STATE AID — UNITED KINGDOM

State Aid SA.35980 (2018/NN) — Electricity Market Reform: Capacity Mechanism

Invitation to submit comments pursuant to Article 108(2) of the Treaty on the Functioning of the European Union

(Text with EEA relevance)

(2019/C 109/02)

By means of the letter dated 21 February 2019 reproduced in the authentic language on the pages following this summary, the Commission notified the United Kingdom of its decision to initiate the procedure laid down in Article 108(2) of the Treaty on the Functioning of the European Union concerning the abovementioned measure.

Interested parties may submit their comments on the measure in respect of which the Commission is initiating the procedure within one month of the date of publication of this summary and the following letter, to:

European Commission Directorate-General Competition State Aid Greffe B-1049 Bruxelles/Brussel BELGIQUE/BELGIË Fax + 32 22961242 Stateaidgreffe@ec.europa.eu

These comments will be communicated to the United Kingdom. Confidential treatment of the identity of the interested party submitting the comments may be requested in writing, stating the reasons for the request.

1. PROCEDURE

The United Kingdom authorities notified to the Commission on 23 June 2014 a measure to support capacity providers in the electricity market in Great Britain called ‘capacity market’. The national legal basis for the measure is the Energy Act 2013.

In the course of the pre-notification contacts and the preliminary examination, the Commission received several submissions by certain operators in the United Kingdom that alleging that certain aspects of the measure may be incompatible with the internal market pursuant to Article 107(3)(c) of the Treaty. After having assessed the notification, which also responded to the allegations raised in the operators’ submissions, on 23 July 2014, the Commission decided not to raise objections to the aid scheme establishing the measure, on the ground that that scheme was compatible with the Union rules on State aid.

On 15 November 2018, the General Court of the European Union in case T-793/14 — Tempus Energy and Tempus Energy Technology v Commission (ECLI:EU:T:2018:790) annulled the Commission decision. 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, which should have led it to initiate the formal investigation procedure in accordance with Article 108(2) of the Treaty.

In order to comply with the General Court judgment, the Commission re-examined the notified measure and decided to initiate the formal investigation proceedings under Article 108(2) TFEU.

2. DESCRIPTION OF THE MEASURE IN RESPECT OF WHICH THE COMMISSION IS INITIATING THE PROCEDURE

The liberalisation of electricity markets and their increased integration in one internal electricity market creates challenges for ensuring generation adequacy. In 2014, the United Kingdom (UK) estimated that the electricity market in Great Britain (GB) would reach critical levels of generation adequacy around 2017/2018. The UK therefore designed the measure as a capacity market.

Under the capacity market, the UK system operator organises annual centrally managed auctions to procure the level of capacity required to ensure the ability of the power system to cover the peak load. Capacity providers can bid for lead-times of one or four years ahead. In return for a steady payment for the duration of the capacity agreement (ranging between 1 and 15 years), successful bidders in the auctions are required to provide capacity at times of stress events on the electricity system or face financial penalties. Auctions are open to existing and new electricity generators, demand side response (DSR) operators and storage. Interconnectors are allowed to participate as of 2015. The costs of the Capacity Market (i.e. those incurred to fund capacity payments to providers) are paid by all licensed suppliers based on electricity consumption between 16.00 and 19.00 each weekday in winter.

The national legal basis for the measure is the Energy Act 2013. Secondary legislation in the form of Electricity Capacity Regulations and Capacity Market Rules was adopted by Parliament on 1 August 2014.

3. ASSESSMENT OF THE MEASURE

3.1. Existence of aid within the meaning of Article 107(1) of the TFEU

The Commission considers that the capacity payment constitutes a resource that is under the control of the State and that is imputable to it. The Commission notes that the successful bidders receive, through the notified mechanism, a remuneration they would not receive if they continued to operate in the electricity market on normal economic conditions selling electricity and ancillary services only. Moreover, the measure confers an advantage to only certain undertakings able to help tackle the identified adequacy problem that compete with other electricity producers. The notified measure will thus confer an economic advantage to undertakings that are in a comparable factual and legal situation to other electricity producers. As a result, the measure is selective. Electricity generation as well as electricity wholesale and retail markets are activities open to competition throughout the EU. Therefore, an advantage from State resources to any undertaking in that sector has the potential to affect intra-Union trade and to distort competition. Consequently, the Commission concludes that the measure constitutes State aid within the meaning of Article 107(1) TFEU.

