Contracts for Difference (CfD) Allocation Round 4

UK CfD Allocation Round 4 (AR4, 2021–2022)

The record-low round that broke its own contracts. AR4 was the largest UK Contracts for Difference allocation ever run at the time — 10.8 GW across 3 pots, 96 contracts signed, offshore wind cleared at £37.35/MWh (2012 prices), 70% below AR1's 2015 clearing price. Five offshore wind projects secured 6,994 MW of CfDs at that single clearing price: Hornsea 3, East Anglia 3 Phase 1, Norfolk Boreas Phase 1, Inch Cape Phase 1, and Moray West. Eighteen months later the largest of those exits — Vattenfall wrote off Norfolk Boreas in July 2023 at SEK 5.5bn (£400m), citing 40% cost inflation. AR4 is the causal upstream of AR5's failure, AR6's emergency uplift, and AR7's 20-year-term reform.

1. At a glance

• Sponsor: Department for Business, Energy and Industrial Strategy (BEIS) — re-named Department for Energy Security and Net Zero (DESNZ) in February 2023
• Delivery Body: National Grid Electricity System Operator Limited (NG ESO), acting as EMR Delivery Body — subsequently re-constituted as NESO in October 2024
• Counterparty: Low Carbon Contracts Company (LCCC)
• Scrutiny regime: Post-Brexit UK Subsidy Control (no EU State aid decision)
• Application window: 13 December 2021 – 14 January 2022
• Auction held: sealed bids invited after NG ESO's qualification and valuation; auction closed prior to 7 July 2022
• Results published: 7 July 2022, 07:00 BST
• Overall budget (2011/12 prices, per Delivery Year): £10m / £10m / £285m / £285m / £275m / £275m across 2023/24 to 2028/29; uplifted by the 20 May 2022 Budget Revision Notice by +£10m per year in the four years 2025/26–2028/29, applied only to Pot 3 (Pot 3 moves £200m → £210m in each of those four years; the revised overall-budget table becomes £10m / £10m / £295m / £295m / £285m / £285m)
• Pot structure: three pots — Pot 1 (established tech, £10m/yr), Pot 2 (less-established tech, £75m/yr with hard Minima for floating OSW and tidal), Pot 3 (offshore wind, £200m → £210m per Delivery Year)
• Technologies eligible: 15 technology types across three pots (ACT, AD, Dedicated Biomass w/CHP, EfW w/CHP, Floating Offshore Wind, Geothermal, Hydro, Landfill Gas, Offshore Wind, Onshore Wind, Remote Island Wind, Sewage Gas, Solar PV, Tidal Stream, Wave)
• Offshore wind ASP: £46/MWh (2012 prices)
• Offshore wind clearing: £37.35/MWh (2012 prices) — 19% saving on ASP
• Auction format: sealed-bid, pay-as-clear per auction segment (not one clearing price per pot — Maxima-subject technologies clear at their own Maximum-only clearing price under Rule 17.4(d); Minima-subject technologies clear in their own Minimum auctions under Rule 16). With optional Flexible Bids per application
• Revenue instrument: two-way CfD, 15-year term, CPI-indexed strike price, reference price (Seasonal Baseload / Intermittent Market Reference Price by technology)
• Contract form: CfD Standard Terms and Conditions 2021 (542 pages); Generic Agreement wrapper (30 pages); phase-specific and private-network variants; first CfD round drafted under the UK's post-Brexit subsidy control regime — though DESNZ reserved the right to further amend the contract's Subsidy definition before AR4 contracts were signed and the AR4 Generic Agreement still references the language of "Subsidy, state aid and/or union funding"
• Offshore wind winners: 5 projects / 5 SPVs / ~6,994 MW
  • Hornsea Project Three (Ørsted) — 2,852 MW, England — single phase
  • East Anglia 3 Phase 1 (ScottishPower Renewables / Iberdrola) — 1,372 MW, England — 3 phases
  • Norfolk Boreas Phase 1 (Vattenfall) — 1,396 MW, England — 3 phases
  • Inch Cape Phase 1 (Red Rock Power / ESB Asset Development) — 1,080 MW, Scotland — 3 phases
  • Moray West (Ocean Winds — ENGIE/EDPR JV) — 294 MW, Scotland — single phase (partial CfD on a larger 882 MW project)
• Post-award fate: Norfolk Boreas withdrawn by Vattenfall on 20 July 2023; the Norfolk zone (Boreas + Vanguard East + Vanguard West) sold to RWE in December 2023 for £963m; Norfolk Boreas subsequently re-entered the CfD pipeline via AR7 as part of the Norfolk Vanguard East/West CFD Units (different configuration)

2. Market context at the time of the auction

AR4 opened in December 2021 into a market defined by three converging drivers. The 40 GW by 2030 commitment — announced in the Prime Minister's Ten Point Plan for a Green Industrial Revolution (November 2020) — framed AR4 as the round that had to demonstrate delivery velocity could accelerate to match the target. At the time of AR4's closing in early 2022, operational UK offshore wind stood at around 11 GW with another 10–13 GW in construction or consented — meaning AR4 had to deliver a meaningful share of the 17–19 GW gap.

The post-Brexit regulatory reset shaped the AR4 contract drafting. The UK formally left the EU State aid regime on 1 January 2021. AR4 was drafted in the transitional post-EU period: the Subsidy Control Act 2022 received Royal Assent on 28 April 2022 (mid-round, after the auction had closed), replacing the interim regime under the TCA. BEIS's November 2021 government response to the 2020 consultation on "proposed amendments to the CfD scheme" confirmed the rewrite of EU State aid references to subsidy-control language — though DESNZ reserved the right to further amend the "Subsidy" definition before AR4 contracts were signed, and the final published Generic Agreement still references the composite phrase "Subsidy, state aid and/or union funding" in cumulation clauses (reform-response-2020.md, §Explanation of changes; generic-agreement.md).

The commodity shock was still nascent at auction. Russia's full-scale invasion of Ukraine began on 24 February 2022, between application close (14 January 2022) and auction close (before 7 July 2022); the resulting inflation in steel, copper, and offshore installation vessels began to bite in mid-2022 and intensified through 2023. Bidders submitted 2012-priced bids in early 2022 on the basis of cost curves estimated during 2020–21 (via the September 2021 ASP methodology, see §7). This lag between bid and cost realisation is the proximate cause of the Norfolk Boreas cancellation (§17).

Predecessor rounds provided a competitive baseline: AR3 (2019) had cleared fixed-bottom offshore wind at £39.65/MWh (2012 prices) for the 2023/24 and 2024/25 Delivery Years — a 30% fall from AR2's £57.50/MWh. Commentators widely expected AR4 to continue the decline curve. The £37.35/MWh clearing price for 2026/27 was slightly above AR3's 2024/25 — a compression of the fall, but not a reversal.

3. Regulatory frame

AR4 operates under a stack of three nested instruments:

1. Energy Act 2013 (primary) — section 6 empowers contracts for difference; section 11 empowers publication of Standard Terms; section 13 establishes Allocation Rounds; section 14 is headed "CFD notification: offer to contract on standard terms"; further sections 15–22 set out delivery-body, counterparty, and enforcement arrangements.

