Tuesday, January 10, 2006

Credit Aspects Of North American And European Nuclear Power


In general, nuclear plant ownership tends to be less supportive of credit quality because it introduces added levels of operating, regulatory, and environmental risk to a business profile. On a global scale, nuclear generation poses a number of risks that are common to all operators. However, there are nuances that are unique to particular regions. This article examines a number of topics that influence the nuclear industry, particularly in North America (Canada and the U.S.) and in Europe.
One common theme shared by the North American and European nuclear industries is the concentration of ownership. All three regions exhibit a high ownership concentration. This has not yet hindered credit quality, but too-large a critical mass could cause diminishing economies of scale and may negatively affect credit.
Conversely, there are features of each region that present varying degrees of risks, such as the level of regulation. While all regions have an oversight body in place, regulatory bodies that grant an authorized rate of return on plant, or allow recovery of other prudent costs through rate increases tends to differ widely. Canadian nuclear operators seem to benefit the most from the safety net of regulation given the heavy concentration of government ownership and participation. Most European plant owners are not afforded the same level of benefits. The U.S. environment tends to fall somewhere in between.
Again, Canada tends to benefit more from its ownership structure and the regulatory environment in terms of lower decommissioning risk because the government assumes the decommissioning risk. In Europe, mitigating decommissioning risk varies from country to country in terms of procedures and policies for funding and decommissioning methodology. Also, in the U.S. the split between rate-based and "nonregulated" plants has some implications for future decommissioning risk.
Also, another common theme in these regions is the rumbling for the resurgence of nuclear plant construction, but the volume associated with this noise varies. In Canada, the interest stems from a need for more generation capacity in Ontario and a reluctance to rely on coal-fired generation due to environmental concerns. New federal legislation has helped to create interest in the U.S. And, while there is some new construction in Europe, sentiment varies slightly from country to country. In all, it seems more likely that the focus on nuclear in these regions will be on life-time extensions and capacity upgrades.
These topics are discussed in more detail below in an effort to help put a global perspective on how Standard & Poor's analyzes some of the aspects of nuclear generators and operators. Recent trends in North American and European markets regarding nuclear generation developments are also discussed.
Concentration Of Ownership
Since 1999, nuclear plant ownership in the U.S. has become more concentrated and has pressured the credit profiles of those pursuing a roll-up strategy. Over the past six years 21 units (19 operating and 2 shutdowns) have been purchased by six large utilities: Exelon Corp., PSEG Energy Holdings LLC, Entergy Corp., FPL Group Inc., Dominion Resources Inc., and Constellation Energy Group Inc. Exelon and Entergy account for two thirds of these transactions.
Furthermore, this group could become more concentrated in members and gain more mass with a successful merger of Exelon and PSEG and a completed sale of Alliant Energy Corp.'s interest in the Duane Arnold plant (announced in July 2005) to FPL. To date, these owners control about 44% of the nuclear generation in the U.S. These events could portend the potential disappearance of the single-unit owner. Currently, only a handful of investor-owned utilities, such as Detroit Edison Co., CMS Energy Corp., and Ameren Corp., retain this strategy. In December 2005, CMS Energy announced plans to sell its stake in the Palisades nuclear power plant.
There is a strong probability that more nuclear plants could be sold and good chance that ownership could become more concentrated. Deregulation and competitive forces can pressure other, less-concentrated owners to pursue a sale strategy in an effort to gain operating efficiency and reduce production costs. The motivation for most of these sales occurred out of a need to improve plant performance and relieve financial burdens. The trend has been to contract the output of the plant back to the plant's original owner. Conversely, the acquirers see transactions as a way to exert their operating prowess, achieve cost savings, and enhance cash flow by purchasing less-efficient plants. Also, many deals were sweetened with a deeply discounted price due to poor performance, but this is less reflective of more recent transactions.
