COMMISSION DECISION (EU) 2020/348

of 24 October 2019

on the aid scheme SA.35980 – 2019/C United Kingdom – Electricity Market Reform: Capacity Mechanism

(notified under document C(2019) 7610)

(Only the English text 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 given notice to the parties concerned to submit their comments pursuant to those Articles (1) and having regard to their comments,

Whereas:

1. PROCEDURE

(1) Following pre-notification contacts, the United Kingdom (UK) authorities notified to the Commission on 23 June 2014, in accordance with Article 108(3) of the Treaty, of a proposed measure to support capacity providers in the electricity market in Great Britain (‘GB’) (2). That measure is referred to in this Decision as ‘the measure’.

(2) On 23 July 2014, the Commission decided not to raise objections to the aid scheme establishing the measure on the ground that the scheme fell within point (c) of Article 107(3) of the Treaty and was therefore compatible with the internal market (3) (‘the 2014 Decision’).

(3) The first auction in the capacity market to which the measure relates (‘the Capacity Market’ or ‘CM’) took place on 16-18 December 2014. The auction was for delivery of capacity four years later, i.e. in 2018.

(4) On 15 November 2018, the General Court of the European Union annulled the 2014 Decision, in its judgment in Case T-793/14 – Tempus Energy and Tempus Energy Technology v Commission (‘the GC judgment’). In summary, the General Court considered that, based on the length and circumstances of the pre-notification phase and the lack of appropriate investigation by the Commission at the preliminary examination stage with regard to some aspects of the Capacity Market, more specifically with regard to the role and treatment of demand side response in the notified capacity mechanism, the Commission should have had doubts as to the compatibility of the measure with the internal market. Those doubts should have led it to initiate the procedure provided for in Article 108(2) of the Treaty, thereby allowing interested parties to submit their observations to the Commission and to put the relevant information at its disposal so that it would be better able to assess the Capacity Market’s compatibility with the internal market.

(5) Additional information was received from the UK on 20 December 2018.

(6) On 25 January 2019, the Commission appealed the GC judgment (Case C-57/19). As the appeal does not have suspensive effect, in order to comply with the GC judgment, the Commission reassessed the CM.

(7) Following that reassessment, the Commission informed the UK, by letter dated 21 February 2019, that it had decided to initiate the procedure laid down in Article 108(2) of the Treaty in respect of the measure.

(8) The Commission decision to initiate the procedure (‘the Opening Decision’) was published in the Official Journal of the European Union (4). The Commission called on interested parties to submit their comments.

(9) The UK sent its comments on the Opening Decision to the Commission by letter dated 12 April 2019. The Commission received comments from 35 interested parties. It forwarded them to the UK and gave the UK the opportunity to react. The Commission received the UK’s comments in response by letters dated 7 June 2019, 19 July 2019 and 12 September 2019.

(10) On 29 March 2017, the United Kingdom submitted the notification of its intention to withdraw from the Union pursuant to Article 50 of the Treaty on European Union (TEU). In accordance with Article 50(3) TEU, the Treaties are to cease to apply to the withdrawing State from the date of entry into force of a withdrawal agreement or, failing that, two years after the notification, unless the European Council, in agreement with the Member State concerned, unanimously decides to extend this period. The period has been extended twice, last time by European Council Decision (EU) 2019/584 (5), which extended it until 31 October 2019.

(11) On 11 January 2019, by Decision (EU) 2019/274 (6), the Council authorised the signature of the withdrawal agreement agreed at negotiators’ level on 14 November 2018. On 17 October 2019, the European Council endorsed the revised Withdrawal Agreement agreed at negotiators’ level. On 21 October, the Council, on a proposal from the Commission (7), amended Decision (EU) 2019/274 so as to authorise the signature of the revised Agreement. The Union re-confirmed that it stands ready to proceed swiftly with its signature and conclusion in the event that the United Kingdom Parliament approves the withdrawal agreement. Part Four of the withdrawal agreement provides for a transition period starting on the date of entry into force of the agreement, during which Union law is to continue to apply to and in the United Kingdom as laid down therein.

(12) In any event, this Decision applies only as long as Union law applies to and in the United Kingdom.

2. DETAILED DESCRIPTION OF THE MEASURE

2.1. Overview of the measure

(13) In 2014, the UK estimated that the electricity market in GB would reach critical levels of generation adequacy around 2017/2018. The UK therefore designed the measure as a capacity market where the System Operator would organise centrally-managed auctions to procure the level of capacity required to ensure generation adequacy.

(14) The auctions organised under the measure were initially open only to existing and new generators, demand side response (DSR) operators and storage operators. Interconnectors were permitted to participate as from the second auction in 2015.

(15) Bidders who are successful in the auctions are awarded capacity agreements under which they will receive a steady payment for the duration of the capacity agreement in return for a commitment to deliver electricity at times of system stress if called upon to do so by the System Operator. Financial penalties apply if the capacity provider does not deliver the amount of energy required in accordance with its according to its capacity commitment. The measure is financed through a levy on electricity suppliers.

(16) The first auction was organised in 2014 for delivery of capacity in 2018. It was followed by three further four-year ahead (‘T-4’) auctions (in 2015, 2016 and 2017), one one year-ahead (‘T-1’) auction (in 2017), and two transitional auctions (‘TAs’) in 2016 and 2017).

(17) The UK suspended the measure on 15 November 2018 following the GC judgment, mentioned in recital 4 and currently under appeal. The UK confirmed that no further aid would be granted through auctions in the Capacity Market and that payments for the aid granted through the auctions that had already taken place had been halted pending a decision by the Commission to approve the measure.

(18) Nevertheless, following the GC’s judgment, the UK did put in place the following measures: (a) A replacement T-1 top-up auction for delivery of capacity in the 2019/20 delivery year was held in June 2019, as a result of which conditional capacity agreements were awarded which were conditional on the State aid approval being obtained and on the necessary procedural steps being taken under the legislation establishing the Capacity Market; (b) Compliance with capacity agreements awarded in previous auctions was still enforced so that, subject to a positive State aid decision, deferred capacity payments could be made to capacity providers who had complied with their obligations during the standstill period; (c) Electricity suppliers were to continue passing on the levy to consumers during the standstill period to ensure they would be in a position to pay outstanding supplier charges in respect of the standstill period fully and promptly if State aid approval were granted; and (d) Prequalification procedures were launched on 22 July 2019 for a T-1 auction (delivery year 2020/2021), a T-3 auction (delivery year 2022/2023) and a T-4 auction (delivery year 2023/2024), each of which was due to take place in the first quarter of 2020.

2.2. Legal basis and government arrangements

(19) The legal basis for the measure is the UK Energy Act 2013. Secondary legislation in the form of the Electricity Capacity Regulations 2014, the Electricity Capacity (Supplier Payments etc.) Regulations 2014 and the Capacity Market Rules governs implementation of the measure.

(20) The UK regularly reviews the CM mechanism in the light of feedback received from each auction process. It has also conducted a number of public consultations to make incremental improvements to the regulatory detail of certain specific features of the scheme. The energy regulator (Ofgem) also annually gathers stakeholder views on potential changes to the operational and administrative features of the scheme and makes amendments to the rules. In addition, a more formal and comprehensive review is scheduled to take place every five years, involving both the government and Ofgem, to assess the extent to which the Capacity Market effectively delivers on its objectives and remains the most effective form of intervention to address those objectives. The objectives include considering underlying market failures. In essence, the review consists of the following two stages: (a) Ofgem carries out five-year reviews of those areas of the Capacity Market design that are covered in the Capacity Market Rules, looking at the effectiveness of the scheme and whether its existing arrangements are fit for purpose, and (b) the Government assesses the Capacity Market and its objectives from a more high-level perspective and addresses the question of whether the Capacity Market is still needed in the future or should be phased out and the extent to which the objectives of the Capacity Market could be achieved in way that imposes less regulation. This is informed by the Government’s annual internal consideration of whether to run the Capacity Market auction as well as the findings of Ofgem’s first stage review. The Government carries out public consultations as part of this review process.

(21) The UK Government initiated the first five-year review process by publishing a Call for Evidence in August 2018, thus inviting views and evidence at a high level on issues such as whether there is a continuing need for the CM, and the identification of any priority areas where changes should be made. In September 2018, Ofgem published an Open Letter asking for views and evidence on whether the Rules continue to meet their objectives. The final report of the UK’s government five-year review was published on 22 July 2019 (8), while Ofgem’s final report was published on 31 July 2019 (9). Besides, the Science and Technology Committee of the UK’s House of Commons published a report on 22 August 2019 mentioning, among other themes, the GB Capacity Market (10).

(22) The measure is implemented by the UK Government, Ofgem, the Delivery Body (National Grid – ‘NG’), the Settlement Body (a new institution created under the Energy Act 2013, subject to government direction and oversight) and the settlement service provider (Elexon). A brief high-level description of their roles and responsibilities is set out below.

(23) The UK Government is responsible for the strategic oversight of the Capacity Market and for changes to the Regulations governing the scheme and to ensure continued accountability for key aspects of the Capacity Market design. The Regulations include for example general eligibility criteria for entry to Capacity Market auctions, functions of the System Operator for delivery of the Capacity Market, and the settlement of payments.

(24) The UK Government designed the Capacity Market Rules, but Ofgem is responsible for implementing them (both the UK Government and Ofgem may amend the Rules). The Capacity Market Rules include technical rules and procedures concerning pre-qualification and capacity auctions, the contents of capacity agreements and the obligations of capacity agreement holders. When considering changes to the Rules, Ofgem is bound by a set of objectives enshrined in the Regulations and the Rules, which ensures transparency and confidence in the governance of the Capacity Market. Ofgem is also responsible for the resolution of disputes raised by applicants about the outcome of pre-qualification.

