US nuclear power - can competition give it renewed life?28 May 1999
The US nuclear vendor industry is in a race for its survival. By making license renewals and longer service lives financially attractive, the low operating cost of the industry’s older reactors has bought it time to reduce the capital cost of building new reactors for the US market. While the industry’s growing competitiveness may not yet make it easy to predict the ultimate survival of US nuclear power, recent developments do at least make it harder to predict an early demise.
There continue to be many reasons to fear for the continued survival of US nuclear power. The US Energy Information Administration’s Annual Energy Outlook 1999, for example, projects that more than half of current US nuclear capacity will be out of service by 2020. EIA’s reference case predicts that with the early retirement of 27 nuclear units, nuclear’s share of total electricity generation will have fallen by then from 18% to 7%.
Furthermore, new orders for reactors in the US will likely remain at zero for as far as the eye can see. According to a late 1997 report of the President’s Committee of Advisors on Science and Technology, “the outlook is that no new nuclear plant will be built in the United States in the next 10 – or perhaps even 20 – years.” The drought of new orders is also drying up the inflow of new nuclear engineers, and the pool of university reactors for training them. As fewer students decide to pursue carreers in nuclear engineering, fewer universities can justify keeping their reactors. The number of US university research reactors has dropped from 70 to fewer than 30 in 18 years, and the US is now losing them at the rate of two a year.
But now there are also good reasons not to give up hope. The industry’s current circumstances are better described as a stay of execution than a new lease of life, but they are nonetheless sufficient grounds to call off plans for any death watch. As with other US industries once thought vulnerable to collapse, increasing competition is turning out not to be the coup de grace for nuclear power, but a tonic for its resuscitation.
There are other positive indicators. Most importantly, more and more utility officials are seeing that well-run nuclear units with little or no remaining debt are among the cheapest and most lucrative assets available as the US electricity generating base restructures for retail price competition. In addition, the Clinton Administration, not known for its pro-nuclear sentiments, has now realised that it cannot meet US carbon emission abatement targets without nuclear power.
LOW O&M COSTS
Competition is fundamentally changing the economics of utility investment. Anticipating that its prices and profits will no longer be regulated, a utility may now calculate that if it can keep its O&M costs low enough, and run its existing plants long enough, it may be able to maintain sufficient profit margins to pay off the capital costs it incurred when it was a regulated monopoly. According to the Nuclear Energy Institute, a research and lobbying group led by nuclear utilities, the average cost of electricity from US nuclear plants in 1996 was 1.91 cents/kWh – competitive with the 1.83 cent/kWh production cost of the average coal-fired baseload plant, the cheapest central station power generation technology in operation today. This low cost enables the utility to profit when competitive prices are established at the margin by higher-cost gas-fired units. Thus, during the current transition to retail competition, a utility may no longer respond to unfavourable state regulatory decisions on capital cost recovery by shutting down the affected nuclear plant.
Although some US utilities’ nuclear investments could be financially “stranded” in the transition to deregulated retail power markets, NEI President Joe Colvin expects that even in a worst-case scenario, the nuclear units of a utility bankrupted by unrecoverable capital costs could continue to operate competitively at the margin. Units like these can be acquired at low cost by experienced nuclear operating companies like Entergy and PECO, he says.
NEW LIFE FOR LIFE EXTENSION
With such low operating costs, the economics of extending the operating life of these reactors has become enticing. The longer a fully paid-off plant can continue to operate at such low costs in a deregulated market that permits good margins even at lower prices, the better an investment in life extension begins to look. Duke Power now expects it to cost $4-6/kW of capacity to obtain an extension of the Nuclear Regulatory Commission’s operating licences for its three-unit 2500-MW Oconee Nuclear Station, according to Michael Tuckman, the utility’s Executive Vice President for Nuclear Generation.
