Contracts for Difference Allocation Round 5

UK CfD Allocation Round 5 (AR5, 2023)

1. At a glance

Source documents (11 primary sources, all mirrored to B2): core-parameters, budget-notice, budget-revision-notice, allocation-framework, standard-terms-and-conditions (541 pp, 168K words — the master contract text), generic-agreement, application-guidance (EMR Delivery Body), sealed-bid-guidance, supply-chain-plan-guidance, administrative-strike-prices (methodology), results.

2. Market context at time of auction

AR5 ran at the point where the UK offshore-wind story flipped from triumphant to fragile. It was the first of the new annual CfD rounds promised by the British Energy Security Strategy (7 April 2022) — a cadence change from the previous biennial pattern, designed to accelerate deployment toward the 50 GW by 2030 target. It was also the first auction designed entirely after the inflationary shock of 2021–22, yet its parameters were set using cost evidence assembled before that shock fully registered on developers' balance sheets.

The 50 GW by 2030 target, and the cadence shift. The British Energy Security Strategy raised the UK's offshore wind ambition from 40 GW to up to 50 GW by 2030, including 5 GW of floating offshore wind. Achieving that target from a 2022 base of ~11 GW operational required multi-gigawatt CfD awards every year. AR5 was positioned as the first in that new annual series and as a signal of policy momentum.

The AR4 reference point. AR4 had concluded in July 2022 with a spectacular result: 6.99 GW of offshore wind cleared in Pot 3 at £37.35/MWh (2012 prices) — the lowest price ever awarded for offshore wind in the UK, anywhere in the world. Flagships Hornsea 3, Norfolk Boreas, East Anglia 3, Moray West, and Inch Cape all won at this price. Across the industry, £37.35 was celebrated at auction day but privately regarded by developers as tight even on 2021 cost assumptions. By mid-2023, every AR4 winner was rethinking viability; in July 2023 — six weeks before AR5 results — Vattenfall announced it would not progress Norfolk Boreas at the AR4 price, writing off ~£415m. The AR4-price collapse was not a forecast; it was already visible.

Cost inflation and the supply chain. Between the ASP methodology cut-off (used for AR5 Core Parameters, finalised autumn 2022) and the AR5 application window (March–April 2023), offshore wind developers confronted: double-digit percentage cost increases in monopiles and cables, order-book congestion at Tier-1 WTG manufacturers (Siemens Gamesa, Vestas, GE) driving delivery dates out to 2026–28 with price escalators, sustained central bank rate hikes raising project WACC from the ~4–5% assumed by BEIS to >7–8% in developer term sheets, and insurance premium spikes for construction-phase marine operations. Industry submissions to DESNZ in early 2023 (Energy UK, RenewableUK) warned explicitly that £44/MWh in 2012 prices did not cover the post-escalation cost base. DESNZ did not move the ASP.

Methodology versus market. The Administrative Strike Prices Methodology document set AR5 offshore wind ASP at £44/MWh using an LCOE-style supply-curve approach targeting 50% of the estimated pipeline (raised from 25% in AR4) — a target deliberately calibrated to encourage participation. The methodology was internally consistent; what it missed was that its supply-curve inputs (a BEIS internal cost database plus public domain pipeline-project data, validated with costs from REPD and Catapult/OREC advice) trailed the market by ~18 months. By the time the ASP was communicated, half the pipeline data was stale. This is the gap that defined AR5.

Political moment. AR5 was framed and delivered under a Conservative government (Energy Security Minister Graham Stuart), five months before a General Election cycle began to loom. The zero-bid offshore wind outcome on 8 September 2023 became an immediate political liability: the industry's coordinated response — Energy UK, RenewableUK, SSE, Ørsted, ScottishPower Renewables, Vattenfall — framed it as preventable planning error. DESNZ announced the structural AR6 reforms (Pot 3 reintroduction, ASP uplifts, Permitted Reduction) within weeks.

3. Regulatory frame (brief)

The AR5 auction sits inside a well-established statutory regime; full treatment is in regulatory-sketches/uk.md. Key actors for this round:

Statutory instruments:

• Energy Act 2013 (scheme foundation; empowers CfD Counterparty)
• Contracts for Difference (Allocation) Regulations 2014, as amended (round mechanics, budget notices, allocation process)
• Contracts for Difference (Standard Terms) Regulations 2014, as amended (incorporates the Standard T&Cs into each CfD Agreement)
• Electricity Act 1989 (Section 36 consents in Scotland; OFTO regime)
• Planning Act 2008 (NSIP/DCO in England/Wales)

4. Pre-round preparation and timeline

4.1 Full chronology

Elapsed time summary:

• Core Parameters → Round opens: ~3.5 months (industry preparation window)
• Round opens → Application closes: 3 weeks 4 days
• Application closes → Budget Revision: ~14 weeks
• Budget Revision → Sealed bid opens: 6 days
• Sealed bid open → close: 5 working days
• Sealed bid close → Results: ~3.5 weeks
• Total from round open to results: 5 months 1 week
• Total from Core Parameters to results: ~8.5 months

4.2 The budget revision that did not touch offshore wind

The Budget Revision Notice of 3 August 2023 is the single most revealing document in the AR5 corpus for the zero-bid outcome. Two months after applications closed, NG ESO had a complete valuation of the qualifying pipeline. DESNZ knew — from the valuation — that Pot 1 was oversubscribed on solar and onshore wind (explaining the £20m Pot 1 uplift to £190m) and that Pot 2 had strong tidal/geothermal interest (explaining the £2m Pot 2 uplift to £37m). What the valuation also showed — unmistakeably — was that offshore wind applications, if any existed in the pipeline, were either absent or uneconomic at £44/MWh.

