Nuclear new-build: subsidies

The role of carbon prices

21 January 2011

It is quite obvious that a price on carbon emissions has an impact on the competitiveness of nuclear power generation compared with the generation of electricity with fossil fuels, in particular coal. However, the magnitude of that impact is still imperfectly understood and it can vary depending on the form of carbon pricing. By Ron Cameron and Jan-Horst Keppler

Essentially, one can distinguish three different forms of carbon pricing:

  • Carbon emission trading with free allocation of permits (‘grandfathering’);
  • Carbon emission trading with auctioning of permits;
  • A flat tax on carbon emissions.

Emission trading with free allocation is distinguished from the other two options by the fact that it leaves substantial surplus profits (rents) with the operators of fossil-fuel plants. A flat tax on carbon emissions instead is distinguished from emission trading by the stability of the cost differential that it imposes on operators. As is well known, the stability of profits per unit of output (i.e. per unit revenues minus variable costs) is vital for the competitiveness of capital-intensive technologies such as nuclear energy. Following up on these two factors, the present article will provide an indication of the order of magnitude of the impact of different forms carbon pricing on the competitiveness of nuclear energy. A systematic study of these issues, ‘Carbon Pricing and Nuclear Power Development,’ is currently under way at the OECD Nuclear Energy Agency for publication in 2011.

The key parameter: carbon

Assuming stable future costs and prices, it is straightforward to show that the higher the price of carbon, the more competitive is nuclear energy. Based on the levelised average lifetime costs for the production of baseload electricity in the three main OECD regions from the recent IEA/NEA study ‘Projected Costs of Generating Electricity: 2010 Edition,’ the figures below show that even a modest carbon price can make a decisive difference for the competitiveness of nuclear energy in comparison with fossil fuels [1]. Given the importance of the cost of capital for capital-intensive technologies such as nuclear or renewables, results are provided for real interest rates of 5% and 10% which may be considered a lower and an upper bound of the true costs of capital.

In OECD North America the competitiveness of nuclear energy against coal is thus established by a carbon price that, depending whether the cost of financing is closer to 5% or 10%, evolves in a range between $15 and $45 (EUR 11 and EUR 34). In OECD Europe, the range would stretch from $8 to $45 (EUR 6 to EUR 34). In OECD Asia even a very modest carbon price of $ 7 to $ 14 (EUR 5 to EUR 11) would suffice to yield the same effect.

Of course, the question is often posed what would be the true cost of capital for nuclear energy. If 5% is a realistic interest rate, nuclear energy is easily the most competitive source for baseload electricity generation, even if there was only a modest probability for a carbon price during a plant’s lifetime of 60 years. If real rates are closer to 10%, the case for the overall competitiveness of nuclear is more difficult to make.

Looking at the rates that companies need to pay their creditors for funds, a first observation is that nominal market rates need to be adjusted for inflation to be comparable to the real interest rates (net of inflation) that are used in the IEA/NEA study. This means if inflation is 2% per year a 5% real interest needs to be compared to 7% nominal interest. In September 2010, the average nominal yield (interest rate) on US investment-grade corporate bonds (rated BBB or higher) was 4.4% [2] and annual US inflation stood at 1.1% at the end of August 2010. This amounts to a real cost of corporate debt of 3.3% [3]. A 5% real interest rate is thus a very realistic and even conservative assumption for the price of debt capital.

There is, however, an additional twist to the story. Only in countries where governments hold large stakes in energy utilities or prices are regulated in a manner to provide stable rates of return, could utilities expect to finance the totality or even the majority of their capital expenditures through debt. In fully liberalised electricity markets instead, no company would be able to finance all of its investments with the help of relatively risk-averse debt investors. A substantial part of the investment would have to be carried by equity investors with a direct stake in the project. These investors will have variable returns on their investments and will be subordinated to debt investors in the case of default, in other words they assume both price and default risk.

Higher risk, however, means higher average returns, which means that equity investors may demand nominal rates between 10% and 15% depending on the project. The cost of debt and the cost of equity weighted according to their respective share in financing together form what is called the weighted average cost of capital (WACC). For example, if the cost of debt is 5% nominal, the cost of equity is 15% nominal and their respective shares are half and half, then the nominal WACC would be 10% and the real cost of capital net of inflation would be 8%. An IEA analysis on the total cost of financing for US electricity companies showed that the WACC was 10.5% in the fourth quarter of 2008 (IEA, 2009). The real rate was thus 8.5%. Considering that the end of 2008 saw the height of the financial crisis, this is probably on the high side. We may conclude that the real total cost of capital for electricity companies is probably in the range of 7% to 9% real or 9% to 11% nominal.

