Introduction

Nuclear power accounts for about 13 percent of the Nation's electricity generating capacity and about 19 percent of total electricity generation.⁶⁷ As the electric utility industry is restructured, the 105 commercial nuclear power plants currently in operation will face increasing competition.⁶⁸ The prospect of having to compete on the basis of market value of electricity threatens the continued operation of a number of units. From January 1997 through January 1998, utilities have announced the retirement of five units at four plants before the expiration of their operating licenses (Table 10). In each case, the utility owner calculated that continued operation was uneconomical given the costs of operating the plant, the market value of the electricity, and the long-term prospects for making the plant economical.

The continued operation of the remaining nuclear power plants depends on the ability of each plant owner to recover operating and capital improvement (i.e., capital additions) costs.⁶⁹ If revenues under competition exceed operating and capital improvement costs, the plant will probably continue to operate. Plant owners, however, may have stranded costs because of the inability of the plant to generate revenues that fully cover sunk capital costs. By contrast, if revenues do not exceed operating and capital improvement costs and the utility has no real prospect of changing this relationship, the plant will most likely be retired or, if possible, sold to another company that believes it can make the long-run operating costs economical. These decisions and relationships take place on a unit-by-unit basis according to the specific factors affecting the unit, State, and local power market.

This chapter discusses the potential impacts of electric power restructuring on the nuclear power industry. The issues facing the industry include stranded cost recovery, market competitiveness of plants, and the funds needed to cover decommissioning costs. Potential impacts on the nuclear fuel industry are also included.

Stranded Cost Recovery

Under the regulatory frameworks that have prevailed at the State and Federal levels, utilities are permitted to recover all their prudently incurred expenses and to earn a rate of return that fairly compensates the providers of capital.⁷⁰ In a competitive market, utilities will charge market rates for their electric power. The market rates will establish the value of the utilities' nuclear assets. If they cover operating expenses but not all the capital charges, the assets will essentially be devalued, but the plants may continue to operate. If the market rates fail to cover operating expenses, however, the plants will most likely be shut down or sold.

Over the past decade, several nuclear plants have been offered for sale in whole or in part. Before prematurely retiring the Rancho Seco plant in 1989, the Sacramento Municipal Utilities District was involved in discussions with Duke Power, Bechtel, and others about a potential sale. In the late 1980s, Consumers Power Company evaluated selling its Palisades plant, located in South Haven, Michigan, to a consortium led by Westinghouse. In 1996 and 1997, the owners of Maine Yankee plant held discussions about selling the plant to Philadelphia Electric Company (PECO). Ultimately, none of the plants was sold.

Table 10. List of Recent Nuclear Plant Closings as of January 31, 1998

Currently, General Public Utilities (GPU) has offered for sale both its nuclear units, Oyster Creek and Three Mile Island-1.⁷¹ On April 16, 1998, Boston Edison announced that it was seeking qualified buyers for its Pilgrim nuclear plant.⁷² Potential buyers for nuclear plants are, in general, more aggressive utilities with large and successful nuclear plant operations, such as Duke Power and AmerGen, a joint venture of PECO and British Energy. As issues such as divestiture  and  mitigation of stranded costs become major factors in utility restructuring, more nuclear plants may be offered for purchase.

In the electric utility industry, the difference between full cost recovery under regulation and market-based income is "stranded cost." Figure 8 shows a simplified depiction of the potentially strandable nuclear cost components. With the advent of competition, utilities with high-cost nuclear units in States requiring retail competition may not be able to recover all the costs they have incurred to build the plants, the costs they are incurring to operate them, or the costs they are committed to incur to decommission them. To the extent that these costs would have been recoverable under conventional cost-of-service regulation, the unrecoverable amounts will be stranded.⁷³

Figure 8. Simplified Depiction of Potentially Stranded Nuclear Cost (Click graph to view full size)

The nuclear stranded cost issue is a question of recovery—that is, how much can be recovered from ratepayers through the State procedures established through legislation or regulatory orders and how utility stock and bondholders will be affected by retail competition in electricity markets.

State Approaches to Stranded Costs

For the States that have approved retail competition, most allow full or substantial recovery of stranded capital assets, decommissioning costs, and regulatory assets incurred as of a specific date. In many cases, the accelerated recovery of stranded costs is timed to coincide with the introduction of competition at the State level. Recovery of stranded costs typically takes place over a period of about 4 to 9 years. Overall costs to ratepayers are reduced via "securitization" of the stranded cost income streams and through utility acceptance of reduced but accelerated cost recovery.⁷⁸

All States with restructuring programs are attempting to mitigate stranded costs by aggressive cost cutting, staff reductions, and incentive pay plans. Another way to mitigate costs is to sell the stranded assets. In New England, for example, old and apparently uneconomical non-nuclear generating plants have brought much higher prices than valuations established by the selling utility or the book value of the assets. One way that this increased valuation can arise is if the acquiring utility places a high value on the land, site, and non-generating infrastructure (e.g., transmission connections) associated with the uneconomical generating assets. Because the higher value could not be realized by the continued use of the generating assets under regulation but could be realized under competition by replacing the plant with a new, more efficient plant, the revaluation of the non-generating assets may offset the devaluation of the generating assets. For nuclear assets, the primary way for the valuations to be increased is for a plant to be acquired by a more efficient operator—presumably, one with many nuclear plants and economies of scale, which can justify paying more for the asset than it is worth to the selling utility.

The following sections provide examples of State rulings on specific nuclear stranded cost items.

