UK CfD Allocation Round 7 (AR7)Reassessing the Results in the Offshore Wind Sector

in Japanese

(originally published in Japanese on 19 February 2026)

On 14 January 2026, the results of the United Kingdom’s 7th Contracts for Difference (CfD) Allocation Round (AR7) were announced, securing a record-breaking 8.4 GW of offshore wind capacity. This article reviews the structure of the UK offshore wind auction system, examines the policy and market developments leading up to AR7, and considers the broader implications of the latest auction outcome.

Overview of the UK Offshore Wind Allocation Framework

Unlike Japan’s system, offshore wind development in the UK proceeds through a two-stage process: first, the acquisition of seabed development rights, and second, participation in the CfD auction¹.

Stage One: Securing Seabed Development Rights

Developers must initially participate in seabed option auctions administered by The Crown Estate (England and Wales) or The Crown Estate Scotland. Successful bidders obtain exclusive rights to develop projects within designated offshore zones.

At this stage, however, developers do not yet hold a full lease. Instead, they secure an option agreement, allowing them to conduct site investigations, environmental assessments, and permitting activities while paying annual option fees. Only after obtaining the necessary approvals can a formal seabed lease be executed, with lease payments structured separately as a percentage of project revenues².

Recent leasing rounds include Round 4 (2023), Round 5 (2025), and Scotland’s ScotWind process (2022).

Stage Two: The CfD Auction

Once project development has sufficiently progressed and a path to project feasibility becomes clearer, developers may enter the government-run CfD Allocation Round.

Introduced in 2014, the CfD mechanism stabilizes renewable energy revenues by compensating generators for the difference between wholesale electricity prices and a contractually agreed strike price over a 20-year period. Strike prices are determined through a reverse auction, capped by a government-set Administrative Strike Price (ASP).

Because CfD contracts provide long-term revenue certainty, it often represents a necessary milestone in the development of the project. Without a CfD, electricity must be sold at market prices, exposing projects to price volatility, significantly increasing financial risk.

The importance of CfD can be seen in the case of EnBW’s Morgan project³, which was discontinued immediately after failing to secure a CfD in AR7.

From CfD Award to Final Investment Decision

After securing a CfD and fulfilling permitting requirements, developers finalize financing arrangements and construction contracts before reaching final investment decision (FID). Around the same time, a formal seabed lease is signed with The Crown Estate or The Crown Estate Scotland, effectively confirming project realization. Yet even after a successful auction outcome, projects remain vulnerable. Rising costs or regulatory delays may still prevent projects from reaching FID—as demonstrated by Orsted’s Hornsea 4 project. Hornsea 4 was awarded a CfD in AR6 but it was still discontinued in May 2025 due to deteriorating market conditions⁴.

Timing Gap Between Leasing and CfD Awards

A critical point of the UK system is the substantial time lag between seabed option auction and CfD auction. Industry practice suggests that 5 to 7 years typically elapse between securing development rights and winning a CfD.

For example, Awel y Môr⁵ —originally securing seabed lease in 2020 under extension program (separate from public seabed leasing round), not public auction—required roughly six years of development before successfully securing support in AR7.

Meanwhile, none of the 19 ScotWind projects awarded options in 2022 were successful in AR7. With only four years of development progress, perhaps many were simply not mature enough to compete.

Market Conditions Leading Up to AR7

The twelve months preceding AR7 were particularly challenging for Europe’s offshore wind sector. Auctions in Denmark⁶, Germany⁷, and the Netherlands⁸ all concluded without successful bids. The UK itself faced setbacks: AR5 produced no winners, while AR6’s sole new project, Hornsea 4⁹ , was later cancelled—raising concerns over the government’s 2030 offshore wind target of 43–50 GW¹⁰.

Compounding these concerns, the initial AR7 budget allocation of £900 million was widely viewed as insufficient to compensate for earlier shortfalls.

