UK CfD Allocation Round 6

UK CfD Allocation Round 6 (AR6, 2024)

1. At a glance

Source documents (10 primary sources, all mirrored to B2): core-parameters, budget-notice, allocation-framework, standard-terms-and-conditions (551 pp, 171K words — the master contract text), generic-agreement, application-guidance, sealed-bid-guidance, supply-chain-plan-guidance, results, hornsea-4-cancellation.

2. Market context at time of auction

AR6 ran in a policy climate defined by a single ambitious target and one catastrophic immediate predecessor.

The 50 GW by 2030 target. The British Energy Security Strategy (7 April 2022) raised the UK's offshore wind ambition from 40 GW to up to 50 GW by 2030, including 5 GW of floating offshore wind — a near-quintupling from the ~11 GW then operational. The Offshore Wind Net Zero Investment Roadmap (March 2023) reiterated the target. By the time AR6 opened, about 15 GW was operational, 20–25 GW was in active development, and the 50 GW ambition required every CfD round between AR4 and AR7 to secure multi-gigawatt offshore wind volumes.

AR5 failure as the immediate backdrop. AR5 (September 2023) secured zero offshore wind bids — no applicant chose to submit at the £44/MWh Administrative Strike Price that had been set before the post-pandemic cost inflation properly bit. The failure was publicly recognised as a planning error by government and industry alike. In response:

1. AR6 Administrative Strike Price for Pot 3 (offshore wind) was raised 66% to £73/MWh (2012 prices).
2. Floating Offshore Wind ASP was raised from £116/MWh to £176/MWh — a 52% increase — to address the same cost pressures on immature technology.
3. Pot 3 was retained as a ring-fenced pot dedicated solely to offshore wind, preventing mature offshore from being crowded out by cheaper technologies and vice versa.
4. A new Offshore Wind Permitted Reduction category was introduced within Pot 3 — allowing projects with existing CfDs from earlier rounds (notably AR4 at £37.35/MWh) to surrender part of their awarded capacity and rebid it into AR6 at the higher price. This became the mechanism by which Hornsea 3, Inch Cape, East Anglia 3, and Moray West recovered commercial viability after AR4 pricing became uneconomic.

Supply chain and macro backdrop. The 18 months leading into AR6 saw sustained cost pressure on offshore wind developers: inflation in steel, cables, and turbines; higher interest rates affecting financing costs; and lengthening lead times from Tier-1 suppliers (notably WTG manufacturers). Developer pressure for higher strike prices was vocal and evidence-based. LCCC noted in its pre-round explainer that "Final Parameters for AR6 are still to be announced but... the already published AR6 Administrative Strike Prices are much higher than AR5 (e.g. 66% higher for offshore wind). Higher ASPs together with healthier pipelines of eligible projects should lead to significantly higher budgets" — a signal the scheme was being deliberately calibrated to restore participation.

Political moment. AR6 was launched under a Conservative government in March 2024; the results were published under a Labour government elected in July 2024. The initial £1.025 bn budget set in March was revised upward to £1.555 bn on 31 July 2024 — shortly after the election — a decision the Labour administration inherited and took, leaning into the policy signal that offshore wind was getting generous treatment. The cfdallocationround.uk budget increase announcement framed this as "the budget for the latest auction round... revised to £1.555 billion, an increase of over 50%".

3. Regulatory frame (brief)

The AR6 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

AR6 followed a standard five-stage pattern — Core Parameters → Budget Notice → Application → Valuation → Auction → Notification — but with the wrinkle that on opening, DESNZ publicly stated "AR6 will run to one of five potential timeline scenarios depending on whether there are any appeals following assessment of the submitted applications" (cfdallocationround.uk "Allocation Round 6 opens"). The actual path taken is reconstructed below from the primary sources.

4.1 Full chronology (structured)

Every event, date, actor, and source document is persisted as machine-readable YAML at ../source-docs/uk_ar6/timeline.yaml. The table below is the human-readable rendering; the YAML is the canonical source for any downstream visualisation or ingestion.

Elapsed time summary:

• Core Parameters → Round opens: ~4.5 months (industry preparation window)
• Round opens → Application closes: 3 weeks 3 days
• Application closes → Assessment closes: 4 weeks 2 days
• Assessment closes → Budget Revision: ~10 weeks (the Ofgem appeals + NESO valuation phase)
• Budget Revision → Sealed bid opens: 5 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: ~9.5 months

4.2 Was AR6 on time?

On opening, DESNZ had stated "Results from the round are expected at some point this summer" (27 March 2024). The actual results date of 3 September 2024 fell two days into meteorological autumn but within astronomical summer. The "five potential timeline scenarios" language on opening suggests government was explicit about uncertainty driven by the appeals branch. No public announcements of delays or extensions were issued — the 10-week gap between Assessment closing (20 May) and Budget Revision (31 July) is the most likely absorber, corresponding to the appeals handling period.

4.3 Why a Budget Revision was legally possible

The regulations allow DESNZ to increase (but not decrease) the Budget between the initial Budget Notice and the opening of the sealed bid window, once NESO has provided a final valuation of qualifying applications. The mechanism is the Budget Revision Notice (Regulations 11/12). DESNZ's explicit use of this option in AR6 — increasing the envelope by 52% after seeing the valuation — reflects a deliberate policy choice to capture more of the capacity pipeline rather than reject projects at the margin.

5. The prize — CfD contract mechanics

A winning AR6 bid delivers a 15-year revenue-stabilised subsidy contract with LCCC. The core mechanics are unchanged from earlier rounds, but the specific numerical parameters and a few detail clauses are AR6-specific. The definitive text is in standard-terms-and-conditions (551 pp, "version 6 as at 13 March 2024") and generic-agreement.

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 (£54.23, £58.87, or £139.93/MWh for AR6 offshore wind). 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 in the T&Cs.

5.3 Reference Price

For intermittent technologies (which includes all AR6 offshore wind), 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 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.

Important correction of common misconception: AR6 has no 6-hour threshold for the negative pricing rule. Some pre-AR4 documentation and commentary references a "six-hour consecutive negative price" rule that withheld payment only after six consecutive hours of negative prices. From AR4 onwards (and applying here in AR6), the rule is per Settlement Unit — a single negative half-hour results in zero CfD top-up for that half-hour. There is no minimum duration.

5.5 Contract term — the 15-year clock

Per Generic Agreement Clause 3:

"Specified Expiry Date" applicable to this Contract for Difference is: the 15th anniversary of the earlier of the Start Date and the last day of the Target Commissioning Window.

Two things worth emphasising:

1. The clock starts at the earlier of two events, not the later. If a project commissions early (Start Date before TCW end), the 15-year clock starts at the Start Date. If a project delays commissioning past the TCW end, the clock still starts at the TCW end — the Generator forfeits the subsidy window for the period of delay. This prevents gaming by slow commissioning to "extend" the 15 years.
2. AR6 retained 15 years; the extension to 20 years was introduced for AR7 onwards (from July 2025 reforms). AR6 Generators are locked into the 15-year term.

5.6 Target Commissioning Window, Conditions Precedent, and Longstop

• Initial Milestone Delivery Date: 18 months after the Agreement Date (sourced from the CfD agreement's specific drafting rather than a numbered §5.5 clause in the Standard Terms — the earlier §5.5 citation was imprecise; the Standard Terms define "Milestone Delivery Date" by reference to the "Initial Milestone Delivery Date" in the agreement). Project must evidence sufficient progress to meet the Generator's Milestone — broadly demonstrating construction has started and key contracts are in place.
• Target Commissioning Window (TCW): up to 1 year in length for Offshore Wind and Floating Offshore Wind per Allocation Framework Schedule 6 (the shorter windows apply to other technologies — e.g. 3 months for Solar PV, 6 months for Landfill Gas). The TCW is positioned by the Generator such that: (a) the Target Commissioning Date (TCD) falls within the TCW; (b) the TCD falls no earlier than the first day of the first Delivery Year and no later than the last day of the final Delivery Year, with an explicit exception for later phases of Phased Offshore Wind CFD Units whose TCDs can fall beyond the last Delivery Year; (c) the TCW Start Date is no earlier than the point at which the final day of the TCW falls on the first day of the applicable Delivery Year — this is an earliest-TCWSD floor, not a TCW-end ceiling, so the TCW can straddle the Delivery Year and extend up to one year beyond the final Delivery Year's last day.
• Initial Conditions Precedent: must be fulfilled within 20 Business Days of the 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.
• The Milestone Delivery Date and Longstop Date can both be extended day-for-day for specific delay causes listed in the T&Cs, including judicial review of planning consents (within statutory windows) and Ministry of Defence Radar Mitigation Scheme non-confirmation (for offshore wind, onshore wind, and remote island wind specifically).

