Global offshore wind: UK

Focus on UK: Market overview

The UK remains a world leader in offshore wind, accounting for roughly 20 percent of global offshore wind capacity, with 11.3 GW operational. It is forecast that installed capacity will rise to 19.5 GW by mid 2020s. The UK Government has consistently signaled its continuing intention to bring forward more offshore wind. The Offshore Wind Sector Deal signed in 2019 targeted 30 GW by 2030. However, the government has subsequently pledged to increase ambition to 50 GW by 2030 to meet the target for net-zero greenhouse gas emissions by 2050 under the Climate Change Act 2008. Scenarios published by the Committee on Climate Change estimate that at least 75 GW of offshore wind could be needed to meet this target. The size of projects is increasing, enabling economies of scale to be captured. The table and map below provide an overview of operational, construction and consented projects.

UK: Development process overview (England & Wales)

UK: New Leasing opportunities

Round 4 Offshore Wind Leasing 

As managers of the seabed around England, Wales and Northern Ireland, The Crown Estate launched Round 4 of its Offshore Wind Leasing programme in September 2019. 8 GW of potential new offshore wind capacity has been made available across six projects.

The Round 4 pre-qualification phase (financial strength and technical competence) was followed by a two-part invitation to tender (ITT) phase. ITT Stage 1 assessed the specific project financial and technical assessments. Bidders then proposed their best Agreement for Lease (AfL) fee price (in £/MW/year) in ITT Stage 2. 

A nine-month habitats regulations assessment (HRA) followed, completing in April 2022. In January 2023, the Crown Estate announced it had signed AfL for six offshore wind projects which are expected to begin generating by 2030 and have the potential to generate 8 GW of renewable electricity.

• Daily bidding cycles: Projects awarded daily, aimed at increasing price and project location transparency.
• Cash and Caps: ITT2 bids assessed bidder cash availability and bidder caps (i.e. no more than 3 GW or three projects per bidder) and locational caps (i.e. no more than 3.5  GW in any bid region and no overlaps with earlier bids).
• No upfront premium: Ten-year AfLs granted with annual fees (rather than a ten-year premium), with a right to break at any time on or after the AfL second anniversary (subject to break fee).
• Deposit: Successful bidders to pay a one-year AfL fee deposit (non refundable including if the HRA or seabed activities means the project cannot proceed).
• Locational flexibility: Bidders could propose up to five primary project sites (with variants) across the Round 4 bidding areas.
• Larger minimum project sizes: 600 MW in Dogger Bank and 400 MW in other bidding areas (previously 300 MW) and lease terms of 60 years.
• Fewer development milestones: (i) development activity commenced within 18 months of the AfL (Geophysical or Ornithological surveys or EIA scoping) and (ii) consent application for the wind farm and export cable submitted within five years of the AfL.

In January 2022, Crown Estate Scotland offered 17 projects option agreements under its ScotWind programme, the first round of offshore wind leasing (OWL) in Scottish waters for a decade. A number of these sites plan to deploy the latest floating offshore wind technologies, signaling a significant step forward for the industry. For further information, please refer to the section on floating offshore wind.

UK: Support regimes and offtake

The primary support scheme for offshore wind in the UK is the Contract for Difference (CfD) scheme, which replaced the previous Renewables Obligation (RO) scheme.

The CfD scheme is, in essence, a power price hedge to pay or be paid the difference between a notional market reference price for electricity and a bid “strike price.” This can lead to the generator receiving payments from or having to make a payment to, the Low Carbon Contracts Company, which has been operational since 2014 and was designated as the CfD Counterparty under the Energy Act 2013. Generators sell power separately under a power purchase agreement (PPA).

Since the full implementation of the CfD regime, there have been five competitive auction rounds to award CfDs concluding in 2015, 2017, 2019, 2022 and 2023.

Allocation Round One, saw CfDs awarded to two offshore wind projects with a combined capacity of 1.16 GW at an average price of £117.14/MWh

Allocation Round Two saw 3.1 GW of offshore wind awarded CfDs, with prices ranging from £74.75/MWh for projects commissioning in the 2021/22 delivery year and reducing to £57.50/MWh for the 2022/23 delivery year.

Allocation Round Three saw 5.46 GWs of offshore wind offered CfDs. The round saw the first “zero monetary budget impact” bids, with strike prices below wholesale power prices at £39.65/MWh for delivery in 2023/24 and £41.611/MWh for delivery in 2024/251.

In Allocation Round Four, offshore wind was given its own separate pot of budget for the first time, resulting in almost 7 GWs of new offshore wind projects being awarded CfDs. The per unit price of offshore wind secured has continued to decline, with successful projects securing a strike price of £37.35 per MWh for delivery in 2026/27.  A capacity cap was also introduced to maintain competitive tension.

