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Preliminary Research on the Economics of Nuclear Energy

Kasper Holst, 03.01.2025

The world is faced with two crises; the climate crisis and the energy crisis. Nuclear Energy is gaining increasing interest as a prospect for solving both. We need to rapidly expand the global supply of clean energy, and solar and wind have their intermittent problems. This memo delves into the economics of nuclear, uncovering some of the broader challenges and opportunities of nuclear fission. It is drawn from The IAEA’s report Climate Change and Nuclear Power 2024: Financing Nuclear Energy in Low Carbon Transitions, and The World’s Nuclear Association’s Economics of Nuclear Power. 

IAEA is projecting a capacity increase for nuclear energy of 2.5x by mid-century, with nuclear power playing a key role in the energy market. It’s more optimistic target of 3x is reported to require upwards of $150bn in annual investment. 

The situation around a nuclear power plant can summed up well with IAEA Direct General Rafael Mariano Grossi’s words; “Across its near century-long lifetime, a nuclear power plant is affordable and cost competitive. Financing the upfront costs can be a challenge however, especially in market driven economies and developing countries”

The economics of nuclear energy

Two main components drive project feasibility and financial sustainability: capital costs (CAPEX) and the cost of capital (the cost of financing). CAPEX and the cost of capital account for about 70% of LCOE (see figure below). In the industry, “overnight costs” is usually used and not CAPEX, or the costs that are incurred during construction, and that relates to the actual construction, i.e. not the financing of the construction. I use overnight costs and CAPEX interchangeably, though there may be some differences I am not aware of.

Figure 1: LCOE by technology

Overnight costs = CAPEX, Interest during construction = Cost of capital

Building a nuclear power plant is incredibly capital intensive, and takes several years to build, which is where it poses as inferior to that of gas plants, which can be considered a direct substitute due to their role in the energy market. The competitiveness of nuclear – and why it is advantageous to gas and other fossil fuel sources – comes from the fact that nuclear plants can have lifetimes of close to a century

That said, the capital intensity of nuclear still makes the economics of a plant sensitive. So much so that even slight changes in the cost of financing the project can lead to the closing of new builds. A 1% change in the cost of capital for a project can lead to a 10% change in electricity generation costs. In addition, a delay of two years in construction can lead to 5% increase in electricity generation costs, only taking into account the interest rates during construction and not the increase in overnight costs due to the delay. Thus, investors focus rather on the predictability of costs and schedules rather than the actual expenditure. 

When building new plants, construction costs are highly project specific, and vary widely across countries and markets, due to differences in tech, labor costs, project scope, financing, and – importantly – plant constructions experiences. It has been documented that when introducing FOAK plants, the need to (re-)establish supply chains and workforce have led to delays and increase in cost. Reported capital costs for new projects after many idle years in the EU, UK and US range around $8,000 – 11,000/kW or more, excluding financing costs. Comparatively, countries with ongoing, retained experience, and mature processes, costs have been lower. China, Korea, and Russia are reported to have capital costs in the range of $2,500 – 5,000/kW. Nuclear leaders in Asia (e.g. Japan, China, Korea) have generally managed to deploy plants both faster and cheaper, than most of what is seen in the west (IAEA, 2024).

 

Breaking down the cost components of nuclear energy

The cost of nuclear energy – essentially what makes up the levelized cost of electricity (LCOE) for nuclear – can be broken down into x components; 1) capital costs, 2) plant operating costs, 3) external costs, and 4) other costs

Capital costs

Capital costs include site preparation, construction, manufacturing, commissioning, and financing. Included in costs pre-construction are design and licensing, where regulator fees are typically around $60mn per reactor per country, and costs payable by a vendor to support the licensing process are around $180-$240mn per design per country. 

Construction costs of nuclear plants are significantly higher than that of coal or gas plants, because of the need for special materials, sophisticated safety features and backup control equipment, according to the World Nuclear Association. The long construction time pushes up the financing costs significantly, as we have seen examples of above.

