As the nuclear power industry in America approaches forty a number of issues face it now and over the next few years. The oldest of our current fleet of nuclear plants are nearing the ends of their original license periods and their owners must decide between license renewal, decommissioning, and sale of their plants. The utility industry as a whole is changing due to restructuring, the Kyoto Protocol, slow domestic demand growth and the consolidation of generation. In this chapter we will cover these issues.

The length of operating licenses granted to U.S. nuclear plants was based upon a provision in the Atomic Energy Act of 1954. In determining the appropriate time period the Joint Committee on Atomic Energy balanced the recommendations of the Justice Department who were concerned that too long a period would produce monopolies, and the Industry who were concerned that the period would be too short for amortization of their investments. Justice suggested 25 years and Industry suggested 40-59 years. A compromise was arrived at and the licensing period was set at 40 years. No technical considerations entered into the decision since there had been such limited operating experience, and none with power reactors at that point. In 1979 the first Industry sponsored study of license renewal was released which concluded that the costs associated with renewal compared favorably with new plant construction. A 1982 study by the same group, the Electric Power Research Institute, established that considering the cost of replacing components vs. the cost of new construction, renewal of licenses represented a viable option financially. The actual cost comparison would have to be done on a plant by plant basis, and take into account a number of factors including the projected power demand, the condition and operating history of the plant, and the financial situation of the utility.

During the mid 1980s the NRC began to consider its position on license renewal and initiated study on the subject. By April of 1986 the NRC had framed a draft proposal and presented it for public comment. A number of issues would require resolution in order to begin renewing licenses, for instance-how long a period should the renewal be for, what level of safety equipment should be required and what were the technical ramifications of license extension? Predictably, industry wanted minimal upgrades in equipment and a streamlined approach to the renewal process; antinuclear groups wanted no license extensions at all or requirements to retrofit plants to meet current requirements. Industry spokesperson, Jack Ferguson stated that “the key to the decision to pursue the life extension option will be cost, and the key to cost will be the complexity of the regulatory process. Many owners are likely to conclude that they cannot afford to pursue life extension unless NRC has established ahead of time a clear, practical, and predictable policy and regulatory framework”.

In order for NRC to proceed toward that goal they required the resolution of legal issues regarding extensions. In January of 1989, NRC’s General Counsel issued his opinions regarding these issues, namely that the extension be accomplished via a new license rather than an amendment of the current license and that an environmental assessment would be required with either a finding of ‘no significant impact’ or an environmental impact statement. Office of General Counsel (OGC) stated that based upon their review of case law and regulations, an antitrust review would not be required. NRC staff reached certain conclusions based upon OGC’s input and the opinions offered by other interested groups, among these, that the current licensing basis would “provide reasonable assurance of adequate protection” of the public. They determined that NRC should draft a generic environmental impact statement to be used in all renewal cases. The environmental issues were to be covered under 10 CFR Pt. 51 and the technical issues under 109 CFR Pt. 54. Staff proposed that applications for renewal be filed at least 5 years prior to the expiration date of the current license but not more than 20 years before, and that the maximum extension period be 20 years. Final rules were issued in December of 1991 to cover the technical aspects. Revisions were made in 1994 to clarify several points and establish a process for application.

License renewal applications are submitted to the NRC after the licensee has examined their plant for aging effects and determined to their own satisfaction that these can be addressed adequately to warrant extension of the plants operating license. The application is prepared and includes the method and results of this examination as well as general information and technical information to comply with 10 CFR Part 54. The licensee must demonstrate the steps they will take to mitigate the aging effects particular to their facility in sufficient detail that the NRC staff can determine whether the steps to be taken are adequate to prevent undue risk to the public. A safety review is performed based upon the application information, and additional information is requested if necessary to enable the NRC to reach a conclusion regarding the potential for safe operation during the extension. The information provided by the licensee must include: Integrated Plant Assessment, Current License Basis, Time-Limited Aging Analyses, Final Safety Analysis Report and Technical Specifications. In addition, an Environmental Review is required to determine the impact of license extension on the environment in accordance with the National Environmental Policy Act as well as 10 CFR Part 51. A Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS) is used which examines issues common to any License Renewal and includes site-specific information relevant to the particular plant as identified in the original Environmental Impact Statement filed when the plant was initially licensed. The NRC plans to take 30-36 months to review each License Renewal Application, but it may well take longer than that. They must review the Application, the Technical supplements, the GEIS as well as inspect the plant to determine if it meets the requirements for renewal and verify that the Licensee has in fact implemented the mitigation plan they describe in their application. In addition, there are several opportunities for public comment in the renewal process and the NRC may request additional information from the Licensee.

