The Science may make sense, but plans for new nuclear plant capacity could yet be thwarted by difficult economics. Investor caution remains the order of the day, as prohibitive capital-investment costs and hefty decommissioning expenses run into tens of billions of dollars, James Gavin writes.
The irony is that one of the main arguments put forward by the nuclear industry is the competitive operating costs of nuclear reactors. Numerous studies indicate competitive costs compared with the lowest-cost alternative, gas. A well-managed nuclear unit can produce electricity profitably at a total cost of $0.02-0.025 per kilowatt-hour (kWh), including capital costs. A new gas-fired plant would, in contrast, produce electricity at a total cost of $0.035-0.045/kWh, assuming a plant capital cost of $500-600/kW and gas prices of $3-4/m Btu, says the US-based Nuclear Energy Institute.
But if judged on capital costs alone, nuclear fares less well. A recent study for the Royal Institute for International Affairs (RIIA) shows that capital costs for combined-cycle gas turbines (CCGTs) range between $450/kW and $900/kW, compared with $2,000-2,500/kW for large-scale nuclear plants using 1980s designs. Construction times for a 1 gigawatt (GW) CCGT may be two years or less, compared with around seven years for conventional light-water reactors.
The trend to liberalised energy markets over the last decade has further undermined the nuclear energy cost advantage. The RIIA says the introduction of electricity-market competition means new plants no longer have customers for their output, which in turn increases the risk of any new nuclear plant.
The nuclear lobby acknowledges that electricity deregulation has worked against the sector. "Certainly, the short-term nature of buying and selling in liberalised power markets means that, all things being equal, a low capital cost, high running cost plant is easier to manage in purely economic terms," says Ian Hore-Lacey of the World Nuclear Association. "That's not to rule out the possibility of long-term contracts, it's just that markets are designed for plants that are already there and not much thought is given to the effect of these kinds of power markets on new plant investment."
With political support for nuclear evaporating in the 1980s and 1990s, raising finance for new capacity became even more difficult. Without supportive government policies or limited availability of gas or coal supplies, "no-one in a competitive market is likely to contemplate construction of a large-scale nuclear reactor based on designs now in operation," says the RIIA report.
This may change with the advent of cheaper reactor models such as the Westinghouse AP1000, estimated to require half the construction cost of traditional pressurised-water reactors (PWR). But cheaper capital costs alone will not unlock new investment streams. The real challenge in raising funds for nuclear facility investments, says a report from the OECD's Nuclear Energy Agency, is not the level of funding requirements, but rather the perceived financial risks to investors and the need for adequate rates of return on energy investments.
Analysts say that for banks to regain their appetite for nuclear risk, the anticipated new fleet of reactors may have to be structured on a radically different financial basis.
Most existing nuclear plant was planned more than two decades ago and was expected to occupy a competitive position in the power market, because energy prices in general were expected to rise. With electricity systems organised along monopoly lines, generating companies had secured markets for their output, creating, in the RIIA study's words, a perception that investment in generation was low risk, with investors expecting no more than utility rates of return – around 5-6%.
The market structure no longer conforms to this stereotype. But proposed changes could improve the financial-risk profile for nuclear plant construction. Politics may shift the competitive position of nuclear plant compared with fossil-fuel energies, if authorities start to ascribe a value to reductions in carbon dioxide (CO2) emissions, for example.
The rise of carbon-emissions trading may work to the nuclear sector's advantage, with the new European Union emissions-trading scheme forcing rival coal and gas-fired power stations to buy carbon credits if they exceed CO2 emissions limits. "The possibility that carbon emissions will acquire a cost is becoming a reality in Europe," says Hore-Lacey.
The evolution of new reactor models may also relieve some of the financing risk. The planned 1.6 GW next-generation European PWR from Finland's Olkiluoto 3 consortium will involve an innovative financing structure – the more than 60 domestic firms participating in the investment also have a share of the electricity to be produced by the unit, which starts commercial operation in 2009.
This consortium comprises major electricity users in which the customers are the shareholders. "They have a long-term market for the electricity – the market is themselves. They take output from the plant as a proportion of the initial investment – an example of nuclear working in a market economy," says Malcolm Grimston, author of the RIIA study and nuclear policy adviser at Chatham House.
That model may not be easily replicable, however. A likely financing structure in other European markets such as the UK might involve the consortia putting up around 20% in equity, says Chris Lambert, director of the Westminster Energy Forum think-tank. "The government might demand that level to indemnify the other 80% provided by the banks. If the government indemnifies it, that would give it a AAA credit rating," he says.
Although the magnitude of the investment requirements of large-scale newbuild reactors is not insurmountable, the OECD report warns that much depends on whether investors perceive the rates of return as sufficient to overcome the initial financial risk.
The industry has a lot of convincing to do if that risk perception is to shift. "The utilities need to be convinced they can sell the power at a certain price. The government has to be sure it's not going to have to indemnify industry if the costs skyrocket," says Grimston.
With capital costs prohibitive, lifetime extension stands as the least risky and most cost-effective option for the nuclear industry. This is now standard practice in the US, where streams of licence-extension applications are pending, many of them 15 years ahead of their scheduled mothballing. "That the wholesale electricity price is double what it was two years ago provides an argument for sweating existing assets and extending existing assets as far as you can," says Grimston.
But the financial implications of nuclear plants extend well beyond the initial construction and operation costs. The soaring cost of safety regulations in the wake of the Three Mile Island reactor meltdown in the US, in 1979, has amplified the financial risk of nuclear plant.
The potentially exorbitant cost of decommissioning adds another significant risk. French utility Electricité de France (EdF) has long-term decommissioning obligations of Euro48bn ($62bn) and the cost of decommissioning a US plant is estimated to average $325m per reactor.
France's public-sector auditing body recently accused EdF of failing to implement a "clear financial strategy" to meet its long-term decommissioning obligations, noting that it could count on only Euro2bn of assets to cover its commitments.
A cautionary tale
The experience of British Energy (BE) provides another cautionary tale. The privatised UK nuclear power group, the only stock-market-listed owner of nuclear plant, had to be bailed out with UK taxpayers' cash, having been left with large expenses initially contracted to British Nuclear Fuels. When a slump in wholesale power prices sent BE to the brink of bankruptcy in 2002, the government was forced to step in with a rescue package. A debt-for-equity swap late last year cleared £1bn ($1.9bn) of debt off its balance sheet and transferred nuclear liabilities to the government.
The BE restructuring may create a template for new financial structures in the sector. "This is a model we'll see more and more, separating liabilities from operations. Saddling companies with sizeable liabilities is a disincentive to doing anything commercial as any money it does make is sucked into a decommissioning hole. The liability for newbuild should stay with the company that's building it, but historical liabilities should be separated out," says Grimston.
Building up appetite for new financing structures will inevitably take time. But analysts see utilities cautiously dipping their toes in the water as the comparative costs of fossil-fuel-fired power generation starts to rise. The bankers are likely to be only a few steps behind.