COMMISSION DECISION (EU) 2022/639

of 27 August 2021

on the aid scheme SA.54915 – 2020/C (ex 2019/N) Belgium – Capacity remuneration mechanism

(notified under document C(2021) 6431)

(Only the English version is authentic)

(Text with EEA relevance)

THE EUROPEAN COMMISSION,

Having regard to the Treaty on the Functioning of the European Union, and in particular the first subparagraph of Article 108(2) thereof,

Having regard to the Agreement on the European Economic Area, and in particular Article 62(1) (a) thereof,

Having called on interested parties to submit their comments pursuant to the provisions cited above (1) and having regard to their comments,

Whereas:

1. PROCEDURE

(1) Following a pre-notification procedure, by letter dated 19 December 2019, the Kingdom of Belgium notified the Commission, in accordance with Article 108(3) of the Treaty on the Functioning of the European Union (‘TFEU’), a market-wide capacity remuneration mechanism (‘the measure’ or ‘CRM’).

(2) By letter dated 21 September 2020, the Commission informed Belgium that it had decided to initiate the procedure laid down in Article 108(2) TFEU in respect of the measure.

(3) The Commission decision to initiate the procedure (‘the Opening Decision’) was published in the Official Journal of the European Union (2). The Commission called on interested parties to submit their comments.

(4) By letter dated 22 October 2020, Belgium submitted its comments on the Opening Decision. The Commission further received comments from 15 interested parties. It forwarded them to Belgium, which was given the opportunity to react. Its comments were received by letter dated 24 December 2020.

(5) On 9 July 2021, Belgium exceptionally agreed to waive its rights deriving from Article 342 TFEU, in conjunction with Article 3 of Regulation 1/1958 (3), and to have this Decision adopted and notified in English.

2. DETAILED DESCRIPTION OF THE MEASURE

2.1. Overview of the measure

(6) Belgium estimates that it will face an electricity generation adequacy problem from 2025, predominantly resulting from its decision to phase-out all nuclear capacity over the period 2022-2025 and from the decommissioning of thermal generation capacities in Belgium and its neighbouring countries.

(7) Therefore, the objective of the measure is to ensure that there is sufficient capacity for the production of electricity and that such production meets the expected demand of electricity.

(8) Under the CRM, the beneficiaries would be selected though a competitive bidding process and would be remunerated for their availability. The support would take the form of a capacity payment for the duration of the capacity agreement. In exchange, the successful bidders would give their availability to meet the transmission system operator’s (‘TSO’) demand during stress events that could occur.

(9) Belgium has set its national decarbonisation objectives in its National Energy and Climate Plan (‘NECP’) (4). Based on this NECP, the share of renewable energy sources in the Belgian electricity consumption is planned to increase from 17 % in 2017 up to at least 40.4 % in 2030. Reaching these objectives will require integrating significant renewable energy sources (‘RES’) such as wind and solar, whose intermittent feature may pose a challenge to adequacy and security of supply.

(10) Although the development of RES is not its primary objective, the design of the CRM embraces the ambitious targets to further introduce RES in the Belgian energy mix and acts as a complement to the further development of new intermittent RES.

2.2. Legal basis and government arrangements

(11) The legal basis of the measure is the Electricity Act of 29 April 1999 on the organisation of the Belgian electricity market (‘the Electricity Act’), which has been modified by laws (5) published on 16 May 2019 and 19 March 2021 in the Belgian Official Gazette.

(12) Additionally, Royal Decrees (6) and the Rules on the Functioning of the Belgian CRM (7) were prepared to further elaborate the modalities of the CRM: (1) the Royal Decree of 28 April 2021 to determine the methodology for the capacity calculation and auction parameters in the context of the capacity remuneration mechanism (8); (2) the Royal Decree of 21 May 2021 on eligibility criteria related to cumulative support and minimal participation threshold (9); (3) the Royal Decree of 4 June 2021 on investment thresholds and eligible costs (10); (4) the draft Royal Decree on the determination of the conditions based on which capacity holders of foreign capacities can participate in the CRM (11); and (5) the Royal Decree of 30 May 2021 on control modalities (12).

(13) In August 2020, Elia, the Belgian TSO, carried out a public consultation on the Rules on the Functioning of the Belgian CRM (13).

2.3. Generation adequacy in Belgium

2.3.1. Reliability standard

(14) The primary objective of the proposed CRM is to ensure security of supply, as defined in a reliability standard.

(15) As notified in 2019, the reliability criteria in Belgium was defined by a two-part Loss of Load Expectation (‘LOLE’) criterion: the anticipated number of hours during which it will not be possible for all the generation resources available to the Belgian electricity grid to cover the load and need for operating reserves, taking into account also demand response, storage and interconnectors, shall not exceed 3 hours for a statistically normal year. As a second criterion, the LOLE shall remain below 20 hours for a statistically abnormal year (‘LOLE95’) (14). These values were also enshrined in the Electricity Act.

(16) The reliability standard is an expression of the estimate of the value consumers attach to avoiding disconnections of their electricity supply (‘VOLL’), and the expected cost of new capacity in Belgium (‘CONE’).

(17) Article 23(6) of Regulation (EU) 2019/943 of the European Parliament and Council of 5 June 2019 on the internal market for electricity (15) (‘Electricity Regulation’) provides for the establishment of a Union methodology for calculating the VOLL, the CONE and the reliability standard.

(18) On 2 October 2020, the Agency for the Cooperation of Energy Regulators (‘ACER’) approved the methodology for calculating the VOLL (‘VOLL methodology’), the CONE (‘CONE methodology’) and the reliability standard (‘RS methodology’). The three methodologies are collectively referred to as the ‘VOLL/CONE/RS methodology’ (16).

(19) On 7 June 2021, Belgium submitted the calculation of the new VOLL, CONE and the reliability standard in accordance with the VOLL/CONE/RS methodology.

(20) On 28 May 2021, the Belgian regulator for energy (‘CREG’) sent to the Minister of Energy its proposal for a reliability standard for Belgium. The reliability standard proposed by the CREG was 2 hours and 43 minutes.

(21) The Directorate-General for Energy of the Federal Public Service Economy (‘FPS Economy’) in its opinion of 2 June 2021 recommended to round the reliability standard to 3 hours in order to ensure consistency with previous studies on the adequacy of national and European resources, to enable compliance with the practice of expressing reliability standards in rounded hours as in neighbouring countries and to take account of the fact that the non-marginal deficit identified for Belgium will be filled by an energy mix and not by a single reference technology.

(22) According to the draft Royal Decree on the determination of the reliability standard and the approval of values for the cost of VOLL and CONE, the new reliability standard is set at 3 hours.

(23) The draft Royal Decree also approves the single estimate of the cost of VOLL, on the basis of the value set by the Directorate-General for Energy of the FPS Economy together with the Planning Bureau, and the CONE on the basis of the DSR technology (17).

(24) The VOLL will be set at EUR 16 033/MWh and the CONE at EUR 45/kW/year.

(25) The VOLL was calculated using a triangulation method which took into account the production function and a survey on the willingness to pay carried out by the CREG. According to the Belgian authorities, the survey carried out by the CREG was not robust as, among others, the single scenario proposed (at a temperature of less than +5°C) was not representative for most scarcity scenarios. Therefore, the weight put on the results of the survey to estimate the VOLL was limited.

(26) According to the Electricity Act, the calculations relevant for the CRM will be carried out based on the reliability standard in force on 15 September of the year preceding the auction.

(27) In view of the tight timetable, Belgium calculated the volume to be procured in the Y-4 and Y-1 auctions, planned for October 2021 and 2024 respectively, based on the old reliability standard subject to the commitment to adjust the volumes, if needed, should the new reliability standard and the adequacy assessment show a significant lower capacity need.

(28) Belgium also committed to update the VOLL based on a new survey regarding willingness to pay, in line with the CONE/VOLL/RS methodology and, if needed, set a new reliability standard before September 2022, with a view to using the new reliability standard to determine the volume to be procured at the latest for the 2023 auction.

2.3.2. Adequacy assessment

(29) According to the Belgian authorities, Belgium will be confronted with an adequacy problem from 2025, predominantly resulting from the nuclear phase-out that is planned between 2022-2025, reinforced by the decommissioning of thermal generation capacities in neighbouring countries. The adequacy problem has been established by way of a national resource adequacy study assuming several scenarios.

(30) The national adequacy study covering the period between 2020-2030, published by the Belgian transmission system operator Elia in June 2019 (‘the 2019 Adequacy and Flexibility study’) (18), identified a systematic need for new capacity of at least 3,9 GW in the High Impact Low Probability (HiLo) scenario (EU-HiLo), by the winter of 2025-2026. This scenario takes account of imported electricity and assumes that several French nuclear units might not be available (on top of ‘normal’ unavailability). The same scenario was used in the framework of the strategic reserve volume evaluation (19). The EU base case scenario (20) shows a shortage of 2,4 GW if the existing thermal capacity in the system is maintained (see Figures 4-18 of the 2019 Adequacy and Flexibility study).

(31) The results of the 2019 Adequacy and Flexibility study show, for the EU-HiLo scenario that, without intervention, the LOLE would be as high as 10,5 hours in 2025, thereby significantly exceeding the national reliability standard in terms of security of supply. The LOLE95 indicator would even increase to 84 hours. The following table shows the LOLE results, as entailed in the national adequacy study for the EU-HiLo and the EU base case scenarios: Table 1 LOLE results for Belgium in the Adequacy and Flexibility study 2025 2028 2030 EU-base EU-HiLo EU-base EU-HiLo EU-base EU-HiLo Remaining market LOLE (hours) 9,4 10,5 6 6,9 6 6,2 Remaining market LOLE95 (hours) 89 84 63 76 43 51 Source: 2019 Adequacy and Flexibility study

(32) On 11 July 2019, CREG published an analysis of the 2019 Adequacy and Flexibility study (21). In this analysis, among others, CREG questioned the use of the EU-HiLo scenario as the main scenario. According to the CREG, the methodology for evaluating the profitability of existing and new capacity should be improved and all available balancing reserves in Belgium and abroad to should be taken into consideration.