The NRC has estimated that the preparation of a license renewal application requires over 200 person years over a period of 3-5 years at a cost of $30 million. Industry estimates of the cost are less at $10 million under the new license renewal rules, but under the original rules estimates were higher, $40 million. In an attempt to save money several owners groups are working on preparation of license renewal documents that will be generic to all plants designed and built by the same firm. Babcock and Wilcox, General Electric, and Westinghouse are each developing technical reports on common systems and components. This will allow Utilities to reference the reports applicable to their plants design when submitting their renewal applications. In order to be granted a license extension the licensee must demonstrate that the aging effects specific to their plant can be managed adequately. In some cases this is either not possible or the cost of demonstrating to the NRCs satisfaction is prohibitive. For example, Yankee Rowe a 185 MW PWR operated for 30 years and its owners began the process of license renewal. During its examination of the plant and the application the NRC raised questions concerning reactor pressure vessel embrittlement. To satisfy these questions the licensee estimated would cost at least $23 million, and that would not guaranty NRC approval since no agreement had been reached as to what would constitute a demonstration of adequacy. The decision was made to retire the plant rather than attempt to meet the requirements set by the NRC.

The demand for license renewal anticipated by Industry has not occurred. Only two Applications for License Renewal are currently being considered, Calvert Cliffs Units 1 and 2, and Oconee Nuclear Station Units 1,2 and 3. Baltimore Gas and Electric, owner of Calvert Cliffs, submitted an Integrated Plant Assessment methodology in August of 1995 which NRC examined and approved in April 1996. BGE submitted additional technical documentation in 1997 and submitted the actual application in April of 1998. A decision on the application is not expected until May of 2000. Duke Power Company, owner of Oconee, submitted preliminary documents in March 1997 for NRC comment and filed their application in July of 1998. A decision on the application is not expected until August of 2000. An additional ten sites have indicated that they will file for License Renewal between December of 1999 and December of 2003. For a variety of financial reasons, most utilities have decided to close plants rather then apply for license renewal. This may change as large numbers of licenses begin to run out in the early years of the 21^st century. In 1996 53 reactors were 20 years old or more, by 2000 61 will be. This represents 56% of the licensed plants in the U.S. The final revision of the technical issues rulemaking were resolved and it became final on June 7, 1995. The final version of the environmental rules were made final September 5, 1996. All of the currently operating plants licenses will have expired by 2035, it remains to be seen how many of these will apply for license renewal.

Note: For a current list of those that have received or applied for extentions, and those that are expected to, see Renewals.

It is expected that the deregulation of the electric utilities will put additional economic pressure on utilities that own nuclear power plants to divest themselves of plants that can’t compete on price. In the 1998 Annual Survey conducted by Washington International Energy Group of utility CEOs and Managers it was found that “only 42% of the respondents believe that nuclear power plants can compete in a price conscious market while less than half believe that most nuclear plants will remain in operation through their initial license term [and] virtually twice as many respondents (39%) as last year (20%) believe that a large number of nuclear plants will be shut down in the next five years”. Studies have been made of the existing nuclear plants to attempt to determine which plants are likely to be closed early and which are likely to remain open. One conducted by the Edison Electric Institute identified 42 nuclear plants that are not competitive. This study compared the operation and maintenance costs to the price of replacement power over a three year period from 1994-1996. The study was released by the Critical Mass Energy Project of Public Citizen in 1998. Jim Riccio of Public Citizen concluded “Even if nuclear utilities can bring operation and maintenance costs under control, the combination of cheap replacement power and the rapid aging of reactors will likely doom many of these nuclear plants long before the expiration of their licenses”. In another study conducted by Synapse Energy Economics of Cambridge, Massachusetts, authors Bruce Biewold and David White found that as many as 90 of the plants now operating could be forced to close under deregulation, potentially creating an unfounded liability for decommissioning of up to $15.3 billion and for spent fuel storage of $46.5 billion.