DESNZ's response was to not revise the offshore wind ASP, not introduce a Pot 3, and not introduce offshore-wind maxima within Pot 1. The Budget Revision Notice's Schedule 1 explicitly lists only Pot 1 and Pot 2 uplifts. Under Regulation 12(5), DESNZ could have increased the overall budget and uplifted any existing maximum; they could not have introduced a new maximum retroactively, because Regulation 12 permits budget revision but constrains the legal form of that revision. A structural change (introducing a new pot, uplifting the ASP) would have required a fresh Budget Notice and therefore a new allocation round.

This legal constraint — not policy preference — is a material part of why the zero-bid outcome was not averted mid-round. Once the £44/MWh ASP was locked in the March 16 Budget Notice and applications had closed on April 24, there was no legal mechanism for DESNZ to rescue offshore wind participation within AR5. The earliest corrective action was in Core Parameters for AR6, published 16 November 2023.

5. The prize — CfD contract mechanics

A winning AR5 bid delivers a 15-year revenue-stabilised subsidy contract with LCCC. The core mechanics are unchanged from AR4, with a small number of AR5-specific drafting tweaks. The definitive text is in standard-terms-and-conditions (541 pp) and generic-agreement (30 pp).

5.1 The two-sided CfD

Each Settlement Unit (half-hour), LCCC calculates a Difference Amount per unit of metered output:

Difference Amount = (Strike Price – Reference Price) × Metered Output

• If positive (Reference < Strike), LCCC pays the Generator the top-up.
• If negative (Reference > Strike), the Generator pays LCCC the claw-back.

Over a Billing Period, the half-hourly amounts aggregate to a Net Payable Amount. If negative, Generator pays by direct transfer within 10 Business Days. This is a true two-sided CfD — the Generator bears no wholesale price upside beyond the strike price.

5.2 Strike Price

The Strike Price is the nominal 2012-price value awarded at auction (£47/MWh solar, £52.29/MWh onshore & RIW, £198/MWh tidal, £119/MWh geothermal for AR5). It is CPI-indexed annually on the Indexation Anniversary using a ratio of (January CPI in current year) to (Base Year CPI = October CPI in the year preceding the Base Year). The T&Cs contain a re-basing formula that accommodates ONS CPI index re-bases without breaking the chain.

Additional Strike Price adjustments exist for: Qualifying Change in Law (QCiL), Generation Tax, Transmission Loss Multiplier (TLM(D)) revisions, and Sustainability Criteria-in-Law (SCiL) events — each with its own formula.

5.3 Reference Price

For intermittent technologies (solar PV, onshore and remote island wind, tidal stream), the Reference Price is the Intermittent Market Reference Price (IMRP) — a time-weighted day-ahead index published per Settlement Unit. It is computed from the Initial IMRP Indices specified in Annex 5 of the T&Cs, with substitution rules if an index source is replaced. Baseload technologies (geothermal in AR5, if configured non-intermittent) use the BMRP (Baseload Market Reference Price), a seasonal index computed from forward-season contract prices per Annex 4.

5.4 Negative pricing rule

For every Settlement Unit where the IMRP is negative (i.e. less than £0/MWh), the Intermittent Difference Amount is zero — LCCC pays nothing, and the Generator receives only whatever market revenue (possibly negative) it is generating. The AR5 T&Cs preserve the AR4-onwards per-Settlement-Unit rule — no 6-hour threshold. A single negative half-hour results in zero CfD top-up for that half-hour.

5.5 Contract term — 15 years

Per Generic Agreement, the "Specified Expiry Date" is the 15th anniversary of the earlier of the Start Date and the last day of the Target Commissioning Window. The clock starts at whichever comes earlier. If a project commissions early the 15-year clock starts at the Start Date; if a project delays past the TCW end the clock starts anyway at the TCW end — the Generator forfeits subsidy for the period of delay. AR5 retained 15 years; the extension to 20 years arrived for AR7 onwards.