(33) In November 2019, the European Network of Transmission System Operators for Electricity (‘ENTSO-E’) released the Mid-term Adequacy Forecast 2019 (‘MAF 2019’) (22) which shows the following results for Belgium in 2025: Table 2 LOLE levels for Belgium in MAF 2019 Base case scenario – 2025 Low carbon sensitivity (23) – 2025 Average LOLE 1,09 hours 1,61 hours LOLE95 3,15 hours - Source: ENTSO-E’s ‘Mid-term Adequacy Forecast – 2019’

(34) However, according to Belgium, the ENTSO-E’s MAF 2019 does not present the LOLE results for Belgium, accurately enough as it assumes the availability of additional 2,5 GW (24), which in fact is not guaranteed.

(35) In its final report of April 2020 (25), the Pentalateral Energy Forum (26) (‘PLEF’) presented the following results for Belgium in 2025: Table 3 LOLE levels for Belgium in PLEF General Adequacy Assessment 2020 Base case scenario – 2025 (27) Low gas sensitivity – 2025 (28) Low nuclear/CH NTC sensitivity 2025 (29) Average LOLE 3,3 hours 8,1 hours 4,6 hours Source: Pentalateral Energy Forum ‘Generation Adequacy Assessment – April 2020 – Final report’

(36) In November 2020, ENTSO-E released the MAF 2020. For the base case 2025 scenario, the MAF 2020 results show an average LOLE of 0,4 hours which therefore meets the legal adequacy criterion for Belgium of LOLE 3 hours.

(37) However, in the countries’ comments annexed to the MAF 2020, Belgium indicated that: ‘There is a significant amount of assumed ‘new built’ capacity in MAF 2020 distributed over a large set of countries. It should be noted that there is in general no certainty that these capacities would finally materialize in 2025, hence these assumptions and the results following those as presented in MAF 2020, should be interpreted carefully. Furthermore, Belgium is since several years part of the region where Flow-Based Market Coupling has already been implemented. Whereas a flow-based simulation model has been developed and implemented by Elia, e.g. in the 2019 Elia study and which was also used in the PLEF GAA 2020 study, such approach is not yet used in the present MAF 2020 study’.

(38) In its notification, the Belgian authorities indicated that the methodology and data are aligned on European level so that the 2019 Adequacy and Flexibility study is in line with the MAF 2019.

(39) According to Article 23(3) of the Electricity Regulation, ENTSO-E should develop a methodology which shall be used for the European resource adequacy assessment (‘ERAA’) and any national resource adequacy assessment (‘NRAA’) (see Article 24 of the Electricity Regulation). This methodology should be approved by ACER.

(40) On 2 October 2020, ACER approved the methodology for the European resource adequacy assessment (‘the ERAA methodology’) (30).

(41) On 30 June 2021, Elia published a new Adequacy and Flexibility study for the period 2022-2032 (‘the 2021 Adequacy and Flexibility study’).

(42) In line with the ERAA methodology, Elia integrated the elements of the ERAA methodology outlined below into the framework of the 2021 Adequacy and Flexibility study: (a) climate years: Elia chose to implement the first option outlined in the ERAA methodology, i.e. relying on a best forecast of future climate projections. (b) economic viability assessment: Elia developed a method for calculating the economic viability of the different assets in the electricity system, in line with the ERAA methodology. (c) flow-based: Elia’s modelling framework integrates all known and planned market design introductions into the flow-based capacity calculation method, such as the extension of the region to Core; ‘advanced hybrid coupling’; or the minRAM rules introduced by the Electricity Regulation. (d) flexibility: the study includes both the calculation of the total system’s flexibility needs and means and an assessment of the dimensioning of Frequency Containment Reserves and Frequency Restoration Reserves for each target year to reflect reserve needs that will cover imbalances in line with legal requirements which are modelled in the adequacy simulations. Furthermore, the flexibility characteristics of offshore wind power are refined, and power-to-x technologies are included as new technologies. Finally, specific focus is placed on the impact of the integration of the second wave of offshore generation capacity and cross-border balancing platforms. (e) sectorial integration: regarding sector coupling, the interfaces between the electricity system and different sectors such as the transport, heating and gas sectors are taken into account through the inclusion of assumptions about electric vehicles, heat pumps and thermal gas unit generation capacities respectively. In order to grasp the implications of using electricity to generate hydrogen in the modelling used in the present study, electrolysers were added as a (flexible) consumption of electricity in Belgium and abroad. Moreover, special attention was given to digitalization of additional electricity consumption from transport and heat. (f) ten-year horizon: the study is based on the ten-year horizon (2022-2032). In order to reduce the amount of simulations and computations, not all sensitivities and scenarios were simulated for all the years: some key years were analysed more in depth. A large amount of sensitivities were performed on Belgium and abroad in order to grasp and understand the implications of varying certain assumptions. For comparison, the ERAA 2021 is expected to only simulate the years 2025 and 2030. (g) variants with and without capacity mechanisms: in line with the Electricity Regulation and the ERAA methodology, Elia included scenarios both with and without market-wide capacity mechanisms in Europe.

(43) The Belgian authorities submitted that the main methodological requirements stipulated in the ERAA methodology have been implemented in this study.

(44) Based on the Electricity Regulation, the NRAA must contain the reference central scenarios. Those scenarios shall include, among other, an economic viability assessment of generation assets. The ERAA methodology further specifies that two central reference scenarios are to be defined, one with capacity mechanisms across Europe and the other one without such capacity mechanisms.

(45) Consequently, in the 2021 Adequacy and Flexibility study two central scenarios were explored: (a) ‘EU-BASE’: reflects a scenario which takes into account already approved market-wide capacity mechanisms in France, Great Britain, Poland, Italy and Ireland and assumes that these will be in place until the end of this study’s timeframe; (b) ‘EU-noCRM’: this reflects a scenario that excludes market-wide capacity mechanism revenues, so assuming that no market-wide capacity mechanisms exist in Europe.

(46) The 2021 Adequacy and Flexibility study takes account of the contribution of all resources including existing and future possibilities for generation, energy storage, sectoral integration, demand response, and import and export and their contribution to flexible system operation.

(47) The Belgian authorities submitted that the modelling of the maximum clearing prices performed in the 2021 Adequacy and Flexibility study takes into account all the available legal provisions, such as the currently applicable maximum price limit, the 60 % rule (31) as set in Commission Regulation (EU) 2015/1222 of 24 July 2015 establishing a guideline on capacity allocation and congestion management (32), and Decision No 04/2017 of ACER of 14 November 2017.

(48) The 2021 Adequacy and Flexibility study models the automatic increase of the maximum clearing price from 2025 onwards. According to the Belgian authorities, it is most probable that no LOLE will occur before 2025, therefore no maximum clearing price increase is modelled before 2025. However, even if price cap increases were to occur, according to the Belgian authorities, the modelling shows that the results of the economic viability assessment for 2025 would not change (see Figures 3-72 of the 2021 Adequacy and Flexibility study). Belgium committed to ensure that the new adequacy study, to be published by June 2023, fully takes into account the methodology for dynamic price increases from the beginning of the simulation time period onwards.

(49) According to the 2021 Adequacy and Flexibility study, from 2025, once the nuclear phase-out is completed, Belgium will face a structural need for new capacity. This need amounts to 2 GW in 2025 in the central ‘EU-BASE’ scenario, and gradually increases to 3,9 GW by 2032. The increased need is linked to the expected increase in electricity consumption and reduced imports during periods of scarcity in Belgium.

(50) The 2021 Adequacy and Flexibility study provides that only a very small share of the new capacity will be viable via the energy-only market by 2025.

(51) Consequently, the Belgian authorities consider that, with no action, a resource adequacy concern is identified in Belgium from 2025 onwards.

(52) The 2021 Adequacy and Flexibility study represents the latest and best view of the need for the CRM.

2.3.3. Market failures

(53) Belgium has identified a number of market failures which hamper a well-functioning, secure, affordable and sustainable electricity market.

(54) A first market failure stems from different factors that prevent efficient price signals and the fact that energy prices are prevented from rising to VOLL and other market design imperfections.

(55) The combination of these market failures and associated regulatory action may tend to ‘dampen’ price signals in electricity markets so that prices fail to increase to an ‘efficient’ level at times of scarcity. This leads to a chronic shortage of revenues for plant operators and demand response operators, so that ability to recover their fixed and variable costs is affected, usually referred as the ‘missing money’, preventing market forces from achieving the required level of adequacy.

(56) In theory, the inability of consumers to select their desired level of reliability could be addressed in an energy-only market by allowing prices to rise to a regulatory level reflecting the price at which consumers would no longer be willing to pay for energy and allowing generators to receive scarcity rents. However, as a consequence of low demand response, it is difficult to capture the actual VOLL and price spikes face issues of political acceptability.

(57) According to the Belgian authorities, a second market failure results from the risk aversion of investors in a context of increased volatility and high regulatory uncertainty. The increasing penetration of intermittent renewable energy sources makes prices more volatile and increases the uncertainty on the possibility for conventional technologies to recover their fixed costs in the electricity market. According to Belgium, slight variations of conditions related to the level of the introduction of RES, e.g. targets regarding solar, onshore wind and offshore wind, could have significant impact on the revenues of conventional generation technologies. The ‘missing money’ problem is becoming more severe as the intermittent capacity increases. As a result, according to the Belgian authorities, this increases the economic risk associated with investments in flexible conventional generation technologies. In addition, according to Belgium, energy prices usually do not provide for a more than three-year forward hedging horizon, which is short to build an investment case for investors. Besides, according to the Belgian authorities, even though forward markets could accommodate incremental changes in supply and demand, they would not be able to provide a hedge in case of an important structural shock, such as the planned nuclear phase-out in Belgium.

