WG European Market Design

1. WG European Market Design Apr 23rd 2019 10:00 – 12:00

2. Agenda General status intraday – 30 min BeDeLux update – 10 min Core Capacity Calculation Methodology: outcome ACER decision – 30 min Day-Ahead Capacity Calculation on Nemo Link – 15 min LTR curtailment on BE-FR border – 10 min Red zone statistics – 15 min

3. 1. General status intraday

4. CWE IDCC – Current ATC extractionandincrease/decreaseprocess 1. FB DA domain 2. DA MCP 3. DA leftover ATC 4. ID ATC incr requests 5. Available ID ATC From FB DA domain to available ID ATC: DA leftover ATC (step 3): FB DA domain is updated based on MCP & exchanges are increased until reaching the limits of the updated domain (considering differences in PTDF between elements!) ID ATC increase process (steps 4-5):  • 300 MW of ID ATC increase requested per BE border • ATC increase requests are accepted if validated by all other TSO/RSC

5. CWE IDCC – Current ATC increase/decreaseprocess ATC increase/decrease process: • Starting point = DA leftover ATC computed from FB domain • Local evaluation by each TSO/RSC to request ATC increases or to decrease ATC on its borders • Merging of ATC increase requests & ATC decrease notifications by Central Matching Tool • Local analysis by each TSO/RSC to fully accept/partially accept/reject the ATC increase requests • Central Matching Tool consolidates acceptances/ rejections & distributes them back to the TSOs • Final CWE ID ATCs & NTCs are available for capacity allocation

6. CWE IDCC – Current ATC extraction: impact DA MCP on ATC leftovers BE > NL Examples: DA Market Clearing Point inside FB domain. ID ATC available in all 4 market directions. DA Market Clearing Point on edge of FB domain. Only ID ATC available in 2 market directions. DA Market Clearing Point in corner of FB domain. No ID ATC available. BE > FR

7. CWE Flow Based IDCC As discussed during CWE Consultative Group meeting on 17/04, the Flow Based ID Capacity Calculation project has been put on hold due to delay in the CGMES project within ENTSO-E • As illustrated on the next slide, the quality of the grid model is key to ensure an efficient capacity calculation in intraday Awaiting the re-start of the project (in CWE or CORE), the ATC extraction and increase/decrease process will remain

8. CWE Flow-based IDCC – Drivers for DA MCP outside FB ID domain 2. Modeling • ∆ between D2CF forecasted NP & DA MCP • ∆ in renewable / load forecasts from D2CF to DACF • ∆ in generation patterns between D2CF & DACF • RA required by DA security analysis are not included in CGM for IDCC -> input CGM is not congestion free* 3. Insufficient RA provided to FB IDCC optimizer 1. LTA inclusion & MinRAM20 • Illustration: *Solutions are being developed within the CSA and Coordinated CGM methodologies at EU/CCR level (by the SO GLs).

9. General status update on ID Nemo Link: Discussions are ongoing between Elia / Nemo Link / NGESO to introduce an ID product on Nemo Link. The timing is not known, but Elia intends to launch such a product as soon as possible. Due to the uncertainty on the Brexit (thus whether GB will be part of the IEM market or not), the project partners decided to first implement ID explicit auctions via JAO Key points of the auction design are being clarified and will be consulted with the market via the consultation of the NLL access rules: At first an MTU of 60’ is foreseen to allow for a short implementation time. In a later stage, the MTU could be shortened to 30’ (ISP in GB is 30’). Alegro: Go live is planned in Q4 2020. The project partners intend to launch an ID product at or close after go-live. Change of MTU: Elia is working together with the neighboring TSOs to reduce the MTU of the cross border capacity from 60’ to 15’ (BE-NL) and 30’ (BE-FR) in line with the ACER decision on the IDCZGTs (which includes a clarification of the MTU definition)

10. 2. BeDeLux update

11. Bedelux update The phase shifter transformer (PST) located in Schifflange connecting the grid of Elia and Creos was put in operation 11 October 2017 with a one year technical trial period. As the previous SPAIC study showed a neutral impact on the regional welfare due to limited use of the interconnector. The technical trial phase was performed to gain experience and to assess whether a significant adjustment of the technical parameters (constraints and/or available PST taps for capacity calculation in DA Market Coupling timeframe) could be envisaged. Four quarterly monitoring reports of the technical trial phase have been shared with all CWE NRAs. The aim of technical reports is to assess the approved operational principles based on the collected data. The involved parties have agreed on and implemented an adapted operation concept in order to maximise the operational time of use of the IC BeDeLux. This adaptation of the operational concept is one major improvement of the trial phase. It has allowed to improve the SoS of Luxembourg. Based on the results of the trial phase, projects partners concluded that these results do not allow significant adaptation of the technical parameters and as such justifying the launch of a new SPAIC study. The project parties have decided that there will be no commercialisation of the interconnector. The above information was shared with the CWE NRAs and market Parties.

