In February we published Investability and Scottish Wind, an open-source analysis paper exploring how different assumptions affect the investability of an example Scottish onshore wind farm. Since then, we have engaged with investors, developers and other stakeholders to dig deeper into the business case for onshore wind in Scotland. This paper presents what we have learned and sets out three recommendations to ensure that onshore wind can support delivery of Clean Power 2030. Alongside the new paper, an updated open-source financial model is available through the Regen Open Data portal.
Key takeaway
The investment needed in Scottish onshore wind for Clean Power 2030 can be delivered, but regulatory and policy decisions must take a realistic view of the risks and costs that projects face today. The upcoming onshore wind strategy from the UK government and decisions taken on electricity market reform in the coming months need to provide the certainty needed to support the current pipeline of onshore wind across the whole of Scotland.
If the government chooses a reformed national market: TNUoS and transmission losses need to be capped for Scottish generators on an enduring, rather than temporary, basis and at a level that is compatible with the modest returns needed to attract sufficient investment. Under existing rules, locational costs will rise in coming years and will be incompatible with Clean Power 2030.
If the government chooses to move to a zonal market: A strong and comprehensive support package must be provided which fully replaces lost revenue and mitigates risk across the whole project lifetime. Without this, developers and investors continue to make clear that the investment needed for Clean Power 2030 will be unachievable. The package must be in place before the AR7 auction and it must also be sufficient for projects with existing CfDs and should address future allocation rounds.
The whole sector, including government, NESO, developers and investors, needs to develop a common understanding of the likely scale and impact of economic curtailment under a Clean Power 2030 electricity system and ensure that policy and regulation reflects this context.
Lessons from our engagement with developers and investors
Our first paper used public data, and our own knowledge, to set assumptions for a simple financial model for an onshore wind farm. It was, at heart, a discussion paper. At the end we asked seven questions, encouraging feedback from the sector.
This new paper has emerged out of discussions with 25 organisations from across the energy sector who were keen to help us improve our modelling or share their thoughts on the evolving investment landscape. Many are onshore wind developers and investors, and many were willing to discuss – confidentially – some of the assumptions that go into their financial modelling as well as their concerns about the investment landscape today. Their input has allowed us to refine the open-source financial model, updating assumptions to reflect the feedback we received.
Some of the important messages include:
Hurdle rates have increased significantly in recent years
Capital costs are higher than recent government assumptions, driven by strong inflation affecting the inputs to wind farms more than the wider economy as measured by standard inflation metrics
Developers and investors tend to use optimistic assumptions about future TNUoS levels with assumptions typically lower (often significantly so) compared with our previous modelling, based on the official Ten-Year Forecasts published in autumn 2023
Renewable Energy Guarantees of Origin should be included, despite being a relatively small revenue stream, as they can make a difference where the investment case is marginal
Community benefit payments are an important operational cost for onshore wind farms in Scotland where best practice guidance – almost universally followed by developers and operators – is for a £5,000/MW/year payment to local communities
Transmission Loss Factors are an additional, strong locational signal disincentivising generators in Scotland. These make a significant difference to revenue by reducing the volume of energy generators can sell.
These conversations also reinforced the message that a move to zonal pricing will lead to a reduction of revenue and increase in uncertainty and, without very strong price and volume protection, will create a significant barrier to existing and new projects reaching financial close. The government has now acknowledged that, and, through the REMA process, is developing a ‘financial protection scheme’ which could be used if it opts for a zonal market. However, fully closing the gap created by zonal pricing will be expensive.
Incorporating this feedback into our financial model leads to several large swings in the Internal Rate of Return (IRR). For example, the more optimistic TNUoS assumptions used in this paper increase the IRR by 1.84% compared with our original assumption, while Transmission Loss Factors (TLFs) and higher capital costs reduce it by 0.60% and 0.90% respectively. Overall, the headline return on investment is similar to the original paper, at 7.03%.
2.6 GW Scottish onshore wind pipeline with an existing CFD awaiting Final Investment Decision
7.03% The Internal Rate of Return in the Regen open-source base-case for onshore Scottish wind
0.68% The decrease in Internal Rate of Return due to a £100k/MW increase in capital costs
What did we learn from other stakeholders?
We also spoke to organisations involved in making energy policy and regulation. Through these discussions we identified several areas that we think need further work. Firstly, the understanding of negative wholesale pricing, oversupply of renewables and economic curtailment (that is, curtailment due to system-wide energy balance reasons, rather than network constraints) is mixed across both developers/investors and the public sector. The prevalence of these factors can have a significant impact on project finances even within a national (rather than a zonal) wholesale market. We recommend that, across government and industry, more is done to understand these factors, what will drive them, what their impact could be and how to best manage them.
Secondly, we are concerned that there is a risk of a divergence in assumptions about TNUoS between industry and policymakers. Our conversations with developers and investors suggest they use relatively optimistic assumptions in their financial models about future TNUoS charges in Scotland relative to, for example, the Ten-Year Forecast, published by National Grid ESO (now NESO) in 2023. While at the same time, at least some of the messaging from the government and public sector suggests that high locational TNUoS remains an option under a reformed national market to retain some financial locational signals.
Sensitivity of rate of return to TNUoS assumptions
It is critical that government understands the impact that locational TNUoS has on returns, particularly when combined with other locational signals such as TLFs. And it is important that there is a shared expectations about future charges.
What about offshore wind?
At the end of the paper, we present an illustration for an offshore wind farm in Scotland. This highlights that offshore wind faces an equally difficult investment climate, with many of the same issues affecting projects. This is an area that needs further attention, and we hope to return to it later this year.
Improving understanding
This is not the end of the process, and we continue to welcome discussions on the issues raised in the paper.
If you want to understand our modelling in more detail, or if you think you can help us improve the open-source analysis, please get in touch with Simon Gill.