(58) Third, the reliability of electricity systems has certain features of a public good. This is because investments for a higher level of security of supply benefit all, while, as explained earlier, it is not possible for most individual final consumers to be selectively disconnected by the system operator on the basis of their willingness to pay. Thus, generators will likely have suboptimal incentives to invest in generation capacity, which would therefore ultimately deliver suboptimal levels of system reliability.

(59) According to the Belgian authorities, these issues take a particular form in Belgium, insofar as it is a relatively small and highly interconnected market and thus is also affected by similar supply risks from neighbouring electricity markets. Therefore, according to the Belgian authorities, Belgium’s adequacy is largely influenced by the situation in the neighbouring electricity markets.

(60) In 2018, the Commission approved a strategic reserve for Belgium until 31 March 2022 (33). The objective of the strategic reserve is to meet peak demand during winter periods when the market fails to do so, by maintaining some existing generation and demand response capacity out-of-market as a back-up only to be activated when the balancing resources are exhausted.

2.3.4. Market reforms

(61) On 25 November 2019, the Commission received an implementation plan (34) from the Belgian Ministry of Energy prepared pursuant to Article 20(3) of the Electricity Regulation, which requires Member States with adequacy concerns to set out measures to eliminate regulatory distortions or market failures on their markets in an implementation plan. Following a public consultation, the Commission adopted on 30 April 2020 an opinion on Belgium’s implementation plan, pursuant to Article 20(5) of the Electricity Regulation (35). Belgium adopted and submitted to the Commission a final version of its implementation plan (36).

(62) As regards balancing markets, Belgium has introduced a so-called ‘alpha component’ in its imbalance pricing mechanism. It constitutes an extra imbalance price component laid upon Balance Responsible Parties (‘BRPs’) to increase the real-time price signal when the system imbalance of the Belgian control zone increases. In its Opinion, the Commission invited Belgium to consider whether the scarcity pricing function should apply not only to BRPs but also to balancing service providers (‘BSPs’). This may support security of supply by ensuring that BRPs and BSPs face the same price for the energy produced/consumed, as price differentiation may result in inefficient arbitrage from market players. The Commission also considers that the scarcity pricing function should be triggered by the scarcity of reserves in the system and it should be calibrated to increase balancing energy prices to the VOLL when the system runs out of reserves. The Commission invited Belgium to consider amending its scarcity pricing scheme accordingly by no later than 1 January 2022. Moreover, Belgium is implementing imbalance netting, as well as preparing for joining the EU balancing platforms for aFRR (automatic Frequency Restoration Reserve) and mFRR (manual Frequency Restoration Reserves) which are expected to be in place by end 2021 and 2022 respectively. Besides, Belgium has committed to the following concerning the procurement of balancing and ancillary services: (a) no later than July 2020, FCR (frequency containment reserves) had to be tendered on a daily basis and procured exclusively regionally. (b) no later than July 2020, aFRR had to be tendered on a daily basis and all technologies, all players and all voltage levels will be able to participate in the market. Activated balancing energy shall be remunerated through marginal pricing as soon as there will be sufficient liquidity. (c) since February 2020, mFRR is dimensioned and sized on a daily basis, and activated balancing energy is remunerated through marginal pricing.

(63) In the annual report, submitted by Belgium in July 2021, it is confirmed that these actions have taken place in the meantime.

(64) In Belgium, demand side response is eligible to participate in the wholesale electricity markets (including day-ahead and intra-day) as well as the balancing market and is treated in a similar way as other market participants and balancing service providers. Demand side response can be represented either individually or via aggregators. To further facilitate demand side response, Belgium committed in its implementation plan (submitted in 2019) to a roll-out of smart meters which will be different for each of its regions: (a) Flanders (37): (1) no later than 2023, 33 % of customers shall have a smart meter. (2) no later than 2028, 66 % of customers in Flanders shall have a smart meter. (3) no later than 2034, 100 % of customers in Flanders shall have a smart meter. (b) Wallonia: (1) no later than 1 January 2023, there will be a systematic roll out of smart meters (i) for residential consumers in default of payment, (ii) when the meter has to be changed, (iii) for new connections to the grid, (iv) when the consumer requests it. (2) no later than 31 December 2029, there will be 80 % of smart meter installed for (i) consumers with a consumption equal or above 6 000 kWh, (ii) prosumers, when the net developable electrical power is equal or above 5 kWe; (iii) for charging points open to the public. (c) Brussels Region: smart meters rolled out (i) when meters have to be changed or (ii) for new connections to the grid.

(65) Belgium had an electricity interconnection rate of 21 % in 2020. With the projects already planned (see Federal Development Plan 2020-2030 (38)), the Belgium electricity interconnection rate will reach around 30 % by 2030 (39). The following Belgian network reinforcements recently became or will become operational in the coming years: (a) ALEGrO: the ALEGrO project of common interest (PCI) for a 1 GW interconnector between Belgium and Germany was commissioned in 2020 (40). (b) NEMO: the NEMO PCI project for a 1 GW interconnector between Belgium and the United Kingdom has been operational since 2019. (c) BRABO: the BRABO PCI project concerns an upgrade of the Belgian electricity grid with the aim to, among others, increase the import capacity from the Netherlands.

2.4. Beneficiaries

2.4.1. Eligibility

(66) The CRM will be open to all capacities that can contribute to resource adequacy, both existing and new capacity, storage and demand response. Aggregation of capacity, including from different technologies will be allowed.

(67) Participation of foreign capacity will also be allowed. The rules are further described in section 2.10.

(68) The beneficiaries of the CRM will be the capacity providers selected in the competitive bidding process.

2.4.2. Minimum threshold for participation

(69) The minimum participation threshold has been set at 1 MW, notably for the following reasons: (a) alignment with the balancing market; (b) the value is the result of a continuous dialogue with market participants, including several formal public consultations; (c) going below the 1 MW-limit implies that many small capacities must start the compulsory CRM prequalification process and face the related costs even though they may have no intention to participate in the CRM auction; (d) going below the 1 MW threshold also increases significantly the administrative burden.

(70) The Royal Decree on eligibility criteria related to cumulative support and minimal participation threshold foresees to evaluate the level of the minimum participation threshold during the lifetime of the CRM, at least every 5 years.

(71) Aggregation rules enable participation of smaller capacity providers that do not meet the minimum threshold requirement.

2.4.3. Aggregation

(72) Multiple capacity providers can choose to aggregate into a single capacity market unit of minimum 1 MW without maximum size limitation. The only limitation is that delivery points for which the energy markets daily programs apply (typically today delivery points with a size of above 25 MW) cannot be part of an aggregated portfolio. Aggregation is allowed across all technologies. In addition, the reallocation of components within an aggregated capacity market unit (‘CMU’) is allowed to increase the flexibility towards aggregators and to encourage their participation in the auction process.

(73) Aggregation rules will be periodically reviewed and modified if deemed necessary by the Belgian authorities, in order to ensure that the aggregation rules do not constitute an obstacle to the participation in the auction.

2.4.4. Unproven capacity

(74) A specific category of ‘unproven capacity’ is foreseen in the mechanism. It is defined as a capacity, which, at the start of the Y-4 prequalification process, cannot be associated to a delivery point and therefore cannot respect the delivery point prequalification requirements. The category is open to all technologies and aims at fostering the participation of capacities which may have more difficulties to already provide the standard required maturity level in Y-4. Unproven capacities represent less mature projects, e.g. when the delivery point is not known yet; no project execution plan is available and the project only matures further during the pre-delivery period. The Belgian authorities explained that the concept of ‘unproven capacity’ was introduced at the request of the market and might particularly be of use to aggregators/DSR providers, which consider being able to find such a capacity over the pre-delivery period, but e.g. still have to finalise agreements with demand sites/are considering multiple prospects. An unproven capacity should only be offered in Y-4 auction. This category can only be assigned the standard capacity category of 1-year contract (see recitals (138) and (145)).

(75) To limit the risk to system security by relying on less mature projects, the overall capacity to be accepted in this category is limited to 200 MW for the first auction. The Electricity Act foresees that a decision on this maximum overall capacity is taken per auction. The threshold could further evolve over time based on a positive return of experience.

2.4.5. De-rating

2.4.5.1. General rules

(76) The CRM is open to all capacity holders in function of their availability rate and their contribution to the objective of resource adequacy. Indeed, CMUs are not expected to be available 100 % of the time at 100 % of their reference power due to e.g. weather conditions, maintenance cycles, breakdowns.

(77) For this reason, a de-rating factor is calculated for every technology in order to assess its reliability and its contribution to the security of supply during moments that are particularly relevant from an adequacy point of view (so called ‘simulated scarcity hours’). Capacity holders can therefore only participate in the auction and are thus only eligible for capacity contracts up to their de-rated capacity (41).

(78) The methodology to calculate these de-rating parameters differs per technology and is specified more in detail in the Royal Decree, which sets out the methodology for the capacity calculation and auction parameters. It will depend on the category of capacity: (a) de-rating factors for thermal technologies with a daily schedule are determined based on statistical analysis from historical data by undercutting the forced outage rate as this parameter is assumed independent from climatic conditions. (b) de-rating factors for thermal technologies without a daily schedule are determined by measurements. If measurements are insufficient they are simulated by dividing the expected average contribution of those technologies during the simulated scarcity hours by the aggregated nominal reference power of the technology. (c) de-rating factors for weather dependant technologies with a daily schedule and for the weather dependent technologies without a daily schedule that have not chosen a service level agreement (see point e) below) will be determined by dividing the associated average contribution from those technologies during simulated scarcity hours by the aggregated nominal reference power of the applicable technology. (d) de-rating factors for technology with a daily schedule which are energy-limited will be determined by dividing the expected average contribution of such technologies during simulated scarcity hours by the aggregated nominal reference power. (e) service level agreement (‘SLA’) (typically demand response or small storage but it is also accessible to all technologies without a daily schedule, including RES): the de-rating factor is associated to each SLA selected by the CMU itself during the pre-qualification process (and as fixed in the capacity contract) depending on the selected energy constraints. This allows the technologies without a daily schedule to determine for themselves which SLA suits best their technical constraints, rather than putting them into a pre-defined SLA. In addition, an aggregator can choose a SLA which best fits his portfolio.