Two crucial issues

The analysis above assumes that the cost of carbon is levied in form of a constant per unit levy on CO2 emission, which is usually referred to as a carbon tax. This very intuitive idea makes nevertheless two important assumptions. The first assumption is that emitters actually pay the full price for their emissions. This is not always the case. In the largest and best known emission trading system, the European Emission Trading System (EU ETS), for instance emitters obtain the full amount of their annual emissions (minus a small percentage corresponding to the emission reduction objective) at no cost. This practice of free allocation known as ‘grandfathering’ was in place during the Phase I trial period, 2005-07, and is still in place during Phase II, 2008-12. Only with the beginning of Phase III, 2013-20, will significant amounts of emission permits be auctioned off. In particular, the electricity sector must then acquire the totality of its emission rights in advance. Paying or not paying, however, makes an enormous difference for carbon-emitting fossil-fuel technologies.

The second crucial assumption is that carbon prices remain constant over the lifetime of the plant. This is, of course, the case of a carbon tax, at least in principle. It is, however, not the case in a cap-and-trade trading system such as the EU ETS or any of the other carbon trading systems currently discussed from Australia to the United States. A crucial question then is how a constant price for carbon compares in terms of competitiveness with a carbon trading system with volatile prices. Competitiveness in fact depends primarily on the volatility of carbon prices in a trading system and their correlation with volatile fuel and electricity prices. Assessing the precise impact of such volatility is the key aim of the NEA study.

Free allocation and auctioning

Let us first turn to the question of what is the impact of changing from a regime of ‘grandfathering’ to a regime of ‘auctioning’. Evidence from the first three-year phase of the EU ETS pointed towards substantial gains for carbon emitters due to the free attribution of carbon permits, in particular for fossil-fuel based power generators. This effect is due to the ability of power generation to pass on the higher marginal costs of carbon to electricity consumers. The principle of opportunity cost ensures that operators will include the market price of a carbon permit into the price of their output (electricity) even if they have received the permit for free. Fossil-fuel based generators will thus receive higher prices for electricity but their costs stay the same. Emitters thus received substantial windfall profits or ‘carbon rents’, in the sense of unearned income.

While this state of affairs has lead to numerous criticisms, it does not allow any firm conclusions on the impact of carbon trading with free allocation on the competitiveness between fossil fuels and carbon free generating technologies such as nuclear and renewables. This is due to the fact that nuclear and renewables also gained from higher electricity prices.

The key issue is that the full competitive effects of carbon pricing will come into play only once utilities operating fossil fuel-based power generation technologies actually have to pay for their emissions. The table on p33 shows estimates of the surplus profits or the additional costs that European power producers either obtained in Phase I with grandfathering or will have to pay during Phase III when generalised auctioning is introduced for electricity producers in the 27 EU countries (the calculations assume that the auction price will correspond to the average Phase I price which is a rather optimistic assumption). It is obvious that from 2013 onwards auctioning will impose a significant additional cost on fossil fuel-based power producers, in particular coal, and thus enhance the competitiveness of nuclear power. At a carbon price of EUR 12, the difference between the two modes of allocation is in the order of EUR 10 billion for coal-fired power producers and in the order of EUR 3 billion for gas-fired power producers. Undoubtedly, switching to auctioning in carbon emissions trading will bring significant competitiveness gains for nuclear energy.


The second great issue in carbon pricing that affects the competitiveness of nuclear energy with other technologies is the increased volatility of the profit stream that may come with the introduction of carbon pricing and, in particular, carbon emission trading. Even without carbon pricing, the volatility of commodity prices is among the major sources of risk in the energy industries, in particular for fossil fuel-based technologies. Carbon emission trading introduces an additional source of risk for carbon emitting industries.

The difference between a carbon tax and a carbon trading system in this context is that in the first case the carbon price is fixed, whereas in the second it fluctuates. To the extent that carbon prices are uncorrelated with coal and gas prices, volatile carbon prices will increase the volatility of the revenues of the operators of coal- and gas-fired power plants. In such a case, one would expect that nuclear will benefit more from carbon trading than from a carbon tax.