(25) The System Operator is the National Grid. It undertakes the delivery role for the Capacity Market, including: providing advice to Ministers on the security of supply outlook and recommending the amount of capacity to auction in order to meet the reliability standard; pre-qualifying auction participants, administering the capacity auctions and issuing the contracts (so-called ‘capacity agreements’) with the successful bidders; developing and administering new supporting procedures such as the provision of Capacity Market warnings.

(26) The UK Government sets out the delivery functions of the System Operator in secondary legislation, which are ‘relevant requirements’ enforceable by Ofgem. This gives the Government certainty about what will be delivered and a clear basis for Ofgem to manage NG’s performance in its delivery role. A panel of technical experts provides independent scrutiny of NG’s advice on the recommended amount of capacity to auction.

(27) The UK Government set up (11) the Capacity Market Settlement Body (‘the Electricity Settlement Company’) to provide ultimate accountability, governance and control of the settlement process and payments disbursed under capacity agreements (12). The Settlement Body is a private company limited by shares owned by the Government as the sole shareholder (13). It is responsible for setting its own internal governance so that it is able to meet its obligations, but the Government has retained overall control over it (14).

(28) The UK Government announced the decision to contract functions out to Elexon Ltd. through the Official Journal of the European Union in February 2013. Elexon operates as the settlement service provider, with responsibilities for carrying out calculations and determinations of capacity payments. Elexon’s role as settlement service provider is similar but more limited than the role it currently has under the Balancing and Settlement Code. A contract between the Settlement Body and Elexon outlines the details of the service to be delivered, the cost of that service and performance monitoring arrangements.

2.3. Beneficiaries

2.3.1. Eligibility

(29) Capacity providers participate in the Capacity Market on the basis of ‘Capacity Market Units’ (CMUs). It is at the CMU level that pre-qualification applications are made, capacity agreements are awarded, the obligations which apply in times of system stress are specified and penalties/over-delivery payments are calculated. Generators (both existing and new), interconnectors, storage providers and DSR providers are able to participate.

(30) Generating units (defined by reference to providing electricity, being capable of independent control, net output measured by half hourly meter(s), connection capacity in excess of 2 MW) may participate individually as a single CMU or aggregate with other eligible generating units under the following conditions: (a) the units all form part of the same Trading Unit (i.e. power station); or (b) all the units are connected to the system at the same Boundary Point; that is the same site, but the Trading Unit concept does not apply; or (c) the aggregate capacity of all the units is between the minimum (2 MW) threshold and 50 MW (effectively embedded generation spread across several sites).

(31) DSR CMUs are defined by reference to a commitment to reduce demand. A DSR provider is defined as being (i) an electricity customer directly; (ii) an entity owning the electricity customer; or (iii) an entity having contractual DSR control over the electricity customer. The commitment must cause the electricity customer to reduce its import of electricity (as measured by half hourly meters) and/or to export electricity generated by on-site generating units owned by the electricity customer. DSR providers can participate individually as a single CMU or aggregate with others. In addition, each component must be connected to a half hourly meter and the provider’s total DSR capacity must be between 2 MW and 50 MW. Table 1 below shows the results of DSR performance in the auctions held before July 2019. Table 1 DSR performance in the capacity auctions held before July 2019 Entered auction (MW) Won agreements (MW) 2014 T-4 603 174 2015 T-4 673 456 2016 T-4 1 798 1 411 2017 T-4 2 246 1 206 2018 T-4 (15) (susp.) 2 618 N/A 2017 T-1 1 283 443 2018 T-1 (susp.) 2 124 N/A 2019 T-1 (conditional) 1 333 203 2015 TA 619 475 2016 TA 373 312

(32) The Capacity Market excludes capacity providers already in receipt of support from other measures. The following providers are not eligible to participate in the Capacity Market: (a) Low-carbon generating plants receiving support through the Contracts for Difference (CfDs) or the small scale Feed-In-Tariff; (b) Renewable generators receiving support through the Renewables Obligation (RO), unless they choose to forego receiving RO payments (they are allowed to participate once their RO contracts expire); (c) Plants in receipt of the Renewable Heat Incentive (RHI) – this is because the RHI has been designed to complement the RO and the CfD for renewables; (d) Plants in receipt of funding from the UK Carbon Capture and Storage (CCS) Commercialisation Competition – because the CfD for CCS has been designed to provide them with the additional support needed to be commercially viable; (e) Technologies in receipt of funding from the EU New Entrants Reserve 300, which aims to support emerging low carbon technologies such as CCS and tidal energy as they are also eligible to receive support under the CfD; (f) Plants which were awarded 15 year contracts by NG to form part of the Short-Term Operating Reserve (‘long term STOR’) immediately prior to the initial Electricity Market Reform (EMR) policy proposals in 2010, and which chose to maintain them.

(33) Companies who have participated in the Enterprise Investment Scheme (EIS) and Venture Capital Trust (VCT) schemes are not precluded from participation in the CM, but are subject to a test to ensure they do not receive ‘double subsidy’ (in order to avoid cumulation of State aid).

(34) While the direct participation of foreign capacities is not authorised, interconnectors have been eligible to participate in the Capacity Market since the second auction held in 2015, as CMUs, on an equal basis with GB-based generators and DSR providers, subject to essentially the same regime of rewards and penalties, and de-rated to reflect their contribution to security of supply (16). Table 2 shows the participation of interconnector CMUs (‘IC CMUs’) in the auctions held to date. Table 2 Interconnector CMU participation in CM auctions to date Auction type T-4 T-1 Auction Year 2015 2016 2017 2018 (susp.) 2018 (susp.) 2019 (condition.) Delivery Year 19/20 20/21 21/22 22/23 19/20 19/20 Number of IC CMUs pre-qualified 3 5 6 8 3 3 Number of IC CMUs successful 2 4 6 NA NA 3 Of which new build 0 0 3 NA NA 1 Of which existing 2 4 3 NA NA 2 Capacity of IC CMUs successful (GW) 1,86 2,34 4,56 NA NA 1,025

(35) In the 2014 Decision, permission was granted to not include interconnected capacity for the first auction (December 2014) due to the following constraints: (a) Capacity to procure: A new methodology to de-rate the interconnector contribution in the auction was needed. Closer cooperation with other Member States on assessing generation adequacy was needed to eliminate potential free riding where countries had different reliability standards. (b) Prequalification: At that point in time, it was not possible for the Delivery Body to independently complete the prequalification stage for a foreign capacity provider. Cooperation with foreign TSOs on measurement and verification, dispatch for testing and data-sharing platforms would have been needed. (c) Auction: The auction would have been open to gaming if foreign capacity had been allowed to participate. A new methodology would have been needed to limit the amount of foreign capacity up to the de-rated capacity of the interconnector. Furthermore the price-taker threshold was likely to be different in another market, meaning that the auction clearing price set in GB might not have been appropriate for capacity in another market and a zonal auction might have been necessary. (d) Delivery: The obligation to deliver requires generators to generate when a 4-hour capacity market warning is called. In another market, this could have resulted in out of merit dispatch, causing market distortion (17). This would have not rendered an additional security of supply benefit to the UK in a world where market coupling is fully implemented with electricity flows already responding to scarcity pricing.

(36) For 2014 only, in the absence of direct participation by interconnected capacity, the expected contribution from interconnection at times of GB system stress was reflected in the amount of capacity auctioned. For example, if 1 GW of imports were expected to be available at times of GB system stress, the amount of capacity auctioned in the Capacity Market would be reduced by 1 GW. The contribution of non-CM interconnection was initially assessed by NG at zero (float) when recommending the T-4 target for the delivery year 2018/19, but this was subsequently revised to a net contribution of 2,1 GW for the T-1 auction.

2.3.2. Pre-qualification process

(37) Participation in the Capacity Market is not mandatory. However, it is mandatory for all licenced, eligible capacity to participate in the pre-qualification process, even if it does not intend to bid. The purpose of the pre-qualification process is to ensure participants in the auction can deliver the capacity they offer, and the System Operator is able to adjust the amount of capacity to auction based on the volume of capacity opting out of the auction.

(38) Any eligible capacity that opts out of the capacity auction is not exposed to Capacity Market penalties for non-delivery, nor are they eligible for any payment for over-delivery. Such capacity is able to opt back into subsequent auctions and can participate in the secondary market. As with ineligible plants, the amount auctioned is reduced to account for the amount of capacity of plants opting out.

(39) To ensure reliable capacity is ready for the delivery year, the System Operator undertakes pre-qualification checks ahead of the auction to confirm the eligibility and bidding status of all potential capacity. Pre-qualification requirements vary for different types of capacity (e.g. for generation and DSR).

(40) As part of their pre-qualification application, applicants have to meet both generic and specific pre-qualification requirements, which vary depending on whether the unit is an existing or prospective generating unit, or a DSR unit. The generic requirements include basic administrative details (contact details, licence status, corporate structure, location and various Directors’ declarations), whilst existing generation units have to also demonstrate their historic performance. Prospective units have to provide evidence of planning consent and connection agreement, a detailed construction plan and details of their expected capital expenditure relative to the duration of the capacity agreement being sought. They are also required to lodge credit support (i.e. collateral, or ‘bid bond’) as an indication of their seriousness to participate in the auction and to deliver an operational unit by the start of the delivery year.

(41) New generation and unproven DSR (as opposed to proven DSR (18)) are required to submit a bid bond of GBP 5 000 (around EUR 5 650) per megawatt for four-year ahead and one year-ahead auctions and of GBP 500 (around EUR 565) per megawatt for transitional auctions. Concerning DSR, the measure provides that the bid bond is forfeited pro rata to the volume of capacity that was not actually supplied by the DSR operators, provided that they provide at least 90 % of the volume of capacity that they had committed to. While DSR operators can aggregate several sites in order to reach the 2 MW minimum threshold, it should be noted that they are liable to pay a bid bond on the whole of the 2 MW, if even only a small proportion of that volume is unproven DSR capacity. According to the UK, a CMU can only be proven as a single unit, proven on the same day in the same settlement period. This requirement to prove as a unit should minimise gaming risk. Otherwise, applicants could prove at different times and put together a unit which might not be able to perform together during a stress event, with resulting security of supply risk.