(79) On 4 May 2021, Belgium provided updated de-rating factors illustrated in the table below: Table 4 De-rating factors Service Level Agreement (SLA) Availability/Duration [h] SLA Large-scale storage 1 h 11 % 11 % 2 h 19 % 19 % 3 h 28 % 28 % 4 h 36 % 36 % 6 h 52 % 52 % 8 h 65 % 65 % Thermal technologies with a daily schedule Subcategory De-rating factor Combined cycle gas turbine 91 % Open cycle gas turbine 90 % Turbojets 96 % Gas engines 95 % Diesel engines 93 % CHP 93 % Biomass 93 % Waste 93 % Nuclear 96 % Coal 90 % Energy-limited technologies with a daily schedule Availability/Duration [h] De-rating factor 1 11 % 2 19 % 3 28 % 4 36 % 5 -6 52 % 7 -8 65 % Weather-dependent technologies Subcategory De-rating factor Offshore wind 15 % Onshore wind 6 % Solar 4 % Hydro Run-of-River 34 % Thermal technologies without a daily programme Subcategory De-rating factor Aggregated thermal technologies 62 % Source: Notification (42)

(80) The de-rating rules can be reviewed yearly and modified if needed. In particular, the TSO will consult upon the list of current technologies existing in the market. If feedback would be received that a new type of technology is missing in the list, this could still be taken into account during the yearly calibration of the de-rating factors. Hence, if needed, the de-rating factors and the technologies will be updated yearly and reviewed.

2.4.6. Rules applicable to cross-border participation

(81) As regard cross-border participation, the maximum entry capacity available for the participation of indirect foreign capacity in a control zone shall be defined by the system operator for each directly electrically connected market zone to the Belgian control area, in accordance with Article 26 of the Electricity Regulation.

(82) Pending the adoption of the relevant strategies, proposals or decisions implementing Article 26 of the Electricity Regulation, the contribution of each market zone directly connected with Belgium is determined by the contribution of those zones during simulated scarcity hours as described in section 2.10.1.

2.4.7. Rules applicable to unproven capacity

(83) To guarantee a level playing field with other contracted capacities in Y-4 auction, Elia will use the de-rating factors known at the moment of the Y-4 auction as an input parameter for the standard prequalification process of unproven capacities (as the standard prequalification process related to those capacities can be organized up to 24 month after the Y-4 auction).

2.5. Auction process and pricing rules

2.5.1. Auctions frequency

(84) According to the notification, the TSO will organise CRM auctions in function of the level of capacity resources that are needed to guarantee an adequate level of resource adequacy to reach the reliability standard.

(85) A capacity auction is held every year for delivery in 4 years’ time in a ‘Y-4 auction’. A further year-ahead auction is held in the year immediately prior to the delivery year of the main auction (‘Y-1 auction’). The first Y-4 auction is planned to be organised in 2021, while the first Y-1 auction should take place in 2024.

2.5.2. Determination of the volume to be auctioned

(86) In an earlier version of the Electricity Act, Article 7 undecies paragraph 2 provided that the methodology defining the parameters determining the quantity of capacity to be purchased was proposed by the TSO. Under the Electricity Regulation, which is applicable since 1 January 2020, the Member State shall approve the volume to auction on the basis of a proposal from the regulator CREG. The CRM committee (FPS Economy, CREG, Elia and the Cabinet of the Energy Minister) therefore decided in 2019 already that the CREG would develop a proposal for the methodology for the parameters determining the volume to be procured in the auctions. The following recitals give more details on the chronology.

(87) On 22 November 2019, Elia elaborated a draft proposal of a Royal Decree for the determination of the methodology for the auction parameters (such as de-rating factors, strike and reference prices, intermediate price cap), including the process to determine the scenario to determine the capacity needed (43). On 6 December 2019, the CREG adopted an opinion (44) on Elia’s proposal in which it notably explains that the use of the EU-HiLo scenario to determine the capacity to be purchased is inappropriate (45) and not in line with Article 24(1) of the Electricity Regulation.

(88) On 18 March 2020, the CREG sent a draft proposal 2064 for the determination of the volume of capacity to be procured to the Belgian Minister of Energy. The draft proposal was largely inspired by the CREG’s note (Z) 2024, which was sent to the Minister on 20 December 2019 after a public consultation (46). The CREG adopted the final proposal on 24 March 2020 (47). The proposal: (a) derives a budgetary constraint in which the cost of the CRM must be lower than the cost to the consumer due to the expected non-delivered energy (EENS) (48) which is avoided by a CRM. The cost of CRM is the cost of the capacity requested to comply with the reliability standard. The expected cost of missing energy is the EENS multiplied by the willingness to pay for customers who unintentionally do not receive this energy (VOLL). In the event of a security of supply risk, this VOLL represents the cost of non-supply announced in advance. Using values of VOLL of the Plan bureau (49) and of a study by ACER (50), the CREG derives the following budgetary constraint: Source: CREG ‘Proposition (E)2064 – 24 mars 2020’ (b) derives the following demand curve, where the targeted volume to be auctioned is C-Q (51): Source: CREG ‘Proposition (E)2064 – 24 mars 2020’

(89) Taking into account the results of the public consultation on the CREG note 2024, the Belgian Ministry of Energy concluded that the methodology proposed by the CREG (especially the budgetary constraint) did not provide sufficient guarantees that the CRM objective to ‘ensure the required level of security of supply’, would be respected in accordance with the legal criteria.

(90) Consequently, the Belgian Ministry of Energy drew up an alternative method defining the parameters determining the quantity of capacity purchased under the capacity mechanism, taking into account Elia’s proposal of a Royal Decree mentioned in recital (87) and the CREG’s proposal mentioned in recital (88). A public consultation was held on this adapted methodology from 23 March 2020 to 27 March 2020. Pursuant to the Amended CRM Law, the adapted Article 7 undecies, paragraph 2 of the Electricity Act provides that the parameters defining the amount of volume to be procured shall be defined in a Royal Decree, on the basis of a proposal from the regulator. The final Royal Decree was published in the Belgian Official Gazette on 30 April 2021, following the approval of the Amended CRM Law (52). Recitals (91) to (99) describe the process as provided for in this final Royal Decree.

(91) Each year, the amount of capacity required to meet the reliability standard in a particular future delivery year (i.e. the target volume) will be determined based on a proposal from the regulator. The regulator makes this proposal taking into account data provided by the TSO, but also this data is calculated by the TSO on the basis of a scenario and intermediate values that have been proposed by the regulator and have been determined by the Minister. The target volume is determined on the basis of the legal reliability standard, which corresponds to a certain LOLE value. A scenario is calibrated to ensure that this criterion is met. Once the scenario is calibrated, a market simulation is carried out and leads to the identification of simulated scarcity hours. The target volume is then calculated as the sum of the mean load during the simulated scarcity hours and the balancing need, from which the average EENS during the simulated scarcity hours is subtracted.

(92) The scenario mentioned in recital (91) will be one of the central reference scenarios used to identify the resource adequacy concern, either from the latest ERAA (53) or from the latest NRAA (54), and will be updated with the most recent information available (55). The process for finalising the amount of capacity to procure also needs to respect the relevant parts of the Electricity Regulation.

(93) The Royal Decree provides the following process in order to establish the reference scenario. As input for the decision by the Minister of Energy, the Belgian TSO will publish a recommendation, after public consultation of the market parties on the data and assumptions. Consecutively, the regulator will make a proposal on the reference scenario, taking into account the methodology as foreseen in the Royal Decree. Finally, the FPS Economy will publish an advice on this proposal. The final decision of the scenario choice is the responsibility of the Minister of Energy.

(94) A global auction cap determines the maximum remuneration that can be received by a bid in the CRM auction and is applicable to all capacity categories. By limiting the maximum remuneration that can be received, the global auction cap limits the possibility for abusing market power by submitting inappropriate bids. The global auction price cap is calculated as the multiplication of the net-CONE (56) by a factor X. The value of the correction factor X takes into account the uncertainties related to the estimation of the net-CONE, both at the level of the gross cost variability of a new entrant associated with different technologies and in the determination of the annual infra-marginal annuities in the energy market and the net revenues on the market for auxiliary balancing services. The global auction price cap for the first auction is equal to EUR 75/kW/year, which is equal to the net-CONE multiplied with a correction factor of 1,50 (57).

(95) The demand curve for the Y-4 auctions is designed on the basis of 3 points, as shown in Figure 1 below:

(96) The demand curve for the Y-1 auctions is designed on the basis of the same points B and C as for Y-4 auctions, but the target volume is adjusted to take into account capacity already contracted in the Y-4 auction corresponding to the same delivery period. Point A corresponds, in ordinate to the global auction price cap, and in abscissa, to the target volume.

(97) The Belgian authorities consider that the design of the demand curves respects two principles: (a) ensuring security of supply: this means that once Y-4 and Y-1 auctions have been concluded the reliability standard should be met, otherwise the CRM would not meet its objective. As point B corresponds to the volume required to meet the reliability standard it should be ensured that at least this volume is contracted. As after a Y-4 auction, there is still the opportunity to contract further capacities in the Y-1 auction, a sloped curve between point A and point B in Y-4 is possible, allowing to contract less than the amount calibrated for point B in that Y-4 auction. However, contracting less than the volume associated to point B in Y-1 would not guarantee that the reliability standard is met. This explains the vertical section in Y-1 between point A and point B; and (b) ensuring a proportionate, least-cost mechanism: this means that overall the volume to be procured should not exceed the volume required for meeting the reliability standard as otherwise this would inflate the mechanism’s total cost. This explains why the demand curve is vertical between point B and the intersection with the X-axis both in Y-4 and Y-1 auctions.

