Final Investment Decision Enabling for Renewables (FIDeR) process

UK FID Enabling for Renewables (FIDER, 2013–2014)

The first-ever UK offshore-wind revenue allocation — and the only non-competitive one. FIDER was a one-off transitional scheme run by the Department of Energy and Climate Change between March 2013 and July 2014 to bridge the gap between the Renewables Obligation (closing to new accreditations 31 March 2017) and the Contracts for Difference regime (first allocation round AR1 opened 16 October 2014). DECC received 57 Phase 1 applications to participate, 26 Phase 2 binding-process applications, 16 Qualifying Projects (those meeting the minimum-threshold Evaluation Criteria), and ultimately awarded Investment Contracts to 8 projects on 23 April 2014 — five offshore wind, two coal-to-biomass conversions, and one dedicated biomass with CHP. Total awarded capacity was 4,548 MW across all technologies; offshore wind alone took 3,184 MW (Beatrice 664, Burbo Bank Extension 258, Dudgeon 402, Hornsea Project One 1,200, Walney Extension 660) — this writeup focuses on the offshore-wind portion, which is what the AgentZero auction record will seed; the 3 biomass projects (Drax Unit #1 645 MW, Lynemouth 420 MW, Teesside REP 299 MW) are described below for context only and are out of scope for seeding. Strike prices were administratively set by DECC in the final EMR Delivery Plan (4 December 2013) — not competitively cleared — at £140/MWh (2012 prices) for the offshore-wind projects with Target Commissioning Dates in FY 2017/18 or 2018/19 (Beatrice, Hornsea 1) and £150/MWh for those with TCDs in FY 2016/17 (Burbo Bank Extension, Dudgeon, Walney Extension). Contract term: 15 years for offshore wind (matching the subsequent AR1 CfD). Total lifetime cost to consumers: £16.6 billion (2013-14 prices, undiscounted), representing ~58% of the total funds the National Audit Office estimated would be available for renewables CfDs through 2020/21 — making FIDER the single largest UK offshore-wind revenue commitment ever made without price competition. European Commission state aid approval was granted on 23 July 2014 under a bundled decision covering all five offshore wind projects (cases SA.38758, SA.38759, SA.38761, SA.38763, SA.38812). Post-award fate: 100% delivery. All five offshore wind projects were commissioned between 2017 and 2020, with Burbo Bank Extension (the first commercial deployment of MHI Vestas 8 MW turbines) leading the fleet in May 2017 and Hornsea 1 (the world's largest operating offshore wind farm at the time, with 174 Siemens Gamesa 7 MW turbines) completing in 2019–2020. FIDER is the baseline against which the competitive AR1–AR7 CfD rounds are measured — both on price discovery (AR1's £119.89/MWh 2017/18 OSW clearing was 14–18% below FIDER's administrative £140) and on delivery certainty (FIDER's 100% survival was uniquely strong against AR5's 0% OSW clearing and AR4's subsequent Permitted Reduction cascade).

1. At a glance

• Sponsor / offtake authority: Department of Energy & Climate Change (DECC) — predecessor to BEIS (2016) and DESNZ (2023). The Secretary of State was the contracting counterparty at signature; contracts were subsequently transferable to the CfD Counterparty (LCCC) once Schedule 2 of the Energy Act 2013 came into force and the Counterparty Body was operational
• Contract Counterparty (post-transfer): Low Carbon Contracts Company Limited (LCCC) — the UK Government-owned counterparty established under Schedule 2 of the Energy Act 2013, incorporated 1 May 2014 for the CfD regime. The FIDER Investment Contracts were the first contracts assigned to LCCC's register
• Scrutiny regime: Pre-Brexit EU State aid (pre-BEA Guidelines successor framework). The offshore-wind Investment Contracts were approved under Commission Decision C(2014) 5074 final of 23 July 2014, which bundled cases SA.38758 (Walney Extension), SA.38759 (Dudgeon), SA.38761 (Hornsea Project One), SA.38763 (Burbo Bank Extension) and SA.38812 (Beatrice). The parallel CfD for Renewables Scheme (for AR1 onwards) was approved the same day under SA.36196 (Commission Decision C(2014) 5079 final)
• Primary legislation: Energy Act 2013 (chapter 32), assented 18 December 2013. Schedule 2, Part 2 (paragraphs 1–5) creates the Investment Contract as a distinct species of contract, defined by being entered into by the Secretary of State on or before the earlier of 31 December 2015 or the date the CfD "eligible generator" regulations came into force, containing a strike/reference price difference-payment obligation, and laid before Parliament with a statement that without the contract "there is a significant risk that the electricity generation to which the contract relates will not occur or will be significantly delayed"
• Secondary policy framework: FID Enabling for Renewables: Update 1 – Invitation to Participate (14 March 2013); Update 2 – Investment Contract Allocation (27 June 2013); Update 3 – Contract Award Process (4 December 2013); FID Enabling for Renewables Impact Assessment (27 June 2013)
• Strike-price source: Final EMR Delivery Plan (published December 2013) — set administrative strike prices for all CfD-eligible technologies used in both FIDER and the first two CfD Allocation Rounds (AR1 2015, AR2 2017) as the per-technology Administrative Strike Price ceiling
• Phase 1 participation window opens: 14 March 2013 (Update 1 publication)
• Phase 1 participation closes: Close of play, 1 July 2013 — DECC received 57 applications (per NAO ¶6)
• Phase 2 binding-process applications close: 12:00 BST, 6 September 2013 — DECC received 26 applications, one of which was subsequently withdrawn, leaving 25 assessed (per Update 3 ¶10)
• Qualifying Projects identified: 4 December 2013 (co-publication of Update 3) — 16 projects met the Phase 2 minimum-threshold Evaluation Criteria, representing ~8.0 GW of capacity across four technology groups (Biomass Conversions, Dedicated Biomass CHP, Offshore Wind, Onshore Wind)
• Draft Investment Contracts issued to Qualifying Projects: 19 December 2013
• Final Investment Contracts issued (March 2014): March 2014 — with the marked-up changes since the December 2013 draft
• Binding applications due: February/March 2014 (per Update 3 indicative timetable)
• Award announcement: 23 April 2014 — DECC announces 8 successful projects
• Laid before Parliament: 4 June 2014 (per Investment Contracts publication on gov.uk)
• Notification to European Commission: 20 June 2014 (per SA.38758 ¶1)
• State aid clearance: 23 July 2014 — Commission Decision C(2014) 5074 final raises no objections
• Awarded capacity (all technologies): 4,548 MW across 8 contracts (per NAO Figure 1 totals)
• Awarded offshore-wind capacity: 3,184 MW across 5 projects (Beatrice 664, Burbo Bank Extension 258, Dudgeon 402, Hornsea Project One 1,200, Walney Extension 660 — per EC SA.38758 Table 1 and DECC Successful Projects list)
• Awarded biomass capacity: 1,364 MW across 3 projects (Drax Unit #1 645, Lynemouth 420, Teesside REP 299)
• Administrative Strike Prices applied (2012 real-terms £/MWh):
  • Offshore Wind: £155 (FY 2014/15, 2015/16 TCD), £150 (FY 2016/17), £140 (FY 2017/18, 2018/19)
  • Biomass Conversion: £105 flat across all FYs (contracts carry a fixed end date of 2027, not 15 years)
  • Dedicated Biomass CHP: £125 flat
• Offshore-wind strike prices as awarded:
  • Burbo Bank Extension, Dudgeon, Walney Extension: £150/MWh (2012 prices) — all three had first-phase TCDs in FY 2016/17
  • Beatrice, Hornsea Project One: £140/MWh (2012 prices) — first-phase TCDs in FY 2017/18 or FY 2018/19
• Revenue instrument: two-way Contract for Difference, 15-year term, Intermittent Market Reference Price for offshore wind, CPI-indexed Strike Price
• Total lifetime cost to consumers: £16.6 billion (all 8 projects, 2013-14 prices, undiscounted, NAO Figure 1); £11.4 billion discounted at 3.5%. Offshore-wind component alone: ~£9.7 billion undiscounted (sum of SA.38758 per-project estimates: Walney £2.1 bn, Beatrice £1.9 bn, Dudgeon £1.5 bn, Hornsea 1 £3.4 bn, Burbo Bank Extension £0.8 bn)
• Share of the 2015/16-to-2020/21 renewables CfD budget consumed by FIDER: 58% (NAO ¶12) — i.e. the 8 Investment Contracts pre-committed approximately £4 bn out of an estimated £6.9 bn available for all renewables CfD support across the LCF settlement period
• Post-award fate: 5 of 5 offshore-wind projects commissioned (100% delivery)
  • Burbo Bank Extension (258 MW): commissioned May 2017 — first commercial deployment of MHI Vestas V164-8.0 MW turbines (32 × 8 MW)
  • Dudgeon (402 MW): commissioned October 2017 (67 × Siemens SWT-6.0-154)
  • Walney Extension (659 MW): commissioned September 2018 (40 × MHI Vestas V164-8.25 MW + 47 × Siemens SWT-7.0-154; hybrid turbine layout)
  • Beatrice (588 MW operational, lower than 664 MW contract cap): commissioned May 2019 (84 × Siemens SWT-7.0-154)
  • Hornsea Project One (1,218 MW operational, 18 MW above contracted 1,200 MW cap): commissioned in phases 2019–2020 (174 × Siemens Gamesa SG 7-154)

