Addressing the “conventional offtake” challenge

This challenge largely stems from the increased capacity awarded during the ScotWind leasing process, which surprised everyone in 2021 by granting almost 28 GW of capacity in areas very far from UK demand centres. As a result, the power generation “centre of gravity” has shifted significantly away from demand, inherently increasing future stress on the transmission system. 

Clean Power “mission control” and NESO are now working to address the issue by carefully reviewing the grid-connection queue to remove inactive projects and prioritise those most beneficial to CP2030 goals. Meanwhile, the long-running debate over locational pricing in the UK power system — intended to discourage such distant generation — continues. Planned grid upgrades, such as undersea cables, will help alleviate transmission bottlenecks, but these measures only buy time rather than resolve the underlying problem.

However this cat-and-mouse game plays out, the Scottish power transmission system will reach wind-power “saturation” well before the rest of the UK does. Even accounting for planned grid updates — which may face construction delays — offshore wind projects north of the border (or, technically speaking, beyond the B6 grid boundary) will likely experience significant negative price episodes and/or curtailment in the 2030s and beyond. While curtailment can currently be revenue-neutral through Balancing Mechanism payments to generators, CfD terms have already become increasingly strict on negative pricing. With AR6 removing CfD support entirely during negative wholesale pricing episodes, a saturated grid will pose a substantial financial risk to offshore wind business models, making it increasingly difficult to secure a final investment decision (FID).

First-wave ScotWind projects, such as West of Orkney, will be least affected. However, every subsequent capacity addition will experience greater exposure to CfD non-payment which will make reaching FID progressively more challenging, with each new gigawatt worsening the issue. This issue has been further exacerbated by INTOG, with its initial projects already seeing Contract for Difference (CfD) success ahead of ScotWind projects. Congestion caused by large onshore wind projects located at ever-greater distances also contribute to the issue.

The Department for Energy Security and Net Zero (DESNZ) acknowledges this problem, but recognition does not equate to action. A CfD mechanism originally designed to remove revenue volatility for operators is now reintroducing it in an indirect way. Developers must factor this risk into their financial models when entering a CfD allocation round and carefully assess revenue uncertainty well in advance. This is where we at GHD will be able to assist.

Without revenue support during negative pricing episodes, offshore wind projects will need to explore alternative offtake strategies to bridge the gap left by the CfD negative price episode rules. Whilst alternative offtakes are unlikely to become the primary revenue stream for offshore wind in the near future — aside from a few niche cases — a well-structured offtake strategy could mean the difference between success and failure at the CfD allocation stage.

Developing alternative offtakes introduces additional complexity but can also provide a competitive edge over conventional projects. Historically, projects have struggled to establish merchant (non CfD) routes to market despite the potential upside compared to existing CfD contracts. Whilst power purchase agreements (PPAs) are growing, they remain insufficient in scale. Green hydrogen, meanwhile, is still far from reaching the maturity needed to support 100 MW+ offtakes. However, a combination of overplanting and optionality could form the basis of a hybrid offtake model that mitigates negative pricing risk whilst diversifying revenue streams.

Take, for example, a ScotWind project with a 1.5 GW grid connection. Adding approximately 10 per cent additional capacity — equating to 150 MW of overplanting — makes it possible to supply a 100 MW electrolyser, located onshore, with a very high load factor. Even during zero-wind periods, reverse export could enable hydrogen production, addressing the challenge of low-load-factor electrolysis and producing comparatively low cost green hydrogen.

What about pricing? Around 40 per cent of the time, when the offshore wind asset is generating at full capacity, the electrolyser is being powered using ‘spilled’ electricity that cannot be exported to the grid. At any output below full capacity, the overplanted wind turbines can either feed the grid or the electrolyser, depending on the economics.

This optionality enables the combined asset to respond flexibly to price signals, prioritising the most lucrative option at any given time — whether that be CfD-backed reports, merchant power sales, or hydrogen production.

This approach has already been modelled to work effectively with 10 per cent overplanting, which is financially viable even without hydrogen under a pure CfD scenario. We anticipate that overplanting proportions of 20 per cent, or more, could become commonplace in future projects, presenting a significant opportunity to produce competitively priced hydrogen as part of an OSW generation profile.

We have developed a robust levelized cost of hydrogen (LCOH) model and possess Plexos modelling capabilities, allowing us to rapidly assess alternative-offtake business models for offshore wind developments and evaluate their impact on project returns.

DESNZ has already indicated that CfD could work alongside the hydrogen business model. With an ongoing consultation on support mechanisms for long-duration energy storage, we are beginning to see how a hybrid offtake project — where green hydrogen is stored and used for power generation during peak demand periods — could unlock multiple revenue streams simultaneously.