(42) Following consultation in March 2016, the UK Government raised the pre-auction bid bond for new build generation to GBP 10 000/MW to help fully secure exposure to the increased termination fee liability, as well as to help to deter speculative applications by requiring a greater level of pre-auction commitment. The level of pre-auction bid bond for unproven DSR, however, was left at GBP 5 000/MW following feedback from stakeholders during the consultation that it is comparatively more expensive for DSR aggregators to secure credit cover from lenders.

(43) The System Operator publishes technology specific de-rating factors in advance of the pre-qualification window. For the majority of technology classes, these factors are based on class type historic performance over the previous seven years and represent the average expected contribution of plants at times of system stress on a technology specific basis. A different methodology is used for some classes where historic evidence is either lacking or is less relevant as a robust guide to future performance (e.g. interconnectors or innovative technologies such as battery storage). The relevant factors apply to all plants of a specific technology, irrespective of their age or status. Capacity providers which are successful in the capacity auction receive payments (at the auction clearing price) proportionate to their de-rating factor multiplied by their connection capacity (volume which their physical grid connection permits them to export onto the system). One of the purposes of the penalty regime is to fine tune the level of payments from this estimated performance level to the actual performance level of individual plants.

2.4. The auction process

2.4.1. Establishing the amount of capacity to auction

(44) The decision whether to run the capacity auctions is taken annually and is informed by an independent electricity capacity assessment carried out by the System Operator. Looking 15 years ahead, NG assesses the likely evolution of future capacity margins, the contribution of interconnected capacity and DSR, and recommends the amount of capacity needed to deliver the enduring reliability standard. In this manner, the Government is able to annually assess whether a capacity auction is needed.

(45) The decision on how much capacity to contract in each capacity auction is informed by an enduring reliability standard. A reliability standard is an objective level of security of electricity supply, and is the basis for establishing a demand curve in advance of each capacity auction.

(46) The UK notes that no electricity system can ever be 100 % reliable, and there is always some trade-off between the cost of providing additional back up capacity and the level of reliability achieved. Establishing a reliability standard allows this trade-off to be made as it identifies the point at which additional security benefits are outweighed by the costs of providing capacity. It aims to give investors and market participants clarity over the Government’s long-term security of supply objectives and to help reduce costs to consumers. It also aims to ensure that the Government cannot contract more than the economically efficient level of capacity, which prevents over-procurement of GB capacity.

(47) The UK Government has set an enduring reliability standard for the GB electricity market equal to a loss of load expectation of 3 hours/year. This translates as a system security level of 99,97 %. The loss of load expectation is the number of hours/periods per annum in which, over the long term, it is statistically expected that supply will not meet demand, and which reflects the economically efficient level of capacity. The reliability standard has been established on an enduring basis, but there will be an opportunity for the Government to review it should it prove necessary.

(48) Each year, the System Operator sets out how much capacity is needed to meet the reliability standard and provides advice to the Government by 30 May in an Electricity Capacity Report (ECR). The recommendation on the amount of capacity to contract in the capacity auctions to meet the reliability standard is based on NG’s assessment of different scenarios for the level of electricity demand and the amount of capacity provided by power plants which are not eligible for capacity payments, e.g. low carbon generation, and thus sets out NG’s recommendation on whether, and how much, capacity needs to be secured for the delivery year in question through the CM. NG’s report is scrutinised by an independent Panel of Technical Experts (PTE) who provide advice to Government on the robustness of the analysis and recommendations.

(49) The System Operator uses a range of demand scenarios as well as sensitivities to account for uncertainties in weather, plant availability, interconnector flows and levels of embedded generation. The System Operator then nets off capacity that is not able to participate in the auction (for example low carbon plant receiving other support) and the capacity that has ongoing capacity agreements (e.g. in cases when a capacity provider has a multi-year agreement covering the relevant delivery year).

(50) The System Operator then uses a ‘robust optimisation’ methodology which minimises the worst possible outcome in terms of cost of capacity and unserved demand across the scenarios and sensitivities. The modelling results in a set of options for a single amount to procure and a recommendation.

(51) In the notification of 2014, the UK provided the prediction depicted in Figure 1 for a range in capacity to procure that could be required in the period 2018 to 2030. Figure 2 shows an updated prediction from December 2018. Figure 1 2014 Estimates of the capacity to procure under different scenarios (GW) Figure 2 2018 Estimates of the capacity to procure under different scenarios (GW)

(52) The Government takes the final decision over how much capacity to procure in each auction on the basis of a demand curve, which is derived according to the methodology set out in the recitals below.

(53) The demand curve gives the Government some flexibility on the amount of capacity to contract from year to year depending on cost. The sloping demand curve allows a trade-off to be made between reliability and cost, so that less capacity is procured in a given year if the price is very high. It also helps to mitigate gaming risks because it provides an auction price cap, and flexibility to procure less capacity if the price is high – both of which reduce opportunities for participants to push up prices by exercising market power.

(54) The Government publishes the demand curve in advance of each capacity auction. The demand curve gives the relationship between the price of capacity and the amount of capacity in the auction demanded by the System Operator. Each demand curve is constructed around the target capacity level required to meet the reliability standard indicated by the System Operator and an estimate of the reasonable cost of new capacity (the net cost of new entry or ‘net-CONE’). The intersection of these target capacity and net-CONE fixes one point in the demand curve. Figure 3 below presents an example of the capacity demand curve. Figure 3 Illustrative capacity demand curve Sources: UK authorities.

(55) Net-CONE is determined based on the expected clearing price of capacity in the auction and is revised if necessary for each auction, for instance based on new engineering cost estimates for new build and on information gained in previous auctions. The cost of new entry is based on estimates of the capital cost of new built capacity provided by a report (19) commissioned by the UK authorities assuming a 7,5 % hurdle rate and a 25 year payback period.

(56) Alongside the target capacity level and the net-CONE, other key parameters of the demand curve are: the auction price cap (the maximum price at which Government is willing to procure capacity), the price taker threshold (the maximum price at which existing plants can offer capacity in the auction (20)) and the minimum level of supply needed to hold the auction (a minimum competition requirement). The Government confirms the final auction parameters for each capacity auction just before the relevant pre-qualification window opens.

(57) The auction price cap determines the top of the demand curve – i.e. the price at which no more capacity will be auctioned. The purpose of a price cap is to protect British consumers from unforeseen problems with the auction, such as a lack of competition or abuse of market power by participants. However, according to the UK authorities, setting the auction price cap too low could put off bidders and reduce competition, so it is important that the price cap is set at a level that encourages competition in the capacity auction, and allows the market to set an efficient price for new capacity based on participants’ judgement of the risks and potential returns in the electricity and capacity markets. Getting the level of the price cap right depends on an assessment of the degree of uncertainty around the central estimate of net-CONE.

(58) In 2014, the UK Government set the price cap at the level of GBP 75/kW. The UK explained that this price cap is above the modelled clearing price in the auction under a range of credible scenarios, yet not so high as to allow plants to exercise significant market power if there is limited new build participating. It also acts to ensure that new build cannot seek to recover all its fixed costs in its auction bid – it must take at least some account of energy market revenues and capacity market payments beyond the initial contract length for the project to be viable.

(59) The Government also has a further opportunity ahead of the auction to satisfy itself that there is sufficient competition in the auction. Parties that have prequalified to participate in the auction must commit two weeks ahead of the auction if they will offer capacity into the auction. The Government can then review the list of capacity units that will be participating in the auction – considering for instance the volume of supply offered, the mix of technologies, and the ownership of units being offered – and can cancel the auction if it is not satisfied that the process would be sufficiently competitive to achieve value for consumers.

2.4.2. Auction frequency and format

(60) The capacity auction is held every year for delivery in four years’ time: e.g. the 2014 auction was for delivery in 2018/19, with the delivery year running from 1 October 2018 to 30 September 2019. Since the implementation of the measure in 2014, four four-year ahead auctions have taken place: in 2014, 2015, 2016 and 2017. The four-year ahead auction scheduled for 2018 with the delivery in 2022 was halted by the UK following the annulment of 2014 Commission decision by the GC judgement. To secure the supply in 2022, the UK authorities submitted in December 2018 that, as part of the notified measure, they would exceptionally organise a three-year ahead auction in 2019 (see recital 18(d) above).

