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| Fig. 1: Profit versus inflation-adjusted electricity price as given by Eq. (2), assuming a 1,000 MW capacity plant and additional model parameters in the top left box. The expected profit is expressed as millions of dollars after a 20 year license extension. The inflation adjustment of the price ($/MWh) is also made over 20 years. The break-even point, highlighted by the dashed line, is when an extension of the plant license results in no economic net gain or loss. The break-even point here occurs at $63/MWh. Below this value, extension results in financial losses (shaded in red). Above it, extension is profitable (shaded in green).(Image Source: R. Low). |
Nuclear plant retirements are fundamentally economic decisions. Plant owners close facilities when continued operation incurs losses, regardless of technical capability. This article examines the factors that determine whether a reactor gets an extension to its service, postulating a simple economic model in the process.
Three main factors that shape the decision are discussed in this article: engineering requirements for safe operation, regulatory frameworks that mandate periodic reviews, and economic policies that affect electricity market prices.
The U.S. Nuclear Regulatory Commission (NRC) established a standard 40-year operating period when commercial licensing began in the 1970s. [1] This timeframe was chosen not because reactors fail after four decades, but to ensure periodic comprehensive safety reviews and align with accounting practices for capital depreciation. [1] Other nations adopted similar frameworks, creating a global standard. [2]
The 40-year mark serves as a regulatory checkpoint where operators must demonstrate that their facilities can continue operating safely for an additional period, typically 20 years in the United States. Operators submit extensive documentation, component inspections, and environmental reviews. [1] The NRC evaluates reactor vessel integrity, cable conditions, and concrete structure degradation. [3] This regulatory hurdle arrives when plants face their most difficult economic conditions: major components need replacement, maintenance costs rise sharply, and newer generation sources offer cheaper electricity. [2]
Companies extend reactor lifetimes only when economically favorable. The individual decision process is internal to each company, but the basic framework for analysis can me made straightforward: compare the cost of refurbishment against expected profits over 20 years.
Profit depends on several variables. The license extension period determines how long the plant earns revenue. Refurbishment costs vary with plant conditionmajor components like steam generators can cost $500 million to replace. [4] Electricity prices determine revenue. The plant's capacity factor (fraction of time operating, typically 90%) affects total generation. [2] Annual operating costs cover fuel, maintenance, and staffing. These costs escalate as systems age, typically rising 2-3% annually beyond baseline inflation. [5]
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(1) |
A company can decide on the extension decision using a simple cost-benefit analysis:
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(2) |
where the sum runs over 20 years (extension period). The first term is the costs from initial refurbishments during the license extension. The second term accounts for revenue minus operating costs. Annual revenue equals electricity price times reactor generation (plant capacity fraction of time operating 8,760 hours/year). Annual operating expenses grow at 2-3% above the baseline due to aging equipment. [5] The total yearly profit is divided by 1.07 which represents a typical 7% annual discount rate for operation. [2] Fig. 1 shows this calculation for a representative 1,000 MW plant with 90% operating time, with an upfront refurbishment cost of $800M, annual operating expenses of $340M, discount rate of 7% and increasing cost of maintenance of 2.5%.
Based on a rather simplistic model, we get a break-even point of $63/MWh for a 1,000 MW plant. While it is difficult to forecast electricity prices for the next 20 years, our model implies that it is economically favorable to extend the plant license if the company is confident in electricity prices exceeding $63/MWh.
Vermont Yankee shut down in 2014, two years after receiving a 20-year NRC extension. Owner Entergy cited the collapse of wholesale electricity prices driven by cheap natural gas, which made continued operation unprofitable even before required cooling tower upgrades were factored in. [3]
Oyster Creek, New Jersey, closed in 2018 after 49 years - eleven years before its license would have expired. [3] Exelon determined that the cost of mandated cooling tower construction could not be recovered under prevailing market prices.
Turkey Point, Florida, illustrates the opposite outcome. Florida Power and Light invested over $3B in upgrades and secured a 20-year extension, subsequently pursuing a second extension targeting 80 years of total operation. Florida's growing electricity demand and regulated rate structure made the long-term investment recoverable. [4]
In regulated electricity markets where utilities can pass costs to ratepayers, the calculation may favor extension. However, in deregulated markets, nuclear plants compete directly with natural gas, wind, and solar power. The past decade has seen wholesale electricity prices in many regions fall below the marginal cost of operating aging nuclear facilities.