Capital Costs

Virtually all the more recently constructed nuclear plants, such as the Seabrook, South Texas, and Comanche Peak plants, have substantial stranded capital costs. Stranded capital costs exceeding $1 billion per unit are not unusual for units that originally cost $2 billion or more to construct. In general, States are treating stranded capital costs as fully or partially recoverable; however, no one clear theme has emerged among the States. The following approaches have been, or are about to be, implemented:

• In California, restructuring legislation passed in 1996 included recovery of transition (i.e., stranded) costs and provided for a 10-percent electricity rate reduction for residential and small commercial customers by March 31, 1998. The restructuring legislation authorized utilities to finance a portion of their transition costs with "rate reduction bonds." The maturity period of the bonds is expected to extend beyond the transition period at a below-market rate of return. In the case of Pacific Gas & Electric's (PG&E) Diablo Canyon nuclear power plant, sunken costs will be fully recovered over a period ending in 2001 at a return on common equity equal to 90 percent of PG&E's embedded cost of debt (7.52 percent in 1996).⁷⁹ For Southern California Edison (SCE), sunk costs at the Palo Verde nuclear power plant will be recovered over the same period at a 7.35-percent rate of return on ratebase.⁸⁰ Southern California Edison will also use a balancing account to pass through Palo Verde's incremental operating costs (considered reasonable so long as they do not exceed 30 percent of a baseline forecast and the site's gross annual capacity factor does not go below 55 percent). Recovery of San Onofre nuclear power plant operating costs will be on a fixed per-kilowatthour basis. This difference recognizes that SCE is the operator of San Onofre but only a minority partner of Palo Verde.⁸¹
  
  
• In Pennsylvania, recovery is limited to "just and reasonable" amounts, as determined prospectively by the State Public Utilities Commission (PUC). These costs, after mitigation by the utility, are to be recovered through the Competitive Transition Charge (CTC) approved by the PUC and collected from distribution customers for up to 9 years.⁸²
  
  
• In New Jersey, the State is proposing that utilities have an opportunity for a limited number of years to recover stranded generating capacity costs through rates, with the intent to open the electricity market to all retail customers by July 2000. The determination of stranded cost recovery would be undertaken on a case-by-case basis—100 percent recovery of all eligible stranded costs would not be guaranteed. The opportunity for full recovery of such eligible costs would be contingent upon and may be constrained by the utility's meeting a number of conditions, including achieving the goal of delivering a near-term rate reduction to customers of 5 to 10 percent.⁸³ Public Service Electric & Gas (PSE&G) plans to reduce its rates by a combination of securitizing a portion of its strandable costs and extending the depreciation period of its distribution assets. Securitization involves the financing of stranded costs, up to a specified limit, by insurance of debt and subsequent liquidation of it through a surcharge on the utility's customers. The extension of the depreciation period for the distribution assets (to 45 years from 28 years) results in a theoretical increase in depreciation reserves, which PSE&G proposes to use as a partial offset for stranded generating assets.⁸⁴

Decommissioning Costs

A large portion of the stranded costs for nuclear power plants is associated with the amount of unrecovered decommissioning costs. Currently, decommissioning costs appear to average slightly more than $400 million for a single-unit station and about $700 million for a two-unit station.⁸⁵ A major variable in decommissioning cost and timing is the cost of low-level waste (LLW) disposal, which has been increasing steadily over the past 10 years, with no clear abatement in sight.

The procedure for collecting decommissioning costs is through annual payments to a trust fund over the expected 40-year licensed operating life of the plant.⁸⁶ Because of the payment structure, utilities will not collect half of the required final balance until after the 30^th year of contributions and accruals. Since more than half of the current capacity has 20 or more years of life remaining, the assets in decommissioning trusts are substantially below the estimated terminal requirements. On a national average basis, they are about one-third of the estimated terminal values.

In the past, regulatory authorities have permitted utilities to collect all or most of the decommissioning cost shortfall from ratepayers for the commercial reactors that were shut down before their operating licenses expired. Regulatory authorities generally recognize that the issue of decommissioning cost shortfalls is related in principle to the issue of unrecovered capital costs (i.e., liabilities of a plant no longer generating revenue), and they seem to treat such costs similarly.⁸⁷

With the advent of restructuring, most States are treating decommissioning costs as fully recoverable stranded costs. For the most part, decommissioning costs that could not be covered by revenues would be recovered through a transmission charge or a charge on departing customers. The prospect for adjustments in decommissioning costs over time is unclear. Some States (e.g., Rhode Island) will allow decommissioning cost adjustments that reflect new information about the actual cost to decommission a unit. In Maine, a nuclear utility will have one opportunity to estimate and charge decommissioning costs under restructuring.⁸⁸ After that point, the utility will bear all the risk of cost increases.

Another issue in the debate over stranded nuclear decommissioning costs concerns the operating costs from the time a utility terminates commercial operation to the time it receives its possession-only license (POL). Nuclear power plant operators incur costs to maintain the plant at a commercial level. Aside from the defueling activity itself, other major cost areas are plant staffing, maintenance, security, and compliance with Nuclear Regulatory Commission (NRC) regulations.

Utilities currently treat these costs as operating costs, not decommissioning costs. For a typical operating plant with a staff of 500 to 1,500, annual transition costs could be in the range of $50 million to $150 million. Recently, POL transition periods have been on the order of 1 to 2 years. These periods should decline to 3 to 6 months for plants that shut down according to a planned retirement schedule. Plants that shut down abruptly, however, may continue to have transition periods of 2 years or more, and their transition costs could be $100 million to $250 million. Because these costs are part of nuclear operations (not decommissioning), they do not appear to be recoverable under any definition of stranded costs. Utilities will be able to recover these costs if plants are retired while still under rate regulation; however, if plants are retired in deregulated, competitive markets, the costs may not be recoverable.

Implications of Denying Stranded Cost Recovery

Although the States are establishing procedures for stranded cost recovery, those procedures may not result in full recovery of nuclear stranded costs because of time limits on recovery or the prescribed procedure for determining stranded costs. Without substantial stranded cost recovery, a significant number of nuclear utilities will suffer large losses in market value.

