Economics of Nuclear Power

(Updated March 2020)

Nuclear power is cost competitive with other forms of electricity generation, except where there is direct access to low-cost fossil fuels.

Fuel costs for nuclear plants are a minor proportion of total generating costs, though capital costs are greater than those for coal-fired plants and much greater than those for gas-fired plants.

System costs for nuclear power (as well as coal and gas-fired generation) are very much lower than for intermittent renewables.

Providing incentives for long-term, high-capital investment in deregulated markets driven by short-term price signals presents a challenge in securing a diversified and reliable electricity supply system.

In assessing the economics of nuclear power, decommissioning and waste disposal costs are fully taken into account.

Nuclear power plant construction is typical of large infrastructure projects around the world, whose costs and delivery challenges tend to be under-estimated.

For information on the financing specifically, please see information paper on Financing Nuclear Energy.

Assessing the relative costs of new generating plants utilising different technologies is a complex matter and the results depend crucially on location. Coal is, and will probably remain, economically attractive in countries such as China, the USA and Australia, as long as carbon emissions are cost-free. Gas is also competitive for base-load power in many places, particularly using combined-cycle plants.

Nuclear power plants are expensive to build but relatively cheap to run. In many places, nuclear energy is competitive with fossil fuels as a means of electricity generation. Waste disposal and decommissioning costs are usually fully included in the operating costs. If the social, health and environmental costs of fossil fuels are also taken into account, the competitiveness of nuclear power is improved.

The basic metric for any generating plant is the levelised cost of electricity (LCOE). It is the total cost to build and operate a power plant over its lifetime divided by the total electricity output dispatched from the plant over that period, hence typically cost per megawatt hour. It takes into account the financing costs of the capital component (not just the 'overnight' cost).

On a levelised (i.e. lifetime) basis, nuclear power is an economic source of electricity generation, combining the advantages of security, reliability and very low greenhouse gas emissions. Existing plants function well with a high degree of predictability. The operating cost of these plants is lower than almost all fossil fuel competitors, with a very low risk of operating cost inflation. Plants are now expected to operate for 60 years and even longer in the future. The main economic risks to existing plants lie in the impacts of subsidised intermittent renewable and low-cost gas-fired generation. The political risk of higher, specifically-nuclear, taxation adds to these risks.

The World Nuclear Association published Nuclear Power Economics and Project Structuring in early 2017. The report notes that the economics of new nuclear plants are heavily influenced by their capital cost, which accounts for at least 60% of their LCOE. Interest charges and the construction period are important variables for determining the overall cost of capital. The escalation of nuclear capital costs in some countries, more apparent than real given the paucity of new reactor construction in OECD countries and the introduction of new designs, has peaked in the opinion of the International Energy Agency (IEA). In countries where continuous development programs have been maintained, capital costs have been contained and, in the case of South Korea, even reduced. Over the last 15 years global median construction periods have fallen. Once a nuclear plant has been constructed, the production cost of electricity is low and predictably stable.

In deregulated wholesale electricity markets the economic justification for any capital investment has been decreasing while the actual need increases due to the ageing of existing plants. The IEA points out that at the turn of the century one-third of investment in electricity flowed into deregulated markets exposed to wholesale price uncertainty, whilst two-thirds went into regulated markets with some assurance of return on capital. By 2014 only 10% of investment was directed into deregulated markets. This has prompted urgent reviews by governments concerned about medium-term energy security. All operating nuclear power plants were built by governments or regulated utilities where long-term revenue and cost recovery was virtually certain. Some of these plants, especially in the UK and USA, now find themselves in a deregulated market environment.

Regulated and government utilities make investments in generation assets, spend money on power plant fuel and operation, and make decisions about retiring existing assets. These decisions are based on long-term planning processes focused on ensuring reliable operation while minimising total costs over the long-term. In a deregulated market a merchant generator depends on the inherently short-term and often volatile market for its revenue, putting the operator is at risk; and the developer of a new plant faces considerable uncertainty due to greater completion risk. Government support is needed to mitigate these risks and make new projects bankable.

A further economic aspect is the system cost of making the supply from any source meet actual demand from the grid. The system cost is minimal with dispatchable sources such as nuclear, but becomes a factor for intermittent renewables whose output depends on occassional wind or solar inputs. If the share of such renewables increases above a nominal proportion of the total then system costs escalate significantly and readily exceed the actual generation cost from those sources. This is modelled in a 2019 OECD Nuclear Energy Agency study and very evident in Germany, and is an important consideration beyond the LCOE in comparing sources (see section below on Other costs).

Assessing the costs of nuclear power

The economics of nuclear power involves consideration of several aspects:

Capital costs, which include the cost of site preparation, construction, manufacture, commissioning and financing a nuclear power plant. Building a large-scale nuclear reactor takes thousands of workers, huge amounts of steel and concrete, thousands of components, and several systems to provide electricity, cooling, ventilation, information, control and communication. To compare different power generation technologies the capital costs must be expressed in terms of the generating capacity of the plant (for example as dollars per kilowatt). Capital costs may be calculated with the financing costs included or excluded. If financing costs are included then the capital costs change materially in relation to construction time of the plant and with the interest rate and/or mode of financing employed.

Plant operating costs, which include the costs of fuel, operation and maintenance (O&M), and a provision for funding the costs of decommissioning the plant and treating and disposing of used fuel and wastes. Operating costs may be divided into ‘fixed costs’ that are incurred whether or not the plant is generating electricity and ‘variable costs’, which vary in relation to the output. Normally these costs are expressed relative to a unit of electricity (for example, cents per kilowatt hour) to allow a consistent comparison with other energy technologies. To calculate the operating cost of a plant over its whole lifetime (including the costs of decommissioning and used fuel and waste management), we must estimate the ‘levelised’ cost at present value. The levelised cost of energy (LCOE) represents the price that the electricity must fetch if the project is to break even (after taking account of all lifetime costs, inflation and the opportunity cost of capital through the application of a discount rate).

External costs to society from the operation, which in the case of nuclear power is usually assumed to be zero, but could include the costs of dealing with a serious accident that are beyond the insurance limit and in practice need to be picked up by the government. The regulations that control nuclear power typically require the plant operator to make a provision for disposing of any waste, thus these costs are ‘internalised’ as part of operating costs (and are not external). Electricity generation from fossil fuels is not regulated in the same way, and therefore the operators of such thermal power plants do not yet internalise the costs of greenhouse gas emission or of other gases and particulates released into the atmosphere. Including these external costs in the calculation for alternatives improves the economic competitiveness of new nuclear plants.

Other costs such as system costs and nuclear-specific taxes.

Each of these apects is considered below.

Capital costs

Costs are incurred while the generating plant is under construction and include expenditure on the necessary equipment, engineering and labour, as well as the cost of financing the investment.

The overnight cost is the capital cost exclusive of financing charges accruing during the construction period. The overnight cost includes engineering, procurement and construction (EPC) costs, owners' costs (land, cooling infrastructure, associated buildings, site works, switchyards, project management, licences, etc.) and various contingencies.