5.7 What happens if a project fails to commission

If Operational CPs are not met by the Longstop Date, the CfD can be terminated by LCCC. If a project commissions later than the TCW end, the 15-year clock has already started and the Generator loses the subsidy for the lost period. This is the central enforcement mechanism: there is no "pause" on the 15-year term for late delivery. The Hornsea 4 cancellation (see §18) is the most visible recent example of a Generator walking away from its CfD — in that case before the Initial Milestone Delivery Date, to cap the sunk-cost exposure before Ørsted's internal Final Investment Decision.

6. Budget architecture

This is the most commonly misunderstood aspect of a CfD round. The numbers in the Budget Notice are not additive year totals — they are per-year caps on annual subsidy exposure from winners of this round, across each of the applicable Delivery Years and subsequent Valuation Years. A project awarded in AR6 draws subsidy from the same annual envelope every year it is operational under its 15-year contract; the Budget Notice constrains how much that annual draw-down can be in any single year across all AR6 winners combined.

6.1 The initial Budget (6 March 2024)

From:

How to read this: a Pot 3 project with Target Commissioning Window Start Date in 2027/28 draws from the £800 m/year Pot 3 budget in 2027/28, 2028/29, 2029/30, 2030/31 — its annual subsidy valuation is counted against Pot 3 in each of those years. If a second Pot 3 project also commissions in 2027/28, both projects' annual valuations must together fit within £800 m per year. The 2030/31 row does not add £800 m of new budget — it is the continuation of the exposure carried over from Pot 3 winners whose contracts are still running. (Pot 1 has no 2030/31 row because Pot 1 Delivery Years end at 2027/28, so Pot 1 winners' contracts have started drawing from Pot 1 budget but the final valuation year of 2030/31 is not a Pot 1 Delivery Year.)

The initial budget is quoted in 2011/12 prices — an older base than the 2012 prices used for strike prices. Both are reconciled by the CPI inflator of 1.0193 that converts 2011/12-price figures to 2012-price figures for valuation against bids. The explicit formula is $CPI\ Adjustor_{£{2011/12} \to £{2012}} = AverageCPI_{2012} / AverageCPI_{2011/12}$, yielding 1.0193.

6.2 Maxima, Minima, and their role

Within the pot envelopes the Budget Notice sets hard-constraint Maxima and Minima:

• Pot 1 Maxima — three separate £120 m Maxima for Onshore Wind, Remote Island Wind, and Solar PV. Hard constraint in monetary terms. This prevents any one established technology from absorbing the whole Pot 1 envelope.
• Pot 2 Minimum — £10 m ringfenced for Tidal Stream. Hard monetary constraint. Ensures tidal gets at least £10 m/year of annual support even if it would otherwise be outcompeted.
• Pot 2 Maximum — £8 m cap on Geothermal. Hard monetary constraint.
• Pot 3 Maxima — two separate £800 m Maxima: one for Offshore Wind Permitted Reduction projects (rebids from earlier rounds) and one for new Offshore Wind projects. Hard monetary constraints. Because each Maximum matches the Pot 3 envelope, neither sub-category can absorb more than the full pot — but the two cannot together exceed £800 m/year either, because they share the same Pot 3 envelope.

Hard vs Soft constraints: constraints expressed in monetary terms are always hard — a bid that would push monetary spend over the Maximum/Minimum/Pot is simply unsuccessful. Constraints expressed in capacity terms (MW) can be designated Soft by the Budget Notice, in which case they may be exceeded in the interleaving process but only in specific circumstances. For AR6 no Soft Constraints were used; every Pot and Maxima/Minima operated as hard constraints.

6.3 The budget revision (30 July 2024, announced 31 July)

Regulations 11 and 12 give DESNZ an upward-only option to revise the Budget after NESO has completed its valuation of qualifying applications and any Ofgem appeals are concluded. DESNZ exercised it in full via the Budget Revision Notice signed and dated 30 July 2024 by Sarah Redwood (Director Renewable Electricity, on behalf of the Secretary of State) and publicly announced the following day via cfdallocationround.uk.

Full revised budget (2011/12 prices):

Per-pot change vs the initial Budget Notice:

Crucially, the Maxima were uplifted in parallel — resolving a question that could only be answered by reading the Revision Notice itself rather than the cfdallocationround.uk announcement:

• Pot 3 Offshore Wind Permitted Reduction Maximum: £800 m → £1,100 m
• Pot 3 new Offshore Wind Maximum: £800 m → £1,100 m
• Pot 1 Solar PV Maximum: £120 m → £185 m
• Pot 1 Onshore Wind Maximum: £120 m → £185 m
• Pot 1 Remote Island Wind Maximum: £120 m → £185 m
• Pot 2 Tidal Stream Minimum: £10 m → £15 m
• Pot 2 Geothermal Maximum: £8 m (unchanged)

Each Pot 3 Maximum now equals the Pot 3 envelope of £1,100 m, so either sub-category could absorb the entire Pot 3 budget in principle — but they compete for a shared envelope and cannot collectively exceed it. In practice, the actual AR6 outcome left headroom in Pot 3 (peak annual impact of £870 m/year against a £1,100 m envelope — see §10.1), so the Maxima were not the binding constraint that closed the auction.

Regulation 12(5) — the upward-only mechanics, in detail:

Where, the Secretary of State may increase the overall budget but must not—

(a) decrease (i) the overall budget; (ii) any maxima; or (iii) any minima; or (b) increase any maxima or minima, unless the overall budget is increased by at least the same amount; or (c) remove the application of a soft constraint to a budget.

This regulation is the legal constraint that shaped AR6's revision. DESNZ could increase the overall budget (and did, by £530 m); could increase Maxima only because the overall budget was increased by at least the same amount (satisfied — £530 m overall > any individual Maximum increase); and could not remove soft constraints (none were in use anyway). The practical effect: once you enter the sealed bid window, the only valid revisions are upward, and they must be "budget-led" rather than "Maximum-led" — you can't narrow the envelope or tighten a sub-cap mid-auction.

Political context: the revision was signed 30 July 2024, five days after Labour took office on 4 July (actually 26 days — apologies, Labour election was 4 July 2024 and they took office the same day, so the Revision Notice was 26 days into the new government). It was effectively the Starmer administration's first major CfD policy decision, though the technical work on the valuation had been done by NESO during the Conservative administration's final weeks. Labour inherited and executed the uplift.

"There is no capacity budget for AR6": the Notice explicitly confirms that AR6 used no capacity caps — every Pot, Maximum, and Minimum was expressed purely in monetary terms. See §8.9.

6.4 Why this structure matters for comparisons

When comparing AR6 to other auctions, the peak annual exposure cap is the meaningful budget number — not some "total programme cost" calculation. AR6's £1.555 bn/year for ~5 months of bidding is dramatically larger than any previous CfD round but commensurate with the 5 GW/year of fresh offshore wind capacity the 50 GW 2030 target implicitly requires. By contrast, auctions like Denmark's Thor or Germany's N-12 operate on award-price-plus-concession-fee mechanics rather than annual subsidy envelopes, so "budget" is not a like-for-like comparator across regimes. A good auction comparison page needs to normalise for this.

7. Administrative Strike Prices

The ASP is the maximum strike price an applicant can receive — the ceiling on the auction clearing price, and the fallback "default" strike price awarded in unconstrained allocation (no auction held). For AR6 the ASPs for all eligible technologies:

The two uplifts that matter for this writeup — offshore wind +66% and floating offshore wind +52% — are the direct AR5-failure response. Every other ASP stayed the same or had minor adjustments. The signal was unambiguous: the Pot 3 ASP had been too low at £44/MWh in AR5; £73/MWh was DESNZ's calculated best guess at what would restore participation without overcompensating bidders.

All ASPs are quoted in 2012 prices. To convert to a more current price base, applicants can use the CPI inflator published alongside the Core Parameters. At Core Parameters publication (November 2023, CPI base September 2023), the inflator was 1.3736. At Budget Notice publication (March 2024, CPI base January 2024), the inflator had climbed to 1.3956 — a useful proxy for ongoing inflation between the two publications.

Converting AR6 offshore wind ASP of £73/MWh (2012) using the March 2024 inflator gives ~£101.9/MWh in January 2024 money — a meaningful number when comparing to then-current wholesale prices or cost-of-energy estimates.

8. Qualification criteria

A project had to pass a sequence of qualification gates before NESO would even consider its sealed bid. These are structural prerequisites, not competitive factors — they either all pass or the application is non-qualifying.

8.1 Planning consent

• England/Wales ≥100 MW: a Development Consent Order (DCO) under the Planning Act 2008 (NSIP regime), granted by the Secretary of State on Planning Inspectorate recommendation.
• Scotland: a Section 36 consent under the Electricity Act 1989, granted by Scottish Ministers.
• For Permitted Reduction rebids (projects that already won an earlier CfD), the underlying DCO/S36 is already in place — a partial reason the rebid mechanism works at all.

