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. As shown in Table 1 , of the 134 commercial reactors that have started operating since the beginning of the U.S. nuclear power program, 35 have permanently closed, leaving 99 currently operating and 4 under construction. The 99 operating U.S. commercial power reactors are located in 30 states at 60 plant sites. Nuclear power plants annually provide about 20% of total U.S. electricity generation, most recently 19.5% in 2015. Nuclear power accounted for 61.6% of U.S. "zero carbon" electricity generation in 2015. Under the Atomic Energy Act, nuclear power reactors are licensed to operate for 40 years and are eligible for 20-year license renewals thereafter. Because about half of U.S. reactors started operating in the 1970s or earlier, the licenses of much of the reactor fleet would have expired by now without renewal. As of July 2016, according to NRC, 80 of the 99 currently operating reactors have received 20-year license renewals, and 12 additional renewal applications are under review. The 20-year renewals, allowing 60 years of operation, would extend the licenses of most current reactors through the 2030s and of almost all the remainder through the 2040s. Further 20-year renewals are also possible under the AEA, extending plant lives to 80 years or longer. After experiencing no commercial reactor closures during the first decade of the 21 st century, the U.S. nuclear power industry has seen six reactors retire during the past five years, with at least 19 more considered to be at risk of closure by their owners or major credit rating agencies (see Table 2 ). However, New York and Illinois have recently taken action to keep seven of the at-risk reactors operating. These actual, announced, and potential nuclear plant shutdowns fall into several broad and sometimes overlapping categories. The fundamental problem for most of the at-risk plants is that their revenues depend almost entirely on regional wholesale electricity markets, where prices have been insufficient to cover their costs. Some plants, such as Quad Cities, have relatively low operating and maintenance costs, but still cannot bring in sufficient revenue in their regional markets, because of a combination of oversupply, transmission congestion, and other local factors. Several single-unit nuclear plants, which generally have higher costs per megawatt-hour, are having trouble competing even in markets with relatively high power prices. For example, the Pilgrim plant in the New England market is reportedly receiving revenues that are insufficient to cover fuel, operating and maintenance, and capital expenditures, as discussed below. The chronic inability to cover costs during routine operations is not the only source of nuclear plant retirement risk: Marginally economic plants can be vulnerable to closure because of major repairs, capital expenditures, prolonged shutdowns, and other non-routine events. Merchant plants may be especially vulnerable, but such occurrences can even prompt the retirement of rate-regulated plants, as seen at San Onofre and Crystal River. Non-revenue factors, such as concerns about seismic safety at Diablo Canyon, can also contribute to nuclear plant closures. The first nuclear shutdown resulting from the recently changing competitive environment was the 566 megawatt single-unit Kewaunee plant in Wisconsin. In its October 2012 announcement that Kewaunee would be closed, plant owner Dominion said the small plant could not cover its costs in the midst of low regional power prices. An industry consultant commented after the announcement, "This might be the beginning of a new wave of shutdowns." Kewaunee closed in May 2013. Duke Energy decided on February 5, 2013, to retire the Crystal River 3 reactor in Florida. Crystal River's previous owner, Progress Energy, had severely damaged the reactor's massive concrete containment structure while attempting to replace the plant's steam generators. Duke Energy, which acquired Crystal River in 2012, said it decided to close the plant because of unacceptable uncertainty about the scope, cost, and duration of repairing or replacing the damaged containment structure. About two-thirds of U.S. nuclear power plants use steam generators to transfer heat from reactor cooling water to a secondary piping loop in which hot water is converted to steam to drive the turbine generators that produce electricity. Most steam generators have required replacement after 20-30 years of service, a capital expenditure of several hundred million dollars per reactor. Steam generators are such large components that temporary holes must be cut in the reactor containment to remove the old ones and bring in new ones. Some nuclear plants have been closed and decommissioned to avoid the cost of steam generator replacement, such as Oregon's Trojan reactor in 1992. However, most nuclear plant owners have opted to replace the steam generators when necessary, and these projects, while requiring complex planning and execution, have become fairly routine in the nuclear power industry. No other steam generator replacement project caused containment damage similar to that suffered by Crystal River 3. Nevertheless, unrelated problems with another steam generator replacement project, at California's San Onofre station, also led to that plant's permanent shutdown just a month after Crystal River 3. Southern California Edison (SCE), the plant's owner, replaced the steam generators in units 2 and 3 in 2010 and 