The restructuring of the electric supply system in the United States from a system of vertically integrated monopolies to a competitive market system is being conducted on a state by state basis. 23 states have begun implementation of free market policies to their retail electric markets. These states include: Arizona, Arkansas, California, Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, Michigan, Montana, Nevada, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia. Vermont has yet to implement their retail competition plan, but has begun the process. The effects of this competitive market upon nuclear power is yet to be fully revealed, however, the issue of stranded costs has arisen. Stranded costs are capitol costs, including depreciation and return on investment, incurred by the electric utility for a generating plant that can not be recovered in a competitive market because the market price for electricity is lower than total operating cost. Many of these investments were made by utilities when they believed that demand would be substantially higher for electricity in the 1980s and 1990s than it was in the actual event. Nuclear plants, with their higher initial capital requirements, have in many cases been unable to recover the utilities investment due to the lower demand for electricity that projected. In addition, the cost of coal and particularly natural gas has been substantially lower than projected when the nuclear facilities were built, resulting in an abundance of low cost electricity generated from these less expensive sources. Shareholders of utilities want to be reimbursed in some way for these investments in generating capacity that they will be unable to recover without a future, captive ratepayer base.

There are a number of options for dealing with stranded costs, most of them not particularly attractive to one or another of the interested parties. The utility could write off the capital costs, but shareholders object to taking the loss on their investment. The loss could be minimized by improving the efficiency of the plant in question, but this option may not recoup the investment fully and is not favored by utilities since it requires additional investment in plants that they seek to unburden themselves of. The costs could be distributed among residential utility customers who would not be allowed to choose power suppliers until sometime after commercial and industrial customers, but residential customers object to bearing the cost of generating facilities that were built to serve all customers. The costs could be recovered by delaying the transition to retail competition to allow more time for capital recovery, but large electric users are anxious to reap the benefits of competition and don’t care to wait. The final option is to redistribute some of the stranded costs to the public sector by nationalizing of particularly uneconomic assets, but why should the taxpayer be required to bail out shareholders for the poor financial decisions of utility management. On the other hand, the mirror image of stranded costs is windfall profits from low cost, efficient plants that will provide the utilities with an edge in the new competitive atmosphere, no utility wants to forfeit any of these ‘stranded benefits’ to balance their ‘stranded costs’. Many see the stranded cost issue as a means for the utilities to divest themselves of nuclear plants and uneconomic generating facilities in order to streamline themselves and compete more profitably in the new environment. They could recoup their investments in generation facilities that they have been unable to previously in spite of the fact that allowances were made for their generating costs by the States PUCs in setting their rate structure. The amount of stranded costs for utilities in the United States approaches $130 billion to $550 billion according to Moodys and ICF Kaiser.

As in any other industrial plant, nuclear plants consist of an assemblage of parts which are subject to wear and tear. Over the course of time these parts age and eventually wear out. Many smaller parts are intended to be replaced once or several times in the lifetime of the plant. Some larger parts may also have to be replaced in order for the plant to operate for its full lifetime, but others are intended to last and not be replaced. These must all be inspected for signs of aging degradation. A number of environmental factors within the plant tend to degrade the structures and components, including: radiation, high heat, high pressure, steam, water and reactive chemicals. These factors produce a variety of changes within the material; the metal, concrete, electric cables as well as others; that make up the plant. Changes in dimension, ductility, fatigue capacity, and mechanical or dielectric strength. Physical and chemical processes add to aging degradation of the systems, structures and components (SSCs) such as corrosion, fatigue, embrittlement, fabrication defects, vibration, water hammer, and wear.