8.2 Grid connection

The applicant must hold a valid grid connection offer from the relevant transmission owner (SSEN Transmission, SP Energy Networks, National Grid Electricity Transmission) with a defined connection date and point. Grid connection queue reform was happening during the AR6 window but did not substantially affect AR6 eligibility — subsequent rounds are more exposed to the TMO4+ and other queue reforms.

8.3 Supply Chain Plan (SCP)

A statutory gate for larger projects and all floating offshore wind:

• Projects ≥300 MW: must submit a Supply Chain Plan to DESNZ and receive an approval statement from the Secretary of State before the Allocation Round application window opens.
• All floating offshore wind projects (any size): must submit a lighter-touch, bespoke floating-OW SCP. DESNZ's rationale: floating OW is "on the verge of mass commercialisation and deployment... likely to play an important role in meeting our 50 GW target".
• Pass thresholds:
  • ≥300 MW projects: scoring <60% in any one section of the SCP risks refusal of the approval statement
  • Floating OW projects: scoring <50% across the whole SCP risks refusal
• SCP scores do not influence strike price or budget impact — they are a pass/fail gate only. The Secretary of State's approval is a binary signal to NESO that the project qualifies.
• Separate questionnaires exist for offshore wind, onshore wind, solar PV, and floating OW, each calibrated to the technology's supply chain profile.

8.4 Bid submission constraints

Once qualified, an applicant can submit up to four Flexible Bids per application:

• Each Flexible Bid is a sealed bid with potentially different capacity, Target Commissioning Dates, and Strike Price.
• No more than two bids may have a Target Commissioning Window Start Date in the same Delivery Year.
• All Flexible Bids must be at different Strike Prices.
• Subject to a carve-out for Phased Offshore Wind, Flexible Bids cannot have earlier TCWSDs or greater capacity than the Original Application.
• Strike prices in Flexible Bids must be expressed to the nearest £0.001 (tenths of a penny per MWh) per Allocation Framework Rule 11.6(b), subject to the Rule 11.4 carve-out that the lowest Strike Price bid in each Delivery Year must be to the nearest £0.01.

8.5 Phased Offshore Wind CfD Units — constraints

Offshore wind projects can bid as Phased Offshore Wind CfD Units, where the project delivers in sequential phases each with its own Target Commissioning Window but sharing a single Strike Price across all phases. The structure comes with four hard constraints:

1. Maximum 1,500 MW total across all completed phases. This is a project-level cap that limits how large a single phased offshore wind CfD Unit can be.
2. First phase ≥25% of total capacity. Prevents gaming by bidding a tiny token first phase followed by a giant second phase.
3. First phase Target Commissioning Date ≤ 31 March of the last applicable Delivery Year. Anchors the delivery schedule against the Pot's Delivery Years.
4. Final phase TCD ≤ 2 years after first phase TCD. The maximum spread between first and last phase commissioning is 2 years — you cannot phase a 10-year buildout across a single AR6 CfD.
5. Phased structure restricted to older leases — per Rule 4 the phased option is only available to offshore wind projects originating from Crown Estate Round 2 or Round 3 leases, or Scottish Territorial Waters leases. Crown Estate R4 (2021) and ScotWind (2022) projects cannot use the phased structure.

The practical implications for AR6:

• Hornsea Project Three (Crown Estate R3, Ørsted) used the phased structure — 3 × 360 MW = 1,080 MW total, under the 1,500 MW cap. The resulting awards are reported as Hornsea 3 AR6 A, B, C at £54.23/MWh Permitted Reduction.
• Hornsea Project Four (Crown Estate R3, Ørsted) at 2,400 MW could not use the phased structure because it exceeds the 1,500 MW cap. It was submitted as a single non-phased bid at £58.87/MWh — and, notably, became the single largest AR6 award before being discontinued in May 2025 (see §17.1). A counter-factual worth flagging: if Hornsea 4 had been allowed to phase, Ørsted might have had more commercial flexibility to deliver in stages rather than a single all-or-nothing commitment.
• East Anglia Two was split into phases, with only "Phase 1" (963 MW) entering AR6. Subsequent phases would need to enter later rounds.

8.6 Excluded applications

Pursuant to: "no Application may be made in respect of a CFD Unit where the CFD Unit is or is part of a Generating Station which has been Commissioned." Already-commissioned projects are excluded — the CfD is a support mechanism for projects still to be built, not a retroactive subsidy for operating assets. This rules out any "rebid for an already-operating project" scenario and restricts the Permitted Reduction mechanism to pre-commissioning AR4 winners.

8.7 Technology-specific minimum capacity thresholds

From the Pot definitions:

• Pot 1: Onshore Wind >5 MW, Remote Island Wind >5 MW, Solar PV >5 MW, Hydro >5 MW and <50 MW (upper bound!). Energy from Waste with CHP, Landfill Gas, Sewage Gas — no explicit lower bound stated.
• Pot 2: Anaerobic Digestion >5 MW. All other Pot 2 technologies (ACT, Dedicated Biomass with CHP, Floating Offshore Wind, Geothermal, Tidal Stream, Wave) — no explicit lower bound.
• Pot 3: Offshore Wind — no explicit lower bound stated at the technology level, though the practical minimum is around 100 MW (the NSIP DCO threshold for England/Wales offshore wind).

The hydro upper bound (<50 MW) is unusual — it reflects the policy intent that larger hydro projects (which are typically pumped-storage or run-of-river on major rivers) are commercial without CfD support and should not enter the scheme. No other Pot 1 technology has an explicit upper bound.

8.8 INTOG leasing does not automatically qualify for CfD

An important wrinkle for offshore wind specifically: states "an exclusivity agreement granted by Crown Estate Scotland, such as through the Innovation and Targeted Oil and Gas leasing round, does not satisfy Regulation 27(2) of the Contracts for Difference Allocation Regulations 2014". In other words, an INTOG exclusivity agreement alone is insufficient — an INTOG-origin project needs additional seabed rights or agreements beyond the INTOG lease to qualify for a CfD.

Implication for Green Volt: Green Volt is an INTOG-origin project, but it successfully qualified for and won the AR6 floating OW CfD. This means Flotation Energy/Vårgrønn had additional lease or rights documentation satisfying Regulation 27(2) beyond the INTOG exclusivity agreement itself.

8.9 Capacity Caps in principle, not used in AR6

For completeness: the Budget Notice mechanism supports Pot Capacity Caps (per pot, in MW) and Overall Capacity Caps (across all pots, in MW) in addition to monetary Maxima and Minima. These operate the same way as monetary caps — if the valuation total exceeds the capacity cap, an auction is triggered. Capacity caps can be designated as either Hard or Soft constraints (Soft only for capacity-expressed constraints).

AR6 did not use any capacity caps — the Budget Revision Notice explicitly states "There is no capacity budget for AR6", confirming that every Pot, Maximum, and Minimum was expressed purely in monetary terms. The initial Budget Notice had already indicated this via the text "will be applied on a monetary budget (£ million) basis"; the Revision Notice made the absence of capacity caps explicit and categorical. In other CfD rounds (AR4 used capacity caps for solar and onshore wind in Pot 1), capacity caps have been an active feature. AR6's pure-monetary approach simplified the constraint checking but left more flexibility for technology mix within each Pot's £ envelope.

9. Evaluation criteria, process, and scoring

This is the fullest answer to "how did National Grid ESO turn a pile of applications into 131 successful applicants (130 later signed per LCCC 14 Nov 2024) across all technologies?" The process is specified in and summarised in. It splits into three distinct scoring exercises, each with its own criteria, followed by a deterministic allocation process that applies those scores to select winners.

9.1 Scope of evaluation — what IS and ISN'T evaluated

AR6 is a price-only sealed-bid pay-as-clear auction with binary qualification gates. Only one dimension is evaluated competitively: the bid Strike Price. Every other factor either passes a qualification test (binary) or is used to compute budget impact from the Strike Price (deterministic formula).

What is NOT evaluated competitively at auction:

• Applicant financial strength (no credit rating assessment affects scoring)
• Technical competence or technology-readiness (not scored at auction stage)
• Local content, ESG, or deliverability weighting (contrast with Crown Estate R5, ScotWind, DK Thor)
• Project-specific cost reconciliation (the bid price is accepted at face value — no bottom-up cost audit)
• Developer track record (no prior-performance multiplier)
• Stakeholder or community benefits (not scored)

What IS evaluated before the auction, as pass/fail qualification gates:

• Planning consent — DCO (E/W NSIPs ≥100 MW) or Section 36 (Scotland) must be in place and valid
• Grid connection — a valid connection offer with a defined date and point
• Supply Chain Plan approval — Secretary of State must have issued an SCP approval statement (for projects ≥300 MW or any floating OW)

What IS evaluated competitively at the auction:

• Bid Strike Price — a single monetary value (expressed to the nearest £0.001/MWh) that becomes the competitive scoring dimension

The contrast with multi-criteria regimes is the single most important structural feature of AR6 for comparative analytics. Crown Estate R5 (Celtic Sea, 2025) evaluates on a weighted multi-criteria basis (supply chain, environmental/social, deliverability, price); ScotWind (2022) used 10 scored criteria; DK Thor (2021) used monetary concession fee competition (negative bidding); DE N-12.1 (2023) used pre-investigated site auctions with uncapped monetary bidding. AR6 is the cleanest "pure price-only offtake" auction in the comparison set — which makes it the benchmark against which those regimes should be differentiated, not a proxy for them.