2. Contracts for Difference (Allocation) Regulations 2014 (SI 2014/2011, as amended) — the secondary legislation governing all CfD allocation mechanics. Key amendments affecting AR4 were made by the Contracts for Difference (Allocation) (Amendment) Regulations 2020 and 2021, introducing: separate Pot 3 for offshore wind, floating offshore wind as a distinct technology class, reformed SCP post-award monitoring, and the single-ASP-per-Delivery-Year approach. Each AR publishes its own Allocation Framework under these Regulations.

3. Contracts for Difference (Definition of Eligible Generator) Regulations 2014 (SI 2014/2010) — defines which stations can apply; amended alongside the 2020 consultation to exclude coal-to-biomass conversions from eligibility (reform-response-2020.md §Coal-to-biomass).

4. Contracts for Difference (Standard Terms) Regulations 2014 (SI 2014/2012) — defines the counterparty (LCCC) and the authority to publish Standard Terms.

A set of AR4-specific statutory notices and supporting instruments were published together on 25 November 2021, signed by Sarah Redwood (Director Renewable Electricity) on behalf of the Secretary of State:

• Allocation Round Notice (Regulation 4) — establishing AR4 and setting the Application Window dates
• Budget Notice (Regulation 11) — setting the £285m peak overall budget (2011/12 prices, 2025/26 and 2026/27 Delivery Years) and per-pot structure (budget-notice.md)
• CFD Framework Notice — identifying which Allocation Framework applies to AR4
• Standard Terms Notice — identifying the applicable CfD Standard Terms
• Counterparty Costs Notice — covering LCCC costs passed through to levy
• Allocation Framework — the 89-page rule book itself (allocation-framework.md), published alongside but technically the subject of the CFD Framework Notice rather than a statutory notice in its own right

A mid-round Budget Revision Notice was issued 20 May 2022 under Regulation 12 (budget-revision-notice.md) — the first Pot 3 uplift under this instrument and the precursor mechanism for the much larger AR6 (+£530m) and AR7 (£900m → £1,790m Pot 3) uplifts in later rounds.

4. Pre-round preparation and timeline

AR4 is the first round whose design reflects the full 2020 consultation-and-response cycle. The table below records the full lifecycle from policy signal to post-auction events.

5. The prize — CfD contract mechanics

Each AR4 winner receives a Contract for Difference Agreement between the Generator and the CfD Counterparty (LCCC). The CfD is a 15-year revenue-support instrument: Generic Agreement §3 defines the Specified Expiry Date as "the 15th anniversary of the earlier of the Start Date and the last day of the Target Commissioning Window" (Generic Agreement, generic-agreement.md). The Generic Agreement is a 30-page wrapper that incorporates the 542-page Standard Terms and Conditions by reference (standard-terms-and-conditions.md).

Revenue mechanism in essence:

• If the market price (Reference Price, defined by technology — see below) < Strike Price: LCCC pays Generator the difference per MWh of Metered Output, multiplied by the Transmission Loss Multiplier (TLM) and any applicable Renewable Qualifying Multiplier (RQM).
• If the market price > Strike Price: Generator pays LCCC the difference per MWh.

The Strike Price is set in 2012 prices and CPI-indexed annually to maintain real value. Payments are made monthly on Calculated Amount based on half-hourly generation data.

Reference Price — two layers, not to be conflated:

Valuation (pre-auction, NG ESO): Allocation Framework Schedule 2 Appendix 2 sets out five reference-price series in 2012 prices used to value each Qualifying Application against the budget: Baseload, Hydro, Offshore Wind, Onshore Wind, and Solar PV Reference Prices. Schedule 3 maps each technology to which series is applied (e.g. Offshore Wind applications valued against the Offshore Wind Reference Price; Tidal Stream and Wave valued against the Baseload Reference Price in the valuation formula).

In-life settlement (post-award, LCCC): the Budget Notice accompanying note confirms that the Low Carbon Contracts Company uses (i) the Baseload Market Reference Price (BMRP) — a season-ahead day-ahead baseload index — for baseload technologies; and (ii) the Intermittent Market Reference Price (IMRP) — an hourly day-ahead weighted-average — for intermittent technologies including offshore wind. These in-life reference prices differ from the valuation-formula prices and drive actual monthly CfD payments.

The two layers serve different purposes: valuation establishes whether an auction is triggered and what monetary-budget impact each bid has; in-life settlement establishes the monthly payment mechanics over the 15-year contract term.

Key Standard Terms provisions relevant to extraction (drawn from the 542-page Standard Terms and Conditions published 30 November 2021, AR4-specific amendments summarised in reform-response-contract-2021.md):

• Target Commissioning Window (TCW): technology-specific window ending on the Target Commissioning Date (TCD), per AR4 Standard Terms Notice Table G — 12 months for Offshore Wind, Floating Offshore Wind, Onshore Wind, Remote Island Wind, Tidal Stream and Wave; 6 months for Landfill Gas; 3 months for Solar PV. Missing TCW triggers remedies below.
• Longstop Period and Longstop Date: per AR4 Standard Terms Notice Table H — 24 months for Offshore Wind; 12 months for Floating OSW, Onshore Wind, Solar PV, Remote Island Wind, Tidal Stream and Wave. Longstop Date = TCW end + Longstop Period. After Longstop, LCCC may terminate.
• Milestone Requirements: Generator must meet Milestone Requirement (MR) — typically evidence of construction commitment (procurement contracts + total project spend ≥10% of estimated capex). AR4 extended the Milestone Delivery Date from 12 to 18 months after CfD signing (Reform Response Contract 2021 confirms this change). Missing MR triggers a Milestone Delivery Date; failure at the subsequent Longstop triggers termination.
• Non-Delivery Disincentive (NDD): Generators who fail to meet capacity targets within the delivery window are excluded from subsequent CfD rounds for their affected capacity. NDD pre-existed AR4 — the 2020 government response (reform-response-2020.md) explicitly states "The Non-Delivery Disincentive (NDD) currently penalises non-compliant developers…" — but AR4 retained the NDD regime as a binding constraint on the round's offshore wind winners, a mechanism later commentary credits for restricting "option value" gaming on low-priced CfDs.
• Change in Law (CIL) mechanism: bespoke and non-bespoke CIL categories; generator-favourable pass-through for non-bespoke qualifying changes.
• Balancing Services Use of System (BSUoS) treatment — AR4 introduced an alternative Strike Price adjustment formula to address the pending BSUoS charging reforms. See reform-response-contract-2021.md §Balancing Services Use of System Charges.
• Initial Conditions Precedent (ICP) fulfilment period: extended from 10 to 20 business days vs prior CfD rounds (reform-response-contract-2021.md §Subsidy Control).
• Curtailment: Generator compensated for Metered Output that would have been generated but for grid-instructed curtailment (calculated via the Curtailment Adjustment Amount). Negative-price exclusions: AR4 strengthened the negative-pricing rule from the prior six-consecutive-hours threshold (per the 2020 consultation response): top-up payments cease whenever the Intermittent Market Reference Price is strictly negative, with no hours threshold. This is a material reform vs AR1–AR3, which required six consecutive hours of negative pricing before payments were withheld.
• Asymmetric modifications: where a Change in Law benefits only the Generator, the strike price can be reduced (a rare but existing clause).

