In Part 1 of this paper we have assessed the amount of electricity that would need to be generated in emerging countries to reach a level of economic development and living standards close to those enjoyed by citizens of developed countries. We have set the target per capita electricity consumption at 5,000 kWh. The required amount of electricity to reach that target is 17,000 TWh, almost 2/3 of electricity produced in the world in 2019. We have shown that without reliance on fossil fuels, all non-fossil sources will need to be relied upon with nuclear power playing an essential role as the only available dispatchable low-carbon source that is scalable, with the obvious exception of a few countries particularly endowed by certain renewable resources, hydro in particular. We have provided an overview of advantages of nuclear power compared to other low-carbon sources of electricity.
In this Part 2 we analyse the all-important economic aspect – the cost of nuclear power in comparison with other low-carbon sources.
Part 3 will then look at the available nuclear technologies and how they may fit the economic development needs of emerging countries.
Nuclear power is expensive – is it really?
The media worldwide have been largely covering the significant schedule and cost overruns of nuclear new builds – most often the first units of new generation III technologies (referred to as First Of A Kind, or FOAK, in the nuclear community), like the first builds of the Westinghouse AP1000 in the US or the first units of the European Pressurized Reactor (EPR) under construction in Finland and in France. This fact, largely attributable to excessively optimistic initial estimates, starting construction with incomplete detailed design, and to the difficulties intrinsic to building a prototype of an extremely complex machine with components submitted to the most stringent requirements related to their design, manufacturing, control and licensing – all with the objective to guarantee the highest achievable level of safety - in a context where no new nuclear construction has been undertaken for more than 20 years and lot of expertise, competences and know-how had been lost.
A study by the UK Energy Technologies Institute (1) has analysed the main cost drivers in nuclear build and has shown that the large cost overruns are not a fatality in nuclear new build. Nuclear reactors recently built in China, in South Korea, in Russia and in Japan, have shown much better construction performance and significantly lower capital costs, as indicated in the following figure.
The OECD International Energy Agency and the Nuclear Energy Agency have regularly undertaken in-depth analyses and comparisons of plant-level Levelised Costs Of Electricity (LCOE) for different technologies (fossil-fuelled, nuclear and renewable) and different regions of the world. Some key conclusions of the latest evaluation done in 2020 (2) are the following:
The key insight from this 2020 edition is that the LCOE of low-carbon generation technologies are falling and are increasingly below the costs of conventional fossil fuel generation. Renewable energy costs have continued to decrease in recent years. With the assumed moderate emission costs of USD 30/tCO2 their costs are now competitive, in LCOE terms, with dispatchable fossil fuel-based electricity generation in many countries
Nuclear remains the dispatchable low-carbon technology with the lowest expected costs in 2025. Only large hydro reservoirs can provide a similar contribution at comparable costs but remain highly dependent on the natural endowments of individual countries. Compared to fossil fuel-based generation, nuclear plants are expected to be more affordable than coal-fired plants. While gas-based combined-cycle gas turbines (CCGTs) are competitive in some regions, their LCOE very much depend on the prices for natural gas and carbon emissions in individual regions.
The LCOE for different technologies presented in the following figure.
The LCOE values for fossil technologies presented in the above figure include a carbon price of 30 USD per tonne of CO2.
The following figure demonstrates the high sensitivity of nuclear to the discount rate. Logically, the LCOE of nuclear as a relatively capital-intensive baseload technology depends more heavily on the discount rate than the LCOE of other dispatchable plants, i.e. gas and coal, a feature that it shares with renewable technologies such as wind and solar. Up to 5%, nuclear is thus easily the least costly choice, whereas at 10% it is competitive only in certain countries.
Another factor contributing to nuclear being more impacted by the discount rate is its relatively long technology lifetime: the higher the discount rate, the less beneficial are revenues at the end of the observation period. As we see, the purely financial and social perspectives are clearly not aligned.
As a result, the long construction times and the high complexity of nuclear new build projects result in very high financing costs if the financing comes from private investors and banks having the perception of the high underlying risks and expecting adequately high returns.
This underpins the importance of reducing the cost of capital in financing nuclear power plants and the role governments can play in achieving that.
The example of the Hinkley Point C (HPC) nuclear project in the UK is instructive in this respect. The total construction costs of the HPC project are 25 billion € for 2 units of 1600 MW each, or about 8,000 € per kW. The two units will produce at least 26 TWh of electricity annually, or 1500 TWh over the 60-year lifetime. This yields a construction cost per MWh of about 16 €.
The operating costs after commissioning of the plant are estimated at between 15 and 25 € / MWh. This covers all running costs during operation, including personnel costs, fuel costs, permits, insurance, maintenance, taxes and premiums to the decommissioning fund and the processing and, importantly, the ultimate disposal of nuclear waste.
