Recent and planned nuclear reactor closures have raised questions about the future of nuclear power in the United States and its potential contribution to the U.S. electricity mix. The nuclear power industry and its supporters have proposed that Congress take action to prevent the shutdown of currently operating U.S. reactors before the expiration of their operating license. Supporters contend that nuclear power should be valued as a domestic source of highly reliable, low-carbon electricity. However, opponents contend that nuclear power suffers from too many drawbacks (e.g., safety risks) and that federal incentives should focus instead on renewable energy and efficiency. There are currently 60 operating nuclear power plants in the United States comprising 99 reactors and representing 99,316 Megawatts of generating capacity—nearly 10% of existing utility-scale generating capacity, and approximately 20% of total power generation. Generally, U.S. nuclear plants are located in one of two market types: (1) competitive—where the value of electricity fluctuates based on supply-side price offers that are generally a function of fuel (e.g., natural gas) costs and demand-side price bids, and (2) cost-of-service—where the value of electricity is set at a rate based on regulator-approved costs, operating expenses, and a reasonable investment return. Some nuclear plants located in competitive power markets are subject to full or partial rate regulation, which reduces financial risk associated with fluctuating electricity prices. Access to competitive wholesale power market prices can result in regulatory bodies deciding that early nuclear plant retirement is in the best interest of rate payers based on projected electricity prices. Other plants located in competitive power markets operate on a "merchant" basis, where electricity prices and revenues are subject to commodity price fluctuations and supply/demand dynamics. Merchant nuclear power plants are the focus of this report. Competitive power markets are managed by either a Regional Transmission Organization (RTO) or an Independent System Operator (ISO), which operates electricity and capacity markets that determine revenues for nuclear, and other, power generators. Unlike cost-of-service market areas—where generators have electricity price rates that are approved and periodically revised by a state utility commission—competitive power markets are subject to electricity price volatility that results from supply and demand fundamentals as well as fuel (e.g., natural gas and coal) costs for the marginal price-setting generators. While generators operating in cost-of-service market areas are not immune to fuel competition, to date nuclear power plants that have announced early closure or have been identified by financial consultants and ratings agencies as "at-risk" of closure are located in competitive market areas. U.S. nuclear power plants operating in competitive power markets are in an era of challenging economic conditions—increasing operating costs and low wholesale power prices in some locations—that create uncertainty regarding the future of some plants. Six reactors have permanently shut down during the past five years; 10 reactors—at eight plant sites—have announced, since 2010, their intent to close—nine in the past two years (see Figure 1 ); and 10 have been identified by consultants and ratings agencies as "at-risk" of closing prior to the expiration of their operating licenses. In total, these plants represent 22,078 Gigawatts of generating capacity, which is roughly 20% of the current nuclear power fleet. Of the 10 power reactors that have announced their intent to close, some operate under full or partial rate regulation—they receive a set price for electricity sales—and some operate solely as merchant power plants—they are subject to the price dynamics of competitive power markets. However, the one common link among the reactors that have announced their intent to close is that they are located in competitive power markets ( Figure 1 ). Because they are subject to wholesale power price dynamics, merchant generators operating in competitive power markets are the focus of the economic discussion included in this report. This report provides background on the evolution of nuclear power in the United States, discusses recent and announced plant closures, explains the economic conditions creating financial challenges for merchant nuclear power plants, and presents policy considerations associated with the future of existing nuclear power plants. The financial situation for each nuclear power plant is unique. Operating costs, expected capital expenditures, wholesale power prices, capacity payments, hedging exposure, power purchase agreements (PPAs), and full or partial regulated rate structures are financial components that are plant and location specific. Nevertheless, much of the economic and financial information presented in this report is generalized in order to illustrate the cost and pricing trends across the entire industry. While some plant-by-plant analysis is referenced and contained in this report, there are important data assumptions that should be noted. To date, CRS has not been able to locate or aggregate a comprehensive data set that would allow for a plant-by-plant analysis that accurately reflects all financial variables. Commercial-scale