical Grid Situations analysis), OPC (Outage Planning Coordination), STA (Short-Term Adequacy assessment) • Principle of a single CGM per time frame to be retained: use of CGM to be described in process descriptions for subsequent processes, not in the CGMM • ==> Combine both tasks in order to achieve synergies • ==> Work on this revision has begun