5.6 Target Commissioning Window and Conditions Precedent

• Initial Milestone Delivery Date: 18 months after the Agreement Date. Project must evidence sufficient progress.
• Target Commissioning Window (TCW): sized per technology — up to 1 year for offshore wind and floating offshore wind; shorter windows apply to other technologies (e.g. 3 months for Solar PV, 6 months for Landfill Gas).
• TCD in Delivery Years: AR5 tightened the rule — Schedule 1 of the allocation-framework clarifies that "(with the exception of later phases of Phased Offshore Wind CfD units) the Target Commissioning Date must fall within the Delivery Years". This was a tightening over AR4's drafting.
• Initial Conditions Precedent: must be fulfilled within 20 Business Days of Agreement Date.
• Operational Conditions Precedent: must be fulfilled before the Longstop Date — the last day of the Longstop Period following the final day of the TCW.
• Milestone Delivery Date and Longstop Date can be extended day-for-day for listed delay causes (judicial review of planning consents within statutory windows; MOD Radar Mitigation Scheme non-confirmation for offshore wind, onshore wind, and remote island wind).

5.7 Contract variants used in AR5

DESNZ published six Phase Agreement variants plus a Private Network variant and an Unincorporated Joint Venture (UJV) variant alongside the Generic Agreement:

• Generic (standard) Agreement — 30pp
• Phase 1 (Single Metering) — 36pp
• Phase 2 (Single Metering) — 29pp
• Phase 3 (Single Metering) — 29pp
• Phase 1 (Apportioned Metering) — 43pp
• Phase 2 (Apportioned Metering) — 35pp
• Phase 3 (Apportioned Metering) — 36pp
• Private Network Agreement — 113pp
• Unincorporated Joint Venture Agreement — 49pp

The Phase variants are the legal hooks for Phased Offshore Wind CfD Units — offshore wind projects that commission in distinct phases, each with its own Target Commissioning Date, jointly metered or apportioned across phases. None of these variants were activated in AR5 because no offshore wind contracts were awarded. They became operationally relevant only from AR6 onwards (Hornsea 3 Phase 1/2/3, Dogger Bank D, etc.).

6. Budget architecture

6.1 The initial Budget Notice — 16 March 2023

The Pot 3 omission is the structural anomaly of AR5. AR4 had introduced a dedicated Pot 3 for offshore wind (£200m/year in AR4 budget terms, to handle the expected 5+ GW flow). Reverting to a Pot 1/Pot 2 structure for AR5 — with offshore wind competing against solar at £47/MWh — was a deliberate design choice. The stated rationale in DESNZ briefings was that "with ASPs now providing price discrimination between technologies, separate pots are less necessary" — but by removing the ringfence, the design made the Pot 1 offshore wind allocation contingent on offshore wind bids being economically compatible with the Pot 1 clearing dynamics.

6.2 The Budget Revision Notice — 3 August 2023

The Pot 1 uplift was driven by strong solar and onshore wind valuations; the Pot 2 uplift accommodated the tidal and geothermal valuations. The absence of an offshore wind uplift — the most conspicuous gap in the revision — reflects the legal constraints of Regulation 12 (a budget revision cannot introduce a new pot or structural change) combined with no evidence the offshore wind pipeline would respond even to a larger Pot 1.

6.3 Inflator and price base

The AR5 Budget Notice specifies two inflators:

• £2011/12 → £2012: 1.0193 (fixed; applied by NG ESO before valuing bids submitted in 2012 prices)
• £2011/12 → current (Jan 2023): 1.3415 (illustrative; for stakeholder conversion)

Budgets are rounded to the nearest pence at the 2012-price conversion step.

7. Administrative Strike Prices

7.1 AR5 ASPs (2012 prices)

7.2 The methodology — how £44 was chosen

The ASP Methodology document sets out a five-step approach:

1. Gather data to estimate lifetime cash-flows for each project in the pipeline
2. Sum NPV of total expected costs and revenues in each year
3. Set strike price to make NPV equal to zero for the marginal project
4. Repeat for all pipeline projects to build the supply curve
5. Identify the target percentage of pipeline capacity to cover and set ASP at the corresponding point

For AR5, the target percentages were:

• 50% of the supply curve for: Offshore Wind, Floating Offshore Wind, Onshore Wind, Solar PV
• 25% of the supply curve for all other technologies

The 50% target for offshore wind (up from 25% in AR4 for onshore and solar) was itself a liberalisation designed to set more generous prices — the idea being that covering half the pipeline would ensure participation even if cost assumptions were imperfect. Offshore wind had already been at 50% in AR4.

For offshore wind specifically: "We have constructed supply curves consisting of specific known projects in the pipeline, informed by information included in planning consents. Project-specific costs have been estimated where possible…" The input cost database came from BEIS's Generation Cost update plus project-specific pipeline data; TNUoS charges were forecast per-site using National Grid's charging assumptions.

7.3 Why the methodology delivered £44 and why £44 failed

The methodology is internally coherent; its failure was in input data currency.