Three groups of nuclear utilities are at particularly high risk: utilities with heavy investments in relatively recent (and therefore relatively costly) nuclear plants; utilities with older, poorer performing units; and utilities with relatively concentrated nuclear exposure regardless of the vintage of the plants. At-risk utilities include a few very large investor-owned utilities, such as Commonwealth Edison, and a considerable number of municipal utilities and cooperatives. For example, large shares of the Catawba and McGuire plants in North Carolina and the River Bend plant in Louisiana are owned or have been owned by municipal utilities and cooperatives, which are at risk as a result of asset concentration, independent of the absolute capital or operating costs of their nuclear plants.

Competitiveness of Nuclear Plants

Figure 9. Comparison of Average O&M Costs for U.S. Nuclear and Coal-Fired Power Plants, 1981-1996 (Click graph to view full size)

Although nuclear plants are competitive with coal-fired plants on average, there are wide variations among individual nuclear units (Figure 10). For the 1994-1996 period, roughly 16 percent of the units had O&M costs exceeding 2.5 cents per kilowatthour. About 12 percent of the units had O&M costs exceeding 3.0 cents per kilowatthour. If significant additional costs must be incurred to ensure safety and reliability, some nuclear plants may cease to be competitive.

Figure 10. Variation in O&M Costs for U.S. Nuclear Plants, 1994-1996 (Click graph to view full size)

Many utilities, including GPU Nuclear Corporation (the owner of Oyster Creek), Commonwealth Edison (the owner of Dresden and Quad Cities), Wisconsin Public Service (the owner of Kewaunee), and Boston Edison (the owner of Pilgrim) have publicly addressed these issues, with varying results. In some cases (e.g., Oyster Creek), the utility has said that the plant will either be sold or closed, because the prospects for making it competitive are poor.⁹⁴ In other cases (e.g., Pilgrim), the utility has said that the plant will be brought up to competitive standards over the next few years and will not be retired prematurely.⁹⁵ The following section outlines some of the factors that go into these decisions.

Market Value

Under restructuring, the market value for long-term firm capacity and energy in each region of the country will determine the value of nuclear power plants. In the short term, firm capacity and energy will be available in most of the country for the incremental price of coal-fired energy from plants operated at less than baseload levels. This price is less than $20 per megawatthour in most of the country, although it is higher in some regions, such as New England. No utility, however, retires a plant with 10 to 20 years of remaining life because replacement power costs are low for the next year or two. Figure 11 shows the current average operating costs of nuclear power plants by North American Electric Reliability Council region.

Regional differences will play a major role in market value assessments. In New England, for example, coal-fired power is expensive because the coal sources are distant and the regulations governing air emissions and siting are stringent. Transmission of surplus coal-fired power from the Midwest and Mid-Atlantic would lower prices, but it is limited by the existing transmission capacity to New England, which is much less than would be optimal, given the differences in relative generating costs among the regions. Over the long term, new gas-fired combined-cycle capacity in New England and upgraded or possibly new transmission capacity to other regions, including Canada, may eliminate some of the regional pricing differences. In the Southwest, on the other hand, almost all these factors are reversed. Coal-fired power is available, transmission constraints are minimal, and surplus power is exported to Mexico. The net result is that the market value for power in the Southwest is much less than in New England.

As surplus coal-fired capacity available for baseload generation is used up in the first half of the next decade, prices may rise, making nuclear-powered generation more competitive. Prices may also rise in the early part of the next century as stringent sulfur dioxide emissions standards under the Clean Air Act take hold. New emissions standards for nitrogen oxides, as proposed by the U.S. Environmental Protection Agency in October 1997, would also significantly add to long-run operating costs. Limiting these increases in the long-run market price for baseload capacity and energy will be new combined-cycle gas-fired power plants, which can deliver power and energy at less than $40 per megawatthour, including capital recovery.

Operation and Maintenance Costs

If nuclear power plants are to remain viable in deregulated electricity markets, their O&M costs will have to be maintained at the competitive levels achieved over the past decade. Factors contributing to nuclear O&M costs include plant size and age, required capital expenditures, and capacity factor.

Size

Roughly 70 percent of the O&M expenditures for nuclear units are for labor. Labor costs are largely fixed by regulatory requirements that do not relate to size. Moreover, multi-unit plants share a considerable amount of the labor relating to regulatory compliance, procurement, permitting, etc. Thus, larger units and multi-unit plants have the potential to be less costly to operate per kilowatthour than smaller units and single-unit plants. Most of the nuclear units prematurely retired or announced for premature retirement in recent years have been single-unit plants (e.g., Trojan, Rancho Seco, Maine Yankee, Big Rock Point, Oyster Creek, and Haddam Neck) and many are small units.

ECAR	ERCOT	MAAC
MAIN	MAPP	NPCC
SERC	SPP	WSCC
Figure 11. Variation in O&M Costs for U.S. Nuclear Power Plants by NERC Region, 1994-1996 (Click graph to view full size)

Age

The age of a plant is significant for several reasons. First, as a plant passes 20 or 25 years of its 40-year license life, the remaining lifetime of the plant may be too short to permit competitive amortization of the costs of major capital improvements, such as steam generator replacements. Second, older plants are usually smaller, meaning that the fixed costs of replacements are spread over fewer kilowatthours of generation. Third, older plants have often required major upgrades because of their vintage rather than their operational performance. Several units (e.g., San Onofre 1, Yankee Rowe) have been prematurely retired because they could not economically be brought up to current standards while remaining economical. On the other hand, one unit—Robert Ginna, a 470-megawatt unit in Rochester, New York—had its steam generators replaced in 1995 because the utility, Rochester Gas and Electric Corporation, determined that the plant's long-run economics were favorable.

Large Capital Expenditures

Another major factor in determining a plant's competitiveness is whether significant capital expenditures will be needed in the near future for continued operation. Such capital expenditures are not sunk costs and, in a competitive marketplace, must be included in the cost of electricity generation. A plant that is currently competitive but is anticipated to require a large influx of capital in the next several years is a less desirable economic asset and may simply be operated until a large capital infusion is needed and then shut down.

