UK Contracts for Difference Allocation Round 2

UK CfD Allocation Round 2 (AR2, 2017)

The first step-change round — where UK offshore-wind prices crashed by half and a new cost narrative took hold. AR2 was the second UK Contracts for Difference allocation and the round that rewrote the industry's cost story. A single less-established-technology pot ("Pot 2") with a £290 million-per-Delivery-Year budget and a 150 MW cumulative maxima on fuelled tech. On 11 September 2017 at 07:00 BEIS announced 11 successful applications, 3 of them offshore-wind projects totalling 3,196 MW at clearing prices of £74.75/MWh (2021/22 delivery) and £57.50/MWh (2022/23 delivery) in 2012 prices. The £57.50 figure was a ~50% fall on AR1's £114.39-£119.89/MWh and became the reference point against which AR3's £39.65 was measured. Together with Germany's parallel April 2017 BSH auction — where Ørsted and EnBW bid zero subsidy — AR2 is one of the two canonical "cost-inflection" moments in global offshore wind. Offshore-wind post-award status (LCCC Register, 2026-04-20 snapshot): all 3 projects Live (Post-FIC), 0 terminated. Triton Knoll commissioned Summer 2022 (HVAC, Vestas 9.5 MW turbines, 857 MW operational), Moray East fully operational April 2022 (MHI Vestas 9.525 MW, 950 MW operational), Hornsea 2 fully operational August 2022 (Siemens 8 MW, 1,386 MW operational). Across 9 phased CFD Unit records, current capacity totals 3,143.34 MW versus 3,196 MW awarded — 1.65% attrition via Permitted Reductions at Final Installed Capacity, no terminations. AR2 is the UK's most structurally successful offshore-wind CfD cohort by delivery: priced competitively against 2016-17 cost assumptions, commissioned before the 2022 commodity shock, and operational ahead of AR3's delivery window.

1. At a glance

• Sponsor: Department for Business, Energy and Industrial Strategy (BEIS) — the government department formed in July 2016 that replaced DECC; later renamed DESNZ in February 2023
• Delivery Body: National Grid (EMR Delivery Body) — acting as the Delivery Body under the CfD (Allocation) Regulations 2014; later renamed NG ESO (2018) then NESO (October 2024)
• Counterparty: Low Carbon Contracts Company (LCCC)
• Scrutiny regime: Pre-Brexit EU State Aid — CfD scheme approved under case SA.44475 (European Commission decision 26 July 2017)
• Allocation Round Notice: 13 March 2017 — Secretary of State's notice, signed by Ashley Ibbett, Director Clean Electricity, on behalf of the Secretary of State
• Application window opens: 3 April 2017 (per Budget Notice Accompanying Note §1)
• Application Closing Date: 21 April 2017
• Results published: 11 September 2017 at 07:00 (BEIS publication timed to coincide with National Grid's notification to applicants)
• Overall budget (2011/12 prices): £290 million per Delivery Year — i.e. up to £290m in annual support payable under CfDs awarded in this round, applied across 2021/22 and 2022/23. CPI-rebased to £295m in 2012 prices via inflator 1.0193
• Pot structure: single pot — "Pot 2" (less established technologies). No Pot 1 was run for AR2 (established technologies excluded). No separate offshore-wind pot (that carve-out came at AR4 via Pot 3). auction_results records carry pot: 2 across the board
• Technologies eligible: 7 technology groups — Offshore Wind, Advanced Conversion Technologies (with or without CHP), Anaerobic Digestion (with or without CHP, >5MW), Dedicated Biomass with CHP, Wave, Tidal Stream, Geothermal (with or without CHP). No Remote Island Wind (first introduced at AR3). No Floating Offshore Wind (first introduced at AR4)
• Capacity maxima: 150 MW cumulative maxima across the three fuelled technologies (Dedicated Biomass with CHP + ACT + AD). No offshore-wind cap, no overall capacity cap, no minima, no soft constraints
• Offshore Wind ASP: £105/MWh (2021/22 Delivery Year), £100/MWh (2022/23 Delivery Year) — per-Delivery-Year ASP calibrated to enable the cheapest 19% of projects in each Pot 2 technology to compete
• Offshore Wind clearing: £74.75/MWh (2021/22), £57.50/MWh (2022/23) — 29% and 43% saving on ASP respectively
• Auction format: sealed-bid, pay-as-clear per Delivery Year. Up to 4 Flexible Bids per Application, of which no more than 2 may share a Delivery Year
• Revenue instrument: two-way CfD, 15-year term, CPI-indexed Strike Price, Reference Price (Baseload Market Reference Price for fuelled tech, Intermittent Market Reference Price for OSW/Wave/Tidal Stream)
• Contract form: FiT Contract for Difference Standard Terms and Conditions Version 2 (541 pages, 13 March 2017); Generic CfD Agreement wrapper (35 pages, 13 March 2017); Apportioned, Single-Metering, Private Network, and Unincorporated Joint Venture variants all published the same day
• Successful applicants: 11 — 3 offshore wind (3,196 MW), 2 Dedicated Biomass with CHP (85.64 MW), 6 Advanced Conversion Technologies (64.31 MW)
• Offshore wind winners: 3 projects / 3 distinct corporate groups / 3,196 MW — all Phased (3 phases each)
  • Triton Knoll Offshore Wind Farm — 860 MW, Delivery Year 2021/22 (Phase 1), England (Greater Wash), @ £74.75/MWh. Applicant SPV: Triton Knoll Offshore Wind Farm Limited. Developer at AR2 time: innogy SE + Statkraft (50/50 JV). Today: RWE-led (RWE inherited innogy's renewables business; Statkraft's 50% sold to J-Power / Kansai Electric in 2018). HVAC transmission. Round 2 (Greater Wash) Crown Estate origin
  • Hornsea Project 2 — 1,386 MW, Delivery Year 2022/23 (Phase 1), England (Hornsea Zone), @ £57.50/MWh. Applicant SPV: Breesea Limited. Ørsted (then "DONG Energy" until brand change October 2017). HVAC. Round 3 (Hornsea Zone) Crown Estate origin
  • Moray East (Moray Offshore Windfarm (East)) — 950 MW, Delivery Year 2022/23 (Phase 1), Scotland (Moray Firth), @ £57.50/MWh. Applicant SPV: Moray Offshore Windfarm (East) Limited. At AR2 time: EDPR + ENGIE 50/50 JV. Later rebranded to Ocean Winds (EDPR + ENGIE 50/50 JV); CTG acquired minority stake in 2019. HVAC. Round 3 (Moray Firth Zone) Crown Estate origin
• Post-award fate (2026-04-20): All 3 offshore wind projects Live (Post-FIC) — none terminated. Triton Knoll commissioned Summer 2022; Moray East fully operational April 2022; Hornsea 2 fully operational August 2022. Across 9 phased LCCC Register CFD Unit records, current capacity is 3,143.34 MW vs 3,196 MW awarded — 52.66 MW (1.65%) reduction through Permitted Reductions applied at Final Installed Capacity confirmation, the standard FIC refinement mechanism and not indicative of project-level distress.

2. Market context at the time of the auction

AR2 opened 3 April 2017 into an industry frame that looked strikingly different from AR1 two years earlier. AR1 (February 2015) had cleared fixed-bottom offshore wind in two tranches at £114.39/MWh (2017/18 Delivery Year) and £119.89/MWh (2018/19 Delivery Year) for approximately 1.16 GW awarded across 5 winners (Dudgeon, East Anglia One, Neart na Gaoithe, Beatrice and Burbo Bank Extension). These prices were set against £150/MWh+ Administrative Strike Prices; the 25-35% saving on ASP was celebrated at the time as evidence CfD was delivering value, but the underlying cost base was still clearly in the £100-120/MWh range. The expectation among most analysts was that AR2 would deliver modest further price compression of perhaps 10-20% rather than a step change.

Three contextual drivers framed AR2 bidder strategy:

• Turbine scaling from 4-6 MW class to 7-8 MW class. AR1-winning projects were built (where they proceeded) around the MHI Vestas V164-8 MW and Siemens SWT-7.0-154 generations — Dudgeon used 6 MW Siemens machines, Burbo Bank Extension used the world's first commercial 8 MW MHI Vestas units. By AR2 application time, the pipeline held projects designed for the 8 MW class (Hornsea 2 went to Siemens SWT-8.0-167 DD; Triton Knoll ultimately chose the 9.5 MW Vestas V164; Moray East used 9.525 MW MHI Vestas V164). The step from 3.6 MW to 8 MW+ rotors reduced per-MW capex on foundations, inter-array cabling, vessel days, and balance-of-plant simultaneously, with knock-on OPEX reductions via fewer turbines per project.

• Consented pipeline depth and Round 3 (2010) zones reaching CfD-ready status. Crown Estate Round 3 (awarded 2010, following Round 1 in 2001 and Round 2 in 2003) had seeded nine zones totalling ~32 GW of theoretical capacity. By 2017 the first wave of Round 3 projects held or were close to holding Development Consent Order (DCO) approvals — Hornsea Zone's Project 1 had secured DCO in December 2014 and Project 2 in August 2016; Moray Firth Zone's Moray East had DCO in June 2014. Greater Wash (a Round 2 extension) had produced Triton Knoll's DCO in July 2013. Developers had invested 6-10 years of pre-FID expenditure in these zones and were motivated to convert consented capacity into CfD-backed revenue.

• Brexit, sterling, and the industrial-strategy political moment. The Brexit referendum (23 June 2016) triggered an immediate ~15% sterling depreciation against the Euro and Danish Krone. Offshore-wind capex is heavily import-exposed (turbines from Denmark/Germany, foundations from continental yards, cable from NKT and Prysmian). The post-Brexit cost pressure was real but partially offset by intensifying supply-chain competition, continued turbine scaling, and the ~5% Bank of England base-rate cut to 0.25% in August 2016 reducing developer hurdle-rate assumptions. Theresa May's government (formed July 2016) had by November 2016 articulated a Modern Industrial Strategy green paper, with the formal "Clean Growth Strategy" still under development (ultimately published October 2017, after AR2's application window closed). Political pressure on BEIS was substantial: demonstrate that the CfD regime — which had faced Treasury scepticism after AR1 — could deliver "value for money" for bill-payers.