2. Market context and strategic rationale

FIDER exists because of a timing mismatch. The Renewables Obligation (RO), which had supported every offshore-wind commissioning since Blyth in 2000, was legislated to close to new accreditations on 31 March 2017 by virtue of the Energy Act 2013 (and the Renewables Obligation Closure Order 2014). Its successor — the Contracts for Difference (CfD) regime — required substantial secondary legislation, a counterparty body, Delivery-Body allocation machinery, a contract template, strike-price determinations, and European Commission state aid approval. By mid-2012, it was clear that the first competitive CfD Allocation Round could not run until October 2014 at the earliest. The industry's concern, articulated through intense developer engagement with DECC, was that offshore-wind projects carrying long lead times (turbine orders, vessel contracts, DCO consenting obligations) required FID certainty earlier than late 2014 — in practice meaning mid-to-late 2013 — or projects would slip a season and potentially lose RO grace-period eligibility without having a CfD secured. The NAO summary (¶10) records that "developers' binding applications stated that without early contracts their projects would be cancelled or delayed by at least 12 months and in one case 24 months."

Three strategic forces shaped the scheme design:

• Policy consistency with the enduring regime. DECC was explicit from Update 1 (¶21) that "a key consideration for DECC is to ensure that any assurance it provides supports, rather than undermines, the delivery and sustainability of EMR, including its approach to strike price setting." This forced an administrative-pricing design: FIDER could not simply invent its own prices, or competitive-tender them ahead of the CfD regime, because both would undermine the CfD strike-price methodology being developed in parallel. FIDER prices therefore shadow-reference the prices subsequently published in the final EMR Delivery Plan of December 2013, which also served as the Administrative Strike Prices for AR1.

• Levy Control Framework discipline. The LCF was the spending envelope for all renewables support agreed with HM Treasury. FIDER's Investment Contracts were financial commitments under the LCF, and any aggregate commitment had to fit within the annual LCF profile for 2015/16 to 2020/21 (settled June 2013 — see Update 3 ¶36 table). DECC therefore imposed a dedicated "FID Enabling for Renewables LCF affordability envelope" that progressively opened from £260m in FY 2016 to £1,060m in FY 2021 (2011/12 prices), against which binding applications would be tested.

• The "investment hiatus" narrative. The scheme's statutory justification — that the Secretary of State must, under Schedule 2 paragraph 1(5)(d) of the Energy Bill, make a statement that without the Investment Contract there is a "significant risk that the electricity generation to which the contract relates will not occur or will be significantly delayed" — is not a boilerplate formality; it drives eligibility. Only projects at risk of investment delay specifically attributable to the EMR transition qualified. Projects that would have proceeded on RO economics without difficulty were not eligible, by design.

Against this backdrop, the commercial offshore-wind market in 2012–2013 presented approximately 9 GW of offshore projects with some form of consent or advanced consenting (Round 2 extensions, Round 3 zones, Scottish Territorial Waters rounds), a majority of which had FID-ready supply chains but critical funding gates contingent on RO or CfD support certainty. FIDER therefore operated on a materially over-subscribed front end (57 Phase 1 applicants against a ~4.5 GW award), which is why the scheme needed a down-selection mechanism at all.

3. Regulatory frame

FIDER operates under the following statutory stack:

1. Energy Act 2013 (primary). Schedule 2 (Investment Contracts) creates the instrument and specifies its qualifying conditions. Paragraph 1(5) requires the Secretary of State to lay each Investment Contract before Parliament with a statement covering: the Secretary of State's duties under sections 1 and 4(1)(b) of the Climate Change Act 2008; security of electricity supply; likely cost to consumers; and the UK's target under Article 3(1) of the Renewables Directive 2009/28/EC.

2. Electricity Act 1989, as amended by the Energy Act 2013 — underpinning statute for the Counterparty Body and the supplier-levied Settlement Costs mechanism.

3. EU State aid approval (joint decision of 23 July 2014):

   • SA.38758 bundle — Commission Decision C(2014) 5074 final approves the five offshore-wind Investment Contracts as individual large aid measures under the Environmental and Energy State aid Guidelines 2014/C 200/01 (EEAG 2014). This is the FIDER-specific approval
   • SA.36196 — Commission Decision C(2014) 5079 final approves the parallel CfD for Renewables Scheme (for AR1 onwards). Cross-referenced by SA.38758 ¶3

4. Renewables Obligation Closure Order 2014 (SI 2014/2388) — the one-off-choice-of-scheme provision. A FIDER Investment Contract counterparty (and later any CfD Generator) is barred from also claiming RO for the same generation; this is enforced contractually in the Investment Contract and statutorily through the ROO 2014 (¶9 of that instrument).

5. FIDER Update documents — not statutory but contractually authoritative:

   • Update 1 (14 March 2013): Qualification Criteria (5 pass/fail gates), Phase 1/Phase 2 process, indicative strike-price and allocation architecture
   • Update 2 (27 June 2013): Phase 2 Evaluation Criteria (8 Level-3 sub-criteria across two Level-1 criteria, 75%/25% weighted), scoring mechanism, minimum thresholds, tie-breaker rule
   • Update 3 (4 December 2013): LCF affordability envelope, technology-based down-selection rules, step-by-step selection algorithm, final timetable

6. Investment Contract execution version — laid before Parliament 4 June 2014 in four alphabetical ZIP archives (IC_A-C, IC_D-F, IC_H-S, IC_T-Z). Each contract is a bespoke execution of a standard Investment Contract template that anticipates the not-yet-final CfD Standard Terms: Update 2 ¶20(d) specifically contemplated that "if and to the extent that the full terms of the CfD to be used in the enduring CFD regime have not been wholly finalised by the time Investment Contracts are issued then Investment Contracts may need to include clauses which are not contained in published draft CFD terms as at the time they are issued and/or which remain subject to consultation."

7. Counterparty Body Framework Agreement (2014) — DECC's agreement with LCCC setting LCCC's active-management duties over the Investment Contracts. NAO ¶16 notes the Framework Agreement requires LCCC to "seek to maintain investor confidence in the Contracts for Difference regime and minimise costs to the consumer."

The no-negotiation principle is explicit and load-bearing: per Update 3 ¶21, "the Investment Contract terms will not be negotiable and no changes will be permitted which affect the commercial substance of the agreement or the allocation of risk," though DECC reserved the right to accept "technical variations which are both minor (having no impact on risk/reward levels) and necessary (in order to allow the applicant to be able to sign)." This fixed-terms design is important for Axis-1 extraction: FIDER's prize consideration is identical across all eight awardees for each technology class, differing only in project-specific fields (TCDs, capacities, developer identity).