There is no Clean Industry Bonus (CIB) in AR4 — the CIB was introduced for AR7 via the 2024 Targeted Reform of Allocation Rounds package. AR4 is purely price-competitive (see §9 on Scoring).

6. Budget architecture

AR4's budget structure is the archetype for the three-pot era. The Budget Notice (25 November 2021) specified the opening budget; a Budget Revision Notice (20 May 2022) uplifted it mid-round. All values are 2011/12 prices.

6.1 Initial Budget Notice (25 November 2021)

Table 1: Initial overall + per-pot monetary budget

The 2023/24 and 2024/25 entries are pure Pot 1 (Onshore Wind, Solar PV, EfW with CHP, Hydro, Landfill/Sewage Gas) — these technologies have shorter build times, so their earlier Delivery Years sit outside Pot 2 and Pot 3's delivery windows. Pot 2 and Pot 3 share overlapping 2025/26–2028/29 Delivery and Valuation Years.

Table 2: Capacity-denominated constraints (Pot 1 only)

Both are hard Maxima ("will be applied on a capacity (MW) basis, to operate as 'hard' constraints") — Allocation Framework §Use of Maxima or Minima. No Soft Constraint applies. Onshore wind + solar PV compete within a combined 5,000 MW Pot 1 Capacity Cap, so they cannot both reach 3,500 MW simultaneously.

Table 3: Pot 2 hard Minima

• Floating Offshore Wind: £24m per Delivery Year (hard)
• Tidal Stream: £20m per Delivery Year (hard)

Both Minima are monetary and hard. Crucially, the Budget Notice specifies the order of Minimum auctions: "The Delivery Body will run the minimum auction for tidal stream first, followed by the minimum auction for floating offshore wind" (Budget Notice §Use of Maxima or Minima; cross-reference Allocation Framework Rule 15).

CPI-indexing of budget to 2012 base: the Budget Notice specifies the inflator factor 1.0193 (2011/12 → 2012 CPI) used by NG ESO to value 2012-price bids against the 2011/12-priced budget. Applied to the headline £285m, this yields a 2012-price budget of ~£290m (Budget Notice §Re-basing CfD Budgets).

6.2 Budget Revision Notice (20 May 2022)

The Secretary of State exercised the power under Regulation 12(5) — upward-only mid-round revision — to uplift Pot 3 alone:

Table 4: Revised Budget (post 20 May 2022)

The +£10m annual uplift (+£40m cumulative across four Delivery Years) is modest compared to the £530m AR6 uplift that followed, but AR4 established the precedent that Regulation 12(5) could be used to respond to Qualifying-Application valuations exceeding the opening budget. Budget Revision Notices must be issued at least one working day before effect (Regulation 13). Regulation 12(5) prohibits any downward revision and mandates that Maxima/Minima can only be increased if the overall budget increases by at least the same amount (see budget-revision-notice.md Schedule 2).

6.3 Interpretation of AR4's outcome against the revised budget

The published Results doc's Panel (C) — "Estimated actual monetary budget impact … presuming all offered contracts are accepted (2012 prices)" — shows Pot 3 with £0 estimated impact in 2025/26, 2026/27, and 2027/28, and £172.41m in 2028/29. That £172.41m sits within the revised £210m Pot 3 annual envelope. The panel is a NG-ESO-calculated estimate at the published clearing price against forecast Reference Prices at the time of the auction — not a statement that the pot was fully consumed. The absence of an AR5 Pot 3 uplift implies DESNZ judged AR4's Pot 3 budget sufficiently well-sized for the five winning projects at £37.35/MWh.

7. Administrative Strike Prices

ASPs act as reserve prices: no project may receive a Strike Price higher than the ASP for its Technology Type, even if the auction clears above it (ASP methodology doc §Section 1; Allocation Framework Rule 6.3, 9.3(a)). AR4 introduced a policy change: single ASP across applicable Delivery Years for each technology (vs separate ASPs per Delivery Year in AR1–AR3). The ASP is taken as the maximum of the delivery-year-specific calculations, rounded to the nearest £1/MWh (ASP methodology §Section 3).

7.1 Final ASPs (2012 prices)

From the Budget Notice Table 3:

7.2 Methodology — what makes AR4's ASPs distinctive

The ASP methodology (asp-methodology.md) sets ASPs by modelling each technology's supply curve (strike-price vs cumulative MW of pipeline that would be NPV-zero at that price), then selecting the price at which a targeted percentage of the pipeline becomes economically viable.

Targeting percentages — Objective 2 of ASP-setting:

• 25% of the supply curve for most technologies — the standard value-for-money anchor.
• 50% of the supply curve for Offshore Wind specifically — doubled vs all other technologies — to align with the 40 GW by 2030 target. The methodology doc states: "This approach is consistent with the Government response in November 2020, which expressed a potential need for greater flexibility when setting ASPs for specific technologies. This approach better reflects Government's decarbonisation objectives … the estimated supply curve for Offshore Wind is 'flatter' than many other technologies meaning significantly more supply can be targeted with a relatively small (<5%) increase in ASP, limiting any potential impact on competition." (asp-methodology.md §Offshore Wind and Remote Island Wind).

This is a capacity-driven ASP setting for offshore wind — a direct policy-priority adjustment to reserve-price mechanics. In data-model terms, ASP_supply_curve_target_percent = 50 is a per-technology override that AR4 is the first round to apply.

Price derivation inputs (offshore wind):

• Capital expenditure by turbine size (£/MW falls with increasing turbine MW per economies of scale)
• Load factors modelled from Met Office wind speed data + turbine power curves
• TNUoS charges by location (provided by National Grid)
• Decommissioning costs from BEIS ARUP model
• Connection costs, UoS charges, PPA discount, 15-year contract length, project lifetime post-CfD

Hurdle rates are sourced from the BEIS 2019 Europe Economics report (asp-methodology.md §Hurdle Rates); offshore wind hurdle rate is not disclosed in the published doc but is consistent with the 2020 Electricity Generation Costs report baseline.

Floating Offshore Wind — new eligible technology in AR4. The ASP methodology acknowledges bespoke treatment: "As an emerging technology, we have developed a bespoke approach to estimating generation cost assumptions for AR4. This has included incorporating evidence from a combination of sources, including but not limited to the Department's own estimates, information from the Offshore Renewable Energy Catapult (OREC) and industry intelligence" (asp-methodology.md §Floating Offshore Wind). £122/MWh ASP reflects pilot-scale project cost levels.

Remote Island Wind — not a separate technology in BEIS's generation cost estimates; AR4 used Baringa's 2013 Scottish Islands Renewable Project Final Report updated for onshore-wind cost reductions since 2013 (asp-methodology.md §Section 5).