2011, respectively (unit 1 had been retired previously). One of the new steam generators experienced internal leakage about a year later; inspections showed vibration-related damage to all the new steam generators, later attributed by SCE to design flaws. After considering options to repair or replace the damaged steam generators, SCE announced in June 2013 that it would retire San Onofre 2 and 3. The company cited uncertainty about whether and when the units would be allowed to restart at lower power by NRC, pending steam generator replacement or repair, as a major factor in the shutdown decision. Other considerations were the projected price of replacement power while repairs were being implemented and uncertainty about renewal of the two reactors' operating licenses in 2022, according to SCE. The Vermont Yankee plant was permanently closed in December 2014 because, according to plant owner Entergy, low power prices in New England were causing chronic losses. The single-reactor plant had received a 20-year license renewal from NRC in 2011, despite vigorous opposition from the state of Vermont that focused on leaks of radioactive tritium. The license renewal allowed the plant to operate until 2032, but Entergy decided two years later to begin decommissioning the unit at the end of 2014. The company cited competition from shale gas-fired generation, the relatively high cost of operating a single-unit nuclear plant, and "artificially low energy and capacity prices in the region." Another single-unit nuclear plant, Fort Calhoun in Nebraska, was the most recent U.S. reactor to permanently close, on October 24, 2016. Fort Calhoun had been the smallest operating power reactor in the United States. Because it was owned by the Omaha Public Power District (OPPD), which sets its own rates, the nuclear plant had not been directly subject to the relatively low power prices in the region. However, OPPD determined that it could save up to $994 million for its customers over the next 20 years by closing Fort Calhoun and purchasing low-cost replacement power in the wholesale market. "The economic analysis clearly shows that continued operation of Fort Calhoun Nuclear Station is not financially sustainable," according to OPPD's chief executive. Ten operating reactors are currently facing permanent shutdown dates imposed by their owners or reached through negotiated agreements, as listed in the "announced shutdowns" section of Table 2 . Facing the most imminent closure on this list are two single-unit New York plants, FitzPatrick, owned by Entergy, and Ginna, owned by Exelon. In announcing plans to close FitzPatrick, Entergy cited the relatively high operating costs of single-unit nuclear plants and "excess power supply and low demand" in the plant's upstate New York market. "Current and forecast power prices have fallen by about $10 per megawatt-hour, which equates to a projected annual loss of more than $60 million in revenues for FitzPatrick," said an Entergy statement. Ginna faces a similar economic situation, according to Exelon. The company said the plant's total market-based revenues would be well below the $55-$60 per megawatt-hour required for profitability. In an effort to keep FitzPatrick and Ginna operating, along with Exelon's two-unit Nine Mile Point plant next to FitzPatrick, the State of New York Public Service Commission approved a system of Zero Emission Credits (ZECs) that would provide additional revenue for the four reactors. The ZEC program would require Exelon to purchase FitzPatrick from Entergy and operate all four of the upstate New York reactors through 2029. Exelon has agreed to the purchase and to keep the four reactors running if the program is implemented as planned. This ZEC funding is being provided in the wake of more than 10 years of experience with a market price on carbon in New York State through the Regional Greenhouse Gas Initiative (RGGI). Given the stated economics of the FitzPatrick and Ginna plants, this price advantage under the market price set through RGGI (approximately $5/ton of carbon dioxide or $2.70 per MWh) for low-carbon power units has not been sufficient to make these plants profitable. The next two shutdowns currently scheduled are Exelon's single-unit Clinton plant and the two-unit Quad Cities plant, both in Illinois. "Quad Cities and Clinton have lost a combined $800 million in the past seven years, despite being two of Exelon's best-performing plants," the company said in announcing the shutdowns. The two plants must sell their power into wholesale electricity hubs at consistently lower prices than at adjacent hubs, a situation that has been attributed to chronic transmission congestion. The Illinois General Assembly passed a bill (S.B. 2814) on December 1, 2016, that would provide ZECs to the Clinton and Quad Cities plants, along the lines of the New York ZEC program. Exelon had previously indicated that such assistance could keep the plants operating beyond their planned shutdown dates. Entergy announced on December 8, 2016, that it would close its single-unit Palisades plant in Michigan on October 1, 2018. Palisades is in a competitive wholesale power market but earns nearly all its revenue under a PPA with Michigan utility Consumers Energy. The PPA, scheduled to continue until 2022, was signed in 2007, when power prices were relatively high and expected to continue rising. In announcing the plant's retirement, Entergy said that, since 2007, "market conditions have changed substantially, and more economic