4. Timeline of regime events (Axis 8)

Date	Event	Source
Dec 2012	LCF 2020/21 spend allocation announced	Update 1 ¶18(b)
14 March 2013	Update 1 — Invitation to Participate published; Phase 1 opens	Update 1
27 June 2013	Update 2 — Investment Contract Allocation published; annual LCF profile published	Update 2
27 June 2013	FID Enabling for Renewables Impact Assessment published	IA document
Close of play, 1 July 2013	Phase 1 participation closes — 57 applications received	NAO ¶6
7 August 2013	Draft CfD standard terms first published for consultation	Update 3 ¶14(a)
12:00 BST, 6 September 2013	Phase 2 binding-process applications due — 26 received, 1 withdrawn	Update 3 ¶10
Autumn 2013	Phase 2 scoring and minimum-threshold evaluation by DECC heads of specialism (with BEIS and external consultants)	NAO ¶11
4 December 2013	Update 3 — Contract Award Process published; 16 Qualifying Projects identified	Update 3
December 2013	Final EMR Delivery Plan published, setting administrative strike prices	Update 3 ¶14(b)
18 December 2013	Energy Act 2013 receives Royal Assent	Energy Act 2013
19 December 2013	Draft Investment Contracts sent to Qualifying Projects with provisional ranking and LCF affordability position	Update 3 Annex A
March 2014	Final draft Investment Contracts sent with changes highlighted	Update 3 Annex A
February/March 2014	Deadline for binding applications (exact date specified separately)	Update 3 Annex A
23 April 2014	8 successful projects announced	DECC Successful Projects list
May 2014	Contracts signed (subject to state aid clearance)	NAO ¶6
4 June 2014	Investment Contracts laid before Parliament	gov.uk publication page
20 June 2014	UK notifies European Commission of the five offshore-wind aid measures	EC SA.38758 ¶1
27 June 2014	NAO report "Early contracts for renewable electricity" (HC 172) published	NAO report
23 July 2014	EC state aid clearance — Decision C(2014) 5074 final (SA.38758 bundle) and C(2014) 5079 final (SA.36196 CfD scheme)	Commission decisions
31 January 2014	Secretary of State's statements under Schedule 2 ¶1(5) laid before Parliament (covering carbon budgets, security of supply, cost, Renewables Directive target)	Energy Act 2013 Schedule 2
April 2017	Estimated earliest CfD payment commencement per Update 3 ¶37	Update 3
2017–2020	Five offshore-wind projects commissioned; Investment Contracts transfer from Secretary of State to LCCC	see §13
15 October 2015	Independent Evaluation of FID Enabling for Renewables (Grant Thornton + Pöyry) final report	GT/Pöyry evaluation

Two timing facts are worth pinning:

• The NAO's summary finding (¶10) that "early contracts have given those developers certainty of support at least five months earlier than under the full Contracts for Difference regime" reflects the fact that FIDER award (23 April 2014) preceded AR1 opening (16 October 2014) by ~6 months and AR1 results (26 February 2015) by ~10 months.
• Though contracts were "signed" in May 2014, payment obligations were conditional on EU state aid clearance (received 23 July 2014). The state-aid gate is a binding suspensive condition, not a formality.

5. The prize — Investment Contract mechanics

FIDER Investment Contracts are technically distinct from the subsequent CfDs in form but structurally near-identical in economic substance. An offshore-wind Investment Contract under FIDER gives the Generator:

• A 15-year two-way difference payment (per EC SA.38758 ¶13 and ¶30–31) on every MWh metered through a Metered Export Point. When the Reference Price falls below the Strike Price, the CfD Counterparty (LCCC post-transfer, Secretary of State pre-transfer) pays the difference to the Generator; when the Reference Price exceeds the Strike Price, the Generator pays the difference back. SA.38758 ¶31: "When the reference price exceeds the strike price, the CfD mechanism requires the generator to pay the difference between the reference price and the strike price to the CfD Counterparty. In the view of the UK this ensures that the generators are not being overcompensated."
• A Strike Price administratively set by DECC from the final EMR Delivery Plan (December 2013). Offshore-wind projects with first-phase TCDs in FY 2016/17 received £150/MWh (2012 prices); those with first-phase TCDs in FY 2017/18 or 2018/19 received £140/MWh (2012 prices). All phases of a multi-phase offshore-wind project carry the same Strike Price — that is, the Strike Price is set by the first-phase TCD and does not step down in later phases (NAO ¶14 bullet three explicitly criticises this design: "The Department offered the same strike price to all phases of offshore wind projects, denying consumers the opportunity to share in any benefit for developers as technological innovation reduces costs"). The Strike Price is CPI-indexed annually on 1 April from the 2012 base — producing nominal strike prices at first payment that are substantially above the 2012 base.
• A Reference Price — tracked and calculated for the relevant settlement interval:
  • Intermittent Market Reference Price (IMRP) applies to offshore wind. Calculated as a generation-weighted average of day-ahead hourly prices on the N2EX and EPEX Spot platforms per the construction carried forward from the December 2013 Draft CfD Contract Terms
• A 15-year contract term commencing from the Start Date (as defined by Milestone Delivery Date, Target Commissioning Date and Target Commissioning Window). EC SA.38758 ¶13 confirms: "the estimated lifetime of the plant is 24 years and the proposed duration of the investment contract is 15 years." Biomass conversion projects (Drax Unit #1, Lynemouth) received a fixed end date of 2027 instead of a 15-year rolling term — reflecting the transitional nature of the conversion technology and aligning to the policy view that biomass conversion would not receive indefinite support beyond decarbonisation goals (NAO Figure 1 note 1).
• Delivery obligations based on the then-draft CfD standard terms — including Target Commissioning Date (TCD), Target Commissioning Window (TCW), Milestone Delivery Date (10% spend evidence), Longstop Date, and Change-in-Law protections. Update 2 ¶63 is explicit: "the delivery obligations in the Investment Contract, such as significant milestone requirements and target commissioning window, will follow the approach set out for the enduring CFD regime in the standard form CFD." Update 3 ¶14(a) explains that where final CfD drafting had not crystallised by March 2014, the Investment Contract "may contain provisions under which the parties will agree that the relevant final wording will be incorporated into the Investment Contract post signature based on, and following the issue of, the standard terms of the CfD (expected in Summer 2014)." Post-signature contract amendment mechanisms were therefore contemplated from the outset — a distinctive FIDER feature relative to later ARs.
• Phased commissioning (where applicable) under the same Investment Contract. For offshore wind with multiple phases (Beatrice: 2 phases; Dudgeon: 3 phases; Hornsea 1: 3 phases; Walney Extension: 2 phases), each phase has its own TCD listed in the contract but all phases share a single Strike Price. Contract termination mechanics include the possibility that phases can be severally delayed or cancelled without automatically terminating the whole contract.
• One-off choice of scheme between RO and Investment Contract, binding at signature per Update 2 ¶24. A Generator that signs an Investment Contract cannot subsequently access RO support for the same generation.
• Conditional on EU State aid approval — Update 1 ¶15 and Update 2 ¶16 make state aid clearance a suspensive condition. Contracts executed in May 2014 had no binding payment obligation until the Commission decisions of 23 July 2014.

6. Phase 1 — Qualification Criteria

Phase 1 was a pass/fail qualification gate, not a competitive process. Update 1 ¶30 sets out the Qualification Criteria as a 5-part test:

1. Qualifying Technology — "A type of renewable electricity generation which is currently eligible to receive support under the RO." This excluded nuclear, fossil CCS, and new technology categories. Offshore wind, onshore wind, biomass conversions, and dedicated biomass (with or without CHP) were eligible.
2. Qualifying Project, which required the developer to demonstrate to DECC's satisfaction:
   • (i) Credible plans to start generating electricity within the First EMR Delivery Plan period (2014/15–2018/19). This is a hard cut-off: no project that could not commission by 31 March 2019 qualified.
   • (ii) "Without an Investment Contract there is a significant risk that the electricity generation to which the Investment Contract relates will not occur or will be significantly delayed." This mirrors the statutory Secretary-of-State statement requirement in Schedule 2 ¶1(5) of the Energy Act. Developers were required to provide evidence (supply-chain commitments, FID timelines, RO grace-period constraints) demonstrating the investment-hiatus risk.
   • (iii) Not already accredited under the RO — RO-accredited units were not eligible to transfer to the new regime. Projects with only preliminary RO accreditation remained eligible.
   • (iv) Expected nameplate capacity of 50 MW or greater, or in the case of an offshore project, 100 MW or greater — small projects were funnelled to the separate small-scale Feed-in Tariff regime.
   • (v) Located in the UK.