Corrosion occurs in piping, steam generator components, nearly all the plant as a result of contact with steam, water and chemicals. Wastage, stress corrosion, erosion and intergranular attack are all forms of corrosion that occur. Parts must be inspected regularly, replaced when necessary and the water treated to manage the chemistry in order to mitigate the effects of corrosion. Cyclic mechanical or thermal loads result in fatigue of materials, particularly metal, pressure vessel components, piping, valves and other parts. Materials have a fixed number of cycles of strain they can bear before they begin to crack and fail. Regular inspection and careful initial choice of materials can help mitigate the process of fatigue but it cannot be eliminated. Casting and forming defects and weld related defects amplify the effects of corrosion and fatigue cracking. Embrittlement is decreased ductility as a result of prolonged exposure to heat and radiation. Neutron bombardment produces changes in metal that tend to make it less flexible and more susceptible to cracking. Dosimetry to determine levels of neutron bombardment as well as inspection can help to identify embrittlement.

Embrittlement particularly effects the reactor pressure vessel (RPV) and the presence of trace amounts of copper or nickel in the welds or materials used to construct the RPV leads to more rapid embrittlement. It results in a reduction of fracture toughness and is greater for PWRs than BWRs. It is due to the nucleus of the metals atoms being stuck by neutrons that are emitted in the process of the nuclear chain reaction which alters the metals crystalline structure making it more brittle and harder. The vessel beltline which is closest to the fuel is more severely affected. It is possible to design the core so that fewer neutrons reach the vessel wall, this is termed a ‘low leakage’ core design. Many licensees have opted for this configuration to reduce embrittlement. The RPV is intended to last for the full operating life of the plant, potentially 60 years, without replacement and minimizing embrittlement is important. Reactor vessel steel is more ductile and less susceptible to crack growth at higher temperature. Transition temperature is a term used to describe the point below which the steel may crack. The transition temperature for a particular RVP gradually increases over its lifetime. The NRC has been particularly concerned about RPV embrittlement because of the possibility of pressurized thermal shock (PTS) in PWRs if the emergency core cooling system (ECCS) activates while the vessel is still pressurized under accident conditions. The input of cold water to the hot, pressurized, RPV combined with embrittlement could crack the RPV due to the large thermal stresses. This cannot occur in a BWR since the input of cold water via the ECCS to a BWR vessel would automatically reduce the pressure by condensing the steam inside the vessel. The NRC has established criteria for the increase in transition temperature and the decrease in “upper shelf energy’ or “the ability of the metal to resist cracking at temperatures significantly greater than the transition temperature”.

When the RPV is placed into service samples of the steel from which it is made are placed inside it between the fuel and the vessel wall. . Licensees monitor RPVs for embrittlement by checking one of these samples regularly on a predetermined schedule. The NRC requires that the licensee report to them three years before the RPV is estimated to reach the NRCs specified screening level for embrittlement. It is possible to correct RPV embrittlement by using a process called in-place dry thermal annealing. In this process the empty RPV is heated to 800°-900°F and held there long enough to allow the molecules in the metal to migrate to and fill the defects produced by neutron bombardment. 80-90% of the steels original ductility can be restored using this method. The procedure has been used with success on a number of Navy vessels and has been tested successfully on a RPV of commercial power producing size although, to date, no commercial power plant has used the method. The NRC has developed a rule regarding annealing (10 CFR, Part 50.66 December 1995) which outlines the requirements for licensees who wish to utilize the process.