However, the roll-up strategy being pursued does exert pressure on credit quality given the unique set of operating risks associated with nuclear plants. Improved operating performance through fewer unplanned outages, shorter durations for refueling, higher capacity factors, and lower production costs help to mitigate some of the risk. Also, improved financial performance is necessary to maintain credit quality. This is expected of "fleet-style" operators because they can reduce costs by centralizing functions such as fuel purchasing and can more efficiently deploy specialized personnel such as refueling teams. Canada
In Canada, nuclear power is concentrated in a handful of provinces, and like the U.S. and Europe, the ownership of nuclear facilities is concentrated among a handful of market participants. Only the provinces of Ontario, Quebec, and New Brunswick have nuclear capacity. However, unlike the trend in the U.S. and Europe, the ultimate ownership of all the nuclear plants in Canada by province-owned utilities means a consolidation of existing nuclear generators is highly unlikely. Furthermore, the involvement of provincial governments in the nuclear industry, either as the ultimate owner of all the facilities or as a counterparty to contract for difference/price agreements (in the case of the leased Bruce Power facility), has positive implications for the sector's credit quality in particular through enhancing cash-flow stability for generators, and through the funding of decommissioning costs.
The Canadian nuclear fleet has three owners and four operators. Ontario Power Generation Inc. (OPG,) owns about 90% of Canadian nuclear capacity, with the remaining two units owned by Hydro-Quebec and NB Power Nuclear Corp. The provinces of Ontario, Quebec, and New Brunswick wholly own these three power companies respectively. The fourth player in the industry is Bruce Power Inc., a consortium of industrial and investment companies similar in nature to the consortiums found in the Finnish nuclear industry. The Ontario-based Bruce Power consists of:
Canada's largest uranium producer, Cameco Corp.;
Canada's largest gas transmission company, TransCanada PipeLines Ltd.; and
BPC Generation Infrastructure Trust, a trust established by the Ontario Municipal Employees Retirement System, with a small proportion held by the Power Workers Union and the Society of Energy Professionals.
Bruce Power operates the Bruce nuclear station, consisting of the Bruce A and Bruce B facilities, under a long-term lease arrangement with OPG. Each facility has four CANDU reactors. Six of the eight reactors are operational and the combined net output of the stations is about 4,640 MW. Europe
The ownership of European nuclear assets is fairly concentrated. In countries with a dominant power company, such as in France (Electricite de France (EdF)) and Belgium (Electrabel), all nuclear assets are owned by a single company. All Eastern European countries fall into this category, including the Czech Republic (CEZ). In countries with a more fragmented market and ownership structure, such as Germany, Finland, Spain, and Sweden, nuclear assets tend to be owned by a few companies, generally the largest utilities. Often, nuclear generation has been built in consortia to exploit economies of scale and reduce risks for the individual company. Finnish Teollisuuden Voima Oy, owned jointly by a large number domestic industrial companies, municipal utilities, and the formerly 100% state-owned power company, is probably the best example of this.
Standard & Poor's expects concentration to prevail and even increase further in line with the general consolidation driven by the EU energy market integration. More joint ventures involving major utilities could be expected for new nuclear power projects, exemplified by the recent decision on a new French reactor. This reflects that the risk of nuclear generation has increased in a deregulated market environment. Projects in Eastern Europe could attract interest from Western European utilities aiming at increasing their nuclear know-how, and invest in nuclear without stirring controversy in their core markets.
While major industrial customers could see nuclear generation as a way to secure stable, long-term power-supplies in today's volatile and fuel price-sensitive markets, Standard & Poor's believes that the Finnish mixed-ownership model will be difficult to copy elsewhere. Utilities are likely to keep their nuclear know-how for themselves. Without that experience, it is hard to imagine any nuclear plant concessions to be granted.

Level Of Regulation
Regulation plays a supportive role to credit quality in the U.S., as it allows for prudently incurred recovery of capital costs, purchased replacement power, and decommissioning underfunding. However, deregulation has created a dichotomy among nuclear plant owners. To date, newly acquired plants in the US have not been deemed part of a utility's rate base and therefore not able to reap the benefits of a guaranteed return. The absence of this protection presents uncertainty regarding the ability to recover certain costs. Also, decommissioning risk is greater because underfunding cannot be recovered through a regulatory process.