(98) According to the Electricity Act, a minimum volume of capacity needs to be reserved for Y-1 auctions and be deducted from the target volume for the Y-4 auction. This reserved volume shall be at least equal to the capacity required, on average, to cover the total peak capacity for less than 200 hours of operation per year. According to the Royal Decree to determine the methodology for the capacity calculation and auction parameters in the context of the capacity remuneration mechanism, the capacity necessary to cover the total peak capacity for less than 200 hours on average shall be determined, for each block of 100 MW, by the average number of hours required to comply with the security of supply criterion based on the load duration curve. These are the hours needed by certain capacity needs to meet the maximum electricity consumption. The estimation of the demand curve resulted in the reservation of approximately 2,5 GW for the Y-1 auction foreseen in 2024. According to Belgium, the decision to reserve part of the volume to be procured for the Y-1 auction process reflects its willingness to stress the technical-neutrality and technical openness of the mechanism. This measure encourages the participation of demand response providers as it might be more difficult for these capacities to plan their availability long in advance, possibly complicating their participation in the Y-4 auction. Notwithstanding this shift of capacity volume to the Y-1 auction, all capacity holders are allowed to participate in both the Y-4 and Y-1 auction process for a certain delivery period.

(99) Anticipating the implementation of the final draft Royal Decree: (a) Elia launched a public consultation on the scenarios, sensitivities and data for the CRM parameter calculation for the Y-4 auction for delivery period 2025-2026. The public consultation was held between 5 May 2020 and 5 June 2020 (59). Elia consulted on the data from ENTSO-E’s MAF 2019, updated with the most recent available information from public sources and on sensitivities to be included in the reference scenario that can have an impact on the security of supply of Belgium, in accordance with the Royal Decree (see recital (93)). After the public consultation, Elia recommended integrating into the reference scenario a ‘low demand’ sensitivity and a sensitivity corresponding to the EU-HiLo scenario (60) (see recital (30)). On 10 July 2020, the CREG subsequently adopted a proposal of a reference scenario (61), in which it notably reiterates its criticisms against Elia’s recommendation to include a sensitivity of a reduction of the availability of French nuclear by 4 units (see recital (87)), pointing also to the existing capacity mechanism in France to ensure adequacy and to the risk of an increase in the capacity to be procured. However, shortly after, the Directorate-General for Energy of the FPS Economy adopted an advice to the Minister of Energy (62), in which it recommends integrating in the reference scenario a modification of the expected demand as the latter dropped subsequent to the impact of the Covid-19 outbreak. It also included an additional unavailability of nuclear units in France. Thus, the Directorate-General of Energy of the FPS Economy rejected most of CREG’s criticisms but still invited Elia to review its analysis in light of what the PLEF has done (see recital (35)). (b) The CREG organised as public consultation from 1 July 2020 to 13 July 2020 on a proposal about the values of the gross CONE, the weighted average cost of capital (WACC) and the correction factor X (63). The Minister of Energy decides yearly on the basis of the CREG’s proposal but can depart from it.

(100) The demand curve for the Y-4 auction in October 2021 is based on the central scenario of the MAF 2019, with updated data and corrections based on the ‘Generation Adequacy Assessment’ performed by the PLEF and published in April 2020 (see also recitals (287) to (289)).

(101) 2021 Adequacy and Flexibility study uses the central scenario of the MAF 2020, complemented with the most recent dataset available for each country and collected within ENTSO-E and public information or updated national studies for other countries. According to Belgium, by using the same source (MAF) as dataset for both the resource adequacy assessments and the demand curve calibration, coherence is insured.

(102) Belgium clarified that the sensitivity used in the calculations of the demand curve for the first auction about the unavailability of the French nuclear capacity (in line with the ‘Generation Adequacy Assessment’ performed by the PLEF) has also been modelled in the 2021 Adequacy and Flexibility study.

(103) The estimated volume to be procured in the first Y-4 and Y-1 auctions is around 9,5 GW. The overall volume is defined per auction and it based on the methodology described in section 2.5.2. In the demand curve for the Y-4 auction, the Belgian authorities have set aside a significant volume for the Y-1 auction, ensuring that a new calibration will take place closer to the delivery year and avoiding that too much capacity would be auctioned in the first Y-4 auction. This large Y-1 reservation allows the Belgian authorities to cope with slight deviations following new input data and methodological improvements, but also ensures that new and innovative technologies are given ample possibilities to participate, thus ensuring in practice the technological neutrality of the measure.

(104) Overall, about 54 % of the average peak consumption at scarcity moments will be contracted in the Y-4 auction in 2021, thus reducing the targeted volume to what is strictly required.

(105) Belgium committed to cross-check and adjust if need be the volumes to be procured in T-4 auction in 2023 and T-1 auction in 2026 with the results from the NRAA 2023.

2.5.3. Pre-qualification phase

(106) A mandatory pre-qualification procedure is applicable to all holders of generation capacity above 1 MW. Nevertheless, prequalified capacities are not obliged to participate in the bidding process (opt-out). To facilitate this mandatory prequalification, a fast track prequalification process is foreseen to enable capacity holders to meet the prequalification obligation at a minimum effort (only a minimum quantity of information is required, such as an identification number, type of delivery point and total installed capacity): capacity holders after a fast track pre-qualification process, the capacity is automatically treated as opt-out.

(107) The pre-qualification requirements include an emission limit: capacity providers that exceed the emission limit below cannot participate in the capacity auction: (a) for capacities that started production on or after 4 July 2019 an emission limit of 550 gr CO2 of fossil fuel origin per kWh of electricity applies; (b) capacities that started production before 4 July 2019 can neither emit more than 550 gr CO2 of fossil fuel origin per kWh of electricity, nor more than 350 kg CO2 of fuel origin on average per year per installed kWe.

(108) Further, as part of the pre-qualification process, the candidates have to deliver a provisional financial security in order to be allowed to participate in the auction. This provisional financial security becomes effective when the CMU is selected in the auction. If the capacity provider, after selection in the auction, does not respect its contractual obligations or in case he is not willing to sign the capacity contract, financial penalties will be applied as part of the pre-delivery control process. The contractual counterparty has the right to claim financial security in case these penalties would remain unpaid. At the moment of prequalification, the amount of the provisional financial security will be 20 000 EUR/MW for virtual and additional CMUs and 10 000 EUR/MW for existing CMUs, in function of the CMU’s eligible volume (given that the contracted capacity is not known yet and ensuring that the financial security is proportional to the size of the project and the consequent risk to system in case of not delivering). If the final contracted capacity of the CMU is lower than its eligible volume, the amount of the financial security is lowered for the positive difference between the eligible volume and the contracted capacity, multiplied by EUR 20 000 (for virtual and additional CMUs) or EUR 10 000 EUR (for existing CMUs).

(109) In addition, parties wishing to apply for pre-qualification for new installations (for a 15-year capacity contract) fired with fossil fuels must recognise that obtaining a capacity contract does not exempt them from current and future legislation and objectives established by the European Union and/or Belgium to reduce greenhouse gas emissions. In addition, they must acknowledge that obtaining a capacity contract commits them to contribute to policy preparation to achieve these objectives. To this end, they need to attach a written declaration in which they undertake to: (a) study the technical and economic feasibility of reducing greenhouse gas emissions, in accordance with relevant European and Belgian legislation and targets, of the installation concerned by 31 December 2026; (b) establish, by 31 December 2027, an emission reduction plan indicating how they will contribute to the transition to climate neutrality in 2050, with interim targets for the years 2035 and 2045; and (c) achieve zero or negative emissions by 2050. The parties involved in the establishment of an emission reduction plan may decide to carry out this study jointly.

(110) Compliance with the commitments set out in recital (109) must be demonstrated to the Directorate-General for Energy of the FPS Economy.

2.5.4. Specific auction design features

2.5.4.1. Pricing rule

(111) The competitive auction mechanism makes use of the sealed bid auction format where bidders anonymously submit bids and the market is subsequently cleared in one single round. According to the Belgian authorities, by not providing information to the market during market clearing and not allowing bidders to update their bids, the sealed bid auction format limits the potential for market power abuse. They also indicate that with the sealed bid process, unlike in descending clock auctions, bidders are not tied up for (typically) 2-3 days in which they have to be available to react on the information that is made available for the auction process. The less complex and time-consuming auction process could further lower the entry barrier, especially relevant for new and small players and for demand side response parties whose core business is not the energy market.

(112) All successful bidders will be awarded a capacity remuneration, based on the pay-as-bid pricing rule for all auctions related to at least the initial two delivery periods (Y-4 and Y-1 auctions for delivery periods starting in November 2025 and November 2026). In other words, successful capacity providers will receive their bidding price as capacity remuneration.

(113) Following the presentation to the Parliament of an evaluation report, the pay-as-cleared pricing rule could apply for auctions related to subsequent delivery periods. Under the pay-as-cleared rule, the capacity remuneration equals the bid price of the most expensive bid selected (with the limitation of the intermediate price cap, see section 2.5.4.2).

(114) The Belgian authorities believes that the adequacy situation in Belgium around 2025 will require new capacity (see recital (29)). Therefore, capacity holders presenting very heterogeneous cost structures will probably compete in the initial CRM auctions. Consequently, the Belgian authorities fear that some capacity providers could benefit from high inframarginal CRM rents and hence windfall profits if the pay-as-cleared pricing rule is applied. According to Belgium, in theory, in case of perfect information when market participants can anticipate the would-be market clearing price under pay-as-cleared, a pay-as-bid pricing rule would result in the same outcome, as bidders have an incentive to bid in at this anticipated clearing price. In practice however, a certain degree of uncertainty and unpredictability related to the potential pay-as-cleared market price is inevitably associated with the first CRM auctions. Therefore, under a pay-as-bid pricing rule, market players may act more prudently to avoid the risk of not being selected, and hence pay-as-bid may lead to a less costly result.

