Risk and investment in zero-carbon electricity markets
Authors: Will Blyth, Robert Gross, Stephen Nash, Malte Jansen, Jamie Rickman, Callum MacIver and Keith BellDownload the full report
This discussion paper has been produced to present preliminary findings from ongoing research and engagement activity led by UKERC on the topic of the future of electricity markets. To support development of a zero-carbon electricity market design in the UK, and to help meet net zero commitments around the world cost effectively, this initial analysis is being published on Science & Innovation Day at COP26. The work has been part funded by SSE Plc. Experts from BEIS, Ofgem, the Energy System Catapult and Energy UK are helping to inform the analysis.
Ambitious wind deployment
The paper takes as a starting point the bold ambitions that the UK has for expanding renewable energy, particularly offshore wind. At the end of 2020, the UK Prime Minister announced an aspiration to build 40 GW of offshore wind by 2030 and the 2021 Net Zero Strategy doubled down on this, reiterating the importance of offshore wind in meeting net zero aspirations. However, this is just the start. Scenarios from National Grid ESO, the Great Britain electricity transmission system operator, put the amount of offshore wind needed at between 80-110GW by 2040 requiring investment of up to £200 billion.
Policies put in place in 2013 under ‘Electricity Market Reform (EMR)’ have played a key role in driving cost reduction and deployment of wind and solar power. Government backed contracts known as Contracts for Difference, or CfDs, have proved attractive to investors and developers. These provide low carbon energy sources with a secure revenue stream by fixing the ‘strike price’ paid for each unit of electricity they produce – for 15 years for renewable power.
The debate over market design
The CfD prices are set through auctions, placing downward pressure on prices, which have fallen so dramatically that some commentators are questioning whether renewables still need government support through long term contracts. They argue for a different approach, based on an obligation on suppliers rather than government contracts. The logic is that although CfDs make investment less risky, they also largely remove incentives for renewable generators to respond to short-term changes in the wholesale market price of electricity. It is argued that wind and solar developers will find new ways to help ensure demand meets supply if they are exposed to these price fluctuations.
Others argue that applying this approach would put the cart before the horse when we have only just started to deliver the massive shift in the country’s power infrastructure needed for decarbonisation of the electricity system by 2035. They argue that we need to keep the costs of capital as low as possible to help us afford huge new investments needed in low carbon power.
In today’s power system fuel costs dominate overall costs, as we have seen recently with high gas prices leading to very high costs of electricity. In the low carbon system of the future, the cost of generating electricity becomes less about the price of fuel and more about the cost of borrowing money. Rather ironically, power prices tend to fall when it is windy or sunny and wind or solar power is plentiful. This is a phenomenon known as price cannibalisation, which creates new risks and may deter investors.
This balance between market price signals and investment risk can be characterised as a trade-off: Do the cost savings arising from low cost of capital achieved through de-risking policies outweigh the potential system cost benefits that might arise from exposing renewables projects to greater levels of market price risk?
Uncertainty impacts on investment risk
In this paper we explore how uncertainty about the power generation system of the future affects investment risk. We then explore in simplified terms how different market or incentive designs mitigate or exacerbate risks, and therefore affect the cost of capital. We use published scenarios to illustrate possible different pathways to a zero-carbon electricity system, all of which include very large increases in offshore wind power capacity from 10 GW now to 100-120 GW in 2040. We then look at how exposure to decarbonisation pathway risks varies depending on the policy / market design frameworks in place for remunerating renewable energy.
Initial results indicate that the degree of exposure varies by around 1-5 percentage-points between the most risk-exposed framework to the least risk-exposed. Very roughly, for every 1%-point increase in the cost of capital, the £15bn annual financing cost of offshore wind increases by £1bn per year. This suggests that the choice of policy framework could impact the cost of delivering the offshore wind component of the low-carbon transition by between £1bn and £5bn per year, or up to a third of the overall annual cost.
We have not yet attempted to quantify the degree to which exposing wind projects to more market price risk would achieve cost savings in the wider electricity system. To result in a net cost saving, reduction in grid and balancing costs that can be attributed to exposing renewables schemes to greater price risk would have to be at least as large as the cost of capital effects. Future work will explore whether potential system cost savings could be as large or larger than the £5bn per annum impacts of market price risks.
Authors and affiliations:
- Will Blyth, UKERC researcher, Oxford Energy Associates
- Robert Gross, UKERC Director
- Stephen Nash, Kuungana Advisory
- Malte Jansen, UKERC researcher, Imperial College London
- Jamie Rickman, UKERC Researcher, University College London
- Callum MacIver, University of Strathclyde
- Keith Bell, UKERC Co-Director, University of Strathclyde