During the auction period, however, the government nearly doubled the available budget to £1.79 billion through ministerial authority¹¹. This adjustment enabled both higher strike prices and an extension of CfD contract duration from 15 to 20 years—ultimately unlocking the record 8.4 GW award.

Combined with 16 GW already operational and 11.5 GW¹²under construction, the UK’s 2030 target once again appears within reach.

3 Key Policy Changes in AR7

1. Expanded Budget: Funding for fixed-bottom offshore wind nearly doubled, allowing significantly larger capacity awards.
2. Higher Administrative Strike Price: The ASP increased by approximately 10% compared with AR6, reflecting inflationary pressure across materials, financing, and supply chains.
3. Extension of Contract Duration: The CfD term was extended from 15 to 20 years, improving debt repayment profiles and strengthening project bankability.

Together, these measures restored investor confidence and improved the likelihood of projects reaching FID.

Figure 1: UK CfD Auction (2012 Price)

Chart 2: CfD Rounds (2024 real price base)

AR7 Results¹⁴

AR7 delivered a combined 8.4 GW across fixed-bottom and floating offshore wind—marking the largest allocation in the scheme’s history.

Table 1: AR7 Results

Fixed Bottom Offshore Wind

A total of 8.25 GW was awarded. Most notably, RWE secured approximately 6.9 GW—over 80% of total capacity.

Awarded Fixed Bottom Projects

RWE
RWE won bids for five fixed-bottom projects, totaling 6.9 GW, at a strike price of £91.20/MWh (2024 price).¹⁵

1. Norfolk Vanguard East & West (total: 3.1 GW): This project was purchased and developed by RWE after the exit of Vattenfall, but now with KKR's investment, making it 50 : 50¹⁶ partnerships.
2. Dogger Bank South East & West (3.0 GW total): Developed in partnership with Masdar (49%)¹⁷.
3. Awel y Môr (Wales) (775 MW): Ownership configuration RWE (60%), Stadtwerke München (30%) and Siemens (10%)¹⁸won the bid.

SSE
SSE secured 1.4 GW for Berwick Bank Phase B at a strike price of £89.49/MWh¹⁹. The broader Berwick Bank project has a total potential capacity of up to 4 GW, meaning additional phases are likely to be submitted in future CfD rounds.

The fact that only two companies captured the full 8.25 GW awarded in fixed-bottom offshore wind speaks volumes about the sector’s structural realities.

First, navigating today’s risk landscape requires either a robust balance sheet or a powerful financial partner. Second, mitigating construction and execution risk demands deep offshore wind experience and seasoned internal teams. Third, negotiating effectively within a strained global supply chain increasingly depends on scale.

In short, offshore wind has become an endurance test of capital strength, operational depth, and strategic leverage.

Floating Offshore Wind

In the floating segment, two projects secured CfDs at a strike price of £216.46/MWh. Both are under 100 MW in size—representing that these are still stepping-stone projects rather than full commercial-scale developments. The pricing reflects this pre-commercial stage.

Awarded Floating Projects

• Pentland Floating Offshore Wind (Scotland): Developed by Copenhagen Infrastructure Partners (CIP) in partnership with Eurus Energy and Hexicon, the project also secured additional investment in November 2025 from the UK’s National Wealth Fund (formerly the UK Infrastructure Bank), Great British Energy, and the Scottish National Investment Bank²⁰.
• Erebus (Wales): Owned by Blue Gem Wind, a joint venture between TotalEnergies and Simply Blue Energy, it is under development in the Celtic Sea.

Interpreting the AR7 Results

Developers’ hurdle rates have been trending upward, and with sustained cost inflation, the profitability of AR7-winning projects remains far from guaranteed.

Transmission charges in the UK are distance-based, meaning projects located far from demand centers—such as those in central and southern England—face higher grid costs. That imbalance remains unresolved. Hence, Scotland, blessed with excellent wind resources, continues to face structural disadvantages in CfD auctions.