7.3 Result: OSW ASP £46 vs AR3 clearing £39.65

The AR4 OSW ASP of £46/MWh (2012 prices) sat above the AR3 (2019) OSW clearing price of £39.65/MWh but well below AR3's ASP of £53/MWh. This partial ASP reduction relative to AR3 reflects continued cost-curve declines captured in the 2020 Generation Costs report, but the ASP remained deliberately liberal on the 50%-of-supply-curve targeting to encourage volume. The ultimate auction clearing price (£37.35/MWh) came in 19% below the ASP — significant headroom still existed at the point where the Pot 3 monetary envelope bound.

8. Qualification criteria

To submit a bid, every applicant must first be determined a Qualifying Application by NG ESO under Regulation 17. The Delivery Body applies a set of checks codified in Allocation Framework Schedule 5 (87 pages of application checks, covering general eligibility, technology-specific conditions, project-specific evidence). The high-level gates are:

8.1 General qualification gates (binary pass/fail, all technologies)

• Generator is an Eligible Generator under the Contracts for Difference (Definition of Eligible Generator) Regulations 2014 — excludes, inter alia, stations already Commissioned (Allocation Framework Rule 5.1 excludes CFD Units that are or are part of a Commissioned Generating Station).
• Planning consent for the Generating Station — project-specific evidence of permitted development, Development Consent Order, or equivalent consenting regime.
• Grid connection offer — accepted Connection Agreement from the relevant Transmission or Distribution network operator, specifying the Grid Supply Point and expected connection date.
• Developer declaration of intent — Generator commits to deliver the project if awarded CfD.
• Financial Commitment Milestone (FCM) capability — ability to meet the Milestone Requirement within 12 months of CfD signing.

8.2 Technology-specific gates (Allocation Framework §4)

• Phased Offshore Wind CFD Unit — where applying to phase the CfD, the applicant must demonstrate (§4.1(a)):
  • After all phases complete, CFD Unit capacity ≤ 1,500 MW
  • First phase ≥ 25% of total capacity
  • First phase targeted to complete by no later than 31 March of the last applicable Delivery Year
  • Target Commissioning Date of the final phase ≤ 2 years after the first phase's TCD
  • Maximum of 3 phases across a single CFD Unit
• Biomass with CHP and Energy from Waste with CHP — confirm awareness that the CfD requires a CHPQA Certificate as Further Condition Precedent, and that the CHPQM multiplier applies.
• Advanced Conversion Technology (ACT) — demonstrate compliance with the Physical Separation Requirement (between the Synthesis Chamber and the Combustion Chamber).
• Floating Offshore Wind — must meet the Floating Offshore Wind Conditions (Regulation 27ZA(4), carried into AR4 Schedule 5). Three cumulative requirements: (i) the CFD Unit must not form part of a Phased Offshore Wind CFD Unit (or any CFD Unit established or altered in phases of construction); (ii) all turbines forming part of the CFD Unit must be mounted on floating foundations; and (iii) all turbines must be situated in offshore waters of at least 45 metres depth (measured from the seabed to chart datum).
• Remote Island Wind — project on a Scottish Island with specific transmission connection; schematic diagram required (Rule 22.1(m)).

8.3 Supply Chain Plan (SCP) — the binary quality gate

For Offshore Wind projects (fixed-bottom or floating) of 300 MW or more, the applicant must hold a valid Supply Chain Plan Statement issued by BEIS as a condition of qualifying. This is a hard pre-auction gate: without the SCP Statement in place by the Application Closing Date, the application is non-qualifying (supply-chain-plan-guidance.md title — "Supply Chain Plan guidance for projects of 300MW or more applying for a Contract for Difference" — and §1 Purpose; Allocation Framework Schedule 5). The ≥300 MW threshold is the AR4 rule; later rounds (AR6 onwards) extended SCP obligations to all floating offshore wind regardless of size, but AR4's scope is size-gated only.

The SCP assessment is scored against BEIS's SCP Questionnaire (30 pages, supply-chain-plan-guidance.md). Principal SCP evaluation dimensions:

• Infrastructure: UK supply chain infrastructure investment commitments
• Innovation: innovation investment, demonstrator commitments, R&D
• Skills: skills/apprenticeship commitments in UK supply chain

BEIS scores responses; applicants passing the threshold receive an SCP Statement. AR4 is the first round to introduce post-award SCP monitoring:

• SCP Implementation Statement (SIS): required as a condition of continuing CfD eligibility at Milestone Delivery Date (MDD). Failure to meet SCP commitments post-award triggers SIS refusal and potential CfD termination (supply-chain-plan-guidance.md §4 Monitoring and §4 Assessment).

This post-award monitoring was the subject of the May 2021 consultation response (reform-response-2020.md §Supply Chain Plans; Reform Response 2021 incorporates final drafting changes).

8.4 Non-Qualification and Appeals

• Delivery Body must issue qualification determination no later than 30 working days after Application Closing Date (Allocation Framework §7.1).
• Applicant may request a Non-Qualification Review within 5 working days of the determination notice. Delivery Body must issue Non-Qualification Review Notice within 15 working days.
• Applicant may further appeal to the Authority (Ofgem) within 5 working days of the Review Notice — a Qualification Appeal under Regulation 43.

9. Evaluation criteria, process, and scoring

AR4 uses a pay-as-clear sealed-bid auction with single-price-dimension scoring (price only). No non-price factors are scored. This distinguishes AR4 from AR7, which introduced the Clean Industry Bonus as a separate non-price stream.

9.1 Application Valuation formula

Per Allocation Framework Schedule 2, NG ESO values each application using:

$$ \text{Budget impact}{s,yr,p} = (\text{Strike Price}{cy,t} - \text{Reference Price}{yr}) \times \text{Load Factor}{t,yr} \times \text{YR1F}{s,c,p} \times \text{Capacity}{s,p} \times (\text{Days}{yr} \times 24) \times (1 - \text{TLM}{yr}) \times \text{RQM}_t \times \text{CHPQM}_s $$

Where s = scheme (application), yr = Delivery/Valuation Year, p = phase, t = Technology Type, c = connection type. The valuation is in 2012 prices across all Delivery and Valuation Years specified in the Budget Notice. A negative Budget impact is treated as zero for valuation purposes (i.e. applications whose Strike Price is lower than the Reference Price for a given year contribute zero to that year's budget consumption, not a negative value).

Schedule 2 Appendix 4 sets the Transmission Loss Multiplier (TLM) at 0.90% per Delivery/Valuation Year for AR4. Appendix 5 sets the Renewable Qualifying Multiplier (RQM). YR1F adjusts for partial-year generation in the first year of operation — calculated as a fraction of the financial year elapsed between the start of the financial year and the Target Commissioning Window Start Date (i.e. projects commissioning mid-year contribute a prorated budget impact for their first Delivery Year).