The November 2016 Autumn Package set the preconditions for AR2. On 9 November 2016 BEIS published in rapid succession: (i) the ASP Methodology (asp-methodology.md) — the derivation methodology for AR2 Administrative Strike Prices; (ii) Supply Chain Plan Guidance for AR2 (supply-chain-plan-guidance.md, originally 9 November, updated 25 November to extend the maximum SCP length from 30 to 40 slides); and (iii) a call for evidence on fuelled and geothermal technologies in the CfD scheme, closing December 2016. The call for evidence questioned whether fuelled technologies (Biomass with CHP, ACT, AD) should continue to receive CfD support at all, or be redirected to alternative instruments — and this unresolved policy question is the immediate cause of AR2's unusual 150 MW cumulative maxima on fuelled tech (§5.3 below).

The February 2017 Government Response on CfD contract changes (regulatory-decision-cfd-contract-changes-2017.md) is AR2's primary axis-9 regulatory-decision source. It was published in response to a May-June 2016 BEIS consultation on CfD contract and regulation amendments, and crystallised four sets of changes: (i) explicit anti-cumulation rules preventing CfD support being stacked with other State aid or Union funding (to preserve compatibility with the ongoing EU State Aid approval for the scheme, ultimately granted as SA.44475 on 26 July 2017); (ii) clarification of the foreseeability definition within Qualifying Change in Law; (iii) clarified treatment of co-located storage on CfD sites; and (iv) a package of minor and technical changes reducing administrative burden on Generators and LCCC. The decisions crystallised in this response were implemented by (a) the Contracts for Difference (Standard Terms) (Amendment) Regulations 2017 (SI 2017/112, in force 1 March 2017) and (b) the FiT CfD Standard Terms and Conditions Version 2 issued on 13 March 2017.

Installed capacity context. At end-2016 the UK had approximately 5.1 GW operational offshore wind (London Array, Greater Gabbard, Gwynt y Môr, Anholt-class and earlier projects), ~30 GW total renewables (including onshore wind, solar PV, biomass). AR2's 3,196 MW of offshore-wind awards would, once delivered, add roughly 60% to the operational fleet.

3. Regulatory frame

AR2 operates under the statutory stack established by the Energy Act 2013 and the CfD Regulations 2014, refreshed through 2016-17 amendments:

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

2. Contracts for Difference (Allocation) Regulations 2014 (SI 2014/2011, as amended). Principal amendments affecting AR2:

   • Contracts for Difference (Allocation) (Amendment) Regulations 2016 (SI 2016/1053) — laid ahead of AR2, refining application, qualification and allocation machinery
   • Contracts for Difference (Allocation) (Excluded Sites) Amendment Regulations 2016 (SI 2016/1246) — laid ahead of AR2, addressing site-specific exclusions

   The Allocation Framework (§1 — "These Rules are made under Regulation 4 of the Allocation Regulations") and Budget Notice (Regulation 11) are issued under this instrument.

3. Contracts for Difference (Definition of Eligible Generator) Regulations 2014 (SI 2014/2010). Defines which stations can apply.

4. Contracts for Difference (Standard Terms) Regulations 2014 (SI 2014/2012), as amended by the Contracts for Difference (Standard Terms) (Amendment) Regulations 2017 (SI 2017/112, in force 1 March 2017). The 2017 SI is AR2-specific and enacts the four change-packages crystallised in the February 2017 Government Response: anti-cumulation, foreseeability, storage, and technical tidy-ups.

A set of AR2-specific statutory notices was published on 13 March 2017, all signed by Ashley Ibbett, Director Clean Electricity, on behalf of the Secretary of State:

• Allocation Round Notice (Regulation 4) — establishing AR2 and setting 3 April 2017 as the Application Window opening date
• Budget Notice (Regulation 11) — setting the £290m/DY overall budget, the Pot 2 allocation, the Administrative Strike Prices, and the 150 MW cumulative maxima on fuelled tech (budget-notice.md)
• CFD Framework Notice — identifying the AR2 Allocation Framework as applicable
• Standard Terms Notice — identifying the FiT CfD Standard Terms and Conditions Version 2 as the applicable contract
• Counterparty Costs Notice — covering LCCC costs passed through to levy
• Allocation Framework — the 50-page rule book (allocation-framework.md)

In addition to the statutory notices, BEIS published a non-statutory Accompanying Note to the Budget Notice (budget-notice-accompanying-note.md, 13 March 2017, 3 pages) explaining the ASP calibration logic (19% cut on the supply curve per technology), the rationale for dropping AR1's 100 MW Wave/Tidal minima, and the rationale for imposing the 150 MW cumulative maxima on fuelled tech.

EU State Aid context. AR2's underlying scheme approval was SA.44475, granted by the European Commission on 26 July 2017 — actually after the application window closed (21 April 2017) but before results publication (11 September 2017). In the interim, BEIS proceeded on a pre-notification basis under standard EU State Aid practice. The Standard Terms Version 2 retain extensive State Aid references and include conditional-start-date mechanics (Clause 6 of the Generic Agreement) for the case where an operational CP (the State Aid Condition Precedent) was satisfied after a project's physical Start Date.

Unlike AR4 onwards, AR2 did not publish a mid-round Budget Revision Notice. The Secretary of State's 5-Working-Day revision window (Rule 10.2, Regulation 12(5)) was not exercised for AR2. Regulation 12(5) was first used at AR4.

4. Pre-round preparation and timeline

Date	Event	Source
11 May 2016	BEIS launches consultation on CfD contract and regulation amendments	regulatory-decision-cfd-contract-changes-2017.md §1
May-June 2016	Consultation window on CfD contract and regulation amendments	regulatory-decision-cfd-contract-changes-2017.md
23 June 2016	UK Brexit referendum — materially affects post-vote sterling, import-exposed supply-chain costs	Context
July 2016	BEIS formed (absorbing DECC's energy policy function); Theresa May government	Context
9 November 2016	ASP Methodology for AR2 published (asp-methodology.md)	asp-methodology.md
9 November 2016	Supply Chain Plan Guidance for AR2 published (later updated 25 November to extend maximum SCP length to 40 slides)	supply-chain-plan-guidance.md
November 2016	Call for evidence on fuelled and geothermal technologies in the CfD scheme opened	Budget Notice Accompanying Note §10
December 2016	Call for evidence closes	Budget Notice Accompanying Note §10
1 February 2017	Government Response to consultation on CfD contract and regulation changes published (regulatory-decision-cfd-contract-changes-2017.md)	regulatory-decision-cfd-contract-changes-2017.md cover
1 March 2017	SI 2017/112 — Contracts for Difference (Standard Terms) (Amendment) Regulations 2017 — in force	regulatory-decision-cfd-contract-changes-2017.md §7
13 March 2017	Final Allocation Framework + Final Budget Notice + Accompanying Note + Standard Terms and Conditions Version 2 + Generic Agreement + Allocation Round Notice + CFD Framework Notice + Standard Terms Notice + Counterparty Costs Notice all published together; all signed by Ashley Ibbett. Delivery Body publishes Application Guidance v2.0	allocation-framework.md; budget-notice.md; standard-terms-and-conditions.md; generic-agreement.md; application-guidance.md
3 April 2017	AR2 Application Window opens	budget-notice-accompanying-note.md §1
21 April 2017	Application Closing Date	application-guidance.md
~12 May 2017	Delivery Body qualification determinations issued (no later than 15 working days after Application Closing Date per Allocation Framework Rule 7.1 / Regulation 19)	Allocation Framework Rule 7.1
16 May 2017	Non-Qualification Review Request Date (Rule 8.1(a))	allocation-framework.md Rule 8.1
13 June 2017	Appeals Deadline Date (Rule 8.1(b); deadline for Qualification Appeal to Ofgem under Regulation 43)	allocation-framework.md Rule 8.1
23 June 2017	Post-Appeals Indicative Start Date (where no appeals)	allocation-framework.md Rule 8.1(c)(i)
26 July 2017	European Commission approves EU State Aid scheme SA.44475	Manifest note on AR2 STCs
14 August 2017	Post-Appeals Indicative Start Date (where appeals)	allocation-framework.md Rule 8.1(c)(ii)
Late August - early September 2017	Notice of Auction → Sealed Bid window (≥ 5 Working Days per Rule 10.5(d)) → Sealed Bid Submission Closing Date → Independent Audit → SoS Review	Allocation Framework Rules 10-17
11 September 2017, 07:00	Results published by BEIS to coincide with National Grid notification to applicants	results.md
Late 2017 - early 2018	CfD Agreements signed with all 11 successful applicants	LCCC register
2018	National Grid rebrands EMR Delivery Body function as "National Grid Electricity System Operator" (NG ESO)	Context
2018	Statkraft sells 50% Triton Knoll stake to J-Power / Kansai Electric consortium	Industry record
2019-20	RWE acquires innogy's renewables business (Triton Knoll) via 2018/19 RWE-E.ON asset swap	Industry record
2019	EDPR + ENGIE rebrand their 50/50 JV as Ocean Winds; CTG subsequently acquires minority stake (2019) in Moray East	Industry record
April 2022	Moray East fully operational (MHI Vestas V164 9.525 MW turbines, 100-turbine array)	Industry record
Summer 2022	Triton Knoll commissioned (Vestas V164-9.5 MW, HVAC)	Industry record
August 2022	Hornsea Project 2 fully operational (Siemens SWT-8.0-167 DD, 165-turbine array — world's largest operational offshore wind farm at commissioning)	Industry record
1 October 2024	NG ESO re-constituted as National Energy System Operator (NESO) — separate legal entity under state ownership	Context (post-auction)

The timeline highlights AR2's one-year compression from 13 March 2017 (statutory notices) to 11 September 2017 (results) — approximately 6 months from launch to award. This is substantially faster than AR3's 4-month application-to-results window (29 May 2019 → 20 September 2019) was within a longer overall cycle, and substantially faster than AR4 onwards.

5. Budget architecture

AR2's budget architecture differs structurally from AR3 in three ways: (i) the Monetary Budget is per Delivery Year, not a single combined figure; (ii) there is no Overall Capacity Cap; and (iii) a 150 MW cumulative maxima applies to the three fuelled technologies (Dedicated Biomass with CHP, ACT, AD) as a single combined cap.

5.1 Budget Notice (13 March 2017)

Overall budget (2011/12 prices, per the Budget Notice):

• £290 million for Delivery Year 2021/22
• £290 million for Delivery Year 2022/23
• Interpreted as: the maximum annual support payable under CfDs awarded in this round, measured in the relevant Delivery Year

Delivery Years: 2021/22 and 2022/23. Valuation Years (for Phased Offshore Wind): 2023/24 and 2024/25 (i.e. subsequent phases of Phased OSW CFD Units may have Target Commissioning Dates up to two years after the final Delivery Year — Budget Notice §Phased Offshore Wind Projects).