Figure 2: Capital costs of a nuclear power plant, by activity (World Nuclear

Association, World Nuclear Supply Chain Report)

Figure 3: Capital costs of a nuclear power plant, by labor, goods, and materials (World

Nuclear Association, World Nuclear Supply Chain Report)

Due to the few nuclear plants constructed in the west over the past couple of decades, the information on the costs of building modern plants is limited. 

“The OECD Nuclear Energy Agency’s (NEA’s) calculation of the overnight cost for a nuclear power plant built in the OECD rose from about $1900/kWe at the end of the 1990s to $3850/kWe in 2009. In the 2020 edition of the Projected Costs of Generating Electricity joint report by the International Energy Agency (IEA) and the NEA, the overnight costs ranged from $2157/kWe in South Korea to $6920/kWe in Slovakia. For China, the figure was $2500/kWe. LCOE figures assuming an 85% capacity factor ranged from $27/MWh in Russia to $61/MWh in Japan at a 3% discount rate, from $42/MWh (Russia) to $102/MWh (Slovakia) at a 7% discount rate, and from $57/MWh (Russia) to $146/MWh (Slovakia) at a 10% discount rate”

The 2020 report of Projected Costs of Generating Electricity points out how sensitive nuclear is to the financing costs: “At a 3% discount rate, nuclear is the lowest cost option for all countries. However, consistent with the fact that nuclear technologies are capital intensive relative to natural gas or coal, the cost of nuclear rises relatively quickly as the discount rate is raised. As a result, at a 7% discount rate the median value of nuclear is close to the median value for coal [but lower than the gas in CCGTs], and at a 10% discount rate the median value for nuclear is higher than that of either CCGT or coal. These results include a carbon cost of $30/tonne, as well as regional variations in assumed fuel costs.” (World Nuclear Association, 2023)

Plant operating costs

Plant operating costs include fuel costs (including fuel management and final waste disposal), operation & maintenance, provision for funding the cost of decommissioning, testing an disposing used fuel and waste

Nuclear power is characterized by high CAPEX, low OPEX (due to relatively low fuel costs). For nuclear’s (arguably) biggest competitor – gas – tha case is the opposite; low CAPEX, high OPEX, as fuel is one of the biggest expenses on the LCOE. 

Processing, enrichment and fabrication of uranium fuel accounts for about half of the total fuel costs. In the economic analysis of nuclear power, allowances must also be made for the management of radioactive used fuel and the ultimate disposal. Nevertheless, even with these included, the total fuel costs of a nuclear plant in the OECD are about ⅓ to ½ of those for a coal plant, and between ¼ and ⅕ of that of a gas plant. 

Thus, the high fixed-to-variable cost ratio of a nuclear plant leads to low fuel costs having a low impact on the LCOE of a nuclear plant. According to the OECD-NEA, a 50% change in the fuel costs only slightly affects the LCOE. Comparatively, gas and coal are more sensitive, with the LCOE changing ny roughly 7% and 4% respectively on a 10% change in fuel cost. 

Figure 4: Front-end fuel cycle costs of 1 kg uranium

Fuel costs is an area with steady increase in efficiency and cost reduction. In the US, fuel costs declined by 23% between 2012 and 2019, according to the Nuclear Energy Institute. New nuclear plants show an even more efficiency fuel components, where the front-end fuel cost is around 15-20% of total costs, compared to the 30-40% cost for operating nuclear plants, as can be seen in the figure below.

Figure 5: Fuel costs relative to LCOE

Efficiency can also be gained through fuel reprocessing where the recovered plutonium and uranium is used in a mixed oxide (MOX) fuel. Reprocessing comes with a high costs, though it is offset by MOX fuel not needing enrichment and there is less high-level waste produced at the end. 

The “back-end” of the fuel cycle, which included used fuel storage and disposal in waste repository, stands for about 10% of the overall costs per kWh. The $26 billion US used fuel programme is funded by a 0.1 cent/kWh levy.

Operating and maintenance (O&M) account for roughly ⅔ of the total operating costs. O&M can be divided into fixed costs that are incurred at any time regardless of the plant electricity output, and variable costs, which vary in relation to output. 