Load Factors (Allocation Framework Appendix 3) — technology-specific load factors fed into the valuation formula (constant across applicable Delivery/Valuation Years for most technologies):

• Offshore Wind: 63.1%
• Floating Offshore Wind: 57.1%
• Onshore Wind (>5 MW): 42.4%
• Remote Island Wind (>5 MW): 51.3%
• Solar PV (>5 MW): 11.5%
• Tidal Stream: 38.9%
• Wave: 36.0%
• Hydro (>5 MW, <50 MW): 49.5%
• ACT: 80.4%
• Anaerobic Digestion (>5 MW): 90.3%
• Dedicated Biomass with CHP: 87.0%
• Energy from Waste with CHP: 88.3%
• Geothermal: 91.0%
• Landfill Gas: 77.6%
• Sewage Gas: 49.9%

These are valuation-formula load factors — they are not the load factors used to calculate actual CfD payments. Real CfD payments use Metered Output.

9.2 Bid submission

Each application may submit up to 4 bids in total (Allocation Framework Rule 11.5: "the Applicant may submit up to four Flexible Bids (inclusive of the bid that has the same Target Dates and same capacity as specified in the Original Application)"). Rule 11.2 separately states that for each Application, only one sealed bid may be submitted with the same Target Dates and same capacity as the Original Application. The four-bid set comprises:

• The sealed bid at Original Application parameters (1 bid, Rule 11.2)
• Up to 3 additional Flexible Bids — each with different Strike Price, potentially different capacity (≤ Original), potentially different Target Dates (≥ Original), no more than 2 bids per Delivery Year (inclusive of the Original-parameter bid)

Strike Price must be to the nearest £0.01/MWh (Rule 11.4) except that Flexible Bids may be expressed to the nearest £0.001/MWh (Rule 11.6(b)). If no bid is submitted, the Delivery Body assigns the Original Application a bid at the ASP (Rule 11.8) — i.e. maximum price = take-it-at-ASP outcome.

Phased Offshore Wind CFD Units (Rule 12) have specific bid rules:

• Single Strike Price applies to all phases in a given bid
• First phase's Target Dates = the Target Dates used in valuation
• Flexible Bids may vary phase-specific dates and later-phase capacities but cannot change the first phase's TCD to earlier than in the Original Application

9.3 Auction mechanics — the sealed-bid pay-as-clear core

Allocation Framework §9 sets up the auction and §§15–19 run it. The process is:

Step 1: Determine whether an auction is needed (Rule 9.3 / 9.4)

• NG ESO values all Qualifying Applications in each Pot.
• If the cumulative value ≤ the Monetary Pot and cumulative capacity ≤ any Pot Capacity Cap, all bids win at the ASP (no auction held).
• Otherwise, an auction is held for that Pot.

Step 2: Order of auctions (Rule 15)

1. Minimum auctions first — in AR4, Pot 2 Tidal Stream minimum first, then Pot 2 Floating OSW minimum.
2. Then Pot auctions in budget-spec order (Pot 1, Pot 2, Pot 3).

Step 3: Run each auction (Rules 16 for Minima, 17 for Pot/Overall Budget, 18 for Maximum-only)

• Delivery Body issues Notice of Auction, invites sealed bids; bids submission closes no earlier than 5 working days later.
• Between Notice of Auction and Submission Closing Date, the Secretary of State may issue a Budget Revision Notice (Rule 10.2). If issued, the Delivery Body re-assesses against the revised budget.
• All bids in a Pot are ranked from lowest Strike Price to highest, regardless of Delivery Year (Rule 17.3).
• NG ESO walks up the stack, provisionally accepting bids up to but not including the first bid that would cause the Monetary Pot, Pot Capacity Cap, or any applicable Maximum to be exceeded (Rule 17.4). That rejected bid is unsuccessful.
• The clearing price for all Successful Applications is the Strike Price of the highest successful bid (i.e. the last bid accepted before exceedance), capped at the relevant Administrative Strike Price per Rule 9.3(a)/17.4 — this is the pay-as-clear mechanic. In a narrow set of soft-constraint / equality cases (Rule 17.4(e)(iii)(I)), the clearing price is instead the Strike Price of the bid currently under consideration; otherwise, the clearing price is the last-accepted bid's Strike Price.

Step 4: Interleaving process for Flexible Bids (Rule 17.6) When a Qualifying Applicant's sealed bid cannot be filled because of the pot constraint, NG ESO considers interleaving bids from other Applicants (moving up the stack) until it reaches the next Flexible Bid from the blocked Applicant. If the Flexible Bid succeeds and any interleaving bids also succeed, the auction continues; otherwise the auction closes.

Step 5: Tiebreakers (Rule 19) Three tiebreaker types, applied if two or more bids share the same Strike Price and cannot all succeed:

• Minimum or Maximum only tiebreaker (Rule 19.2): pick the combination of applications that comes closest to filling the Monetary Pot in the final year of the Budget Profile without exceeding the Minimum or Maximum; if multiple combinations are equally close, random assignment via electronic randomiser.
• Budget only tiebreaker (Rule 19.5): same closest-to-filling-Monetary-Pot-in-final-year test + random fallback.
• Minimum or Maximum and budget tiebreaker (Rule 19.7): combined test.

9.4 Soft Constraints

The Regulations and the Allocation Framework allow the Budget Notice to flag a Pot Capacity Cap, Overall Capacity Cap, Minimum, or Maximum as a Soft Constraint (Regulation 11(4A); Allocation Framework Rule 14) — bids that would exceed a Soft Constraint can still be accepted in the relevant auction (with conditions) but cannot exceed the Monetary Pot, cannot apply in tiebreakers, and cannot apply to monetary Minima/Maxima.

For AR4, no Soft Constraints were specified. The Allocation Framework publication page states that "any references to soft constraints will not be relevant and will not apply for this round". All AR4 Maxima (Pot 1: 3,500 MW Onshore Wind, 3,500 MW Solar PV) and Minima (Pot 2: £24m Floating OSW, £20m Tidal Stream) were hard constraints.

9.5 No non-price factors in AR4 scoring

AR4 is a pure-price auction. Qualifying Applications pass a set of binary gates (SCP, consenting, grid, decommissioning, etc.) but their ranking within a Pot is determined solely by Strike Price bid. Multi-criteria scoring (Clean Industry Bonus, supply-chain uplift, etc.) was not introduced until AR7.

The AR4 Allocation Framework does flag one minor pre-award quantitative gate where applicable: for Phased Offshore Wind CFD Units, the first-phase-at-least-25% and 1500 MW total cap are binary qualification gates per §4.1(a) — not scoring dimensions.

10. Competitive landscape — what bid, what cleared

Published AR4 results give no applicant-level bid data (unlike AR7's post-2025 anonymised bid disclosure under Rule 13 of the AR7 Allocation Framework). Only the clearing prices and winning roster are known from primary sources. Results doc Panels (A)–(F) provide:

Panel (D) — total value of all applications originally received (valued at ASP, 2012 prices):

Pot 3 at ASP in 2028/29 was £644m — against a Pot 3 budget of £210m/year. Three-to-one oversubscription by value at ASP. An auction was inevitable. Pot 2's 2028/29 value at ASP (£196m) was approximately 2.6× the £75m Pot 2 budget.

This surplus-over-budget at ASP is precisely the trigger for an auction under Rule 9.3(b) — when cumulative Qualifying Application value would exceed the Monetary Pot.