The largest capital expenditure typically facing existing nuclear plants (pressurized-water reactors only) is the cost to replace degraded steam generators.⁹⁶ As a result of degraded steam generators, Commonwealth Edison announced in January 1998 that it was permanently shutting down its Zion plant.⁹⁷

Capacity Factor

The capacity factor of a nuclear power plant has a significant impact on the cost of power from the plant. Although O&M costs usually are seen as variable costs, they are essentially fixed for any operational nuclear power plant. Nuclear fuel costs are also mostly fixed. Thus, most of the change in the capacity factor goes directly to the bottom line of the utility's income statement. For a 1,000-megawatt plant selling power at $25 per megawatthour, each capacity factor point generates $2.2 million in revenue per year and only slightly less in before-tax net income. The net present value of this percentage point change over a typical 20-year remaining life is $15 million to $20 million, depending on the discount rate. Not surprisingly, utilities are willing to make investments to improve plant performance. Similarly, the possibility of multi-point increases in capacity factors is a major influence on the retirement decision. For plants that have historically operated far below the industry average capacity factor (currently in the mid- to upper 70s), the prospect of a double-digit increase in capacity factors may justify expenditures to improve performance.

Decommissioning Assurance

Restructuring of the electricity industry introduces issues that concern the NRC and its relationship to utilities demonstrating financial assurance for decommissioning funds. The current NRC rule is based on the premise that the operator of a nuclear power plant will be an ongoing, capital-intensive concern with significant financial resources, including ratebase access, to cover any shortfall in the plant's decommissioning fund.⁹⁸

With the advent of restructuring, utilities will no longer have a guaranteed customer base. Most State commissions have accepted full recovery for decommissioning costs, but it is unclear how the costs will be translated into rates or charged to existing and former customers. In addition, it is unclear how future increases in decommissioning costs could or would be passed on to former customers.

The NRC has statutory authority to regulate the decommissioning of its licensed nuclear facilities. On April 8, 1996, the NRC posted an announcement in the Federal Register soliciting public comment for a proposed rulemaking, stating it is considering rulemaking that would:

• Require that electric utility reactor licensees assure the NRC that they can finance the full estimated cost of decommissioning if they are no longer subject to rate regulation by State agencies or by the Federal Energy Regulatory Commission and do not have a guaranteed source of income.
  
  
• Require utility licensees to report periodically on the status of their decommissioning funds. The present rule has no such requirement because State and Federal rate-regulating bodies actively monitor the funds. A restructured nuclear utility would have no such monitoring.⁹⁹

The proposed rulemaking would assign financial oversight to the NRC by requiring licensees to report periodically the status of their decommissioning funds to the NRC. Whether the final rule does grant this authority to the NRC remains to be seen. In the past, however, the nuclear industry has resisted any proposals that would give NRC financial oversight responsibility.

Impacts on the Nuclear Fuel Industry

To produce fuel suitable for loading into a nuclear power plant's reactor core, naturally occurring uranium must undergo the following manufacturing steps: (1) extracting and processing ore to produce uranium concentrate (U₃O₈), (2) conversion, (3) enrichment, and (4) fuel fabrication (see textbox, p. 35). These steps are referred to as the "front end" of the nuclear fuel cycle. In contrast, the management of spent fuel discharged from reactors is referred to as the "back end" of the nuclear fuel cycle. Products or services for each front-end stage are bought and sold in separate markets. Available capacity, inventory level, and the application of trade restrictions and other national policies differ from market to market. Consequently, trends in prices may show little correlation between markets. For example, the average annual spot-market price for the restricted U.S. uranium market increased by 36 percent from 1995 to 1996, compared with an increase of only 6 percent in the average annual spot-market price for the restricted U.S. enrichment market.¹⁰⁰, ¹⁰¹, ¹⁰²

The restructuring of the electric power industry is expected to affect the demand for nuclear fuel as uneconomical plants are retired early and the operators of the remaining plants focus on the marginal costs of power production. This section describes the potential impacts that the restructuring of the electricity industry will have on the nuclear fuel industry in the following areas: (1) changing emphasis on fuel costs, (2) declining demand for uranium and nuclear fuel services, (3) availability of uranium made surplus by plant closures, (4) decrease in inventories, (5) consolidation in nuclear fuel procurement, and (6) consolidation in the nuclear fuel industry.

Changing Emphasis on Fuel Costs

Unlike nonfuel O&M and capital additions costs, the cost of fuel has not been considered critical in determining the economic viability of existing nuclear power plants. Factors contributing to this view include: (1) fuel represents a relatively small share of power production costs; (2) fuel has been priced at historically low levels; and (3) utilities, operating as regulated monopolies, have generally been able to pass through fuel costs to customers. With the restructuring of the electric power industry, nuclear generating companies will be selling a commodity (electricity) in a highly competitive marketplace with little opportunity to differentiate their product other than by price. In this setting, they will be forced to focus on the incremental costs of production, including those for fuel, to remain competitive.

Fuel composed just 27 percent of the average nuclear power production expenses reported by major U.S. investor-owned utilities in 1996.¹⁰³ The remaining 73 percent of average nuclear production expenses was categorized as non-fuel O&M. In contrast, fuel contributed to a much greater share of the average power production expenses incurred by fossil steam, gas turbine, and small-scale plants (Figure 12).¹⁰⁴

Figure 12. Fuel as a Share of Average Power Production Expenses for Plants Owned by Major U.S. Investor-Owned Electric Utilities, 1996 (Click graph to view full size)

A general condition of oversupply has kept the prices of uranium and nuclear fuel cycle services at historically low levels (Figure 13).¹⁰⁵ The average annual spot-market price for the U.S. uranium market has declined to levels substantially lower than in the late 1970s, in sharp contrast  to  the  substantial  increases  in nonfuel O&M costs reported by nuclear power plants during the 1980s (Figure 9). There is excess production capacity in both the enrichment and fuel fabrication markets. The current world enrichment services capacity is estimated at 49.5 million separative work units (SWU), compared to 33.9 million SWU projected to be required by the world's nuclear reactors in 1998.¹⁰⁶, ¹⁰⁷, ¹⁰⁸ The current world capacity for light-water reactor fuel fabrication has been estimated at 150 percent of requirements.¹⁰⁹, ¹¹⁰ The market conditions responsible for low prices have enabled utilities to exercise a certain amount of leverage in negotiating favorable contract terms for the purchase of uranium and nuclear fuel cycle services.