nuclear power generation in the United States was inaugurated in 1957 by the startup of the Shippingport reactor in western Pennsylvania. Built by the U.S. Atomic Energy Commission (AEC) and operated by Duquesne Light Company, the relatively small (60 Megawatt) power plant was not considered economically viable. However, Shippingport paved the way for additional demonstration reactors that were rapidly scaled up in generating capacity to provide a viable alternative to power plants fired by fossil fuels. Harnessing the tremendous energy potential of nuclear fission had been a major federal goal since the development of nuclear weapons during World War II. Post-war policymakers widely anticipated that nuclear power plants could generate much or most of the power that would be needed to satisfy the nation's rapidly escalating demand for electricity, particularly if plutonium and uranium from spent nuclear fuel were recycled for use in advanced fast-neutron reactors. It was also hoped that the widespread adoption of nuclear power would mitigate volatile and rising fossil fuel prices, growing dependence on foreign oil, and air pollution. The legal framework for the U.S. nuclear power industry was established by the Atomic Energy Act of 1954 (AEA), which authorized the private sector to own and operate nuclear facilities under AEC licensing. To encourage private-sector adoption of the new and potentially hazardous technology, Congress enacted the Price-Anderson Act as an amendment to the AEA in 1957, establishing a special public liability system for reactor operators and suppliers. Shippingport and other small, early commercial nuclear plants were constructed with subsidies under the AEC's Power Reactor Demonstration Program. Beginning in 1963, reactor suppliers began selling substantially larger units—around 500 megawatts and above—on a "turnkey" basis to electric utilities. By 1965, plants as large as 1,100 megawatts were being ordered by utilities under a non-turnkey basis, with contract terms similar to those of non-nuclear power plants. Rising coal prices and the apparently improved economics of larger reactors prompted electric utilities to order 20 new nuclear units in 1966 and 31 in 1967—only a decade after the startup of Shippingport. Reactor orders continued at a strong pace through 1971 and then jumped to 38 in 1972 and 41 in 1973. However, the wave of reactor orders then receded as dramatically as it had begun. Surging energy prices resulting from the Arab oil embargo in 1973-1974 dramatically slowed the growth of U.S. electricity demand, and it became apparent that electric utilities had ordered too much generating capacity of all types. In addition, nuclear power plant construction costs were sharply escalating, interest rates were rising, and greater safety expenditures were required after the 1979 core-melt accident at Three Mile Island 2. All reactors ordered from 1974 through 1978 were subsequently canceled, and no further reactor orders were placed in the United States until 2008, when contracts were signed for four new units now being built in Georgia and South Carolina. Most of the reactors ordered from 1971 through 1973 were also canceled, for a total of 126 cancellations. In addition to the cancellations, the lower-than-expected growth in electricity demand led electric utilities to slow the construction of many reactors that had not been canceled, stretching their completion into the 1980s and 1990s, and to 2016 in the case of one reactor, Watts Bar 2. Of the 256 reactor orders placed through the 1970s, 134 reactors, including the early AEC demonstration plants, ultimately were completed and placed into service. Throughout the history of the U.S. nuclear power program, reactors have permanently shut down for a variety of reasons. Many of the small, early AEC reactors were not necessarily expected to operate for a long time, and nine of them had been permanently closed by the late 1970s. Three Mile Island 2, a nearly new reactor, closed in 1979 after its accident. Four reactors were permanently closed during the 1980s, including the Shoreham plant on Long Island, NY, which had never begun full-power operation. During the 1990s, 10 reactors shut down, including the large, two-unit Zion plant in Illinois. Rising natural gas prices in the early 2000s significantly improved the economics of nuclear power, because they made gas-fired electric generation more expensive while nuclear generation costs remained comparatively low (discussed in detail later in this report). Existing reactors were no longer being closed, and the first U.S. license applications for new reactors since 1978 were filed with the Nuclear Regulatory Commission (NRC, the regulatory successor to the AEC) beginning in 2007. However, gas prices fell sharply after 2009 and have remained low, primarily because of strong production of domestic shale gas. Six reactors have permanently shut down since the beginning of 2013, and additional closures have been announced. The current economic situation has clouded the outlook for new U.S. reactors. NRC has issued construction and operating licenses to seven new reactors and is currently considering applications for seven more. However, except for the four units in Georgia and South Carolina that are now under construction, no commitments have been made to build any others.