1. Hurdle rate assumption. BEIS's central hurdle rate for offshore wind was assumed at a level calibrated before the late-2022 rate hikes. Developer WACC in early 2023 was ~7–8% (post-SOFR spread, post-insurance spike); the ASP methodology used a lower rate.
2. Supply curve vintage. "Publicly available information relevant to potential applicants" in offshore wind means project-specific cost data from planning applications, capacity register entries, developer briefings — all compiled through 2022. Q4 2022 steel and WTG price escalation was not incorporated.
3. 50% target framing. The 50% target assumes that the lower half of the supply curve represents genuinely economic projects. If the entire supply curve had shifted up by 15–20% between methodology cut-off and auction date, the "50% point" was by auction date in fact the "20% point" of actual economics — nowhere near the mid-point of viable projects.
4. No in-round uplift mechanism. Once the Budget Notice was issued, the ASP was effectively locked (Regulation 12 does not permit ASP revision without a new Budget Notice, which would have required restarting the round).

Industry attempts to flag these gaps — most visibly in Energy UK's May 2023 response and via direct submissions from SSE, Ørsted, Vattenfall, and ScottishPower Renewables — did not shift the ASP. DESNZ's position at the time was that 50% of the pipeline was a generous target and competitive bids should still clear.

7.4 Treatment of "zero" and "held-constant" strike prices across delivery years

AR5 held the offshore wind ASP at £44/MWh constant across 2025/26, 2026/27, and 2027/28 delivery years. This is an AR4-pattern inheritance: AR4 also used held-constant offshore wind ASPs across its delivery years.

Held-constant ASPs are not the same as time-invariant economics. Held-constant means: a project choosing a 2027/28 delivery year faces the same ASP as a project choosing 2025/26. But longer-deferred commissioning typically allows access to newer (cheaper) WTG platforms. For AR5 offshore wind, the economic gap between "bid at £44 with 2025/26 Delivery Year" and "bid at £44 with 2027/28 Delivery Year" was substantial — yet the ASP offered no reward for the riskier early delivery. This contributed to the marginal-economics trap.

8. Qualification criteria

8.1 Universal gates

All AR5 applicants must satisfy:

1. Eligibility — technology on the AR5 eligible list; capacity above de minimis; no state aid disqualifications
2. Planning consents — evidence of consents sufficient to start construction, before the application deadline (Section 36 consent in Scotland; DCO in England/Wales for NSIPs; TCPA consent for smaller projects)
3. Grid connection — evidenced grid connection agreement with the relevant System Operator
4. Supply Chain Plan (SCP) — for all projects ≥300 MW and for all Floating Offshore Wind regardless of size, a DESNZ-assessed Supply Chain Plan must be in place
5. Application bonds and evidence — the full set of evidence requirements specified in application-guidance and the allocation framework

8.2 The Supply Chain Plan gate

The AR5 SCP regime is a DESNZ-run assessment of how a project will deliver supply-chain benefits (UK jobs, economic activity, SME integration). The SCP is a condition precedent to qualification — a project without a valid SCP cannot enter the sealed bid window. For offshore wind specifically, the SCP threshold is 300 MW; for floating offshore wind it is all projects.

The 2023 iteration of the SCP regime included new diligence on supply-chain risks (lead times, Tier-1 concentration) and commitments to UK content. The paperwork and assessment lead time was typically 3–6 months; projects needing SCPs had to start the process well before the AR5 application window opened.

8.3 Technology-specific gates

• Offshore Wind: seabed rights from Crown Estate (E/W) or Crown Estate Scotland must be in place. Eligible seabed sources for AR5 were Crown Estate Rounds 1/2/3/4 (R4 awards finalised Jan 2023 — very tight for AR5 inclusion) plus ScotWind (awards finalised Jan 2022).
• Floating Offshore Wind: SCP + seabed rights + nearshore evidence. Note: the INTOG leasing round (Scotland, floating offshore wind + O&G electrification) awarded preferred bidder sites in March 2023, potentially too late for AR5.
• Onshore Wind / Remote Island Wind: planning consent in place; specific grid arrangements for RIW.
• Tidal Stream: seabed lease (Crown Estate or Crown Estate Scotland); grid connection. Most AR5 tidal winners are at EMEC (Orkney) or Morlais (Anglesey) — established tidal test/demonstration zones.
• Geothermal: drilling/lease rights; grid connection.

9. Evaluation criteria, process, and scoring

9.1 Pay-as-clear sealed-bid auction

AR5 is a pay-as-clear sealed-bid auction under Regulation 31. Each qualified applicant submits a sealed bid specifying:

• Strike Price (£/MWh, 2012 prices, must be ≤ technology ASP)
• Capacity (MW) they are offering
• Delivery Year preference
• Phased Offshore Wind configuration if applicable

Bids are ranked lowest Strike Price first within each pot and sub-technology basket. The auction clears when the next-lowest bid would push the total cumulative budget (in the valuation terms set by the allocation framework) above the pot's available budget in any Delivery/Valuation Year.

Successful applicants all receive the same clearing strike price — the strike price of the marginal (last-admitted) bidder. Projects that bid lower than the clearing price are not rewarded for bidding more aggressively; they simply cleared with the rest of the pack.

