The UK government’s ten-point plan for a ‘green industrial revolution’ commits to nuclear energy being part of the electricity mix, alongside a major expansion of offshore wind energy, and so the debate around the role of nuclear energy will be re-awakened. Dr Marko Aunedi, an investigator on the Integrated Development of Low-carbon Energy Systems (IDLES) programme, and his colleagues, have been looking at the economic and technical case for nuclear energy as part of the energy mix in the UK.
Our analysis finds that for nuclear energy to be a financially viable addition to the UK energy mix, cost reductions of at least 30% are needed, compared to the electricity price of the Hinkley Point C project presently being built which has a 35-year contract for price support (a Contract for Difference) at £92.5/MWh in 2012 prices. This finding is part of a wider exploration of the capacities of generation and storage technologies that could be built to achieve a net-zero carbon emissions electricity system for Great Britain. Nuclear energy is one of the possible zero-carbon sources. The full analysis will be published in a briefing paper (due in January 2021) to provide evidence to policymakers on the lowest-cost direction of energy system evolution towards this target. For now we would like to share our results on nuclear, which are relevant to the ongoing talks between EDF Energy and the UK government to secure construction of a new nuclear power station at Sizewell in Suffolk. The Sizewell C project would provide 3.34GW of electricity, enough to power 6 million homes, and comes with the expectation of boosting jobs, skills and apprenticeships in the area.1
How did we come to our conclusions on the cost reductions needed?
We have been exploring the topic using our Whole-electricity System Investment Model (WeSIM). Capturing the interactions across different time scales and across different technology types is essential for the analysis of future low-carbon electricity systems. WeSIM is a comprehensive analysis tool that can simultaneously balance long-term investment decisions against short-term operation decisions, across electricity generation, transmission and distribution systems.2 It tells us what and where the optimal economic investments are for generation, energy storage capacity and network assets, while ensuring real-time balancing of supply and demand can be achieved and security of supply standards met. All case-studies in the assessment are focused on a net-zero carbon GB power system in the year 2050. The analysis considers a snapshot for the electricity system in that single future year and finds the minimum total cost accounting for the annualised investment cost and the operation cost of all the investments.
One of the recurring questions around cost-efficient decarbonisation of electricity systems is how much firm low-carbon generation should be added to the system to complement variable renewable energy sources such as wind and solar? “Firm low-carbon generation” refers to technologies that can be used to meet demand whenever needed, in all seasons, such as nuclear power, hydroelectric power, bioenergy and fossil fuels with carbon capture and sequestration (CCS). There are clear merits to using such resources, such as better controllability, independence of weather events and technical factors such as provision of inertia and ancillary services. However, the right proportion of firm low-carbon generation in a net zero system will to a large extent be driven by the cost of competing technologies, in particular wind and solar, given their recent sharp reductions in cost.3
Via WeSIM we ran a central scenario with a series of input assumptions including minimum generation capacity levels for each technology, their technical parameters and costs, demand side response uptake, and interconnection capacity between GB and continental Europe. We then studied variations to this central scenario so that trends could be observed and cost-points identified where a significant system reconfiguration would occur. WeSIM identifies the amount of a particular type of generation and energy storage that would be added to the electricity mix at a certain cost, and also calculates how the overall system cost would change relative to the central scenario.
Nuclear power generates about 20% of GB’s electricity at the moment, with eight currently operational stations providing a combined capacity of about 9 GW. However, much of the current capacity is due to be retired by 2030.4In our central modelling scenario to 2050 we therefore assumed a minimum nuclear capacity level of 4.5 GW. This reflects the addition of Hinkley Point C station (3.3 GW), expected to become operational before 2030, and the capacity of Sizewell B (1.2 GW), which is the only existing nuclear plant expected to still be in operation in 2050 (assuming its operating lifetime is extended).