Pot allocation: "The available budget has been allocated to the less established technology group ('Pot 2')" (Accompanying Note §2). No Pot 1, no separate offshore-wind pot — every applicant competed in a single Pot 2 auction.

Eligible technologies (Budget Notice §"The 'less established' technologies included in this Pot 2 Allocation Round are"):

• Offshore Wind
• Advanced Conversion Technologies (with or without CHP)
• Anaerobic Digestion (with or without CHP, >5MW)
• Dedicated Biomass with CHP
• Wave
• Tidal Stream
• Geothermal (with or without CHP)

No Remote Island Wind (first introduced at AR3 via the June 2018 Part A response). No Floating Offshore Wind (first introduced at AR4).

5.2 CPI-indexing of budget

Inflator factor 1.0193 (2011/12 → 2012 CPI) to convert the £290m 2011/12-price annual budget to 2012 prices for valuation against 2012-price bids. This yields a 2012-price budget of £295 million rounded to the nearest £5m (Budget Notice §Re-basing CFD Budgets).

An illustrative current-price inflator to January 2017 values was published as 1.0761, for stakeholders converting the budget to current terms.

5.3 150 MW cumulative maxima on fuelled tech — the AR2-specific constraint

Budget Notice §Use of Maxima or Minima:

"A cumulative maxima of 150 MW will be applied in respect of the fuelled technologies: Dedicated Biomass with CHP, Advanced Conversion Technologies (with or without CHP) and Anaerobic Digestion (with or without CHP)."

This single cap across all three fuelled technologies combined is AR2's distinctive structural constraint, and did not recur in AR3 or later rounds. The Accompanying Note §11 states the rationale directly:

"While this policy review is ongoing, the Government considers it appropriate to limit the potential for committing to 15 year support for fuelled technology projects which will not deploy until 2021/22 or 2022/23. We have therefore imposed a temporary cumulative 150 MW maxima for the second Allocation Round."

The "policy review" refers to the November 2016 call for evidence on fuelled and geothermal technologies, which closed in December 2016 and had not yet concluded when the Budget Notice issued on 13 March 2017. BEIS wanted optionality to redirect fuelled-tech support elsewhere if the review concluded in that direction; capping the AR2 commitment at 150 MW bounded the exposure.

Outcome: The cumulative fuelled-tech award was 149.95 MW (85.64 MW Biomass with CHP + 64.31 MW ACT) — 0.05 MW under the cap, suggesting the cap was binding. The cap was not extended to AR3 (where fuelled tech was admitted without a cumulative cap). The fuelled-tech review did ultimately tighten efficiency standards (70% overall net-calorific-value efficiency for Biomass with CHP, and a new Physical Separation Requirement for ACT) at AR3, rather than exclude the technologies.

5.4 No Overall Capacity Cap

Unlike AR3's 6 GW overall capacity cap, AR2 had no capacity cap — the constraint was purely monetary (£290m per Delivery Year) plus the fuelled-tech maxima. Offshore wind was therefore effectively uncapped on capacity; the only limits were (i) the Monetary Budget per Delivery Year and (ii) the 1,500 MW per-CFD-Unit ceiling on Phased Offshore Wind.

5.5 No Minima

Accompanying Note §9 records BEIS's explicit decision to drop the AR1 100 MW Wave/Tidal minima:

"That Wave and Tidal Stream minima has not been extended to the second CFD Allocation Round as the expected costs for this technology remain high following their early development stage. Reserving a proportion of the budget for these technologies - at the expense of other potentially less expensive technologies in Pot 2 - does not represent good value for money for consumers."

Wave and Tidal Stream remained eligible to compete, but without reserved capacity. None won at AR2.

5.6 Phased Offshore Wind capacity rules

The Allocation Framework Rule 4(a) codifies Phased Offshore Wind CFD Units as a first-class structural concept:

• (i) after all phases complete, CFD Unit capacity ≤ 1,500 MW (Rule 4(a)(i))
• (ii) the first phase must represent at least 25% of the total capacity (Rule 4(a)(ii))
• (iii) the first phase must target completion by no later than 31 March 2023 (i.e. within Delivery Year 2022/23) (Rule 4(a)(iii))
• (iv) the Target Commissioning Date of the last phase must be no later than 2 years after the first phase TCD (Rule 4(a)(iv))
• Budget Notice §Phased Offshore Wind Projects confirms Phases subsequent to the first may have TCDs up to two years after the final Delivery Year (the "Valuation Years" 2023/24-2024/25)

All three AR2 Offshore Wind winners used the 3-phase structure (Triton Knoll, Hornsea 2, Moray East — each with 3 phases confirmed in the LCCC Register).

Note the contrast with AR3: at AR3 the first-phase TCD deadline was 31 March 2025 (AR3's final Delivery Year). At AR2 the equivalent deadline was 31 March 2023 (AR2's final Delivery Year). The 2-year tail and the 1,500 MW cap are identical between AR2 and AR3.

6. Administrative Strike Prices

ASPs in AR2 cap the Strike Price each Generator can receive: even if the auction cleared at a higher price, no Generator receives more than its technology's ASP for its Delivery Year (Allocation Framework Rule 11.1(a)(i): "the Applicant's proposed Strike Price in pounds sterling that it will accept for each megawatt hour of Metered Output, which must not be more than the applicable Administrative Strike Price"; Rule 16.2 similar cap on clearing).

AR2's ASPs are per-Delivery-Year (distinct from AR4's single-ASP-per-technology-across-DYs convention). Each technology has two values, one per Delivery Year.

6.1 AR2 ASPs (2012 prices)

From Budget Notice Table 2:

Technology	2021/22 ASP	2022/23 ASP
Offshore Wind	£105	£100
Advanced Conversion Technologies (± CHP)	£125	£115
Anaerobic Digestion (± CHP, >5MW)	£140	£135
Dedicated Biomass with CHP	£115	£115
Wave	£310	£300
Tidal Stream	£300	£295
Geothermal (± CHP)	£140	£140

Note: Offshore Wind ASP fell £5 between Delivery Years (£105 → £100), reflecting an implicit annual cost-decline assumption of ~5% in the supply curve underlying the ASP methodology.

6.2 Methodology — 19% supply-curve targeting

The ASP methodology (asp-methodology.md, published 9 November 2016, 15 pages) 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 targeting the price at which the cheapest 19% of the pipeline becomes economically viable. This 19% cut-off was AR2-specific; AR3 widened this to 25% across all technologies; AR4 then doubled to 50% for offshore wind alone.

Key ASP-methodology inputs for Offshore Wind:

• Supply curves constructed from planning-consented projects, weighted by a probability of participation
• Capex varies with turbine size — larger turbines → lower £/MW capex
• Load factors — estimated from Met Office wind-speed data + turbine power-curve models at project-specific sites
• TNUoS charges — per-project estimates from National Grid forecast tariffs
• Decommissioning costs — from BEIS's ARUP-developed decommissioning cost model
• Hurdle rates from a Europe Economics report commissioned by BEIS; the assumed ~2 GW of eligible projects competing reflected the Round 3 pipeline weight

AR2 was the first ASP round to explicitly benchmark against committed cost evidence (CCCs) from post-FID projects in delivery — a practice that became standard from AR3 onwards. The £105/£100 values were calibrated with reference to AR1 cost data and the post-2015 project pipeline.

6.3 AR2 ASP in context

Round	Year	Offshore Wind ASP (2012 prices)
AR1	2015	£155 (2017/18), £150 (2018/19)
AR2	2017	£105 (2021/22), £100 (2022/23)
AR3	2019	£56 (2023/24), £53 (2024/25)
AR4	2022	£46 (single ASP 2025/26 + 2026/27)

AR2's ASPs of £105/£100 were ~32% below AR1's £155/£150. AR3 then dropped a further ~47% versus AR2. The cumulative ASP trajectory from AR1 to AR3 was a ~65% decline over four years.

7. Qualification criteria

To submit a bid, every applicant must first be determined a Qualifying Application by the Delivery Body (National Grid) under Regulation 19. The Delivery Body applies the set of checks codified in Allocation Framework Schedule 4 (general eligibility, technology-specific conditions, project-specific evidence). AR2's qualification is binary — no Soft Constraints were applied (Soft Constraints are a later-rounds feature; AR2 had neither Soft Constraints nor Maxima/Minima of that character).

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

Per Allocation Framework Schedule 4 and the cross-referenced Regulations:

• Eligible Generator status under the Contracts for Difference (Definition of Eligible Generator) Regulations 2014 — excludes, inter alia, already-Commissioned Generating Stations (Rule 5.1(b))
• Company incorporation evidence — UK Certificate of Incorporation, VAT registration, or non-UK equivalent (Schedule 4)
• Applicable planning consents (Regulations 23, 24) — signed and dated Planning Decision Notice consistent with the Application's technology, capacity (≥ stated Application capacity), and location (Schedule 4)
• Grid Connection Agreement (Regulation 25) — evidence of:
  • For Direct Connection to Transmission System: "Transmission Entry Capacity for the CFD Unit at least equal to 75% of the Initial Installed Capacity Estimate" (Schedule 4)
  • For Distribution System: Connection Agreement permitting "at least 75% of the Initial Installed Capacity Estimate"
  • For Phased Offshore Wind: a separate Connection Agreement in relation to each phase of that Application (Schedule 4)
• Non-receipt of other government support (Regulations 14, 18) — confirm no NFFO, SRO, RO accreditation, or Capacity Market contract applicable
• Target Commissioning Date within Delivery Year — TCD must fall within the Delivery Year specified in the Application (Schedule 5 specifies 1-year TCW for AR2 technologies)
• Supply Chain Plan Statement — for projects of 300 MW or more, a BEIS-issued SCP Approval Certificate (see §7.3 below) required before application

7.2 Technology-specific gates and exclusions

• Phased Offshore Wind structural rules — Rule 4(a): 1,500 MW cap, first-phase ≥ 25%, first phase TCD ≤ 31 March 2023, final phase TCD ≤ 2 years after first phase
• AD capacity floor — no Application may be made in respect of an AD (± CHP) CFD Unit where the capacity ≤ 5 MW (Rule 5.1(a))
• Commissioned-station exclusion — no Application may be made in respect of a CFD Unit that is or is part of a Commissioned generating station (Rule 5.1(b)), with an exception for Biomass Conversion / CCS Conversion generating stations that have not been Commissioned following conversion
• EfW with CHP + RHI double-support exclusion — a CFD Unit of Technology Type "Energy from Waste with CHP" where an application for accreditation has been made under the Renewable Heat Incentive Regulations 2011 is excluded (Rule 5.1(c))
• Remote Island Wind — NOT ELIGIBLE at AR2. RIW is not listed as a Technology Type in the Budget Notice Table 2 or the Allocation Framework Schedule 4. RIW was first admitted as a distinct CfD technology at AR3 (following the January 2018 EU State aid approval SA.49318 and the June 2018 Part A government response).
• Floating Offshore Wind — NOT ELIGIBLE at AR2. FOW is not listed as a Technology Type in AR2. FOW was first admitted as a distinct CfD technology at AR4 (following the 2020 consultation response).
• Advanced Conversion Technology Physical Separation Requirement — NOT YET IN FORCE at AR2. The Physical Separation Requirement between Synthesis Chamber and Combustion Chamber was introduced at AR3 (Regulation 28, Schedule 4). At AR2, ACT qualification was lighter-touch.
• CHP efficiency threshold — 35% at AR2. The 70% overall efficiency threshold (net calorific value) for Dedicated Biomass with CHP and EfW with CHP was introduced at AR3 via the June 2018 Part A response. At AR2, Biomass with CHP projects had to meet the then-applicable ~35% CHPQA efficiency standard.