Steam generators are used in all PWRs and have between 4,000-15,000 tubes ¾ inch in diameter through which the primary coolant water flows. Inside the steam generator the primary water transfers its heat to the secondary loop water to produce steam to turn the turbines. The tubes are susceptible to primary water stress corrosion cracking which results from the interaction of three factors, the material must be susceptible, there must be high tensile stress, and the environment must be corrosive. The material used to fabricate many steam generators, Alloy 600, has turned out to be particularly susceptible to primary water stress corrosion cracking. Steam generators operate at high pressures which places high tensile stress on the tube walls, stretching them. The water in the primary coolant loop often is borated which makes it acidic and corrosive. In addition, metal fatigue and high temperatures play a part in steam generator tube cracking and thinning. Tubes must be inspected for corrosion, denting, thinning, and cracks on a regular basis using a method known as eddy current testing. To perform this test a probe is inserted in the tubes one at a time and pulled through. The probe has electromagnetic coils which detect the change in conductivity which results from damage to the tubes. Another method of testing utilizes a robot such as the Combined Inspection and Lancing (CECIL) device developed by Consolidated Edison and EPRI to visually inspect the tubes with a miniature video camera. If problems are found the tube can be sealed off at both ends using plugs or a metal sleeve can be inserted to reinforce the damaged portion. Plants can operate with a percentage of the steam generator tubes plugged, the percentage depends upon the plants design. If the damage becomes widespread enough to affect operation the steam generator(s) may have to be replaced which is a major operation and quite expensive. Steam generators can be 70 feet high and weigh as much as 800 tons. Due to contact with the primary coolant they are radioactively contaminated. Costs for replacement of a steam generator can be $100-200 million and each plant has at least two of them.

Boiling water reactor internal components are also subject to aging degradation. Many are fabricated from stainless steel and other alloys which are susceptible to stress corrosion cracking. The core shroud is one such component, its purpose is to direct cooling water and provide channels for control rod insertion. It is 14-17 feet in diameter, 20 feet high, and 1 ½ to 2 inches thick. Core shrouds are fabricated by welding forged plates together and these welds can be affected by cracking as the reactor ages. In addition, the plates themselves can crack. It is possible for the reactor to operate normally with cracks in the core shroud, the problems would arise only if the crack goes through the entire thickness and extends all the way around the shroud. If significant cracking occurs it can be repaired by installing tie rods. To this point tie rods have been installed at Hatch 1, FitzPatrick, Nine Mile Point, Pilgrim, Quad Cities 2, Hatch 2, Dresden 2, and Quad Cities 1.

The practices necessary to deal with the effects of aging on nuclear power plants start with the design and materials of the plant and also include maintenance and testing. Design is an important first step. SSCs must be designed with sufficient care that their useful lifetimes will be adequate to the expected lifetime of the plant. Margins in expected load cycles must be calculated to allow for the part to last through the number of expected cycles the plant will experience. When the current fleet of nuclear plants were designed and built not enough was known about the life expectancy of the plant, or the behavior of the materials to produce a level of confidence. Plants were intentionally over designed with additional margins to allow for unknown effects of operation. In the past two decades as more experience has been gained in operation of existing plants it has become possible to determine which designs were in fact conservative and which were not conservative enough. Predictive methods have become more accurate enabling owners and operators to make changes in the operating plants in order to ensure adequacy of performance. Testing, inspection and fabrication techniques have become better which allows operators to better determine the remaining life of pipes, valves and other parts. Minimum requirements have been established for materials, design, fabrication, testing, inspection and certification. Hardware or procedural modifications have been made in light of research and operating experience.