Decommissioning costs are about 9-15% of the initial capital cost of a plant. That said, when discounted over the plant’s lifetime, they only stand for a few percent of the investment cost and less to the generation cost. In the US they account for 0.1-0.2 cents/kWh, no more than 5% of the cost of the electricity produced (World Nuclear Association, 2023).

External costs

External costs are generally not a factor in nuclear, as (e.g.) regulations require operators to provision used fuel and decommissioning costs, thus internalizing these “external costs” (World Nuclear Association, 2023).

Other costs (system costs & nuclear-specific taxes)

Other costs refer to system costs and nuclear–specific taxes. System costs are the costs incurred in relation to a plant provisioning backup and transmission/distribution facilities. To ensure reliable electricity supply, plants must have reserve capacity to cover for downtime due to refuelling and maintenance in plants that mostly stay active. Due to the intermittency of wind and solar, a provision must also be made for the backup generation. A provision is also needed to transmit the electricity from where it is to where it is needed (the demand). System costs, such as the cost of the provision to transmit the electricity, do not fall on the plant operator or owner, but are handled by a separate entity. It is included here, because the cost is still – naturally – accounted for on the final electricity cost for the consumer, usually as a transmission and distribution cost. 

As is now becoming evident in multiple counties such as Germany, Austria, and Spain, the preferential basis for intermittent renewable supply (wind and solar) creates significant diseconomies for dispatchable electricity supply (e.g. reliable sources, including nuclear). The priority of non-dispatchable sources leads to a situation where the dispatchable sources being de-prioritized, thus decreasing their capacity factor. At levels approaching 40% share of electricity coming from intermittent energy, as the capacity factor decreases, the capital cost of dispatchable sources increases considerably. The effect that this – the utilization effect – has on the economics of base-load generation is not reflected in the levelized cost comparisons from the IEA – NEA reports. 

The low marginal operating costs of wind and solar means that – when the weather conditions allow for it – they undercut all other electricity sources. When the share of generation from wind and solar is high, such as that of the EU’s 30% renewable penetration target, nuclear’s capacity factor is reduced, greatly increasing the wholesale prices, while the average wholesale price falls. Thus, with more renewables, the financial viability of nuclear generation in wholesale markets is questionable. 

While renewables does not necessarily offer the best prices (though it does in several cases), its intermittent nature is a barrier for other energy sources. Reducing the financial viability of base-load energy sources will have a significant impact on electricity markets, and an especially negative impact is the sources impacted are sustainable base-load energy sources such as fission, fusion (in the future) and hydro. Even with renewables offering the best prices, the intermittency factor still poses a risk to the grid and to the end-consumer. Coupling intermittent sources with batteries could substitute for the base-load sources, though the viability of batteries is still very questionable. Until this is solved, the investment in base-load generation is likely to remain insufficiency, particularly in the EU, certain US states, and elsewhere where renewables are significant, or on the agenda to be significant. Potential solutions are introduction of long-term capacity markets and power purchase agreements. 

“When market designs create potentially unreliable supply systems that have to be fixed by setting up additional markets for stand-by capacity and other grid stability services, costs that should be borne by electricity generators (where competitive pressures will act as a restraining factor) have effectively been externalized. In some countries, their market design results in a market failure whereby reliable (and low-carbon) but capital-intensive technologies (such as large hydro and nuclear) cannot be financed because long-term power purchase contracts are not available – so there is no certainty that investments can be recouped. Long-term electricity storage solutions (when/if the technology becomes available) face the same financing problem because these will also be capital-intensive.”

The Costs of Decarbonisation: System Costs With High Shares of Nuclear and Renewables, a 2019 study by the OECD Nuclear Energy Agency, reports that a large share of intermittent renewable energy poses a major challenge for electricity systems in OECD countries and for base-load sources such as nuclear. It found that Grid-level system costs for renewables are high – $8-50/MWh – depending on technology, context, and country. Nuclear system costs are $1-3/MWh. 