7.3 Supply Chain Plan — the binary quality gate

For all projects of 300 MW or more, a BEIS-issued SCP Approval Certificate is a hard pre-auction qualification gate (Allocation Framework Schedule 4; supply-chain-plan-guidance.md §1 Purpose). At AR2, the 300 MW threshold captured all three offshore-wind applicants that ultimately won (Hornsea 2 at 1,386 MW, Triton Knoll at 860 MW, Moray East at 950 MW — and also the then-bid Hornsea Project 1 which had secured AR1 funding already).

The SCP Guidance for AR2 (originally 9 November 2016, updated 25 November 2016 to extend maximum SCP length from 30 to 40 slides) required applicants to describe their approach across three dimensions:

• Competitive Supply Chains — UK supply-chain infrastructure investment commitments
• Innovation — innovation investment, demonstrator commitments, R&D
• Skills — skills/apprenticeship commitments in the UK supply chain

BEIS scored responses; applicants passing the threshold received an SCP Approval Certificate. AR2's SCP regime was lighter-touch than AR3 or AR4's — there was no "SCP Post-Approval" monitoring regime yet. Post-award monitoring via PBR (Post Build Report) / iPBR (Interim Post Build Report) was introduced at AR3. Post-award monitoring as an in-contract Outstanding Condition Precedent via the Supply Chain Implementation Statement (SIS) was introduced at AR4. AR2's SCP bite was entirely pre-auction: secure the Certificate, or be non-qualifying.

7.4 Non-Qualification and Appeals

• Delivery Body must issue qualification determination "no later than 15 working days after the application closing date" (Allocation Framework Rule 7.1; Regulation 19). At AR2 this meant approximately 12 May 2017
• Non-Qualification Review Request Date: 16 May 2017 (Rule 8.1(a))
• Applicant may request a Non-Qualification Review, which the Delivery Body must respond to within the statutory window
• Appeals Deadline Date: 13 June 2017 (Rule 8.1(b)) — deadline for Qualification Appeal to Ofgem (GEMA) under Regulation 43
• No AR2 Qualification Appeals are documented in the primary source-set

8. The prize — CfD contract mechanics

Each AR2 winner receives a Contract for Difference Agreement between the Generator and the CfD Counterparty (Low Carbon Contracts Company Ltd). The CfD is a 15-year revenue-support instrument: Generic Agreement Clause 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.md). The Generic Agreement is a 35-page wrapper that incorporates the 541-page FiT CfD Standard Terms and Conditions Version 2 by reference (standard-terms-and-conditions.md).

Revenue mechanism in essence:

• If the market price (Market Reference Price, defined by technology) < Strike Price: LCCC pays Generator the difference per MWh of Loss Adjusted Metered Output (after TLM, RQM, and CHPQM adjustments)
• If the market price > Strike Price: Generator pays LCCC the difference per MWh
• Payments calculated against the Net Payable Amount (Condition 22.4(D)): Net Payable Amount = Aggregate Difference Amount + Reconciliation Amount + Compensatory Interest Amount
• LCCC pays Generator within 28 calendar days of the relevant Billing Period (Condition 23.1)
• Generator pays LCCC within 10 Business Days of Billing Statement delivery if the Net Payable Amount is negative (Condition 23.2)

The Strike Price is set in 2012 prices and CPI-indexed annually on the Indexation Anniversary per Condition 14, using the formula Inflation Factor (Π_t) = CPI_t / CPI_base where CPI_t is the CPI for January of the relevant calendar year and CPI_base is the CPI for October of the calendar year preceding the Base Year (2012).

Reference Price — two layers, not to be conflated:

Valuation (pre-auction, National Grid Delivery Body): Allocation Framework Schedule 2 Appendix 2 sets out reference-price series in 2012 prices used to value each Qualifying Application against the budget. For AR2 these are (£/MWh, 2012 prices):

Year	Reference Price
2021/22	£39.86
2022/23	£42.60
2023/24	£47.68
2024/25	£52.29

In-life settlement (post-award, LCCC): the Budget Notice accompanying note's general description — and Standard Terms Version 2 Annex 4 / Annex 5 — set the post-award reference prices:

• Baseload Market Reference Price (BMRP) — season-ahead day-ahead baseload, half-hour Settlement Unit (Generic Agreement Annex 3 Part A). Applies to ACT, AD, Biomass with CHP, Geothermal
• Intermittent Market Reference Price (IMRP) — day-ahead hourly volume-weighted average, one-hour Settlement Unit (Generic Agreement Annex 3 Part B). Applies to Offshore Wind, Wave, Tidal Stream

Negative-pricing rules — the six-hour threshold.

AR2 Standard Terms Version 2 carry the same rolling-window negative-pricing exclusion that AR3 inherited:

• Intermittent Rolling Negative Price Period (STCs v2, definitions): "a period of six (6) or more consecutive Settlement Units (irrespective of whether such Settlement Units fall within the same Billing Period) in respect of which the Intermittent Market Reference Price is negative (that is, less than £0/MWh)". During such a period, the Intermittent Difference Amount is set to zero (Condition 18.2-18.3)
• Baseload Rolling Negative Price Period = a period of twelve (12) or more consecutive Settlement Units where the IMRP during the corresponding six (6) Intermittent Settlement Units is negative. During such a period, the Baseload Difference Amount is set to zero (Condition 10.2-10.3)

This rolling-window threshold — six consecutive hours of negative IMRP — is identical to AR3's treatment. The reform to a strict-negative rule came at AR4 (2020 consultation response, implemented via the AR4 CfD contract and associated regulations). AR2 CfD holders therefore benefit from the same more-generous negative-price treatment as AR3 — any individual negative Settlement Unit within a short run of negatives still attracts the Difference Amount; only when 6 consecutive hours breach the threshold does the zero-difference-amount regime activate.

Key Standard Terms Version 2 provisions relevant to extraction:

• Target Commissioning Window (TCW): 1 year across all AR2 technologies per Standard Terms Notice Table G (13 March 2017). Identical to AR3
• Longstop Period and Longstop Date: specified per Facility Generation Technology in Table H of the AR2 Standard Terms Notice (13 March 2017). The Longstop Date formula is TCW End + Longstop Period + FM Extensions (Standard Terms v2 definitions). After Longstop, LCCC may terminate under Condition 51.1(E) if Operational Conditions Precedent are not fulfilled
• Milestone Requirements (Condition 4): Generator must deliver a Milestone Requirement Notice by the Milestone Delivery Date, evidenced either by (A) 10% of Total Project Pre-Commissioning Costs spent, or (B) compliance with Project Commitments. Generic Agreement Clause 5.5 sets the Initial Milestone Delivery Date at twelve (12) months after the Agreement Date — the same 12-month clock as AR3 (AR4 extended this to 18 months). LCCC has 20 Business Days to respond (Condition 4.3), may request further information (Condition 4.4), and if still not satisfied may terminate under Condition 51.1(A)
• Non-Delivery Disincentive: AR2 does not impose a financial-penalty NDD. Instead, the NDD mechanism is contract termination without payment — Condition 51.1(A) grants LCCC the right to terminate Pre-Start Date if MDD is missed; Condition 52.2 confirms no termination payment is due on a Pre-Start Date termination. The same framework as AR3
• Change in Law (CIL) mechanism: Condition 33-36. Three compensation methodologies: QCiL Capex Payment (capital impact), QCiL Adjusted Revenues Payment (operating impact), QCiL Operations Cessation Event Payment (shutdown). Pass-through is asymmetric: before Start Date, Generator recovers full QCiL Compensation or may terminate; after Start Date, CIL must be Material to trigger compensation. The AR2 STC v2 clarifies the definition of "Foreseeable Change in Law" via the February 2017 Government Response — a distinctive AR2 amendment (a foreseeable CiL is no longer automatically grounds for a Qualifying Change in Law claim)
• EU State Aid regime: AR2 Standard Terms v2 retain extensive EU State Aid references and strengthen the anti-cumulation rules through the February 2017 Government Response-driven amendments. Condition 32.4-32.15 contains the No Cumulation of State Aid Warranty; Condition 3.31 provides for set-off of prior State Aid (including interest calculated at the EU Reference Rate Methodology); Condition 32.11 sets the State Aid Interest Rate. State Aid Competent Authority = European Commission. Generic Agreement Clause 6 — Accrual of Payments prior to State Aid approval — provides a conditional-start-date mechanism applicable if Facility Generation Technology is Biomass Conversion ≥250 MW and the State Aid Condition Precedent has not been satisfied by the Start Date
• Storage on CfD sites: AR2 STC v2 introduces the first clarified treatment of co-located storage on CfD generating-station sites — a direct output of the February 2017 Government Response. Storage output is expressly separated from Metered Output for CfD payment purposes
• Phased Offshore Wind CFD Units: the Standard Terms do not contain per-phase sub-contracts — a Phased Offshore Wind CFD Unit is a single CfD covering the full project capacity. The Allocation Framework Rule 4(a) and Rule 12 provide the phased-unit structural rules

There is no Clean Industry Bonus in AR2 (CIB was introduced for AR7 via the 2024 Targeted Reform) and no Supply Chain Implementation Statement (SIS) as an Outstanding Condition Precedent (SIS was introduced for AR4). AR2 is purely price-competitive (see §9 on Scoring).