A related issue is the volatility of electricity prices, which in a deregulated electricity market maintain complex relationships with both carbon and fuel prices. With regulated electricity prices the issue is straightforward: emission trading will increase the volatility of profits for carbon-intensive technologies and thus enhance the competitiveness of nuclear energy relative to coal- and gas-fired power generation more than a carbon tax.

The situation changes in deregulated electricity markets with liberalised electricity prices. Here, electricity price volatility is often the result of gas price volatility, given that gas-fired generation is the fuel with the highest marginal cost and thus usually sets the electricity price. Assuming also that carbon prices are correlated with electricity prices, investors in nuclear energy are thus exposed to higher volatility in profits, because their costs remain stable while their revenue varies. The volatility of profits for gas-fired power generation instead would be reduced. Coal would be placed between gas and nuclear, since coal and gas prices are correlated to some extent due to opportunities for fuel-switching.

There are two contrasting effects under way here. On the one hand, carbon price volatility might hamper the competitiveness of fossil fuels that have to deal with more volatile costs. On the other hand, if carbon prices increase the volatility of electricity prices, this might in return disadvantage high-fixed cost technologies such as nuclear or renewables, since, others things being equal, they suffer comparatively more from volatility than technologies with lower fixed costs, which can leave the market without great loss when conditions turn unfavourable. The question whether nuclear should hope for emission trading rather than a carbon tax or vice versa cannot be decided a priori, but is an empirical question. First results from the NEA study indicate that at identical average prices, emission trading does have some advantages for nuclear due to the increased risk for fossil fuel based power producers.


There is no doubt that carbon pricing increases the competitiveness of nuclear energy very significantly, as long as emitters actually pay for their emissions and do not receive their carbon permits for free. While the precise hurdle price for carbon emissions depends partly on financing costs and partly on local conditions, expected average prices in the $20-30 per tonne range are bound to make a difference. Due to the added risk that fossil fuel-based power producers experience due to the volatility of carbon prices in emission trading systems, this latter form of carbon pricing may have some additional advantages for the competitiveness of nuclear power.

Independent of the ultimate form of carbon pricing, nuclear energy requires a long-term commitment to a substantial carbon price. This is why the frequently voiced demand for a ‘floor price’ of carbon (particularly in the UK) is quite understandable. However, such a carbon floor price is probably best discussed in form of a national ‘carbon levy’ to be collected annually in form of the difference between the average market price and the specified height of the levy rather than as a minimum price in the market itself. At first sight, the latter solution might seem attractive as it would combine the visibility of a minimum carbon price that is so important for nuclear power investors with maintaining the volatility penalty for fossil-fuel based producers. However, in practice a floor price in the market for carbon emissions would raise significant market design issues, distort incentives between trading and abating and would also not be cost-minimising.

A ‘carbon levy’ would instead provide a clear signal to the market. From the point of view of the nuclear industry this solution would forego the competitiveness-enhancing effects of a trading system with volatile prices based on a quantitative emission reduction objective. However, in terms of the political economy, the fixing of a single price for carbon emissions might well be the more feasible and hence preferable solution.

Author Info:

Ron Cameron and Jan-Horst Keppler, nuclear development division, OECD Nuclear Energy Agency, Le Seine St-Germain 12, boulevard des Iles, 92130 Issy-les-Moulineaux, France. References on


Dixit, K. A. and R. S. Pindyck (1994), Investing Under Uncertainty, Camden: Princeton University Press.
Green, R. (2008), ‘Carbon Tax or Carbon Permits: The Impact on Generators’ Risks’, Energy Journal 29(3): 67-90.
Keppler, J. H. and M. Cruciani (2010), ‘Rents in the European Power Sector Due to Carbon Trading.’ Energy Policy 38(8): 4280-90.
NEA/IEA (2010), Projected Cost of Generating Electricity, Paris: OECD.
Roques F. A., W. J. Nuttall and D. M. Newbery, R. de Neufville and S. Connors (2006), ‘Nuclear Power: A Hedge against Uncertain Gas and Carbon Prices?’, Energy Journal 27(4), 1-24.


Table 1: The different impacts of 'grandfathering' and auctioning

IGCC station Polk 1 IGCC station Polk 1
The impact of carbon pricing on the competitiveness of nuclear in different OECD regions. The impact of carbon pricing on the competitiveness of nuclear in different OECD regions.

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