alternatives are now available to provide reliable power to the region." As a result, prices under the PPA, which started at $43.50 per MWh in 2007 and were to rise to $63 per MWh by 2022, have risen substantially above the market level. Entergy's announcement said the early termination of the PPA would reduce electricity costs to Consumers Energy by $344 million from 2018 to 2022, and that the savings would be evenly divided between Entergy and Consumers Energy. Entergy plans to close its single-unit Pilgrim plant in Massachusetts in 2019. "The company is retiring the Pilgrim plant because of continued and projected low energy prices, with no expectation of market structure improvements, along with increased costs," according to Entergy's website. A recent analysis by the R Street Institute said the plant's operation and maintenance costs had risen in recent years and that it needed significant capital expenditures to address safety-related equipment problems that had prompted heightened NRC scrutiny. Although wholesale power prices in the New England market are high enough to cover Pilgrim's operation and maintenance costs, according to the analysis, revenue is not sufficient to justify the capital expenditures needed for the long term. Exelon's single-unit Oyster Creek plant in New Jersey, the nation's longest-operating power reactor, is also scheduled to be retired in 2019. When the plant's initial 40-year NRC license was renewed for 20 years in 2009, the State of New Jersey required it to comply with water discharge requirements by building closed-circulation cooling towers to reduce warm water discharges into Barnegat Bay. Exelon said the cooling towers would have cost $700-$800 million and that it would retire the plant if required to build them. Exelon and the New Jersey Department of Environmental Protection reached an agreement in 2010 to close Oyster Creek in 2019, a decade before its license expiration, without building the closed-circulation cooling system. In contrast to the above closures, the planned shutdown of the two-unit Diablo Canyon nuclear power plant in California is not explicitly based on economic factors. Diablo Canyon is a rate-regulated plant, and therefore its owner, Pacific Gas and Electric (PG&E), is allowed to recover the plant's regulator-approved costs from ratepayers. PG&E contends that the plant "provides low-cost, carbon-free energy" and is a "vital energy resource for California." However, plant opponents have argued for decades that Diablo Canyon's location in a seismically active region poses unacceptable safety risks. The environmental group Friends of the Earth calls the plant "dangerous, destructive and expensive." Friends of the Earth and other groups strongly opposed PG&E's 20-year license renewal applications to NRC, which would allow Diablo Canyon 1 and 2 to operate after 2024 and 2025, respectively. They also opposed the extension of a state land lease for the Diablo Canyon site that was to expire in 2018. To resolve the controversy, PG&E reached an agreement with a coalition of environmental and labor groups on June 21, 2016, to abandon the applications to NRC for Diablo Canyon license extensions in return for support from plant opponents for the state land lease extension (which was granted a week later). As a result, the Diablo Canyon reactors are now scheduled to operate until their current NRC licenses expire in 2024 and 2025. By that time, according to PG&E, sufficient alternative electricity generation will be available to meet regional market demand. Several nuclear power units have been identified by their owners as being at risk of permanent shutdown but without any specific dates or deadlines. An Exelon official was reported in March 2016 to have said the company's Nine Mile Point plant was "losing a lot of money," despite being a dual-unit plant with relatively large total generating capacity, and that the company might have to retire it in the future. As mentioned above, Nine Mile Point may continue operating because of Zero Emission Credits being implemented by the state of New York. A FirstEnergy executive reportedly told financial analysts in November 2016 that his company would close or sell its merchant nuclear and coal plants within 18 months unless they could return to cost-based rate regulation or receive financial assistance. FirstEnergy's nuclear plants are the single-unit Perry and Davis-Besse plants in Ohio and the two-unit Beaver Valley plant in Pennsylvania. The analysts were reportedly told that the plants could not compete in regional wholesale power markets with low-cost electricity from natural gas plants and wind turbines. In addition to nuclear plants identified by their owners, several other reactors have been singled out by at least one of the major financial ratings agencies as being at risk of early retirement, generally because of market conditions. Byron 1 and 2 in Illinois were listed by UBS, and the single-unit Palisades plant in Michigan and Three Mile Island plant in Pennsylvania were listed by Fitch Ratings. At the most basic level, existing nuclear power plants need to generate revenues from electricity sales, capacity markets (where available), and other potential sources that exceed the average total cost (ATC)—fuel, capital, and operating—of producing electricity in order to economically justify continuing operations. Generally, prices for wholesale electricity—the largest source of revenue for merchant nuclear power plants participating in