9.2 Valuation formula

Each bid's budgetary impact is computed as:

Budget Impact (in Delivery Year n, in 2012 prices) = (Bid Strike Price − Reference Price Forecast for DY n) × Expected Annual Generation (in DY n and all subsequent years up to the 15-year term)

The Reference Price Forecast is an administered central BEIS view on the IMRP over the CfD lifetime. Expected Annual Generation is derived from applicant-supplied load factors and capacity.

The valuation formula captures the asymmetric nature of the CfD: if the project's expected strike price is above the Reference Price Forecast, the bid has a positive budgetary impact equal to the expected top-up flow; if below, the bid has a negative budgetary impact (the Generator is expected to pay LCCC on net over the term). The AR5 results include negative budget impacts for Solar PV 2025/26 — the -£183,042.19 figure under notional monetary Budget impact in the results doc.

9.3 Constraints

1. Overall budget per Delivery/Valuation Year must not be exceeded in aggregate across all pots
2. Pot budget per Delivery Year must not be exceeded per pot
3. Pot 2 Tidal Stream minimum of £10m must be satisfied
4. Administrative Strike Price ceiling per technology

No maxima applied in AR5 — meaning, e.g., solar could have taken the entire Pot 1 budget if cheap enough.

9.4 Flexible bids

Applicants may submit flexible bids — effectively multiple bid combinations (price-capacity) from which NG ESO selects the combination that maximises the allocation value consistent with constraints. Flexible bids are the primary mechanism by which applicants hedge between Delivery Years or between partial-capacity scenarios.

9.5 The SoS review

After NG ESO runs the auction and the Independent Auditor signs off, the results are presented to the Secretary of State for a two-day statutory review window. The SoS has limited grounds to intervene — essentially only in the case of auditor-identified procedural errors. In AR5 no interventions occurred.

10. Competitive landscape — what bid, what cleared

10.1 Application-level data

The results document provides the total value of all applications originally received, valued at ASP — a proxy for the scale of the applicant pool:

(All values 2012 prices.)

The £630m 2029/30 Pot 1 ASP-valued application load against a £190m revised Pot 1 budget confirms a ~3.3× oversubscription in Pot 1 (valued at ASP) — and the valuation formulae favour more-competitive bidders, so the clearing price fell materially below the ASP in onshore wind (£52.29 vs £53 ASP) and did not fall at all in solar (£47 vs £47 ASP). This is competition at the ASP ceiling.

10.2 What the applicant pool looked like

A single Excel list of successful applicants is published as a companion to the results PDF. No equivalent list of unsuccessful applicants is published — DESNZ treats unsuccessful bids as confidential.

Publicly-visible AR5 applicants included:

• Solar PV: dozens of independent SPVs (Low Carbon, NextPower, Sonnedix, OPDEnergy, Greentech, etc.) plus the Vattenfall solar JV. Pipeline was strong; only 56 SPVs cleared from a much larger applicant pool. Clearing at the £47 ASP suggests pay-as-clear was binding.
• Onshore Wind: SSE (Strathy South, Bhlaraidh Extension), RWE Renewables (Enoch Hill, Strathy Wood), Force 9 / Clash Gour Holdings (Clash Gour), smaller independents. 14 projects cleared at £52.29.
• Remote Island Wind: one project (see §11.3) at £52.29.
• Tidal Stream: MeyGen (4 phases: AR51-AR54), Morlais hosts (Verdant, Magallanes, Mor Energy, Hydrowing), Orbital Marine (Eday 3 and 4), EMEC Magallanes. All cleared at £198.
• Geothermal: Geothermal Engineering Ltd (Manhay, Penhallow), United Downs Geothermal. All cleared at £119.
• Offshore Wind: publicly reported eligible capacity was up to 5 GW, including potential candidates like Outer Dowsing, parts of Celtic Sea Round 5 (not eligible in AR5 timing), East Anglia 2, and others. Zero applications submitted.
• Floating Offshore Wind: potential ScotWind floating sites and INTOG floating; INTOG timing was likely too late for AR5. Zero applications submitted.

10.3 The developer rationale for not bidding

The industry explanation — reported in contemporary press and in the post-auction Energy UK response — was uniform: at £44/MWh (2012 prices) ≈ £59/MWh in January 2023 prices ≈ £61/MWh in 2023/24 settlement prices, a 15-year CfD could not fund new offshore wind construction at 2023 cost levels. Several developers had specifically requested an administrative uplift via Budget Revision; DESNZ declined.

The effect was coordinated, though not formally collusive: with no offshore-wind bids, no project had to explain to its board why it had accepted uneconomic pricing, and no project had to worry about being outbid by a more desperate competitor. This equilibrium — where participation becomes worse than abstention for every player — is the economic signature of a mispriced auction.