9.2 Scoring exercise #1 — Supply Chain Plan qualification scoring

The SCP is the only place where multi-criteria scoring happens in AR6, and it's a qualification gate, not a competitive factor. Projects ≥300 MW (including all offshore wind projects of any size if their capacity meets the threshold) and all floating offshore wind projects (regardless of size) must submit a Supply Chain Plan to DESNZ before the round opens.

Mechanics:

1. Separate questionnaires per technology:
   • Fixed offshore wind (≥300 MW) — detailed questionnaire covering supply chain engagement, UK content, innovation, skills, emissions
   • Floating offshore wind (any size) — lighter-touch bespoke questionnaire calibrated to floating OW maturity
   • Onshore wind (≥300 MW) — technology-specific
   • Solar PV (≥300 MW) — technology-specific
2. Sectional scoring: each section receives a percentage mark out of the maximum for that section.
3. Pass thresholds:
   • ≥300 MW projects: at least 60% in every section. A score of <60% in any one section is likely to result in refusal of the SoS approval statement. This is an AND threshold — all sections must pass.
   • Floating OW projects: at least 50% across the whole plan. This is a weighted overall threshold, averaged across sections rather than per-section.
4. Decision: the Secretary of State personally issues a written approval statement if the SCP is judged adequate. No approval = no qualification = no participation in the Allocation Round. The SCP score itself is not disclosed publicly and does not feed into any strike price adjustment or bid weighting — it is pure pass/fail.
5. Post-award enforcement: the commitments made in the approved SCP become contractual Project Commitments under Annex 5 of the Generic Agreement. If a Project Commitment is not met by the end of the Target Commissioning Window, the Generator's 15-year CfD term is reduced. This is how SCP gets teeth — failure is punished via lost subsidy years, not lost strike price.

For AR6 offshore wind specifically, every project ≥300 MW (every fixed OW project) and Green Volt (floating) passed this gate or they would not appear in the results. The SCP scores themselves are not published.

9.3 Scoring exercise #2 — the Valuation Formula (budget impact scoring)

Before deciding whether an auction is even needed, NESO must calculate how much monetary budget each application would consume if accepted at its Administrative Strike Price. This is a deterministic formula, not a competitive score, but it's the mechanism by which different technologies and different bid capacities are converted to a common "budget footprint" comparable across the pot.

The formula lives in Schedule 2 of the Allocation Framework. In simplified form for each Application in each Delivery Year:

Annual budget impact (£) = (ASP − Reference Price) × IICE × Days × YR1F × Technology Load Factor × General Conversion Factors

Where:

• ASP (£/MWh, 2012 prices): the Administrative Strike Price for the applicable technology — the maximum that would be paid. Used in the pre-auction valuation regardless of what the applicant eventually bids. In the auction phase, the bid Strike Price replaces ASP in this formula.
• Reference Price (£/MWh, 2012 prices): the forecast Market Electricity Price for the relevant period (Intermittent MRP for offshore wind; Baseload MRP for dispatchable tech). Published in the Allocation Framework annexes — a fixed assumption, not a market-live value.
• IICE (MW): the Initial Installed Capacity Estimate — the capacity declared in the Application or Flexible Bid.
• Days: days in the year (365 or 366).
• YR1F: the Year-1 Factor — a fraction accounting for partial-year generation when the Target Commissioning Window Start Date falls partway through the first year.
• Technology Load Factor: the assumed generation profile as a fraction (e.g. 48% for fixed offshore wind — published per-technology in the Allocation Framework annexes). This is a contested assumption — developers have historically argued load factors are set too high for offshore wind, inflating budget impact and reducing capacity that can clear.
• General Conversion Factors: transmission losses, hours-to-days conversion, etc.

The same formula is used for both the pre-auction valuation (to decide whether an auction is needed) and the auction itself (using the bid Strike Price instead of the ASP). Results are summed by Delivery Year, by Pot, and by Overall Budget to produce the aggregate figures against which budget and capacity constraints are checked.

This is where the "implicit weighting" of the price-only auction lives. Load Factor and Reference Price assumptions — which vary by technology — effectively determine how much budget a given MW of a given technology consumes. A technology with a higher Load Factor assumption produces more annual output per MW and therefore a larger monetary budget impact at the same Strike Price; that technology gets less total capacity through a fixed-£ envelope. The auction is price-only in its ranking dimension but technology-sensitive in its quantity allocated dimension.

9.4 Constrained vs unconstrained — the auction trigger decision

After NESO computes the Valuation Formula across all qualifying applications at each ASP, it compares the aggregate against the Pot's Monetary Budget and any Capacity Cap:

• Unconstrained allocation: if the total valuation of all qualifying applications in a Pot is ≤ the Monetary Pot AND ≤ any applicable Capacity Cap, all applicants are declared Successful at the technology-specific ASP. No auction is held, no sealed bids are invited, every qualifying applicant wins at the ceiling price.
• Constrained allocation: if either the monetary total or the capacity total exceeds its respective ceiling, NESO issues a Notice of Auction to all qualifying applicants, inviting sealed bids. An auction is then run per Rule 17.

For AR6, all three Pots were constrained — which is why clearing prices fell below the ASPs in every pot. Pot 3 was ~3× oversubscribed by value (see §10.1), so the Notice of Auction was inevitable.

9.5 Sealed bid submission — what applicants submit and when

Once a Notice of Auction is issued, the sealed bid window opens. Applicants submit their bids via the EMR Delivery Body Portal during a 5-working-day window:

1. Up to four Flexible Bids per Application. Each Flexible Bid is a tuple of (Strike Price, Capacity, Target Commissioning Date, Target Commissioning Window Start Date).
2. Each Flexible Bid must have a different Strike Price. Duplicate prices within one application are rejected.
3. Prices expressed to the nearest £0.001/MWh — tenths of a penny.
4. No Flexible Bid may have an earlier TCWSD or greater capacity than the Original Application, except in the specific Phased Offshore Wind case.
5. No more than two Flexible Bids may target the same Delivery Year. Applicants must spread their flexibility across years if they want four bids.
6. Bids can be withdrawn and resubmitted any time before the window closes. The last submission at the close time is the one that counts.
7. No submission = default bid: if an applicant submits nothing by the close, NESO assigns them a single bid at the Administrative Strike Price with the original application's capacity and dates. This means a qualified applicant cannot accidentally exit the auction by failing to submit; they stay in at the ceiling price.

9.6 Auction process — Rule 17 step-by-step

When the sealed bid window closes, NESO runs the auction on the next working day. For AR6 this was 12 August 2024. The process per:

Step A — hard-constraint exclusion (Rule 17.2): Walk every bid and check: would this bid alone exceed a hard-constraint Maximum, Monetary Pot cap, or Capacity Cap? If yes, the bid is immediately declared unsuccessful and removed from the stack. This catches outlier bids whose own capacity is larger than the remaining envelope.

Step B — bid ranking (Rule 17.4): Sort all surviving bids within the Pot ascending by Strike Price — lowest price first. The stack is now ordered from cheapest to most expensive.

Step C — walking the stack: Starting at the top (lowest price), NESO provisionally admits bids into the Successful set one at a time. After each admission, it updates a running total of:

• Monetary value used = sum of the Valuation Formula across all provisionally successful bids in that Pot, for each Delivery Year and subsequent Valuation Year
• Capacity used = sum of IICE across all provisionally successful bids in that Pot
• Per-Maximum sub-totals (e.g. the £800 m Permitted Reduction Maximum, £800 m new Offshore Wind Maximum in Pot 3)
• Minimum obligations being satisfied (Pot 2 £15 m ringfenced for Tidal Stream)

The walk stops admitting bids as soon as the next bid would cause a running-total breach of any hard constraint (Pot cap, Capacity Cap, Maximum, or — inversely — cause a Minimum to be under-satisfied without rescue).

Step D — interleaving (Rule 17.6): When the walk hits a bid that would cause a breach, NESO does not immediately close the auction. Instead, it checks whether the breaching applicant has a Flexible Bid still available at a different (higher) price but lower monetary impact — i.e. a smaller-capacity or differently-dated substitute. If so:

1. The breaching bid is rejected.
2. The applicant's next Flexible Bid (at the next-higher strike price) is provisionally admitted.
3. NESO checks if all constraints remain satisfied.
4. If yes, the auction continues walking the stack from where it was; if no, another Flexible Bid substitution is attempted.
5. If all Flexible Bids for that applicant are exhausted and no substitution satisfies the constraints, the auction closes.