Construction/investment cost is the capital cost inclusive of all capital cost elements (overnight cost, cost escalation and financing charges). The construction cost is expressed in the same units as overnight cost and is useful for identifying the total cost of construction and for determining the effects of construction delays. In general the construction costs of nuclear power plants are significantly higher than for coal- or gas-fired plants because of the need to use special materials, and to incorporate sophisticated safety features and backup control equipment. These contribute much of the nuclear generation cost, but once the plant is built the cost variables are minor. About 80% of the overnight cost relates to EPC costs, with about 70% of these consisting of direct costs (physical plant equipment with labour and materials to assemble them) and 30% indirect costs (supervisory engineering and support labour costs with some materials). The remaining 20% of the overnight cost is for contingencies and owners’ costs (essentially the cost of testing systems and training staff).

Financing costs will be dictated by the construction period and the applicable interest charges on debt.

The construction time of a nuclear power plant is usually taken as the duration between the pouring of the first 'nuclear concrete' and grid connection. Long construction periods will push up financing costs, and in the past they have done so very significantly. In Asia construction times have tended to be shorter; for instance the two 1315 MWe ABWR units at Kashiwazaki-Kariwa 6&7 in Japan, which began operating in 1996 and 1997, were built in a little over four years, and 48-54 months is a typical projection for plants today. The last three South Korean reactors not delayed by cabling replacement averaged a construction time of 51 months.

The interest on capital for construction can be an important element of the total capital cost but this depends on the rate of interest and the construction period. For a five-year construction period, a 2004 University of Chicago study shows that the interest payments during construction can be as much as 30% of the overall expenditure. This increases to 40% if applied to a seven-year construction schedule, demonstrating the importance of completing the plant on time. Where investors add a risk premium to the interest charges applied to nuclear plants, the impact of financing costs will be substantial.

An insight into the magnitude of different elements of capital cost was provided by testimony to a Georgia Public Service Commission hearing concerning the Vogtle 3&4 project in June 2014. Here, for Georgia Power’s 45.7% share, the EPC cost was $3.8 billion, owner cost $0.6 billion, and financing cost $1.7 billion (if completed by 2016-17). The cost of possible delayed completion was put at $1.2 million per day. The total cost of the project was expected to be about $14 billion.

The 2016 edition of the World Nuclear Association's World Nuclear Supply Chain report tabulated two breakdowns in capital costs, by activity and in terms of labour, goods and materials:

Design, architecture, engineering and licensing 5% Project engineering, procurement and construction management 7% Construction and installation works: Nuclear island 28% Conventional island 15% Balance of plant 18% Site development and civil works 20% Transportation 2% Commissioning and first fuel loading 5% Total 100%

Equipment Nuclear steam supply system 12% Electrical and generating equipment 12% Mechanical equipment 16% Instrumentation and control system (including software) 8% Construction materials 12% Labour onsite 25% Project management services 10% Other services 2% First fuel load 3% Total 100%

Capital cost escalation

With relatively few nuclear plants constructed in North America and Western Europe over the past two decades, the amount of information on the costs of building modern nuclear plants is somewhat limited. The shift to Generation III reactors has added further uncertainty. Other non-nuclear generation technologies also show variation, as do major infrastructure projects such as roads and bridges, depending upon where they are built. However, the variation is particularly crucial for electricity generation as its economics depend so much on minimising capital investment cost, which must be passed onto consumers, in contrast to roads, bridges and dams which are usually less complex. Large infrastructure projects of all kinds tend to be over budget and late in most parts of the world, according to research by the University of Lincoln (UK) and the European Union's Megaproject.

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 2015 report Projected Costs of Generating Electricity, the overnight costs ranged from $2021/kWe in South Korea to $6215/kWe in Hungary. For China, two comparable figures were $1807/kWe and $2615/kWe. LCOE figures at a 3% discount rate range from $29/MWh in Korea to $64/MWh in the UK, at a 7% discount rate from $40/MWh (Korea) to $101/MWh (UK), and at a 10% rate $51/MWh (Korea) to $136/MWh (UK).

The 2015 NEA report makes the important point regarding LCOE: “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 CCGTs or coal. These results include a carbon cost of $30/tonne, as well as regional variations in assumed fuel costs.”

The US Energy Information Administration (EIA) calculated that, in constant 2002 values, the realized overnight cost of a nuclear power plant built in the USA grew from $1500/kWe in the early 1960s to $4000/kWe in the mid-1970s. The EIA cited increased regulatory requirements (including design changes that required plants to be backfitted with modified equipment), licensing problems, project management problems and misestimation of costs and demand as the factors contributing to the increase during the 1970s. Its November 2016 report, Capital Cost Estimates for Utility Scale Electricity Generation Plants, gave an estimate for a new US nuclear plant of $5945/kW (overnight cost).

There are also significant variations in capital costs by country, particularly between the emerging industrial economies of East Asia and the mature markets of Europe and North America. Variations have a variety of explanations, including: differential labour costs; more experience in the recent building of reactors; economies of scale from building multiple units; and streamlined licensing and project management within large civil engineering projects.

The French national audit body, the Cour des Comptes, said in 2012 that the overnight capital costs of building nuclear power plants increased over time from €1070/kWe (at 2010 prices) when the first of the 58 currently operating PWRs was built at Fessenheim (commissioned in 1978) to €2060/kWe when Chooz 1&2 were built in 2000, and to a projected €3700/kWe for the Flamanville EPR. It can be argued that much of this escalation relates to the smaller magnitude of the programme by 2000 (compared with when the French were commissioning 4-6 new PWRs per year in the 1980s) and the resultant failure to achieve series economies. The French programme also arguably shows that industrial organization and standardization of a series of reactors allowed construction costs, construction time and operating and maintenance costs to be brought under control. The total overnight investment cost of the French PWR programme amounted to less than €85 billion at 2010 prices. When divided by the total installed capacity (63 GW), the average overnight cost is €1335/kW. This is much in line with the costs that were then provided by the manufacturers. In 2019 EDF estimated that the cost of building six EPR2 units in France in the late 2020s would be at least €56 billion, hence around €5700/kW.

In several countries, notably the UK, there is a trend towards greater vendor involvement in financing projects, but with an intention to relinquish equity once the plant is running.

A presentation by Dr N.Barkatullah, UAE Regulation & Supervision, at the World Nuclear Association’s 2014 Symposium showed the risk in construction costs (per kilowatt of capacity), much of it due to financing cost incurred as a result of delays:

The same presentation showed the following ranges of figures for overnight capital cost in different parts of the world:

The IEA-NEA Nuclear Energy Roadmap 2015 estimated China’s average overnight costs of approximately $3,500/kW were more than a third less than that in the EU of $5,500/kW. Costs in the USA were about 10% lower than the EU, but still 30% higher than in China and India, and 25% above South Korea. In its main scenario, 2050 assumptions for overnight costs of nuclear in the USA and EU were estimated to decline somewhat, reaching levels closer to those in South Korea, while costs in Asia were assumed to remain flat.

In China it is estimated that building two identical 1000 MWe reactors on a site can result in a 15% reduction in the cost per kW compared with that of a single reactor.