(115) However, Belgium considers that the cost-efficiency advantage of pay-as-bid auctions likely diminishes over time, not only because the requirement for new capacity might disappear, but also because recurring pay-as-bid auctions allow market participants to better anticipate the reference market clearing price, resulting in a ‘flat’ offer curve. Besides, in case the missing money issue were to disappear in the medium to long-term, pay-as-bid could prevent the price to tend to zero since capacity providers have no incentive to bid in at zero under the pay-as-bid pricing rule.

(116) Belgium considers that after subsequent auctions, the pay-as-cleared pricing rule might become the better choice in order to stimulate competition, provide a transparent price signal and allow capacity remunerations to tend to zero when the level of capacity supplied is expected to be adequate to meet the level of capacity demanded. An important feature of the pay-as-cleared pricing rule is that the rational bidding behaviour is to bid in at true costs. Besides, as pay-as-cleared pricing provides a transparent price signal towards the market, this information can be particularly valuable to small units and new market players, as it may give them a better idea about current and future expected market conditions, thereby encouraging participation over time. Additionally, the pay-as-cleared pricing rule facilitates contractual arrangements, especially for aggregations. Therefore, Belgium will foresee a procedure allowing to change to the pay-as-cleared pricing rule when it is shown that it is beneficial to do so.

2.5.4.2. Intermediate price cap

(117) As described in detail in section 2.6, a CMU that requires significant investments can apply for a multi-year capacity contract. For the time being, this rule does not apply to indirect foreign participation, which can only receive a one-year contract (see recitals (143) and (144)). According to the Belgian authorities, CMUs within the one-year contract category are confronted with no or low investment cost requirements to cover for (otherwise they would qualify for a multi-year contract). Therefore, it is foreseen to apply an intermediate price cap to CMUs in the one-year contract category, to avoid windfall profits. This rule will also apply to the contracts attributed to indirect foreign capacity (see in detail in section 2.10.1).

(118) The CMUs within the one-year contract category will not be allowed to bid at a price higher than the intermediate price cap. Furthermore, even under the pay-as-cleared rule (see recital (113)), these CMUs would not receive capacity payments higher than the intermediate price cap.

(119) According to the Belgian authorities, the intermediate price cap will also prevent market actors with significant market power from strategically deciding to mothball or close existing capacity, thereby effectively taking capacity out of the market, influencing the market clearing price. By limiting the maximum capacity remunerations for capacities in the 1-year contract capacity category (among which existing assets), the intermediate price cap would limit the potential for excessive inframarginal rents.

(120) The Belgian authorities indicate that the intermediate price cap, on the one hand, should be sufficiently low to avoid windfall profits, but, on the other hand, it should not be too low as to prevent normal returns for the investors, or even prevent CMUs from participating in the CRM auction and create an unwanted exit signal.

(121) The methodology described in the Royal Decree setting out the methodology for calculating the auction parameters under the capacity remuneration mechanism determines that the intermediate price cap shall be calibrated to the expected ‘missing-money’ level of the worst performing technology currently in the market, considering both costs and revenues.

(122) The following costs are taken into account: (a) yearly Fixed Operation and Maintenance (‘FOM’) costs; (b) annualized non-yearly maintenance costs (excluding costs related to a capacity augmentation or lifetime extension of an installation); (c) activation costs for an availability test.

(123) These cost components are divided by the applicable de-rating factors, as the intermediate price cap applies in the auction in which prices are expressed per de-rated MW. The Belgian authorities provided the data presented in Table 5 below (64). Table 5 Total yearly costs for a short-list of existing technologies (65) Yearly FOM costs [EUR/kW/year] Activation cost for availability test [EUR/kW/year] De-rating factor (66) LOW MID HIGH CCGT 29 30 41 0 91 % OCGT 19 19 40 0 90 % Turbojet 23 29 29 0 96 % Market response 5 10 15 0,18 36 % Source: Notification

(124) The following yearly revenues are taken into account: (a) yearly infra-marginal rents earned on the electricity market; (b) yearly net revenues from the provision of frequency-related balancing services.

(125) The Belgian authorities provided the data presented in Table 6 below: Table 6 Total yearly revenues for a short-list of existing technologies (67) Total yearly revenues [EUR/kW/year] (68) LOW MID HIGH CCGT 5 11 20 OCGT 10,2 12,6 15,5 Turbojet 19,3 23,2 27 Market response 14,3 17,1 20 Source: Notification

(126) Finally, ‘missing-money’ is calculated by subtracting the yearly revenue from the yearly cost values. A 5 % uncertainty margin is added to the derived number, to take into account general uncertainties that are associated with a ‘missing-money’ estimation, especially given that the calibration of the intermediate price cap requires the generalisation of cost and revenue figures per technology and that this estimation takes place up to several years before the relevant delivery period.

(127) The Belgian authorities provided the data in Table 7. The different ‘levels’ for the value for ‘missing-money’ represent the following categorisation: level 1 considers low cost figures and high revenue figures; level 2 considers low cost figures and mid revenue figures; level 3 considers low cost figures and low revenue figures; level 4 considers mid cost figures and high revenue figures; level 5 considers mid cost figures and mid revenue figures; level 6 considers mid cost figures and low revenue figures. Table 7 ‘Missing-money’ values derived for a short-list of existing technologies (69) ‘Missing-money’ [EUR/kWde-rated/year] Level 1 Level 2 Level 3 Level 4 Level 5 Level 6 CCGT 10,4 20,8 27,7 11,5 21,9 28,8 OCGT 4,1 7,5 10,3 4,1 7,5 10,3 Turbojet 0 0 4 2,2 6,4 10,6 Market response 0 0 0 0 0 0 Source: Notification

(128) On the basis of the input and data provided by Elia, and the advice on these data by the regulator, the Belgian authorities have set the intermediate price cap for the first auction, i.e. the Y-4 auction with a delivery period November 2025-October 2026, at EUR 20/kWde-rated/year.

(129) During the formal investigation procedure, Belgium put in place a mechanism allowing for an individual derogation from the intermediate price cap (70).

(130) The derogation mechanism has been introduced in the Royal Decree to determine the methodology for the capacity calculation and auction parameters in the context of the CRM. The derogation mechanism applies equally to both national and indirect cross-border capacities.

(131) Based on the Royal Decree, for the first auction, due to the limited time between the design of the derogation mechanism and the preparation of the first auction, the derogation will be granted ex-post, i.e. after the closure of the auction. Belgium explained that potential beneficiaries will apply for derogation before the auctions and submit all relevant information before the auctions. All criteria and rules for the derogation will be transparently established before the auctions. The derogation will not depend on the submitted bids of any auction participant. Finally, if ex-post it is concluded that some units do not qualify for derogation and their payments are reduced, this does not affect the outcome (contract, payment and quantity awarded) for other units that participated in the auction.

2.5.4.3. Clearing rules

(132) The capacity auction should be cleared by selecting the combination of bids that maximizes social welfare, taking into account the demand curve (set in an administrative way) and offer curve (by aggregating the different bids of the capacity holders) and by taking into account the volume and price components of the different bids. Social welfare in this context is calculated as the sum of consumer surplus (surplus for society from satisfying the demand for security of supply at a price below the willingness-to-pay for capacity as defined by the demand curve) and the producer surplus (surplus for capacity providers from the selection of their bids at a price above the bidding price).

(133) If multiple clearing solutions (i.e. a combination of bids) are equivalent in terms of maximizing economic surplus, the solution with the lowest CO2 emissions is selected. If two solutions are equivalent both in terms of maximizing economic surplus and weighted average CO2 emissions, the solution with the lowest weighted average contract duration is selected with the goal to limit the lock-in over several years (71).

(134) The auction algorithm will also take into account grid constraints, in such a way that it will reject certain combinations of bids which are together not grid feasible. The set of grid constraints related to the TSO grid that will apply during the auction clearing, will be determined before the auction clearing takes place and will be driven by either system security considerations, or physical spacing limitations.

2.6. Contract duration

(135) According to the Belgian authorities, a longer capacity contract duration allows the capacity provider to secure long-term funding to spread the investment costs over a longer period of time. This could reduce the capacity remuneration required per year and help ensure that a new project is competitive against existing projects in the market. The potential for new entry at a competitive price is also of the utmost importance for controlling the market power of existing capacity providers.

(136) However, a longer capacity contract duration can also ‘lock-in’ a technology in the energy market for a longer period of time. Therefore, the Belgian State has opted for different capacity categories (1 year, up to 3, 8 and 15 years). Consequently, new investments are not immediately granted a capacity contract for the maximum (15 years) period, thereby avoiding that the future energy market would be locked for new (and potentially more environmentally friendly) technologies.

(137) In the Royal Decree of 12 December 2019 (72) proposed by CREG, the eligible costs are established as: ‘initial and non-recurrent investment expenditure, which is ordered from the date of publication of the auction results in which the bid for that capacity is retained and carried out at the latest on the day preceding the first day of the capacity provision period, necessary for the construction and/or the provision of the essential physical technical elements of capacity, and for the purpose of offering to the Belgian market additional capacity, as of the first delivery period covered by the capacity contract’. For existing capacity, expenditure which has the effect of offering additional capacity is: (i) expenditure made necessary to enable the capacity to comply with environmental standards and thus to maintain it on the market; (ii) expenditure necessary to increase the installed capacity or the technical lifetime of the installation and (iii) for direct foreign capacity, expenditure necessary to connect the unit to a network within the Belgian control area (see section 2.10.2).