12. 3. Core Capacity Calculation Methodology: outcome ACER decision

13. Benefits for the integrated electricity market Source: ACER

14. If MS(s) go for an action plan, a linear trajectory applies between 2020 and 2025. A Linear trajectory compliant with the CEP is defined/interpreted in CCM: it applies unless the action plan defines a different trajectory MinRAM: evolution to 70% 30% Flows induced by NEMOLink, BritNed, IFA etc. are part of the 70%

15. 3 main steps in the capacity calculation process • Creation of capacity calculation inputs by the Core TSOs CNEC selection RAs in base case to reduce loop flows Non-costly remedial actions for optimization and costly remedial action for validation • Capacity calculation process by CORESO & TSCNET Non-costly remedial action optimization Adjustment for minRAM: inclusion of 70% or targets as defined in action plans / derogations • Capacity validation by the Core TSOs in coordination with CORESO & TSCNET Two-step validation: coordinated assessment of RAs potential to guarantee the RAM + individual TSO validation – TSO maintains the final say Can lead to capacity reduction but not below LTA inclusion

16. CNEC selection Internal CNECs are allowed only for a transition period (2 years). After the transition period, internal CNECs are allowed only if other alternatives are less efficient Transition period: during first 2 years (till end 2022) no filter on internal CNECs Every 2 years list of internal CNECs to be reviewed and annexed to methodology First submission 18 months after go-live Requirement 1: PTDF threshold 5% Requirement 2: impact assessment PTDF threshold 10% (or higher) Requirement 3: demonstrate through CBA that adding CNEC more efficient than (combination of) RAs – BZ split – invest in grid  methodology, assumptions & criteria to consult with NRAs – pragmatic approach needed Due diligence that alternatives have been explored sufficiently in advance

17. Allocation constraints Transitory period of 2 years to explore alternative solutionsAfter 2 years: allocation constrains should be removed unless alternatives less efficient External constraints may be used by ELIA, TenneT B.V. and PSE during a transition period of two years Elia to publish quarterly report on the value to use and underlying analysis Effectiveness: in case of non-zero shadow price in >= 0.1% of time on quarterly basis, Elia has to provide following Economic loss of having applied the external constraint Effectiveness of the external constraint to address underlying operational security limits, compared to alternative solutions If alternative solutions are more effective: implement them If no alternative solutions: submit proposal for extension by 18 months after go-live Elia can decide to stop application of external constraint at any time: inform NRAs & market 1 months in advance

18. Loopflows & non-costly remedial action optimization (NRAO) Elia will have more flexibility to use its PSTs. Efficiency of the NRAO and impact of the PSTs will be monitored during the // run and after go-live CORE CCM introduces the concept of loopflow threshold on cross-border CNECs TSOs are allowed to define initial settings of RAs with aim to reduce loopflows below this threshold Threshold must be consistent with assumptions on loopflows when defining minRAM minRAM 70%: LF threshold = 30% minus FRM  ~15% NRAO frees up capacity on the most limiting line within two main boundary constraints Constraint 1 = keep monitored CNECs1 secure Constraint 2 = loopflows can’t be increased above the maximum of 2 parameters Parameter 1: loopflow threshold, assume 15% Parameter 2: loopflow calculated at zero-balance exchange taking into account the initial PST settings Example 1: 30% LF anticipated  PSTs initial setting reduce LF to 15%  loopflow = max (15,15) = 15% Example 2: 10% LF anticipated  PSTs neutral position  loopflow = max (10,15) = 15% 1) monitored CNEC = internal CNEC added solely during NRAO step, no PTDF threshold, minimum 50 MW RAM available

19. Capacity validation Capacity reductions shall be exceptional and justified. If such deviations occur > 1% per quarter, TSO has to file a plan how it will be solved TSOs have the right to correct cross-zonal capacities for reasons of operational security If insufficient RAs: internal line can be added as CNEC on the condition that it respects the PTDF threshold Coordinated assessment will be gradually implemented First year: information exchange After 24 months: full analysis, the rules are to be defined through an amendment to be delivered by TSOs 18 monhts after go-live