“In absolute terms, [the cost of extending Oconee’s operating licences] is a pretty good amount of money,” Tuckman said. “But in terms of the cost of the existing plant, or the cost of replacing it with another unit, the relative cost is miniscule.” Looking beyond Oconee to all nuclear plant owners, a recent NEI survey backs him up: the estimated total cost of licence renewal ranges from $10 to $50/kW, says NEI Vice President Marvin Fertel. These licence renewal costs may include additional maintenance costs but no major capital expenses, he explained. In contrast, the cost of building the most comparable non-nuclear alternative for new baseload generation is $405/kW, by EIA’s estimate. Even the cheapest alternative technology for new capacity in EIA’s Annual Energy Outlook 1999 is $325/kW – still about an order of magnitude greater than the costs of licence renewal for an operating reactor.
Nor does repowering of fossil-fired power plants offer a lower-cost alternative to nuclear plant life extension. According to EIA’s most recent study in 1992, the estimated capital cost of replacing the steam supply system on a comparable existing fossil-fired power plant ranges from $400 to $800/kW. Even the cost of performance optimisation, which involves only repair, refurbishment, or replacement of equipment to permit 20 more years of plant operation, ranges from $100 to $250/kW on a coal-fired unit of 200 MW or more.
Duke’s updated economic model showed that, even under fully competitive market conditions, Oconee’s PWRs would remain profitable, Tuckman said – even during the years when their steam generators are to be replaced, a job that normally costs several hundred million per unit. He noted that Baltimore Gas and Electric, the other nuclear utility to have applied to the NRC for licence extension, is also planning to replace the steam generators on its two-unit Calvert Cliffs plant. This too suggests that a facility’s expected profitability during extended operation might even help utilities afford such a major investment. In the past, when nuclear operating costs were escalating and electricity prices were regulated, a utility facing such major capital costs would have been prudent to consider retiring the affected reactor before the end of its original 40-year operating licence.
Tuckman, who also chairs NEI’s working group on licence extensions, reports that more and more utilities are beginning to appreciate the economics of extending their reactors’ operations. These utilities are also becoming less fearful that their strategic plans for these facilities will become hostage to a long and unproductive NRC licence review process. This process permits “intervenors,” or groups with legal standing, to participate in the licence review, to request an adjudicatory hearing.
NRC has narrowed the scope of the licence extension review to a subset of age-related safety issues, and a potential intervenor must have a valid safety issue, relevant to the reactor under review, that has not been adequately addressed by previous NRC regulatory actions. Because plants are already required by NRC regulations to monitor, maintain, and replace many types of safety-related equipment during the course of their initial 40-year operating licence, this makes it much more difficult for anti-nuclear groups to find such issues.
A number of utilities have still been holding back on licence extensions, Tuckman said, “but as they’re seeing the NRC show some discipline in its process, I’m seeing many more coming out of the woodwork. At every meeting with the NRC on this lately, I’ve been seeing more and more utilities attending.” Commission Chair Shirley Ann Jackson recently estimated that the Oconee licence renewal review will take 25 months, and possibly less. Bear in mind, too, that Oconee’s NRC review will be the first of its kind. Subsequent reviews should take less time as the applicant and the NRC get down a learning curve.
Longer-running plants could help the industry’s recruitment problem. As NEI’s Joe Colvin notes, a prospective nuclear engineering student wants a challenging career with a long future. “So when these students see an industry with plants that have only 10-15 years left on their operating licences, how do they view their career prospects? If we told them that we’re going to renew the licence of this plant, and it has at least 30 more years left in its operating life, then that’s more than a career.”
CONSOLIDATIONS BRING OPERATING EFFICIENCIES
The growing consolidation of nuclear power plants into fewer utilities or operating consortia promises to reduce nuclear generating costs even further, making licence extensions more attractive. Entergy Nuclear, for example, and AmerGen, a joint venture of Philadelphia Electric Company (PECO) and British Energy, are “generating lots of cash” from well-run nuclear plants, and are looking to buy more, observes one vendor executive. Some of the better plants are also surprisingly inexpensive to buy compared to the original capital cost of these units or the cost of new units today, he says. Remarking on the same trend, NEI’s Colvin cites the sale of TMI Unit 1 and Pilgrim, and the pending sales of Clinton, Nine Mile Point, and Vermont Yankee, as examples of the consolidation that competition has made possible. Responding to these market changes, even General Public Utilities, which had abandoned an earlier effort to sell its Oyster Creek unit, is again seeking buyers.