11. Results — Pot 1

11.1 Solar PV (>5MW)

• Projects cleared: 56
• Total capacity: 1,927.68 MW
• Clearing strike price: £47.00/MWh (2012 prices) — identical to the ASP
• % saving on ASP: 0%
• Delivery Years: 393.96 MW (2025/26) + 150.74 MW (2026/27) + 1,382.98 MW (2027/28)

Solar PV cleared at the ASP ceiling, signalling that the pot was budget-constrained even at the maximum admissible price. In a pay-as-clear auction, a 0% saving means the clearing bid exactly matched the ASP — the marginal-admitted bid bid at £47 precisely. This is the classic sign of binding ASP.

Top 10 solar winners by capacity (from results Part A):

(The results PDF enumerates all 56 rows; the Excel companion is the machine-readable source. The writeup cites the full list by reference rather than reproducing 56 rows inline.)

11.2 Onshore Wind (>5MW)

• Projects cleared: 14
• Total capacity: 1,480.74 MW
• Clearing strike price: £52.29/MWh (2012 prices)
• ASP: £53/MWh
• % saving on ASP: 1.34% (£0.71/MWh)
• Delivery Years: 31.10 MW (2025/26) + 204.40 MW (2026/27) + 1,245.24 MW (2027/28)

The 1.34% saving is a thin margin — the marginal onshore bid bid at £52.29. With more aggressive bidding, onshore could have cleared lower; it did not, suggesting either (a) enough applicants bid near the ASP to set the clearing price near the ceiling, or (b) bid valuation constraints selected a marginal £52.29 project that was not displaced by a cheaper competitor.

Top onshore winners by capacity:

• Strathy South Wind Farm — SSE Generation Limited — 231.00 MW
• Clash Gour Wind Farm — Clash Gour Windfarm Holdings Limited — 168.75 MW
• Limekiln Wind Farm — Limekiln Extension Limited — 106.00 MW
• Bhlaraidh Extension Wind Farm — SSE Generation Limited — 100.80 MW
• Enoch Hill Windfarm — RWE Renewables UK Onshore Wind Limited — 69.00 MW
• Blarghour Wind Farm — Blarghour Wind Farm Limited — 67.20 MW
• Greenburn Wind Park — REG Greenburn Limited — 63.00 MW
• Strathy Wood Windfarm — RWE Renewables UK Onshore Wind Limited — 62.70 MW
• Fell Wind Farm — Energyfarm UK Fell LLP — 50.00 MW

11.3 Remote Island Wind (>5MW)

• Projects cleared: 1
• Total capacity: 223.60 MW
• Clearing strike price: £52.29/MWh (2012 prices) — same as onshore
• ASP: £53/MWh
• % saving on ASP: 1.34%
• Delivery Year: 2027/28

One RIW project cleared. Historically RIW sits at a price similar to onshore wind because the ASP/methodology treat them interchangeably. In AR5 the RIW clearing price was identical to onshore at £52.29.

11.4 Offshore Wind

• Projects cleared: 0
• Total capacity: 0 MW
• Clearing strike price: n/a (no bids)

The Pot 1 Offshore Wind sub-technology returned no successful applicants and no clearing price. This is the signature event of AR5.

12. Results — Pot 2

12.1 Tidal Stream

• Projects cleared: 11 — a record
• Total capacity: 53.04 MW
• Clearing strike price: £198/MWh (2012 prices)
• ASP: £202/MWh
• % saving on ASP: 1.98%
• Delivery Years: 4.50 MW (2026/27) + 48.54 MW (2027/28)

The £10m Pot 2 tidal stream minimum, combined with the Pot 2 £37m revised budget, allowed tidal stream to expand to its widest-ever allocation. Tidal concentration in three locations:

The MeyGen project — previously cleared a Pot 2 CfD in AR4 — expanded by ~20 MW across four AR5 phases. Morlais hosted five independent developer projects on a single seabed lease, each a sub-array.

12.2 Geothermal (first ever CfDs)

• Projects cleared: 3 — first ever geothermal CfDs in scheme history
• Total capacity: 12.00 MW
• Clearing strike price: £119/MWh (2012 prices) — identical to ASP
• % saving on ASP: 0%
• Delivery Years: 7.00 MW (2026/27) + 5.00 MW (2027/28)

Winners:

• Manhay Geothermal Power Plant — Geothermal Engineering Limited — 5.00 MW — 2026/27
• Penhallow Geothermal Power Plant — Geothermal Engineering Limited — 5.00 MW — 2027/28
• United Downs Geothermal Power Plant — United Downs Geothermal Limited — 2.00 MW — 2026/27

All three are Cornish projects leveraging the hot-granite geothermal resource in the Carnmenellis and Redruth areas. United Downs was already operating as an R&D demonstrator; Manhay and Penhallow were new build projects.

12.3 Floating Offshore Wind

• Projects cleared: 0
• Total capacity: 0 MW
• Clearing strike price: n/a

At £116/MWh (2012 prices) the floating offshore wind ASP was held constant from AR4. Floating faced the same supply-chain pressures as fixed offshore plus the incremental cost base of a less mature technology. No floating project bid. This was the first year floating had been eligible in a pot where non-floating bidders could have absorbed the budget — floating's absence was structurally similar to fixed's absence.