Market economics alone do not determine outcomes. New York, Illinois, and New Jersey introduced zero-emission credit programs that provide supplemental revenue to nuclear plants for their carbon-free generation, keeping several plants operating that would otherwise have closed on market grounds alone. [5] More broadly, capacity marketswhich pay generators for availability rather than energy producedcreate more stable revenue streams than energy-only markets, improving the economics of license extension. [6] Carbon pricing, where it exists, further increases the relative value of nuclear generation by raising costs for fossil-fuel competitors. [7]
The coming decade will see a substantial portion of the global reactor fleet reach decision points on life extension. In the United States alone, approximately 20 reactors will approach 60 years of operation by 2035, forcing second-generation license extension decisions. The industry is actively pursuing regulatory frameworks for 80-year operation, but economic rather than technical factors will likely determine how many facilities pursue this path. [7]
Emerging technologies and market developments may alter the economic calculus. Small modular reactors, if successfully commercialized, could potentially replace aging large reactors on existing nuclear sites, leveraging existing infrastructure and workforces. Advanced reactor designs promise higher thermal efficiencies and lower operating costs, though their economic viability remains unproven at commercial scale. Grid storage technologies and improved renewable energy economics will continue reshaping competitive dynamics in electricity markets. [8]
Perhaps most significantly, climate policy developments could fundamentally change the value proposition for existing nuclear capacity. As nations pursue net-zero emissions targets, the difficulty of replacing large quantities of carbon-free baseload generation may lead to policy interventions supporting license extensions even where pure market economics would dictate retirement. The social cost of carbon, if properly internalized, might justify considerable investment in maintaining existing nuclear capacity as a bridge technology. [9,10]
The aging of the global nuclear fleet presents a complex intersection of engineering, economics, and energy policy. While modern reactors are technically capable of safe operation well beyond their original 40-year licenses, economic viability in competitive electricity markets poses the greater challenge. Plant operators must balance substantial upfront investments against uncertain long-term revenues, making decisions with decades-long consequences. As the energy transition accelerates and the urgency of decarbonization intensifies, the fate of aging nuclear reactors will depend less on their technical capabilities than on whether societies choose to value their carbon-free generation enough to support the economics of continued operation.
© Raphael Low. The author warrants that the work is the author's own and that Stanford University provided no input other than typesetting and referencing guidelines. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.
[1] "Nuclear Energy - Providing Power, Building Economies," U.S. National Renewable Energy Laboratory, NREL/TP-6A50-82419, April 2022.
[2] M. Schneider et al., "The World Nuclear Industry Status Report 2019," Mycle Schneider Consulting, September 2019.
[3] L. M. Davis, "Prospects for Nuclear Power," J. Econ. Perspect. 26, No. 1, 49 (20112).
[4] M. Schneider et al., "World Nuclear Industry Status Report 2023," Mycle Schneider Consulting, December 2023.
[5] R. L. Fisher and D. Rich, "Review of Florida Power and Light Company's Project Management Internal Controls for Nuclear Plant Uprate and Construction Projects," Florida Public Service Commission, PA-10-01-001, July 2010.
[6] J. R. Lovering, A. Yip, and R. Nordhaus, "Historical Construction Costs of Global Nuclear Power Reactors," Energy Policy 91, 371 (2016).
[7] "The Future of Nuclear Energy in a Carbon-Constrained World," Massachusetts Institute of Technology, 2018.
[8] B. Daigle, S. DeCarlo, and N. Lotze, "Big Change Goes Small: Are Small Modular Reactors (SMRs) the Future of Nuclear Energy?" U.S. International Trade Commission, Working Paper ICA-105, March 2024.
[9] J. D. Jenkins and S. Thernstrom, "Deep Decarbonization of the Electric Power Sector: Insights from Recent Literature," Energy Innovation Reform Project, March 2017).
[10] "Reactor License Renewal," U.S. Nuclear Regulatory Commission, Jnanuary 2022.