Competitive nuclear generation presents an added risk factor to a firm's business profile, given the inability to recover unexpected costs through a regulatory process. So far, those operating nonregulated generation have had success by mitigating risk through enhanced operating performance (higher capacity factors, shorter outage intervals), expertise in managing nuclear assets, and the ability to sufficiently fund decommissioning costs. Still, some element of event risk will always remain with this business strategy, which could ultimately impinge on credit quality.
To date, those with nonregulated nuclear generation exposure have performed well, despite greater business risk related to fuel procurement and storage, asset concentration, and the potential need of replacement power. In Standard & Poor's view, these nonregulated nuclear operations have higher risk than those plants that reside in a regulated utility business.
Standard & Poor's expects the current trend of regulatory treatment of rate-based plants in the U.S. and the unregulated status of future acquisitions to continue. This again, places a greater emphasis on stronger operations, competitive production, prudent contract pricing and sufficient decommissioning funding for those involved in competitive nuclear generation. Canada
Unlike many of their counterparts in the U.S. and Europe, nuclear generators in Canada benefit from regulated prices or price support mechanisms. In Ontario, OPG and Bruce Power sell their nuclear output into the competitive Ontario wholesale market. Despite the wholesale market exposure, cash flow from all of OPG's nuclear production is supported by a legislated fixed price of C$49.50 per megawatt-hour (MWh) until 2008, at which time the province's independent regulator is expected to determine the price received. Bruce Power is a merchant generator, mitigating the price and volume risk associated with its Bruce B plant through off-market contract for differences with electricity suppliers and the government. As part of the arrangement with the provincial government to proceed with refurbishing units at Bruce A, the consortium will receive a reference price of C$63/MWh for its output from Bruce A once commissioned, and for its Bruce B units it will receive a floor price of C$45/MWh, but retain the potential to benefit from pool prices that may be higher than the floor price. Both the reference price for Bruce A and the floor price for Bruce B escalate with the Consumer Price Index (inflation). Output from Hydro-Quebec's single nuclear unit, Gentilly-2 (675 MW), is considered part of the company's regulated heritage asset base and as such receives a legislated price for all of its output from Hydro-Quebec Distribution and the output from the New Brunswick-based Pt. Lepreau plant once refurbishment is to be supplied under contract with the province's government-owned incumbent electricity distributor, New Brunswick Power Distribution and Customer Service Corp.
Like its global peers, the operational performance of Canadian nuclear facilities is closely monitored and licensed by an independent regulator. In Canada, the relevant regulator is the Canadian Nuclear Safety Commission (CNSC). The CNSC is an independent federal government agency accountable to Canada's Parliament through the Minister of Natural Resources Canada. It is charged under the Nuclear Safety and Control Act to regulate, among other things, the use of nuclear energy, and it is the responsible authority to approve life extensions for plants, unit restarts, and license renewals. It is also responsible for ensuring compliance with safety requirements through regular audits. Europe
As a consequence of deregulation of European power markets, European nuclear operators are not offered any regulatory protection. This implies uncertainty about the ability to recover costs, including decommissioning costs. In addition, operating risks is high, and has a political dimension in jurisdictions where the attitude toward nuclear is negative (as demonstrated by very high safety requirements and prolonged regulatory related outages for some German nuclear plants). This increases the business risk. Standard & Poor's sees nuclear generation generally to have the highest overall business risk compared with other types of generation.
This is mitigated by the absence of price regulation, which financially benefits nuclear operators by raising their margins to levels well above full cost recovery. The price formation in the wholesale markets, and indirectly the retail markets, is nowadays based on marginal cost of generation. Nuclear generation is very competitive, as it tends to be positioned favorably in the low cost base load part of the generation merit order. This position is further supported by the introduction of carbon dioxide emission allowances trading, which increases marginal generation costs for coal- and gas-fired generation.
European nuclear operators have improved nuclear operating performance by increasing capacity factors and shortening overhaul intervals, though this improvement has not been as pronounced as in the U.S. Still, like in the U.S., strong operations, competitive production, prudent contract pricing, and sufficient decommissioning funding remain important considerations for utilities involved in competitive nuclear generation.