competitive markets—have decreased in recent years while nuclear generation ATCs have increased. As a result, the financial condition of some U.S. nuclear power plants has been stressed and in some cases ATCs have exceeded revenues, resulting in actual and planned closures. However, the degree of financial pressure across the nuclear fleet is not uniform. Each power plant is subject to a unique mix of market and cost variables, including (1) plant site and locational pricing, (2) the Regional Transmission Organization (RTO) market, (3) non-electricity revenue sources (e.g., capacity payments), (4) plant size, (5) transmission constraints, (6) generation mix within the transmission area, and (7) the marginal cost of electricity from price-setting fuels (e.g., coal and natural gas). A limited plant-level assessment of electricity revenues and fuel and operations and maintenance (O&M) costs is included in this report (see the Appendix ). However, a detailed plant-by-plant financial analysis that includes all revenue and cost variables is beyond the scope of this report, as are the economics and levelized cost of electricity (LCOE) considerations associated with constructing new nuclear plants. The following sections provide an overview of concepts and trends that impact the financial and economic conditions considered by existing U.S. nuclear power plants. Much of the discussion surrounding nuclear power economics has focused on revenue items such as low natural gas prices, the depressed wholesale market clearing prices that result, and low capacity revenues in some organized markets. These items certainly impact the economics of nuclear power, and this report includes discussion of these revenue-related issues. However, the cost portion of the financial equation is also important to understand due to its impact on economic viability. At an industry-wide level, the Nuclear Energy Institute (NEI) reports that average total generating costs—which include fuel, capital, and operating costs—for nuclear electricity increased from $28.27 per megawatthour (MWh) to a peak of $39.70 per MWh in 2012 and in 2015 were reported to be $35.50 per MWh. The NEI analysis indicates that while all cost categories have increased, capital expenditures were the largest contributor to average total costs, having more than doubled over the same time period. NEI also reports that total average costs can vary depending on the number of reactor units at each power plant. Total average costs for multi-unit plants were $32.90 per MWh in 2015 versus $44.52 for single unit power plants. The majority of this difference is in the "operating" cost category. In response to these cost trends, NEI has an active initiative called "Delivering the Nuclear Promise" which aims to reduce fleet-wide total generation costs by 30% by 2018 from the 2012 high of $39.70 per MWh. For the purpose of comparing revenues and costs for the industry as a whole, average total costs of generation are used in order to illustrate the relationship between electricity sales revenue and all cash costs that are incurred. In addition to the NEI industry-wide average total cost information, CRS has access to 2015 plant-level fuel and O&M costs for 33 nuclear power plants that operate in competitive power markets. This plant-level fuel and O&M cost information is compared with nodal electricity prices paid to each generator in order to determine whether revenue from electricity sales exceeds fuel and O&M costs (for additional information see the Appendix ). In a competitive power market, the per-unit wholesale price of electricity (e.g., dollars per Megawatthour) paid to generators is their primary revenue source and is based on the economic concepts of supply and demand curves. Price determination in competitive markets is subject to Security Constrained Economic Dispatch (SCED), which takes into account costs, transmission limitations, and reliability requirements. In simple terms, all generators within a competitive market offer electricity at prices and volumes that are organized by the RTO from lowest to highest price in order to construct a supply curve (see Figure 2 ). Once expected demand levels and price bids for this time period (e.g., hourly) are determined, the price at which demand and supply intersect, when taking into account SCED considerations, is referred to as the "market clearing price." This is the price received by all generators that offered electricity at a price equal to or below the market clearing price level. As an example, a nuclear plant might offer to sell a certain volume of electricity at $7 per MWh (approximate value for fuel costs) and a wind generator may offer electricity for $0 per MWh. However, if the clearing price is $40 per MWh (because the marginal generator submitted a $40 per MWh offer) then the nuclear plant and wind generator will be dispatched (i.e., ordered to run) and both will receive $40 per MWh for electricity provided during this time interval. Figure 2 provides a hypothetical illustration of how wholesale electricity prices are generally determined. Nuclear power being offered at less than the market clearing price does not necessarily mean that it is profitable. Merchant nuclear plants are generally viewed as "price takers" in a wholesale power market since the plants generally prefer to operate on a continuous basis, regardless of the market price. However, indications are that some nuclear generators may start following demand load patterns in order to improve