This gives a total not exceeding 41 € / MWh. Yet the contractual “strike price” agreed between the developer and future operator, EDF Energy and the UK Government, is 113 € / MWh. The difference, or 72 € / MWh, will be paid as a premium (interest, dividend or other forms of profit distribution) to the investors (EDF of France and CGN of China) and lenders (pension funds and state participations of France and China) of HPC. Alternative approaches to project financing, in particular, the involvement of the government to share some of the project risks and provide direct financing and guarantees could have significantly reduced the price for consumers. In its audit of the HPC project, the UK National Audit Office concluded that “Alternative ways of the government providing support for HPC could have resulted in lower costs to consumers over the life of the project. The government contributing to the project’s financing could have reduced financing costs because the government’s cost of borrowing is lower than for private investors. (3) “
With the rapid development of intermittent renewables (wind and solar PV) worldwide, we hear very often the argument that their plant-level LCOE continues to decrease and will further decrease in the future, while that of new nuclear, due to ever increasing safety requirements and complexity of the technologies, continues to grow.
Let us look a little more deeply in this argument.
For the plant-level LCOE, calculated at the busbar of an individual plant, we indeed see renewable energy developers winning tenders with very low prices (in $/MWh), lower than what a modern large NPP could reasonably achieve. But are we comparing the same service? The simplest way to answer this question would be to ask the winner of a PV or wind farm tender whether he could offer the same price not for a kWh produced but for a guaranteed delivery of a kWh on demand, i.e. at the time and place it is required. It is beyond any doubt that the answer would be negative. To guarantee the delivery, the said developer would need to have sufficient storage capacity or dispatchable back-up sources (typically gas or coal; among low-carbon sources, biomass and geothermal could offer such service, not cheap though…) to be able to deliver the guaranteed kWh even when there is no wind or no sunshine. This fundamental difference in the quality of service delivered to society, in providing either dispatchable low-carbon electricity (nuclear) or fatal, intermittent, poorly predictable electricity (solar and wind) is always neglected when direct comparisons of plant-level LCOE are made. This implies that there are other costs to the electrical system that have to be covered in order to integrate the intermittent renewables into the system, beyond the plant-level LCOE.
Generally speaking, the electrical system costs reflect the fact that power plants do not exist in isolation but that they interact with each other and their customers through the electricity grid. This means that electricity provision generates costs beyond the perimeter of the individual plant or the individual consumer, even without taking into account impacts on the wider natural, economic and social environment. Such system effects can take the form of variability, network congestion or greater grid instability. The three most significant effects are the increased costs for providing the residual load (load remaining to be satisfied beyond the portion covered by intermittent renewables), for short-term balancing and for the extension and reinforcement of the transmission and distribution grids. This is due to three characteristics that are by and large unique to intermittent renewables such as wind and solar PV (4). It has been shown that the system costs increase with the increase of the rate of penetration of intermittent renewables in the system.
Consequently, the plant-level LCOE is not the right metric to compare the cost of different technologies at the level of the electric system as a whole (grid-level). Multiple studies have looked at this issue, introducing the concept of “system LCOE (5)”. These studies clearly show that the system-level costs of renewables are much higher than their plant-level LCOE and they increase rapidly with the rate of penetration of intermittent renewables in the electricity system.
In addition to the grid-level costs, numerous externalities are not included in the LCOE, most importantly the environmental and social costs of climate change, air pollution etc.
The full cost of electricity provision can thus be represented as a sum of three components:
Full costs of electricity provision = Plant-level costs + Grid-level system costs + External or social costs outside the electricity system
An objective comparison of the costs of different technologies would need to compare the full costs of electricity provision or, as a minimum, at the system level include the grid-level system costs.
Another aspect omitted in plant-level LCOE comparisons is the fact that the lifetime of a modern nuclear power plant is 60 years with the possibility to extend it to at least 80 years, while a wind turbine or a PV plant will have a lifetime of 20-30 years at the most. Over the 60-year lifetime of the nuclear power plant, the investment into wind or PV technologies will have to be done two or three times.
Nuclear power is competitive with other low-carbon sources and arguably indispensable for deep decarbonisation of the economy if considered from a long-term systemic perspective taking into account the benefits to society and considering all externalities of alternative solutions. Commonly used discounted cashflow models and plant-level LCOE comparisons do not provide such systemic and long-term perspective. This underscores the important role governments and policy makers have to play to ensure that the decisions made to progress on the transition path to a decarbonised economy optimally allocate capital and reflect the common interests of society.
In the upcoming Part 3 we will make a brief overview of the current end promising advanced nuclear reactor technologies that emerging countries may consider if they decide to pursue the development of nuclear energy or to embark on it if they are newcomers to nuclear.
(1) The ETI Nuclear Cost Drivers Project: Summary report; Energy Technology Institute, April 2018
(2) Projected Costs of Generating Electricity, 2020 Edition, IEA – NEA, 2020
(3) UK NAO Report “Hinkley Point C”, HC 40, Session 2017-2018, 23 June 2017
(4) The Full Costs of Electricity Provision, OECD/NEA, 2018
(5) (a) Falko Ueckerdt, Lion Hirth, Gunnar Luderer, Ottmar Edenhofer: System LCOE: What are the costs of variable renewables?; Potsdam Institute for Climate Impact Research, Vattenfall GmbH, 2013; (b) The Full Costs of Electricity Provision, OECD/NEA, 2018