3.2. Lawfulness of aid

Although the Capacity Market was notified by the UK authorities before being put into effect, the 2014 Commission decision authorising the scheme was annulled by the General Court. In light of the General Court’s judgment annulling the 2014 Commission decision, the implementation of the aid in question must be regarded as unlawful (1).

3.3. Compatibility of the measure

In accordance with the Commission notice on determination of the applicable rules for the assessment of unlawful State aid (2), the Commission has assessed the compatibility of the measure with the internal market, from 2014 until November 2018 and for the future. The assessment is based on the conditions established in Section 3.9 of the Environmental and Energy Aid Guidelines (EEAG) (3), which set specific conditions for aid to generation adequacy and have been applicable since 1 July 2014.

3.3.1. Objective of common interest and necessity of the aid

The UK generation adequacy concerns are identified through a quantifiable indicator and the findings are consistent with the analysis carried out by the European Network of Transmission System Operators for electricity (ENTSO-E). The measure pursues a well-defined objective. It addresses the nature and causes of the problem and in particular, the market failure that prevents the market from delivering the required level of capacity. The UK has considered alternative options to address the problem to avoid missing the objective of phasing out environmentally harmful subsidies. Therefore, the Commission reaches the preliminary conclusion that the UK Capacity Market contributes to an objective of common interest and is necessary.

3.3.2. Appropriateness of the aid

The choice of the instrument is coherent with other measures aimed at the same market failure and the aid only compensates the service of availability of capacity. However, the Commission seeks clarifications whether the measure is sufficiently open to all relevant capacity providers, especially to demand response (DSR) providers because of differences in the applicable contract lengths, limited guarantee for the volume of capacity reserved for the year-ahead auctions, and the minimum capacity level for participation. The Commission also has doubts concerning the participation of interconnected capacity, which is currently limited by the use of an interconnector-led model.

3.3.3. Incentive effect

The generation adequacy estimates presented by the UK in 2014 show that, without the measure, generation adequacy would have reached critical levels as of 2018/2019. The more recent adequacy estimates provided by the UK in December 2018 demonstrate that generation adequacy concerns remain and could reach critical levels in the next decade. Without the measure, the capacity providers would not make available the necessary capacity to meet the reliability standard set by the UK to deliver energy at times of stress. The Commission therefore reaches the preliminary conclusion that the measure has an incentive effect.

3.3.4. Proportionality

The Commission seeks clarifications whether the measure is proportionate due to potentially discriminatory differences in the treatment of DSR operators compared to generating operators with regard to the length of capacity contracts. As the General Court pointed in the judgment, the Commission’s doubts should also concern the cost recovery method, which might fail to sufficiently incentivise consumers to reduce their consumption during demand peaks and therefore does not allow the total amount of aid to be limited to the minimum amount necessary.

3.3.5. Avoidance of negative effects on competition and trade

As requested by the EEAG, the measure does not reduce the incentives to invest in interconnectors and does not undermine market coupling. In addition, it does not undermine investment decisions that preceded the introduction of the measure. It also rightly gives preference to low-carbon technologies in case of equivalent technical and economic parameters. This said, the Commission seeks clarifications whether the measure avoids negative effects on competition and trade since long term contracts are reserved for generating units, limiting the openness of the measure, and since the direct participation of foreign capacity is currently not permitted in the UK capacity mechanism.

3.3.6. Compliance with Article 30 and 110 TFEU

As indicated in point 29 of the EEAG, if a State aid measure or the conditions attached to it (including its financing method when it forms an integral part of it) entail a non-severable violation of Union law, the aid cannot be declared compatible with the internal market. In the field of energy, any levy that has the aim of financing a State aid measure needs to comply in particular with Articles 30 and 110 TFEU. The Commission reaches the preliminary conclusion that the financing mechanism of the notified aid measures does not introduce any restrictions that would infringe Article 30 or Article 110 TFEU.

In accordance with Article 16 of Council Regulation (EU) 2015/1589 (4), all unlawful aid can be subject to recovery from the recipient.