(138) The proposed Royal Decree foresees the thresholds presented in Table 8. These investment thresholds have been calculated so as to ensure that the average estimated annualized investment costs are equal between the capacity categories linked to a maximum capacity contract duration of 15, 8 and 3 years. The CREG will propose to update the investment thresholds when it seems necessary and at least every 3 years (73). The thresholds take into account the installed capacity rather than the de-rated capacity. According to Belgium, in case the de-rated capacity offered by the CMU instead of the installed capacity would be taken into account for the investment thresholds, capacities with a high de-rating factor would reach the investment thresholds for multi-year contracts more easily, which would be contradictory to the CRM objective. Table 8 Investment thresholds for long-term capacity remuneration contracts Contract duration Thresholds proposed by CREG New proposal from Belgian Government Years €/kW €/kW 15 600 360 8 400 239 3 177 106 Source: SPF Economie

(139) The CREG will monitor the investment costs to ensure, both ex ante and ex post unit’s submission, that the capacity category assigned to each capacity provider is appropriate. In particular, the capacity provider has to provide an ex post investment file that the regulator can use for its ex-post assessment of the assigned capacity category. If the ex post analysis reveals that the cost criteria were not met (including a limited tolerance range to account for small uncertainties), contractual conditions could be revised (e.g. reclassification of the CMU in the appropriated category of contract). Additionally, in case the ex-post investment file is not provided (on time), reclassification of the CMU in the 1-year capacity category by the regulator is possible as well.

(140) According to the initial proposal, a contract category is also assigned to aggregated offers. If an aggregated offer is made of capacities corresponding to different contract categories, the aggregated offer is assigned the contract category corresponding to the capacity with the shortest contract category.

(141) This proposal was revised after the formal investigation procedure. Based on the Royal Decree setting the investment thresholds, the eligibility criteria for investment costs and the ranking procedure, every capacity that is part of an aggregated offer is classified in a capacity category. On the basis of the classification of capacities, the CREG determines, where appropriate, its different classification combinations and links each combination to a maximum nominal reference power corresponding to the sum of the nominal reference capacities of the capacities of the aggregated offer, which are classified in a capacity category that is equal to or higher than the specified capacity category. Based on this, the manager of the aggregated offer chooses the capacity category that applies to the aggregated offer.

(142) Following the formal investigation procedure, Belgium also amended the provisions of the Royal Decree regarding eligible investment costs. The amended Royal Decree states that only costs to adapt to future Union standards will be eligible under the CRM.

(143) According to the Belgian authorities, the possibility for multi-year contracts cannot be foreseen for foreign capacity as, in the long-term, sufficient entry capacity cannot always be guaranteed. The latter does not only depend on the level of interconnection and its availability, but also on the risk of concurrent system stress with neighbouring countries. This latter risk may vary significantly over time, depending on the adequacy and market situation in other countries.

(144) The Belgian authorities committed however to review the possibility for foreign capacities to access multi-year contracts. The first review will be carried out by 15 January 2023 and thereafter every 2 years. If the review shows that the risks related to the level and availability of the interconnector and the risk of stress of the simultaneous system are adequately mitigated, so that contracts of more than one year for indirect foreign capacity do not create unreasonable risks to adequacy, multi-year contracts for foreign capacities may be granted.

(145) Finally, unproven capacity can only be eligible to a one-year capacity contract, because it is difficult to justify precise cost figures that would allow them to be categorised in one of the multi-year contract categories (see section 2.4.4).

2.7. Obligations

2.7.1. Reliability options

(146) In the Belgian capacity mechanism, the contractual counterparty buys the capacity from the capacity providers in the form of reliability options. The capacity providers that are selected in the auction sell the reliability options to the central buyer and receive a fixed capacity remuneration in return. Whenever the reference price exceeds a pre-defined level, the so-called strike price, the capacity provider has a payback obligation of the difference between the reference price and the strike price towards the central buyer, calculated on the contracted capacity volumes.

(147) As a result, revenues for the capacity provider on the energy only market are capped at the strike price, but capacity providers are ensured a fixed and certain capacity remuneration in return. In other words, the capacity providers give up part of their uncertain scarcity rents to receive a certain capacity remuneration in return, significantly reducing the risk of volatile revenues and therefore the risks related to the investment to be made. The reliability option objective is twofold. Primarily, the payback obligation limits the potential for windfall profits and secondarily, incentivises CMUs to be available in moments relevant for security of supply.

2.7.2. Reference price

(148) Belgium has selected the day-ahead market (DAM) price as reference price. According to Belgium, its main advantages are: (a) the DAM represents the most pertinent market signal related to adequacy issues as most drivers of the market actors’ positions are incorporated in the production planning and forecasts; (b) the DAM has a strong signalling function and represents the strongest, most liquid spot market, because of its granularity and the high accuracy of the assumptions, which is reflected in the exchanged volumes; (c) after the day-ahead matching in the Belgian system, all Balancing Responsible Parties have to be balanced (nomination DA at 15h00) and at that unique moment, the market is settled. In this way, the DAM is the last opportunity in the electricity product timeline to cross the full remaining demands and offers after the forward market and before the flexibility needs of the intraday and balancing; (d) due to its timing position in the spot markets, it should allow all technologies (e.g. also slow capacity) to react upon.

(149) Belgium explained that the methodology of the reference price may be reviewed in the future to make sure it sends the most adequate price signal, once the maturity of other spot markets will increase to a level close to the day-ahead market. In particular, intraday market prices may be considered again once the liquidity is sufficient and it is continuous.

(150) Belgium has opted for a single strike price with some corrections to ensure technology openness of the system and limiting windfall profits in the calibration. According to the Belgian authorities, these corrections are necessary to limit the risk of a single strike price for the participation of some technologies to the CRM. Particularly technologies with a short run marginal cost above the strike price may be hindered without these corrections.

(151) As foreseen in Article 7 undecies paragraph 2 of the Electricity Act, the strike price parameter will be calibrated each year by a Ministerial Decree no later than 31 March of that year (both for the Y-4 and Y-1 auction) and based on the methodology that is set in the Royal Decree for the auction parameters.

(152) It will be based on an analysis of the aggregated curves gathering the elastic part of the volume of reaction from the market observed on the DAM weighted over a period of 3 years for the relevant periods during these 3 years (winter weekdays). The methodology indicates that the calibrated strike price should be selected between the corresponding range [75 %; 85 %] of the price-elastic volume of reaction from the market reacting to it and taking into account a number of guiding principles: (a) first criterion: the short run marginal costs (SRMC) of the technologies with daily schedule should be covered by the selected strike price; (b) second criterion: the strike price calibration takes the calibration curve shape into account; (c) third criterion: the strike price calibration takes the energy market evolution into account; (d) fourth criterion: strike price stability in time; and (e) fifth criterion: a reasonable chance for the strike price to be reached by the reference price.

(153) For the assessment of the first criterion, this is looked at in the light of the results and hypotheses used in the 2019 Adequacy and Flexibility study, especially in sections 2.9.3 and 2.9.4. The calculation of these SRMC is based on several assumptions: an estimation of the fuel prices, an estimation of the potential evolution of the CO2 price, an estimation of the performance (‘efficiency’) of the various technologies considered in the 2019 Adequacy and Flexibility study (in this case CCGT, OCGT and diesel generator).

(154) Belgium proposed an indicative calibrated strike price range based on the last 3 winter periods (winter 2016/2017 to winter 2018/2019) to be narrowed to [320; 500] EUR/MWh.

(155) This implies that the strike price may evolve over time (but remains fixed for a CMU’s capacity contract duration), in line with evolutions on the energy market, and that capacity contracts as a result of one auction do not necessarily include the same strike price as capacity contracts related to another auction. In any case, the capacity providers will be informed of the applicable strike price prior to each auction, allowing them to factor in this information into their bids.

(156) In addition, Belgium has opted to offer CMUs without individual scheduling obligation (demand side response providers and aggregators typically fall into this category) the possibility to replace the one single strike price by their declared market price (i.e. their short run marginal cost) in the pay-back obligation whenever this would be higher than the one single strike price. In other words, these CMUs without individual scheduling obligation (and thus demand response providers) are only subject to the payback obligation in case the reference price exceeds their declared market price (DMP), representing the price above which these capacity providers have declared to deliver energy in the energy market. In other words, in case the single strike price calibration would result in a price below their activation cost, these CMUs are not obliged to pay back revenues that were not received in the energy market (in case the reference price would exceed the strike price, but would be below their declared market price). This measure was introduced after the public consultation process to mitigate the concern of demand response providers and other parties that they otherwise would face more difficulty in participating as they may be subject to paybacks without being dispatched and having earned the revenues in the first place. According to Belgium, it also ensures a technology-openness while limiting the windfall profits. In particular, according to the authorities this design element should explicitly facilitate the participation of demand-response in the CRM and any other technology with higher short run marginal costs.

(157) Additionally, CMUs without individual scheduling obligation can decide to declare several day-ahead prices as DMP. This is particularly relevant for aggregators, which may have a portfolio composed of CMUs with different marginal prices and reflect their actual cost curve. This is meant to avoid applying the payback obligation on energy that has not been sold on the market and where no revenue was earned.

2.7.3. Paybacks

2.7.3.1. Description

(158) Whenever the electricity price on the wholesale day-ahead market exceeds the strike price, the capacity provider has to pay the difference between the reference price and the strike price to Elia, calculated on the contracted capacity volumes. As a result, revenues for the capacity provider on the energy only market are capped at the strike price, but capacity providers are ensured a fixed and certain capacity remuneration in return.

(159) The capacity provider will be subject to the payback obligation, irrespective of whether it was selling electricity at high prices during the relevant settlement period.

(160) It is important to add that the reliability option is designed in such a way that planned and unplanned outages of the assets duly communicated in advance are exempted from this payback obligation to the extent of the unavailability. Indeed, the payback obligation aims to avoid windfall profits by reimbursing unanticipated revenues from the energy market. However, in case of outages (both planned and unplanned), no energy is delivered. As a consequence, in case of (duly communicated) outages, it is impossible for the capacity provider to capture the higher energy revenues resulting from the high price spikes, so therefore no pay-back obligation should be applicable in these circumstances.

(161) Demand side response units and other capacity without a daily schedule obligation are subject to the payback obligation in case the reference price exceeds their declared market price (see recital (156)).