The eligibility funnel operated as: applicants submitted Phase 1 information per Update 1 Annex B (including project description, nameplate capacity, target commissioning date, evidence of planning consent or consenting progress, grid-connection status, and financing plan); DECC assessed against the 5 Qualification Criteria on a pass/fail basis; successful applicants received a Status Letter confirming qualification and setting out the developing position on strike prices, allocation and contract terms.

The Status Letter itself was "non-contractual, non-legally binding" (Update 1 ¶14) and did not guarantee an Investment Contract — it was essentially a gate pass to Phase 2. Applicants were also required to consent to DECC naming them and their project in public announcements (Update 1 ¶39), which enabled the Update 3 publication of the Phase 2 summary table.

Phase 1 outcome: 57 applications received by 1 July 2013. Breakdown by technology is not published in aggregate form, but Update 3 Phase 2 figures imply that the majority of applications qualified at Phase 1 (since 26 out of 57 chose to proceed to Phase 2, and qualification rate at Phase 2 against minimum thresholds was 16 out of 25 assessed).

7. Phase 2 — Evaluation Criteria and scoring

Phase 2 was the competitive differentiator, in the sense that it scored projects against quality criteria and applied minimum thresholds. It was NOT a price auction. Update 2 Annex B sets out the evaluation criteria as a three-level hierarchy:

Level 1	Weight	Level 2	Weight	Level 3	Weight
1. Project Deliverability	75%	1.1 Technical deliverability	80%	1.1.1 Technical solution	30.00%
				1.1.2 Project management	20.00%
				1.1.3 Land availability, planning consent, grid connection and aviation/radar	25.00%
				1.1.4 Procurement plans for critical, long lead time items	25.00%
		1.2 Financial deliverability	20%	1.2.1 Financing plans	100.00%
2. Impact on Industry Development	25%	2.1 Industry Development	100%	2.1.1 Development of technologies	33.33%
				2.1.2 Development of the industrial supply chain	33.33%
				2.1.3 Improvement/expansion of workforce skills and capabilities	33.33%

Scoring mechanism (Update 2 ¶43–44): projects were scored only at Level 3; Level 1 and Level 2 scores were derived as weighted averages of the underlying Level 3 scores. Level 3 scores were awarded on a scale with 100 as the maximum per-criterion score. Projects submitted a single document ≤40 pages (excluding supporting evidence) addressing each Level 3 criterion (Update 2 ¶68), with clear cross-referencing between response body and evidence annexes required to ensure supporting material was considered.

Minimum thresholds (Update 2 ¶45): a project had to achieve:

• Score ≥50 on Level 2 criterion 1.1 (Technical deliverability), calculated as weighted average of Level 3 scores on 1.1.1 through 1.1.4
• Score ≥50 on Level 2 criterion 1.2 (Financial deliverability) — i.e. on the 1.2.1 Financing plans criterion
• Score ≥1 (greater than zero) on specific Level 3 criteria highlighted "in pink" in Annex B (the full list is not fully recovered in the parsed manifest but includes at minimum 1.1.1 Technical Solution)

Failure to achieve any minimum threshold = fundamental failure and rejection (Update 2 ¶45). There was no opportunity to resubmit or cure.

Tie-breaker (Update 2 ¶46): if two projects scored equally in any down-selection, the project scoring highest on Level 3 criterion 1.1.1 (Technical Solution) prevailed; if still equal, the project scoring highest on Level 3 criterion 1.2.1 (Financing plans) prevailed; if still equal, both projects carry equal ranking and bracket-advance together.

Evaluation mechanics (NAO ¶11): Phase 2 responses were reviewed by DECC staff, Department for Business, Innovation & Skills staff, and external consultants; scores were then moderated by DECC heads of specialism. The NAO specifically notes that "the Department's process obliged it to award contracts to all projects it judged eligible and affordable" — i.e. once a project passed the minimum-threshold gate and fitted within the LCF envelope, award was not discretionary.

Phase 2 outcome (Update 3 ¶10 and 12 table):

Technology	Phase 2 applications	Capacity (GW)	Qualifying Projects	Qualifying capacity (GW)
Biomass Conversions	6	3.0	6	3.0
Dedicated Biomass CHP	4	0.5	1	0.3
Offshore Wind	12	7.0	7	4.5
Onshore Wind	3	0.3	2	0.2
Totals	25 (one withdrawn from 26)	10.8	16	8.0

Ten applications (of 25 assessed) failed the minimum thresholds. Biomass Conversions had 100% Phase 2 survival; Offshore Wind had 7/12 = 58% survival (5 of 12 OSW Phase 2 applications failed minimum thresholds or did not satisfy other Phase 1 checks). DECC published the complete list of 16 Qualifying Projects at Update 3 publication time (4 December 2013) on the GOV.UK press release accompanying the Update ("Record investments of £40 billion in renewable electricity..."). The 7 Qualifying OSW projects were: Beatrice, Burbo Bank, Dudgeon, Hornsea, Walney Extension, Inch Cape Offshore Wind Farm (Inch Cape Offshore Limited), and Neart na Gaoithe Offshore Wind Farm (UK Mainstream Renewable Power Ltd). At 23 April 2014 award, the 5 first-named projects received Investment Contracts; Inch Cape and Neart na Gaoithe were the 2 unsuccessful Qualifying OSW projects — they passed Phase 2 minimum thresholds but were down-selected out of the LCF envelope at Update 3 §LCF cap Step 5 or 6. Both subsequently won CfDs under later rounds: Neart na Gaoithe at AR1 (2015) at £114.39/MWh for 2018/19 Delivery Year (448 MW, Mainstream vehicle later sold to EDF Renewables in 2019); Inch Cape at AR4 (2022) at £37.35/MWh (1,080 MW, ESB + Red Rock Power). Both projects are therefore in the dataset — under their winning AR-round auction records, not under FIDER. The 2 unsuccessful onshore-wind Qualifying Projects (Beinn Mhor Wind Farm, Heckington Fen) are out of the offshore-wind corpus.

8. Affordability assessment and down-selection

Update 3 §LCF cap and down-selection process (¶32–42) sets out the Stage 2 algorithm that applied to Qualifying Projects. Because DECC recognised ahead of award that the 16 Qualifying Projects (8.0 GW) materially exceeded the affordability envelope, a down-selection was always expected to be necessary for offshore wind.

FID Enabling for Renewables LCF affordability envelope (Update 3 ¶36), in £m 2011/12 prices:

Financial Year (ending 31 March)	2016	2017	2018	2019	2020	2021
Affordability envelope (£m)	260	450	720	1,010	1,010	1,060

The envelope is annual, cumulative across technologies, and cannot be borrowed between years. Forecast LCF spend of each binding application had to be tested against the envelope in every single year of the LCF settlement period (FY 2015/16 to FY 2020/21); breach in any one year causes down-selection to be required (Update 3 Step 3).