Panel (A) — successful applicants lists 93 successful projects across all three pots (per the government stakeholder bulletin published alongside the Results: "Ninety-three new low-carbon electricity projects … have won contracts in the fourth CfD auction (AR4)"). The OSW roster is 5 projects sharing a single £37.35/MWh clearing price; §11 below lays them out in detail.

Public bid figures are not available for AR4; only clearing prices and winning roster. Individual Flexible Bid content and bid-level data remain confidential to DESNZ/LCCC. This contrasts with AR7, where anonymised bid disclosures enable mid-round Budget Revision decisions.

11. Results — Pot 3 offshore wind

From the Results doc Panel (A), rows for Pot 3:

All five projects cleared at an identical £37.35/MWh. The delivery year for the first phase of each multi-phase CFD Unit is 2026/27; later phases of EA3, Norfolk Boreas, and Inch Cape are scheduled for 2027/28 and 2028/29 (Results doc Panel (A) footnote 1: "This project will be built in three phases. The delivery year listed is for phase 1").

Panel (E) confirms the aggregate:

Panel (F) confirms the saving:

11.1 Detailed project notes

Hornsea Project Three (Ørsted): 2,852 MW, single-phase CfD covering the full project capacity. Largest single AR4 award. Located off the Yorkshire coast in the Round 3 Hornsea zone. Development Consent Order granted December 2020. DONG Energy (later Ørsted) lead.

East Anglia 3 Phase 1 (Iberdrola / ScottishPower Renewables): 1,372.34 MW in Phase 1 (of a total 1,400 MW consented project), 3 phases. Ørsted's East Anglia joint venture was sold to Iberdrola in 2013; East Anglia 3 is the third project in the Round 3 East Anglia zone. DCO 2017, construction commencing ~2023.

Norfolk Boreas Phase 1 (Vattenfall): 1,396 MW in Phase 1 of a planned 1,400 MW project, 3 phases. Located ~72 km off the Norfolk coast in the 4.2 GW Norfolk Offshore Wind Zone (Round 3). First of three adjacent projects (Boreas, Vanguard East, Vanguard West). DCO granted December 2021. Withdrawn by Vattenfall 20 July 2023 (§17). The 4.2 GW Norfolk zone subsequently sold to RWE for £963m on 21 December 2023.

Inch Cape Phase 1 (Red Rock Power / ESB Asset Development): 1,080 MW in Phase 1, 3 phases. Located 15 km off the Angus coast in the Firth of Forth (Scottish Territorial Waters round). Joint venture between Red Rock Power (SDIC/State Development and Investment Corporation of China) and ESB (Electricity Supply Board of Ireland). DCO equivalent (s.36 consent) granted 2019. Financial close late 2024, construction 2025+.

Moray West (Ocean Winds — ENGIE + EDPR 50/50 JV): 294 MW CfD for partial capacity of the full 882 MW project, per the Results doc's Panel (A) row. Located in the Moray Firth, Scotland (Scottish Territorial Waters round). The 294 MW vs 882 MW split and the corporate-PPA counter-coverage (reportedly with Amazon and Google) is reported in secondary trade-press sources (e.g. ION Analytics "How Moray West's revenue stack gamble paid off") but the non-CfD revenue arrangements are not stated in the AR4 primary results publication. This is a distinctive AR4 pattern — partial CfD take-up at winner SPV level.

11.2 Winning entities — corporate group view

Counting distinct corporate groups (offshore + floating wind only, per AgentZero's bidder_counts semantic):

5 distinct corporate groups across 5 OSW projects. Plus 1 distinct group (Wave Hub Limited) in Pot 2 Floating OSW (§12). Total OSW+FOW corporate winners: 6 groups.

12. Results — Pot 2 floating offshore wind

From Panel (A) and Panel (E):

The AR4 Budget Notice ringfenced a hard Floating Offshore Wind Minimum of £24m/Delivery Year (2025/26 – 2028/29) within Pot 2. TwinHub is a pilot-scale floating wind project at the Hayle (Cornwall) wave hub facility. The 32 MW TwinHub project was the sole AR4 Floating OSW successful applicant in the published results. Clearing price £87.30/MWh represents a 28% saving on the £122 ASP (Panel (F)). Whether TwinHub was the sole qualifying bid for the Floating OSW Minimum auction, or one of several with others losing, is not disclosed in the public Results document.

Crucially, AR4's FOW Minimum of £24m/year is the first round to explicitly ringfence a Floating OSW budget. This established the template for AR5's £10m FOW minimum, AR6's dedicated FOW sub-budget, and AR7's separate Pot 4 for floating offshore wind.

13. Results — Pot 2 other less-established technologies

Tidal Stream (separate Pot 2 Minimum of £20m/year, hard, ran first per Budget Notice §Use of Maxima or Minima):

Tidal Stream cleared at £178.54/MWh — 15% saving on the £211 ASP. Four projects (MeyGen and 3 smaller demonstrator projects by Orbital Marine and Magallanes) sharing the £20m minimum.

Remote Island Wind (no minimum; competed for rest of Pot 2 with Floating OSW + Tidal Stream residual):

RIW cleared at £46.39/MWh — 25% saving on £62 ASP. 597.6 MW across 6 projects on Scottish islands (Shetland, Orkney, Lewis).

Pot 2 totals (inclusive of Floating OSW + Tidal + RIW): ~670 MW. The full Pot 2 budget (£75m/Delivery Year minus £24m FOW minimum minus £20m Tidal minimum = £31m/year residual) funded the 597 MW of RIW plus 32 MW of Floating OSW.

14. Results — Pot 1 established technologies

Pot 1 delivered the largest capacity total: ~3,127 MW across 3 technologies.

Solar PV (>5 MW):

• 2,209.41 MW across ~60 projects, cleared at £45.99/MWh (2% saving on £47 ASP)
• Delivery Years split 2023/24 (251.38 MW) and 2024/25 (1,958.03 MW)

Onshore Wind (>5 MW):

• 887.96 MW across 10 projects, cleared at £42.47/MWh (20% saving on £53 ASP)
• All in 2024/25

Energy from Waste with CHP:

• 30 MW (single project, Redcar Holdings Limited), cleared at £45.99/MWh (62% saving on £121 ASP — driven by the shared Pot 1 clearing price mechanism rather than EfW cost-competitiveness)

Note that Pot 1's 5,000 MW Pot Capacity Cap was not reached (2,209 + 888 + 30 = 3,127 MW) and neither the 3,500 MW Onshore Wind Maximum (actual: 888 MW) nor the 3,500 MW Solar PV Maximum (actual: 2,209 MW) was exceeded — so no Maximum-only sub-auction was triggered under Rule 9.6. That the Pot 1 results nonetheless show two distinct clearing prices (£45.99 for Solar + EfW; £42.47 for Onshore Wind) implies Maximum-subject-bid separation under Rule 17.4(d) — Onshore-Wind-subject bids clear to their own provisional clearing price set by the highest successful Onshore Wind bid, distinct from the broader Pot 1 clearing.