12.4 Other Pot 2 technologies

• ACT, Anaerobic Digestion, Dedicated Biomass, Wave: zero awards across AR5 — no applications or no awards.

13. Offshore Wind — the non-event

13.1 Evidence of absence

The results document enumerates every successful applicant across all 95 awards. No offshore wind project appears anywhere in the document — not in Part A (project-by-project), not in Table E (outcome by technology), not in Table F (% saving by technology). Table F explicitly lists only Solar PV, Onshore Wind, Remote Island Wind, Tidal Stream, and Geothermal as cleared technologies.

Further, the Monetary Budget Impact tables (Part B, C, D) have no Pot 3 row — because AR5 had no Pot 3 — but also have no Pot 1 Offshore Wind row within the Pot 1 breakdown. The Budget Impact tables aggregate at the pot level, but the results Table E (outcome by technology) covers only those technologies that awarded at least one contract. Offshore Wind's absence from Table E is authoritative.

13.2 Pre-auction signals

Industry warnings about AR5 offshore wind pricing were explicit from early 2023:

• Energy UK's AR5 response (May 2023) — specifically called for uplifts to offshore wind ASPs prior to round-open, flagging supply-chain and financing cost pressures.
• Direct developer submissions — SSE, Ørsted, Vattenfall, ScottishPower Renewables, EDF Renewables all made written representations to DESNZ (partially visible via Freedom of Information responses), arguing for a structural reset of offshore wind parameters.
• Vattenfall's 20 July 2023 announcement — Vattenfall formally paused Norfolk Boreas (AR4-winning 1.4 GW project at £37.35/MWh), writing down ~£415m. This was nine working days before the AR5 sealed bid window opened. It was the most publicly visible signal that £37.35/MWh was no longer a viable offshore wind price — implying £44/MWh also was not.

13.3 Post-auction framing

DESNZ's public response on 8 September 2023 framed the zero-bid outcome as a reflection of global trends (similar pricing tensions in Germany, Spain) and supply-chain pressure, while still asserting the 50 GW by 2030 target. The industry reaction was sharp: Energy UK's subsequent statement called AR5 "deeply disappointing", and the offshore wind trade press headlines (e.g. offshorewind.biz 8 Sep 2023: "Offshore Wind Developers Take a Pass on UK's Fifth CfD Round as Maximum Bid Price Was Too Low") foregrounded the £44/MWh cap as the cause.

13.4 Consequences for the 50 GW pathway

The zero-bid outcome represented up to 5 GW of eligible offshore wind capacity that was not contracted in AR5 — capacity that the 50 GW by 2030 pathway had been counting on. The 18-month gap between AR5 failure and AR6 commissioning-deliveries (i.e. the delay to the deployment trajectory) is itself a structural cost, though the worst-case commercial outcome was averted by the fact that AR5 applicants became the first wave of AR6 applicants at higher prices.

14. Clearing prices — analysis

14.1 Clearing price vs ASP (all cleared technologies)

14.2 What the 0% clearing tells us

Solar and geothermal both cleared at exactly their ASP. This is the classic signature of ASP-binding competition: enough qualifying applicants bid at or near the ASP that the pay-as-clear mechanism did not drive the price below the ceiling. Interpretation:

• For solar: the pot was genuinely oversubscribed (see the £629m valuation load vs £190m budget in 2029/30). The pay-as-clear rule rewards the marginal bidder; if the marginal bidder was at £47, the clearing price is £47. Solar developers priced at the ASP ceiling because anyone pricing higher would not qualify, and anyone pricing lower without need was leaving money on the table.
• For geothermal: only 3 projects cleared. These were pre-existing committed projects with high technology risk premia, clearing at a price pegged to ASP because the marginal bidder was the third project.
• Tidal at 1.98% saving: the £10m Pot 2 minimum effectively guaranteed space for 11 projects. The clearing price £198 vs ASP £202 suggests at least one tidal bidder bid sub-ASP.
• Onshore/RIW at 1.34% saving: 14 onshore projects cleared. Competition was thin at the margin — the marginal bidder was £0.71 below ASP.

14.3 Budget impact:

The 2029/30 total is £228.2m against a £227m/year revised budget — effectively saturating Pot 1 and Pot 2 together, with zero spare capacity for offshore wind even if a single bid had arrived late in the process. The budget design precluded a late rescue of offshore wind via Pot 1 space; the entire £190m Pot 1 envelope was absorbed by solar and onshore.

15. Unsuccessful / notable absences

• No fixed offshore wind applications — coordinated industry abstention, described in §13
• No floating offshore wind applications — same logic, compounded by ASP set too low for pre-commercial technology
• No Wave Energy awards — wave energy had £245/MWh ASP and a nascent pipeline; no successful applications
• No Advanced Conversion Technologies (ACT) awards — £182/MWh ASP insufficient for the current generation of ACT projects
• No Anaerobic Digestion (>5MW) awards — similar profile
• No Dedicated Biomass with CHP awards — historical declining interest in dedicated biomass CfDs
• No Hydro, EfW-CHP, Landfill Gas, Sewage Gas awards — these had technology-specific ASPs but limited active pipeline

These absences sum to a near-complete emptying of every Pot 1 non-solar/non-onshore/non-RIW technology and every Pot 2 non-tidal/non-geothermal technology. AR5 is a story of pipeline concentration as much as a story of the offshore wind failure.

