Keywords

Nuclear is recognized by the Intergovernmental Panel on Climate Change (IPCC) as a low-carbon energy source, along with renewables and fossil fuels with carbon capture and sequestration (CCS). As of today, it is available in more than 30 countries and deployable on a large scale. Public opinion toward nuclear varies a lot from one country to another, with strong influence on energy policies: some countries, like the United Kingdom, are developing nuclear to meet their climate goals and insure security of supply, while others, like Germany, have decided to phase it out.

At a 2019 conference, the IPCC Chairman pointed out that “there is considerable potential, as well as considerable uncertainty for nuclear power” (Lee 2019). He added that, beyond public opinion, the real challenge in the years to come for nuclear power was “to be cost competitive with other non-fossil fuel technologies and to deploy nuclear power much faster than in the past”. He addressed the representatives of the nuclear community: “I wish you success in meeting these challenges because climate needs all the help it can get”.

This chapter discusses the economics of nuclear. It covers the fundamentals of nuclear economics and reviews the cost drivers for the long-term operation of the existing fleet and new nuclear projects. It then reviews the latest research related to the value that nuclear can bring to the overall electricity system and in wholesale price formation in deregulated markets.

1 Reminder: Current and Expected Role of Nuclear in Decabonization Scenarios

Today, nuclear makes a significant contribution to low-carbon global electricity supply:

  • As of 2020, about 450 nuclear reactors operate in the world (IAEA n.d.), with a combined capacity of more than 400 GWe. Nuclear energy accounts for more than 10% of worldwide gross electricity production (OECD-IEA 2019) and 25% in the European Union.

  • Thanks to nuclear, more than 60 Gt of CO2 emissions have been avoided since 1970 (OECD-IEA 2019), equivalent to five years’ worth of CO2 emissions from the electricity sector. Nuclear is the second largest source of low-carbon energy in the world behind hydropower and the number one source in the OECD.

International institutions have stated that all low-carbon technologies, including nuclear, will be needed to achieve carbon neutrality by 2050.

  • According to the IPPC, “the strategy for reducing energy related CO2 emissions are robust and well-known: very ambitious efficiency improvement, increased electrification, and decarbonization of electricity supply” (Lee 2019). The SR1.5 report describes four “1.5C” trajectories in its “Summary for policymakers”, envisaging nuclear production two to six times higher by 2050, compared to today.

    • According to the IEA, to meet climate goals, the expansion of clean electricity would need to be three times faster than at present (OECD-IEA 2019). Along with massive investments in efficiency and renewable energies, the trajectory should deliver an 80% increase in global energy power production by 2040.

    • The latest reference scenarios from the European Commission confirm that the combination of nuclear and renewables will be the basis of a carbon-free energy mix in 2050 (European Commission 2018). By this time, nuclear would represent about 18% of the total.

2 Fundamentals of Nuclear Economics

2.1 Cost of Production

The cost of nuclear power production, as for any other energy source, includes generally three different components:

  • Capital costs: These have a very high contribution to the LCOE of new plants, as they include the initial investment in building the plant. Nuclear, like wind and solar, is a highly capital-intensive industry. The share of capital costs decreases after the initial depreciation period, specifically in the case of long-term operation of nuclear plants.

  • Plant operating costs: These include the fuel costs and operation and maintenance costs (O&M). The share of fuel costs, which is usually high for fossil fuel and biomass, and zero for wind and solar, is considered low for nuclear, with uranium estimated on average at 5% of total nuclear production cost. As a result, nuclear plants are less subject to fuel price volatility than fossil fuel plants: a 50% rise in the fuel cost would only result in a 5% increase in the overall generation cost (Cour des Comptes 2014).

  • External costs: As opposed to coal or gas plants, nuclear is a low-carbon technology and provides little to no air pollution. Also, as it is highly regulated, it must include costs provisions for funding the plant decommissioning and the management and disposal of used fuel and wastes. External costs could however include the costs of dealing with a serious accident that are beyond the insurance limit: in practice, this type of risk (high potential cost with very low probability) is picked up by governments.

2.2 Revenues from Nuclear Plants

The cost of power generation is one of the three components of the retail price of electricity, together with the cost of the transmission and distribution infrastructures, and taxes.