A 2016 study by The Breakthrough Institute on Historical construction costs of global nuclear power reactors presented new data for overnight nuclear construction costs across seven countries. Some conclusions emerged that are in contrast to past literature. While several countries, notably the USA, show increasing costs over time, other countries show more stable costs in the longer term, and cost declines over specific periods in their technological history. One country, South Korea, experiences sustained construction cost reductions throughout its nuclear power experience. The variations in trends show that the pioneering experiences of the USA or even France are not necessarily the best or most relevant examples of nuclear cost history. These results showed that there is no single or intrinsic learning rate expected for nuclear power technology, nor any expected cost trend. How costs evolve appears to be dependent on several different factors. The large variation in cost trends and across different countries – even with similar nuclear reactor technologies – suggests that cost drivers other than learning-by-doing have dominated the experience of nuclear power construction and its costs. Factors such as utility structure, reactor size, regulatory regime, and international collaboration may have a larger effect. Therefore, drawing any strong conclusions about future nuclear power costs based on one country's experience – especially the US experience in the 1970s and 1980s – would be ill-advised.

Plant operating costs

Operating costs include the cost of fuel and of operation and maintenance (O&M). Fuel cost figures include used fuel management and final waste disposal.

Low fuel costs have from the outset given nuclear energy an advantage compared with coal and gas-fired plants. Uranium, however, has to be processed, enriched and fabricated into fuel elements, accounting for about half of the total fuel cost. In the assessment of the economics of nuclear power, allowances must also be made for the management of radioactive used fuel and the ultimate disposal of this used fuel or the wastes separated from it. But even with these included, the total fuel costs of a nuclear power plant in the OECD are typically about one-third to one-half of those for a coal-fired plant and between one-quarter and one-fifth of those for a gas combined-cycle plant. The US Nuclear Energy Institute suggests that the cost of fuel for a coal-fired plant is 78% of total costs, for a gas-fired plant the figure is 87%, and for nuclear the uranium is about 14% (or 34% if all front end and waste management costs are included).

Front end fuel cycle costs of 1 kg of uranium as UO 2 fuel

Process Amount required x price* Cost Proportion of total Uranium 8.9 kg U 3 O 8 x $68 $605 43% Conversion 7.5 kg U x $14 $105 8% Enrichment 7.3 SWU x $52 $380 27% Fuel fabrication per kg $300 22% Total $1390

* Prices are approximate and as of March 2017.

At 45,000 MWd/t burn-up this gives 360,000 kWh electrical per kg, hence fuel cost = 0.39 ¢/kWh.

Fuel costs are one area of steadily increasing efficiency and cost reduction. For instance, in Spain the cost of nuclear electricity was reduced by 29% over the period 1995-2001. Cost reductions of 40% were achieved by boosting enrichment levels and burn-up. Prospectively, a further 8% increase in burn-up will give another 5% reduction in fuel cost.

Uranium has the advantage of being a highly concentrated source of energy which is easily and cheaply transportable. The quantities needed are very much less than for coal or oil. One kilogram of natural uranium will yield about 20,000 times as much energy as the same amount of coal. It is therefore intrinsically a very portable and tradeable commodity.

The contribution of fuel to the overall cost of the electricity produced is relatively small, so even a large fuel price escalation will have relatively little effect (see below). Uranium is abundant and widely available.

There are other possible savings. For example, if used fuel is reprocessed and the recovered plutonium and uranium is used in mixed oxide (MOX) fuel, more energy can be extracted. The costs of achieving this are large, but are offset by MOX fuel not needing enrichment and particularly by the smaller amount of high-level wastes produced at the end. Seven UO 2 fuel assemblies give rise to one MOX assembly plus some vitrified high-level waste, resulting in only about 35% of the volume, mass and cost of disposal.

This 'back-end' of the fuel cycle, including used fuel storage or disposal in a waste repository, contributes up to 10% of the overall costs per kWh, or less if there is direct disposal of used fuel rather than reprocessing. The $26 billion US used fuel program is funded by a 0.1 cent/kWh levy.

Operation and maintenance (O&M) costs account for about 66% of the total operating cost. O&M may be divided into ‘fixed costs’, which are incurred whether or not the plant is generating electricity, and ‘variable costs’, which vary in relation to the output. Normally these costs are expressed relative to a unit of electricity (for example, cents per kilowatt hour) to allow a consistent comparison with other energy technologies.

Decommissioning costs are about 9-15% of the initial capital cost of a nuclear power plant. But when discounted over the lifetime of the plant, they contribute only a few percent to the investment cost and even less to the generation cost. In the USA they account for 0.1-0.2 cent/kWh, which is no more than 5% of the cost of the electricity produced.

External costs

External costs are not included in the building and operation of any power plant, and are not paid by the electricity consumer, but by the community generally. The external costs are defined as those actually incurred in relation to health and the environment, and which are quantifiable but not built into the cost of the electricity.

The European Commission launched a project, ExternE, in 1991 in collaboration with the US Department of Energy – the first research project of its kind "to put plausible financial figures against damage resulting from different forms of electricity production for the entire EU". The methodology considers emissions, dispersion and ultimate impact. With nuclear energy, the risk of accidents is factored in along with high estimates of radiological impacts from mine tailings (waste management and decommissioning being already within the cost to the consumer). Nuclear energy averages 0.4 euro cents/kWh, much the same as hydro; coal is over 4.0 c/kWh (4.1-7.3), gas ranges 1.3-2.3 c/kWh and only wind shows up better than nuclear, at 0.1-0.2 c/kWh average. NB these are the external costs only. If these costs were in fact included, the EU price of electricity from coal would double and that from gas would increase 30%. These are without attempting to include the external costs of global warming.

A further study commissioned by the European Commission in 2014, and carried out by the Ecofys consultancy, calculated external costs for nuclear as €18-22/MWh, including about €5/MWh for health impacts, €4/MWh for accidents and €12/MWh for so-called ‘resource depletion’, relating to the “costs to society of consumption of finite fuel resources now, rather than in the future”. Although Ecofys acknowledges that the resource depletion cost is difficult to calculate since the scarcity of a finite natural resource is already reflected in its market price, and could therefore just as well be zero, a high estimate was asserted using a questionable methodology and without taking account of the potential for recycling nuclear fuel.

Another report for the European Commission made by Professor William D’haeseleer, University of Leuven, in November 2013, estimated the cost of a potential nuclear accident to be in the range of €0.3-3.0/MWh.

Pricing of external benefits is limited at present. As fossil fuel generators begin to incur real costs associated with their impact on the climate, through carbon taxes or emissions trading regimes, the competitiveness of new nuclear plants will improve. This is particularly so where the comparison is being made with coal-fired plants, but it also applies, to a lesser extent, to gas-fired equivalents.

The likely extent of charges for carbon emissions has become an important factor in the economic evaluation of new nuclear plants, particularly in the EU where an emissions trading regime has been introduced but which is yet to reflect the true costs of carbon emissions. Prices have stayed relatively low within the national and sub-national jurisdictions that currently put a price on carbon emissions. In the EU, since 2013, the European Union Allowance price stagnated around €5-9/tCO 2 to the end of 2017, but has since tripled. The EU considered reforming the Emissions Trading System to ensure more stable and higher permit prices needed to support the delivery of its 1990-2030 greenhouse gas emissions reduction target of 40%.