(61) A further year-ahead auction is held in the year immediately prior to the delivery year of the main auction. The process for setting the demand curve for this auction is the same as that for the main (four-year ahead) auction – with the final decision taken by the Government based on an analysis provided by the System Operator. The one year ahead auction ensures the right amount of capacity is procured when more accurate demand forecasts are available and is important for enabling DSR capacity (which finds it difficult to participate in an auction four years ahead of delivery) to actively participate in the mechanism. Since the implementation of the measure in 2014, one year-ahead auction took place in early 2018 for delivery year 2018/2019 (21). As mentioned in recital 18(a) above, a replacement and conditional T-1 top-up auction took place in June 2019 for the 2019/20 delivery year

(62) Some capacity is held back from the four-year ahead auction and ‘reserved’ for the year ahead auction. In 2014 and 2015, the amount of reserved capacity was based on an assessment of the amount of the cost-effective DSR that could participate in an auction, and was made public when the demand curve for the four-year ahead auction was published (2,5 GW). A review of the methodology used to determine the T-1 set-aside was carried out by the UK Government in March 2016. Following the review, a new ‘set-aside’ methodology based on the application of a 95 % confidence interval around National Grid’s annual T-4 capacity recommendation set out in the ECR was agreed and has been used since 2016. When modelling the Least Worst Regrets (LWR) process in the ECR, National Grid derives a 95 % confidence interval around the capacity recommendation. Table 3 below presents the volume set-aside for T-1 auctions. Table 3 T-1 set aside and the Capacity to Procure at T-1 (GW) Delivery Year Target to Procure at T-4 auction Capacity set aside for T-1 Target to Procure at T-1 Amount Procured at T-1 auction 2018/19 48,6 2,5 4,9 5,79 2019/20 (conditional auction) 44,7 2,5 2,7 3,68 2020/21 51,7 0,6 N/A N/A 2021/22 49,2 0,4 N/A N/A

(63) If demand falls between the four-year ahead and year ahead auctions, the amount of capacity auctioned in the year ahead auction is reduced. However, because the year ahead auctions provide a better route to market for DSR, in 2014, the UK Government committed to procure in the year ahead auctions at least 50 % of the capacity reserved four years earlier. In the T-1 auction for delivery year 2018/2019, more than double the capacity reserved four years earlier was procured (4,9 GW compared to 2,5 GW originally envisaged) while, in the T-1 conditional auction for delivery year 2019/2020, the target to procure was also higher than the capacity originally set aside (2,7 GW compared to 2,5 GW).

(64) The UK Government expects to run T-4 and T-1 capacity auctions every year, but it is only once prequalification for an auction is completed, when the Government is able to make a final decision about whether to hold a capacity auction.

(65) The UK Government has discretion to cancel or postpone the auction at any point up to the start of the first round of the auction. If the Government does not choose to cancel the auction, the auction will automatically proceed. Once the auction has started, the Government only has discretion to reject the result of the auction if there are reasonable grounds to suspect that NG, as delivery body, has not run the auction in accordance with the Regulations and the Rules. If the Government does not choose to cancel the auction, the auction is automatically validated. Once an auction has commenced, the Government does not have any discretion to influence its outcome.

(66) Each Capacity Market auction is a descending-clock, pay-as-clear auction in which all successful participants are paid the last-accepted bid. The auction is run on the basis of pre-defined rules. The auctioneer announces a high price at the beginning of the auction and eligible participants submit bids to indicate how much capacity they are willing to supply at that price. This process is repeated in successive rounds according to a pre-determined schedule until the auction discovers the lowest price at which demand equals supply. All successful participants are paid the same clearing price (pay-as-clear model). In addition, there exist a number of measures aimed at minimising gaming risks and ensuring an efficient outcome.

(67) When deciding how much capacity to provide at any given capacity price, participants are expected to factor in the possibility of earning revenues on the energy market. Expected energy market revenues vary by provider depending on their expected load factors, wholesale prices and fuel and carbon costs.

(68) In 2014, ‘turn-down’ DSR, generation-derived DSR and embedded (or distribution-connected) generation (up to 50 MW) were regarded by the UK as nascent sectors in need of additional support to help them prepare for competition in the main CM auctions. As a result, two transitional auctions (TAs) were held for 2016 and 2017 to support them. While the first transitional auction was indeed open to the three categories of capacity described above, the level of success of embedded (or distribution-connected) generation and generation-derived DSR in the first TA auction, and in the T-4 auctions in 2014 and 2015, let the UK consider that these participants were mature enough to compete successfully in the main CM auctions against other types of capacity without further ring-fenced support. The UK therefore excluded these resources from the second (and final) TA auction so only ‘turn down’ DSR could participate. Furthermore, for the second TA, the UK indicated that it decided to test whether a lower participation threshold (i.e. 500 kW instead of 2 MW) could be a beneficial amėndment to the enduring Capacity Market regime for all participants. Table 4 shows the results of the TA. Table 4 Capacity (de-rated, MW) securing agreements through the Transitional Arrangements auctions 1st TA Auction 2nd TA Auction Distribution-connected generation 328 n/a Total DSR, of which: 475 312 — Generation-derived DSR 322 n/a — Turn-down DSR: — Including capacity < 2 MW 153 — n/a 312 — 8,5 (representing 8 CMUs) Total 803 312

(69) Table 5 shows, for each auction held since 2014, NG’s recommended amount to be procured, the target volume approved by the Secretary of State and the amount eventually procured at the T-4 and T-1 auctions. Table 5 Capacity Requirements (GW) National Grid’s Recommended amount to procure in ECR National Grid Adjusted recommendation of amount to procure at auction following prequalification Amount to procure Target volume approved by Secretary of State Amount procured at auction T-4 2014 53,3 48,6 48,6 49,3 (22) T-4 2015 47,9 44,7 45,4 46,4 T-4 2016 49,7 51,1 51,7 52,4 T-4 2017 50,5 49,2 49,2 50,4 T-1 2017 6,3 4,9 4,9 5,79 T-1 2019 (conditional auction) 4,6 4,3 (November 2018) 2,3 (May 2019) 2,7 3,6

2.4.3. Price takers

(70) To mitigate market power in the auction, potential capacity providers who have successfully pre-qualified are classified as either ‘price takers’ (who cannot bid above a relatively low threshold) or ‘price makers’ (who can). Existing capacity providers are price takers by default. New entrants and DSR resources are classified as price makers, and are free to bid up to the overall auction price cap. According to the UK, this distinction reinforces incentives for participants to bid at true value of their capacity and mitigates the risk that existing plants with lower costs may seek to set a high price in years where new entry is not needed. The UK argues that the price taker threshold should be set at a level that captures the majority of existing plants, while being at a price low enough to mitigate gaming risk. The price taker threshold has been set at GBP 25/kW (50 % net CONE). This is high enough to capture the majority of existing plants. In 2014, the UK’s modelling suggested that this would capture around 80 % of existing plants. Table 6 shows that in reality, around 60 % of existing plants were captured by the price taker threshold. GBP 25/kW is also significantly below the expected cost of new entry. As a result, a price taker threshold of GBP 25/kW also mitigates gaming risk. Table 6 Existing Plants captured by Price Taker Threshold since 2014 Auction Existing Plant captured by Price taker threshold Capacity (MW) % Clearing Price (GBP/kw) 2014 T-4 25 007 67 19,40 2015 T-4 39 286 80 18,00 2016 T-4 29 548 56 22,50 2017 T-4 31 099 57 8,40 2017 T-1 2 306 29 (23) 6,00 2019 T-1 (condit.) 1 758 (24) 49 0,77

(71) Existing plants with particularly high costs can be allowed to participate as price makers (and bid higher than the price taker threshold), but they have to provide a justification for needing a higher level of payment (for example a board certificate and business plan presented to the provider’s board). This justification must be provided to Ofgem, and may be used as part of any investigation into abuse of market power.

(72) Any existing providers that bid at a price above the ‘price maker’ threshold and do not receive a capacity agreement in the auction, but continue to operate in the delivery year, are likely to be investigated by Ofgem, which may use the information provided alongside the price setting auction bid.

(73) New entrants are able to set a price without justifying their bid, though if it were perceived that they were seeking to exercise market power this could be also subject to investigation by Ofgem as part of its normal enforcement role. The level of bid is in any case capped by the price cap set in the demand curve provided in advance of the auction.

2.4.4. Capacity Agreement duration

(74) If successful at the auction, capacity providers are awarded a capacity agreement at the clearing price. The length of available capacity agreements varies to ensure a level playing field between capacity providers.

(75) Most existing capacity providers have access to one year agreements; generation capacity providers undertaking capital expenditure above an original GBP 125/kW threshold (refurbishing plants) are eligible for capacity agreements of up to a maximum of 3 years; generation capacity providers undertaking capital expenditure above originally GBP 250/kW (new plants) are eligible for capacity agreements up to a maximum of 15 years. These thresholds are reviewed each year and have been subject to slight increases over time, standing at GBP 135/kW and GBP 270/kW respectively in December 2018. Agreements longer than 1 year are only available to participants in the four-year ahead auction.

(76) To ensure regulatory certainty and foster investors’ confidence in the mechanisms, the key terms of a capacity agreement are ‘grandfathered’ (25) (subject to any future regulation to the contrary, although no such changes have been made so far). These key terms are: (a) agreement length; (b) capacity price and entitlement to payment; (c) capacity obligation and de-rating figure; (d) completion milestones and termination fees applicable; (e) maximum liability for penalties.

(77) The UK argues that the rationale for longer-term contracts for new entrants is to help promote competitive new entry into the market. Allowing new entrants to receive a long-term contract enables new entrants to secure lower-cost financing for their investment. The UK believes that this can help mitigate barriers to entry for independent firms who cannot finance investment in new capacity on the back of revenues from other plant in their portfolio. By encouraging competition in the market, longer-term contracts can therefore help lowering costs for consumers in both the energy and capacity markets. Longer-term contracts should also, according to the UK authorities, reduce the risk that participants with high investment or refurbishment costs load all of these costs into a single year agreement.

2.5. Secondary market (trading)

(78) Between auction and delivery and in the delivery year/s, participants are able to adjust their position through trading, e.g. by taking on a greater or lesser obligation, or finding alternative capacity to meet temporary shortfalls. Secondary trading is an important tool for parties to manage their risk of exposure to penalties within the Capacity Market. There are different forms of secondary trading allowed under the Capacity Market: financial trading, volume reallocation and obligation trading.

2.6. Delivery

(79) The Capacity Market follows a ‘delivered energy’ model: capacity providers are obliged to deliver energy whenever needed to ensure security of supply, i.e. in real system stress situations. They face penalties if they fail to do so. The model also includes additional physical testing of capacity. Failure to demonstrate capacity to the required level on the requisite number of occasions results in capacity payments being forfeited until successfully demonstrated.