In so-called regulated markets, revenues from power generation are determined through a regulatory process, under the supervision of a Public Utility Authority. In “deregulated” markets, the electricity produced is traded in a wholesale market, where prices are set, on an instant basis, by the “merit order” (economic precedence) logic: as electricity cannot be stored on a large scale, to meet a given level of demand, the various power generation units are called according to their increasing marginal cost.

Nuclear power plants, as we have seen, have low fuel costs, and therefore low marginal costs: they are usually called second after the units with zero to no fuel costs, such as hydro, wind, and solar. Nuclear is called before thermal power plants (coal or gas). The wholesale price for electricity, which will determine the nuclear plant revenue, will be given by the variable cost of the marginal plant, usually a thermal one.

3 Economics of Nuclear Long-Term Operations

In advanced economies, most of the nuclear power plants now in operations were built before 1990, and the average age of nuclear capacity stands at 35 years (OECD-IEA 2019). Most existing nuclear plants have been built with an initial design lifetime of 40 years, but engineering assessments have established that they can operate much longer (60 or even 80 years in the United States). One of the fastest and cheapest ways for these countries to support low-carbon production capacity is to undergo “long-time operation” programs (Fig. 7.1).

Fig. 7.1
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Age profile of nuclear power capacity in selected countries/regions. (Source: OECD-IEA [2019])

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In the past years, operators of many older nuclear plants have been investing in such programs, in some cases increasing capacity at the same time (so-called uprates). In the United States, 95 nuclear reactors are currently in operations (IAEA n.d.). They account for 20% of the nation’s total electric energy generation and about 50% of US low-carbon generation. About 88 have already renewed their operating license once, extending their lifetimes from 40 to 60 years (Patel 2019). However, since the majority of these will be nearing the end of that 20-year extension by 2029, it is expected that many will seek to renew their license a second time for another 20-year period. In December 2019, the US Nuclear Regulatory Commission (NRC) has for the first time issued license renewals that authorize nuclear reactor operation beyond 60 years and up to 80 years for 2 units in Florida.Footnote 1

3.1 Cost Drivers for Long-Term Operation of Nuclear Plants

Cost estimates are impacted by reactor type, plant situation, and regulatory requirements (IAEA 2018). Most of the costs are related to plant refurbishment and, in particular, replacement of major components to mitigate aging or obsolescence. But they also come from safety enhancements to meet the changes in national licensing requirements: these come, for instance, in response to lessons learned from operating experience, changes in industry practices and operating experience feed-back, or studies and lessons learned from accidents (such as Fukushima Daichi). Many new plant systems or systems configuration that were not considered at the time of plant commissioning may be added. In some cases, refurbishments and safety enhancements will come with power uprates, which include new licensing costs, changes in the fuel cycle, and replacement of some other components.

3.2 Competitiveness of Long-Time Operations of Nuclear Power Plants

According to OECD-IEA (2019), nuclear lifetime extensions are “one of the most cost-effective ways of providing low-carbon sources of electricity through to 2040”. The capital costs of extending the operational lifetime of light water nuclear power plants generally range from USD 500 million per GW to USD 1.1 billon per GW, for a duration between 10 and 20 years. The levelized cost of electricity (LCOE) associated with a nuclear long-time operations project generally falls into the range of USD 40–60 per MWh.Footnote 2 The competitiveness of nuclear plant extensions is even more favorable when the full value of nuclear power as a dispatchable, high-availability (on average the capacity factor for nuclear has consistently been between 78 and 83% over the last 20 years), low-carbon source of electricity is taken into account, as we will see in part IV. In the graph below, the “value adjusted LCOE (VALCOE)” is a new IEA metric which combines a technology’s costs with estimates of these values (Fig. 7.2).

Fig. 7.2
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LCOE by technology in the United States, 2018. (Source: IEA, LCOE by technology in the United States, 2018, IEA, Paris https://www.iea.org/data-and-statistics/charts/lcoe-by-technology-in-the-united-states-2018)

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4 Economics of New Nuclear Projects

The number of nuclear reactors in construction worldwide is 54 (OECD-IEA 2019), the majority of them in Asia, with some in Europe and America.