(162) The Belgian authorities committed to carry out a technical and economic analysis which will examine the bids and the results of the auctions, with a particular focus on the effect of the payback obligation. The analysis will be carried out every 2 years, starting after the first auction in spring 2022. The results of the analysis will be submitted for a public consultation.

2.7.3.2. Stop-Loss Mechanisms

(163) Belgium will also implement a stop-loss mechanism on both the payback obligation (linked to the reliability options) and the penalties for unavailability, which are applied cumulatively (see section 2.8.4).

(164) Such stop-loss mechanism implies that the capacity provider under the CRM will never have to repay an amount exceeding the value of its annual capacity remuneration. In other words, in case the contract value is reduced to zero, there is no payment obligation (not for the reliability options, nor for the availability payments). This principle implies a useful risk limitation for the capacity provider, allowing zero bids in case the ‘missing-money’ in the energy market is reduced to zero. On the contrary, without such a stop-loss mechanism, the capacity provider would risk to be subject to a payback obligation and/or a penalty, even in case it would have no missing-money and a capacity contract value of EUR 0. To cover this risk, a capacity provider would never bid at EUR 0/MW/year (even in case he would have no missing-money) without the implementation of this stop-loss mechanism.

2.8. Availability monitoring, testing and penalties

2.8.1. Pre-delivery control

(165) During the pre-delivery period (i.e. the period after a CMU is selected in the auction but before the start of the delivery period), the selected capacity providers are subject to a set of requirements to ensure that their contracted capacity will be available at the start of the delivery period and contribute to security of supply. They are notably meant to mitigate the gaming risk and cover the uncertainty inherent to new investments (e.g. delay in construction works).

(166) A conditional financial security is required to ensure the requested and punctual fulfilment of all the obligations in respect of the pre-delivery controls arising from the Capacity Contract and/or the Rules on the Functioning of the CRM Market Rules (see recital (108)). In case of non-respect of a Capacity Provider’s obligations during a pre-delivery period, the financial security can be invoked.

(167) For existing CMUs, pre-delivery availability tests will be organized, to which penalties apply in case of non-compliance. Furthermore, for additional and virtual CMUs, additional obligations and monitoring requirements between Y-4 and the delivery period are foreseen. The pre-delivery monitoring of these new capacities will be based on the detailed project planning provided by the capacity provider. In case the capacity provider does not meet the milestones set in the project planning, resulting in a residual delay, penalties will apply, including financial penalties (covered by the financial security), or in some cases the reduction of the initially contracted capacity (and thus the capacity remuneration per year) and/or reduction of the capacity contract duration (and thus the number of years during which a capacity remuneration will be received).

2.8.2. Availability Monitoring

(168) The Belgian TSO ensures the availability of all the contracted CMUs (taking into account de-rating) to reach the targeted level of security of supply. Given that the main objective of the CRM is to ensure an adequate level of capacity in the system, the availability monitoring takes place during moments that are relevant for security of supply. In this respect, an Availability Monitoring Trigger (AMT) is defined to identify the moments relevant from an adequacy point of view and during which the TSO will monitor the availability of CMUs.

(169) The AMT is based on the day-ahead market price. The reasons for opting for the day-ahead market price are the same as for the payback obligation, as described in section 2.7.2. During AMT moments (i.e. moments during which the day-ahead market price exceeds the AMT), the TSO can verify whether the procured capacity is indeed able to respond to a day-ahead market signal. If the capacity does not meet the obligated capacity (74) (based on the terms and conditions in the capacity contract and the functioning rules), the part of the obligation that was not available is liable to penalties, unless the CMU can cover the positive difference between obligated capacity and available capacity (75) via the secondary market of the CRM (see section 2.9). By selling obligations on the secondary market, the capacity provider can effectively reduce the obligated capacity to avoid a discrepancy between the obligated and available capacity and thus penalties.

(170) For the calculation of the obligated capacity, a distinction is made between energy-constrained and non-energy constrained assets as they contribute to the security of supply in a different way. An energy-constrained asset (e.g. batteries, demand side response) can only be available during a certain number of consecutive hours, whereas these constraints do not apply for the non-constrained assets.

(171) For non-energy constrained assets (e.g. thermal installations, wind farms), the duration of the AMT moment (expressed in a number of hours) does not affect the available capacity. On average, these assets should be able to deliver at least their de-rated capacity. Therefore, at every AMT hour during the capacity contract, the obligated capacity equals the de-rated capacity of the asset as determined during the pre-qualification phase.

(172) Given that energy-constrained assets (e.g. batteries, demand side response) can only be available during a certain number of consecutive hours, during the prequalification phase these CMUs can select a certain Service Level Agreement (SLA). Therefore, the obligated capacity equals their non-de-rated capacity for hours within their energy constraints. The obligated capacity will equal 0 MW for any other AMT hour in the same day. The CMU retains the liberty to dispatch their asset for any AMT moment of a set of AMT hours they chose as long as they have delivered at least their SLA over all AMT hours of a day.

(173) Capacity providers with a daily schedule obligation in the energy market are presumed to have an available capacity at each AMT hour of maximum power (Pmax) available (76).

(174) On the other hand, there is less visibility on the actual availability for capacity providers without such a scheduling obligation. Therefore, these latter capacity providers are always obliged to communicate before day-ahead market closure, a day-ahead price above which they would deliver energy to the market with the CMU in accordance with at least the obligated capacity, which can be above the AMT price. If the market clearing occurs below this price, the unit is presumed to be available (but not delivering energy) according to a declaration. In case of a market clearing above the declared day-ahead price, the TSO will verify energy delivery. In this way, the monitoring does not impose the delivery of energy during all AMT moments, only in case market conditions are favourable for the CMU (i.e. the declared day-ahead price).

(175) Optionally, the capacity provider without a scheduling obligation can also declare other prices to indicate delivery on other markets (intraday or balancing markets) and/or for lower volumes. This is meant to reflect market functioning as part of the energy can be sold closer to real-time. The TSO will monitor availability using the price that corresponds to when the energy was delivered. In case the declared price(s) are never surpassed on their respective market(s), the asset will not be sufficiently visible in the market and will consequently be more prone to testing. The Rules on the Functioning of the CRM will include a right for the TSO to request a certain number of tests during a delivery period (see section 2.8.3).

(176) According to Belgium there are two main drivers for a capacity provider to declare correct prices for their CMUs, as regards the pay-back obligation and the availability monitoring: (a) successful dispatching of the CMU in response to a declared price contributes to the credibility of the unit’s capability to respond to the market. As stated before, this will reduce the chance of availability tests. The costs associated to these tests are borne by the capacity provider (see recital (181)) which creates an incentive to show availability through the declared prices mechanism; (b) during AMT hours with a payback obligation, the CMU’s dispatching will be checked in accordance with the capacity provider declared prices. In other words, the TSO should be able to measure the communicated volume to be delivered as well as the margin to be retained. As an example: if a CMU has indicated that, based on resulting market prices, they would dispatch energy at 90 % of the contracted capacity, 90 % delivery should be measured as well as 10 % margin compared to the technical limit. The result of not respecting either the energy delivery or margin that was communicated will result in availability penalties. This avoids false declaration of prices to omit the payback obligation. Outside of payback obligation AMT hours, such checks will not be made as there is no such potential gain for the capacity provider.

2.8.3. Testing

(177) Elia can verify the availability of a CMU through unannounced availability tests. Such tests will be notified by Elia to the capacity provider between 15:00 CET and 15:30 CET the day before the availability test at the latest, i.e. the same moment at which the identification of AMT hours is communicated.

(178) Elia can test a CMU up to three times successfully during the winter period and one time successfully outside the winter period. Additionally, Elia reserves the right to test at maximum one time the full duration of the SLA (if any) successfully. Elia will not conduct availability tests in a period where they have prior knowledge of planned unavailability for the concerning CMU on the (part of the) capacity which is not available (i.e. the obligated capacity is limited to what is known to be available).

(179) Elia will select the CMU’s to be tested according to an internal procedure, which will not be disclosed publicly. Nevertheless, Elia shall base its procedure on criteria including, but not limited to: (a) the amount of proven availability of the CMU’s relative to all other CMUs subject to a capacity contract for the current delivery period; (b) previously failed availability tests by the CMU; (c) missing capacity during availability monitoring; (d) correlation of the CMU’s outputs with the declared market prices.

(180) When Elia notifies the availability test along with its expected duration (full SLA duration or 1 quarter-hour) to the capacity provider, it shall also contain its start and end time. Within that period, the capacity provider has the freedom to organise the energy delivery as it suits him best.

(181) Any missing capacity during this period is liable to an availability penalty. Any costs of availability tests are borne by the capacity provider.

2.8.4. Penalties

(182) Any missing capacity, i.e. a positive difference between obligated and available capacity, during an AMT hour is liable to an availability penalty.

(183) The total amount of availability penalties a capacity provider can receive for one CMU, for one delivery period and for missing capacity holding a primary market obligation or a secondary market transaction of which the transaction period covers at least one complete delivery period, is limited to the awarded selected bid prices in the auctions for the delivery period multiplied with the contracted capacities in the auctions.

(184) The total amount of availability penalties a capacity provider can receive for one CMU, for 1 month and for missing capacity stemming from a primary market obligation or a secondary market transaction of which the transaction period covers at least one complete delivery period, is limited to 20 % of the awarded selected bid prices in the auctions for the delivery period multiplied with the contracted capacities in the auctions.

(185) In case missing capacity over 20 % of obligated capacity is established during three separate AMT moments and/or availability tests for the same CMU, Elia issues a downwards revision of the capacity remuneration for that CMU proportional to the maximum missing capacity established during that period. The capacity provider however retains an availability obligation and remains liable to possible availability penalties for that CMU as in the original capacity contract. The total contract value is not altered. The original capacity remuneration is reinstated after the CMU has successfully provided its obligated capacity, corresponding to the contracted capacity and SLA in the primary contract, during three consecutive AMT moments or availability tests.

(186) In case the CMU was subject to a downwards revision of capacity remuneration during two subsequent