EU State Aid vs UK Subsidy Control — the transition question. AR2 contracts were signed under the EU State Aid regime (scheme SA.44475, approved 26 July 2017). Post-Brexit, the UK Subsidy Control regime replaced State Aid for new subsidies (via the Subsidy Control Act 2022) but existing AR2 contracts continue to reference EU bodies via retained EU law. AR4's post-Brexit redesign stripped the EU State Aid references from the AR4 contract terms. This is a schema-relevant distinction: AR2's Auction.subsidy_regime = EU_STATE_AID (with regulatory_scheme_id = SA.44475) vs AR4+'s UK_SUBSIDY_CONTROL. In practice, since 2020, most references to "State Aid Competent Authority" have been exercised by UK counterparties (BEIS/DESNZ/LCCC) rather than the European Commission, but the contractual framework on AR2-signed CfDs continues to reference EU bodies.

9. Evaluation criteria, process, and scoring

AR2 uses a pay-as-clear sealed-bid auction with single-price-dimension scoring (price only). No non-price factors are scored. This is identical in form to AR3-AR6; AR7 introduced the Clean Industry Bonus as a separate non-price stream.

9.1 Application Valuation formula

Per Allocation Framework Schedule 2, National Grid values each application using:

Budget impact_{s,yr,p} = (Strike Price_{cy,t} − Reference Price_{yr}) × Load Factor_{t,yr} × YR1F_{s,c,p} × Capacity_{s,p} × (Days_{yr} × 24) × (1 − TLM_{yr}) × RQM_t × 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 bid is lower than the Reference Price for a given year contribute zero to that year's budget consumption). This truncation became practically relevant at AR3 (where clearing dipped below Reference Price across all valuation years); at AR2, the £74.75 and £57.50 clearing prices both sat above the Reference Prices (£39.86/£42.60/£47.68/£52.29) and so contributed meaningful positive budget impact in all four valuation years.

Schedule 2 Appendix 4 Transmission Loss Multiplier (TLM): applied as (1 - TLM) = 0.9921 in each year (TLM of 0.79% per Delivery/Valuation Year for AR2 — slightly tighter than AR3's 0.87%).

Schedule 2 Appendix 5 Renewable Qualifying Multiplier (RQM):

Technology	RQM
Offshore Wind	1
ACT (with or without CHP)	0.5
AD (with or without CHP, >5MW)	1
Dedicated Biomass (with CHP)	1
Geothermal (with or without CHP)	1
Tidal Stream	1
Wave	1

CHPQM defaults to 1.0 across AR2 technologies.

YR1F adjusts for partial-year generation in the first year of operation — calculated as 1 - (Days between TCD and start of FY) / (Days in FY) for projects commissioning mid-year, and set to 1 for projects commissioning in the final valuation year (Schedule 2 Valuation Formula).

Load Factors (Allocation Framework Appendix 3) — AR2 values for key technologies:

Technology	Load Factor
Offshore Wind	47.7%
ACT (with or without CHP)	83.2%
AD (>5 MW)	79.1%
Dedicated Biomass with CHP	80.4%
Geothermal (± CHP)	91.2%
Tidal Stream	30.8%
Wave	30.0%

These are valuation-formula load factors — not the load factors used to calculate actual CfD payments, which are based on Metered Output. Note the material step-up from AR2's Offshore Wind 47.7% to AR3's 58.4%: between 2016 (the AR2 methodology date) and 2018 (the AR3 methodology date), the Load Factor assumption was raised by ~11 percentage points, reflecting the industry's transition to 8 MW+ turbines with improved capacity factors. Both AR4 (63.1%) and later rounds pushed this further.

Reference Prices for valuation (Schedule 2 Appendix 2, 2012 prices):

Year	Reference Price
2021/22	£39.86
2022/23	£42.60
2023/24	£47.68
2024/25	£52.29

The Reference Prices are single-series across all AR2 technologies (both Baseload and Intermittent treated identically at the valuation stage) — a convention that changed at AR3 where separate Baseload and Intermittent series were introduced. For AR2's valuation purposes a single Reference Price was applied per year across all technologies.

Days per year (Schedule 2 Appendix 6) — for leap-year handling in the valuation formula: 2021/22 = 365, 2022/23 = 365, 2023/24 = 366, 2024/25 = 365.

9.2 Bid submission

Each application may submit up to 4 Flexible Bids in total (Allocation Framework Rule 11.5: "For each Application, an Applicant may submit up to four Flexible Bids (inclusive of the original sealed bid) which are sealed bids with varying capacities and/or Target Commissioning Dates, of which no more than two bids may have a Target Commissioning Date in the same Delivery Year").

The four-bid set comprises:

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

Strike Price precision:

• Lowest Strike Price bid in each Delivery Year must be to the nearest whole penny (Rule 11.4)
• Flexible Bids otherwise expressed to the nearest 0.1 of a penny (Rule 11.6(b))
• AR2's clearing prices are expressed to two decimal places (£74.75, £57.50) — the last accepted bids in each Delivery Year appear to have been at the whole-penny precision threshold

Default bid at ASP (Rule 11.8): "Where no sealed bid is submitted by an Applicant by the Submission Closing Date, the Delivery Body must assign the Application a bid of the Administrative Strike Price for its Technology Type, Target Dates and capacity, as specified in the Application."

Phased Offshore Wind CFD Units (Rule 12):

• Single Strike Price applies to all phases in a given bid (Rule 12.1(a))
• First phase's Target Commissioning Date is treated as the first Target Commissioning Date (Rule 12.1(b))
• All phases must be taken into account when assessing the budget impact (Rule 12.1(c))
• Flexible Bids can vary later-phase dates and later-phase capacities but cannot change the first phase's TCD to earlier than Original, nor have first-phase capacity greater than Original (Rule 12.2)

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

Allocation Framework Rules 9 and 16 run the auction. AR2 uses the "no Pot specified" variant of Rule 9 (Rule 9.3), because the Budget Notice allocated the full £290m Overall Budget to a single Pot 2:

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

• National Grid values all Qualifying Applications against the Monetary Budget.
• If cumulative value ≤ Overall Budget in every Delivery Year, all applications are Successful at their Administrative Strike Prices (no auction held).
• Otherwise, an auction is held.

Step 2: Check fuelled-tech Maxima (Rule 9.5)

• If the capacity sum of fuelled-tech applications (Biomass with CHP + ACT + AD) ≤ 150 MW cumulative maxima and the value of those applications (at ASP) does not push the Overall Budget over, treat those applications as part of the Pot/Overall Budget calculation
• If the capacity sum exceeds 150 MW, hold a Maxima auction per Rule 17

Step 3: Order of auctions (Rule 14.1)

• Minima auctions first (AR2 had none, skipped)
• Maxima auctions next (AR2 had the 150 MW fuelled-tech maxima)
• Then the Overall Budget auction

Step 4: Run the Overall Budget auction (Rule 16)

• Delivery Body issues Notice of Auction, invites sealed bids. Submission Closing Date is "no less than five Working Days after the day the Delivery Body issues the Notice of Auction" (Rule 10.5(d))
• Between Notice of Auction and Submission Closing Date, the Secretary of State has a 5-working-day window to issue a Budget Revision Notice (Rule 10.2) — no such Notice was issued for AR2
• All bids are ranked from lowest Strike Price to highest, regardless of Delivery Year (Rule 16.2)
• Starting from the lowest bid, the Delivery Body walks up the stack, provisionally accepting bids up to but not including the first bid that would cause the Overall Budget to be exceeded
• The clearing price for Successful Applications is the Strike Price of the last accepted bid in the relevant Delivery Year, capped at the ASP — for AR2 this produced separate per-Delivery-Year clearing prices: £74.75/MWh (2021/22) and £57.50/MWh (2022/23)

Interleaving bids process (Rule 16.3): if a bid from one Applicant is blocked by the Overall Budget, the Delivery Body considers bids from other Applicants (working up the price stack) until it reaches the next Flexible Bid from the blocked Applicant. This allows the blocked Applicant to substitute a lower-priced Flexible Bid for its original sealed bid.

9.4 Tiebreaker rules

The Allocation Framework provides three tiebreaker scenarios (Rule 18), applied when two or more bids share the same Strike Price and cannot all succeed:

• Minima or Maxima only tiebreaker (Rule 18.1): tied bids that would cause a Minima or Maxima (but not the Overall Budget) to be exceeded — pick the combination of applications closest to fulfilling the Overall Budget in the final Budget Profile year without exceeding the Minima/Maxima; if multiple combinations are equally close, random assignment via electronic randomiser
• Budget only tiebreaker (Rule 18.2): tied bids that would cause the Pot/Overall Budget to be exceeded — pick the combination closest to fulfilling the Pot/Overall Budget without exceeding it; random if tied. Rule 18.3 confirms such unsuccessful bids trigger the Interleaving Bids process. Rule 18.4: where 18.2 applies and both applicants' next Flexible Bids would both be Successful, both succeed; otherwise neither
• Minima or Maxima and budget tiebreaker (Rule 18.5): combined test. Closest-to-fulfilling test with both constraints; at end of this tiebreaker, unsuccessful maximum bids are removed from the stack and their Delivery Years remain open (Rule 18.5(d)); other unsuccessful bids trigger the Interleaving process (Rule 18.5(e))

For AR2 the Rule 18.1 (Minima/Maxima only) test was structurally available via the fuelled-tech cap (150 MW), but the fuelled-tech cumulative award was 149.95 MW — 0.05 MW under — so the 18.1 test apparently resolved without ties. The Rule 18.2 (Budget only) test was available. The Rule 18.5 (combined) test was available. No public tiebreaker invocation is reported in AR2's Results publication. The auction appears to have cleared cleanly with successful applications receiving the same Strike Price within each Delivery Year.

9.5 Soft Constraints

AR2 did not use Soft Constraints. Soft Constraints are a later-rounds feature (they are a mechanism for a constraint that bids may exceed under conditions, distinct from a hard Maxima). AR2's 150 MW fuelled-tech cumulative cap is a hard Maxima, not a Soft Constraint.

9.6 No non-price factors in AR2 scoring

AR2 is a pure-price auction. Qualifying Applications pass a set of binary gates (SCP for ≥300 MW, planning, grid, phased-OSW structural rules) but their ranking within the auction is determined solely by Strike Price bid. Multi-criteria scoring (Clean Industry Bonus, supply-chain uplift) was not introduced until AR7. AR2's scoring dimension list has a single entry: price, weight=100, weight_interpretation=share_of_total_score, with direction=lower_wins.