An analysis by the Brattle Group in 2016 showed that zero-emission credits for nuclear power could secure the economic viability of nuclear plants in competition with subsidised renewables and low-cost gas-fired plants. It said: "A typical revenue deficit for a vulnerable nuclear power plant is around $10/MWh," which is equivalent to costing "the avoided CO 2 emissions... between $12 and $20 per ton of CO 2 , varying with the regional fossil fuel mix that would substitute for the plant." It said: "This cost compares favorably with other carbon abatement options such as state policies designed to reduce CO 2 emissions from the power sector, as well as with many estimates of the social cost of carbon."

“These findings demonstrate that the retention of existing nuclear generating plants, even at a modest operating cost recovery premium for a limited period, represents a cost-effective method to avoid CO 2 emissions in the near term and would enable compliance with any future climate policy at a reasonable cost. Sustaining nuclear viability in the interim is a reasonable and cost-effective insurance policy in the longer term.”

Under New York's Clean Energy Standard (CES), zero-emission credits (ZEC) will be implemented in six tranches over a period of 12 years starting April 2017. For the first two-year period nuclear generators received ZECs of $17.54/MWh, paid by the distribution utilities (and hence eventually ratepayers) but otherwise similar to the federal production tax credits applying to renewables since 1993 on an inflation-adjusted basis, though at a lower rate than its $23/MWh for wind. ZECs would escalate to $29.15/MWh over subsequent years.

The NY Public Service Commission on 1 August 2016 approved the Clean Energy Standard. The majority vote was reported to be on three main criteria: grid reliability, reducing carbon emissions, and maintaining jobs. The governor’s announcement stated: “A growing number of climate scientists have warned that if these nuclear plants were to abruptly close, carbon emissions in New York will increase by more than 31 million metric tons during the next two years, resulting in public health and other societal costs of at least $1.4 billion.”

In Illinois, in December 2016 the Future Energy Jobs Bill was passed, with a core feature being the establishment of the Zero Emission Standard (ZES) to preserve the state’s at-risk nuclear plants, saving 4,200 jobs, retaining $1.2 billion of economic activity annually and avoiding increases in energy costs. The bill provided ZECs similar to those in New York – "a tradable credit that represents the environmental attributes of one megawatt hour of energy produced from a zero emission facility" (such as the nuclear power plants which supply about 90% of the state’s zero-carbon electricity). It will provide up to $235 million annually to support two plants – 2,884 MWe net capacity – for ten years.

For more information on ZEC programmes established elsewhere in the USA, see Nuclear Power in the USA.

Other costs

In order to provide reliable electricity supply, there must be reserve capacity to cover refuelling or maintenance downtime in plants which are producing most of the time, and also provision must be made for backup generation for intermittent wind and solar plants at times when they are unable to operate. Provision must also be made to transmit the electricity from where it is generated to where it is needed. The costs incurred in providing backup and transmission/distribution facilities are known as system costs.

System costs are external to the building and operation of any power plant, but must be paid by the electricity consumer, usually as part of the transmission and distribution cost. From a government policy point of view they are just as significant as the actual generation cost, but are seldom factored into comparisons of different supply options, especially comparing base-load with dispersed intermittent renewables such as solar and wind. In fact the total system cost should be analysed when introducing new power generating capacity on the grid. Any new power plant likely requires changes to the grid, and hence incurs a significant cost for power supply that must be accounted for. But this cost for large plants operating continuously to meet base-load demand is very small compared with integrating intermittent renewables into the grid.

For nuclear and fossil fuel generators, system costs relate mainly to the need for reserve capacity to cover periodic outages, whether planned or unplanned. The system costs associated with intermittent renewable generation relate to their inability to generate electricity without the required weather conditions and their generally dispersed locations distant from centres of demand.

The integration of intermittent renewable supply on a preferential basis despite higher unit cost creates significant diseconomies for dispatchable supply, as is now becoming evident in Germany, Austria and Spain, compromising security of supply and escalating costs. At anything approaching a 40% share of electricity being from intermittent renewable energy, the capital cost component of power from conventional thermal generation sources increases substantially as their capacity factor decreases – the utilisation effect. This has devastated the economics of some gas-fired plants in Germany, for instance.

In some countries, market design results in a market failure wherby 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, meaning 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 overall cost competitiveness of nuclear, as measured on a levelised basis (see figure below on Comparative LCOEs and System Costs in Four Countries), is much enhanced by its modest system costs. However, the impact of intermittent electricity supply on wholesale markets has a profound effect on the economics of base-load generators, including nuclear, that is not captured in the levelised cost comparisons given by the International Energy Agency (IEA) - Nuclear Energy Agency (NEA) reports. The negligible marginal operating costs of wind and solar mean that, when climatic conditions allow generation from these sources, they undercut all other electricity producers. At high levels of renewable generation, for example as implied by the EU’s 30% renewable penetration target, the nuclear capacity factor is reduced and the volatility of wholesale prices greatly increases whilst the average wholesale price level falls. The increased penetration of intermittent renewables thereby greatly reduces the financial viability of nuclear generation in wholesale markets where intermittent renewable energy capacity is significant. See also Electricity markets section below.

The integration of intermittent renewables with conventional base-load generation is a major challenge facing policymakers in the EU, in certain US states and elsewhere. Until this challenge is resolved, e.g. by the introduction of long-term capacity markets or power purchase agreements, then investment in base-load generation capacity in these markets is likely to remain insufficient. 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 externalised. 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.

A 2019 OECD Nuclear Energy Agency study, The Costs of Decarbonisation: System Costs With High Shares of Nuclear and Renewables, found that the integration of large shares of intermittent renewable electricity is a major challenge for the electricity systems of OECD countries and for dispatchable generators such as nuclear. Grid-level system costs for intermittent renewables are large ($8-$50/MWh) but depend on country, context and technology (onshore wind < offshore wind < solar PV). Nuclear system costs are $1-3/MWh.

See also paper on Electricity Transmission Grids.

Nuclear-specific taxes are levied in several EU countries. In 2014 Belgium raised some €479 million from a €0.005/kWh tax. In July 2015, Electrabel agreed to pay €130 million tax for the year 2016, alongside a fee for the operating lifetime extension of Doel 1&2 (€20 million/yr). From 2017 onwards, a formula applies for calculating tax contributions, with a minimum of €150 million per year.

In 2000 Sweden introduced a nuclear-specific tax on installed capacity, which gradually increased over time; in 2015, the tax raised about €435 million. In June 2016 the Swedish government, amid growing concerns over the continued viability of existing plants, agreed to phase out the tax on nuclear power from 2017 onwards.

In Germany, a tax was levied on nuclear fuel that required companies to pay per gram of fuel used over six years to 2016. After various court rulings, in June 2017 the Federal Constitutional Court finally ruled that the nuclear fuel tax was “formally unconstitutional and void,” which meant that the three major utilities could be reimbursed some €6.3 billion paid between 2011 and 2016 – €2.8 billion by E.On, €1.7 billion by RWE and €1.44 billion by EnBW, plus interest.

The UK imposes a Climate Change Levy, which continues to 2023. It is a downstream tax on energy delivered to non-domestic users in the UK introduced in 2001. Initially levied against fossil fuels and nuclear, the government removed renewables' exemption in its July 2015 Budget. In 2011 the government introduced a carbon floor price – a mechanism that has long been seen as fundamental to the economics of new UK nuclear power. The government set a minimum of £16 per tonne CO 2 from 2013, rising steadily to £30 per tonne in 2020, and £70 per tonne in 2030.