• As regulated monopolies, utilities were able to pass through fuel costs to customers as long as such costs were determined to be prudent by State public utility commissions; however, the move toward full competition will make it increasingly difficult for nuclear generating companies to recover above-market generation costs. For example, some States have implemented performance-based ratemaking in exchange for allowing utilities to accelerate the recovery of their stranded costs as a transition to full competition (see text box on page 37). Performance-based ratemaking affects the profits of utilities by setting a level of operating revenues available to utilities for covering the day-by-day costs of generating electricity. To realize a profit, the utility must keep its production costs below the available revenue limit. However, the fixed portion of production costs, such as those for engineering and plant safety, are considered as unavoidable. Therefore, a nuclear generating company must focus on the variable portion of production costs, including fuel, to improve profit margins.

Declining Demand for Uranium and Nuclear

Figure 13. Spot Market Price for the U.S. Uranium Market, 1976-1996 (Click graph to view full size)

Because of differences in the types of reactors and management policies, not all reactors are operated in the same way. For this analysis, fuel cycle requirements for the Zion units are assumed to approximate those for plants with a similar generating capacity. Based on this assumption, uranium and enrichment services requirements would be reduced by about 500,000 pounds U₃O₈ and about 125,000 SWU, respectively, for each 1,000-MWe increment of net generating capacity retired from service. Thus, the closure of a 1,000-MWe nuclear unit would have only a marginal impact on total U.S. requirements, which are projected to be 49.4 million pounds U₃O₈ and 11.1 million SWU for 1998.¹¹³ Similarly, requirements for conversion and fuel fabrication services would be affected only marginally.

From the perspective of the U.S. nuclear fuel supply industry, however, each plant closure represents the loss of an actual or potential customer in a highly competitive marketplace. Plant closures could have a detrimental impact on suppliers that have relatively high marginal costs of production or have large shares of their business concentrated in the United States. The following discussion focuses on the U.S. uranium and enrichment service industries.

Because of differences in the quality of ore reserves, uranium concentrate (U₃O₈) is more expensive to produce in  the  United States than in such countries as Australia and Canada. In addition, to earn foreign exchange, the Commonwealth of Independent States and other countries have supplied uranium to utilities in the United States from mines that might not be economical to operate under U.S. accounting principles.¹¹⁴ Driven by competitive pricing, imports have become the most important source of uranium for meeting U.S. requirements. The equivalent of 43.0 million pounds U₃O₈ was imported by U.S. suppliers and utilities in 1997.¹¹⁵, ¹¹⁶ In contrast, domestic uranium concentrate production was 5.6 million pounds U₃O₈ in 1997.¹¹⁷

A decline in demand brought about by nuclear power plant closings could weaken the price of uranium, forcing producers with marginal production costs above the market price to suspend operations. Under a scenario of declining price, relatively higher cost U.S. production would be particularly susceptible to competitive pressures exerted by imports.

The United States Enrichment Corporation (USEC), the only domestic provider of enrichment services, reported that contracts with U.S. utilities accounted for more than 60 percent of its total worldwide sales in 1996.¹¹⁸ It provided enrichment services to four-fifths of the domestic nuclear power generating industry in 1997.¹¹⁹ Thus, USEC's earnings would be more sensitive to closings of U.S. nuclear power plants than would those of enrichers with less exposure to the U.S. market. Because enrichment services are sold under long-term contracts, USEC could be challenged to find new customers should the domestic market be substantially reduced.

Availability of Uranium Made Surplus by Plant

With restructuring, some companies may completely exit the nuclear power generation industry. If they do, they are likely to sell inventories of uranium no longer needed to meet previously scheduled fuel reloads. For example, inventory equivalent to approximately 500,000 pounds U₃O₈ became surplus as a result of the decision by Connecticut Yankee Atomic Power Co. (CYAP) to close the Haddam Neck nuclear power plant permanently. This quantity of uranium is equivalent to about 9 percent of the 5.6 million pounds of uranium produced in the United States during 1996.¹²⁰ In August 1997, Northeast Utilities, the parent company of CYAP, sold the uranium through an auction.

The sale of uranium made surplus by the closure of nuclear power plants displaces other sources of supply. The extent to which surplus uranium impacts the market depends on the timing and mechanism involved in selling the uranium. At the time that Northeast Utilities announced its intent to sell uranium made surplus by the closure of Haddam Neck, the uranium market had experienced a significant decline in price. The monthly spot-market price for the restricted U.S. market declined from $16.50 per pound U₃O₈ in July 1996 to $10.20 per pound U₃O₈ in August 1997. During the third quarter of 1996, the demand for uranium on the spot market reached a low not recorded since 1988.¹²¹

In addition to Northeast Utilities, the U.S. Department of Energy (DOE) announced plans to sell uranium that had been declared surplus.¹²² The planned sales contributed to the downward pressure on price, with other sellers offering uranium at prices lower than the prevailing spot-market price in order to complete sales, before Northeast Utilities and DOE entered the market. By using an auction, however, Northeast Utilities was in a position to decline bids that were below the prevailing spot-market price. Buyers anticipating no further decline in spot-market price provided bids at or above the prevailing market to procure uranium at relatively low prices.¹²³ Prospective buyers apparently withheld demand until they perceived that the anticipated sales of surplus uranium would no longer push prices lower. Following sales of uranium by both Northeast Utilities and DOE, the spot-market price for the restricted U.S. market rose to $12.75 per pound U₃O₈ in October 1997.