This mechanism lets high-confidence bidders "scale back" their capacity mid-auction to fit within the residual envelope rather than being excluded entirely. It's why applicants are incentivised to submit the full four Flexible Bids: optionality during interleaving is valuable.

Step E — tiebreakers (Rule 19): If two or more bids cannot all be accepted without breaching a relevant budget / Maximum / Minimum constraint, the Delivery Body (National Grid ESO) selects the application (or combination of applications) that comes closest to filling the relevant envelope without breach. If multiple alternatives are equally close, the Delivery Body chooses at random via a deterministic electronic random-assignment process. This is an envelope-fit rule, NOT a "rank by capacity, then random" rule — the selection criterion is proximity-to-envelope, not absolute capacity. No public tiebreaker application is reported for AR6, suggesting no relevant envelope-fit ties occurred, though the Permitted Reduction bids all cleared at exactly £54.23/MWh — consistent with them sharing a common bid price that fit within the envelope without needing tiebreaker discrimination.

Step F — auction closes: The auction terminates when NESO cannot admit any further bids without breaching a constraint or exhausting the applicant Flexible Bid options. All provisionally successful bids become Successful Applications.

9.7 Clearing price determination — pay-as-clear with per-Maximum separate clearing

The scoring process so far has determined which bids are successful. The clearing price step determines what price each winner receives:

Pay-as-clear base rule: all Successful Applications in a Pot receive the same Clearing Price, equal to the highest Strike Price of any Successful Application in that Pot, capped at each winner's own Administrative Strike Price. This is the "pay-as-clear" (or "uniform-price") mechanism — the highest-price winner sets the price for all winners, which is a lower-price outcome than pay-as-bid (where each winner receives their own bid price).

Separate per-Maximum clearing (Rule 18): when a Pot has Maxima applied to sub-categories, each Maximum runs its own clearing-price calculation. Successful bids within a Maximum receive a clearing price equal to the highest successful bid price within that Maximum, not the Pot as a whole. The practical effect: sub-category bids compete against each other rather than against the whole Pot.

Why AR6 Pot 3 produced TWO clearing prices: Pot 3 had two £800 m hard Maxima — one for Offshore Wind Permitted Reduction and one for new Offshore Wind. Each Maximum ran its own separate clearing calculation:

• Permitted Reduction Maximum: the successful PR bids (Hornsea 3 A/B/C, Inch Cape A/B, Moray West S9, EA3B) all had sealed bids at or just below £54.23/MWh. The highest successful PR bid set the PR clearing price at £54.23/MWh.
• New Offshore Wind Maximum: the successful new-capacity bids (Hornsea 4, East Anglia Two Phase 1) had bids at or just below £58.87/MWh. The highest successful new-OW bid set the new-OW clearing price at £58.87/MWh.

Neither the PR clearing price nor the new-OW clearing price was set by the highest bid in Pot 3 as a whole — each Maximum operated its own clearing, producing the two-price outcome in a single Pot. This is the structural reason AR6 reported two Pot 3 clearing prices rather than one.

Cap at ASP: no Clearing Price can exceed the technology-specific ASP. For AR6 the Pot 3 ASP was £73/MWh; neither clearing price came close, so this cap did not bind. In AR5 (which failed), the issue was different — bids were not submitted at all because the £44/MWh ASP ceiling was below developer break-evens, so no bids entered the stack to clear.

9.8 Post-auction audit and Secretary of State review

Immediately after NESO runs the auction, an Independent Auditor (appointed per Regulation 36) conducts a Process Audit of the valuation and allocation calculations. The Independent Auditor:

1. Verifies NESO used the Valuation Rules and Allocation Rules correctly
2. Verifies applicant details were applied correctly to the formulae
3. Produces an Audit Report stating: (a) whether calculations were correct and accurate, and (b) identifying any errors and their consequences

NESO then transmits the Audit Report plus its own recommendation to the Secretary of State for Energy Security and Net Zero, who has two working days to decide:

• Proceed — accept the results and instruct NESO to notify winners
• Re-Run — if errors were found, re-run some or all of the auction
• Cancel — terminate the Allocation Round entirely (never invoked in practice to date)

If the Secretary of State does not respond within two working days, NESO proceeds with its recommendation by default. The auditor's report and the SoS decision record become part of the Allocation Round file.

For AR6, the SoS review decision was Proceed. NESO notified all applicants on 3 September 2024 and DESNZ published the results document on the same day.

9.9 From evaluation to results

To summarise the full end-to-end process for AR6:

1. ≥300 MW and all floating OW projects submit Supply Chain Plans to DESNZ (pre-round). SoS approves or rejects. Binary pass/fail — no competitive scoring.
2. Applicants submit Applications via NESO's EMR Portal during the application window (27 Mar – 19 Apr 2024).
3. NESO runs qualification assessment against DCO, grid connection, SCP approval (22 Apr – 20 May 2024). Ofgem handles appeals (~May–Jul 2024).
4. NESO computes the Valuation Formula across all qualifying applications at their ASPs, summed by Pot and Delivery Year.
5. NESO reports the valuation total to DESNZ; DESNZ exercises the Budget Revision option (notice signed 30 Jul 2024, announced 31 Jul) to increase the Pot envelopes and lift all Maxima in parallel before sealed bid.
6. Because the revised Pot budgets are still exceeded by the valuation, NESO issues Notices of Auction (5 Aug 2024). Sealed bid window opens.
7. Applicants submit up to 4 Flexible Bids each via the EMR Portal (5–9 Aug 2024).
8. NESO runs the auction per Rule 17 on the next working day (~12 Aug 2024): exclusion → ranking → walking the stack → interleaving → tiebreakers → close.
9. NESO determines clearing prices — one per Pot, or one per Maximum when sub-categorised (as in Pot 3). Pay-as-clear at the highest successful bid within each scope.
10. Independent Auditor reviews the calculations. SoS reviews the audit report and NESO's recommendation. SoS issues Proceed notice.
11. NESO notifies all applicants on 3 September 2024. DESNZ publishes the results document the same day.

The output of this process is a list of Successful Applications with their awarded Strike Prices (cleared, not bid), the 6 affected fixed offshore wind projects across two sub-category clearing prices, the Green Volt 400 MW floating award, plus solar, onshore wind, and tidal stream winners totalling 133 contracts and 9,648 MW.

10. Competitive landscape — what bid, what cleared

The AR6 results document publishes a remarkable data point: the total value of all applications originally received, valued at the Administrative Strike Price, alongside the actual monetary budget impact of the awarded contracts. Putting these side by side gives a direct read of competitive tension:

10.1 Pot 3 (offshore wind) — ~3× oversubscription by value

Interpretation: in the peak exposure year (2030/31), applicants brought £2.83 bn/year of subsidy demand valued at the £73/MWh ASP, of which £870 m/year was selected into the winning set — a clearance rate of around 31%. Two thirds of the Pot 3 applications by value were left on the table. This is a strong oversubscription signal and a primary reason the clearing prices landed well below the ASP (see §14).

Price-base warning on headroom calculations: the revised Pot 3 envelope of £1,100m is published in 2011/12 prices per the Budget Revision Notice, while the results impact figures are calculated in 2012 prices. The Budget Notice specifies a CPI inflator of 1.0193 to rebase 2011/12 figures to 2012 prices before valuation. So the like-for-like comparison is £870.30m (2012) against £1,121.23m (2012-rebased Pot 3 envelope), leaving about £251m of headroom in 2012-price terms. Comparing £870m directly against £1,100m (as my earlier draft did) mixes price bases and understates the actual headroom slightly. The qualitative point — Pot 3 had unused headroom — still stands, but the specific headroom figure should be the rebased comparison. The published primary sources do not disclose why the auction closed at its particular level (the losing bid stack is confidential), so the inference that "the next bid would have either broken a Maximum sub-cap or competed below its cost floor" goes beyond what the primary record establishes and should be softened to "the auction closed before the overall Pot 3 envelope was reached, leaving headroom — the precise marginal-exclusion mechanism is not public".

10.2 Pot 2 (less-established tech) — severe floating oversubscription in later years

Pot 2's annual exposure of ~£228 m/year fits neatly within the revised £270 m envelope (headroom ~£40 m/year). The clearance rates suggest Pot 2 was tighter in earlier years (where tidal and small projects live) and more comfortable in later years (where floating OW commissions).

10.3 Pot 1 (established tech)

Peak Pot 1 annual exposure of £187.34m/year (in 2012 prices) fits inside the revised £185m envelope once the envelope is rebased: the Budget Revision Notice's £185m is in 2011/12 prices, which rebases to approximately £188.57m in 2012 prices using the published 1.0193 inflator. So Pot 1 on a consistent-price basis is within the revised envelope, not slightly above it as my earlier draft incorrectly stated. Same price-base correction applies to Pot 2 (£228.23m impact vs rebased £275.21m envelope) and Pot 3 (£870.30m impact vs rebased £1,121.23m envelope). The point about Pot 1 per-technology Maxima (£120m each for onshore wind, solar, remote island wind) being the binding shaping constraint still holds.