2.6.1. The capacity agreement obligation

(80) Under the capacity agreement obligation, system stress events are defined as any half hour settlement periods in which either voltage control or controlled load shedding are experienced at any point on the system for 15 minutes or longer. Providers are required to determine their own response at such times, and avoid breaching any existing code or licence conditions. To date, there have only been two Capacity Market Notices issued by the system operator, on the 31 October 2016 and 7 November 2016. The winter (2018/19) was to be the first year of the measure’s operation in full.

(81) To ensure participants are able to adequately manage the risk of exposure to penalties, e.g. the risk that a number of plants simultaneously trip, the System Operator has published a notice of system stress via a ‘Capacity Market warning’, based on the methodology set out in the Capacity Market Rules (8.4.6) (26). Unless this warning has been issued, a scarcity event will not trigger Capacity Market penalties or ‘over-delivery’ payments.

(82) Capacity agreements oblige participants to deliver a specified quantity of electricity. A provider’s obligation at the time of stress events is calculated from their obligations they entered through the four-year and year-ahead auctions, plus any secondary traded obligations they entered for the specific settlement periods in which a stress event occurs.

(83) In stress periods preceded by a Capacity Market warning of at least four hours’ notice, providers’ obligations are ‘load following’. That means they are only required to be generating electricity or reducing demand up to the total level of their obligation if all capacity, for which capacity agreements have been concluded in the market, is necessary to meet demand. In a stress event where only 70 % of such total capacity is necessary to meet demand, each provider is only required to generate electricity or reduce demand up to 70 % of their full capacity obligation.

(84) According to the UK authorities, load following obligations are appropriate to ensure generators have incentives to operate efficiently in the market, and are proportionate to the harm caused to consumers by any lost load. If every participant risked being penalised for their full total capacity obligation whenever there was system stress, the Capacity Market would create signals for plants to run warm even when it was economically inefficient for them to do so – increasing both emissions and consumer bills.

2.6.2. Penalties

(85) The penalty regime aims to provide capacity providers with incentives to deliver energy when needed. Units which perform below the expected level of performance are penalised, while those that exceed the expected level receive over-delivery payments, so that at the end of the year each unit’s capacity payments broadly reflects their performance. The penalty regime consists of three main elements: (a) a monthly liability cap of 200 % of a provider’s monthly capacity revenues, which, given the weighting of monthly payments according to system demand, may expose providers to a penalty liability of up to 20 % of their annual revenue in any one month; (b) an overarching annual cap of 100 % of annual revenues; (c) a penalty rate set at 1/24th of a provider’s annual capacity payments.

2.6.3. Testing regime

(86) The penalty regime is complemented by a rigorous system of performance demonstrations to ensure capacity providers are able to deliver energy when needed and only receive capacity payments if reliable. This is especially important for those delivery years with no stress events in which testing providers’ performance ensures that providers are physically capable of delivering as per their capacity obligations.

2.7. Budget, financing of the measure and payment flows

(87) Table 7 shows a summary of the outcome of the various capacity market auctions which have taken place since 2014, including the transitional auctions (TA). Table 7 Summary of Capacity Market Auction Outcomes Auction Auction acquired capacity GW Clearing Price GBP/kW Total budget for Capacity committed at auction (27) GBP millions T-4 2014 49,3 19,40 1 734 T-4 2015 46,4 18,00 1 082 T-4 2016 52,4 22,50 2 012 T-4 2017 50,4 8,40 500 T-1 2017 5,8 6,00 35 T-1 2019 (conditional) 3,6 0,77 3 TA 2016 0,8 27,50 22 TA 2017 0,3 45,00 14

(88) According to Article 6(1) of the Electricity Capacity (Supplier Payment etc.) Regulations 2014, all licensed suppliers must pay a capacity market supplier charge, to finance the costs of the Capacity Market (i.e. those incurred to fund capacity payments to providers) according to the following process: (a) payments are profiled according to system demand – so capacity providers receive a higher proportion of their payments during months of high demand (i.e. over the winter) and a lower proportion in periods of low demand. (b) three months before the start of the delivery year suppliers forecast their demand over the period 4-7 p.m. on all weekdays from the start of November to the end of February and notify these estimates to the Settlement Body. (c) supplier charges are determined based on their forecast market share and monthly charges are levied upon licensed suppliers in order to match the payment profile to capacity providers. Supplier charges are calculated based on demand between 4-7 p.m. on winter weekdays in order to incentivise suppliers to reduce their customers’ electricity demand at the times when demand is typically highest. This should reduce the amount of capacity that is needed, and therefore will reduce the cost of the Capacity Market. (d) Supplier charges are updated to reflect actual data on market share once it becomes available as with the existing Balancing and Settlement Code (BSC) reconciliation process. This reconciliation process continues for 14 months as revised demand data is received.

(89) All payment flows associated with the Capacity Market, for all participants, are calculated and administered by the Settlement Body, assisted by a settlement service provider (Elexon). The role and responsibilities of the Settlement Body and Elexon are outlined in Section 2.2.

(90) Capacity payments are determined by the amounts set out in each provider’s capacity agreement following the outcome of the relevant auction for each delivery year: capacity payments equal the amount of capacity that successful capacity providers have bid in the capacity auction, multiplied by the clearing price.

(91) Funds received by the Settlement Body are held in a non-interest bearing Government Banking Service bank account. The Settlement Body is also responsible for collecting, holding and (where necessary) returning any collateral that has been posted by new-build generators or DSR providers as part of the pre-qualification process in advance of each capacity auction.

(92) The principal financial flows to and from the Settlement Body are as follows: (a) Suppliers are obliged to pay to the Settlement Body the so-called ‘settlement body charges’ on a monthly basis beginning from the financial year 2015/2016. The ‘settlement body charge’ covers the administrative costs of maintaining the Capacity Market settlement function incurred by the settlement body (and its agent). The collection of these payments happens according to the April-March UK financial year, so to a separate timetable to other capacity market payment flows which runs according to the October-September capacity year. (b) Suppliers are obliged to provide a credit cover before the start of each month in the delivery year. This cover must equal 110 % of their supplier monthly charge and is intended to ensure that payment flows to the capacity provider can continue to be made in the event that a supplier defaults. (c) Suppliers are obliged to pay a ‘supplier monthly charge’ to the Settlement Body no later than 24 working days after the end of each month in the delivery year. The supplier monthly charge is an obligation on suppliers (via a condition in their supply licence) to fund the Capacity Market. (d) In the event of any under-performance against their capacity obligations during a stress event occurring in the delivery year, capacity providers are obliged to pay to the Settlement Body a ‘penalty charge’. This must be paid by no later than 24 working days after the end of the month. (e) The Settlement Body pays providers a ‘capacity payment’. This is an amount determined according to their capacity obligation (the amount set in the capacity auction) within 29 days after the end of each month within the delivery year. All payments to providers are funded by the revenue from the charges levied upon licenced suppliers. In the event that a capacity provider has failed to pay its penalty charge, the provider’s payment is withheld until the necessary penalty charge has been recovered. Actual payments to providers take account of any obligation trading that has taken place between the auction and the delivery period. (f) In the event that capacity providers over-deliver against their capacity obligations during a stress event occurring in the delivery year, the Settlement Body pays an ‘over-delivery payment’. Over-delivery payments due to each capacity provider are calculated at the end of the capacity year, and are paid using the funds that have been collected as penalties over the course of the year. This does not increase the overall level of capacity payment in a given year – as payments for over-delivery offset the penalties collected for non-delivery. (g) If applicable, the Settlement Body returns to suppliers a ‘penalty residual supplier amount’. This is the revenue remaining after over-delivery payments that have accumulated over the year have been paid at the necessary rate.

2.8. Generation adequacy in Great Britain

2.8.1. The electricity market in Great Britain

(93) On 1 April 2005, the UK introduced in GB a single set of wholesale electricity trading and transmission arrangements known as BETTA (British Electricity Trading and Transmission Arrangements). BETTA is based on bilateral trading between generators, suppliers, customers and traders, and participants self-dispatch rather than being dispatched centrally.

(94) Under BETTA, contracts for electricity are agreed in forwards and futures markets from several years up to 24 hours ahead of a given half hour delivery period. Short-term power exchanges and energy brokers give participants the opportunity to fine tune their contract positions from 1 to 24 hours before delivery. All the deals are bilateral, and are settled at the price registered on the power exchange or agreed bilaterally or through a broker.

(95) Under BETTA, the wholesale electricity price rewards generators for their electricity and capacity, and investors must decide to invest based on their expectation of recovering the costs of this investment through selling electricity in the wholesale electricity market.

(96) Closer to delivery, there is a balancing mechanism through which the System Operator accepts offers and bids for electricity close to real time. This enables the System Operator to balance supply and demand. At ‘gate closure’, 1 hour before each half hour delivery period, generators are required to inform the System Operator of the energy they are contracted to deliver and the expected output from each plant. Suppliers (retailers) must declare the amount they have contracted to buy, which should be the amount they expect their customers to consume. Finally, an imbalance settlement process makes payments to and from those market participants whose contracted positions do not match their actual metered electricity production or consumption. It also settles other costs of balancing the system. Participants face a relatively penal ‘cash-out’ price if their contracted positions do not match their actual consumption or production. Therefore, the imbalance settlement or cash-out price incentivises participants to help balance the system in real time.

(97) At the end of December 2017, the UK had a total of 81,3 GW of electricity generating capacity. In addition, the UK has four interconnectors allowing trade with Europe: England-France (2 GW capacity), England-Netherlands (1 GW), Northern Ireland-Ireland (0,6 GW) and Wales-Ireland (0,5 GW) (28). The NEMO interconnector between England and Belgium (1 GW) went live on 31 January 2019.