Even with 8.4 GW awarded, some in the industry question whether the UK’s 2030 targets are fully realistic. Securing capacity at auction is only the first milestone; delivering projects to FID and construction is the true test.

Regional Perspectives

Scotland

• ScotWind: 4 years have passed since the 2022 ScotWind leasing round, yet none of the 19 awarded projects secured a CfD in AR7. While Berwick Bank (fixed-bottom) and Pentland (floating) are located in Scottish waters, neither originates from ScotWind. With over 60% of ScotWind capacity planned as floating wind, longer development timelines are inevitable. Still, the absence of ScotWind winners in AR7 highlights the development maturity gap.
• Transmission charge: It remains a central challenge. Projects in Scotland face higher grid costs due to their distance from high-demand regions. Because offshore wind construction generates significant regional economic benefits, the Scottish Government has expressed concern that AR7 may further widen regional disparities²¹. A particularly notable case is West of Orkney (2 GW)²², developed by Corio Generation, TotalEnergies, and RIDG. Despite being one of the earliest ScotWind projects to secure consent, it did not win a CfD in AR7. Recent statements indicate that unless transmission charging inequalities are addressed, development will not proceed²³.

Figure 3: Grid Charge by UK Region

Wales

In Wales, both Mona and Morgan—Irish Sea projects originating from the 2021 Round 4 leasing process—failed to secure CfDs in AR7.

*For non-winning and non-bidding projects, please refer to the end.

Final Comments on AR7

1. The five-year extension: CfD term increase from 15 to 20 years was a decisive factor in AR7’s success. A longer revenue horizon improves debt coverage ratios, lowers annual repayment burdens, and can enhance project IRR by 1–2 percentage points. That improvement materially increases the probability of reaching FID.
2. Mid-Auction Budget Increase: The government’s decision to raise the budget during the auction echoes a similar adjustment in AR6²⁵. While effective in ensuring auction success, repeated post-launch budget increases risk distorting bidder behavior. Developers may begin to anticipate upward revisions, weakening confidence in announced budget ceilings.
3. Slow Consenting and Permitting: Entry requirements for AR7 were eased compared to prior rounds, allowing projects at earlier permitting stages to participate. While this addressed longstanding concerns over the UK’s slow planning processes, it effectively shifts—rather than eliminates—permitting risk. For example, RWE’s Dogger Bank South project secured a CfD, yet its government consent decision was postponed by three months from 10 January 2026 to 30 April 2026²⁶. Similarly, North Falls (developed by SSE and RWE) also experienced delay from 15 January 2026 to 28 April 2026²⁷. Awarded capacity does not eliminate regulatory uncertainty.
4. Project Concentration: Greater concentration improves execution certainty but increases systemic risk²⁸. With a large share of 2030 capacity dependent on a small number of major projects, any delay or cancellation could have large market consequences.
5. Cost Pressures: Offshore wind remains capital-intensive and heavily exposed to steel prices, turbine costs, and macroeconomic volatility. Additional environmental regulatory requirements may further increase costs. The era of steady cost decline has given way to a more complex reality requiring rigorous internal project management.
6. Financing Capacity: Large-scale infrastructure expertise—often provided by financial partners such as KKR—has become essential. With strike prices around £91/MWh and 20-year contracts, project IRRs may sit in the high single digits. Whether this meets rising developer hurdle rates is an open question. As a matter of fact, RWE increased its hurdle rate from 8% to 8.5% in March 2025²⁹. Similarly, SSE raised its from 11% to 12% in May 2025³⁰. RWE is targeting FID this summer; SSE aims for 2027³¹.
7. Clean Industry Bonus (CIB)³² : Introduced in AR7, the Clean Industry Bonus incentivizes domestic supply chain investment. Projects that meet defined investment commitments receive a separate payment independent of the strike price; however, failure to deliver results in penalties. The government estimates that AR7 will drive approximately £3 billion of investment into UK ports and manufacturing through the CIB mechanism³³.
8. Floating Wind Still at Stepping-Stone Phase: Compared to AR6’s 400 MW Green Volt project, AR7’s floating awards—Erebus (92.5 MW) and Pentland (100 MW)—are smaller. While strike prices have risen modestly in real terms, floating wind remains in a preparatory stage focused on technology validation and supply chain development. Scotland and Wales both secured floating projects, laying groundwork for future industrial capacity. However, with projects still small and geographically dispersed, cost reduction through scale and synergy remains some distance away.