4.1 Challenges Associated with Delays and Cost Overruns in Recent Projects

Over the last decade , as mentioned by William Magwood, Director General of OECD’s Nuclear Energy Agency (NEA), “significant cost overruns and delays in a number of OECD countries have challenged the competitiveness of nuclear power and are driving the risk perception on future projects” (OECD-NEA 2020). As the industry transitioned from “generation 2” reactors to “generation 3” reactors, which present an increased level of safety but are more complex to build, most “First of a Kind” (FOAK) projects worldwide have shown significant delays compared to initial estimates, as shown by Table 7.1:

Table 7.1 Construction costs of recent FOAK Gen-III/III+I projects
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This situation is quite common for the delivery of large complex infrastructure projects, specifically FOAK projects, and is well documented in the economic literature. A well-known example is the construction of the Channel Tunnel, whose initial budget doubled by completion. Many studies (McKinsey 2013; Merrow et al. 1981; Yemm et al. 2012) have also highlighted the “optimism bias” upstream of these projects, as well as the “rapid learning” phases on the subsequent projects.

Delays for nuclear projects vary according to two country profiles. On one side, there are countries which have been building new reactors in a continuous manner over time, either because they are still in the process of building their initial fleet (China) or because they have begun renewing part of their fleet (Russia). It is symptomatic that the first of third-generation reactors put into service was in Russia and that the first European Pressurized Reactor (EPR) to start was in China. On the other side, there are countries (France, Finland, the United States) which had stopped building for 10 to 15 years: these countries not only have had to face the challenges associated with the first projects (FOAK), but also had to bring their skills and supply chain back again up to the standards required for the construction of nuclear reactors.

4.2 Cost Drivers of New Nuclear Projects

As for renewable energy projects (wind, photovoltaic, and hydraulic) nuclear production costs are very largely dominated by the cost of investment during the construction phase. In an average case (see Fig. 7.3), it is estimated that the cost of investment will make about two-thirds of the production cost. More than half of the investment cost will be the construction cost. Furthermore, the cash flow structure of nuclear projects requires large amount of capital to be mobilized upfront. Construction lead times and costs, together with the cost of capital, determine a plant’s economic performance. Once a plant is built, its O&M and fuel costs are low and predictable.

Fig. 7.3
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Production and Investment Cost. (Source: OECD, SFEN)

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When evaluating the cost of a new nuclear project, the discount rate, which varies a lot depending on whether the borrower is the government or a private party, has a major impact on LCOE. A sensitivity analysis by the OECD-NEA (2015) shows that average plant construction expenses would account for 45€/MWh with a 7% discount rate, but only 20€/MWh with a 3% discount rate.

4.3 Potential for Reduction in the Cost of New Nuclear Projects

Several reports and studies (OECD-NEA 2020; SFEN 2018), in recent years, have looked at lessons learned from projects as well as cost reduction drivers to reduce construction and capital costs on new nuclear projects. We will draw from them in this section.

The most important lesson learned, and cost driver, from FOAK projects has been that detailed designs must be complete and ready before the construction starts, in order to translate design specifications into detailed supply chain requirements and plans for each construction stage. For example, for the EPR construction in Finland, where anticipation of a nuclear renaissance and hopes to benefit from a first mover advantage had led Areva-Siemens to bid with an unfinished design, reveals the need for numerous adjustments which, given the complexity of the project, were responsible for the major part of the delays and cost overruns. Conversely, the construction of the EPR in Taishan benefited from the design and first level of lessons learned from Flamanville: according to the Folz report (2019), while the final cost of construction of Flamanville 3 in France is estimated at 12.4 Bn€, the total cost for the two EPRs in Taishan are estimated at 12.3 Bn€, that is 6 Bn€ per unit.

Besides this key lesson, recent studies have identified numerous cost reduction opportunities, as described in Fig. 7.4:

Fig. 7.4
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Nuclear cost and risk reduction drivers. (Source: Author’s elaboration on OECD-NEA 2020)

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In the FOAK stage, the interplay between plant design and effective project management presents a range of cost reduction opportunities: one key example is the engagement in the supply chain early in the design process to integrate all requirements necessary for construction. In the post-FOAK stage, continuous improvement and innovation can yield additional opportunities: one example is the expected introduction into the nuclear industry of the “system engineering” and “project life management” methods, which have been successfully implemented in aeronautics and allow all players involved in a given project to share the same data, from design to construction.