2.8.2. Generation adequacy problems

(98) The Reliability standard is expressed in terms of a Loss of Load Expectation (LOLE). This involves setting a standard, which sets out the average number of hours per year in which demand is not expected to be met by supply in a typical year. LOLE represents the number of hours per annum in which, over the long-term, it is statistically expected that supply will not meet demand. This is a probabilistic approach – that is, the actual amount will vary depending on the circumstances in a particular year, for example how cold the winter is; whether or not an unusually large number of power plants fail to work on a given occasion; the power output from wind generation at peak demand; and, all the other factors which affect the balance of electricity supply and demand. However, it is important to note when interpreting this metric that a certain level of loss of load is not equivalent to the same amount of blackouts; in most cases, loss of load would be managed without significant impacts on consumers. The critical level established by the UK is a LOLE of greater than three hours.

(99) In the notification, the Government noted that, regardless of the modelling approach chosen, the future outlook for electricity security of supply is very difficult to project with full confidence due to the sensitivity to key assumptions including electricity demand, retirement decisions, new build, the contribution of interconnection, and the availability factors of different technologies.

(100) At the time of the notification of the measure in 2014, the UK stated that in Ofgem’s 2013 Electricity Capacity Assessment, LOLE were shown to rise to up to 9 hours in 2015/16 (although noting that there was little impact in the Conventional Generation High Availability case), they would then recover before rising again in 2018/19. At the time, the UK considered that the range of scenarios demonstrated the uncertainty with the high end of the range rising above 3 hours in 2018/19 making, according to the UK, a strong case for intervention. Ofgem’s reference scenario assumed 0,75 GW of net exports in the winter season. Figure 4 Loss of load expectation and reliability standard, as supplied by the UK in its notification of 2014 Source: Ofgem, DECC analysis.

(101) The UK also stated that the UK Department of Energy and Climate Change (DECC) had also carried out simulations of investment in generation up to 2030. DECC’s Base Case scenario without a capacity market presented a similar trend to the Ofgem analysis up to 2016/17. Beyond 2016/17, DECC’s Base Case scenario saw a downward trend in capacity margins continuing into the early 2020s. DECC’s modelling assumed an additional 2,9 GW of interconnection coming forward by 2030 and assumed that interconnectors were, on a net basis (i.e. taking all interconnection capacity together), neither importing nor exporting at times of peak demand. Figure 5 Long-term estimates of de-rated capacity margins, as supplied by the UK in its notification of 2014 Source: Ofgem 2013, DECC analysis 2013.

(102) The UK estimates that analysis undertaken by the UK Government, as well as a separate analysis provided by National Grid, demonstrate the ongoing need for the CM in order to ensure that the Reliability Standard of 3 hours LOLE is met. When the CM is excluded from the modelling, the reliability standard is likely to be breached in every year included in the modelling.

(103) NG produces a 5-year EMR Base Case as part of the Future Energy Scenarios (29) to assess the capacity to secure in the capacity market auctions. In December 2018, NG set out a revised set of assumptions to assess the potential impact on the Base Case if there was no CM in the UK. NG’s assessment is that LOLE would range between 3 and 7 hours LOLE between 2019/20 and 2023/24 without the capacity market.

(104) The UK Department of Business, Energy, and Industrial Strategy (BEIS) undertook an analysis independently from National Grid, using the most recent ECR recommendations from National Grid (ECR 2018) in conjunction with BEIS commercial insights and BEIS assessment of plant economics. This analysis concludes that the expected LOLE range breaches the 3 hours LOLE reliability standard in all years to 2030 (between 3 and 345 hours LOLE between 2019/20 and 2029/30).

2.8.3. The reasons behind the generation adequacy problems

(105) The UK submits that two main market failures explain the generation adequacy problem described in the previous section.

(106) The first market failure is that reliability is a public good. Customers cannot choose their desired level of reliability, since the System Operator cannot selectively disconnect them, and consumers do not respond to real-time changes in the wholesale price. It can therefore be expected that capacity providers will not provide the socially optimal level of reliability in the absence of intervention. This may also lead to high costs to society as a result of having an unreliable electricity supply. These would be external costs if they are not charged to generators.

(107) The second market failure is the ‘missing money’ problem. The concept has been identified and described in academic literature and affects energy-only markets (30). 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 level reflecting the average value of lost load, that is the price at which consumers would no longer be willing to pay for energy and allowing generators to receive scarcity rents. However, in practice an energy-only market may fail to send the correct market signals to ensure optimal security of supply and to enable investors to obtain project finance for building new capacity. This means that energy market revenues alone may fail to bring forward sufficient investments in capacity due to ‘missing money’. The reasons why this may happen are twofold: (a) inability of prices to reflect scarcity: Current wholesale energy prices do not rise high enough to reflect the value of additional capacity at times of scarcity. This is due to the fact that charges to generators who are out of balance in the balancing mechanism (cash-out) do not reflect the full cost of the balancing actions taken by the System Operator (such as voltage reduction). (b) lack of certainty that prices will rise, even if they can: At times when the wholesale energy market prices should peak to high levels, investors are concerned that the Government/market regulator will act on a perceived abuse of market power, for example through the introduction of a price cap. They are also concerned that prices simply will not rise – for example, if wind capacity performs better than expected, reducing the opportunities for more expensive dispatchable capacity to run.

(108) The UK submits that ‘missing money’ is not a theoretical problem. Historically, GB cash-out prices had not exceeded GBP 938/MWh. The UK submits that evidence from recent scarcity situations in the GB market also indicates that prices have not risen to the levels that would have been expected. The UK Government and Ofgem commissioned an independent study to estimate the value of lost load (VoLL), which has concluded that the average value to consumers of preventing disconnections at times of system peak is around GBP 17 000/MWh (31).

(109) The UK submits that the market failures are aggravated in the short and medium term by the very rapid closure plans of existing capacity: according to NG’s central scenario, if CM revenues were not available any more, up to 8 GW of the in 2018/2019 available coal and gas plants could close in 2019/2020.

2.8.4. Additional measures to ensure generation adequacy

(110) In addition to the notified measure, the UK has undertaken and is still undertaking a range of actions in the GB electricity market that could help address the market failures listed in the previous section. The three main initiatives from the UK’s notification are listed below.

(111) The first measure quoted by the UK aimed at reducing overall electricity requirements and increasing the responsiveness of consumer demand. The UK stated that it was taking steps to reduce overall electricity requirements, for example through the Green Deal and Energy Company Obligation. The UK also pursues opportunities to encourage both lasting reductions in demand, (which the Government terms Electricity Demand Reduction or EDR) and short term reductions in demand like peak shaving/shifting (which the Government terms demand side response or DSR). In particular, the UK is committed to ensuring that every home and small business in the country is offered a smart meter by the end of 2020 (32). Smart meters are an enabler of time-of-use (ToU) tariffs which have lower energy prices at off-peak times. The first static ToU tariff in the UK was introduced by Green Energy in early 2017, offering its smart meter customers a much cheaper rate of electricity during weekday nights. However, this does not reflect actual wholesale costs which would allow consumers to respond in real time (33). What is more, following preceding work and a call for evidence, in July 2017, the UK Government and Ofgem jointly published a Smart Systems & Flexibility Plan (34). This plan outlines the underlying principles of the UK’s approach to enable the transition to a smart and flexible system, followed by 29 actions for the Government, Ofgem and/or industry.

(112) The second measure is the reform of cash-out arrangements. Imbalance or cash-out prices provide market participants with incentives to ensure that the volumes of electricity they sell or consume match the volumes they have contracted to sell or consume. The UK argues that a reform of the way the market operated helps to ensure security of supply.

(113) Ofgem launched the Electricity Balancing Significant Code Review (EBSCR) in 2012 (35) to address several long-standing concerns about factors that have dampened cash-out prices. Ofgem adopted and published their final policy decision in May 2014 (36). The implemented reforms to cash out are as follows: (a) Cash-out prices have been made ‘marginal’ by calculating them using the most expensive action the System operator (SO) takes to balance the system. This was introduced in steps, the first step was that prices would be calculated using an average of the top 50 MWh of SO actions (rather than 500 MWh) from November 2015. Since November 2018, prices have been calculated using the top 1 MWh. (b) A cost for disconnections and voltage reduction has been included into the cash-out price calculations based on the Value of Lost Load (VoLL) to consumers. This cost was introduced in steps starting at GBP 3 000/MWh from November 2015 and at GBP 6 000/MWh from November 2018. (c) The way reserve costs are priced has been improved by reflecting the value reserve provides to consumers at times of system stress. To achieve this, a Reserve Scarcity Pricing function has been introduced which prices reserve when it is used based on the prevailing scarcity on the system (37). (d) A move has been introduced to a single cash-out price for each settlement period to simplify the arrangements and reduce imbalance costs, in particular for smaller parties.

(114) Ofgem has published a review of the first phase of the EBSCR (38). Since the implementation of the first phase, the average Imbalance Price (cash out price) has fallen. The majority of Imbalance Prices now lie within the range of GBP 20-30/MWh, rather than GBP 30-40/MWh as previously observed. The Imbalance Price has, however, become more volatile. The maximum price in the two years preceding the reform was GBP 429,10/MWh whereas after the reform it was GBP 1 528,72/MWh.