See also paper on Energy subsidies and external costs.

Electricity markets

The economics of any power generation depends primarily on what each unit (kWh, MWh) costs to produce for the consumer who creates the demand for that power. This is the LCOE as outlined above. But secondly it depends on the market into which the power is sold, where the producer and grid operator run into a raft of government policies often coupled with subsidies for other sources. Such policies raise the question of what public good is served by each, and whether overall the public good is optimised. Where the outcome is not maximising public good effectively, there is market failure.*

* This section draws heavily on the Nuclear Economics Consulting Group webpage on Market Failure.

A market can work well to achieve its stated objectives, but still result in market failure. This is often explained by externalities – negative or positive impacts of an industry – that are not reflected in the market. With electricity, the direct (private) costs of generating power at the plant do not usually include the external costs (e.g. emissions, system costs due to intermittent operation, land use, noise) nor do they account for the benefits of positive externalities (e.g. knock-on economic activity from jobs, system reliability, fuel diversity).

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. An electricity market with efficient short-term spot prices should not be expected to achieve other objectives such as lower emissions, long-term system reliability, or implementation of national policy.

Merchant generating plants rely on selling power into a commodity market which is shaped by policies including those which may favour particular sources of power regardless of their immediate and longer-term deficiencies in relation to the public good. (Generating plants in a regulated or government-owned electricity industry can deliver power essentially on a cost-plus basis, with regulators or governments able to reflect externalities in decisions.) Nuclear power plants provide a range of benefits to society that are not compensated in the commodity electricity market revenue stream. These public benefits include emission-free electricity, long-term reliable operation, system stability, system fuel diversity and fuel price hedging, as well as economic benefits from employment.

Generic approaches to fix market failure include imposing costs on negative externalities such as CO 2 emissions, providing compensation to support positive externalities, and government ownership of sectors likely to experience market failure. Some US states make zero emission credit (ZEC) payments to nuclear generation to reward the positive externalities. ZECs are similar to the production tax credits applying to wind power, though lower, but are based directly on estimated emission benefits. They mean that the value of nuclear electricity can be greater than the LCOE cost of producing it in markets strongly influenced by low gas prices and subsidies on intermittent wind generation which has market priority. Without the ZEC payments, nuclear operation may not be viable in this situation.

Comparing the economics of different forms of electricity generation

In 2017 the US EIA published figures for the average levelised costs per unit of output (LCOE) for generating technologies to be brought online in 2022, as modelled for its Annual Energy Outlook. These show: advanced nuclear, 9.9 c/kWh; natural gas, 5.7-10.9 c/kWh (depending on technology); and coal with 90% carbon sequestration, 12.3 c/kWh (rising to 14 c/kWh at 30%). Among the non-dispatchable technologies, LCOE estimates vary widely: wind onshore, 5.2 c/kWh; solar PV, 6.7 c/kWh; offshore wind, 14.6 c/kWh; and solar thermal, 18.4 c/kWh.

The 2015 edition of the OECD study on Projected Costs of Generating Electricity showed that the range for the levelised cost of electricity (LCOE) varied much more for nuclear than coal or CCGT with different discount rates, due to it being capital-intensive. The nuclear LCOE is largely driven by capital costs. At 3% discount rate, nuclear was substantially cheaper than the alternatives in all countries, at 7% it was comparable with coal and still cheaper than CCGT, at 10% it was comparable with both. At low discount rates it was much cheaper than wind and PV. Based on a 0% discount rate, LCOE for nuclear soared to three times as much as the 10% discount rate, while that for coal was 1.4 times and for CCGT it changed very little. Solar PV increased 2.25 times and onshore wind nearly twice at 10% discount rate, albeit with very different capacity factors to the 85% for the three base-load options. For all technologies, a $30 per tonne carbon price was included. LCOE figures omit system costs.

Comparative LCOEs and system costs in four countries (2014 and 2012)*

* LCOE plant costs have been taken from Projected Costs of Generating Electricity 2015 Edition. System costs have been taken from Nuclear Energy and Renewables (NEA, 2012). A 30% generation penetration level for onshore wind, offshore wind and solar PV has been assumed in the NEA estimates of system costs, which include back-up costs, balancing costs, grid connection, extension and reinforcement costs. A discount rate of 7% is used throughout, which is therefore consistent with the plant level LCOE estimates given in the 2015 edition of Projected Costs of Generating Electricity. The 2015 study applies a $30/t CO 2 price on fossil fuel use and uses 2013 US$ values and exchange rates.

Projected nuclear LCOE costs for plants built 2015-2020, $/MWh

Country At 3% discount rate At 7% discount rate At 10% discount rate Belgium 51.5 84.2 116.8 Finland 46.1 77.6 109.1 France 50.0 82.6 115.2 Hungary 53.9 89.9 125.0 Japan 62.6 87.6 112.5 South Korea 28.6 40.4 51.4 Slovakia 53.9 84.0 116.5 UK 64.4 100.8 135.7 USA 54.3 77.7 101.8 China 25.6-30.8 37.2-47.6 48.8-64.4

Overnight capital costs for nuclear technologies in OECD countries ranged from $2021/kWe of capacity (in South Korea) to $6215/kWe (in Hungary) in the 2015 edition of Projected Costs of Generating Electricity.

Rosatom claimed in November 2015 that due to its integrated structure, the LCOE of new VVERs exported is no more than $50-$60/MWh in most countries.

A November 2018 report from Lazard compared the LCOE for various generation technologies on the basis of its estimates, related to input from "a wide variety of industry participants". For nuclear power (2200 MWe plant), capital cost including financing (at a high discount rate) ranged from $6500 to $12,250 per kilowatt, and the LCOE accordingly varied from $112 to $189/MWh. For a 600 MWe coal plant the capital cost ranged from $3000 to $8400/kW, giving a LCOE of $60 to $143/MWh. Gas combined cycle (550 MWe) capital cost was $700 to $1300/kW and LCOE $41 to $74/MWh. The purpose of the study was to compare these figures with 'alternative energy technologies', particularly wind and solar PV, but without taking account of system costs. The nuclear costs estimated by Lazard were well above those in the IEA-NEA study based on existing projects, with well-referenced data.

The impact of varying the uranium price in isolation is shown below in a worked example of a typical US plant, assuming no alteration in the tails assay at the enrichment plant.

Effect of uranium price on fuel cost

Doubling the uranium price (say from $25 to $50 per lb U3O8) takes the fuel cost up from 0.50 to 0.62 US c/kWh, an increase of one quarter, and the expected cost of generation of the best US plants from 1.3 c/kWh to 1.42 c/kWh (an increase of almost 10%). So while there is some impact, it is minor, especially by comparison with the impact of gas prices on the economics of gas generating plants. In these, 90% of the marginal costs can be fuel. Only if uranium prices rise to above $100 per lb U3O8 ($260 /kgU), and stay there for a prolonged period (which seems very unlikely), will the impact on nuclear generating costs be considerable.