In Allocation Round 5, offshore wind sat in Pot 1, alongside solar and onshore wind.  For the first time since the inception of the CfD scheme, not a single megawatt of offshore wind secured government support under the CfD regime.  Whilst a disappointment for the sector, the outcome did not come as a surprise to many in the industry.

From March 2023, the UK government is increasing the frequency of CfD auctions to every year (rather than every two years).

In the UK and as evidenced by the outcome of Allocation Round 5, the prices available to projects under the government’s CfD regime appear insufficient to absorb the rising interest rates, supply chain constraints and spiraling inflation which are squeezing margins across the industry. Some developers appear to be reconsidering the attractiveness of investing in a fully CfD-backed project. The announcement in July 2023 that Vattenfall would not take an investment decision to proceed with the development of its Norfolk Boreas offshore wind project is one concerning example of the practical realities of the cost crisis facing the UK offshore wind sector. The culmination of rising costs of capital and up to 40% increases in supply chain costs have been cited by Vattenfall’s UK country manager as making the investment uneconomic, as CfD strike prices have failed to keep pace with the market. Given the growing economic uncertainty in the sector and the outcome of the CfD Allocation Round 5, the CfD will need to undergo further review and/or project sponsors need to consider alternative offtake strategies to substitute / supplement support under the CfD regime as market conditions continue to disrupt the sector.

In April 2023, the Government announced a call for evidence in relation to its plan to introduce non-price factors as part of the CfD assessment criteria and how such measures should be introduced. This development highlighted a re-prioritisation by Government beyond price-alone in order to ensure that other factors such as capacity, sustainability, innovation and system flexibility, are also being appropriately accounted for by the UK’s renewable energy project pipeline. The hope is that these changes could also potentially assist future projects to deal with the multitude of disruptive trends affecting offshore wind project development domestically and globally.

In November 2023, the Government released the strike prices for the sixth allocation round (AR6). The strike price for offshore wind projects is £73/MWh in 2012 prices, with the strike price set at £176/MWh in 2012 prices for floating offshore wind project to be delivered in the same period.

In setting these prices, for the first time ever, the Government comprehensively set out the methodology it used to determine the strike prices for the sixth allocation round (AR6) in a methodology note. The methodology note set out the Government’s objectives, approach and assumptions to setting strike prices. Chief among the factors considered were:

• technology specific factors such as capital and operating costs, financing costs as well as any build constraints;
• market conditions such as estimated wholesale electricity prices and the discount which generators may face when signing a Power Purchase Agreement (PPA); and
• policy considerations such as the statutory purpose of the scheme to encourage low carbon electricity generation and the need to have regard to meet Carbon Budget 6 (CB6) and Net Zero targets, the likely cost to consumers, and ensuring security of supply.

The Government has also introduced a risk premium for offshore wind technologies, applied as an addition to the hurdle rate. DESNZ believes that the combination of cost uncertainty, complex supply chains, lack of capacity and limited price discovery secured through AR5, as well as TNUoS uncertainty warrants a risk premium of 2% be added to the hurdle rates of fixed and floating offshore wind. Accordingly, the hurdle rate with the added risk premium is 9.8% for floating offshore wind and 8.33% for fixed offshore wind. The Government stated that this “… will allow room for future price movements until project costs are secured” and support the ambition for the strike price “… to act as a backstop for the auction rather than a significant constraint on participation”.

The Government also made some changes to the CfD standard terms and conditions and private network CfD agreement including:

• Making generators that directly supply offshore oil and gas facilities ineligible for AR6;
• Strengthening generators know your customer requirements; and
• Providing flexibility to the Milestone Delivery Date where a generator has not received confirmation from the Ministry of Defence of the availability of suitable mitigation measures in relation to interference between windfarms and air defence radar systems.

On 27 March 2024, AR6 was opened and it subsequently closed on 19 April 2024.  Technologies were grouped between 3 distinct pots, with Floating Offshore Wind comprising part of Pot 2 and all other Offshore Wind generally forming Pot 3.  In structuring Pot 3, the Government also acknowledged the fact that there was a mixture of projects bidding into AR6 and as such, Pot 3 was split between Offshore Wind Permitted Reduction projects and new Offshore Wind projects.  Offshore Wind Permitted Reduction projects are those who had secured a CfD in a previous allocation round; however, have since chosen to reduce the capacity under such CfD by up to 25% in order to permit that project to re-bid into AR6 owing to the economic limitations of the strike prices achieved in previous allocation rounds in the context of the current market environment.  We continue to eagerly await the outcome of AR6.

UK: Hot topics

Shared infrastructure and changes to Anticipatory Investment

Ever increasing cost pressures are incentivizing developers to identify new ways of developing projects in order to mitigate some of these cost burdens. This trend is being evidenced by developers absorbing operation and maintenance services, as well as by the proliferation of shared servicing “hubs” and other shared infrastructure platforms to support the construction, operation and maintenance of co-located projects.