(115) The UK Government believes that the Capacity Market and cash-out reform have distinct but complementary roles in seeking to ensure security of electricity supply. It is better to pursue the Capacity Market as well as supporting reform of the cash-out arrangements, rather than simply to rely on the cash-out reform for the following reasons: (a) while cash-out reform should strengthen energy market investment incentives in the long term, it is expected to have a more limited impact on overall levels of investment in the short and medium term (39). This is because generators sell almost all their energy in forward markets. However, over time the cash-out reform will lead prices in forward markets to rise as generators exploit arbitrage opportunities between forward markets and the price in the balancing mechanism; (b) cash-out reform cannot address the increased riskiness of investment in thermal capacity as the power sector decarbonises: thermal capacity will increasingly run as backup and will have to recover its fixed costs through earning high prices on the few occasions where there is scarcity and prices spike; (c) in practice, investments may be dependent on a liquid market for ‘reliability options’ trading around a real-time price – whereby suppliers pay generators a fixed price in exchange for an option to buy energy at a strike price. This is unlikely to emerge under Ofgem’s reform of cash-out arrangements as the market even after the current cash out reforms remains a quasi-market with cash out determined through complex administrative procedures, but could develop if a balancing electricity market is introduced that can act as a robust reference market for options trading (40); (d) it is unclear whether investors will have confidence that any new arrangements would be maintained. This is because when prices are allowed to peak to high levels, it becomes increasingly difficult for the regulator to assess whether very high prices are efficient market operation or profiteering. This means that generators may be averse to offering energy at a high price (for fear of investigation for abuse of market), or that they may expect public intervention in the future to mitigate more frequent price spikes; (e) in the event that cash-out reforms are put in place and work well to address market failures, sharper cash-out prices have the potential to reduce the cost of procuring capacity through the Capacity Market, so that the price paid for capacity should fall to zero in the auction; (f) although cash out reform could, once completed, lead to higher prices during times of scarcity, the inherently high level of uncertainty regarding scarcity events makes relying on high scarcity rents alone a risky strategy for investors in large new build projects. The CM provides a stable, regular payment for up to 15 years for new build projects which reduces risks to investors and encourages investment in new and existing capacity.

(116) The third measure quoted by the UK is completing the internal energy market and supporting greater levels of interconnection. The UK has implemented the Third Energy Package into national legislation and submitted that it was contributing to the development of network codes. In particular, the market-related EU network codes, which harmonise the timeframes in which capacity is allocated and traded, will introduce a standard set of market rules across Europe and promote the implementation of a competitive pan-European energy market. The UK submits that these changes have the potential to improve the case for interconnector investment through more efficient utilisation of the assets. The UK also notes that in GB, the level of interconnection has increased from 4 % in 2014 to 6 % of total installed capacity in 2019, notably as the NEMO interconnector went live on 31 January 2019, and has the potential to rise to 9 % by 2021 (41).

(117) The UK also submitted that it was actively participating in the EU process for identifying priority cross-border projects every two years as set out in the ‘TEN-E Regulation’. These priority projects received ‘Projects of Common Interest’ (PCI) status enabling them to benefit from potentially faster planning and permitting procedures, potential regulatory incentives, and possible access to financial support from the Connecting Europe Facility.

(118) Ofgem’s Integrated Transmission Planning and Regulation (ITPR) project concluded in 2015 (42). It established the Network Options Assessment (NOA) process and publishing of annual NOA reports. The System Operator’s analysis provides improved information to interconnector developers, including locations where new interconnection capacity can most easily be accommodated. The new role also includes the consideration of specific interconnector proposals and provide Ofgem with assessments of their impacts.

2.9. Duration

(119) The Energy Act 2013 does not contain an end date for the Capacity Market. The State aid clearance is however valid for a period of 10 years (43) starting from the date of the first implementation of the measure in 2014 (44).

2.10. Grounds for initiating the procedure

(120) Although the Capacity Market was notified by the UK authorities before being put into effect, the 2014 Decision authorising the scheme was annulled by the General Court. In light of the GC judgment annulling the 2014 Decision, the implementation of the aid in question until the GC judgment must be regarded as unlawful (45).

(121) In accordance with the Commission notice on determination of the applicable rules for the assessment of unlawful State aid (46), the Commission has assessed the compatibility of the measure with the internal market, from December 2014 until November 2018 and for the future, on the basis of the conditions established in Section 3.9 of the Environmental and Energy Aid Guidelines (‘EEAG’) (47), which set specific conditions for aid to generation adequacy and have been applicable since 1 July 2014.

(122) The procedure for adopting a new decision may be resumed at the very point at which the illegality occurred (48).

(123) In the light of the conclusions in the GC judgment that the Commission should have had doubts as to the compatibility of certain aspects of the measure with the internal market, the Commission decided to initiate the formal investigation procedure.

(124) On the basis of the available information and the elements described in the Opening Decision, the Commission sought clarification and solicited comments on the following matters in particular: (a) appropriateness of the measure: (1) whether the measure was sufficiently open to all relevant capacity providers, especially to DSR providers because of differences in the applicable contract lengths, limited guarantee for the volume in the T-1 auction, and the minimum level of participation; (2) whether the participation of interconnected capacity should continue to be limited by the use of an interconnector-led model. (b) proportionality of the measure: (1) whether the measure was proportionate due to potentially discriminatory differences in the treatment of DSR operators compared to generators in the form of contract duration; (2) whether the cost recovery method failed to incentivise consumers sufficiently to reduce their consumption during demand peaks and therefore did not minimise the total amount of aid. (c) avoidance of negative effects on competition and trade: (1) whether the measure avoided such effects since long term contracts were reserved for generating units, limiting the openness of the measure, and since the direct participation of foreign capacity was currently not permitted in the GB capacity mechanism.

3. COMMENTS FROM INTERESTED PARTIES

(125) This section summarises comments received by the Commission during the consultation period from 35 interested parties, in particular from stakeholders active in the energy sector (such as companies active in conventional generation, interconnectors, renewable energy generation and demand side response operators, as well as trade associations and non-governmental organisations), Ofgem and National Grid.

3.1. Objective of common interest and necessity of the measure

(126) Although the Commission did not explicitly address in the Opening Decision the issue of the common objective or of the necessity of the measure, some interested parties specifically commented on those issues. Most of them were supportive of the objective and necessity of the measure. Some simply agreed with the Commission’s preliminary conclusion in the Opening Decision, whilst others: (a) cited analyses by ENTSO-E, the UK Government, National Grid and third parties which demonstrate that without the Capacity Market the UK’s Reliability Standard would be breached; (b) stated that even in the light of recent developments in the energy market (e.g. introduction of smart meters) the Capacity Market remained necessary; or (c) explained that the Capacity Market provided an important signal which supported investment in new capacity and the maintenance of existing capacity.

(127) As regards the role and potential of DSR some interested parties pointed to the increasing volume of DSR participating in the auctions as evidence that the Capacity Market was designed appropriately and as evidence of the absence of barriers for DSR. Several interested parties also stressed the positive role played by the transitional auctions to encourage the growth of DSR, all the more as they cleared at higher prices and were not open to other capacity providers.

(128) Other interested parties questioned whether the CM is necessary, arguing that: (a) the UK market would be oversupplied. Comments noted the conservative approach taken by National Grid in forecasting demand and supply, the high capacity margins for winter 2018/19, the low level of the LOLE, the reassurances given by the UK in relation to security of supply that winter, the low clearing prices and the significant growth in interconnection; (b) the energy-only market would better ensure generation adequacy, especially following the UK’s implementation of reforms such as the smart meter roll out, cash out reforms, and half-hourly settlement periods. One interested party cited the Australian energy-only market as an example where wholesale price volatility provides clear signals to invest in DSR; (c) the CM would perpetuate the ‘missing money’ problem by dampening scarcity pricing which is necessary to encourage investment in DSR and storage. Several comments cited changes in electricity prices following the General Court’s judgment as evidence for this dampening effect. (d) the Commission should assess thoroughly the potential of DSR, throughout a 10-year period, and the impact of the CM on this potential. Referring to studies, they indicate that (i) if smart meters and other useful devices are widely deployed, 15 GW of domestic demand could potentially be shifted on a winter peak day in 2025; (ii) industrial customers were estimated, in a model of 2012, to provide a capacity of 4-5 GW of DSR; while (iii) the potential for DSR from all non-domestic and non-industrial buildings were estimated to be, for 2012, between 1,2 and 4,4 GW on a winter peak day; (iv) up to 1 GW of DSR could be available in London in 2050. They also consider that DSR participation in the CM auctions is low, with DSR having obtained 1,37 % of the total capacity auctioned. Finally, some interested parties criticised the transitional auctions (TAs) as not sufficient to promote DSR because of the exclusion of DSR providers with contracts under the enduring auctions and because the second TA was limited to turn-down DSR and was therefore not sufficient to promote this type of DSR in the long term. They also regret that the UK did not extend the TA for two more years.

3.2. Appropriateness of the measure

3.2.1. Choice of instrument

(129) One interested party argued that the CM was likely to be inconsistent in a number of ways with Regulation (EU) 2019/943 because (i) the UK will already have implemented the majority of the energy-market reforms necessary to avoid a CM and (ii) if residual capacity concerns remained, a strategic reserve would be preferable.

3.2.2. Remuneration solely for the service of pure availability of capacity

(130) Some interested parties claimed that the existing notification arrangements ahead of stress events (i.e. a four-hour warning, with the timing and depth of the stress event identified ex-post) disadvantaged decentralised assets, including DSR. They suggested that the UK should explore the introduction of a dispatch mechanism or more warnings in the run-up to a stress event.

(131) Some interested parties indicated that the current penalty regime may not be sufficiently strong to ensure capacity providers respond effectively during system stress events.

(132) On the one hand, some interested parties argued that basing the definition of stress events on a ‘delivered energy’ model breaches paragraph 225 of the EEAG and allows the manipulation of de-rating factors in a manner which discriminates against low carbon (wind and solar) and alternative technologies (such as storage).

3.2.3. Openness of the measure to all relevant capacity providers

3.2.3.1. Potential discrimination against DSR providers because of the absence of time-bound delivery agreements

(133) Some interested parties claimed that the requirement for capacity agreement holders to respond to a stress event at any time of the day and for however long it lasted made participation in the CM a difficult proposition for DSR providers. They therefore argued that time-bound delivery capacity agreements should be offered through the CM.

3.2.3.2. Differences in the available contract lengths

(134) Under the current GB CM rules, most existing capacity providers have access to one-year agreements. Only generation capacity providers undertaking capital expenditure (CAPEX) above certain thresholds are eligible for longer-term capacity agreements of up to 15 years.