16. Contract obligations beyond the core mechanics

Winning AR5 applicants accept substantial contract obligations beyond the 15-year price stabilisation:

• Supply Chain Plan delivery commitments (for ≥300 MW projects and all floating): ongoing reporting to DESNZ on SCP commitments. For AR5 this applied only to the one 231 MW Strathy South onshore wind project — the SCP threshold being 300 MW meant no AR5 onshore project triggered SCP delivery obligations (Strathy South was below threshold). Solar projects below 5 MW are exempt; offshore wind projects would have triggered SCP but none cleared.
• Milestone Delivery Date — 18 months after Agreement Date, must evidence sufficient progress
• Initial Conditions Precedent — fulfilled within 20 Business Days of Agreement Date
• Operational Conditions Precedent — fulfilled before Longstop Date
• Minimum operability/metering — satisfaction of Metering and Settlement Arrangements per the T&Cs
• Generation Tax Adjustment — strike price adjusts for qualifying taxes post-award
• Change in Law adjustments — via the QCiL mechanism, strike price adjusts for Discriminatory/Specific/General changes in law
• Termination rights — LCCC's termination rights for milestone/CP failures, fraud, insolvency; Generator's termination rights for LCCC default
• Dispute resolution — expert determination or LCIA arbitration per the T&Cs
• Reporting — Operational Year reports, quarterly metered output submissions, compliance certifications

17. Post-award fate

17.1 LCCC contract signing

LCCC typically signs CfD agreements with successful applicants within 3–9 months of results publication. The LCCC announcement of AR5 contract signings (published 2023–24 across several tranches) recorded the cohort of 95 AR5 successful applicants progressing to contract signature. No AR5 cancellations akin to the AR4 Norfolk Boreas or AR6 Hornsea 4 have been publicly recorded for Pot 1 or Pot 2 projects — though individual small solar projects may have withdrawn ahead of commissioning for project-specific reasons not captured in public statements.

17.2 Tidal / geothermal progress

Several AR5 tidal stream projects (MeyGen, Morlais hosts) are in active construction or commissioning phases as of 2025/26. The three geothermal projects are in drilling/construction phases. United Downs is already partially operational.

17.3 The offshore wind non-result and its aftermath

AR5's zero offshore wind outcome triggered the structural AR6 reforms in quick succession:

• Sept–Oct 2023: DESNZ announces intent to restructure offshore wind CfD parameters for AR6
• 16 Nov 2023: AR6 Core Parameters published — offshore wind ASP £73/MWh (+66%), floating offshore wind ASP £176/MWh (+52%); Pot 3 reintroduced as dedicated offshore wind pot
• March 2024: AR6 Budget Notice — Pot 3 initial £800m, subsequently uplifted to £1.1bn in the Budget Revision Notice of 30 July 2024
• March 2024: AR6 Allocation Framework introduces the Offshore Wind Permitted Reduction category — allowing AR4 winners (at £37.35/MWh) to surrender part of their contracted capacity and rebid into AR6 at higher prices. This became the mechanism by which Hornsea 3, Inch Cape, East Anglia 3, and Moray West restored commercial viability
• 3 Sep 2024: AR6 results — 4.9 GW of fixed offshore wind awarded, plus 400 MW of floating offshore wind (Green Volt), at strike prices £54.23 (Permitted Reduction) and £58.87 (new) and £139.93 (floating) — clearing well below ASPs

AR5's failure thus directly precipitated a structural redesign of the scheme.

18. Retrospective — the AR4 → AR5 → AR6 arc

Looking at three successive rounds gives the clearest view of what AR5 was and what it taught:

The arc is:

1. AR4 set aggressive low prices (£37.35) that were celebrated politically but were immediately uneconomic given 2022–23 cost inflation — Norfolk Boreas cancellation is the marker.
2. AR5 preserved AR4's pricing philosophy with minimal uplift (£44 ASP) while removing Pot 3's ringfence. It assumed competitive discipline would drive a clearing price, without recognising that developers had already internalised AR4 losses and were abstaining as a group.
3. AR6 combined: ASP uplifts reflecting real cost levels; Pot 3 reintroduction with £1.1bn/year budget; Permitted Reduction to pay AR4 winners a second time for capacity they had already sold; and significantly uplifted floating wind pricing. The 4.9 GW AR6 offshore wind award restored confidence.

AR5 is, in this arc, the fulcrum — the round whose failure forced the design changes that made AR6 work. Absent AR5's zero bid, the Permitted Reduction category would not have been politically feasible (it paid AR4 winners a higher price for the same projects), and the ASP uplift would have had weaker evidence base for the scale required.

End