Decommissioning risk remains an important factor in determining credit quality of U.S. firms and weighs more in the analysis of competitive nuclear generators. This is the case because, again, a regulatory process can provide recovery for underfunding.
Unlike many of their peers who own nuclear plants in rate base, owners of nuclear power plants not in rate base neither collect decommissioning costs in rates nor do they have recourse to the local regulator for relief. Therefore, the funding responsibility falls squarely on the owners of nonrate-based nuclear plants. Standard & Poor's views this obligation to be debt-like, similar to underfunded pension benefit obligations, and may incorporate any shortfall into computing credit metrics.
In the U.S., all nuclear plant owners are required to provide financial assurance that funds will be available to decommission the plant once the operating license expires. This is done by estimating the future value of the cost to decommission a plant, recording a liability for this amount, and then creating a trust that holds funds to cover the value of the liability.
These funds are recovered in rates for a regulated plant and typically capitalized into the electricity sales prices of competitive plants. However, the future estimate of the obligation can't account for any unanticipated overruns that could be caused by some unforeseen event or inaccurate future costs estimates. A regulated plant can mitigate this risk by seeking recovery of a shortfall.
In addition, the Nuclear Regulatory Commission (NRC) acts as an overseer to ensure that the decommissioning funds remain outside the reach of general creditors if a bankruptcy occurs and are used solely for decommissioning the nuclear plants. The NRC biannually reviews the balance available in the decommissioning trust fund and annually evaluates the future decommissioning cost estimate in an attempt to ensure that when the plant is to be retired, the liability will be fully funded. Also, five years before the plant's operating license expires, the NRC performs a detailed assessment of the expected decommissioning costs and the associated decommissioning trust fund balance and requires companies to demonstrate how they will address any potential shortfall. Importantly, the NRC only requires companies to demonstrate how any shortfall will be covered and does not have the authority to provide for necessary rate increases. For these increases, the regulated electric utilities would typically turn to their state regulators or the FERC to determine the amount to be collected in rates and the method of collection.
To make matters more challenging, given that the decommissioning trust funds cannot be commingled, it is possible that a utility with multiple nuclear plants not in rate base may have a plant whose decommissioning trust fund appears fully funded today, and another whose decommissioning trust fund is underfunded. However, given the consolidated presentation of this information in company financial statements, it may be difficult to discern the true funding level of each plant.
In addition, many plant owners are mitigating the short-term funding risk through license extensions. To date, there have been 33 renewals, with 16 more in process and another 25 expected over the next six years. If all were completed, this would represent about 72% of the existing U.S. nuclear fleet. Although this strategy does not eliminate the decommissioning responsibility, it does shift the burden out another 20 years and allows the company more time to fund the liability. Canada
The ultimate ownership of nuclear plants in Canada by provincial governments mitigates the risks associated with the asset-retirement obligations (ARO). Provincial governments indirectly through their utilities and directly through established obligations largely assume the risk surrounding the liabilities associated with waste management and decommissioning. Although government-owned utilities only operate 60% of existing capacity, they ultimately own 100% of capacity. For the 40% not controlled by the government, as represented by the Bruce Power facility in Ontario, the government nevertheless assumes all the nuclear liability and waste management as it retains ownership of the plant through OPG. Annual payments to OPG for prefunding waste management and decommissioning by Bruce Power mitigate the financial risk somewhat.
The prefunding of future nuclear waste management and decommissioning costs by Canadian utilities also mitigates the potential for contingent liabilities. Nuclear generators are required under federal legislation to establish a waste management organization as a separate legal entity and to set up trusts to finance the implementation of the nuclear fuel waste management. The Ontario government and OPG currently make annual combined cash payments to a segregated nuclear liability fund to meet future decommissioning and a segregated fund to meet future waste-management costs. OPG's cash contribution to the funds in 2004 was C$454 million. For OPG, waste-management and decommission liabilities have also been capped under an agreement with the provincial government at C$6 billion. Furthermore, the provincial government provides a financial guarantee to the CNSC for OPG's nuclear waste management and decommissioning liabilities. In accordance with the legislated requirement, but on a much smaller scale, Hydro-Quebec and New Brunswick Power Nuclear are also putting money aside from cash flow from operations to fund their future AROs.