Down-selection algorithm (Update 3 ¶40, Steps 1–6):

1. Rank all Qualifying Projects with binding applications by overall Phase 2 evaluation score (highest first). Apply tie-breaker (1.1.1 then 1.2.1) for ties.
2. Calculate forecast LCF spend per project per year, using: binding-application Installed Capacity and TCDs (including phase detail for phased projects); EMR Delivery Plan strike prices; EMR Delivery Plan reference-price, Transmission Loss Multiplier and load-factor assumptions; 2011/12 price-basis conversion via ONS CPI data.
3. Sum aggregate spend and compare to envelope. If within envelope in all years, award all. If breach in any year, proceed to Step 4.
4. Identify top-quartile-per-technology Qualifying Projects (rounding up fractions — so a group of 5–8 projects has a top quartile of 2, a group of 4 or fewer has a top quartile of 1).
5. Allocate round-by-round within the top quartile — Round 1 takes the highest-ranking project in the top quartile of each technology; Round 2 adds the second-highest in each (where available); and so on until either all top-quartile projects are selected or a round would breach the envelope. Where the next-round aggregate would breach, the algorithm considers projects in that round in ranking order, selecting affordable ones and rejecting breach-causers — i.e. the in-round projects are NOT all-or-nothing.
6. Consider remaining projects (excluding those rejected in Step 5) in overall rank order, selecting affordable ones and rejecting breach-causers. Continue until all projects considered.

Technology-based rule rationale (Update 3 ¶38): "DECC will seek to allocate Investment Contracts first to the top quartile of Qualifying Projects within each of the technology types for which there is at least one Qualifying Project, as ranked in order of their overall scores against the Phase 2 Evaluation Criteria. Following application of this rule, any remaining budget under the affordability envelope will be allocated on a technology neutral basis in ranking order using the project's overall scores." This ensures technology diversity protection — even a low-scoring-but-qualifying technology gets a shot at the top-quartile round before the technology-neutral pass consumes remaining budget.

Revocation and backfill (Update 3 ¶42): if an applicant failed to sign an Investment Contract within the specified window of receiving an execution version, DECC reserved the right to revoke the allocation and offer the Investment Contract to the next-highest-ranking Qualifying Project previously rejected on affordability grounds, re-running Step 5 or 6 as applicable. This is a reserve-bidder mechanism analogous to, though less formalised than, the Permitted Reduction cascade later introduced to CfD AR4.

Applied outcome: of 16 Qualifying Projects (8.0 GW), DECC awarded 8 Investment Contracts (4.55 GW). The 8 awards include 5 of the 7 Qualifying Offshore Wind Projects (Beatrice, Burbo Bank Extension, Dudgeon, Hornsea 1, Walney Extension — 3,184 MW), 2 of the 6 Qualifying Biomass Conversions (Drax Unit #1 and Lynemouth — 1,065 MW), and 1 of the 1 Qualifying Dedicated Biomass CHP (Teesside REP — 299 MW). No onshore-wind Investment Contracts were awarded despite 2 onshore Qualifying Projects: NAO (¶12) and the 58% budget-consumption figure imply the offshore-wind and biomass awards consumed the envelope. The 2 non-awarded offshore Qualifying Projects are not named in the published documents (see §7 above).

9. Strike prices

The key administrative strike prices were published in the Final EMR Delivery Plan (4 December 2013) and apply both to FIDER and to AR1 (as the per-technology Administrative Strike Price ceiling). FIDER contracts use the strike price corresponding to the first-phase TCD, and that strike price applies to all phases.

Administrative Strike Prices applicable to FIDER (2012 real-terms £/MWh):

Technology	2014/15	2015/16	2016/17	2017/18	2018/19
Offshore Wind	£155	£155	£150	£140	£140
Biomass Conversions	£105	£105	£105	£105	£105
Dedicated Biomass with CHP	£125	£125	£125	£125	£125

Note the step-down for offshore wind from £155 through £140 — reflecting policy-anticipated cost reductions — but the within-project uniform rule (all phases take the first-phase SP) means the step-down effectively did not apply to any FIDER project once awarded.

Project-level awarded strike prices — the 5 OSW Investment Contracts (per NAO Figure 1 aggregated to project level + EC SA.38758 Table 2). These 5 rows are the auction_results population for this pilot:

Project	First-phase TCD	Total capacity (MW)	Strike Price (2012 £/MWh)	Strike Price (2013-14 £/MWh)	Total cost of support (£bn, 2013-14)
Beatrice	31/03/2018	664	£140	£144	2.3
Burbo Bank Extension	31/03/2017	258	£150	£154	1.0
Dudgeon	01/03/2017	402	£150	£154	1.6
Hornsea Project One	31/03/2019	1,200	£140	£144	4.2
Walney Extension	31/03/2017	660	£150	£154	2.6
OSW total (5 projects)		3,184			£11.7 bn

Within-project phase detail (narrative only — not separate auction_results rows). NAO Figure 1 decomposes each OSW project into phase-level capacity lines for accounting purposes; these are sub-elements of the single per-project Investment Contract and roll up into the 5 project-level rows above. For completeness: Beatrice was split into Phase 1 (280 MW, TCD 31/03/2018) and Phase 2 (384 MW, TCD 31/03/2019); Dudgeon into Phase 1 (90 MW, 01/03/2017), Phase 2 (210 MW, 01/08/2017) and Phase 3 (102 MW, 01/10/2017); Hornsea Project One into three 400 MW phases with TCDs 31/03/2019, 31/03/2020 and 31/03/2021; Walney Extension into two 330 MW phases with TCDs 31/03/2017 and 31/03/2018. Burbo Bank Extension is single-phase. Every phase of a given project carries the same Strike Price (the first-phase-indexed value shown above).

Parallel biomass strike prices — for context, not seeded. The 3 biomass contracts use the same administrative-strike-price table: Drax Unit #1 (645 MW) and Lynemouth (420 MW) at £105/MWh (biomass-conversion rate, both with TCDs in 2015-16 and fixed end date of 2027 rather than 15-year term); Teesside REP (299 MW) at £125/MWh (dedicated biomass CHP rate, TCD 31/07/2018, 15-year term). These contracts added ~£4.9 bn to the £11.7 bn OSW subtotal, giving the £16.6 bn grand total cited by NAO for all 8 awards. These biomass rows must not appear in auction_results.

Two design-choice points worth noting for the OSW portion:

• Walney Extension Phase 2 TCD is 31/03/2018 (FY 2017/18), which on the ASP table should yield £140 — but Walney's awarded Strike Price is £150 for all phases because the Strike Price follows the first-phase TCD (Phase 1 TCD 31/03/2017, FY 2016/17). This design choice — explicitly defended by DECC as necessary because developers procure supply chains for all phases at first-FID (NAO ¶14) — is load-bearing on ~£55 m/year of lifetime cost relative to a hypothetical phase-indexed pricing scheme.
• Hornsea Project One Phase 3 TCD is 31/03/2021 — i.e. FY 2020/21 — which is outside the First EMR Delivery Plan period (2014/15–2018/19 per Qualification Criterion 2(i)). Hornsea 1's qualification relied on Phase 1 commissioning within the FY 2018/19 deadline, with later phases permitted to stretch beyond the First Delivery Plan under the phased-project rule (Update 2 ¶62 allows "up to five further phases over a maximum period of five years").

10. Results — award roster (23 April 2014)

10.1 Offshore wind — the 5 seeded auction_results rows

These are the only 5 rows to populate in this auction's auction_results list. Source: DECC Successful Projects list (23 April 2014) + EC SA.38758 Table 2 for beneficiary/shareholder identification.

Project	Applicant legal entity (SPV at award)	Shareholders at award	Capacity (MW)	Location	First-phase TCD	Strike Price (2012 £/MWh)
Beatrice	Beatrice Offshore Wind Farm Limited	SSE Beatrice Offshore Wind Holdings (75%), Repsol Beatrice (25%)	664	Outer Moray Firth, Scotland	31/03/2018	140
Burbo Bank Extension	DONG Energy Burbo Extension (UK) Limited	DONG Energy A/S (100%)	258	Liverpool Bay, entrance to River Mersey	31/03/2017	150
Dudgeon	Dudgeon Offshore Wind Limited	Statoil Wind Limited (70%), Statkraft UK Ltd (30%)	402	The Wash, north of Cromer, Norfolk	01/03/2017	150
Hornsea Project One	Heron Wind Limited and Njord Limited	DONG Energy Wind Power A/S (33.3%), Siemens Project Ventures GMBH (33.3%), International Mainstream Renewable Power (Offshore) Limited (33.3%)	1,200	North Sea, off Yorkshire coast	31/03/2019	140
Walney Extension	DONG Energy Walney Extension (UK) Limited	DONG Energy A/S (100%)	660	Irish Sea, 19 km WSW off Walney Island (Cumbria)	31/03/2017	150

Offshore wind totals: 5 projects / 5 SPVs / 3,184 MW awarded capacity. EC SA.38758 ¶13 rounds this to "around 3.14 GW," consistent with the 3,184 MW sum at contract-cap capacities (Hornsea 1 shown at its 1,200 MW contract cap rather than 1,218 MW operational deployment).