Similarly, the UK Government is itself wary of the constraints imposed by the current approach to the development of offshore transmission infrastructure on the outlay of offshore wind capacity in light of its own net-zero targets. Increasing transmission network use of system charges (TNUoS) has become a key consideration for offshore wind project developers in recent times, placing ways to reduce these costs – including by way of shared offshore transmission infrastructure – firmly on the agenda.

To this end, the potential value of shared offshore transmission infrastructure to both developers and to the UK Government’s own objective to accelerate the rollout of offshore wind projects culminated in Ofgem’s April 2022 consultation: Offshore Coordination - Early Opportunities: Consultation on our Minded-to Decision on Anticipatory Investment and Implementation of Policy Changes (the Consultation). Ofgem’s proposal seeks to encourage early stage projects to collaborate by facilitating the making of anticipatory investment (AI) by an initial user towards the construction of offshore transmission infrastructure for itself and for other participating projects who will subsequently connect into the transmission infrastructure once completed.

The Consultation made certain ‘minded to’ proposals, amongst them a revised risk allocation between the initial user (i.e. the developer of the offshore transmission infrastructure), the later user and the consumer. It is proposed that the consumer would insulate the initial user from the risk of non-connection by the later user, while the later user would absorb the risk of late and non-connection from the consumer. The latter would be achieved by amending the user commitment arrangements in Section 15 of the CUSC (Connection and Use of System Code).

In October 2022, Ofgem published its Decision on Anticipatory Investment and Implementation of Policy Changes (the Decision). The Decision confirmed Ofgem’s intention to proceed with its ‘minded to’ proposals as set out in the Consultation, including its proposal to extend user commitment arrangements under Section 15 of the CUSC. At the time of publication, further steps are to be taken to implement the Decision, with the expectation that any code modification process would take 12 months, and depending on the complexity, a further 12 months for implementation.

It is also pertinent to note that in July 2023, the Government released its future framework recommendations flowing from the Offshore Transmission Network Review (OTNR), which was launched in 2020. The recommendations acknowledge that a new approach is needed to the upgrade of the transmission network in order to more appropriately support the UK’s decarbonisation and net-zero objectives. In particular, the recommendations note that the delivery of transmission is a key limitation and risk to the delivery of offshore generation. At the heart of the Government’s recommendations is the adoption of a more strategic approach for the deployment of offshore wind, predicated on more collaboration between the various key governmental stakeholders and regulators in order to streamline delivery. Importantly, this could lead to a re-think of the current OFTO framework as the case for a more centralised network design grows.

Spotlight on OFTOs

In the UK, the offshore transmission owners (OFTOs) are responsible for offshore transmission assets. Whilst in theory OFTOs may design and build offshore wind connections, in practice, offshore wind farm developers have always elected to build the link themselves, in order to mitigate the risk of non-delivery of the connection assets. After commercial operations start, the transmission assets are then sold to the selected OFTO. However, developers are often keen to provide the operations and maintenance services in respect of the OFTO assets to ensure availability standards are met (particularly as no direct compensation is payable by the OFTO to the wind farm in the event of a connection outage).

While placing responsibility for the development of offshore transmission into the hands of generating asset developers has assisted with the rollout of offshore wind capacity in the UK, the limitations posed by the onshore grid remains a key issue for developers and investors and should also be a key focus for the UK Government.

UK Policy developments

Energy Act 2023

In August 2022, the UK Government published the draft Energy Security Bill (the Bill). The draft Bill followed off the back of the British Energy Security Strategy published in April 2022 and sought to introduce new measures that the UK Government states would aid it in meeting its ambition to deliver up to 50GW of offshore wind by 2030.

After a tumultuous and protracted journey, the new Energy Act 2023 (the Act) finally received Royal Assent on 26 October 2023.

• First, the Act amends the Electricity Act 1989 to introduce multi-purpose interconnectors (MPIs) as a licensable activity, providing certainty to investors and developers and aiding the integration of renewable energy, such as offshore wind, onto the grid.
• Secondly, the Act enshrines the policy proposals underpinning a new Offshore Wind Environmental Improvement Package (OWEIP) into law. The Government published a Policy Statement setting out details of the OWEIP in January 2023. Said to help accelerate deployment of offshore wind whilst continuing to protect the marine environment, the Act imposes new powers as part of the OWEIP to amend and improve the HRA process specifically for the marine aspects of offshore wind developments. This will speed up the consenting process and, ultimately, the deployment of offshore wind projects.
• In addition to the OWEIP, new strategic compensatory measures have been introduced under the Act, enabling collaborative work between developers and the UK Government to compensate for negative environmental effects that cannot be avoided or mitigated.  An industry-funded Marine Recovery Fund (MRF) is to be established to support delivery of strategic compensatory measures. The intention was for the MRF to be operational and able to receive payments from late 2023, although this is yet to happen.