Nevertheless, for nuclear power plants operating in competitive power markets where it is impossible to pass on any fuel price increases (i.e. the utility is a price-taker), higher uranium prices will cut corporate profitability. Yet fuel costs have been relatively stable over time – the rise in the world uranium price between 2003 and 2007 added to generation costs, but conversion, enrichment and fuel fabrication costs did not follow the same trend.

For prospective new nuclear plants, the fuel component is even less significant (see below). The typical front end nuclear fuel cost is typically only 15-20% of the total, as opposed to 30-40% for operating nuclear plants.

Competitiveness in the context of increasing use of power from renewable sources, which are often given preference and support by governments, is a major issue today. The most important renewable sources are intermittent by nature, which means that their supply to the electricity system does not necessarily match demand from customers. In power grids where renewable sources of generation make a significant contribution, intermittency forces other generating sources to ramp up or power down their supply at short notice. This volatility can have a large impact on non-intermittent generators’ profitability. A variety of responses to the challenge of intermittent generation are possible. Two options currently being implemented are increased conventional plant flexibility and increased grid capacity and coverage. Flexibility is seen as most applicable to gas- and coal-fired generators, but nuclear reactors, normally regarded as base-load producers, also have the ability to load-follow (e.g. by the use of ‘grey rods’ to modulate the reaction speed).

As the scale of intermittent generating capacity increases however, more significant measures will be required. The establishment and extension of capacity mechanisms, which offer payments to generators prepared to guarantee supply for defined periods, are now under serious consideration within the EU. Capacity mechanisms can in theory provide security of supply to desired levels but at a price which might be high. For example, Morgan Stanley has estimated that investors in a 800 MWe gas plant providing for intermittent generation would require payments of €80 million per year whilst Ecofys reports that a 4 GWe reserve in Germany would cost €140-240 million/year. Almost by definition, investors in conventional plants designed to operate intermittently will face low and uncertain load factors and will therefore demand significant capacity payments in return for the investment decision. In practice, until the capacity mechanism has been reliably implemented, investors are likely to withhold investment. Challenges for EU power market integration are expected to result from differences between member state capacity mechanisms.

The 2014 Ecofys report for the European Commission on subsidies and costs of EU energy purported to present a complete and consistent set of data on electricity generation and system costs, as well external costs and interventions by governments to reduce costs to consumers. The report attributed €6.96 billion to nuclear power in the EU in 2012, including €4.33 billion decommissioning costs (shortfall from those already internalised). Geographically the total broke down to include EU support of €3.26 billion, and UK €2.77 billion, which was acknowledged as including military legacy clean-up. Consequently there are serious questions about the credibility of such figures.

Economic implications of particular plants

Apart from considerations of cost of electricity and the perspective of an investor or operator, there are studies on the economics of particular generating plants in their local context.

Early in 2015 a study, Economic Impacts of the R.E. Ginna Nuclear Power Plant, was prepared by the US Nuclear Energy Institute. It analyzes the impact of the 580 MWe PWR plant’s operations through the end of its 60-year operating licence in 2029. It generates an average annual economic output of over $350 million in western New York State and an impact on the U.S. economy of about $450 million per year. Ginna employs about 700 people directly, adding another 800 to 1,000 periodic jobs during reactor refueling and maintenance outages every 18 months. Annual payroll is about $100 million. Secondary employment involves another 800 jobs. Ginna is the largest taxpayer in the county. Operating at more than 95% capacity factor, it is a very reliable source of low-cost electricity. Its premature closure would be extremely costly to both state and country – far in excess of the above figures.

In June 2015 a study, Economic Impacts of the Indian Point Energy Center, was published by the US Nuclear Energy Institute, analyzing the economic benefits of Entergy’s Indian Point 2&3 reactors in New York state (1020 and 1041 MWe net). It showed that they annually generate an estimated $1.6 billion in the state and $2.5 billion across the nation as a whole. This includes about $1.3 billion per year in the local counties around the plant. The facility contributes about $30 million in state and local property taxes and has an annual payroll of about $140 million for the plant’s nearly 1,000 employees. The total tax benefit to the local, state and federal governments from the plant is about $340 million per year, and the plant’s direct employees support another 5,400 indirect jobs in New York state and 5,300 outside it. It also makes a major contribution to grid reliability and prevents the release of 8.5 million tonnes of CO 2 per year.

In September 2015 a Brattle Group report said that the five nuclear facilities in Pennsylvania contribute $2.36 billion annually to the state's gross domestic product and account for 15,600 direct and secondary full-time jobs.

Future cost competitiveness

Understanding the cost of new generating capacity and its output requires careful analysis of what is in any set of figures. There are three broad components: capital, finance, and operating costs. Capital and financing costs make up the project cost.

Calculations of relative generating costs are made using estimates of the levelised cost of electricity (LCOE) for each proposed project. The LCOE represents the price that the electricity must fetch if the project is to break even (after taking account of all lifetime costs, inflation and the opportunity cost of capital through the application of a discount rate). It is useful from an investor's point of view. But LCOE does not take account of the system costs of integrating output into a grid to meet demand, and is therefore a very poor metric for comparing dispatchable generation (coal, gas, nuclear) with intermittent renewables (wind, solar) from any policy perspective. System costs escalate greatly with increasing share of intermittent renewables.

This is partly addressed by the International Energy Agency in its World Energy Outlook 2018 by introducing value-adjusted LCOE (VALCOE), which combines LCOE with energy, flexibility and capacity values, enabling a better comparison of the overall value and competitiveness among technologies from the perspective of planners and policymakers. However, it still omits important aspects of system costs such as grid integration.

A 2019 report from the OECD's Nuclear Energy Agency, The Costs of Decarbonisation: System Costs with High Shares of Nuclear and Renewables, probes the system cost question more fully. It works within a very tight 50g CO 2 per kWh emission constraint for electricity, as required to achieve the targets to combat climate change under the 2016 Paris Agreement. Nuclear power is the mainstay meeting base-load demand in the 98 GWe base case model system. The report points out that the variability of wind and solar PV production imposes costly adjustments on the residual system, and these system costs are currently not properly recognised in any electricity market. They are simply borne by the system in a way that makes sensible policy formulation virtually impossible.

"The most important categories of system costs of VREs are increased outlays for distribution and transmission due to their small unit size and distance from load centres, balancing costs to prepare for unpredictable changes in wind speed and solar radiation and, perhaps, most importantly, technologies and costs for organising reliable supplies through the residual system during the hours when wind and sun are not fully available or not available at all." System costs rise from less than $10/MWh for 10% wind and solar to more than $50/MWh for a 75% wind/solar share, or a 50% share under some circumstances.

It is important to note that capital cost figures quoted by reactor vendors, or which are general and not site-specific, will usually just be for EPC costs. This is because owners’ costs will vary hugely, most of all according to whether a plant is greenfield or at an established site, perhaps replacing an old plant.

There are several possible sources of variation which preclude confident comparison of overnight or EPC capital costs – e.g. whether initial core load of fuel is included. Much more obvious is whether the price is for the nuclear island alone (nuclear steam supply system) or the whole plant including turbines and generators. Further differences relate to site works such as cooling towers as well as land and permitting – usually they are all owners’ costs as outlined earlier in this section. Financing costs are additional, adding typically around 30%, dependent on construction time and interest rate. Finally there is the question of whether cost figures are in current (or specified year) dollar values or in those of the year in which spending occurs.