10.4 Non-offshore-wind winners (brief)

This is an offshore-wind-focused writeup, but for completeness the non-offshore-wind awards were:

Solar PV was the dominant technology by count but below offshore wind on capacity (3.3 GW vs 5.3 GW). Onshore wind's 990 MW in AR6 was concentrated almost entirely in Scotland (909.77 MW out of 990.37 MW — 91.9%), reflecting both the lifting of the effective English onshore wind moratorium and the concentration of Scottish wind development. Tidal stream secured 28 MW across two Delivery Years — modest but meaningful for a near-commercial technology, and the £15 m ringfenced Tidal Minimum did its intended job.

Total AR6 capacity across all technologies and pots: 9,648.26 MW across 131 successful applicants at the 3 September 2024 results publication, of which 130 signed CfD contracts with LCCC by 14 November 2024 (per LCCC's official announcement of that date), delivering 9.58 GW of new renewable capacity once commissioned. One project was offered a contract but did not sign.

10.5 Regional distribution

From:

Every megawatt of new fixed offshore wind in AR6 went to English projects (Hornsea 4 and East Anglia Two). Scottish offshore wind was entirely in the Permitted Reduction category (Inch Cape A/B, Moray West String 9) plus Green Volt's 400 MW of floating. Wales received no offshore wind awards — a reflection of the AR6 Pot 3 pipeline at the time, not of the Crown Estate Round 5 Celtic Sea leasing round which was concluded subsequently and will feed future CfD rounds with Welsh floating projects.

11. Results — new fixed offshore wind (Pot 3)

New-capacity fixed offshore wind cleared at £58.87/MWh (2012 prices) for 3,363.07 MW of capacity across two projects, both commissioning in Delivery Year 2028/29:

Two key observations:

Concentration risk. Hornsea 4 alone represents 71% of new fixed offshore wind capacity in AR6 (2,400 / 3,363.07 MW). This is extreme concentration in a single project from a single developer. Post-award, when Ørsted cancelled Hornsea 4 in May 2025 (see §17), 71% of the AR6 new-OSW capacity disappeared from the pipeline overnight — demonstrating the fragility of relying on a small number of very large projects to meet capacity targets.

Phased delivery. East Anglia Two split its capacity into "Phase 1" for AR6 — a Phased Offshore Wind CfD Unit structure under. Subsequent phases of East Anglia Two may be bid into later Allocation Rounds, allowing the developer to stage both commissioning and capital commitment across multiple years and regulatory windows.

12. Results — Offshore Wind Permitted Reduction (Pot 3)

Permitted Reduction rebids cleared at £54.23/MWh (2012 prices) for 1,578.51 MW across four projects in Delivery Year 2027/28:

Seven contract lines across four underlying projects (Hornsea 3 used three phases, Inch Cape used two). All rebids originated from AR4 (2022), where they had cleared at £37.35/MWh (2012 prices) — meaning these projects recovered an additional £16.88/MWh of indexed subsidy (+45% on their AR4 strike price) by entering the Permitted Reduction category.

How Permitted Reduction works mechanically

A project that has already been awarded a CfD in an earlier round (here AR4) can, under the AR6 Allocation Framework, enter a new bid for a subset of its AR4 capacity in AR6. The mechanics are:

1. The developer surrenders a defined capacity from its existing AR4 CfD (which reduces the AR4 contract's Installed Capacity).
2. The same capacity is entered into AR6 as a Permitted Reduction bid, subject to the separate £800 m/year Pot 3 Maximum for Permitted Reduction.
3. If successful at the AR6 auction, the surrendered capacity receives the AR6 clearing price (£54.23/MWh) for a fresh 15-year term, rather than continuing under the AR4 £37.35/MWh contract.

Why developers chose this route: AR4 strike prices were set before the 2022 cost shock and left many projects sub-economic at £37.35/MWh. Rather than cancel altogether (and forfeit their AR4 CfD), developers took the partial-surrender-and-rebid route to lift their blended revenue. The "A/B/C" phasing on Hornsea 3 allowed Ørsted to commission one slice at a time, converting AR4 capacity into AR6 capacity at each phase.

Why the £54.23 vs £58.87 gap exists

Permitted Reduction bids had strong economic incentive to bid into the auction even at lower prices than new-capacity projects would accept — because Permitted Reduction projects had already made most of their sunk development costs and merely needed enough revenue to justify construction execution. New projects, by contrast, had to cover full development-stage risk in their bid. The two sub-categories also cleared in separate Maximum-specific auction stacks per Rule 18 of the Allocation Framework, so they did not directly compete — each sub-category cleared to its own Maximum-only clearing price. The £4.64/MWh gap (£58.87 − £54.23) is the difference in the marginal bid economics between the two populations.

13. Results — Floating offshore wind (Pot 2)

Floating offshore wind cleared at £139.93/MWh (2012 prices) for 400 MW — a single project — in Delivery Year 2028/29:

Green Volt is a milestone project: the first commercial-scale floating offshore wind project to win a CfD in the UK. It was developed under the INTOG (Innovation and Targeted Oil & Gas decarbonisation) leasing round run by Crown Estate Scotland in 2022, specifically to deliver low-carbon power to oil and gas platforms as well as to the grid. The project has a total planned capacity of 560 MW, of which 400 MW is CfD-subsidised; the balance is intended to serve platform electrification via direct connections outside the CfD framework.

Ownership context: Flotation Energy is owned by Tokyo Electric Power Company (TEPCO) following its 2022 acquisition. Vårgrønn is a joint venture between Eni Plenitude and HitecVision. Both are well-capitalised parents, which matters for financial close — a recurring risk for floating OW where commercial-scale financing is still maturing.

Price signal: £139.93/MWh (2012) — around £195/MWh in January 2024 real terms after CPI rebasing — is the first data point on what "commercial-scale floating offshore wind" actually costs via CfD in the UK. The Pot 2 Floating OW ASP of £176/MWh was a 52% uplift from AR5's £116/MWh, and Green Volt cleared at a 20.5% saving against the uplifted ASP. The clearing price is materially higher than AR6 fixed OW (£58.87 new / £54.23 rebid) — roughly 2.4× as expensive — reflecting floating OW's higher capex, smaller supply chain, and pre-commercial deployment maturity.

14. Clearing prices — analysis

Consolidated AR6 clearing prices vs ASPs:

Several analytical takeaways:

Tidal Stream had the largest saving at 34.1%. This is consistent with the ringfenced £15 m Minimum plus a small, competitive group of eligible tidal projects — Minima push clearing prices down because the Delivery Body must award until the Minimum is satisfied, and with few bidders this tends to drive competitive bidding. (The 28 MW cleared split across two Delivery Years at identical £172/MWh also suggests tiebreak/consolidation mechanics operated.)

Onshore wind, solar, new OW, and floating OW all cleared at ~18–21% below ASP — a tight cluster that suggests DESNZ calibrated the ASPs consistently across technologies based on a consistent methodology (likely the 2012-prices ASP methodology DESNZ publishes ahead of each round, incorporating expected cost-of-energy estimates and a reserve margin). A ~20% ASP-to-clearing saving band is the pattern AR6 broadly delivered for mature-to-near-mature technologies.

Permitted Reduction cleared further below ASP (25.71%) than new OW (19.36%). The £4.64/MWh gap between the two Pot 3 clearing prices is the cleanest available read of the "rebid discount" — roughly a 6.3% discount on the new-OW clearing price. Rebid economics genuinely are different from new-build economics.

Comparison to wholesale prices: converting £58.87/MWh (2012) using the ~1.40 CPI inflator to January 2024 terms gives ~£82/MWh in 2024 prices for new offshore wind. Contemporary UK day-ahead wholesale prices ranged £60–£90/MWh during most of 2024. A CfD at £82/MWh (real) is therefore delivering a modest top-up over average wholesale prices in normal conditions — and very substantial downside protection when prices drop. For developers, it locks in project economics at a level that was commercially unviable during the 2023 cost shock but is clearly bankable post-2024.

The "record saving" framing

DESNZ's coverage of the results emphasised the ~20% saving-vs-ASP on offshore wind and presented AR6 as a "successful competitive outcome". The more useful comparator is AR4 versus AR6: AR4 cleared fixed offshore wind at £37.35/MWh (2012), AR6 at £58.87/MWh for new capacity — a +57.6% increase in the real-terms price of new UK offshore wind over two years. This is the true headline finding of AR6, not the 19.36% ASP saving. The "saving" language compares bids to the administrative ceiling; the year-on-year price movement compares what offshore wind actually costs now versus two years ago, and it is firmly upward.