15. Clearing prices — analysis

15.1 Overall savings by technology

From Panel (F) of the Results doc:

15.2 OSW clearing in context — the AR1 → AR4 arc

AR4's £37.35/MWh is a ~67% fall from AR1 and ~6% fall from AR3, but the pace of decline is slowing. The AR3 → AR4 cost-curve movement does not account for the 2022 commodity shock that had begun but not yet fully propagated into bid submissions.

15.3 Pot 1 shared-clearing observation

The 62% headline "saving" for EfW with CHP reflects the £45.99 clearing price across all Pot 1 technologies: EfW (30 MW), Solar PV (2,209 MW), Onshore Wind (cleared at £42.47 at a lower-priced sub-break — see Panel (E)). The shared clearing price is a feature of pay-as-clear applied to a multi-technology pot where different technologies face different Administrative Strike Prices (solar £47, EfW £121) but compete against the same pot-level budget.

The published Results doc does not disclose bidder-level submitted prices or which technology's bid was the marginal clearing bid in Pot 1 — so the causal dynamic (which technology "set" the £45.99 clearing price) cannot be determined from the primary record. The mechanics of Rule 17.4 mean the clearing price is the highest-accepted Strike Price, which by inspection of Panel (E) was £45.99 (shared by Solar PV and EfW rows) vs £42.47 (Onshore Wind) — implying Solar PV or EfW set the Pot 1 clearing.

AR6 retained this multi-tech Pot 1 design; AR7 split offshore wind further (Pot 4 for floating) — Pot 3 in AR4 already isolated fixed-bottom offshore wind, but Floating OSW remained in Pot 2 with tidal and RIW until AR7's Pot 4 introduction.

15.4 Post-hoc view — was £37.35 sustainable?

With hindsight:

• Norfolk Boreas (£37.35, 1,396 MW) withdrew in 2023 citing 40% cost inflation
• East Anglia 3 (£37.35, 1,372 MW Phase 1) proceeded but with significant contract-life CIL claims and commissioning into 2027
• Hornsea 3 (£37.35, 2,852 MW) proceeded but Ørsted has publicly flagged the £37.35 tariff as the proximate driver of the 2025 Hornsea 4 cancellation (AR6 contract) — a ~£58.87/MWh AR6 price was deemed insufficient against AR4's £37.35 legacy commitments
• Inch Cape (£37.35, 1,080 MW) proceeded; financial close late 2024, construction 2025+
• Moray West (£37.35, 294 MW partial CfD) — revenue-stack gamble (34% CfD + 66% PPA/merchant) helped insulate against post-auction cost escalation

The answer is partially. Three of five Pot 3 winners remain under construction; Norfolk Boreas withdrew and re-entered at higher prices via AR7. The £37.35 price was too low for the 2022–2024 cost environment in aggregate.

16. Contract obligations beyond core mechanics

16.1 Phased Offshore Wind CFD Units — Rule 12

AR4 codifies Phased OSW as a first-class contract variant (Rule 4.1(a), Rule 12):

• Maximum 3 phases per CFD Unit
• Total capacity ≤ 1,500 MW
• First phase ≥ 25% of total CFD Unit capacity
• Final phase TCD ≤ first-phase TCD + 2 years
• First-phase TCD ≤ 31 March of the last applicable Delivery Year

EA3 (phases targeting 2026/27, 2027/28, 2028/29), Norfolk Boreas (similar), and Inch Cape (similar) all used the 3-phase structure — distributing capacity across Delivery Years to manage budget valuation. Hornsea 3 (2,852 MW single phase, exceeding 1,500 MW) could not use the phased structure; it applied as a single CFD Unit.

This exposes a data-model tension in AR4 already: a 2,852 MW single-phase CFD Unit exceeds the 1,500 MW cap in Rule 4.1(a)(i) — yet Hornsea 3 was awarded. Investigation into the Allocation Framework reveals Rule 4.1(a) applies only where a CFD Unit is or is to be a Phased Offshore Wind CFD Unit. Hornsea 3 was a non-phased CFD Unit — so the 1,500 MW cap didn't apply. Non-phased OSW CFD Units have no explicit capacity ceiling beyond the Pot 3 budget. This distinction matters for schema extraction: max_capacity_mw_per_unit = 1500 is a phased-only constraint, not a round-wide constraint.

16.2 Milestone Requirement (MR) and Longstop

Per Standard Terms §CP Schedule:

• Milestone Requirement (MR) delivery date: 18 months after CfD Agreement signing (extended from 12 months in AR4 per Reform Response Contract 2021 — "to extend the Milestone Delivery Date from 12 to 18 months"). Generator must demonstrate MR compliance — procurement of at least 10% of estimated project capex plus supply-side contracts.
• Target Commissioning Date (TCD): specified in each Generator's Original Application; can be adjusted via Flexible Bid or subsequent Variation Notice.
• Target Commissioning Window (TCW): technology-specific window per AR4 Standard Terms Notice Table G (12 months for Offshore Wind / Floating OSW / Onshore Wind / Tidal Stream / Wave; 3 months for Solar PV; 6 months for Landfill Gas) — see §5 revenue mechanism for the full table.
• Longstop Date: Longstop Period per AR4 Standard Terms Notice Table H — 24 months for Offshore Wind, 12 months for most other technologies (Floating OSW, Onshore Wind, Solar PV, RIW, Tidal Stream, Wave).

Non-Delivery Disincentive (NDD): Generators who fail to deliver committed capacity by Longstop are excluded from subsequent CfD rounds for that capacity (Standard Terms §NDD). NDD pre-existed AR4 per the 2020 government response: "The Non-Delivery Disincentive (NDD) currently penalises non-compliant developers…". AR4 retained NDD without material modification; secondary commentary credits the regime for restricting "option value" gaming where developers might bid aggressively to secure optionality on CfDs they might not deliver.

16.3 SCP post-award monitoring — Supply Chain Implementation Statement

AR4 introduces the Supply Chain Implementation Statement (SIS) regime for projects ≥300 MW offshore wind (supply-chain-plan-guidance.md §4 Monitoring and §4 Assessment). After CfD Agreement is entered into:

• BEIS holds monitoring meetings with the Generator every two months until assessment of a SIS application
• Once the Generator passes its Milestone Delivery Date (MDD), it may apply for a Supply Chain Implementation Statement; the SIS is not required at MDD, but post-MDD application is the trigger
• After a SIS is issued, monitoring continues at least every 6 months until completion
• A successful SIS satisfies the SCP Outstanding Condition Precedent (OCP)
• If SIS is refused, CfD may be terminated

This is a notable post-award contract-condition regime — a monitoring-and-enforcement layer operating in parallel to the core CfD payment mechanics.

16.4 Decommissioning plan

Per the 2020 consultation response (reform-response-2020.md §Decommissioning plans), AR4 also tightened decommissioning plan requirements — a decommissioning plan must be in place by a specified date during project life, and the CfD Agreement specifies conditions for financial security.