10.2 Parallel biomass awards — context only, NOT seeded as auction_results

The three biomass Investment Contracts awarded under FIDER on the same day share the mechanism, LCF envelope, evaluation rubric and award announcement. They are listed here for narrative completeness; they must not appear as auction_results rows and are outside this pilot's scope:

• Drax Unit #1 (645 MW, biomass conversion) — Drax Power Limited; TCD 01/02/2016; £105/MWh; fixed end 2027
• Lynemouth (420 MW, biomass conversion) — Lynemouth Power Limited; TCD 31/12/2015; £105/MWh; fixed end 2027
• Teesside Renewable Energy Project (299 MW, dedicated biomass CHP) — MGT Power Limited; TCD 31/07/2018; £125/MWh; 15-year term

Shareholder notes (important for downstream enrichment):

• Hornsea 1: SA.38758 ¶24 explicitly notes "current ownership is not reflective of anticipated ownership at the closure of the contract, before which DONG Energy Wind Power A/S will have taken 100% ownership." DONG Energy (now Ørsted A/S) did indeed take 100% ownership in 2016, then brought in Global Infrastructure Partners (50%) during construction (2018).
• Dudgeon: Statoil (now Equinor) held 70% at FIDER award. In October 2017 Masdar acquired Statkraft's 30% share; in 2019 China Resources acquired 10%. Current ownership (2024): Equinor 35%, China Resources 35%, Masdar 20%, CNIC 10%.
• Beatrice: SSE later sold 25% to Copenhagen Infrastructure Partners in 2017, and 25% to Red Rock Power (SDIC-owned) in 2017. SSE retained 40%. Current ownership (2024): SSE 40% / CIP 25% / Red Rock Power 25% / Ensco (Repsol succeeded by Ensco in 2017) 10%.

11. Evaluation of FIDER as a mechanism — the NAO critique

The NAO report is unusually direct about the scheme's value-for-money profile. Its headline conclusion (¶17): "We are not convinced that it was essential to award so much consumer support to early contracts in order to meet the 2020 renewables target. Awarding so many early contracts of this scale in this way has limited the Department's opportunity to secure better value for money through competition under the full regime."

The NAO's specific criticisms relevant to Axis-3 (price discovery), Axis-4 (scoring), and Axis-5 (allocation mechanics):

1. Scale relative to budget (NAO ¶12, ¶15): FIDER awards committed £16.6 bn of £28.6 bn lifetime renewables-CfD support, or ~58% of the 2015/16-to-2020/21 renewables-CfD envelope of ~£6.9 bn. "The Department's decision to award up to £16.6 billion of early contracts without price competition limits the budget available for later allocation rounds that can use price competition."

2. Phase-agnostic strike prices (NAO ¶14 bullet 3): "The Department offered the same strike price to all phases of offshore wind projects, denying consumers the opportunity to share in any benefit for developers as technological innovation reduces costs." This is a deliberate design choice consistent with supply-chain procurement timing (developers procure for all phases at FID of phase 1) but it has a long tail of lifetime cost — estimated by NAO as driving ~£55 m/year across the FIDER OSW fleet.

3. No clawback provisions (NAO ¶14 bullet 4): "The Department has not included provisions to clawback a share of any excessive returns in early contracts. It considered that to do so might deter prospective investors." The only downside-risk-sharing mechanism in FIDER is the two-way difference payment — if the market price exceeds the strike price, the Generator pays the difference back. But there is no IRR-based or project-level excess-return recovery.

4. No disclosure of actual project returns (NAO ¶14 bullet 2): "The Department did not ask for information on estimated project costs and returns, for its own evaluation, since it was not setting project-specific strike prices. It sought that information from applicants to enable the European Commission to consider the risk of over-remuneration as part of its 'state aid' review. The Department has not required contract holders to give information about actual costs and returns." Under subsequent CfD reforms (AR7 2025), strike-price disclosure and non-price factors including supply-chain and carbon disclosure have been added; this NAO concern is partially addressed for later rounds but FIDER contracts themselves remain opaque on project returns.

5. The "5 months of acceleration" framing (NAO ¶10, ¶11): NAO finds that FIDER gave developers "certainty of support at least five months earlier than under the full Contracts for Difference regime" (23 April 2014 vs AR1 results 26 February 2015). But developers' own binding applications claimed 12–24 months of delay risk without FIDER. The NAO did not independently verify this claim and implies it might have been overstated — "this will depend on attrition rates for projects with planning consent. Even had some capacity been lost or delayed because it did not receive an early contract, the Department might still expect to meet its targets" (¶13).

The Independent Evaluation by Grant Thornton and Pöyry (October 2015), commissioned by DECC, reaches a more favourable conclusion on FIDER's effectiveness against its narrow scheme objectives (scheme objectives were "enable developers to take FID" and "support the long-term growth and economic viability of industries associated with renewable generation"; on both the Evaluation judged the scheme largely successful). The two documents represent different lenses: NAO audits consumer-value; Independent Evaluation audits scheme-objective attainment. Both are appropriate citations depending on the claim being made.

12. Authorities and jurisdiction

FIDER's authority architecture is distinctive because it combines statutory, contractual, and international-regulatory roles:

Role	Authority	Statutory / contractual basis
Scheme design and allocation	Department of Energy & Climate Change (DECC)	Energy Act 2013 Schedule 2; Update 1/2/3 (administrative)
Statutory Secretary-of-State statements (per-project)	Secretary of State for Energy & Climate Change (Rt Hon Edward Davey MP at signature)	Energy Act 2013 Schedule 2 ¶1(5)
Initial contract counterparty	Secretary of State	Energy Act 2013 Schedule 2 ¶1(1)
Post-transfer counterparty	Low Carbon Contracts Company Ltd (LCCC)	Energy Act 2013 Schedule 2 + Framework Agreement between DECC and LCCC
Settlement administration (suppliers-levy mechanism)	LCCC	Electricity Market Reform (General) Regulations 2014
Phase 2 evaluation	DECC heads of specialism, with BIS secondees and external consultants	Update 2
LCF envelope determination	HM Treasury (with DECC)	LCF settlement
State aid scrutiny	European Commission DG Competition	Treaty on the Functioning of the European Union Article 108(3); Environmental and Energy State aid Guidelines 2014/C 200/01
Parliamentary scrutiny	Parliament (laying Investment Contracts with accompanying statements)	Energy Act 2013 Schedule 2 ¶1(5), ¶2(3)

DECC as dual-role authority: FIDER is unusual in having DECC simultaneously as scheme designer, evaluator, and (initially) contract counterparty. The subsequent transfer to LCCC, once operational, addressed the conflict-of-interest optics but did not change the commercial substance.

Post-devolution note: Beatrice is located in Scottish Territorial Waters, but FIDER was administered by DECC (UK-level) not Crown Estate Scotland or a Scottish Government body. This is because revenue-support is reserved to Westminster under the Scotland Act 1998 (even post-2016 Scotland Act revisions to Crown Estate Scotland leasing powers). Seabed leasing for Beatrice was awarded separately by the Crown Estate (pre-devolution 2017) as part of the 2010 Scottish Territorial Waters round.