Decrease in Inventories

In a competitive business environment, companies have historically sought to minimize inventory holding costs. For example, it is well documented that U.S. automobile manufacturers have met this goal by matching the delivery of parts from suppliers with assembly activities. This strategy has been popularly referred to as "just-in-time" delivery management. In contrast, nuclear utilities historically have favored the maintenance of inventories in excess of immediate fuel requirements.

Inventories of uranium are managed by utilities as part of work-in-process or "pipeline" materials required for the preparation of nuclear fuel to be loaded into the core of reactors.¹²⁴ In addition to the pipeline category, utilities also hold strategic inventories that could be used to minimize possible disruptions in supply, as well as hedging inventories used to take advantage of movements in uranium spot-market prices. Countries distant to uranium supply or nuclear fuel cycle services are more likely to hold strategic inventories. In contrast, some utilities in the United States, beginning in the 1980s, have held only inventories of the magnitude needed in the pipeline for a particular fuel reload.¹²⁵ Nevertheless, U.S. utilities have acquired excess inventories to hedge against a rise in prices. For example, discretionary purchases made in 1995 to hedge against a possible price rise contributed to an increased volume of spot-market transactions and the first increase in U.S. utilities' year-end inventories since 1983.¹²⁶

As the electric power industry moves toward competitive retail markets, nuclear generating companies are likely to minimize inventory holding costs for both economic and regulatory considerations. Public utility commissions are likely to increase the regulatory oversight of fuel costs as they authorize nuclear utilities to recover potentially strandable costs before the onset of fully competitive markets while, at the same time, minimizing the impact on customers. As a result, nuclear power plant operators may not be able to recover their traditional out-of-core inventory holding costs.¹²⁷

To reduce inventory holding costs, the operators of nuclear power plants are expected to seek more flexible delivery schedules from nuclear fuel cycle vendors. Lead times for delivering uranium to each successive nuclear fuel cycle stage will be reduced. In a competitive marketplace, it will be important for fueling outages to coincide with low power market prices. This will require fuel deliveries to be flexible enough to meet the timing of the outages.

Enriched uranium product (EUP) is expected to be used in a just-in-time strategy. EUP can be purchased directly from suppliers for delivery to fuel fabricators.¹²⁸ This differs from traditional procurement practices, whereby the customer purchases uranium and delivers it first to a converter and then to an enricher. Since the customer does not hold title to the uranium contained in the EUP, the price of EUP includes both the cost of the uranium feed (uranium and conversion segments of the nuclear fuel cycle) suitable for enrichment and the enrichment service. By purchasing EUP, nuclear power plant operators no longer would carry the holding costs involved in owning the uranium through the enrichment stage, which would be transferred to the supplier and included in the price of EUP. The largest suppliers of EUP are expected to be enrichers with access to both competitively priced uranium feed and excess enrichment capacity.

Consolidation in Nuclear Fuel Procurement

A likely outcome of electric power industry restructuring is a consolidation in the ownership of nuclear power generation capacity. Consolidation is expected to take place through mergers, acquisitions, and plant closures. Also, some firms with successful nuclear operating experience will seek to provide operations management and related services to other owners of nuclear power plants. Corresponding to the consolidation in nuclear generating companies will be a decline in the number of buyers of uranium and nuclear fuel cycle services. In addition, individual utilities have developed working partnerships for the purpose of creating the economies of scale required to obtain nuclear fuel and other services at lower cost. One such partnership, the Utilities Service Alliance, was formed by 10 utilities.

Those fuel buyers remaining after industry consolidation are expected to engage in highly efficient procurement practices. They will be positioned to seek price discounts and other advantages from suppliers. Faced with oversupply and declining market prices, suppliers have been offering flexible contracts to utilities for many years. One such flexible contract arrangement offers the option to take delivery of additional quantities of uranium. The decision by a nuclear generating company whether or not to exercise such an option depends on market conditions and the contract price. The option is less likely to be exercised when the spot-market price is lower than the contract price. In this situation, a nuclear generating company could decrease its average cost by purchasing some uranium at a lower price on the spot market.

Consolidation in the Nuclear Fuel Industry

The dramatic decline in uranium prices since the late 1970s (Figure 13) has caused a number of companies to exit the industry. Large oil, metal mining, and nuclear services companies based primarily in the United States have divested significant holdings of uranium assets to concentrate on their core businesses.¹²⁹ The buyers generally have been either vertically integrated foreign nuclear fuel cycle companies with foreign government ownership or small domestic uranium mining companies. The consolidation of the uranium industry is continuing, although it is not as intense as it was between about 1985 and 1995.

Recently, the fuel fabrication industry has become the focus of significant consolidation that has been attributed to electric power restructuring. For example, a Siemens executive commented on the joint venture negotiations with British Nuclear Fuels, Ltd. (BNFL), initiated in October 1997, as follows: "These talks are aimed at strengthening the position of both BNFL and Siemens in a competitive market place. The deregulation of the world's electricity markets is increasing the pressure on nuclear power plant operators to reduce their costs and increase plant availability. We want to explore whether a joint venture company will enable us to better meet our customers' requirements by combining our technological and economic strengths."¹³⁰

Fuel fabrication is less of a commodities business than uranium, conversion, or enrichment. Fabricators are involved in the design, manufacture, installation, and service of fuel assemblies for customers with a variety of reactor designs. With a goal of reducing costs, nuclear power generating companies are looking at fuel management practices, such as extending the time between refueling outages. To meet the needs of their customers' changing fuel management practices, fuel fabricators must develop innovative products and services. Facing the high cost of continuously improving the performance of reactor fuel in a potentially declining market, some companies have chosen to exit the business or seek joint venture partners. The remaining companies have one or more of the following strengths: (1) large market share, (2) manufacturing economies of scale, (3) technological innovation, or (4) overall financial strength.