Implications for Japan

1. Bankability Matters More Than Targets: The UK’s experience underscores that ambitious capacity targets mean little without revenue certainty. Japan’s offshore wind market must likewise prioritize financeable frameworks.

2. Scale and Certainty Are Essential for Supply Chain Growth: Even in a mature market like the UK, domestic supply chains require dedicated support mechanisms such as the CIB. If offshore wind is to become a core industrial pillar rather than merely a power generation segment, Japan will need comparable large-scale industrial policy support.

3. Developer Concentration: AR7 confirms that offshore wind is increasingly balance-sheet driven. Japanese consortia must ensure that a clear lead developer with execution capacity carries responsibility through to FID.

4. Transmission and Regional Planning: Strong wind resources alone are insufficient. Grid connection feasibility—and in the UK’s case, transmission charging structures—can determine project viability. Transmission planning and site designation must advance in parallel.

5. Overseas Experience of Japanese Firms: Japanese companies have accumulated valuable experience in the UK over the past decade. While Sumitomo did not secure an award this time, and Eurus Energy participates in the successful Pentland project, the question now is how that accumulated expertise can be translated into Japan’s domestic market.

Conclusion

AR7 marks a strategic reset for UK offshore wind policy. By recalibrating contract structures to reflect present-day cost realities, the government successfully reactivated a stalled market.

Yet the results also illuminate structural tensions: intense price competition, growing developer concentration, regional imbalances, and the long road ahead for floating wind commercialization.

For projects still without market access, AR8 will be critical. Since achieving national targets will require sustained capacity growth, both the policymakers and the market need to remain flexible and adaptable to new conditions.

If AR7 delivers one lesson for Japan, it is this: flexibility and adaptability, not ambition alone, determine whether offshore wind policy ultimately succeeds.
 

*Reference: Unsuccessful and Non-Participating Projects 34 Despite a substantial number of advanced projects meeting the eligibility requirements for AR7, the final list of successful bidders was strikingly narrow. The outcome reflects not only the intensity of competition, but also deeper structural factors—ranging from electricity market design to regional disparities—that shape auction results behind the scenes. EnBW / JERA Nex BP: EnBW and bp jointly secured the Irish Sea projects Mona and Morgan in the 2021 Round 4 seabed option auction35, submitting the highest bids at the time36. However, after failing to secure CfDs in AR7, they announced their withdrawal from both projects. Mona is to be sold to JERA Nex BP37, while Morgan has been formally discontinued. EDF: EDF Renewables did not secure a CfD for the floating wind project Blyth Phase 2 and has subsequently announced its exit from the development38.  Equinor: Expansion phases of existing projects such as Sheringham and Dudgeon—which would be expected to benefit from lower costs compared with greenfield developments—also failed to secure awards. ScottishPower Renewables (Iberdrola): East Anglia One North, one of the larger anticipated contenders, did not appear among the winning projects. Sumitomo Corporation: Sumitomo holds a 20.38% stake in the RWE-led Five Estuaries consortium39 (RWE 33.33%, Macquarie Asset Management 25%, ESB 20.83%). Although positioned as an extension project, it too did not secure a CfD. Orsted: Although Orsted had secured a CfD for Hornsea 4 in AR6, it later announced the project’s cancellation. Under CfD rules, a contract default results in exclusion from participation in the subsequent two allocation rounds40.