Major studies on future cost competitiveness

There have been many studies carried out examining the economics of future generation options, and the following are merely the most important and also focus on the nuclear element.

The 2015 edition of the OECD study on Projected Costs of Generating Electricity considered the cost and deployment perspectives for small modular reactors (SMRs) and Generation IV reactor designs – including very high temperature reactors and fast reactors – that could start being deployed by 2030. Although it found that the specific per-kWe costs of SMRs are likely to be 50% to 100% higher than those for large Generation III reactors, these could be offset by potential economies of volume from the manufacture of a large number of identical SMRs, plus lower overall investment costs and shorter construction times that would lower the capital costs of such plants. "SMRs are expected at best to be on a par with large nuclear if all the competitive advantages … are realised," the report noted.

A May 2016 draft declaration related to the European Commission Strategic Energy Technology plan lists target LCOE figures for the latest generation of light-water reactors (LWRs) 'first-of-a-kind' new-build twin reactor project on a brownfield site: EUR(2012) €48/MWh to €84/MWh, falling to €43/MWh to €75/MWh for a series build (5% and 10% discount rate). The LCOE figures for existing Gen-II nuclear power plants integrating post-Fukushima stress tests safety upgrades following refurbishment for extended operation (10-20 years on average): EUR (2012) €23/MWh to €26/MWh (5% and 10% discount rate).

Nuclear overnight capital costs in OECD ranged from US$ 1,556/kW for APR-1400 in South Korea through $3,009/kW for ABWR in Japan, $3,382/kW for Gen III+ in USA, $3,860/kW for EPR at Flamanville in France to $5,863/kW for EPR in Switzerland, with a world median of $4,100/kW. Belgium, Netherlands, Czech Republic and Hungary were all over $5,000/kW. In China overnight costs were $1,748/kW for CPR-1000 and $2,302/kW for AP1000, and in Russia $2,933/kW for VVER-1150. EPRI (USA) gave $2,970/kW for APWR or ABWR, Eurelectric gave $4,724/kW for EPR. OECD black coal plants were costed at $807-2,719/kW, those with carbon capture and compression (tabulated as CCS, but the cost not including storage) at $3,223-5,811/kW, brown coal $1,802-3,485, gas plants $635-1,747/kW and onshore wind capacity $1,821-3,716/kW. (Overnight costs were defined here as EPC, owners' costs and contingency, but excluding interest during construction).

OECD electricity generating cost projections for year 2015 on – 5% discount rate, c/kWh

country nuclear coal Gas CCGT Belgium 6.6 7.7 10.4 Czech R - - - France 6.5 - 9.5 Germany - 7.1 10.4 Hungary 7.0 - 9.9 Japan 7.4 10.1 13.6 Korea 3.4 7.9 12.0 Netherlands - 8.3 9.9 Slovakia 6.7 - - Switzerland - - - USA 6.5 8.8 6.3 China* 3.5 8.0 9.1 Russia* - - -

At a 5% discount rate comparative costs are as shown above. Nuclear is comfortably cheaper than coal and gas in all countries (with the exception of gas in the USA). At a 10% discount rate (see below) nuclear is still cheaper than coal in the majority of estimates, but gas proves cheaper in all countries apart from Japan and China.

OECD electricity generating cost projections for 2015 on – 10% discount rate, c/kWh

country nuclear coal Gas CCGT Belgium 11.6 9.4 10.6 Czech R - - - France 11.5 - 10.1 Germany - 8.5 10.6 Hungary 12.5 - 10.5 Japan 11.3 11.9 14.3 Korea 4.2-4.8 7.1-7.4 - Netherlands 10.5 10.0 - Slovakia 11.6 - - Switzerland - - - USA 10.2 10.4 7.1 China* 5.7 8.2 9.5 Russia* - - -

In 2013 the Nuclear Energy Institute (NEI) announced the results of its financial modelling of comparative costs in the USA, based on figures from the US EIA’s 2013 Annual Energy Outlook. The NEI assumed 5% cost of debt, 15% return on equity and a 70/30 debt/equity capital structure. The figures are tabulated below. The report went on to show that with nuclear plant licence renewal beyond 60 years, power costs would be $53-60/MWh.

NEI 2013 Financial Modelling

EPC cost capacity Electricity cost Gas combined cycle, gas @ $3.70/GJ $1000/kW 90% $44.00/MWh Gas combined cycle, gas @ $5.28/GJ $1000/kW 90% $54.70/MWh Gas combined cycle, gas @ $6.70/GJ $1000/kW 90% $61.70/MWh Gas combined cycle, gas @ $6.70/GJ, 50-50 debt-equity $1000/kW 90% c $70/MWh Supercritical pulverised coal, 1300 MWe $3000/kW 85% $75.70/MWh Integrated gasification combined cycle coal, 1200 MWe $3800/kW 85% $94.30/MWh Nuclear, 1400 MWe (EIA's EPC figure) $5500/kW 90% $121.90/MWh Nuclear, 1400 MWe (NEI suggested EPC figure) $4500-5000/kW 90% $85-90/MWh Wind farm, 100 MWe $1000/kW 30% 112.90/MWh

In mid-2015 the NEI published figures from the Institute for Energy Research (IER) report The Levelized Cost of Electricity from Existing Generation Resources, including the finding that nuclear energy had the lowest average costs of electricity for operating facilities. For new plants, it showed nuclear at just over $90/MWh, compared with coal almost $100/MWh and gas just over $70/MWh.

The China Nuclear Energy Association estimated in May 2013 that the construction cost for two AP1000 units at Sanmen are CNY 40.1 billion ($6.54 billion), or 16,000 Yuan/kW installed ($2615/kW) – about 20% higher than that of improved Generation II Chinese reactors, but likely to drop to about CNY 13,000/kW ($2120/kW) with series construction and localisation as envisaged. Grid purchase price is expected to exceed CNY 0.45/kWh at present costs, and drop to 0.43/kWh with reduced capital cost.

Advanced reactors study

A peer-reviewed study in 2017, undertaken by the Energy Innovation Reform Project (EIRP), with data collection and analysis conducted by the Energy Options Network (EON) on its behalf, compiled extensive data from eight advanced nuclear companies that are actively pursuing commercialization of plants of at least 250 MWe in size. Individual reactor units ranged from 48 MWe to 1650 MWe.

At the lower end of the potential cost range, these plants could present the lowest cost generation options available, making nuclear power “effectively competitive with any other option for power generation. 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 were Elysium Industries, GE Hitachi (using only publicly available information), Moltex Energy, NuScale Power, Terrestrial Energy, ThorCon Power, Transatomic Power, and X‐energy. LCOE ranged 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.

Financing new nuclear power plants

For more detail on financing, please see Financing Nuclear Energy information paper.

There are a range of possibilities for financing, from direct government funding with ongoing ownership, vendor financing (often with government assistance), utility financing and the Finnish Mankala model for cooperative equity. Some of the cost is usually debt financed. The models used will depend on whether the electricity market is regulated or liberalised.

Apart from centrally-planned economies, many projects have some combination of government financial incentives, private equity and long-term power purchase arrangements. The increasing involvement of reactor vendors is a recent development.