TEXT OF LETTER

The Commission wishes to inform the United Kingdom that, following the Judgement of the General Court of the European Union of 15 November 2018 in case T-793/14 — Tempus Energy and Tempus Energy Technology v Commission (‘the GC judgement’), it has re-examined the information supplied by your authorities on the measure referred to above After re-examination of the notification, the Commission has decided to initiate the procedure laid down in Article 108(2) of the Treaty on the Functioning of the European Union (TFEU). 1 PROCEDURE (1) Following pre-notification contacts, the UK authorities notified to the Commission on 23 June 2014, in accordance with Article 108(3) of the Treaty on the Functioning of the European Union (TFEU), a measure to support capacity providers in the electricity market in Great Britain ( 5 ) (‘the measure’). (2) In the course of the pre-notification contacts and the notification process the Commission received several submissions alleging the incompatibility of the measure with Article 107(3)(c). (3) On 23 July 2014, the Commission decided not to raise objections to the aid scheme establishing the measure, on the ground that that scheme was compatible with the Union rules on State aid ( 6 ) (4) On 15 November 2018, in the GC judgement, the General Court annulled the Commission decision mentioned in recital (3) above. 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, which should have led it to initiate the formal investigation procedure in accordance with Article 108(2) TFEU, and thus allow interested parties to submit their observations and to put at its disposal the relevant information in order to better assess the compatibility of the planned capacity market. (5) Following the annulment of the Commission decision, the Commission registered the file under a NN reference, since the measure has been in force since 2014 ( 7 ) . Additional information was received from the UK on 20 December 2018. In order to comply with the GC judgement, the Commission re-examined the notified measure and decided to initiate the formal investigation proceedings under Article 108(2) TFEU. (6) Since the United Kingdom notified on 29 March 2017 its intention to leave the European Union, pursuant to Article 50 of the Treaty on European Union, the Treaties will cease to apply to the United Kingdom from the date of entry into force of the withdrawal agreement or, failing that, two years after the notification, unless the European Council in agreement with the United Kingdom decides to extend this period. As a consequence, and without prejudice to any provisions of the withdrawal agreement, the present decision only applies if (i) the United Kingdom is still a Member State on the first day of the period for which the notified scheme is approved, and (ii) to individual aid granted under the notified scheme until the United Kingdom ceases to be a Member State. 2 DESCRIPTION OF THE MEASURE 2.1 Overview of the measure (7) In 2014, the United Kingdom (UK) estimated that the electricity market in Great Britain (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 organises centrally-managed auctions to procure the level of capacity required to ensure generation adequacy. (8) The auctions were initially open to existing and new generators, demand side response (DSR) operators and storage operators. Participation of interconnectors was enabled as of the second auction in 2015. Successful bidders receive a steady payment during the duration of the capacity agreement in return for a commitment to deliver electricity at times of system stress called on by the System Operator. Financial penalties apply if beneficiaries do not deliver the amount of energy according to their capacity obligation. The measure is financed through a levy on electricity supplies. (9) The first auction was organised in 2014 for the delivery of the capacity in 2018, followed by three further four-year ahead (‘T-4’) auctions (in 2015, 2016 and 2017), one year-ahead (‘T-1’) auction (in 2017), and two transitional auctions (‘TA’, in 2016 and 2017) as discussed in recital (61). (10) The measure was suspended on 15 November 2018 following the GC judgement, mentioned in recital (4) (and currently under appeal). The UK confirmed that no further aid under the Capacity Market (also abbreviated as ‘CM’) would be granted through auctions and that the payments for the aid granted under the auctions that had already taken place had been halted until a State aid approval by the Commission. 2.2 Legal basis, duration, budget and governance arrangements (11) The legal basis for the measure is the Energy Act 2013. Secondary legislation in the form of Electricity Capacity Regulations 2014, the Electricity Capacity (Supplier Payments etc.) Regulations 2014 and the Capacity Market Rules govern the implementation of the measure. (12) The Energy Act does not contain an end date for the Capacity Market. The State aid clearance is however valid for a period of 10 years starting from the date of the first implementation of the measure in 2014 ( 8 ) (13) Table 1 below presents a summary of the outcome of the various capacity market auctions which have taken place since 2014, including the transitional auctions (TA). Table 1 Summary of Capacity Market Auction Outcomes Auction Auction acquired capacity GW Clearing Price GBP/kW Total budget for Capacity committed at auction (9) 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 TA 2016 0.8 27.50 22 TA 2017 0.3 45.00 14 (14) The UK regularly reviews the CM mechanism in the light of feedback of each auction process, and has conducted a number of public consultation exercises to make incremental improvements to the regulatory detail of certain specific features of the scheme. 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 ( 10 ) , involving both the government and Ofgem, to assess the extent to which the Capacity Market effectively delivers on its objectives and to which it remains the most effective form of intervention to address those objectives, which 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. 