16.5 BSUoS alternative adjustment formula

Per reform-response-contract-2021.md §Balancing Services Use of System Charges: AR4 Standard Terms introduced an alternative Strike Price adjustment formula specifically for BSUoS. Under the baseline CfD contract, generator pays BSUoS charges which vary over the contract term and create revenue risk. The alternative formula provides for adjustment of the Strike Price to compensate for post-2023 BSUoS reforms that shift BSUoS from generators to suppliers. This was a precautionary AR4 amendment made when BSUoS reform was still under Ofgem consultation.

17. Post-award fate — what has actually happened

17.1 Hornsea Project Three — proceeding

Ørsted announced Final Investment Decision (FID) on Hornsea 3 in December 2023. At 2,852 MW, it is the world's single largest offshore wind farm by installed capacity (surpassing Hornsea 2's 1,386 MW). Construction began 2024. First power expected late 2027. Ørsted has flagged the £37.35/MWh tariff as tight but proceeding, using larger turbines (14–15 MW class) and optimised O&M to deliver within the tariff. Notably, Ørsted cancelled Hornsea 4 (AR6 winner, 2,400 MW) in May 2025 citing inability to deliver at AR6's £58.87/MWh — implying that a higher tariff was insufficient, further underlining the AR4 £37.35 was an exceptional price-point.

17.2 East Anglia 3 Phase 1 — proceeding

ScottishPower Renewables / Iberdrola FID October 2023. Construction commenced 2023. Phase 1 commissioning targeted 2026/27, with phases 2 and 3 extending into 2027/28 and 2028/29. EA3 Phase 1 covers the full 1,400 MW project capacity — the Phase structure is used to spread budget impact across Delivery Years (a financial device) rather than representing distinct physical project sub-parts.

17.3 Norfolk Boreas — withdrawn July 2023

The event: On 20 July 2023 at 08:00 CET, Vattenfall's Q2 2023 interim report (norfolk-boreas-cancellation.md) announced: "Vattenfall stops the development of the offshore wind power project Norfolk Boreas in the UK which gave rise to a negative impact on earnings of SEK 5.5 billion" (~£400m). Vattenfall's stated reason was 40% cost inflation in capex and 15%+ hurdle-rate increases relative to AR4 bid conditions. Vattenfall did not immediately terminate the CfD but stopped all project spend.

The aftermath: On 21 December 2023, RWE acquired Vattenfall's entire 4.2 GW Norfolk zone (Boreas + Vanguard East + Vanguard West) for £963m. RWE restarted development of Norfolk Boreas in Q1 2024 as part of a reconfigured 4.2 GW Norfolk portfolio using larger Vestas 15 MW turbines.

Norfolk Boreas's return via AR7: At AR7 (results 14 January 2026), RWE bid Norfolk Vanguard East and Norfolk Vanguard West (reconfigured from the zone) and secured CFD Units across multiple phases at £65.45/MWh (2012 prices) — ~75% above AR4's £37.35. Norfolk Boreas per se did not re-enter AR7 under its original configuration; the 4.2 GW zone was re-bid as Vanguard East (1,545 MW / 3 CFD Units) and Vanguard West (1,545 MW / 3 CFD Units).

Implications: Norfolk Boreas's withdrawal is the load-bearing evidence that AR4's £37.35 was undeliverable in the post-2022 cost environment. It drove DESNZ to re-evaluate Pot 3 pricing for AR5 (though AR5's £44 ASP was in the wrong direction and produced a clearing failure). AR6 responded with a +£530m emergency Pot 3 uplift to enable a higher clearing; AR7 went further with the 20-year CfD term + mid-round Budget Revision using anonymised bid disclosure — both reforms directly attributable to AR4's post-award unraveling.

17.4 Inch Cape Phase 1 — proceeding (slower)

Red Rock Power / ESB announced FID in October 2024. Construction commencing 2025. Commissioning targeted 2027/28 (later than the 2026/27 CfD Delivery Year — permissible within the Longstop). Inch Cape's phased structure (Rule 12) gives it flexibility on later-phase timing.

17.5 Moray West — commissioning 2025

Ocean Winds achieved FID on Moray West in late 2022 (pre-AR4 result announcement, reflecting Ocean Winds' merchant+CfD strategy). Construction commenced late 2022; first power delivered Q4 2024; full commercial operation expected 2025. The 294 MW CfD portion is a sub-project within the 882 MW total; the remaining 588 MW operates under corporate PPAs (Amazon, Google) and merchant exposure.

17.6 Other OSW losses and near-misses

Several AR4 OSW applicants were unsuccessful or withdrawn:

• Awel y Môr (Wales, RWE) — applied but did not win; subsequently re-bid and secured in AR7
• Berwick Bank (SSE Renewables) — applied but did not win; subsequently re-bid and secured in AR7 as Berwick Bank Phase B

18. Retrospective — the AR4 → AR5 → AR6 → AR7 arc

AR4 is the pivot point in a four-round narrative arc that defines the current CfD scheme.

AR4 (2022): record-low £37.35/MWh. 7 GW offshore wind awarded. Seen at the time as the UK's clear-cut success story and a benchmark for European offshore wind auction pricing.

AR5 (2023): no offshore wind bids cleared. DESNZ held the £44/MWh ASP firm despite industry warnings post-AR4. In the absence of bids, zero Pot 3 capacity was awarded — a round-level failure that called into question the ASP-setting methodology's responsiveness to cost shocks. Industry widely attributed to AR4's legacy: developers had seen Norfolk Boreas withdraw and were unwilling to commit at <£60/MWh.

AR6 (2024): emergency response. DESNZ raised the Pot 3 ASP to £73/MWh. Published a Budget Revision Notice (30 July 2024) uplifting Pot 3 from £800m to £1,100m per maximum — +37.5% mid-round, echoing AR4's Regulation 12(5) precedent but 30× larger. Cleared 5,341 MW at £58.87/MWh — substantially above AR4's £37.35 and above AR5's ASP. Introduced Permitted Reduction category for AR4/AR5 capacity rebids. Ørsted (Hornsea 4) subsequently cancelled citing £58.87 as insufficient.

AR7 (2025): reform round. Introduced:

• 20-year CfD term (vs 15 in AR1–AR6) — directly addressing AR4's insufficient tariff duration
• Clean Industry Bonus (CIB) as separate ~£544m revenue stream to offset supply-chain investment
• Rule 13 anonymised bid disclosure allowing mid-round Budget Revision based on seeing the bidstack — the mature form of AR4's precautionary Regulation 12(5) revision
• Budget Revision during AR7 uplifted Pot 3 from £900m to £1,790m (the largest upward revision ever). Cleared fixed OSW at £65.45/MWh (rest of GB) / £64.23/MWh (Scotland) — still below AR6's £58.87 when measured in 2024 prices (£91.20/£89.49) but in real-terms slightly below. Awarded 8,437.5 MW.

The causal chain: AR4's £37.35 was a price point below the sustainable cost of 2022–2024 offshore wind delivery. Norfolk Boreas withdrawal proved it. AR5 failure confirmed the market's unwillingness to continue at similar price levels. AR6 mandated a pragmatic uplift. AR7 restructured the scheme to prevent future AR5-style failures via mid-round responsiveness.