(135) To justify the exclusion of DSR providers from longer-term contracts, many interested parties pointed to (i) the low CAPEX levels of DSR providers (49), (ii) their preference for short-term contracts because of their volatile portfolios, (iii) the need to have longer-term contracts for refurbished and new build capacities to avoid higher bids in the CM auctions, higher levels of aid and windfall profits for existing capacities. Some interested parties also indicated that DSR providers using behind-the-meter generation could still qualify for a longer-term contract if they met the CAPEX threshold and if they entered the auction as generation.

(136) Some interested parties suggested (i) to limit the contract length to one year for all capacities, or (ii) to only allow contracts shorter than 5 years but not on the basis of CAPEX which does not take into account all the financial costs of DSR (such as operational costs), or (iii) to allow DSR providers to have access to 3-5 year contracts. Other parties suggested keeping the system based on CAPEX thresholds but giving the opportunity to any technology meeting those thresholds (i.e. including technologies operated by DSR providers) to have access to longer-term contracts and regularly reviewing the CAPEX thresholds or even creating several different thresholds to ensure technology neutrality.

3.2.3.3. Limited guarantee for the volume in the T-1 auction

(137) Some capacity volume is not auctioned four years ahead (T-4) and is ‘reserved’ for the year ahead auction (T-1). If demand falls between the four-year ahead and year ahead auctions, the amount of capacity auctioned in the T-1 auction is reduced. However, because the T-1 auctions provide a better route to market for DSR, in 2014, the UK committed to procure in the year ahead auctions at least 50 % of the capacity reserved four years earlier.

(138) Some comments indicated that the current arrangements were not satisfactory as the organisation of a T-1 is unpredictable. The UK Government can decide to cancel an auction or change the volume to be auctioned in T-1. Some interested parties suggested fixing the amount to be procured in T-1 as a percentage either of the capacity needed for the delivery year or of the capacity auctioned in T-4. Others indicated the need to increase the volume auctioned in T-1 auctions incrementally over five years. Finally, some parties suggested (i) eliminating the T-4 auctions; (ii) organising additional weekly auctions or (iii) organising additional T-2 auctions.

(139) Most interested parties indicated that the current arrangements were adequate and sufficient, pointing notably to the important success rate of DSR in the T-4 auctions. They argued that (i) all market players are equally exposed to the uncertain organisation or volumes of the T-4 and T-1 auctions so that DSR is not discriminated against; (ii) higher volumes of capacity reserved for T-1 could reduce the competitiveness of the T-1 auctions and (iii) higher volumes of capacity reserved for T-1 could increase the risk of over-procurement, if the need for capacity for the delivery year had decreased below the levels previously fixed.

3.2.3.4. Minimum participation threshold

(140) As described in recitals 30 and 31, a minimum threshold of 2 MW is applicable for participation in the Capacity Market for all capacity types.

(141) Some interested parties suggested setting much lower participation thresholds (100 kW, 500 kW, < 1 MW), referring to other markets in which DSR can participate (Pennsylvania-New Jersey-Maryland (PJM) Interconnection, balancing market and ancillary services).

(142) Moreover, some parties criticised the high level of the bid bond applicable to DSR and generation (GBP 5 000/MW in 2014) as being discriminatory against DSR. They argued that this could constitute a barrier to entry in particular for new DSR providers as all participants in the Capacity Market had to commit to covering open-ended delivery and DSR providers might have more difficulty than generators in covering a long delivery period. Due to the higher perceived default risk of DSR providers, they might have more difficulties in financing the amount of the bid bond.

(143) In contrast, many interested parties pointed to the relevance of a 2 MW participation threshold. Beyond the necessity to keep administrative costs low, some interested parties indicated that (i) the 2 MW threshold did not appear to be a barrier for DSR participation since the UK tested a lower participation threshold for the second transitional auction (500 kW) and only eight CMUs below 2 MW qualified, providing less than 3 % of the overall capacity secured in that auction, and since no clustering of DSR CMUs around the 2 MW threshold was noticed in the latest auctions. They also pointed out that (ii) the 100 kW threshold used by PJM applies to smaller regional procurements and is therefore not comparable.

(144) Several interested parties explained that a bid bond requirement was necessary to ensure real delivery and to discourage speculative projects. One interested party indicated that, in the transitional auctions for which the bid bond requirement was only 10 % of the normal level, a high proportion of the new capacity failed to be delivered (25 %).

(145) Moreover, some interested parties pointed to advantages granted to DSR compared to other technologies: (a) unproven DSR that fails to deliver the full amount of its capacity during the DSR tests, only forfeits its bid bond on a pro rata basis provided they still supply at least 90 % of the original capacity committed to, and even then, the DSR CMU can still retain its capacity agreement and avoid termination fees provided it remains above the 2 MW threshold. (b) termination fees are lower for DSR (up to GBP 10 k/MW) than for other forms of capacity (up to GBP 35 k/MW). (c) joint testing allows DSR providers to ‘de-risk’ DSR testing by spreading the risk of under-delivery across a number of CMUs (i.e. any CMUs that over-deliver can be used to compensate for CMUs that under-deliver). (d) since 2015, DSR providers need only to post bid bond once for an unproven DSR CMU and, therefore, can prequalify for multiple consecutive auctions whilst only providing one set of bid bond. (e) in 2016, the UK Government raised the pre-auction bid bond for new build generation to GBP 10 000/MW while the level of pre-auction bid bond for unproven DSR was left at GBP 5 000/MW. (f) the automatic entitlement of DSR to participate in the auctions as a ‘price maker’ and bid above the threshold that ‘price takers’ must accept. (g) uniform de-rating factor of 84 % for DSR irrespective of the technology used to provide the capacity, whereas other technology classes have specific de-rating factors that range from 17 %-96 %. (h) the ability for DSR to participate in secondary trading prior to capacity being proven.

3.2.3.5. Openness of the measure to renewable energy sources and new technologies

(146) Some interested parties claimed that certain renewables – in particular wind and solar energy – are currently not allowed to participate in the CM, in breach of the EEAG. While welcoming the adoptions of new rules for solar and wind in June 2019, they criticised the fact that these rules had not already been in place in 2014 and the fact that the new rules were limited to wind and solar and did not include other RES or new technologies. For instance, a wind farm was rejected at pre-qualification for the T-4 auction in 2017. There was also no mechanism for pre-qualification of merchant renewables for the (cancelled) 2018 T-4 auction (for delivery year 2022/2023). Other comments criticised the de-rating factors applicable to RES as too restrictive.

(147) Another interested party argued against the inclusion of intermittent renewables in the CM – particularly those built and funded under other support measures – as they would continue to operate regardless of CM payment and might not be able to produce and sell electricity during a stress event.

3.2.3.6. Participation of interconnected capacity

(148) Many interested parties pointed to the long-term goal of direct participation of foreign capacities while insisting on the necessity to give the UK enough time to adapt to it, in line with the Regulation (EU) 2019/943.

(149) Other parties however criticised the current interconnector-led model used in the UK, and called for a swift change to direct participation of foreign capacity. One comment indicated that interconnectors are guaranteed regulated returns through the ‘cap and floor’ mechanism. Therefore, it would not be appropriate for these interconnectors to participate in the CM while generation projects receiving subsidies are not allowed to participate.

(150) One interested party commented that interconnectors should have been allowed to participate in the T-1 auction held in early 2018 for the delivery year 2018/2019. It also criticised the exclusion of interconnectors from capacity contracts longer than one year, as well as the de-rating methodology used for interconnectors, which is described as discriminatory notably because it is computed on an individual basis rather than per technology type like for other technologies participating in the CM.

3.3. Proportionality of the measure

(151) One interested party questioned the compliance of the GB CM with paragraph 230 of the EEAG, since in 2016, existing generators successful in the CM auctions received a price of GBP 22,50/kW/year, while in 2017 they received a price of GBP 8,40/kW/year, pointing to overcompensation and windfall profits.

3.3.1. Differences in the applicable contract lengths

(152) The comments related to the applicable contract lengths are summarised in recitals 134 to 136 above.

3.3.2. Exclusion of long-term STOR

(153) One interested party submits that the participation of long-term STOR providers (see recital 32(f)) in the CM would result in windfall profits, while exclusion would not undermine the original business case. Moreover, these operators could participate in the CM and in the annual auctions for short-term STOR contracts, and subsequently (if successful in the CM auctions) exit their long-term STOR contracts with no penalty.

(154) Another interested party argues that there is no prospect of long-term STOR providers achieving windfall profits as the CM is said to have led to lower cash-out prices, lower wholesale prices and lower utilisation of STOR plant. Moreover, long-term STOR providers would be de facto excluded because the final CM Rules specified that only power plants commissioned after 2014 would qualify as new build. In addition, banks would not accept a single-year CM agreement in favour of a 15-year STOR contract. They also argue that a claw-back mechanism would be more proportionate than complete exclusion and suggest that their plant should be retrospectively awarded the CM agreements they should have been awarded in 2014 and thereafter.

3.3.3. Cost recovery method

(155) The cost recovery method is based on electricity consumption between 4-7 p.m. each weekday in winter. As explained in recital 187 of the Opening decision, the UK, before the national public consultation on the capacity mechanism, initially envisaged that the amount of the charges would be calculated on the basis of the electricity suppliers’ market share in the electricity demand registered during the so-called ‘triad’ periods. That is to say the three half-hour periods registering the highest annual electricity consumption in the UK during the period from November to February.

(156) Most comments received on this point consider that the cost recovery methodology is proportionate. They argue that the current methodology strikes the right balance between, on the one hand, a predictable and fair basis for charging suppliers, and, on the other, maintaining a signal to reduce demand during the expected period of peak demand.

(157) Some interested parties also raised a range of concerns ab