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. (15) The UK Government has initiated the first 5-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. (16) The measure is implemented by the Government, the energy regulator (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. The Government (17) The 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. Ofgem (18) The Government designed the Rules for the Capacity Market, but the market regulator Ofgem is responsible for implementing them (both the 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. National Grid (also abbreviated ‘NG’) (19) 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. (20) The 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. The Settlement Body The Government set up the Capacity Market Settlement Body to provide ultimate accountability, governance and control of the settlement process and payments disbursed under capacity agreements. The Settlement Body is a private company limited by shares owned by the Government as the sole shareholder. 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. The settlement service provider (21) The 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 Eligibility (22) Capacity providers participate in the Capacity Market on the basis of ‘Capacity Market Units’ (CMUs). It is at CMU level at which pre-qualification applications are made, capacity agreements are held, obligations that apply in times of system stress are specified and penalties/over-delivery payments are calculated. Generation capacity (both existing and new), interconnectors, storage and DSR are able to participate. The eligibility criteria are set out in recitals (23) to (27). (23) Generating units (defined with reference to: providing electricity, being capable of independent control, net output measured by half hourly meter(s), connection capacity in excess of 2MW) may participate individually as a CMU or aggregate with other eligible generating units under the following conditions: — The units all form part of the same Trading Unit (i.e. power station); or — 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 — The aggregate capacity of all the units is between the minimum (2MW) threshold and 50MW (effectively embedded generation spread across several sites); (24) DSR CMUs are defined with reference to a commitment to reduce demand with the DSR provider 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. Such commitment should cause the electricity customer to reduce the import of electricity (as measured by half hourly meters) and/or export electricity generated by on-site generating units which are owned by the electricity customer. In addition, each component should be connected to a half hourly meter and the provider’s total DSR capacity should be between 2MW and 50MW. Table 2 below shows the results of DSR performance in the auctions held until November 2018: Table 2 DSR performance in the capacity auctions held to date 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 (11) (susp.) 2,618 N/A 2017 T-1 1,283 443 2018 T-1 (susp.) 2,124 N/A 2015 TA 619 475 2016 TA 373 312 (25) The Capacity Market excludes capacity providers already in receipt of support from other measures. The following resources are not eligible to participate in the Capacity Market: — Low-carbon generating plants receiving support through the Contracts for Difference (CfD) or small scale Feed-In-Tariff. — 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). — 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. — 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. — 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. — Plants which were awarded 15 year contracts by NG to form part of the Short-Term Operating Reserve immediately prior to the initial Electricity Market Reform (EMR) policy proposals in 2010, and which chose to maintain them. (26) 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). (27) While the direct participation of foreign capacities is not allowed, interconnectors have been eligible for the participation in the capacity market as from the second auction in 2015, as CMUs, on an equal basis with GB-based generators and DSR resources, subject to essentially the same regime of rewards and penalties, and de-rated to reflect their contribution to security of supply ( 12 ) . Table 3 below presents the results of the interconnectors’ (‘IC CMUs’) participation in the auctions to date: Table 3 Interconnector participation in CM auctions to date Auction type T-4 T-1 Auction Year 2015 2016 2017 2018 (susp.) 2018 (susp.) Delivery Year 19/20 20/21 21/22 22/23 19/20 Number of IC CMUs pre-qualified 3 5 6 8 3 Number of IC CMUs successful 2 4 6 NA NA Of which new build 0 0 3 NA NA Of which existing 2 4 3 NA NA Capacity of IC CMUs successful (GW) 1.86 2.34 4.56 NA NA (28) In the 2014 decision, an exception to the participation of the interconnected capacity was granted for the first auction (December 2014) due to the following constraints: — 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. — Prequalification: At that point in time, it was not possible for the Delivery Body to independently complete the prequalification stage for a foreign capacity. Cooperation with foreign TSOs on measurement and verification, dispatch for testing and data-sharing platforms would have been needed. — 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. — Delivery: The obligation to deliver entails that generators must 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 (13). 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. (29) 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 (cf. recital (143)). Pre-qualification process (30) 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 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. (31) 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. (32) 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). (33) 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 detail (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. (34) New generation and unproven DSR (as opposed to proven DSR ( 14 ) ) 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 minimize 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. (35) 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. (36) 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 Auctioning process Establishing the amount of capacity to auction (37) 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. (38) 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. (39) 