I will not cover nuclear-specific taxes. It is levied in several EU countries. An example is Belgium, who raised €479mn from a €0.005/kWh tax in 2014 (World Nuclear Association, 2023).

 

Risks faced with when building nuclear power plants

Nuclear projects are similar to other large-scale, high capital cost infrastructure project. Beyond these, investors in nuclear are also faced with additional distinct risks, which impacts the cost of capital. Complex project planning, long construction timelines, regulatory complexities, lengthy payback periods and debt tenors adds to the risk profile of nuclear energy. 

Risks over the lifetime of nuclear energy project fall into three categories (Figure 6 on next page):

  • Intrinsic risks – What can be largely controlled by the owner
  • Common level risks – Project related uncertainties, reflecting shared risk allocation between owner and commercial partners
  • Extrinsic risks – An array of additional factors, which can significantly influence the project’s viability but over which the project owner has little to no control

Figure 6: Cashflow and risk factors through project lifespan

As can be seen in Figure 6, risks are the highest in the early phases of the project – pre-project, pre-construction, and the beginning of construction – and progressively decline as construction advances. After commissioning, the risk drops significantly. Intrinsic and common level risks can to some degree be mitigated or managed by parties to the project, and could aid in lowering the cost of capital for the project (IAEA, 2024).

Getting on-time and on-budget

Expertise in the management of the construction schedule in crucial to minimizing the cost and attract investment. The construction timeline must be adhered (and the schedule accurate enough to be adhered) to ensure on-schedule completion, within budgetary constraints, and in accordance with expected cashflow generation. As we have seen, delays in construction significantly increase the financial costs alone, not taking into account the impact on the capital costs. The operations at construction sites are extensive, with a peak workforce of up to 10,000 workers over long periods. Thus, delays during peak construction can incur significant capital costs. A one-month delay during this phase can lead to to an cost increase of tens of millions, excluding the financial costs associated with the delay. 

Figure 7: Total capacity added by construction duration, by region

Figure 8: Factors shared among success stories in nuclear, where majority of plants

have been built in less six years or less

Completing a project on time requires setting appropriate cost and schedule baselines from the start. The UK’s infrastructure and Projects Authority has published guidelines for estimation techniques, which evolve along with the project development maturity. This involves reference class forecasting, where companies with established historic portfolio generate from data and previous experience. Thus, FOAK nuclear technologies, projects, and companies are up for a greater challenge when it comes to setting accurate estimates.

With maturity, a project design will benefit from bottom-up estimates, and eventually be substituted with market data as contracts are awarded. Investor confidence is backed by third party assurance when it comes to the legitimacy of the techniques used for estimations. “KPMG designs cost intelligence approaches for clients to invest effort in the early stages of a project to get the baseline costs right, leveraging outturn costs from the portfolio to feed into more intelligent estimates” (IAEA, 2024)

 

Electricity Markets

The economics of any electricity generation is primarily defined by the unit cost (kWh, MWh) that the electricity costs to produce for the end consumer, who creates the demand – i.e. the LCOE. Secondly, the economics depends on the market where the electricity is sold, in which grid operators and power producers “run into a raft of government policies”, coupled with subsidies for certain sources. For policies, questions must be raised regarding the public good that they serve. Where the outcome does not effectively maximize public good, there is market failure. 

Market failure can often be explained by externalities – positive and negative impacts of an industry, not reflected in the market. For electricity, the direct costs usually do not include external costs such as emissions, system costs, land use, noise.

“Electricity markets rely on direct or private costs at the plant to dispatch (i.e. turn on and turn off) generators to meet varying real-time demand for power. Those costs determine merit order of dispatch. Meeting real-time electricity demand is a difficult and challenging process. The electricity markets do this, but do not reflect the externalities of the generators participating in the market and may result in market failure.”