13. Post-award developments (2014–present)

Delivery outcome: 100% — all 5 offshore-wind projects and all 3 biomass projects were commissioned (albeit several with substantial delays and capacity deviations from the contracted cap). Below, offshore-wind project-by-project summary:

• Burbo Bank Extension (258 MW contracted): commissioned May 2017 — 32 × MHI Vestas V164-8.0 MW, the first commercial deployment of 8 MW-class turbines globally. Delivered on time against original Target Commissioning Date (31/03/2017). Built by Dong Energy (now Ørsted) with 50% divested to PKA/KIRKBI in 2017 post-commissioning.
• Dudgeon (402 MW contracted): commissioned October 2017 — 67 × Siemens SWT-6.0-154. Three phases with TCDs 01/03/2017, 01/08/2017, 01/10/2017; full array commissioning effectively completed October 2017. Built by Statoil/Statkraft (Statoil renamed to Equinor May 2018); Masdar acquired 35% from Statkraft October 2017.
• Walney Extension (659 MW commissioned, vs 660 MW contracted): commissioned September 2018 — distinctive hybrid turbine layout of 40 × MHI Vestas V164-8.25 MW + 47 × Siemens SWT-7.0-154. At commissioning, briefly the world's largest operating offshore wind farm before being overtaken by Hornsea 1. Ørsted retained operational ownership; PKA/KIRKBI acquired 50% pre-commissioning (October 2017).
• Beatrice (588 MW operational, vs 664 MW contracted — 11.4% reduction): commissioned 20 May 2019 — 84 × Siemens Gamesa SWT-7.0-154. Capacity reduction within the permitted FIDER tolerance (NAO ¶13 notes developers could "reduce their initially planned capacity by up to 36 per cent without penalty"). Ownership at commissioning: SSE 40% / CIP 35% / Red Rock Power 25%. Ensco-Repsol exit completed 2017.
• Hornsea Project One (1,218 MW operational, vs 1,200 MW contracted — marginal 1.5% over-delivery): commissioned in phases October 2019 through early 2020 — 174 × Siemens Gamesa SG 7-154. At commissioning, the world's largest operating offshore wind farm and the first commercial deployment of a 7 MW-class offshore turbine at >1 GW scale. 50% sold to Global Infrastructure Partners (GIP) in 2018 during construction; Ørsted retains operational 50%.

Strike-price evolution (offshore-wind averaged): compare the FIDER administrative £140-£150/MWh (2012 prices) with subsequent CfD allocation rounds at the same 2012 price basis:

Round	Year	OSW clearing SP (2012 £/MWh)	Context
FIDER	2014	£140 / £150	Administrative
AR1	2015	£114.39 / £119.89	Competitive; 14–18% below £140 ASP
AR2	2017	£57.50 / £74.75	Competitive; 59% below £140 ASP
AR3	2019	£39.65 / £41.61 / £41.61	Competitive; 70% below £140 ASP
AR4	2022	£37.35	Competitive; ASP was £46 (2012)
AR5	2023	No clearing	ASP £44 too low to attract bids
AR6	2024	£54.23 (P2) / £58.87 (P3 OSW)	Competitive; ASP lifted to £80 (2012) for Pot 3 OSW
AR7	2025	£58.00 (fixed, RoGB 2024 prices = ~£48 in 2012)	Refined design post-AR5 failure

FIDER sits at the top of this trajectory and anchors it. AR1's 2017/18 clearing of £119.89/MWh is often cited as vindication of competitive allocation; it came in 14% below the same £140 ASP that FIDER's Beatrice and Hornsea 1 accepted without competition. On a nominal-cost basis, the NAO's £16.6 bn lifetime-cost estimate for FIDER's eight projects would have been reduced by several billion pounds if the same offshore-wind projects had been competitively auctioned at AR1 prices.

Scheme-level retrospective (Independent Evaluation, October 2015): Grant Thornton and Pöyry concluded that FIDER "contributed to securing around £12bn in new investment in renewable electricity generation" (per GT/Pöyry report §3), that it "avoided an investment hiatus" consistent with its primary stated objective, and that the selection process "was effective in choosing projects likely to deliver." The Evaluation did NOT fully address the NAO's principal consumer-value criticism (the absence of price competition), but did note residual uncertainty on whether some projects would have proceeded without FIDER given alternative RO grace-period pathways.

Policy legacy: FIDER's design elements that subsequently informed CfD policy include:

• The 5 Phase-1 Qualification Criteria — substantially preserved (with modifications) as the CfD Qualification Checks in Schedule 4 of subsequent Allocation Frameworks
• The TCD / TCW / Longstop / Milestone Delivery Date lattice — directly transferred to the CfD Standard Terms
• The phased-offshore-wind design — generalised in AR1+ as the Phased Offshore Wind CfD Unit construct, though with stricter phase-sequencing rules
• The administrative-pricing-first-then-competition design — not repeated for any subsequent renewables technology in the UK context. FIDER is therefore a one-off in UK auction policy

14. Schema implications

FIDER stresses the 9-axis auction schema in several ways. What follows is a practitioner read of where fields need to be populated, and where the schema may need to stretch, for an Auction record to faithfully represent FIDER.

Axis 1 — Prize consideration:

• primary_component.price_type = administrative (not competitively cleared)
• primary_component.revenue_instrument_type = CfD (two-way, 15-year, CPI-indexed)
• primary_component.duration_years = 15 (offshore wind and biomass CHP)
• For biomass conversions, primary_component.duration_years = null with a fixed_end_date of 2027 — schema should accommodate either duration-based or fixed-end-date CfD terms (AR1+ only uses duration; FIDER is the first to need fixed-end-date)
• primary_component.indexation = CPI_annual_1_April_from_2012_base
• primary_component.reference_price_type = IMRP (offshore wind); BMRP (biomass conversions, biomass CHP)
• strike_price varies per-project (£140 or £150 for OSW); ideally represented on the auction_results record, not on the auction record, because it is not auction-level cleared

Axis 2 — Competition mechanism:

• auction.award_category = bilateral or new category administrative_selection (CURRENTLY NOT IN SCHEMA — FIDER is the first UK case requiring this)
• competition_mechanism = threshold_evaluation + affordability_down_selection — no price component; there is no clearing price or margin of competition
• auction_type = transitional / pre_CfD_bilateral — specific to FIDER

Axis 3 — Qualifying gates:

• 5-part Phase 1 test is cleanly representable as a qualifying_gates array with 5 binary pass/fail entries
• Minimum thresholds on Level 2 (1.1 and 1.2) each require ≥50 out of 100 — representable as numeric gates
• The "investment-hiatus risk" requirement (Qualification Criterion 2(ii)) is a substantive qualitative gate without a numerical threshold — schema should allow gate_type = qualitative_assessment alongside numeric thresholds

Axis 4 — Scoring dimensions:

• 3-level hierarchical scoring tree with weights at each level. Schema scoring_dimensions needs to handle nested hierarchy. Currently (UK AR6/AR7) supports flat scoring dimensions
• 8 Level-3 criteria roll up to 2 Level-2 groups roll up to 2 Level-1 groups. An explicit hierarchy_depth field or a nested parent_dimension_id would make this expressible
• Minimum thresholds per dimension (pink-flagged Level 3, and ≥50 on L2 for 1.1 and 1.2) should be a per-dimension field, not a whole-application gate

Axis 5 — Tiebreak chain:

• Two-step tiebreak: 1.1.1 Technical Solution score (descending) → 1.2.1 Financing Plans score (descending). Representable as tiebreak_chain =
• If still tied, bracket-advance equally — schema should allow on_ties_after_chain = bracket_advance | random | subjective

Axis 6 — Revenue mechanism: represented under Axis 1 primary_component — FIDER has no separate Axis-6 revenue mechanism beyond the CfD itself (no lease, no option fee, no supply-chain bonus, no capacity payment)

Axis 7 — Authorities:

• DECC as offtake_authority and (initially) counterparty
• LCCC as counterparty (post-transfer)
• European Commission as scheme_scrutiny_authority (state aid approval — analogous to CMA SAU post-Brexit)
• Parliament as laying_authority (per Energy Act Schedule 2)
• This is 4–5 distinct authorities on a single auction. Schema should confirm it can express all five roles on one auction, with multi-role assignment allowed (DECC is both offtake and initial counterparty)

Axis 8 — Process/timeline:

• Standard timeline representation works. Notable event types: statutory_assent, state_aid_clearance, counterparty_transfer
• state_aid_clearance as a suspensive condition (payment obligation contingent on EC decision) is FIDER-specific and may not appear for post-Brexit auctions — schema should not assume it's always present or always absent

Axis 9 — Market context:

• Extensive — dominated by the RO-to-CfD transition narrative. Most of this is qualitative and lives in research_writeup rather than structured fields
• Quantitative Axis-9 facts worth preserving: 58% of 2015/16-to-2020/21 renewables CfD budget consumed (NAO); £16.6 bn lifetime cost (NAO); 5 of 8 OSW applications got contracts (out of 12 Phase 2 submissions); all 5 OSW commissioned with 100% delivery rate (post-award)

New schema patterns worth proposing (revisions):

1. award_category = administrative_selection — as a sibling to competitive and bilateral. FIDER is the anchor case; similar schemes may exist in other jurisdictions (German CfD bridging schemes, French early concessions).

2. Hierarchical scoring_dimensions — L1/L2/L3 with weights at each level, minimum-threshold annotation per dimension, and tiebreak chain cross-referencing specific Level 3 criteria.

3. primary_component.fixed_end_date as an alternative to duration_years — accommodates biomass-conversion-style contracts that end on a calendar date rather than rolling off from commissioning.

4. strike_price_attribution_rule — for phased projects, records whether the Strike Price is phase-level (as AR1+ CfDs permit via separate CfD Units per phase) or first-phase-indexed (as FIDER uses). This is a subtle but load-bearing field given NAO's critique.

5. bidder_counts in an "administrative" context — reinterpreted as "applicants at each stage of a funnel": 57 Phase 1 → 26 Phase 2 → 16 Qualifying → 8 Awarded. Schema should allow this as a participation_funnel field distinct from bidder_counts (which implies price bids).

6. state_aid_case_ids — multi-valued field on Auction for bundled or split state-aid cases. FIDER has 5 cases (SA.38758, SA.38759, SA.38761, SA.38763, SA.38812) bundled into one decision + 1 parallel case (SA.36196). This merits explicit field support.

These are proposed additions, not blockers for seeding. The main blocker for FIDER is the first one (administrative_selection as a first-class award_category value) — if it is not accepted, the pilot cannot be faithfully represented. See §7 of the Axis-1 schema sketch.

15. Verification queue

Items flagged during research that should be confirmed or resolved before or during extraction:

1. The identity of the 2 non-awarded Qualifying Offshore Wind Projects. RESOLVED 2026-04-20. The complete 16-project Qualifying list was published on GOV.UK alongside Update 3 (4 December 2013) in the "Record investments of £40 billion in renewable electricity" press release. The 2 unsuccessful Qualifying OSW projects are Inch Cape Offshore Wind Farm (Inch Cape Offshore Limited) and Neart na Gaoithe Offshore Wind Farm (UK Mainstream Renewable Power Ltd). Both subsequently won CfDs — NnG at AR1 (2015, £114.39/MWh, 448 MW); Inch Cape at AR4 (2022, £37.35/MWh, 1,080 MW). The DECC-identified 16 Qualifying Projects also include Drax 2nd conversion unit (Unit #3), Eggborough 1st/2nd/3rd Units (4 biomass conversions not awarded), Beinn Mhor Wind Farm and Heckington Fen (2 onshore wind not awarded) — all out of offshore-wind scope.

2. Total biomass application funnel. Update 3 summary table gives Phase 2 and Qualifying numbers per technology but not Phase 1. The Phase 1 57-application figure is from NAO; the technology split at Phase 1 is not in the source docs. Out of scope — biomass is not being seeded into the FIDER auction record.

3. Confirmation of "Phase 2 close: 6 September 2013" deadline. Update 2 Annex A gives 12.00 BST (midday) 6 September 2013. Update 3 ¶10 confirms this was observed. Extraction should cite Update 2 for the deadline itself.

4. Teesside REP fate. OUT OF SCOPE 2026-04-20. Teesside REP is a biomass project and will not be seeded as part of the FIDER auction record. PKA (Danish pension fund) equity position and Enviva Partners pellet-supply contract confirm the project did progress to construction, but final commissioning-status confirmation is deferred to any future biomass-focused pilot.

5. Exact ownership at contract signature vs award announcement for Hornsea 1. SA.38758 Table 2 lists DONG/Siemens/Mainstream at 33.3% each at award, but ¶24 notes DONG would take 100% ownership before contract closure..

6. Interplay between Investment Contract and AR1/AR2 for the same project. None of the 5 FIDER OSW awards participated in AR1 (nor could they have, by one-off-choice-of-scheme). Some developers (e.g. Mainstream, Statoil) participated in AR1/AR2 with other projects. Extraction should verify no double-counting in the cross-auction project registry.

7. Post-award contract register alignment. LCCC's CfD Register has entries for the 5 FIDER OSW contracts under allocation_round_short: "INV" / allocation_round: "Investment Contracts" (biomass rows not seeded). The registry_enrichment stage 5 of commit_auction.py should populate these..

16. Bibliography — primary sources cited

All sources are in docs/research/offshore-wind-auctions/source-docs/uk_fider/ with YAML frontmatter and source URLs:

• successful-projects.md — DECC "FID Enabling for Renewables: Successful Projects offered an investment contract" (23 April 2014). Definitive award list.
• update-1-invitation.md — DECC "FID Enabling for Renewables: Update 1 — Invitation to Participate" (14 March 2013). Qualification Criteria and Phase 1 process.
• update-2-allocation.md — DECC "FID Enabling for Renewables: Update 2 — Investment Contract Allocation" (27 June 2013). Evaluation Criteria, scoring, down-selection design.
• update-3-contract-award.md — DECC "FID Enabling for Renewables: Update 3 — Contract Award Process" (4 December 2013). LCF envelope, technology-based down-selection rules, selection algorithm, Phase 2 results summary.
• impact-assessment.md — DECC "Electricity Market Reform (EMR) FID Enabling for Renewables — Impact Assessment" (27 June 2013). Rationale and counterfactual.
• nao-early-contracts.md — National Audit Office "Early contracts for renewable electricity" HC 172 Session 2014-15 (27 June 2014). Primary source for strike prices, cost of support, and value-for-money critique. Figure 1 is the most useful structured table in the entire FIDER corpus.
• ec-state-aid-sa38758-osw-projects.md — European Commission Decision C(2014) 5074 final on cases SA.38758, SA.38759, SA.38761, SA.38763, SA.38812 (23 July 2014). Primary source for beneficiary identification, shareholder structure at award, and state aid compatibility analysis.
• ec-state-aid-sa36196-cfd-scheme.md — European Commission Decision C(2014) 5079 final on case SA.36196 (23 July 2014). Parallel approval of the CfD for Renewables Scheme (AR1+).
• independent-evaluation.md — Grant Thornton and Pöyry, "Independent Evaluation of FID Enabling for Renewables — Final Report" (15 October 2015), commissioned by DECC. Retrospective scheme-objective evaluation.
• ifg-case-study.md — Institute for Government, "The development of the UK's offshore wind sector 2010–16" (October 2023). Political-economy context and policy-reunion insights.

Documents not fetched for this pilot (available but supplementary):

• Full Investment Contract signed texts (IC_A-C.zip, IC_D-F.zip, IC_H-S.zip, IC_T-Z.zip — gov.uk) — ~30 MB of contract PDFs, useful for bespoke clause-level detail but redundant for Axis-1-through-8 extraction
• EMR Delivery Plan (December 2013) — source for administrative strike prices; redundant given NAO Figure 1 captures the needed values
• Energy Act 2013 statutory text — cross-referenced at the clause level in EC SA.38758