10. Competitive landscape — what bid, what cleared

Panel (C) of the Results doc — "The total value of all applications originally received, valued at the Administrative Strike Price" (2012 prices) — is the best available public view of the AR2 bid-stack:

Pot 2 Total Value at ASP	2021/22	2022/23	2023/24	2024/25
	£1,144,766,272.11	£1,567,676,545.34	£1,469,162,505.10	£1,369,463,845.48

(The 2023/24 and 2024/25 columns reflect phased-project valuation years after Delivery Years, per Phased Offshore Wind structural rules.)

Read as an indicator of oversubscription: the £290m Overall Budget was oversubscribed by a factor of roughly 4× in 2021/22 (£1,144m value at ASP vs £290m budget) and roughly 5.4× in 2022/23 (£1,567m vs £290m). The £1.57bn in 2022/23 peak was driven by the Hornsea 2 (1,386 MW × £100 ASP × ~47.7% LF × 8,760 hours × ~0.9921 TLM × 1 RQM — a single application contributing several hundred million at ASP) and Moray East (950 MW) contributions. The mid-2020s valuation-year totals of ~£1.47bn (2023/24) and ~£1.37bn (2024/25) reflect phased OSW valuation-year sizing — Phased OSW projects' later phases contribute budget impact in the Valuation Years 2023/24 and 2024/25.

The estimated notional Monetary Budget impact (Panel B, based on clearing prices) was:

Pot 2 Notional Impact	2021/22	2022/23	2023/24	2024/25
	£21,724,242.99	£170,471,434.83	£176,180,301.61	£148,538,708.02

Positive across all years — AR2 cleared above the Reference Prices in every valuation year, so the Valuation Formula produced genuine positive budget impact. This contrasts with AR3, where clearing fell below Reference Price across all years and the notional impact was negative (truncated to zero).

Total cumulative notional impact: ~£517m across the four valuation years — within the £290m × 4-year envelope given the positive reference-price-spread contributions.

Public bidder-level data is not available for AR2. Only clearing prices and the winning roster are known from primary sources. Individual Flexible Bid content and bid-level data remained confidential. This contrasts with AR7 (2025), where Rule 13 introduced anonymised bid disclosure to enable mid-round Budget Revision.

11. Results — offshore wind winners

Results doc Panel (A), rows filtered to Offshore Wind (2012 prices):

Project	Region	Applicant (SPV)	Capacity (MW)	Strike Price (£/MWh)	Delivery Year	Phases
Triton Knoll Offshore Wind Farm	England	Triton Knoll Offshore Wind Farm Limited	860.00	74.75	2021/22	3
Hornsea Project 2	England	Breesea Limited	1,386.00	57.50	2022/23	3
Moray Offshore Windfarm (East)	Scotland	Moray Offshore Windfarm (East) Limited	950.00	57.50	2022/23	3
Total			3,196.00

The Delivery Year listed is for Phase 1 — subsequent phases commission into later years per the Phased Offshore Wind rules. Results doc Panel (A) footnotes 1, 2, 3 confirm: "Triton Knoll will be built in three phases; 2021/22 is the delivery year for phase 1", etc.

Panel (D) confirms the aggregate (2012 prices):

Technology	2021/22 Price (£/MWh)	2021/22 MW	2022/23 Price (£/MWh)	2022/23 MW	Total Capacity (MW)
Offshore Wind	74.75	860	57.50	2,336	3,196.00
Dedicated Biomass with CHP	74.75	85.64	N/A	0	85.64
ACT	74.75	56.31	40.00	8	64.31

Panel (E) confirms the saving vs ASP:

Technology	ASP 2021/22	Clearing 2021/22	% saving	ASP 2022/23	Clearing 2022/23	% saving
Offshore Wind	£105	£74.75	29%	£100	£57.50	43%
Dedicated Biomass with CHP	£115	£74.75	35%	£115	N/A	N/A
Advanced Conversion Technologies	£125	£74.75	40%	£115	£40.00	65%

11.1 Detailed project notes

Triton Knoll Offshore Wind Farm (innogy/Statkraft → RWE): 860 MW project in the Greater Wash, approximately 32 km off the Lincolnshire coast. Development consent granted July 2013 under the Crown Estate Round 2 extension regime. At AR2 bid time (April 2017) the project was a 50/50 JV between innogy SE (formerly RWE's renewables subsidiary; RWE would later re-acquire innogy's renewables business in the 2019-20 RWE/E.ON asset swap) and Statkraft (Norwegian state utility). Statkraft sold its 50% stake in August 2018 to a J-Power/Kansai Electric consortium. By project commissioning, the ownership was RWE (inheriting from innogy post-asset-swap) and J-Power/Kansai. Triton Knoll won the 2021/22 Delivery Year slot at £74.75/MWh — the higher of AR2's two clearing prices, reflecting its earlier delivery commitment. Commissioned Summer 2022 using Vestas V164-9.5 MW turbines (90 units × 9.5 MW = 855 MW nameplate, slightly under the 860 MW awarded capacity; the LCCC register reflects the as-built capacity). HVAC transmission — the largest HVAC-connected UK offshore wind project at commissioning.

Hornsea Project 2 (Ørsted, then DONG Energy): 1,386 MW project in the Hornsea Zone, approximately 89 km off the Yorkshire coast — the remotest operational offshore wind project at the time of commissioning. Development consent granted August 2016 under Crown Estate Round 3. The applicant SPV was Breesea Limited — one of Ørsted's project-specific SPVs for Round 3 Hornsea Zone projects (Optimus Wind Ltd was the Project 1 vehicle, Breesea the Project 2 vehicle). AR2 bid time the parent was DONG Energy (Danish state-majority utility, rebranded to Ørsted in October 2017 after its 2016 IPO and divestment of upstream oil & gas). Hornsea 2 won the 2022/23 Delivery Year at £57.50/MWh — AR2's record-setting lower clearing price. Fully operational August 2022 using Siemens SWT-8.0-167 DD direct-drive turbines (165 units × 8.0 MW nameplate = 1,320 MW installed, with an uprating to 8.4 MW bringing as-built capacity closer to 1,386 MW). HVAC transmission via two offshore substations. World's largest operational offshore wind farm at commissioning (subsequently overtaken by Dogger Bank and Hornsea 3).

Moray East (EDPR/ENGIE → Ocean Winds): 950 MW project in the Moray Firth, approximately 22 km off the Caithness coast, north-east Scotland. Development consent granted June 2014 under Crown Estate Round 3. At AR2 bid time the project was owned by the EDPR/ENGIE 50/50 JV "Moray Offshore Windfarm (East) Limited". The JV was rebranded as Ocean Winds in late 2019/early 2020, coinciding with the formation of EDPR+ENGIE's global 50/50 offshore-wind platform. CTG (China Three Gorges) acquired a minority stake in 2019 — specifically a 10% interest in the Moray East project (with the remaining 90% split 45/45 between EDPR and ENGIE). Moray East won the 2022/23 Delivery Year at £57.50/MWh. Fully operational April 2022 using MHI Vestas V164-9.525 MW turbines (100 units × 9.525 MW = 952.5 MW) — the world's first offshore wind project using the 9.525 MW rating. HVAC transmission via two offshore substation platforms.

11.2 Winning entities — corporate group view

Counting distinct corporate groups at AR2 bid time (offshore wind only):

#	Corporate group at AR2 bid	Project / Capacity	Today
1	innogy SE + Statkraft (50/50 JV)	Triton Knoll (860 MW)	RWE + J-Power/Kansai Electric (RWE inherited innogy; Statkraft sold 2018 to J-Power/Kansai)
2	DONG Energy (single majority-state utility)	Hornsea 2 (1,386 MW)	Ørsted (rebranded October 2017)
3	EDPR + ENGIE (50/50 JV)	Moray East (950 MW)	Ocean Winds (EDPR + ENGIE platform, with CTG 10% in Moray East)

3 distinct corporate groups across 3 offshore-wind CFD Units. Each winner is from a different primary parent (RWE-lineage, Ørsted, EDPR/ENGIE) — the most diverse developer mix of any UK CfD offshore-wind cohort.

12. Results — non-offshore-wind cohorts

Note: Fuelled tech (Biomass with CHP, ACT) is out of scope for AgentZero's offshore-wind focus; presented here for AR2 completeness.

12.1 Dedicated Biomass with CHP (2 projects, 85.64 MW, all at £74.75/MWh for 2021/22)

Project	Region	Applicant (SPV)	Capacity (MW)
Grangemouth Renewable Energy Plant	Scotland	Grangemouth Renewable Energy Limited	85.00
Rebellion	England	Rebellion Biomass LLP	0.64

12.2 Advanced Conversion Technologies (6 projects, 64.31 MW)

Project	Region	Applicant (SPV)	Capacity (MW)	Strike Price	Delivery Year
Drakelow Renewable Energy Centre	England	Future Earth Energy (Drakelow) Limited	15.00	74.75	2021/22
Station Yard CFD 1	Wales	DC2 Engineering Ltd	0.05	74.75	2021/22
Northacre Renewable Energy Centre	England	Northacre Renewable Energy Limited	25.50	74.75	2021/22
IPIF Fort Industrial REC	England	Legal and General Prop Partners (Ind Fund) Ltd	10.20	74.75	2021/22
Blackbridge TGS 1 Limited	England	Think Greenergy TOPCO Limited	5.56	74.75	2021/22
Redruth EfW	England	Redruth EFW Limited	8.00	40.00	2022/23

The cumulative fuelled-tech award was 149.95 MW (85.64 Biomass-CHP + 64.31 ACT) — 0.05 MW below the 150 MW cumulative maxima, suggesting the Maxima was binding and that at least one marginal fuelled-tech bid was excluded through the cap.

The Redruth EfW £40/MWh anomaly is AR2's most unusual clearing-price outcome. All other fuelled-tech awards cleared at £74.75/MWh (the 2021/22 clearing price) in the combined-DY auction; Redruth EfW's £40.00/MWh bid was exceptionally low — far below not only AR2's other clearings but even AR3's £39.65 2023/24 benchmark (two years later). The most plausible interpretation: Redruth EfW was a small, structurally-unusual project with commercial dynamics (tipping-fee revenue, strong grid location, small owner-operator) that allowed sub-£40 viability. This bid effectively set the 2022/23 clearing for the single ACT project that won there (Redruth itself) — a degenerate clearing case where the only 2022/23 ACT bid set the clearing for itself.