Conclusion

As the States restructure generation markets over the next few years, utilities that cannot cover the operating costs of their nuclear power plants will be forced either to sell their nuclear units or to retire them prematurely. Nuclear units for which operating costs can be covered—including capital improvement costs—probably will remain in operation, but it is unlikely that all their sunk capital costs can be recovered. The inability of plant owners to cover the plant's full costs, including capital costs, under restructuring, produces "stranded costs."

How the States deal with stranded costs among utility shareholders, creditors, ratepayers, and taxpayers will determine whether nuclear utilities face bankruptcy. The stranded cost recovery issue will not, however, greatly influence whether certain nuclear plants remain in operation. The operational decision will be related primarily to the costs of operating the plant versus the costs of acquiring replacement power on the open market. Issues such as the long-run price of electricity, the supply of surplus capacity, the costs of compliance with Clean Air Act regulations, and the opportunities for greater savings in nuclear O&M costs will determine the outcome of the decision. At this point in time, it seems unlikely that the worst-case scenarios painted by observers of the nuclear energy market will come to pass. Most U.S. nuclear power plants currently are competitive with other sources of electricity, and deregulation probably will not cause them to become less competitive.

Average fuel costs make up just over one-quarter of the electricity generation costs for nuclear power plants. Nevertheless, the competitive environment created by a restructured electric power industry will provide the impetus for nuclear power generating companies to focus on reducing all costs, including fuel. In addition, if early retirements of nuclear power plants are brought about by the economics of electric power restructuring, the demand for nuclear fuel will be reduced. To compete, nuclear fuel suppliers will be forced to reduce prices or provide more efficient, customer-driven services. After enduring a prolonged period of depressed prices, many participants have already exited the nuclear fuel industry. Further consolidation is expected as companies seek to pool resources and spread the risks of operating in a highly competitive environment.

Endnotes

67. Energy Information Administration, Annual Energy Outlook 1998, DOE/EIA-0383(98) (Washington, DC, December 1997), p. 113, and Nuclear Power Generation and Fuel Cycle Report 1997, DOE/EIA-0436(97) (Washington, DC, September 1997), p. 89.

68. A plant comprises one or more units. In common usage, the units are individually and collectively termed "plants." Thus, one speaks of 105 operating nuclear power plants rather than the technically correct 105 operating nuclear units.

69. Operating costs consist of fixed operations and maintenance costs, variable operations and maintenance costs, and fuel costs. Because of regulatory requirements and operational characteristics, the overhead and fuel costs of nuclear plants are highly fixed. Capital improvement costs cover long-lasting equipment, such as steam generators.

70. The restructuring concepts discussed in this chapter apply to all investor-owned utilities. These utilities represent about three-fourths of the plant ownership and electricity sales in the United States. The same concepts may also apply to municipal utilities and cooperatives on a case-by-case issue. Municipal utilities and cooperatives self-regulate but are subject to Federal requirements for reciprocity in providing open access and may be subject to State proposals to permit retail choice. No current Federal or State restructuring plan applies to Federal agencies, such as the Bonneville Power Administration or the Tennessee Valley Authority.

71. "GPU In Serious Discussions Over TMI-1, Oyster Creek Sale," Nucleonics Week (September 18, 1997), p. 12.

72. "Billing It As Hedge Against Fossil Costs, Boston Ed Puts Pilgrim Nuclear on Block," Electric Utility Week (April 20, 1998), pp. 11-12.

73. During the 1980s, regulators disallowed $16 billion in nuclear expenditures as imprudent (Edison Electric Institute News, March 6, 1997). These costs are not recoverable under regulation and thus are not strandable.

74. Regulatory assets are assets created through the regulatory process. For example, a utility may have a portion of its plant balances ruled imprudent on the basis of the "used and useful" standard and thus excluded from the ratebase. Over time, the asset would be allowed into the ratebase as load growth made the plant "used and useful." Another example relates to "phase-in." If a regulatory commission had ordered a utility to phase-in the recovery of capital costs from a new, large power plant to avoid rate shock, the unamortized plant balances in excess of traditional amortization levels would be regulatory assets. In either case, regulatory assets are assets created by the regulatory process for later recovery by the utility.

75. Ibid.

76. Adam D. Thierer, Electricity Deregulation: Separating Fact from Fiction in the Debate Over Stranded Cost Recovery (The Heritage Foundation, March 11, 1997).

77. Ibid.

78. Securitization refers to the process of converting the regulatory-guaranteed stranded cost recovery income over a period of years into security, e.g., a bond that can be sold at a lower interest rate than the utility would otherwise enjoy due to the regulatory guarantee of repayment.

79. Ibid., p. 18.

80. Southern California Edison Co., 1996 Form 10-K, p. 8.

81. Ibid.

82. PECO Energy Company, 1996 Form 10-K, p. 2

83. Public Service Electric & Gas Co., 1996 Form 10-K.

84. Public Service Electric & Gas Co., Form 10-Q for the quarter ended June 30, 1997.

85. Energy Information Administration, Nuclear Power Generation and Fuel Cycle Report, 1996, DOE/EIA-0436(96) (Washington, DC, October 1996), pp. 44-47.

86. The fund operates like an annuity, growing over time as yearly annuity payments are made along with interest earnings.

87. Energy Information Administration, Nuclear Power Generation and Fuel Cycle Report 1996, "Decommissioning U.S. Nuclear Plants," DOE/EIA-0436(96) (Washington, DC, October 1996), p. 51

88. "Energy Online Completes Review of Electric Deregulation Initiatives in All 50 States, Congress, Administration," www.energyonline.com/Restru..ng/news_reports/news/0819wrap.html, accessed October 23, 1997.

89. Energy Information Administration, World Nuclear Outlook 1994, DOE/EIA-0436(94) (Washington, DC, December 1994), pp. 43-44.

90. Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(97/03) (Washington, DC, October 1997), p. 105.