15. Unsuccessful / notable absences

The AR6 results document does not publish the list of unsuccessful applicants or their bid details — NESO maintains commercial confidentiality over losing bids. What can be inferred:

1. ~2/3 of Pot 3 applications by valuation did not clear (see §10.1). This represents the largest pool of unsuccessful bids by value. The specific projects that did not win are not publicly disclosed by NESO.
2. Dogger Bank D (capacity cap ~2.4 GW, SSE / Equinor / Vårgrønn) did not participate in AR6 at all. At the time of AR6 application, Dogger Bank D was at an earlier consenting stage than was required for CfD eligibility, and developer commentary indicated a target of AR7 or later.
3. Outer Dowsing (1.5 GW, Corio Generation / TotalEnergies / Gulf Energy Development) likewise was not publicly reported as winning in AR6 and appears to have targeted later rounds.
4. Scottish ScotWind projects — the 2022 ScotWind leasing round awarded ~25 GW of seabed rights for new offshore wind, but most of these projects were too early in consenting to qualify for AR6. ScotWind-linked projects are expected to feed AR8–AR10.

A systematic list of known-not-awarded projects would require cross-referencing the results doc against a project pipeline database — exactly the kind of analysis the AgentZero projects collection is designed to support, once AR6 winners and losers are both recorded against each project.

16. Contract obligations beyond the core mechanics

Section 5 covered the core financial mechanics of a CfD. Section 16 covers the non-financial obligations the Generator takes on — the commitments that make a CfD enforceable and that determine whether a project actually gets built.

16.1 Project Commitments AND Supply Chain Implementation Statement — two distinct mechanisms

AR6 uses two separate contract mechanisms to enforce the approved Supply Chain Plan — they were conflated in the earlier draft and need to be kept apart:

1. Project Commitments per Generic Agreement §5.7 + Annex 5 (Parts A and B). These are the binding contents of the approved SCP (local content targets, training apprenticeships, commitments to use UK factories for specific components). Per Standard Terms Condition 4.1(B), fulfilment of Project Commitments is one of the routes by which the Generator can satisfy the Milestone Requirement (alongside meeting the Generator's Milestone via construction progress evidence). Project Commitments thus live in the Initial Milestone machinery, not in the Operational Conditions Precedent machinery.
2. Supply Chain Implementation Statement per Standard Terms Schedule 1 Part B paragraph 2.1(G). This is a separate Operational Condition Precedent that the Generator must obtain before the Longstop Date for any project ≥300 MW (and for all Floating Offshore Wind regardless of size). The SCIS is a document issued by DESNZ confirming that supply chain commitments have been implemented, and obtaining it is a condition of the CfD continuing past the OCP deadline.

The SCP guidance confirms the headline penalty principle: "If the Generator does not fulfil an OCP by the end of the CfD Target Commissioning Window, then their 15-year CfD payment term will be reduced" — but the operative OCP in the SCP context is the Supply Chain Implementation Statement, not the Project Commitments. Conflating Annex 5 Project Commitments with OCPs (as the earlier draft did) loses this distinction. In short: Project Commitments = Milestone Requirement route; SCIS = Operational Condition Precedent. Both enforce the SCP but at different stages of the contract's lifecycle.

16.2 Milestone Delivery

The Initial Milestone Delivery Date is 18 months after the CfD Agreement Date (per the agreement-specific drafting rather than a numbered clause in the Standard Terms; my earlier draft's §5.5 citation was imprecise). Before this date, the Generator must demonstrate sufficient progress on construction and contracting — typically including signed supply contracts and evidence of site preparation, OR (per Condition 4.1(B)) fulfilment of Project Commitments from Annex 5. Failure triggers a Milestone Delivery Failure, which is a termination trigger unless the Generator can invoke one of the exhaustive listed extension grounds in the Standard Terms definitions of "Target Commissioning Window" and "Longstop Date": (A) Force Majeure; (B) delay by a Transmission System Operator, Transmission Licensee, Licensed Distributor or OFTO in required system reinforcement or connection works; and (C) for Offshore Wind and Onshore Wind only, MoD non-confirmation of suitable mitigation measures under a Radar Mitigation Scheme Agreement. Judicial review of planning consents is NOT in the TCW/Longstop extension list (it appears in the Foreseeable Change in Law definition instead), and Qualifying Change in Law (QCiL) events drive Strike Price adjustments via the separate Change in Law compensation machinery, not TCW/Longstop extensions — my earlier draft listed both of these as extension grounds, which is wrong.

16.3 Longstop and Operational CPs

All Operational Conditions Precedent must be fulfilled before the Longstop Date — which is the last day of the Longstop Period after the end of the Target Commissioning Window. OCPs include: facility commissioning, metering approval, grid connection energisation, and the Supply Chain Implementation Statement per Standard Terms Schedule 1 Part B paragraph 2.1(G) (applicable to projects ≥300 MW and to all Floating Offshore Wind regardless of size). Project Commitments from Annex 5 of the Generic Agreement are NOT themselves Operational Conditions Precedent — they sit in the Milestone Requirement machinery per Generic Agreement §5.7 + Standard Terms Condition 4.1(B), which allows the Generator to satisfy the Milestone Requirement by evidencing compliance with or fulfilment of those Project Commitments. The SCP enforcement path is bifurcated: (a) Project Commitments → Milestone Requirement route (Condition 4.1(B)); (b) Supply Chain Implementation Statement → Operational Condition Precedent route (Schedule 1 Part B paragraph 2.1(G)). If OCPs are not met, the CfD can be terminated by LCCC.

16.4 Metering, curtailment, change in law

Three more classes of obligation that shape operational life under the contract:

• Metering: the Generator must maintain Facility Metering Equipment to LCCC's specifications, provide a Metering Remediation Plan within 15 Business Days of any breach, and permit CfD Counterparty inspection rights.
• Curtailment rules: if the Facility is curtailed (e.g. by the System Operator for network constraint reasons), the CfD has specific rules about what happens to payments — broadly, curtailed output that would otherwise have been generated is treated in accordance with Condition 11 (Curtailment), with a framework for compensating the Generator where appropriate.
• Change in Law: the Strike Price is adjustable for Qualifying Changes in Law (QCiL) via a defined Strike Price Adjustment formula. The Generator can claim costs passing the QCiL threshold via a Generator QCiL Notice; LCCC responds via a QCiL Response Notice. This is a key protection against regulatory risk over 15 years.
• Generation Tax: if a generation tax is introduced, the T&Cs contain a Generation Tax Strike Price Adjustment formula — the Generator is compensated for the tax via a strike price uplift. (This provision was introduced after the Electricity Generator Levy and similar windfall tax discussions.)

16.5 Termination

LCCC has termination rights under Condition 51 for specified Generator defaults (failed Milestones, failed OCPs, unpaid amounts, insolvency, breach of Project Commitments, etc.). Generators have limited termination rights — primarily under Qualifying Change in Law events that fundamentally alter project economics. Termination payments depend on the specific trigger and are fact-sensitive; the default is that no termination payment flows in either direction on normal expiry.

17. Post-award fate — what has actually happened

AR6 results were published on 3 September 2024. By the time this writeup is being drafted (April 2026), ~19 months have elapsed since award, and the early project trajectories are already visible.

17.1 Hornsea 4 — discontinued (7 May 2025)

The single largest AR6 award was Hornsea 4: 2,400 MW at £58.87/MWh, Delivery Year 2028/29. Ørsted announced its discontinuation eight months after the award, in Company Announcement No. 09 2025 dated 7 May 2025. The full text is preserved in the source docs; the essential content:

• Decision: Ørsted will "stop further spend on the project at this time and terminate the project's supply chain contracts, meaning that Ørsted will not deliver Hornsea 4 under the CfD awarded in AR6".
• Stated reasons: "continued increase of supply chain costs, higher interest rates, and an increase in the risk to construct and operate Hornsea 4 on the planned timeline for a project of this scale... these developments have increased the execution risk and deteriorated the value creation of the project".
• Timing: "well ahead of the planned Final Investment Decision later this year" — the decision was taken before FID, meaning Ørsted had not yet formally committed the full project capital. CEO Rasmus Errboe stated: "We've been maturing the project over the past nine months..." — confirming the 9-month elapsed time between September 2024 award and May 2025 cancellation.
• Financial impact: DKK 3.5–4.5 bn in 2025 breakaway costs, of which DKK 3.0–3.5 bn affects guided EBITDA, plus a further DKK 0.5–1.0 bn of capitalised construction cost write-downs below EBITDA. Ørsted's 2025 EBITDA guidance (£25–28 bn) and gross investment guidance (DKK 50–54 bn) remained unchanged despite the loss.
• Retained rights: Ørsted keeps the Hornsea 4 seabed rights, grid connection agreement, and Development Consent Order. The project will be "re-evaluated" for future development "in a way that is more value-creating for us and our shareholders" — code for: waiting for a higher CfD price in a later round.