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. (40) The 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. (41) 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. (42) 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). (43) 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. (44) 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) (45) 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. (46) 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. (47) 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. Source: UK authorities (48) 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 ( 15 ) commissioned by the UK authorities assuming a 7.5 % hurdle rate and a 25 year payback period. (49) 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 ( 16 ) ) 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. (50) 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. (51) 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. (52) 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. Auction frequency and format (53) 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 that, as part of the notified measure, they may exceptionally organise a three-year ahead auction in 2019. (54) 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 ( 17 ) (55) 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 4 below presents the volume set-aside for T-1 auctions. Table 4 T-1 set aside and the Capacity to Procure at T-1 Delivery Year Target to Procure at T-4 auction (GW) Capacity set aside for T-1 (GW) Target to Procure at T-1 (GW) Amount Procured at T-1 auction (GW) 2018/19 48.6 2.5 4.9 5.79 2019/20 45.4 2.5 4.6 (18) N/A 2020/21 51.7 0.6 N/A N/A 2021/22 49.2 0.4 N/A N/A (56) 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, the Government committed to procure in the year ahead auctions at least 50 % of the capacity reserved four years earlier. To date only one T-1 has taken place and in that auction more than double the capacity reserved four years earlier was procured (4.9 GW compared to 2.5 GW originally envisaged). The proposed target for the next T-1 auction, which has been postponed as a result of the GC judgement, aims to secure over 180 % of the capacity reserved four years earlier. Though the UK authorities indicated that they did not foresee any difficulty in continuing to honour the commitment to secure in the T-1 auctions at least 50 % of the capacity set-aside four years earlier, flexibility will be retained to remove this guarantee if DSR does not prove cost-effective in the long run or if the DSR industry is considered sufficiently mature. (57) The 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. (58) The 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. (59) 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. (60) 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. (61) 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 (TA) 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 indicates that it decided to test whether a lower participation threshold (i.e. 500kW instead of 2MW) could be a beneficial amendment to the enduring Capacity Market regime for all participants. Table 5 below present the results of the TA. Table 5 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 < 2MW 153 — n/a 312 — 8.5 (representing 8 CMUs) Total 803 312 (62) Table 6 below presents, 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 6 Capacity Requirements National Grid’s Recommended amount to procure in ECR (GW) National Grid Adjusted recommendation of amount to procure at auction following prequalification (GW) Amount to procure Target volume approved by Secretary of State (GW) Amount procured at auction (GW) T-4 2014 53.3 48.6 48.6 49.3 (19) 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 Price takers and price makers (63) 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 7 below 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 7 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 % (20) 6.00 (64) 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. (65) 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. (66) 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. Capacity Agreement duration (67) 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. (68) 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. (69) To ensure regulatory certainty and foster investors’ confidence in the mechanisms, the key terms of a capacity agreement are ‘grandfathered ( 21 ) ’ (subject to any future regulation to the contrary, although no such changes have been made so far). These key terms are: — agreement length; — capacity price and entitlement to payment; — capacity obligation and de-rating figure; — completion milestones and termination fees applicable; — maximum liability for penalties. (70) 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) (71) 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 (72) 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. The capacity agreement obligation (73) 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 been no Capacity Market Notices issued by the system operator. The winter (2018/19) was to be the first year of the measure’s operation in full. (74) 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) ( 22 ) . Unless this warning has been issued, a scarcity event will not trigger Capacity Market penalties or ‘over-delivery’ payments. (75) 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. (76) 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. (77) 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. Penalties (78) 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 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. — an overarching annual cap of 100 % of annual revenues. — a penalty rate set at 1/24th of a provider’s annual capacity payments. Testing regime (79) 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 Financing of the measure and payment flows (80) The costs of the Capacity Market (i.e. those incurred to fund capacity payments to providers) are paid by all licensed suppliers according to the following process: — 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. — Three months before the start of the delivery year suppliers forecast their demand over the period 4pm-7pm on all weekdays from the start of November to the end of February and