Our central assumption for the cost of electricity from nuclear is £92.5/MWh, which is consistent with the “strike price” of the Contract for Difference awarded to the Hinkley Point C project. The “strike price” is a guaranteed price. It means that for each unit of electricity generated, the developer will be paid the difference between the strike price and the wholesale price for electricity sold into the market. Under these assumptions for nuclear we see that the cost-optimal electricity system does not expand its nuclear resources, opting instead for strong growth in offshore wind. This is not a huge surprise given the rapid cost reductions seen in offshore wind development in recent years, coupled with the somewhat controversially high strike price of £92.5/MWh for Hinkley Point C. In this case, the absence of an expansion in nuclear capacity, because of the expansion of offshore wind instead, means that the requirement for firm low-carbon generation, needed to ensure secure system operation, is met by adding zero-carbon gas generation. This generation is assumed to run on biogas or hydrogen and was assessed to have roughly double the operating cost of conventional combined cycle gas turbine (CCGT) generators.
So at what point does it make sense for the system to expand its nuclear capacity?
If nuclear power becomes available at a lower cost of £60/MWh, the model suggests adding a further 4.5 GW of nuclear capacity (Figure 1) and, by doing so, the system cost is reduced by £1.8bn per year (Figure 2). At this lower price, new nuclear becomes a more attractive proposition for providing firm zero-carbon generation than zero-carbon gas. If the price drops even further to £45/MWh the model adds 13 GW more nuclear capacity, displacing some offshore wind, and savings to the system increase to £3bn per year. The savings mostly arise from reduced cost of investing into other firm low-carbon generation, with noticeable savings in operating cost, storage investment cost and interconnection investment cost.
Figure 1. GB system for net-zero with variations in cost of nuclear generation: total installed capacities
Figure 2. GB system for net-zero with variations in cost of nuclear generation: changes in annual total system cost vs. Main scenario
We also looked at the cost implications of a decision to lock in a higher minimum volume of nuclear generation. This was prompted by a recent Energy Systems Catapult study5 that suggested that the UK should commit to 10 GW of new nuclear beyond Hinkley Point C (provided, as they note, that its costs fall significantly). This fixed volume of nuclear power is taken as 14.5 GW rather than 4.5 GW, with the cost of nuclear power set at £75/MWh. This additional capacity broadly corresponds to the numbers suggested in several recent system studies, while the cost reflects the price discussed at the time of negotiations around the potential construction of Wylfa station between the investors and the government.
Fixed addition of this 10 GW of nuclear capacity at the cost of £75/MWh results in a total system cost that is £0.5bn per year higher than in the central scenario. Although not a very high amount in relative terms, this highlights the risk of overinvesting in nuclear capacity and therefore not being able to take full advantage of cheaper offshore wind generation.
According to news reports,6 EDF estimates the cost of electricity produced at Sizewell C will be somewhere between £40 and £60/MWh, although this perhaps sounds somewhat ambitious in view of the cost previously agreed for Hinkley Point C and the increasing complexity and risk associated with nuclear projects.7 Our analysis shows that this price will need to be hit in order to make nuclear expansion economically justified from a whole electricity system perspective. The continued cost reductions of other power sources such as offshore wind places considerable pressure on nuclear developers to produce corresponding cost reductions and that is essentially why nuclear schemes such as Sizewell C will need to be at least 30% cheaper than Hinkley Point C in order to secure their future role in the electricity system.
2 A more detailed description of WeSIM modelling framework can be found in the Appendix of the report “Whole-system cost of variable renewables in future GB electricity system”, available at: http://energysuperstore.org/esrn/wp-content/uploads/2016/11/Whole-system-cost-of-variable-renewables-in-future-GB-electricity-system-Imperial_Nov2016.pdf
3 Jansen, M., Staffell, I., Kitzing, L. et al. Offshore wind competitiveness in mature markets without subsidy. Nat Energy 5, 614–622 (2020). https://doi.org/10.1038/s41560-020-0661-2
4 House of Commons Library Briefing Paper “New Nuclear Power” Number CBP 8176, 29 July 2020: https://commonslibrary.parliament.uk/research-briefings/cbp-8176/
5 Energy Systems Catapult (2020) Nuclear For Net Zero; A UK Whole Energy System Appraisal: https://es.catapult.org.uk/reports/nuclear-for-net-zero/