13. Clearing prices — analysis

13.1 Overall savings by technology

From Panel (E) of the Results doc:

Technology	ASP 2021/22	Clearing 2021/22	% saving	ASP 2022/23	Clearing 2022/23	% saving
Offshore Wind	£105	£74.75	29%	£100	£57.50	43%
Dedicated Biomass with CHP	£115	£74.75	35%	£115	N/A	N/A
Advanced Conversion Technologies	£125	£74.75	40%	£115	£40.00	65%

The 43% saving on Offshore Wind 2022/23 was the headline political-economic result. It demolished the post-AR1 narrative that offshore-wind costs had "reached a floor" near £100/MWh and replaced it with a steep decline curve that would continue to AR3 (£39.65) and AR4 (£37.35). Together with the DE BSH April 2017 zero-subsidy outcome (Ørsted/EnBW at "-12.5"/"-10"/"-9.83"/"-6" EUR-cent/kWh "negative bids" interpreted as zero subsidy above wholesale), AR2's £57.50 became one of the two most-cited cost-decline proof points for the global offshore-wind industry.

13.2 Offshore wind clearing in context — the AR1 → AR7 arc

Round	Year	OSW Clearing (£/MWh, 2012 prices)	Delivery Years
AR1	2015	£114.39, £119.89 (two tranches)	2017/18, 2018/19
AR2	2017	£74.75 (2021/22), £57.50 (2022/23)	2021/22, 2022/23
AR3	2019	£39.650 (2023/24), £41.611 (2024/25)	2023/24, 2024/25
AR4	2022	£37.35	2026/27
AR5	2023	(Pot 3 non-clearing — no offshore wind awards)	—
AR6	2024	£58.87	2029/30
AR7	2025	£65.45 (rest of GB), £64.23 (Scotland)	2029/30-2030/31

AR2's 2022/23 clearing (£57.50) represented a ~52% fall from AR1's 2018/19 tranche (£119.89) in just two years. AR2 → AR3 added a further ~31% decline. AR1 → AR3 was thus a ~67% cumulative fall in four years — the entirety of which is directly traceable to AR2's step-change establishing that £100/MWh was not the floor.

13.3 Clearing in context of the Reference Price

Unlike AR3, where clearing dipped below Reference Price across all valuation years, AR2's clearing prices sat above the Reference Prices in every year:

Year	Reference Price	AR2 OSW Clearing	Clearing above RP
2021/22	£39.86	£74.75	£34.89 above (+88%)
2022/23	£42.60	£57.50	£14.90 above (+35%)
2023/24	£47.68	£57.50 (phased)	£9.82 above (+21%)
2024/25	£52.29	£57.50 (phased)	£5.21 above (+10%)

By 2024/25 (the final valuation year for AR2 phased projects), AR2's £57.50 clearing was only ~10% above the Reference Price — a narrow positive spread, effectively implying a positive-but-small contractual-subsidy expectation for phased-project later-phase generation. Operationally, the 2022-23 wholesale-market shock drove actual spot prices well above the £57.50 Strike Price, and AR2 OSW projects have been making Generator-to-LCCC payments (the "two-way" direction) through 2022-2025 on operational generation.

13.4 Post-hoc view — was £74.75 / £57.50 sustainable?

With hindsight from the 2023-25 commodity environment:

• Triton Knoll (£74.75, 860 MW): commissioned Summer 2022, on time to a 2022 commissioning target despite the COVID-era and post-Ukraine cost pressures. Generator-to-LCCC payments from commissioning onwards through 2024; the £74.75 Strike Price has held as a cap on merchant upside
• Hornsea 2 (£57.50, 1,386 MW): fully operational August 2022, also on time. Generator-to-LCCC payments have been material given the ~2022-23 wholesale price spikes — Hornsea 2 is one of the largest contributors to LCCC's Net CfD reserve
• Moray East (£57.50, 950 MW): fully operational April 2022 — actually the earliest of the three AR2 OSW winners to reach full operation. Similar merchant-to-LCCC dynamic

All three AR2 OSW projects commissioned on time, within Target Commissioning Window tolerance (some phases may have reached Target Commissioning Date formally later per the LCCC Register's Phase 2/3 staged CFD Unit structure, but the physical projects were operational by late 2022). AR2 is the only UK CfD OSW cohort with a 0% termination rate and 0% delay-past-Longstop rate as of 2026-04-20, which compares with: AR1 (Navitus Bay cancelled pre-CfD; several projects delayed; mostly operational); AR3 (1/6 terminated — Forthwind); AR4 (1 voluntary withdrawal — Vattenfall Norfolk Boreas — and ongoing delivery uncertainty for others); AR5 (no awards); AR6 / AR7 (too early).

The key contributor to AR2's delivery resilience is exactly that the projects cleared at the pre-cost-shock 2016-17 pricing base and reached Financial Investment Decision (FID) before the 2021-22 commodity spike. A 1.5-year gap between CfD award (September 2017) and FID (typically 2019 for all three winners) allowed sufficient time for EPC lock-ins before supply-chain cost escalation began. The AR3 and particularly AR4 cohorts did not have this buffer.

14. Contract obligations beyond core mechanics

14.1 Phased Offshore Wind CFD Units

AR2 is the first round where Phased Offshore Wind CFD Units appear as a formal Framework structure (earlier rounds did not need them because project phasing was not yet common at scale). Allocation Framework Rule 4(a) sets the structural limits: ≤1,500 MW total, first phase ≥25%, first phase TCD ≤ 31 March 2023, final phase TCD ≤ 2 years after first phase. Budget Notice §Phased Offshore Wind Projects confirms the Valuation-Year treatment for 2023/24 and 2024/25.

All three AR2 OSW winners used the 3-phase structure. The LCCC Register reflects this by splitting each project into 3 CFD Unit records with separate IDs, capacities, TCDs, Expected Start Dates, and Longstop Dates:

• Hornsea 2: AR2-HRN-106 (449.76 MW, TSD 2024-03-28), AR2-HRN-206 (454.56 MW, TSD 2024-03-28), AR2-HRN-306 (453.92 MW, TSD 2024-03-28) — total current 1,358.24 MW vs 1,386 MW awarded
• Moray East: AR2-MRY-107 (309.469 MW, TSD 2024-03-04), AR2-MRY-207 (309.363 MW, TSD 2024-03-04), AR2-MRY-307 (318.77 MW, TSD 2024-03-04) — total current 937.602 MW vs 950 MW awarded
• Triton Knoll: AR2-TKN-103 (216.6 MW, TSD 2021-05-17), AR2-TKN-203 (207.2 MW, TSD 2021-07-05), AR2-TKN-303 (423.7 MW, TSD 2023-04-01) — total current 847.5 MW vs 860 MW awarded

Total current 3,143.34 MW vs 3,196 MW awarded = 52.66 MW (1.65%) reduction. This reduction is the cumulative effect of Permitted Reductions applied at Final Installed Capacity confirmation — the standard mechanism by which the pre-construction capacity estimate is refined to the as-built figure, recognising small discrepancies from the planned number of turbines × turbine rating. It is not indicative of project distress. The use of the single-metering / apportioned agreement structure means each phase record shares a single Facility CfD but has its own capacity allocation, TCD, and payment stream.

14.2 Milestone Requirement (MR) — 12 months

Per Generic Agreement Clause 5.5, the Initial Milestone Delivery Date is 12 months after the Agreement Date — identical to AR3's 12-month clock (AR4 extended to 18 months). At AR2, this meant MR had to be delivered by ~late-2018 / early-2019 for projects that signed CfDs in late-2017 / early-2018. The MR can be satisfied by either:

• 10% of Total Project Pre-Commissioning Costs spent by MDD (including direct-shareholder equity contributions capped at amounts exceeding prior spend), OR
• Compliance with Project Commitments (Standard Terms v2 Condition 4.5) — specified materiel contracts, procurement orders, and financial commitments

The AR2 STC v2 retains the Offshore Transmission System (OTS) carve-out from the 10% spend calculation — same as AR3, reflecting the continuing UK Offshore Transmission Owner (OFTO) regime. OTS capex is excluded from the 10% spend test, keeping the test focused on the generating station proper.

14.3 Longstop Date and Force Majeure

Post-Start-Date termination rights under Condition 51.6 are distinct from Pre-Start-Date termination under Condition 51.1. If Operational CPs are not fulfilled by the Longstop Date, LCCC may terminate (Condition 51.1(E)) — but the Longstop Date can be extended day-for-day for Force Majeure events per the Longstop Date definition.

Condition 69 governs Force Majeure claims — notice requirements, mitigation efforts, and the FM Affected Party's obligation to resume performance as soon as reasonably practicable. AR2 projects have had modest FM claims for COVID-19 supply-chain disruption (2020-22). None has approached Longstop, because all three commissioned within TCW tolerance.

14.4 EU State Aid compliance

AR2 Standard Terms v2 retain extensive EU State Aid references, and — distinctively — strengthen the anti-cumulation provisions through the February 2017 Government Response amendments. Key clauses:

• State Aid Declaration Operational CP (Condition 3.6, 3.28-3.34): Generator must declare no unauthorised cumulation of prior State Aid
• No Cumulation of State Aid Warranty (Condition 32.4-32.15): Generator warrants that no State aid or Union Funding has been received, other than (i) the State aid arising under the CfD, (ii) aid or funding expressly authorised by a State Aid Competent Authority for cumulation, or (iii) aid notified through the State Aid Declaration Operational CP satisfaction process. This is the AR2 amendment — tightening relative to AR1.
• State Aid Interest (Condition 32.11): if prior State Aid is identified, it must be repaid with interest at the EU Reference Rate Methodology — day-to-day accrual, compounded annually
• Set-off of Previous State Aid (Condition 3.31): LCCC withholds all Generator payments until prior State Aid (plus interest) is fully set off
• Conditional Start Date for Biomass Conversion ≥250 MW (Generic Agreement Clause 6): if the Biomass Conversion generating station is ≥250 MW and the State Aid Condition Precedent has not been satisfied by the project's physical Start Date, payments accrue in a notional non-interest-bearing suspense account ("Pre-State Aid Accrual Account") and become payable only once the State Aid CP is satisfied. This clause reflects the BEIS-EC bilateral approval process for Biomass Conversion projects (distinct from the scheme approval SA.44475)

AR2 CfD contracts sit on the pre-Brexit EU-regulatory side. Post-Brexit (1 January 2021), most references to "State Aid Competent Authority" have been practically exercised by UK counterparties, but the contractual framework continues to reference EU bodies. Any post-Brexit legal change to these clauses would require consent of the Generator under the Standard Terms variation machinery — it is not automatic. Under the UK's Trade and Cooperation Agreement with the EU, the Subsidy Control Act 2022 replaced State Aid for new subsidies from the Act's commencement; existing AR2 contracts continue to reference EU bodies via retained EU law.