91. Energy Information Administration, Nuclear Power Generation and Fuel Cycle Report 1996, DOE/EIA-0436(96) (Washington, DC, October 1996), and World Nuclear Outlook 1994, DOE/EIA-0436(94) (Washington, DC, December 1994).

92. Federal Energy Regulatory Commission, Form 1, "Annual Report of Major Electric Utilities, Licensees, and Others."

93. Firm power is power that is intended to be available at all times, even under adverse conditions. Non-firm power does not have the guaranteed continuous availability of firm power.

94. D. Airozo, "Oyster Creek May Close in 2000, Unless a Buyer Can Be Found," Nucleonics Week (April 10, 1997).

95. "Little Pilgrim Working To Avoid Fate of New England Neighbors," Nucleonics Week (June 19, 1997), p. 9.

96. The replacement of steam generators for a pressurized-water reactor between 1994 and 1995 cost between $125 million and $153 million.

97. "ComEd To Close Zion," The Ux Weekly (January 19, 1998), p. 3.

98. The NRC may require accelerated funding of a reactor's decommissioning fund if the operator's bond rating is below "A" by a national rating agency for a specific period of time. The NRC may consider other financial criteria in arriving at its decision. Energy Information Administration, Nuclear Power Generation and Fuel Cycle Report 1996, DOE/EIA-0436(96) (Washington, DC, October 1996), p. 49.

99. NRC Press Release, NRC Electronic Bulletin Board on FEDWORLD, www.fedworld.gov (April 8, 1996).

100. Historical uranium and enrichment spot-market prices used in this chapter are the Exchange and SWU Values, respectively, reported in TradeTech, The Nuclear Review (Denver, CO).

101. In the spot market, transactions are made for the one-time delivery of the entire contract to occur within 1 year of contract execution. Term contracts are typically made for one or more deliveries to occur over a time period in excess of 1 year from contract execution.

102. Due to restrictions on U.S. imports from republics of the former Soviet Union, a two-tiered market for uranium, consisting of restricted U.S. and unrestricted world components, was established in 1992.

103. Federal Energy Regulatory Commission, FERC Form 1, "Annual Report of Major Electric Utilities, Licensees and Others" (1996).

104. The gas turbine and small scale category includes gas turbine, internal combustion, photovoltaic, and wind plants.

105. The nuclear fuel cycle includes the steps necessary for transforming naturally occurring uranium into fuel loaded into nuclear reactors.

106. Separative Work Unit (SWU) is the standard of measure for enrichment services.

107. Enrichment plant capacity from NAC International, Nuclear Industry Status Report on Enrichment, A Fuel-Trac Product (Norcross, GA, February 1997), Table B-3.1.

108. Energy Information Administration, Nuclear Power Generation and Fuel Cycle Report 1997, DOE/EIA-0436(97) (Washington, DC, September 1997), Table F3.

109. The majority of the world's nuclear power reactors are light water reactors.

110. Fuel fabrication capacity utilization from Energy Resources International, Inc., 1997 Nuclear Fuel Cycle Supply and Price Report (Washington, DC, May 1996), p. 7.1.

111. The Ux Weekly (January 19, 1998), pp. 3-4.

112. Ibid.

113. Energy Information Administration, Nuclear Power Generation and Fuel Cycle Report 1997, DOE/EIA-0436(97) (Washington, DC, September 1997), Tables F1 and F3.

114. Energy Information Administration, Uranium Industry Annual 1991, "The Uranium Industry of the Commonwealth of Independent States," DOE/EIA-0478(91) (Washington, DC, October 1992), p. 11.

115. Energy Information Administration, Uranium Industry Annual 1997, DOE/EIA-0478(97) (Washington, DC, April 1998), Table 28.

116. Uranium imports included U₃O₈, UF₆, and enriched uranium product (see text box, p. 35). For comparative purposes, the various forms of uranium are expressed as "equivalent" U₃O₈.

117. Energy Information Administration, Uranium Industry Annual 1997, DOE/EIA-0478(97) (Washington, DC, April 1998), Table 5.

118. United States Enrichment Corporation, 1996 Annual Report, p. 22.

119. United States Enrichment Corporation, "About USEC," website www.usec.com/about.html (accessed March 5, 1998).

120. Energy Information Administration, Uranium Industry Annual 1997, DOE/EIA-0478(97) (Washington, DC, April 1998), Table 5.

121. "Third Quarter Spot U₃O₈ Review," The Ux Weekly (October 13, 1997), p. 1.

122. Energy Information Administration, Commercial Nuclear Fuel from U.S. and Russian Surplus Defense Inventories: Materials, Policies, and Market Effects, DOE/EIA-0619 (Washington, DC, May 1998), p. 37.

123. "The Auction Season (and Its Aftermath)," The Ux Weekly (September 8, 1997), p. 1.

124. Some utilities sell nuclear fuel to another corporation and lease it back for use in reactors.

125. R. McKeon, and J. Stefanko, "Uranium Procurement at Pennsylvania Power and Light Company (One Utility's Perspective)," paper presented at the U.S. Council of Energy Awareness International Uranium Seminar (September 1989).

126. Energy Information Administration, Nuclear Power Generation and Fuel Cycle Report 1997, DOE/EIA-0436(97) (Washington, DC, September 1997), p. 22.

127. J. Sellers, "Strategies for Competition and Nuclear Fuel," paper presented at the Nuclear Energy Institutes's FuelCycle 97 conference (Atlanta, GA, April 1997), p. 6.

128. Energy Information Administration, World Nuclear Outlook 1995, DOE/EIA-0436(95) (Washington, DC, October 1995), p. 35.

129. Energy Information Administration, Uranium Industry Annual 1993, "Uranium In Situ Leach Mining in the United States," DOE/EIA-0478(93) (Washington, DC, September 1994), pp. x-xiii.

130. BNFL, "Siemens and BNFL Agree Talks on Nuclear Co-operation," press release (October 15, 1997).