notify these estimates to the settlement body. — 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 4-7pm 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. — 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. (81) 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 above. (82) 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. (83) 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. (84) The principal financial flows to and from the settlement body are as follows: — 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. — 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. — 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. — 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. — 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. — 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. — 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 The electricity market in Great Britain (85) On 1 April 2005, the UK introduced in Great Britain 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. (86) 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. (87) 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. (88) 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. (89) At the end of December 2017, the UK had a total of 81.3GW 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) ( 23 ) . The NEMO interconnector between England and Belgium (1 GW) will be going live in early 2019. Generation adequacy problems (90) 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. (91) The Government notes 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. (92) 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 0.75GW 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 (93) 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 2.9GW 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 (94) 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. (95) NG produces a 5-year EMR Base Case as part of the Future Energy Scenarios ( 24 ) 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. (96) 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 (ECR2018) 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). The reasons behind the generation adequacy problems (97) The UK submits that two main market failures explain the generation adequacy problem described above. (98) 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. (99) The second market failure is the ‘missing money’ problem. The concept has been identified and described in academic literature and affects energy-only markets ( 25 ) . 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: — 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). — 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. (100) 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 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 ( 26 ) (101) 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 8GW of the in 2018/2019 available coal and gas plants could close in 2019/2020. Additional measures to ensure generation adequacy (102) 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 above. The three main initiatives from the UK’s notification are listed below. (103) 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 ( 27 ) . 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 ( 28 ) . 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 ( 29 ) . 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. (104) 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. (105) Ofgem launched the Electricity Balancing Significant Code Review (EBSCR) in 2012 ( 30 ) 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 ( 31 ) . The implemented reforms to cash out are as follows: — 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 50MWh of SO actions (rather than 500MWh) from November 2015. Since November 2018, prices have been calculated using the top 1MWh. — 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. — 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 (32). — 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. (106) Ofgem has published a review of the first phase of the EBSCR ( 33 ) . 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. (107) The 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: — 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 (34). 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; — 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; — 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 (35). — 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. — 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. — 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. (108) st January 2019, and has the potential to rise to 9 % by 2021 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 31January 2019, and has the potential to rise to 9 % by 2021 ( 36 ) (109) 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. (110) Ofgem’s Integrated Transmission Planning and Regulation (ITPR) project concluded in 2015 ( 37 ) . It established the Network Options Assessment 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 Submissions received in 2014 2.9.1 The submission by a balancing services operator (111) The Commission received letters from a provider of balancing services to the System Operator, on 30 May 2014 and on 26 June 2014, alleging the Capacity Mechanism would be incompatible with the EEAG. In particular, the operator alleges the exclusion of generators with long-term ‘Short-term operating reserve’ (STOR) contracts (see recital (25) above) would be discriminatory and would undermine investment decisions on generation that preceded the introduction of the Capacity Mechanism. (112) The arguments of the operator are as follows: — that, according to EEAG, generation adequacy measures ‘…should be designed in a way so as to make it possible for any capacity which can effectively contribute to addressing the generation adequacy problem to participate in the measure’, that measures should be ‘…delivered through a mechanism which allows for potentially different lead times, corresponding to the time needed to realise new investments by new generators using different technologies’ and that ‘… restriction on participation can only be justified on the basis of insufficient technical performance required to address the generation adequacy problem’; — that a STOR holder operator is not in a different situation to any other plant with a commercial power purchase agreement (‘PPA’) (38) — that the operator currently receives an internal rate of return lower than the rate the UK Government claims is necessary to secure investment in new plant, and would not receive windfall profits as a result of participating in the Capacity Mechanism; and — that, as a consequence and contrary to the EEAG, the exclusion of generators with long-term STOR contracts would ‘…undermine investment decisions on generation which preceded the measure…“. 