Refurbishments of units undertaken in the past few years by OPG and decisions by Bruce Power and the New Brunswick government to refurbish units going forward will have the effect of pushing out the asset-retirement obligations. With refurbishments typically extending the life of units for 25 to 30 years, the realization of long-term decommissioning and waste-management costs surrounding the plants have been extended also.
The more specific issue of the long-term management and storage of nuclear waste falls on the federal government. To date, there is no facility to permanently dispose of nuclear waste currently operating in Canada. The Nuclear Waste Management Organization (NWMO), established under the federal Nuclear Fuel Waste Act (NFWA) in 2002, was charged with investigating approaches for managing Canada's used nuclear fuel. After considering three technical methods (deep geological disposal in the Canadian Shield; centralized storage either above or below ground; and storage at nuclear reactor sites), the NWMO's recently released study recommends that Canada develop a plan to isolate used fuel in a deep underground repository. The NWMO is seeking an informed and willing host community. The Canadian government will decide on the final approach. Europe
Most European nuclear plants were built in the 1970s and 1980s, partly in response to the oil crisis and growing concern regarding countries' dependency on volatile fuel imports in its overall energy mix. The European Commission estimates that 50 to 60 of the 155 nuclear reactors operating in the EU will be decommissioned by 2025. Nuclear-dependent countries, such as Germany, Belgium, Sweden, and the U.K., have decided to fully phase out nuclear generation. This process has started in the case of Germany and Sweden, and according to current policies, could accelerate over the coming decade. Some East European countries have agreed to phase out Soviet-era nuclear reactors considered to be hazardous as part of their accession to the EU (including Lithuania's Ignalina and Slovakia's Buhomice). In countries with a pro-nuclear stance, such as France, Finland, and the Czech Republic, nuclear plants were granted an authorized 40-year life span, although technically plants are likely to be able to operate for up to 60 years as assumed in several cases in the U.S.
The exposure to unfunded decommissioning liabilities is limited in Europe, with the key exception being EdF, which has a €23 billion unfunded liability, and less so with CEZ a.s. having a €900 million deficit. In Sweden and Finland, nuclear operators have contributed cash on an ongoing basis and liabilities are funded by a separate government-controlled fund that today fully cover projected costs. In the case of the German utilities E.ON A.G., RWE A.G., and EnBW Energie Baden-Wuerttemberg A.G., as well as Vattenfall A.B.'s German utility operations, there is no separate funding, but liability provisions are balanced by significant financial assets intended to cover asset and employee retirement obligations. In Spain, the government has retained operational and financial responsibility, but this could change following a government initiative in the Spring 2005. British Energy Group PLC's (the U.K.'s only nuclear operator) nuclear liabilities are also backed by a U.K. government guarantee following the completion of its financial restructuring in January 2005. The Nuclear Liabilities Fund will be funded from a cash sweep from the business, with the government liable for the shortfall.
Decommissioning strategies differ across Europe. German companies tend to have the most conservative approach, assuming a short, quick, and very thorough plant decommissioning. Under the nuclear consensus agreement, they also assume significantly shorter 32-year life spans. As for spent-fuel disposal, deep underground storage is the preferred choice. Germany has selected a deep-storage site and, in Finland, construction has started on one. Only France, the U.K., and Russia continue to permit spent-fuel reprocessing.
Decommissioning liabilities could be influenced by a possible extension of nuclear generation resulting from the more positive attitude seen recently. Still, there is uncertainty in some existing cost estimates. Authorities in France and the U.K. have recently warned that costs could be significantly higher than currently expected. In any case, Standard & Poor's expects that cost and safety aspects will be scrutinized even further as a result of decommissioning starting in some countries and the discussions on allowing for new nuclear generation.

Although there has been no new construction in the U.S. since the mid-1980s, at least a resurgence of interest in potential new construction has occurred. Mainly, this support comes from generation owners and supportive legislation from the Federal government. Still, this support may not be enough to mitigate the risks associated with operating issues and high capital costs that could hinder credit quality.