Besides nuclear plant acquisitions, consolidation is also proceeding through corporate mergers and asset exchanges. The recent exchange between First Energy and Duquesne Light is a case in point. As a result of the exchange with the Pittsburgh-based Duquesne, First Energy, a midwestern utility holding company, now has controlling interests in the Beaver Valley, Davis-Bessie, and Perry stations.
Even where utilities are not acquiring, divesting, or swapping nuclear plants, they are forming nuclear management companies to improve their existing reactors’ efficiencies. Northern States Power Company, Wisconsin Electric Power Company and Wisconsin Public Service, which operate six nuclear units among them, have recently formed a nuclear management company. Alliant Energy, which operates the Duane Arnold nuclear plant in Iowa, is seeking approval from the Securities and Exchange Commission to join later.
Altogether, the nuclear capacity affected by current or pending consolidations, whether through sales, swaps, or joint operating companies, is 12.4 GW, about an eighth of total 1997 net US nuclear capacity, according to the NRC (see table). And this is just the beginning of a trend now in its first few months of life. “Given what we now see happening in the marketplace, we may likely eventually go to about half the number of operators we have today,” Colvin says.
In addition to reducing costs, consolidation will also permit more investment in improving the performance and extending the operating lives of existing US reactors. These reactors will require continuing improvements to stay competitive, says Thomas Mistler, who recently retired from Westinghouse Electric Company as Senior Vice President of its Energy Systems Business Unit. Mistler, who was also a member of the NEI Executive Committee, points out that to extend a plant’s operating licence, for example, or uprate its capacity with higher-burnup fuel, a reactor operating company will need advanced engineering design and analysis. These needs “will keep US suppliers, who are also fuel suppliers, busy for some time,” Mistler argues. He warns, however, that without another order for a new reactor, US vendors’ existing capability to deliver an integrated reactor and plant system will “dissipate.”
ASIAN ORDERS SUSTAIN VENDORS
Fortunately, US vendors have current or pending new orders in Asia that should carry them for several years. ABB-Combustion Engineering is working on five units at the Yonggwang and Ulchin sites in Korea, in addition to the three already in operation. BNFL-Westinghouse and its partner Mitsubishi Heavy Industries expect to receive informal approval in the next several months for design work on two units at the Tsuruga site in Japan. General Electric and its Japanese manufacturing partners Hitachi and Toshiba have recently completed two advanced boiling water reactor (ABWR) units at the Kashiwazaki site, and GE is working on design and construction of two more ABWRs at the Lungmen site in Taiwan.
China has recently signalled that it may defer some previously-planned new orders in its nuclear construction programme due to economic conditions, but the impacts of these decisions, assuming they are made, remains unclear at this point. In any case, it is more likely to be a matter of when, rather than if, China orders new nuclear capacity for its burgeoning demand. According to the EIA, nuclear capacity is projected to reach 18.7 GWe by 2020. This is a big number, and unless China resorts to wholesale cancellations and radical reductions in its nuclear programme, there will still be a lot of work for US and other vendors.
GLOBAL FORMULA FOR COMPETITIVENESS
A US capability to manufacture a number of key reactor components no longer exists, but global commerce at the threshold of the 21st century no longer requires it for a successful US vendor industry, Mistler maintains. He makes a distinction between American vendors’ key to survival – their ability to design and deliver an integrated reactor system – and their ability to fabricate major components of that system.