2.9.2 The submission by an operator owning existing plants (113) On 25 June 2014 and on 3 July 2014 the Commission received letters from an operator that has acquired existing power plants. The operator claimed that the difference in treatment between existing and new plants (restricting existing plants to one year capacity agreements and imposing on them “price taker” status) raised serious concerns regarding the compatibility of the Capacity Mechanism proposals. (114) In particular, the operator submitted that such differentiation between existing and new plant: — was without objective basis (for example, it is not based on technical characteristics); — was liable to result in more than the minimum aid required to meet the policy objective of ensuring security of supply, since it risks accelerating the closure of existing plant, increasing the requirement for new plant; — was inconsistent with point (226) of the EEAG which states that “[t]he measure should be open to and provide adequate incentives to both existing and future generators…“; — Unnecessarily restricted competition (contradictory to points (80) and (232)(c) of the EEAG) by denying consumers the possibility to express preferences as to contract length and by restricting the bids of all existing plants, irrespective of the market power of the generator. (115) The operator submitted numerical examples relating to both a generic plant and a specific plant showing that, under certain assumptions, existing Combined Cycle Gas Turbines (CCGTs) could provide capacity at a lower price than a new entrant CCGT for any given contract duration. However, existing CCGTs could lose out in an auction against new entrant CCGTs based on the proposed Capacity Mechanism design. This would be because existing CCGTs would not have access to a contract duration longer than 1 year (or 3 years in the case of existing plant requiring significant refurbishment), which would enable them to lower their bids, as a result of the increased revenue certainty provided by a longer contract. 2.9.3 The submission by operators in the Demand Response market (116) On 9 June 2014 the Commission received a submission from a group of aggregators of the electricity consumption of industrial and commercial customers who provide certain ancillary services to the System Operator. (117) In particular, the operators submitted that: — Offering one year capacity agreements to DSR would make the business case for DSR less favourable while locking in fossil fuel generation by offering 15 year agreements to generation is discriminatory and incompatible with points (220) and (227) of the EEAG; — DSR would be discouraged from participating in the main auctions four years ahead, since DSR providers who hold a capacity agreement for the enduring regime would not be permitted to enter the transitional auctions; — The costs of the Capacity Market was targeted at all winter peak demand periods rather than the specific hours in which it is used, thereby blunting the economic signal to consumers to shift their demand away from peak times and discouraging DSR, inconsistent with point (224)(b) of the EEAG; — The Capacity Market did not recognise the benefits of DSR compared to generation in avoiding transmission and distribution losses; and — Contrary to point (233)(d) of the EEAG, the treatment of DSR strengthened the dominance of fossil fuel generation. 2.9.4 Observations by the UK authorities to the 2014 third parties” submissions (see sections 2.9.1 to 2.9.3) (118) The UK does not contest that the support granted under the scheme constitutes State aid within the meaning of Article 107 (1) of the Treaty on the Functioning of the European Union (TFEU). However, the UK submits that the Capacity Market is compatible with the internal market pursuant to Article 107 (3)(c) TFEU as it leads to an increased contribution to the EU objective of ensuring security of energy supply without adversely affecting trade and competition in the internal energy market to an extent contrary to the common interest. (119) In particular, the UK submits that the Capacity Market meets the common principles applicable to the assessment of compatibility under the Guidelines on State aid for environmental protection and energy 2014-2020. According to the UK, the Capacity Market (i) contributes to an objective of common interest (security of electricity supply); (ii) remedies well-defined market failures; (iii) is an appropriate instrument to address the objective; (iv) will have an incentive effect on participants; (v) will provide proportionate support by limiting aid to the minimum necessary; and (vi) seeks to avoid any major undue effects on competition and trade between EU Member States. (120) Regarding the submission by the STOR operator, the UK noted that: — Commercial PPAs were different to contracts with the TSO, as these were the contracts that consumers ultimately have to fund directly. — Long-term STOR providers tended to make use of project finance. The UK’s advice from a range of professionals from various types of finance and internally within the UK Government was that project finance was not available to a project exposed to merchant risk. The UK also noted that the technologies used by STOR providers (Open Cycle Gas Turbines, diesel) had high short-run marginal costs (in the range of GBP 70-200/MWh), meaning such projects could not expect to run with a load factor higher than 1-2 %. As such, the project finance case was likely to have “banked” only long-term STOR revenues and little or limited wholesale market revenues, so that long-term STOR revenues should be considered to fully remunerate the investment cost. The UK therefore considered that the impact of the Capacity Market