The useful lifetime of a nuclear power plant is around 20-25 years in actual practice. The NRC limits licensing of commercial power plants to 40 years with up to a 20 year extension, but “primarily because of the radiation induced within their originally non-radioactive components, reactors and other major nuclear facilities may become dangerous to operate-or even approach-long before they show signs of physical deterioration”. The Atomic Industrial Forum estimated that the decommissioning of a 1,150MW plant would result in 594,000ft³ of waste. The DOE projects the total wastes generated from the shutdown of a LWR to be decommissioned between 1993-2030 to be: Class A LLW 1,528,434m³; Class B LLW 22,410m³; Class C LLW 2,424m³; GTCC 1,237m³. The figure for GTCC may appear to be a small volume, but it represents 50,053,764Ci of radioactivity which is a huge amount. The U.S. experience with decommissioning nuclear power plants includes a wide range of facilities from small demonstration project reactors like the 22MW Elk River Power Station to full size electric power generating reactors like the 1130MW Trojan Unit 1. 28 civilian reactors had been shut down as of December 31, 1992, the total of all reactors that have been shutdown of all kinds is 70, 40 of these were research reactors of comparatively small size. The majority of power reactors that have been shutdown have been closed prematurely, before their operating licenses ran out. There are a variety of reasons; operation not economically feasible, persistent mechanical problems, changing safety standards that would be prohibitively expensive to meet, public outcry against the plant, accidents, seismic issues and radioactive contamination. 18 plants have closed early and 97 have been ordered and then canceled before construction was complete.

Under NRC rules, there are three alternative methods of proceeding with decommissioning that are acceptable, these are DECON, SAFSTOR and ENTOMB. DECON involves the immediate dismantlement of the plant, as soon as it closes the equipment is decontaminated, cut up, and removed. Under SAFSTOR the facility is shut down, i.e. the fuel is removed from the reactor and placed in the spent fuel pool, but a skeleton staff remains to maintain and monitor the plant and allow the radioactivity to lessen. ENTOMB means the fuel is removed and the building is closed up using concrete to entomb it literally, encasing the containment and securing the property until such time as the radioactivity has diminished enough to allow unrestricted release. The NRC must approve the decommissioning plan and it must be complete within 60 years. Licensees must notify the NRC and the public of their intent to decommission the plant in advance and meeting must be held to allow public involvement and comment on the proposed plan. Utilities must notify the NRC within 30 days of their intention to close the plant. When the licensee removes the fuel they must notify the NRC which then rescinds the authority to operated the plant. A possession only license is granted which allows the utility to own the plant and it’s fuel, but not to operate the plant. Within two years a written decommissioning plan must be submitted which includes the proposed schedule for accomplishing the steps outlined in the plan. The NRC makes this plan available to the public and holds a public meeting. 90 days after submission of the formal plan and 30 days after the public meeting the Utility can begin implementing the plan.

Each of the three options for decommissioning has advantages and disadvantages. DECON allows for greater certainty of the costs since they will be incurred in the present, availability of the plants operating staff who are familiar with the facility, and quicker release of the site. But DECON also results in higher exposure to radioactivity for workers and increased costs for remote handling as well as larger quantities of waste. SAFSTOR results in less waste for disposal, less exposure for workers, and substantially less radioactivity due to decay. However, SAFSTOR means the site will not be available for other use as quickly, original workers are not available, and there is the cost of maintenance and security during the storage period. ENTOMB mainly provides benefits relating to reduced radioactivity, but it is really not and option for a large power reactor since the length of time required till the site would be safe to release would be prohibitively long but three small demonstration reactors have been ENTOMBED.

Often the best aspects of DECON and SAFSTOR are combined, removing some parts of the plant immediately and putting the rest in storage for a period. SAFSTOR is often chosen when the Utility has another plant still in operation on the same site since the staff of the operating facility can provide security for the closed plant. Three plants have completed their DECON, six are at various stages of their DECON, and eleven are in SAFSTOR. Three Mile Island Unit 2 has a possession only license, two DOE power plants have completed their DECON, and three DOE power plants have bee ENTOMBED. The conclusion of decommissioning requires the licensee to submit an application for license termination at least two years before the termination date requested. The request must include ”a site characterization, identification of remaining dismantlement activities, plans for site remediation, detailed plans for the final survey of residual contamination on the site, a description of the end use of the site (if restricted use is proposed, a description of the institutional controls and maintenance and surveillance programs is needed), an updated site specific estimate of remaining decommissioning costs, a supplement to the environmental report”. The NRC schedules a public meeting, examines the plan considering regulations, public health, environmental impacts and approves or recommends changes. When the licensee has completed the plan, the site is inspected by the NRC and if the site is suitable for release the NRC terminates the license.