In the longer term, as in any other kind of project, product, or service, the main driver for cost reduction in construction is the series effect. When adequate design maturity has been achieved, the design configuration should be frozen and systematically replicated as many times as possible. We can see then first a program effect (studies, qualifications, and testing work are shared across several units) and productivity effects in the supply chain: thanks to the visibility obtained from a guaranteed order, suppliers can plan and optimize their resources and production tools. Feedback from the construction of the French nuclear fleet in the 80s showed that the maximum series effect can be reached by building reactors in pairs (15% of cost reduction for one pair on a single site), with a 30% reduction for a series of a minimum of three pairs (Cour des Comptes 2014; SFEN 2018). The recent Barakah 4-unit project in the United Arab Emirates, whose first unit achieved first criticality in July 2020, is reported to have achieved more than 50% cost reduction between the first and the fourth unit (Gogan 2019). Probably drawing from these conclusions, India recently confirmed the construction of a total of 16 identical 700 MW reactors (IANS 2020), with, after the first units being built, a “set up in fleet mode” for the units to be completed progressively by 2031.

Finally, we have seen above how sensitive the LCOE is to the discount rate. In the case of the Hinkley Point C project in the United Kingdom, the National Audit Office (NAO) has shown the potential for very significant savings on financial costs, via a better distribution of risks between the various stakeholders (NAO 2017). For example, should the required return on capital (after tax) drop from 9% (value close to the rate used by EDF Energy for the project) to 6% (considering the project as a public infrastructure with the associated investment framework), this would result in a reduction by one-third of the cost per kilowatt hour for consumers. Further studies must be carried out to determine the best project governance allowing the distribution of risks between the various actors. In 2019, the UK government launched a consultation on a so-called regulated asset base model (RAB)—used for other forms of infrastructure such as energy networks. This would lower the cost of capital of the scheme because consumers would have a surcharge added to their energy bills before the plant was completed (FT 2020). However, some have suggested that direct government funding would be a more logical and effective solution (Ford 2020).

The EDF CEO has declared that his company’s objectives for future nuclear projects in France, through leveraging all the cost drivers, should be in the 50–70€/MWh range, far below the recently announced Flamanville 3 latest estimate of 110–120€/MWh (Cour des Comptes 2020).

4.4 A Case for Disruptive Innovation: Small Modular Reactors (SMRs)

The delays and cost overruns in large Gen3 projects generated increased interest for a new, disruptive concept of smaller units with simpler designs. Defined as reactors of 300 MWe equivalent or less, Small Modular Reactors (SMRs) would not necessitate as large upfront capital costs per reactor and would be designed for serial construction. In fact, they could potentially be manufactured in an offsite dedicated facility to improve the level of construction quality and efficiency, and then later be installed independently on site or assembled module by module to form a large nuclear power plan.

In addition to traditional baseload power, SMRs would be able to address new markets and applications: their small size and passive safety features would be better suited for countries with smaller grids and less experience of nuclear power. In large countries, they could power islands (e.g., in Indonesia), isolated sites (mines), and remote areas (Northern Canada or Siberia). In the United States, they could target the brownfield sites to replace decommissioned coal plants. Finally, they could be used as well as an alternative to storage, to load follow on grids with a high share of variable renewable energies, to produce heat and decarbonize local district systems (China or Finland), to desalinate water (Saudi Arabia), or to provide low-carbon industrial heat and decarbonize complex industrial processes.

Several projects of SMRs, with different sizes and designs, are underway worldwide. The most advanced is probably the Nuscale project in the United States, which is supported by the US Department of Energy, has reached several licensing milestones, and is currently preparing for its FOAK project in Idaho.

For SMRs to be a credible option by the early 2030s, successful prototypes must be developed in the 2020s to demonstrate the announced benefits. Specially, they will need to deliver on the ambition with regards to the series effect, as well as simplification and standardization, all the more so because they will need to counterbalance some diseconomies of scale, for instance, on safety systems. Having access to a global market is necessary to foster series-production economies, but this will be possible only with regulatory and industrial harmonization.

5 New Research on the Value of Nuclear in the Future Low-Carbon Mix

To maintain a constant balance of electricity supply and demand, in face of constant demand changes and uncertainties, conventional electricity systems have relied on dispatchable generation such as thermal power plants and hydro power, that in some cases provide a lot of flexibility, as they can ramp up and down on short notice.