Scale of the impact on AR6: Hornsea 4 was 71% of new fixed OSW capacity and 48.6% of total fixed OSW capacity (new + Permitted Reduction) awarded in AR6. Its cancellation erases roughly half of the fixed offshore wind volume that AR6 was publicly credited with securing — in effect, turning AR6 back into a ~2.5 GW fixed OSW round rather than a 4.9 GW one. It is the single most consequential post-award fate event in UK CfD history.

Government response: DESNZ did not announce any punitive action or CfD termination. The contract structure (cancellation before FID, before Initial Milestone) meant Ørsted did not trigger contractual penalties beyond the loss of the CfD award itself. The episode fed directly into the AR7 reforms (20-year contracts, higher ASPs, further de-risking measures for bidders) that DESNZ announced in July 2025.

17.2 Inch Cape — financial close and execution phase

Inch Cape Offshore Wind Farm (Inch Cape Offshore Limited, ESB + Red Rock Renewables) moved rapidly in the opposite direction. The project secured AR6 Permitted Reduction top-up awards of 266.11 MW total (177.41 MW + 88.70 MW) at £54.23/MWh, on top of its existing AR4 CfD. Subsequent milestones:

• 28 January 2025: Inch Cape announced £3.5 billion in financing for construction.
• June 2025: Inch Cape entered the execution phase. Forth Ports was announced as Principal Contractor with responsibility for offshore construction compliance. Chinese jacket foundations for 15 MW wind turbines began arriving at Scottish ports in early 2026.
• Project detail: 1.08 GW installed capacity (includes capacity from AR4 and AR6 awards combined), Cambo Ness location in the North Sea off the Angus coast, targeting commissioning in late 2020s.

Inch Cape is the counter-narrative to Hornsea 4: the same AR6 round produced an award that a fully-committed developer used to unlock £3.5 bn of construction capital within four months of award. The lesson is that AR6 awards worked as intended when the underlying project was already mature and the developer was committed; they failed when the developer had optionality to walk away.

17.3 Hornsea 3, East Anglia Two, East Anglia Three, Moray West, Green Volt — status

At the time of writing the post-award status of the remaining AR6 offshore wind awards is less crisp in public sources and would benefit from targeted verification before the writeup is finalised. Indicative status summary:

• Hornsea Project Three (Ørsted, 1,080 MW AR6 Permitted Reduction split into A/B/C): proceeding through construction; Ørsted retained the AR6 Permitted Reduction awards despite cancelling Hornsea 4. Different risk profile because Hornsea 3 was further along in construction commitment at the time of Hornsea 4's cancellation.
• East Anglia Two Phase 1 (ScottishPower Renewables / Iberdrola, 963.07 MW new Pot 3): financial close anticipated but not yet announced as of writing.
• East Anglia Three B (EA3B) (ScottishPower Renewables, 158.90 MW Permitted Reduction): proceeding; construction already well underway under the AR4 base contract.
• Moray Offshore Windfarm (West) String 9 (Ocean Winds — EDPR / ENGIE, 73.50 MW Permitted Reduction): proceeding; Moray West was already in construction at AR6 award time.
• Green Volt (Flotation Energy / Vårgrønn, 400 MW floating): targeting delivery in 2028/29 per AR6 commitment; project delivery phase was reported as starting in 2025; financial close trajectory reportedly cooled in late 2025 when CNOOC (a potential equity partner for Vårgrønn parent Eni) did not proceed.

For the "current status" section of a live auction page, these would be data-driven fields joining to the relevant project records in the AgentZero projects collection, updated as news is ingested via the content-intelligence pipeline.

18. Retrospective — the AR5 → AR6 → AR7 arc

AR6 only makes sense as the middle chapter of a three-round narrative.

18.1 AR5 (September 2023) — the zero round

AR5 secured zero offshore wind bids. The Pot 3 Administrative Strike Price had been set at £44/MWh (2012 prices) based on a methodology that under-weighted the post-2022 cost inflation, interest rate cycle, and turbine supply chain constraints. In the event, no qualifying applicant chose to submit. It was the first time a major CfD round had produced no offshore wind award, and it was publicly recognised — by government, developers, industry bodies, and analysts — as a calibration error rather than a failure of the auction mechanism itself.

The immediate consequences:

1. A ~12 GW gap opened between expected 2030 offshore wind capacity and the 50 GW target, because AR5 was the round that was supposed to contract the capacity delivering in 2027/28 operational years.
2. DESNZ committed publicly to a recalibration of Pot 3 for AR6 — the £73/MWh ASP (up 66%) was the direct result.
3. The Pot 3 structure was retained (introduced in AR5 for the first time to ringfence offshore wind from cheaper technologies) because the failure was not attributed to pot structure.
4. The Permitted Reduction category was formally introduced for AR6 to allow AR4 winners to surrender and rebid capacity — acknowledging that not just AR5 but also AR4 pricing had become unviable given post-2022 cost inflation.

18.2 AR6 (September 2024) — the "recovery" round

AR6 delivered on the recovery narrative: 5,341 MW of offshore wind awarded, strong competition (clearing prices ~19–26% below ASPs), a budget increase that fully absorbed a large valid pipeline, and participation across the UK's major offshore wind developers (Ørsted, ScottishPower/Iberdrola, ESB/Red Rock Renewables, Ocean Winds/EDPR/ENGIE, Flotation Energy/Vårgrønn). At the moment of publication on 3 September 2024, AR6 was universally reported as a success and a convincing reset from the AR5 failure.

But the Hornsea 4 cancellation eight months later fundamentally changed the retrospective view. Approximately half of the fixed offshore wind capacity awarded in AR6 was effectively withdrawn when a single developer recalculated its project economics and decided the £58.87/MWh price was insufficient to justify proceeding under 2025 cost and financing conditions. The recovery narrative held for Permitted Reduction projects (where the underlying projects were already committed and needed the price uplift to finish building) but did not hold for new-build capacity at the scale AR6 was supposed to deliver.

This distinction — AR6 was a successful round for already-committed projects and an unsuccessful round for new-build at scale — is the single most important lesson for interpreting AR6 and for understanding why AR7 needed further reform rather than a repeat of AR6 mechanics.

18.3 AR7 (August 2025 open, January 2026 results) — the re-pricing round

Informed by the post-AR6 events and by extensive consultation with industry through early 2025, DESNZ announced further CfD reforms in July 2025 and opened AR7 in August 2025. Key changes:

1. Contract length extended from 15 to 20 years for fixed-bottom and floating offshore wind (and onshore wind, and repowering). This lowers the weighted cost of capital for a given strike price and should reduce required bids.
2. Higher Administrative Strike Prices reflecting 2024-25 cost data.
3. Reformed budget publication process — the budget-secrecy mechanics changed to de-risk round outcomes for fixed-bottom offshore wind specifically.
4. Initial Pot 3 budget proposal: £900 m for fixed-bottom offshore wind and £180 m for floating offshore wind, for a total of ~£1.08 bn — lower than the revised AR6 Pot 3 figure of £1.1 bn. Industry (RenewableUK, Energy UK) publicly pushed back that the budget was insufficient to meet the 50 GW target and urged DESNZ to uplift.
5. Subsidy Advice Unit review by the CMA (October 2025) added a formal advisory layer to the AR7 scheme design.

The AR7 results were published around January 2026 (per Energy UK and OEUK coverage). Headline numbers (per Carbon Brief analysis):

• ~8.4 GW of offshore wind awarded in total — substantially more than AR6 by capacity.
• Clearing price around £91/MWh for fixed offshore wind in some categories — ~10% higher than AR6's £58.87/MWh equivalent (though direct comparison is complicated by the 20-year vs 15-year contract term, which affects what strike price a bidder needs).

The AR7 headline is therefore: more capacity secured, at a higher price, with a longer contract. The market reset its expectations during 2025, and AR7 is what a post-Hornsea-4 CfD round looks like when developers have repriced their required returns and DESNZ has repriced its willingness to pay.

18.4 The meta-pattern

Looking across AR5, AR6, and AR7 together, the CfD scheme is behaving as intended — it is a price discovery mechanism. AR5 discovered that £44/MWh was below the market clearing price; AR6 discovered that £58.87/MWh cleared but was insufficient for new-build commitment; AR7 discovered that ~£91/MWh with 20-year contracts cleared and (probably) is sufficient for commitment. The auction mechanism itself — sealed bids, pay-as-clear, Maxima/Minima, Permitted Reduction — worked well across all three rounds; the variability was in ASP calibration and contract term length, both of which are administrative inputs rather than auction design features.

For AgentZero's analytics surface, this three-round arc is the kind of comparative story users will want to see. The data model needs to support: AR5 ↔ AR6 ↔ AR7 comparison on a single timeline (ASP, clearing price, awarded capacity, contract term, rule changes), with project-level drill-downs showing which winners from each round proceeded to construction vs cancelled. This is not achievable from narrative writeups — it requires the structured data model that §20 specifies.