“The industry has already developed a virtual global factory,” he said. “Americans linked themselves to this capability by very effective technology transfer. There are now production facilities in Spain and Japan that can deliver reactor vessels, steam generators, and other key components that meet the industry’s high quality standards.” That evolution has caused the US to abandon much of its heavy industrial capability to build major components, but because of what Mistler calls the “tight licensing requirements” on US vendors’ technology transfer, their capability to integrate these systems into a working nuclear power unit has remained here. “So our production capacity for building these components is diminished, but the ability of US suppliers to deliver an integrated system is still very much alive.” At some point, the strong economics for well-run existing reactors will probably persuade a generating company to consider an order for a new one, another vendor executive believes. “It’s just very hard to predict when that might happen.” A major spike in natural gas prices, a carbon tax, or a serious national effort to address US greenhouse gas emission commitments at Kyoto would have a major impact on the timing of any new reactor order, as would the successful development of a repository for nuclear wastes. But these developments are too hard to predict, let alone count on.
If one thing is predictable, however, it is that nuclear generating companies will have a keen and continuing interest in extracting better performance from their facilities at lower cost. If US vendors use their stay of commercial execution as an opportunity for reconceiving reactor design, fabrication, and system integration – and competitive pressures will force them to – there is a real prospect for commercial survival.
A PRESCRIPTION FOR NEW US ORDERS
The key to achieving a competitive industry for new reactors in the US market is to reduce high capital costs, says George Davis, Director of Government Programs for ABB-Combustion Engineering. Even the newly-certified standardised Advanced Light Water Reactor (ALWR) designs have had to incorporate substantial redundancy and overdesign to satisfy prescriptive regulatory requirements and industry standards. These requirements might have been affordable when electricity prices were regulated based on a utility’s cost-of-service; back then, utilities could hope to pass along the higher capital costs of nuclear units. But the overconservatism made possible by regulated prices has resulted, he said, in “gold-plated plants that may not be able to compete in the deregulated US marketplace of the future.” To compete with new fossil-fired plants in this marketplace, he believes, new reactors will have to be at least a third less expensive to build.
NEI as well as the US reactor vendors recognise that ALWR’s were not designed for a market based on open retail competition. Accordingly they have just launched an initiative addressing the changes that might be needed if there are to be new reactor orders in the United States by the middle of the next decade. NEI’s Colvin says “we have to come up with criteria.” The group will discuss “the impediments that would need to be removed to build the next nuclear plant in the US,” says Colvin. This effort is expected to be completed by summer.
The key to reducing capital costs, which is the key to the industry’s future, Davis believes, is to rethink the entire reactor design process. This will only be possible with the use of risk-informed regulation, an approach that would focus on the places in the nuclear plant where the probabilities and consequences of failure are significant. This is not just a matter of rewriting regulatory safety standards, Davis says; it’s more a matter of figuring out how to meet them in a more cost-effective way.
Like the US auto industry of 20 years ago, the nuclear reactor industry has hardly begun to capture the benefits of computer technology, sensor technology, and miniaturisation to enhance safety, improve reliability, and reduce production costs. These technologies could bring significant reductions in capital costs.
If this greater use of smart technology can succeed in increasing reliability and maintaining safety at the component level, there will be much less need for redundancy at the system level, Davis argues. With risk-informed assessments to simplify reactor designs, this would permit much lower capital costs without sacrifices in safety or reliability.
Getting to that point will take “about ten years and a lot of money,” Davis concedes. It will also require an international effort, because the investment will be more than any one company or any one country could probably justify. “But if we don’t do something,” he says, “there isn’t going to be a market for new reactors in the US.” The US nuclear industry has certainly bought itself some time and a strategy is emerging, based on consolidation and plant life extension, that will keep the vendors busy for some time. Success may also depend on a growing public recognition that the country cannot afford to abandon its largest and most reliable source of power that is free of greenhouse gas emissions. These conditions for success are not the stuff of reassurance, but complacency is not what the industry needs at this point. The industry’s growing competitiveness and commitment to future development may help to see it through until better times arrive.
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