electricity sales revenues in some locations. Typically, merchant nuclear plants want to offer prices low enough to clear the market and will participate in the competitive power markets in a way that ensures market clearance and dispatch. As a result, nuclear plant profitability is generally a function of the market clearing price level that is set by price-setting units. In practice, price formation in wholesale power markets can be quite complex, with the RTO/ISO having to manage various system constraints (e.g., transmission, scarcity, reliability) that can challenge the simple application of supply and demand curves. Nevertheless, supply and demand fundamentals are the underlying premise by which wholesale electricity prices are determined. Generally, price offers are a function of the fuel cost needed to generate a unit of electricity, and do not include capital costs. The fuel cost for wind is zero and, according to the Nuclear Energy Institute, the fuel cost for nuclear was approximately $7 per MWh in 2015. Also, nuclear generators—because plants generally prefer to operate on a consistent and near-continuous basis—will offer power at low prices. Wind generators—because many projects receive out-of-market revenue/value sources (e.g., power purchase agreements, tax credits, renewable energy credits)—also want to clear the market and may be motivated to submit zero or even negative price offers, if allowed by the respective RTO, to ensure that they clear and are dispatched (for more information see text box below titled Wind Power and Negative Electricity Prices: What Is the Relationship? ). Coal and natural gas generators, on the other hand, will typically offer electricity prices that are a function of fuel acquisition costs, which can vary based on benchmark fuel prices, the location at which the generator purchases the fuel, and the conversion efficiency (heat rate) of the power plant. Natural gas and coal play an important price-setting role in competitive power markets. For the purpose of this discussion, focus is placed on the role of natural gas and how the price of this fuel can affect the wholesale price of electricity paid to generators. Natural gas affects wholesale electricity prices in two primary ways. First, because natural gas power generators are generally able to follow demand/load patterns and can be dispatched with relative ease, they often set prices during peak demand hours—when electricity demand and prices are typically the highest each day. Second, natural gas power generation is a primary price-setting fuel for wholesale electricity prices in competitive power markets. Table 3 indicates the percentage of time intervals that various fuels set the real-time price in three different RTOs during different years. Data contained in Table 3 suggest that natural gas is a primary price-setting fuel within the three RTOs included in the table. The price-setting contribution of natural gas in MISO and PJM has increased over the respective periods included in the table. While the ERCOT price-setting information suggests that natural gas may have declined in terms of its price-setting role within that RTO, the Market Monitor report indicates that the 34% real-time energy price decline observed in this market from 2014 to 2015 was "primarily driven by lower natural gas prices." Commodity fuel prices for natural gas and coal generally have the largest impact on wholesale electricity prices. With natural gas increasing its price-setting role in some competitive markets, a general analysis of fuel costs for natural gas-derived electricity provides an indication about the downward pressure natural gas has exerted on wholesale electricity prices, and therefore revenue for electric power generators. See Figure 3 . The fuel cost range for generating electricity from natural gas has declined since peaking in 2008, while the ATC (fuel, operations and maintenance, and capital) for nuclear power generation has increased, relative to 2008 levels. As discussed above, lower natural gas costs generally translate into lower wholesale power prices. The combination of rising nuclear generation costs and declining natural gas prices is contributing to the financial challenges encountered by nuclear power plants in competitive power markets. Natural gas fuel costs per MWh ranges in Figure 3 reflect U.S.-wide averages, and it should be noted that each individual nuclear plant will be subject to a unique set of market and location-based price variables that can impact revenue from electricity sales. In competitive power markets, there is not a single wholesale electricity price paid to all electricity generators operating in an RTO region. Rather, electricity revenues received by generators are a function of locational marginal prices (LMPs), which vary within each RTO. LMPs generally include three primary price components: (1) energy, (2) transmission congestion, and (3) energy losses. LMPs can be affected by market variables such as fuel prices, generation mix, and transmission constraints at a specific location. In some locations, the presence of renewable electricity generation from wind and solar projects can affect LMPs and in some instances can cause real-time LMPs to drop below zero for limited periods of time. (See text box below: Wind Power and Negative Electricity Prices: What I s the Relationship ? ) As discussed above, the cost of fuel (i.e., natural gas and coal) affects clearing prices, and fuel costs can also vary by location. For