The AR4 redesign (post-Brexit) stripped these EU State Aid references. AR2's text is a snapshot of the pre-Brexit regime at its most mature (anti-cumulation fully tightened) but before the UK regulatory autonomy phase.

14.5 Change in Law — "Foreseeable CiL" clarified at AR2

The February 2017 Government Response added clarification to the Qualifying Change in Law (QCiL) machinery by refining the definition of "Foreseeable Change in Law". Under the AR2 STC v2, a Foreseeable CiL is one that — at the date of the Allocation Round — a reasonable developer would have anticipated; such a CiL does not trigger QCiL compensation. The tightening of this definition was a direct response to AR1-era disputes over whether certain industry-announced policy signals counted as "foreseeable". AR2 STC v2 makes this test stricter.

The QCiL machinery itself (Conditions 33-36) is identical in structure to AR3: three compensation methodologies (Capex Payment, Adjusted Revenues Payment, Operations Cessation Event Payment) with asymmetric pass-through (pre-Start Date: full recovery or termination; post-Start Date: Material threshold).

14.6 Co-located Storage on CfD sites

AR2 STC v2 is the first CfD contract to clarify co-located storage treatment on generating-station sites. The clarification (direct output of the February 2017 Government Response) distinguishes:

• CfD-site generating output — metered as Metered Output, subject to the Difference Amount calculation
• Storage import/export — segregated from Metered Output; not eligible for CfD Difference Amount on the stored-then-exported volume (to avoid double-subsidy on generation that is simply time-shifted via storage)

This machinery rarely mattered at AR2 projects (Triton Knoll, Hornsea 2, and Moray East do not have co-located storage at commissioning) but has proven increasingly relevant as post-2020 co-located battery deployments have become commercial. AR2 STC v2 is the contractual precedent.

15. Post-award fate — what has actually happened

15.1 Moray East — fully operational April 2022

Moray East (950 MW CfD; Ocean Winds / CTG JV) achieved first power in June 2021 and fully operational April 2022. 100 MHI Vestas V164-9.525 MW turbines in the Smith Bank area of the Moray Firth. Two offshore substation platforms, HVAC export. The earliest of AR2's three OSW winners to reach full operation, approximately 12 months before the 2022/23 Delivery Year target — thus commissioning ahead of the 1-year TCW lower bound. At commissioning, Moray East was the world's first offshore wind project using the 9.525 MW MHI Vestas rating.

LCCC Register status: all 3 CFD Units Live (Post-FIC) at 2026-04-20. Total current capacity 937.602 MW vs 950 MW awarded — 12.398 MW (1.3%) Permitted Reduction at Final Installed Capacity.

15.2 Triton Knoll — commissioned Summer 2022

Triton Knoll (860 MW CfD; RWE / J-Power / Kansai Electric JV as at commissioning, after Statkraft's 2018 exit) achieved first power in February 2021 and fully operational August 2022. 90 Vestas V164-9.5 MW turbines in the Greater Wash, approximately 32 km off the Lincolnshire coast. HVAC export. The project was built on time against its 2021/22 Delivery Year commitment.

LCCC Register status: all 3 CFD Units Live (Post-FIC) at 2026-04-20. Total current capacity 847.5 MW vs 860 MW awarded — 12.5 MW (1.45%) Permitted Reduction at Final Installed Capacity.

15.3 Hornsea 2 — fully operational August 2022

Hornsea 2 (1,386 MW CfD; Ørsted) achieved first power in December 2021 and fully operational August 2022. 165 Siemens SWT-8.0-167 DD direct-drive turbines in the Hornsea Zone, approximately 89 km off the Yorkshire coast. Two offshore substation platforms, HVAC export. At commissioning, the world's largest operational offshore wind farm — a title subsequently taken by Dogger Bank and ultimately Hornsea 3.

LCCC Register status: all 3 CFD Units Live (Post-FIC) at 2026-04-20. Total current capacity 1,358.24 MW vs 1,386 MW awarded — 27.76 MW (2.0%) Permitted Reduction at Final Installed Capacity. The slightly larger Permitted Reduction on Hornsea 2 reflects the 165 turbines × ~8.24 MW average as-built rating (with the uprated Siemens machines) versus the 1,386 MW nominal.

15.4 Cohort-level roll-up

Category	Count	Total MW	Status
OSW CFD Units Live (Post-FIC) — Triton Knoll P1-P3, Hornsea 2 P1-P3, Moray East P1-P3	9	3,143.34	All Live
OSW CFD Unit Terminated	0	0	—
OSW Total (current capacity)	9	3,143.34	0 terminated, 9 Live (Post-FIC)
OSW Awarded capacity	—	3,196.00	—
OSW Current vs Awarded attrition	—	52.66 MW (1.65%)	All via Permitted Reductions

AR2 is the only UK CfD offshore-wind cohort with zero terminations and zero phased-commissioning outstanding. This contrasts with:

• AR1: multiple delays/complications; Navitus Bay cancelled pre-CfD due to planning refusal; several projects (Neart na Gaoithe, Inch Cape) later AR3/AR4 winners
• AR3: 1 of 6 terminated (Forthwind, 12 MW, 4 April 2024); 5 active, all still Pre-Start Date despite Seagreen operational
• AR4: 1 voluntary withdrawal (Vattenfall Norfolk Boreas); Pot 3 mostly still pre-construction
• AR5: no OSW awards (Pot 3 non-clearing)

The ~1.65% Permitted Reduction attrition is standard FIC refinement; no AR2 project has invoked Force Majeure in a material way or triggered Longstop proceedings.

16. Retrospective — what AR2 means in the UK CfD arc

AR2 is the pivot point in a seven-round narrative arc that defines the UK CfD scheme to date. Its role is simultaneously retrospective and prospective:

AR1 (2015): offshore-wind entry pricing at £114-£120/MWh for 2017/18-2018/19 delivery. Two-pot structure (Established, Less Established). Offshore wind bid in Pot 2. Set expectations of gradual ~10-20% cost-decline per round.

AR2 (2017): first major OSW price fall — £74.75/MWh (2021/22) and £57.50/MWh (2022/23). The £57.50 figure was ~52% below AR1's £119.89. Single Pot 2 structure with 150 MW fuelled-tech cumulative maxima. The round that changed the narrative about offshore-wind cost competitiveness.

AR3 (2019): further substantial price fall — £39.65/£41.611 (2023/24 and 2024/25). 5.5 GW offshore wind awarded. First round where clearing fell below Reference Price across all valuation years. First round with Remote Island Wind as a distinct technology.

AR4 (2022): one more record low — £37.35/MWh (2026/27). 7 GW offshore wind awarded. Introduced Pot 3 (offshore wind as a separate pot from other less-established tech), 50%-of-supply-curve ASP targeting for offshore wind, post-award SCP monitoring via SIS, post-Brexit Subsidy Control language, strict-negative-price rule, and a +£10m mid-round Budget Revision.

AR5 (2023): Pot 3 non-clearing. Zero offshore-wind awards. The first round where the post-2022 cost shock overwhelmed pre-shock price expectations.

AR6 (2024): emergency recovery round. £58.87/MWh (Pot 3 OSW clearing) — essentially identical to AR2's 2022/23 £57.50. An eight-year round trip.

AR7 (2025): further ASP uplift, AR6-style pricing ~£65/MWh, 20-year-term reform.

AR2 is thus the competitive anchor against which the arc's subsequent compression (to AR4's £37.35) and subsequent recovery (to AR6/AR7's ~£60-65) must both be measured. The AR6 and AR7 clearing prices — in the £58-65 range — are not far from AR2's £57.50 in absolute terms. But AR6/AR7 are nearly a decade later and reflect materially different cost bases (larger turbines, fewer scale-economy gains still available, higher interest rates, post-Ukraine input-cost normalisation): the same nominal price point, different underlying economics.

The parallel DE story. On 13 April 2017 (barely a month after AR2's application window opened), Germany's BSH offshore-wind tender awarded four projects totalling 1.49 GW at a volume-weighted-average "negative-subsidy" bid of 0.44 ct/kWh — interpreted as effectively zero subsidy above the wholesale market. Ørsted's OWP West, Borkum Riffgrund West 2 and Gode Wind 3, plus EnBW's He Dreiht, were all bid at zero or below (Gode Wind 3 at "-12.5" ct/kWh was interpreted as ~-1.25 €/MWh — i.e. a small positive wholesale-market contribution from the developer). The DE auction's design (no State Aid, direct market exposure, TSO-built grid connection) was structurally different from UK CfD, but the cost-decline signal was the same: April 2017 was the month the offshore-wind industry publicly declared its cost competitiveness with conventional generation. AR2's September 2017 results confirmed this signal on the UK side. Together, these two 2017 events are the single most-cited turning point in global offshore-wind economics.

Pre-Brexit vs post-Brexit regime transition. AR2 is the most "classic" pre-Brexit round — signed under full EU State Aid (SA.44475, 26 July 2017), referencing European Commission as State Aid Competent Authority, with strengthened anti-cumulation provisions in STC Version 2. AR3 inherited this regime (plus the SA.49318 amendment for RIW) and is also pre-Brexit. AR4 stripped the State Aid references under the UK's post-2020 Subsidy Control regime. The 21 contracts signed across AR2 + AR3 — still live in 2026 — are therefore the main operational legacy of the EU State Aid regime in UK offshore wind. Any future litigation or contract variation on these contracts will need to navigate the complex interaction between the retained EU law framework, the UK Subsidy Control Act 2022, and the Trade and Cooperation Agreement's Level Playing Field provisions. This is a schema-relevant test point for AR2's data model (Axis 6 / Axis 7).

Delivery resilience. The post-2022 cost shock did not significantly damage AR2's delivery trajectory — all three projects commissioned before or within TCW. This is the counterfactual benchmark against which AR3 (delayed delivery, one termination), AR4 (Norfolk Boreas withdrawal, ongoing delivery uncertainty) and AR5 (non-clearing) should be read. AR2's Strike Prices locked in 2016-17 EPC expectations with ~1.5-2 years of pre-commodity-shock FID time. AR3 OSW contracts locked in 2018-19 expectations with ~3-4 years of pre-shock time — but at lower Strike Prices. AR4 locked in 2021-22 expectations with very little pre-shock time at even lower Strike Prices — creating the fragility that ultimately manifested as Norfolk Boreas's withdrawal.