Key facts

In November 2022, the UK government announced it would introduce a temporary 45% tax – the Electricity Generator Levy (EGL) - on “extraordinary returns” made from low-carbon UK electricity generation in the period from 1 January 2023 until 31 March 2028 (when the tax ends).

‘Extraordinary returns’ is the aggregate revenue that generator groups or stand-alone companies make in a period from ‘in-scope generation’ in excess of a benchmark price of £75/MWh until 31 March 2024,(after which time the benchmark will be updated annually in line with CPI).

The EGL only applies to (i) companies or corporate groups whose electricity output exceeds 50 GWh per year, (ii) profits exceeding £10 million a year and (iii) to those not generated under a CfD. Draft legislation was published in December 2022, however the EGL was fully legislated for as part of the Spring Finance Bill 2023, published on 23 March 2023. The EGL will be in effect from 1 January 2023 and 31 March 2028 and applies to “extraordinary returns” earned by generators during accounting periods between those dates.

For the upcoming Auction Round 7 (AR7) the Government has announced that it will, subject to parliamentary approval, implement a non-price related support package known as the Contracts for Difference Sustainable Industry Rewards (CfD SIRs). The CfD SIRs aim to address recent supply chain challenges that have been hindering the deployment of offshore wind by providing additional revenue support to developers, through a series of lump-sum payments in addition to their regular CfD payments, should they invest in the economic, social, and environmental sustainability of their supply chains. The criterion for such investments is ‘investment in shorter supply chains’, ‘investment in more sustainable means of production’ and ‘investment in shorter supply chains that use more sustainable means of production’.

Like the CfD regime, CfD SIRs will be awarded through a competitive auction. Developers will submit proposals that in pursuit of the sustainability criteria the Government is offering support for and will compete against each other on the quality and cost of their proposals. The current draft of the CfD SIR allocation framework sets the minimum standard value to participate in the AR7 auction as £100m per GW for a fixed bottom offshore wind farm and £50m per GW for a floating offshore wind farm.

The Government proposes that the CfD SIR will also apply to allocation rounds 8 and 9, though, they have flagged further reconsideration of the minimum standard values and developments to the investment criterion.

Market reaction

Unsurprisingly, the reaction from the market has been one of outrage, with many stating that low carbon investment has already stalled in the wake of the EGL’s announcement.

The full impact of the EGL on low carbon generation is yet to be seen, however already we are starting to see an “offtake re-think” as the incentive to increase merchant exposure is eroded in favor of long-term contract trading arrangements, such as CfDs, under which generators receive £75/MWh (or slightly more) during the EGL’s effective period and beyond.

Some low carbon generators argue that the ultimate increased revenue certainty under these long term contracted models comes at the expense of low carbon innovation and, ultimately, a slower transition to net zero emissions.

UK short-term investor outlook

Notwithstanding the challenges faced by the offshore wind industry, the market outlook for the UK generally remains optimistic. Significant developers such as Ørsted, SSE, Equinor, Ocean Winds, RWE and EON continue to signal their commitment to the sector, and politicians on both sides of the floor remain supportive of the accelerated deployment of UK offshore wind.

Consented projects now primarily rely on the CfD regime for support, which remains a key tenet of the bankability case for projects to avail themselves of project financing. While CfDs are expected to continue to underpin the rollout of UK offshore wind projects, more flexible revenue stacks are being actively pursued, particularly in light of the outcome of the latest CfD Allocation Round.

Anecdotally, industry is also exploring alternatives revenue stabilization mechanisms such as corporate renewable PPAs. Notably the first offshore wind corporate PPA was announced in February 2019 between Northumbrian Water and Ørsted, for the purchase of 100 GWh per year from Ørsted’s Race Bank Offshore Wind Farm over ten years. This trend is only expected to accelerate.

In particular, the market is rapidly evolving to adapt to the current high electricity price climate. This volatility, coupled with the expectation that the high price climate will endure for some time, is enhancing the willingness of developers to explore alternate revenue structures to maximise returns.

The scale and anticipated stability of these price rises over the medium term is also assisting the bankability analysis that remains critical to ensuring projects can access debt markets notwithstanding the desire for increased flexibility vis-à-vis offtake strategy.

There are also significant M&A opportunities for investors in operational projects, as many of the major developers seek to divest offshore wind assets, moving to a ‘utility light’ model and putting sales proceeds into future projects. 

A number of projects have applied and/or secured rights to extend. We have already seen a number of these projects seek additional investment to fund development works and we expect similar opportunities of this nature to come to market.