Providing investment incentives

The economic rationale for electricity from any plants with high capital cost and long life does not translate into incentive for investment unless some long-term electricity price is assured. This has been tackled differently in various countries.

As more electricity markets become deregulated and competitive, balancing supply and demand over the short-term can result in significant price volatility. Price signals in the spot market for electricity supply do not provide a guide on the return that might be achieved over the long-term, and fail to create an incentive for long-term investment in generation or transmission infrastructure, nor do they value diversity of supply. This issue was addressed in a February 2015 World Nuclear News editorial.

Deregulated electricity markets with preferential grid access for renewables have left some utilities with stranded assets, which can no longer be used sufficiently fully to be profitable. As a result, many are being decommissioned, e.g. about 9 GWe by E.On and RWE in Germany to 2013, and a further 7.3 GWe expected there (apart from nuclear capacity).

In the USA, investment in new capital-intensive plant is going ahead only in states where cost-recovery can be assured. Proposed merchant plants in deregulated areas such as Texas and some eastern states have been postponed indefinitely.

In Ontario, Canada, the refurbishment of Bruce A 1&2 was underwritten by a power purchase agreement (PPA) at about $63/MWh, slightly higher than the regulated price. The refurbishment of Bruce A 3&4 (1,500 MWe) from 2016 and the approximately $8 billion needed for the Bruce B units (3,480 MWe) from 2020 is likely to be underwritten similarly with PPAs.

In the UK, legislation from 2013 has three main elements:

Feed-in tariffs (FIT), now relatively common in several countries, give particular low-carbon producers a predictable return per kWh over a set period regardless of prevailing market prices. The FIT can take several forms. In the UK it will be effected through contracts for difference (CfD) which are financial hedge contracts linked to the wholesale market to remove long-term exposure to electricity price volatility. The FIT with CfD means that if the market price is lower that the agreed ‘strike price’, the government or the transmission system operator (TSO) pays that difference per kWh, whilst if the market is above the strike price the generator pays the TSO or government. They are long-term contracts which can be capped regarding quantity of power, helping developers secure the large upfront capital costs for low-carbon infrastructure while protecting consumers from rising energy bills. The first strike prices were published in the 2013-18 Delivery Plan: £155/MWh for offshore wind, £100/MWh for onshore wind and £125/MWh for large solar PV.

A floor price for ‘carbon’ to support de-carbonisation. The idea is that a carbon floor price will drive the market towards any FIT or strike price level applied to clean sources.

Capacity market measures will be introduced. These involve payments for dispatchable capacity maintained to ensure that demand can be met regardless of short-term conditions affecting other generators. They will work through penalties and availability payments to provide incentive for generators to be available when needed, in effect paying for reliability. The first capacity auction was late in 2014, for delivery during winter 2018-19.

In October 2013 the UK government announced that initial agreement had been reached with EDF Group on the key terms of a proposed £16 billion investment contract for the Hinkley Point C nuclear power station. The key terms include a 35-year CfD, the strike price of £89.50 /MWh being fully indexed to the Consumer Price Index and conditional upon the Sizewell C project proceeding. If it does not for any reason, and the developer cannot share first-of-a-kind costs across both, the strike price is to be £92.50/MWh.

In 2018 the UK government announced that it was considering a regulated asset base (RAB) model for future nuclear power plant projects as an alternative to CfDs. Under a RAB model, the UK government would provide a plant owner with regulated rates that can be adjusted to guarantee that its costs are covered. The RAB model allows the owner of a regulated operation to collect an authorised return on the asset's value that includes operating costs and profit. It protects the operator of a facility by ensuring that the operator has sufficient revenue to maintain its financial capability over a period. It is similar to the US rate base model but with greater flexibility on the part of the UK market regulator to determine what is 'reasonable'. This would be the basis of a feed-in tariff (FIT), but how that might relate to the liberalized UK electricity market with short-term price setting is unclear. The RAB model started out as a way of calculating what a fair and reasonable price would be in a monopoly situation. RAB models have been used widely for major infrastructure projects across the UK, but not in the power sector following market deregulation. In July 2018, the UK government and Kepco agreed to carry out a joint feasibility study on the RAB model.

In Turkey, in order to secure investment in the 4x1200 MWe Akkuyu nuclear power plant, a formula for long-term power prices was worked out. This involves the Turkish Electricity Trade & Contract Corporation (TETAS) buying a fixed proportion of the power at a fixed price of US$ 123.50/MWh for 15 years, or to 2030. The proportion will be 70% of the output of the first two units and 30% of that from units 3&4 over 15 years from commercial operation of each. Rosatom will initially have full ownership of the project company, on a build-own-operate basis, and hopes to reduce that to 51%.

Notes & references

OECD International Energy Agency and OECD Nuclear Energy Agency, Projected Costs of Generating Electricity, 2010 Edition

OECD International Energy Agency and OECD Nuclear Energy Agency, Projected Costs of Generating Electricity, 2015 Edition

International Energy Agency, World Energy Outlook 2018

The Costs of Decarbonisation: System Costs with High Shares of Nuclear and Renewables, OECD Nuclear Energy Agency (2019)

OECD Nuclear Energy Agency (2012), Nuclear Energy and Renewables: System Effects in Low-carbon Electricity Systems

US Energy Information Administration, 2013, Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013

Nuclear Energy Institute, US generating cost data

Tarjanne, R & Rissanen, S, 2000, Nuclear Power: Least-cost option for base-load electricity in Finland; in Proceedings 25th International Symposium, Uranium Institute

Gutierrez, J 2003, Nuclear Fuel – key for the competitiveness of nuclear energy in Spain, WNA Symposium

University of Chicago, August 2004, The Economic Future of Nuclear Power

Nuclear Energy Institute, August 2008, The cost of new generating capacity in perspective

Richard Myers, Feb 2013, Nuclear Energy in 2013: Status and Outlook, Remarks to NEI’s License Renewal Workshop

Direction Générale de l'Energie et du Climat, 2008, Synthèse publique de l'étude des coûts de référence de la production électrique

ExternE website

Xu Yuming, May 2013, China’s Nuclear Power Development in Post-Fukushima Era, CNEA.

Ron Cameron, OECD/NEA, July 2013 presentations to Australian Academy of Technological Sciences & Engineering conference in Sydney

Nuclear Energy Institute presentation to financial markets, February 2014

Nadira Barkatullah, Financing Nuclear Power Projects: Challenges and Approaches, World Nuclear Association 2014 Symposium

Ecofys, Subsidies and Costs of EU Energy, Project number: DESNL14583, November 2014

Jessica Lovering, Arthur Yip, Ted Nordhaus, Historical construction costs of global nuclear power reactors, Energy Policy, 91, p371-382 (April 2016)

Nuclear Power Economics and Project Structuring, World Nuclear Association, January 2017

Lion Hirth, Falko Ueckerdt and Ottmar Edenhofer, Integration Costs Revisited – An Economic Framework for Wind and Solar Variability, Renewable Energy, 74, p925-939 (2015)

Dan Yurman, Study Finds Advanced Reactors Will Have Competitive Costs, Neutron Bytes (26 July 2017)

Edward Kee, Commentary #24 – Government Support, Nuclear Economics Consulting Group (17 December 2018)