example, due to potential transportation cost and infrastructure limitations, the price of natural gas paid by a power generator in Pennsylvania might be different from that paid by a generator in New York. All else being equal, the electricity market clearing price at these respective locations might also be different. Figure 4 shows the range of LMPs for nuclear power plants operating in competitive power markets along with average total costs for nuclear power generation. LMP and ATC projected estimates for calendar year 2016 indicate that the entire expected electricity price range for nuclear power plants in competitive markets may be less than the ATC of nuclear electricity generation. While this projection does not include other revenue sources and does not suggest that all nuclear power plants will realize revenue that is less than cost, it does indicate that the location and cost structure of each nuclear power facility is an important consideration when assessing the financial challenges of a specific plant. In addition to electricity sales, which are the largest revenue source for nuclear power plants, some RTO/ISO markets provide other revenue opportunities for power generators. Capacity, uplift, and ancillary services—all defined in the following text—are some areas where generators can be compensated for providing certain services other than selling electricity. Figure 5 provides average all-in electricity prices for various RTO/ISO markets by revenue source. The largest source of non-energy revenue in some competitive power markets is in the form of capacity payments. To ensure resource adequacy, most RTO/ISOs have developed and evolved capacity markets that provide an economic signal that would provide incentives for adequate generation for peak power demands and to ensure that generation resources are available to satisfy future demand. Depending on the RTO, capacity payments can be made through either a bilateral contract between a load serving entity (LSE) and a generator or through participation in a capacity auction that is organized and administered by the RTO/ISO. However, not all RTO/ISOs have a capacity market (e.g., ERCOT does not have a capacity market and uses scarcity pricing as an incentive for motivating new generation sources). For those that do, each has a unique market design that determines the value of and time frame for capacity payments. As indicated in Figure 5 , capacity payments can vary by RTO, and some RTOs have changed their capacity market designs in such a way that may benefit nuclear power generators. Additionally, power plant location can impact the value of capacity payments received by nuclear and other power generators. For example, PJM's 2019/2020 Reliability Pricing Model (RPM) capacity market resulted in clearing prices that ranged from $100 per MW-day to $202 per MW-day across different zones. RPM and similar forward capacity markets guarantee payments for new capacity that performs as projected. Nuclear power plants are eligible for capacity payments, although not all merchant nuclear generators clear capacity auctions. Some nuclear power plants that operate in competitive power markets have separate power purchase agreements (PPAs) outside the RTO market that provide a specified value for electricity generation. The existence of a PPA reduces the price risk to nuclear power producers associated with participating in competitive power markets. It is not clear how many nuclear plants in competitive power markets have PPAs. However, an industry source suggests that at least six nuclear plants have PPAs for either all or a portion of their generating capacity. Depending on the contractual terms—not made available to CRS—included in each agreement, these PPAs could potentially provide some financial stability to plants with such agreements. Located in Cordova, IL, the Quad Cities Nuclear Generating Station consists of two nuclear reactors with a combined net summer electric capacity of approximately 1,820 Megawatts. The plant is partially rate regulated, with 25% of the plant under Iowa rate regulation and the other 75% participating in the PJM power market. On June 2, 2016, Quad Cities owner-and-operator Exelon announced that it was moving forward to shut down and retire the plant before the end of its operating license. Available price information, capacity payments, and production costs (fuel, operations and maintenance) make it apparent that the Quad Cities power plant is under a degree of financial stress. Generally, the nodal electricity price that determines the value of electricity sold by the Quad Cities power plant has been volatile in the years 2013 to 2016 and is expected to be below fuel and O&M costs in 2016. PJM capacity payments for Quad Cities provide some additional revenue. However, the combination of capacity payments and electricity sales is estimated—assuming constant production costs at 2015 levels—to be less than production costs in 2016, not considering any capital expenditures. Current electricity price projections and capacity auction results indicate that electricity sales will not be large enough to pay for production costs, although capacity payments in 2017 may provide supplemental revenue that cover production costs. The Quad Cities plant did not clear the 2018/2019 or 2019/2020 capacity auctions; therefore the plant is not eligible to receive capacity payments during those years. Faced with low electricity price projections and revenues that are expected to be