When it comes to policies for public good in the electricity market, power producers are selling in a commodity market shaped by policies that may favor certain sources over others regardless of the immediate and long-term positive and negative impacts on the public good. In other words, the bureaucracy around policy making, and the degree to which regulation plays a role in the energy market, has let to a situation where the policies are not designed from the truths of the matter, but rather by lobby action and misinformation. One example of this is the recent events in Germany around the total phase-out of nuclear energy. Regardless, beyond Germany, nuclear power serves public good in being cheap, clean, long-term reliable production of base-load energy, though this is not recognized by the regulation and policies of the electricity market.

Some approaches to avoid market failure are to impose costs on effects that negatively impact public good, such as emissions, provide compensation for positive impacts, and ownership by government in sectors where market failure is likely to occur. As an example, certain US states have introduced ZEC (zero-emission credits) payments to nuclear energy for the positive impacts. ZECs serve to reflect that the value provided by nuclear can be greater than the LCOE of nuclear in markets where low gas prices and subsidies for intermittent renewables has market priority. “Without the ZEC payments, nuclear operation may not be viable in this situation.”

The Brattle Group published an analysis in 2016 indicated that ZECs could secure the viability of nuclear power in markets with subsidies for renewables. “The actual near-term shortfall for a distressed nuclear plant tends to be relatively modest – typically around $10/MWh, which translates to $12 to $20 per ton [approx. $13-22 per tonne] of avoided CO2, depending on the size of the shortfall and the carbon-intensity of the affected region. This cost compares favorably with other carbon abatement options, the estimated social cost of carbon, and the cost of state policies designed to reduce CO2 emissions from the power sector”

The US EIA published 2017 figures for the LCOE for different technologies to become active in 2022: 

  • Advanced nuclear: 9.9 cents/kWh
  • Natural gas: 5.7 – 10.9 cents/kWh
  • Coal (with 90% carbon sequestration): 12.3 cents/kWh
  • Wind onshore: 5.2 cents/kWh
  • Wind offshore: 14.6 cents/kWh
  • Solar PV: 6.7 cents/kWh
  • Solar thermal: 18.4 cents/kWh

 

OECD’s 2020 study on Projected Costs of Generating Electricity presented the high variable impact of interest rates on LCOE for nuclear relative to coal or gas. At 3%, nuclear was considerably cheaper than the others in all counties, at 7% it was comparable with coal while still cheaper than gas, while at 10% it was on a competitive level with both. A low discount rates, nuclear was significantly cheaper than wind and solar. Relative to a 0% interest, the LCOE of nuclear proved to increase 3x by increasing the interest to 10%, while coal increased 1.4x, gas changed little, solar increased 2.25x , and onshore wind nearly 2x, though with different capacity factors for the three base-load options. A $30/tonne carbon price was included across all technologies. Note that LCOE omit system costs, which are higher for wind and solar, as seen above. (World Nuclear Association, 2023)

Figure 9: Projected LCOE for n^th-of-a-kind nuclear plants completed from 2025,

in $/MWh

Figure 10: OECD electricity generating costs for 2025 onwards for different countries,

by technology, with 3% discount rate, in $/MWh

 

Study of advanced reactors, future competitiveness of nuclear

A study by the Energy Innovation Reform Project (EIRP)  in 2017 compiled extensive data from eight companies involved with advanced nuclear, pursuing commercialization of plants with individual reactors ranging from 48 MWe to 1650 MWe in size.

In terms of potential costs, at the lower end of the range, these plants could potential supply the lowest cost generation available. “At the same time, this could enable a significant expansion of the nuclear footprint to the parts of the world that need clean energy the most – and can least afford to pay high price premiums for it”. The companies included in the study was Elysium Industries, GE Hitachi (only through publicly available information), Moltex Energy, NuScale Power, Terrestrial Energy, ThorCon Power, Transatomic Power, and X‐energy. The LCOE range was from $36/MWh to $90/MWh, with an average of $60/MWh

“Advanced nuclear technologies represent a dramatic evolution from conventional reactors in terms of safety and non-proliferation, and the cost estimates from some advanced reactor companies – if they are shown to be accurate – suggest that these technologies could revolutionize the way we think about the cost, availability, and environmental consequences of energy generation.” (World Nuclear Association, 2023)

 

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