A number of groups in the U.S. are trying to lead the push for new nuclear generation given the future need for base load generation and incentives provided by new federal legislation. One of the first movers is Nustart; a consortium consisting of 11 members that own, operate, manufacture, or engineer nuclear plants. This group has selected two sites--Grand Gulf Nuclear Station and the Bellefonte Nuclear Plant, to use on a combined construction and operating license application. However, the decision to actually proceed with construction is a ways off because this is the first step in a lengthy process. Even with the more streamlined application process, a new license probably would not be issued before 2010. Another group, called UniStar, a joint venture between Constellation Energy and French plant manufacturer Areva, said it plans to file the same type of application. However, the group is still considering a number of sites for use and is expected to make a decision in early 2006. Other consortia led by entities such as Dominion Resources and the Tennessee Valley Authority have expressed interest in pursuing the same strategy. Another potential investing scenario could involve a regulated utility (or utilities) that may want to take advantage of the financing, tax, and guarantee incentives, along with the benefit of having a plant placed in rate base.
However, this renewed interest still faces some of the same old operating concerns and financing risk, given the high capital costs associated with nuclear construction. New construction is expected to cost about US$1,500 per kilowatt, which is twice the price of a coal-fired generation plant. Also, given that construction would entail using new designs and technology, cost overruns are highly probable.
Through the Energy Policy Act of 2005 (passed in August), the Federal government has attempted to help reduce costs associated with nuclear investment. Particularly, the act includes a 1.8 U.S. cents per kilowatt-hour tax credit for 6,000 MW of capacity for new nuclear generation. However, the credit can only be used for the first eight years of operation and is limited to a total of US$125 million per 1,000 MW of capacity. Also, the act provides for standby support to offset the financial effect of construction delays due to regulatory delays or litigation.
The Energy Policy Act includes some other provisions that are considered supportive of the nuclear industry. These include an extension of the Price-Anderson Act, which provides a framework for limiting operator liability associated with nuclear accidents. Another provision included modifies the tax treatment of certain nuclear decommissioning trusts. This particularly pertains to trusts used to decommission nuclear plants that are not in rate base.
Although these events create some sort of supportive platform for a nuclear renaissance in the U.S., it may not provide sufficient incentive to pursue new construction. From a credit perspective, these legislative measures may not be substantial enough to sustain credit quality and make this a practical strategy. Canada
Recent developments in Canada surrounding nuclear plant refurbishments do not yet signal a renaissance in nuclear power, but reflect a more practical and increasingly urgent need to plug the widening gap between supply and demand in Ontario, and the replacement of aging assets in New Brunswick. Ontario is the biggest user of nuclear generation in Canada, with close to 50% of the province's annual load met by nuclear power. Recent announcements suggest an increasing acceptance by governments and consumers of nuclear energy as a viable, long-term energy source. Bruce Power in Ontario will refurbish its Bruce A units at a cost of C$4.25 billion. In July 2005, the provincial government of New Brunswick decided to proceed with the C$1.44 billion refurbishment of NB Power Nuclear's Pt. Lepreau 635 MW facility. These announcements follow other refurbishments over the past five years, including OPG's Pickering A Units 1 and 4 and earlier work carried out by Bruce Power on two of its Bruce A reactors.
The announcements of plant refurbishments, and commissioning of refurbished units mean the amount of in-service nuclear capacity and life expansion of plants in Canada is set to increase. OPG's commissioned and refurbished 515 MW Unit 1 at the Pickering A station, Bruce Power's restart of units 1 and 2, the planned refurbishment of unit 3, and replacement of steam generators on unit 4 at its Bruce A facility; together with the Pt. Lepreau refurbishment to be completed by fall 2009 will, when completed, bring Canada's total in-service capacity to about 14,100 MW. Total capacity is currently spread across seven plants, including: OPG's Darlington, Pickering A, and Pickering B plants; Bruce Power's Bruce A and B plants, the Gentilly-2 single unit in Quebec, and the Pt. Lepreau single unit in New Brunswick.