on energy market revenues would have no impact on the business case for the project. Taking a combination of annual (i.e. short-term) STOR payments and capacity payments as the counterfactual, then, due to the higher legacy price of the existing long-term STOR contracts, participation of long-term STOR providers in the capacity market could lead to overpayment of up to GBP […] (*1) million per annum (2018 prices). — Long-term STOR providers were not per se excluded from the Capacity Market — effectively, they were given a choice as to whether to give up their long-term STOR contract (without any fear of penalty from the System Operator) and enter both the Capacity Market and the annual STOR tender process; or to choose to retain their long-term STOR contract and remain outside of the Capacity Market. The UK acknowledged that the long-term STOR contract might be an inherent part of providers” financing and that, as such, relinquishing the long-term STOR contract might have required re-financing. However, the UK noted that if long-term STOR providers saw a commercial case for relinquishing their long-term STOR contract and participating in the capacity mechanism, they might have made the case to their lenders and sought new financing terms. Long-term STOR providers would not be required to relinquish their STOR contract unless they were successful in the capacity auction i.e. there was no circumstance where they would be left with neither a long-term STOR contract nor capacity agreement. — The same concerns regarding over-compensation would not be present in the annual STOR auctions. Since the STOR auctions for annual contracts would occur after the Capacity Market auction had taken place, providers would be able to factor in their Capacity Market revenues before bidding in the annual STOR auctions, resulting in no overcompensation. (121) Regarding the submission by the existing operator, the UK noted that: — Different capacity providers were in almost all ways treated equally in the Capacity Mechanism, except most significantly in terms of the agreement length on offer. — Based on feedback from its October 2013 consultation, 15 years was the minimum agreement length necessary to enable new investment by independent generators requiring project finance. According to the UK, 15 years was also the minimum term which would allow an efficient commercial debt structure for a project. Commercial debt tenors were typically 7 years post construction and a 15 year capacity agreement allowed debt to be structured over two such periods with refinancing mid-term (at, for example, year 7). Lenders for the initial 7 year debt term would size the debt as if it were over a 13 or 14 year term since they would be able to assume the debt can be refinanced in the middle of the capacity agreement term, due to the certainty of revenues provided by the longer capacity agreement. This allowed an optimum period to amortise costs and debt service payments would therefore be lower, allowing lower bids. The participation of independent generation was required to ensure effective competition in capacity auctions. — In contrast to new plants, long-term contracts were unnecessary for existing generation as they did not need to secure finance. One year contracts were otherwise beneficial since they ensured that annual auctions were liquid and reduced the risks to consumers of locking in high prices for capacity. — As described in paragraphs (63) to (66) above, the distinction between price makers and price takers was intended to reinforce incentives for participants to bid at their true valuation of capacity and to mitigate market power. Existing generation might have obtained “price maker” status if they provided a justification for doing so. The UK submitted that there was nothing to prevent companies from making provision in such a justification for a rate of return deemed necessary to continue operating (i.e. a rate above mere covering of operating costs). Such a justification would not need validation prior to participation in the auction — it could only be requested as part of any investigation by Ofgem into possible market manipulation. The UK argued that companies that had made honest declarations should not be concerned by such an investigation. The UK noted that companies would in any case be carrying out their own analysis of the price they might be willing to accept in an auction, and that providing a justification for price maker status should entail little additional administrative burden. — That the assumptions used by the operator might have over-stated the likelihood of existing plant losing out to new plants in auctions, in particular by: — Assuming the same relationship between the Weighted Average Cost of Capital (WACC) and contract length regardless of project type and source of finance, whereas the WACC for new build could be higher than for existing plant; and — Assuming amortisation of new plant capital expenditure over the full plant life, rather than within the duration of the capacity market agreement, the latter being more likely to apply to new build project-financed CCGTs. — In the generic example, the capex estimate for returning plant from mothball appeared extremely high (almost as high as possible without causing the plant to be reclassified as “new”) and was inconsistent with evidence from the UK on actual mothball plants. — In the plant-specific example, using an example with a particularly high-cost existing plant which was relatively unlikely to be successful in the auction in any case and adopting a disadvantageous investment schedule which did not enable the plant to access the three-year refurbishment contract, which would, according to the calculations submitted by the operator, enable it to win the auction. — The UK had simulated in their own model the generic plant example submitted by the operator, making the following amendments: — For the existing mothballed plant, assuming required capex equal to GBP 100/kW. — For the new plant: — A scenario using the same assumptions as the operator. — A scenario with revised financing assumptions, namely assuming a debt:equity ratio of 65:35, that this debt is amortised in 14 years (i.e. within the 15 year contract period) and assuming capacity payments need to be equal to at least the debt service cos