Decommissioning costs vary, but the NRC requires a minimum for a BWR of $198 million and for a PWR $157 million. Actual costs are often substantially more, for example Trojan’s decommissioning costs were $362 million, Haddam Neck’s were $426.7 million, and Maine Yankee’s were $377.6 million. The funds are to be set aside prior to the start of operation of the plant and are placed in a trust or escrow account outside the licensees administrative control through prepayment or an External Sinking Fund which receives periodic payments, or the licensee must provide Surety in the form of a bond or letter of credit. This funding is periodically reevaluated throughout the life of the plant and adjustments are made if needed to keep pace with inflation. These requirements were instituted in 1988, a decade after all of the currently operating plants were built and received their operating licenses. Utilities were allowed to make payments to an escrow fund annually for the life of the plant. If the plant operates for its full license period the fund would be adequate to cover decommissioning, if however, it closes prematurely, prior to the expiration of its license, the fund will be short and the extra funds will have to be borrowed or taken from the utilities operating funds. This generally entails obtaining a rate increase to cover the expense.

Deregulation of the Utilities is raising concern over this method of funding decommissioning. If the plants are closed prematurely due to economic pressures will there be enough money to cover decommissioning, and if there isn’t, will the electric utility still have a secure rate base to assure they can get the money needed? The NRC is unsure. The NRC has not required electric utilities to report on the funds they accumulate toward decommissioning and therefore has no idea if the utilities were making the necessary payments or what the balance of the escrow accounts were. The NRC had to change the regulation to require that the Utilities submit a report on the escrow accounts every two years so the NRC could review the rate of accumulation of decommissioning funds and take additional action if they felt that account was under funded. The decommissioning trust fund required by the NRC for licensing cannot be used except within specific guidelines. An initial 3% may be used without prior NRC approval. 20% additional may be used 90 days after submission of the decommissioning plan. The rest becomes available after a site specific cost estimate for the decommissioning plan has been approved.

The costs of decommissioning have dramatically increased since the 1970s when the first plants were decommissioned. LLW disposal is one of the most expensive factors in plant decommissioning. There has been a 2000% increase in the cost of disposal of LLW from $13/ft³ in 1983 to $300/ft³ today at the Barnwell facility for example. Costs range from $200/ft³ to $500 /ft³. It is possible to save some money by sending metal waste to recyclers who charge an average of $100/ft³ to decontaminate the material to release limits and then sell it for reuse. Approximately 60% of the total waste stream can be sent to these processors. Dry waste such as gloves, booties, filters etc. can be compacted to 10% of their original volume and packed in drums to reduce waste disposal costs.

For a list of Decommissioned Commercial Power Reactors, see Formerly Operated Plants.

Costs/Funding

Fuel cost:
For a typical 1100 MWe BWR or PWR, the approximate cost of fuel for one reload (replacing 1/3 of the core) is about $40 million, based on an 18-month refueling cycle.

Low-level radioactive waste disposal costs:
About $100-$1,000 per cubic feet, $235 per cubic feet of which goes to the state of SC for taxes.

Funds committed for Nuclear Waste Fund:
$17 billion (1/10 of a cent/kwh of electricity generated at nuclear power plants plus interest since 1983). Of the $17 billion, $6 billion has been spent.

Average estimated cost of decommissioning:
Per plant $300-500 million—includes estimated radiological, used fuel and site restoration costs—about $300 million, $100-150 million and $50 million, respectively.
Industry $31.9 billion—about $300 million per reactor

Aggregate decommissioning funding status:
Of the total $31.9 billion estimated to decommission all eligible nuclear plants at an average cost of $300 million, $22.5 billion or about two-thirds have already been funded. The remaining 9.4 billion will be funded over the next 20 years (the average nuclear plant is licensed for 40 years).
Figures provided by the NEI