The drivers of nuclear plant overhauls in Canada include the need to ensure adequate generation supply to replace existing coal-fired plants in Ontario, the replacement of aging nuclear plants, and the environmental benefits nuclear offers relative to other generation alternatives. The need for refurbishing nuclear facilities to ensure adequate supply in Ontario is exacerbated by the government's policy to close its coal-fired generation plants (representing 25% of the province's generation capacity) by 2009. Furthermore, a number of nuclear plants in Ontario and the Pt. Lepreau facility in New Brunswick are reaching the end of their useful lives, which presents the power companies and government with the option of mothballing the plants or extending their lives. A telling factor in such a decision is the reduced level of permitting and reduced timetable involved in refurbishing existing plants relative to the time involved in undertaking a greenfield development. Environmental considerations surrounding Canada commitments under the Kyoto Protocol is also influencing the push for, and acceptance of, nuclear as a means to curb greenhouse gas emissions.
The province most likely to build new nuclear generation is Ontario, the country's biggest user of nuclear energy. However, whether or not new plants will be built depends on the Ontario government's response to the advice provided by the province's long-term electricity-planning body, the Ontario Power Authority (OPA). The government asked the OPA to report on what should be the province's long-term generation mix. The outcome of the study, which was released in early December 2005, recommended that nuclear's share of the generation mix in the province remain as it is today. With growing demand for energy this would suggest the need for additional refurbishment of existing facilities as a minimum, and/or the construction of new nuclear capacity to maintain its current share over the long-term. The government has hinted that it is prepared to develop new nuclear and is expected to respond to the findings in the OPA report in the first half of 2006 after a 60-day consultation period. If nuclear power is the answer, an issue for the sector is that decisions will be required to be made in the next few years to allow adequate time to replace or refurbish a number of existing nuclear assets that are due to reach the end of their useful lives in the early to middle part of the next decade. Europe
The outlook is bright for European nuclear generation. Utilities with nuclear generation, including EdF, EON, RWE, and Vattenfall, currently benefit from the high power price environment. Since it is driven by high gas and carbon dioxide emissions allowance prices, nuclear operating margins have increased substantially. The increase in nuclear fuel prices seen in recent years has only marginally tempered enthusiasm.
Furthermore, political sentiments have become more positive toward nuclear generation because of high oil prices, the raising abatement costs for reducing carbon dioxide emissions, and the concerns over security of supply resulting from the dependence on gas imports from non-EU countries. The political support for nuclear power has always remained strong in France, Finland, and several East European countries. Governments in Germany, the U.K., Sweden, and Belgium have been more ambivalent and hostile since the 1980s, with decisions to fully phase out nuclear generation. This process has started in Germany and Sweden, and according to the current policies applied it could accelerate over the coming decade. The recent surge in power prices has sparked a new debate about the long-term role of nuclear, possible extensions to existing lifetimes (Germany and the U.K.), or new capacity (Italy, the Netherlands, and the U.K.).
But the question is if a change in political sentiments and improved profitability will be enough to result in a nuclear renaissance. Developing new nuclear generation in the deregulated European market environment is a high-risk venture, given the long construction times and high capital costs. Siting issues are likely to be more sensitive today than in the 1970s and 1980s when most reactors were built. Furthermore, political support will remain fragile to nuclear safety performance worldwide. Another Chernobyl-like accident can rapidly cool the current cordial sentiments. Fundamental issues, such as the final storage of nuclear waste and far-reaching social consensus, are still likely to be required before a potential large-scale renaissance can happen.
While there are is a new nuclear reactor being built in Finland, and one in advance planning stages in France, investments in new nuclear generation in Western Europe remain limited. For the time being, Standard & Poor's expected most investments to be directed toward lifetime extensions and increased capacity. Some Eastern Europe governments (including Slovakia and Bulgaria) are actively promoting new nuclear capacity, sometimes trying to kick-start project that have been idle for several years. The problem is to secure the funding and to attract partners. Standard & Poor's also expect EU's state-aid rules will challenge the establishment of the required support mechanisms.


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