20. Increased transparency with central role for CORESO & TSCNET Reporting to NRAs Data publication: set-up through stakeholder consultation • Annual report NRAO efficiency incl. economic assessment Systematic withholding of non-costly RA’s Accuracy non-CORE exchanges Data quality • Quarterly report Coordinated and individual capacity reductions, incl. economic assessment Allocation constraints incl. economic assessment • Impact analysis & performance During internal and external // runs: quarterly After go-live: annually • Online communication platform FB params, RAM breakdown, RAO outcome, validation outcome, forecast data, etc Methodology to monitor data quality Yearly satisfaction survey • Tool to evaluate interaction capacities - exchanges

21. Next steps: from internal to external parallel run Internal // run: getting the computational chain in place – from all the local TSO input data up to and including the performance indicators (such as prices and net positions) – and to get a grip on the Core FBMC impact External // run: TSOs, CORESO & TSCNET operators to perform a daily Core DA FB capacity calculation by using industrial IT tools, and the NEMOs perform FBMC simulations using the operational order books Disclaimer: impact of ACER decisions are being assessed and depending on the outcomes the start of the EXT//run might change 18 months after go-live: amendments to improve inputs & validation

22. 4. Day-Ahead Capacity Calculation on Nemo Link

23. Day-Ahead Capacity Calculation on Nemo Link Mercator - Horta is being upgraded to HTLS Before the implementation of the approved Channel DA/ID CCM, Elia has introduced an interim implementation. This interim implementation is based, where possible, on the approved method: The interim method has been published on the website of Elia A capacity calculation is triggered in case of planned outage (i.e. Mercator – Horta) Due to the high impact of NLL (export to UK) direction on the remaining line, Elia had to limit the NTC on NLL. Elia expects the situation to improve once the works are finished. Second circuit is not upgraded yet, Fmax of 1500 MW

24. Day-Ahead Capacity Calculation on Nemo Link In line with the Article 5 (1) of the Channel TSOs proposal of common capacity calculation methodology, ELIA shall calculate the capacity for the Nemo Link and for each day-ahead market time unit using the following approach: The capacity shall be equal to the Maximum Power Transfer Capacity (MPTC) value unless there is a specific planned or unplanned outage with significant impact ELIA shall use the CGMs merged in the scope of the CWE FB DA and shall update the values of the Channels interconnectors to represent full Channel import and export situations between the UK and the CE synchronous area. ELIA shall then perform the qualification of the NTCs using a simplified approach for selecting the Remedial Actions. The calculated NTC is coordinated with NGESO and NLL elia presentation template / City, 19.11.2013 / Firstname Lastname

25. 5. LTR curtailment on BE-FR border

26. LTR curtailment on BE-FR border A reduction period was foreseen in March in the yearly LTR in order to allow for reinforcement work (replacement by HTLS conductors on Avelgem – Mastaing) Due to bad weather conditions in March (high wind) and despite the consideration of additional flexibility in the rescheduling of the work, three additional days have been required In line with HAR, full compensation is granted

27. 6. Red zone statistics

28. Red Zone mechanism, counting and graphical representation • A Red Zone (RZ) is the status of an electrical zone, for a defined direction (I/D) and for a defined period during the day, in which a constraint in MW has been set with regards to production program adaptation on CIPU PU situated in this electrical zone. • As from Q2 2017, three adaptations have been brought to the concept of RZ: • From Peak-Off Peak periods to hourly defined periods allowing a better time granularity • Splitting of the zones of Langerbrugge and Hainaut allowing a better geographical granularity • Intraday update of the status of the RZ in function of the last intraday forecast • One (I/D) RZ is counted for each day where a (I/D) RZ has been applied. This means that different (I/D) RZ in the same electrical zone covering different periods within the same day count as one. • Because of the split of Langerbrugge and Hainaut in Q2 2017, • Dotted lines represent the number of RZ applied on the new electrical zones (LAE,LAW, HTE and HTW) as the beginning of their existence

29. Number of activations of Decremental Red Zones 2013-2018 Increase of activations of decremental red zones, mainly due to high flux in the 380kV. Splitting of the zones Langerbrugge (=LAWest + LAEast) and Hainaut (HTEast + HTWest) as from 05/2017

30. Decremental RZ 2018 “Grid constraint” category is in general a consequence of high flux in 380kV, unbalanced generation between east/west or N-1 constraints on grid elements.

31. Number of activations of Incremental Red Zones 2013-2018 Incremental red zones were mainly due to a high wind generation in LAW (68%) and grid maintenance and a high generation in HTE (resp. 46% & 27%) Splitting of the zones Langerbrugge (=LAWest + LAEast) and Hainaut (HTEast + HTWest) as from 05/2017

32. Incremental RZ 2018 “Grid constraint” category is in general a consequence of high flux in 380kV, unbalanced generation between east/west or N-1 constraints on grid elements.