According to all decarbonization scenarios, future systems will need to integrate more and more variable capacity—essentially wind and solar power—to meet climate objectives. However, at the same time they will need to shut down traditional dispatchable coal and gas plants, to achieve net zero emissions in the electricity sector. This is a true paradigm shift that will have a major impact on how electricity systems are managed, and how much they cost.

5.1 Beyond the Cost of Power Generation, the Notion of “System Costs”

When shares of variable renewables (wind and solar) are low, the variability can be easily absorbed by the system. However, as their share increase, the introduction of variable renewable energies (wind, solar photovoltaic) will require additional back-up (such as storage) and adjustment capacities (such as demand flexibility) in order to guarantee the quality of electricity and the supply-demand balance. It will also involve strengthening the electricity networks. These effects lead to additional costs for the power system to be integrated when comparing the production costs of different technologies. A recent OECD-NEA study (2019) shows that these “system costs” can increase from €7/MWh to almost € 45/MWh when the share of variable renewables increases from 10 to 75% of the electricity mix.

In this new paradigm, the question of the competitiveness of each means of production can no longer be asked without consideration of the characteristics of the system where it operates: we will have to take into account the interdependencies within the electricity system (share of non-dispatchable sources, limits of storage facilities, and other sources of flexibility) and the structure of the electricity market. New nuclear power, a low-carbon source that can be controlled 24/7 and offers great flexibility (possible variation of 5% of nominal power/min), must in fact be compared, with respect to the services it provides to the system, to other controllable means such as hydroelectricity or to fossil means (coal, gas) equipped with carbon capture and sequestration.

5.2 MIT Study Shows That the Least-Cost Carbon-Neutral Portfolio Includes a Share of Nuclear

A recent MIT study (2018) explored in detail how imposing a carbon constraint affects the optimal electricity generation mix in different regions of the world (the United States, the United Kingdom, China). Should the carbon constraint not be a determinant factor, fossil fuels, whether coal or natural gas, are generally a lower cost alternative for electricity generation. Under a modest carbon emission constraint, renewable generation usually offers a lower cost alternative. However, as the world seeks deeper reductions in electricity sector carbon emissions, the cost of incremental power from renewables increases dramatically.

The study concludes that the least-cost portfolios include a significant share for nuclear, the magnitude of which significantly grows as the cost of nuclear drops. The levels of ‘deep decarbonization’—meaning emissions target for the electric sector that is well below 50 gCO2/kWh—including nuclear in the mix of low-carbon solutions, help to minimize rising system costs, which makes attaining stringent emissions goals more realistic (in comparison, worldwide, electricity sector emissions currently average approximately 500 gCO2/kWh). Lowering the cost of nuclear technology can help reduce the cost of meeting even more modest decarbonization targets (such as a 100 gCO2/kWh emissions target).

5.3 Toward Major Changes in the Regulation of Electricity Markets

Several studies (OECD-NEA 2019; SFEN 2020) have shown that, as a consequence of the increased share of variable renewables in the electricity mix, the volatility of electricity prices will increase substantially with periods of very high production of solar and wind (with episodes of very low and sometimes negative prices) alternating with very low production (with episodes of very high prices). As a result, the studies conclude that, as their deployment increases, the value of variable resources for the system decreases: this has important implications on their ability to be financed in energy-only markets.

In this environment, a recent SFEN study in France shows that a significant share of nuclear in the low-carbon mix plays an important role in stabilizing electricity prices; as its marginal cost is not zero, it is dispatchable and capable of load-following to support the integration of solar and wind production. It also provides frequency services to the network and operates in the long-term (60 years at least).

In general, as most generation technologies would have to rely on a limited number of hours with high market prices to recover their investment costs, it will make it even more difficult for investors to predict future revenues from their investment and will require changes in the regulation of electricity markets.

6 Conclusion

In its 2019 report, the OECD-IEA makes a few major recommendations directed at countries that intend to retain the option of nuclear power. The first one is to keep the nuclear option open and authorize lifetime extensions of existing nuclear plants as long as safely possible. The second one is to value dispatchability and design the electricity market in a way that properly values the system services needed to maintain electricity security, including capacity availability and frequency control services. In general, the Agency recommends to value non-market benefits and remunerates them accordingly.