less than fuel and O&M costs, not to mention any capital expenditures, Exelon management decided that it is in the financial best interest of the company to shut down the power plant. The Illinois legislature passed S.B. 2814 on December 1, 2016, which includes a Zero Emissions Credit (ZEC) incentive program for existing nuclear plants in the state. This may result in continued operations of the Quad Cities nuclear plant. Plant-specific cost and price information available to CRS for 33 nuclear power plants that operate in competitive power markets was used to assess whether electricity revenue did, or is expected to, exceed 2015 fuel and O&M costs for each plant for the years 2015 to 2019. The analysis is unique, compared to materials reviewed for this report, in that it compares plant-level nodal electricity prices with plant-level fuel and O&M costs. Nevertheless, this analysis is inherently limited and is included in this report as an initial financial condition assessment of merchant nuclear power plants. Additional revenue sources (e.g., capacity payments) and other costs (e.g., capital) at the plant level were not available to CRS and were not included in the estimates presented. As a result, CRS is not making an assessment of which reactors are at risk of closure. The estimates provide an incomplete view of nuclear power economic viability. Figure 7 summarizes the results of this analysis. Table A-1 in the Appendix provides plant-specific estimates for each of the 33 plants on a per MWh basis. Generally, from the perspective of electricity revenues versus fuel and O&M costs, calendar year 2016 is projected to have been quite challenging for many existing nuclear power plants. Based on data sources available to CRS, and assuming that all electricity is sold in the wholesale market, 19 of the 33 power plants are estimated to have fuel and O&M costs that exceed electricity sales revenue in 2016. Due to forward electricity prices being projected to increase in the near term, this number is projected to drop to seven for the years 2017 to 2019. While this analysis is limited by available plant-level data for all revenues and costs, it does indicate that some nuclear power plants are encountering financial challenges that may be difficult to manage in the near term. The increasing number of recent nuclear power plant closures and announced early retirements has motivated discussion about whether the federal government should provide financial support mechanisms for existing nuclear power facilities. The nuclear industry and its supporters contend that such support is in the national interest because nuclear power plants provide large amounts of highly reliable, low-carbon electricity. However, opponents contend that nuclear power suffers from too many drawbacks (such as accident risk and waste management problems) and that federal incentives should focus instead on renewable energy and efficiency. Furthermore, federal financial incentives for existing nuclear power would likely be opposed by owners of other generating assets that could potentially benefit financially as a result of early nuclear plant retirements. Nevertheless, if federal support for nuclear power were pursued, Congress would have a variety of options to consider, each with its own set of policy questions. One challenge associated with federal-level nuclear incentives is that financial conditions across the entire fleet are not uniform. Each nuclear power facility is subject to a unique set of cost, price, and financial performance variables. To date, much of the policy action has taken place at the state level, with several states considering, passing, or implementing legislation/regulations to support nuclear power (see text box below, State-L evel Policy Action to Support Existing Nuclear Power Plants ). Secretary of Energy Ernest Moniz has reportedly indicated that the federal government has limited existing authority to provide financial support for operating nuclear power plants and that doing so is currently a state issue. A recent report by the Secretary of Energy Advisory Board Task Force on the Future of Nuclear Power included this recommendation for the Department of Energy (DOE): For existing nuclear plants, the Task Force endorses DOE's efforts to work with the Federal Energy Regulatory Commission (FERC), State regulatory authorities, and regional and independent system operators to encourage arrangements that will preserve the U.S. fleet until the end of their useful life, subject to continued compliance with prevailing safety and environmental regulations. The Task Force believes this is essential if U.S. carbon goals are to be achieved. A range of policy options are available to Congress, should it choose to act, that could potentially provide some degree of financial support for operating U.S. nuclear power plants. Some of these potential options are discussed in the following sections. In March 2015 the Nuclear Energy Institute (NEI), along with other industry groups, announced a joint effort to pursue market and price reforms in competitive electric power markets. The groups sent a letter to the Federal Energy Regulatory Commission outlining a set of principles for price formation reforms. Generally, the primary market reform argument is that clearing prices do not include all costs (e.g., start-up and uplift) associated with operating an electric power system. As a result, LMPs may be lower than they otherwise would be if all costs were included. FERC has an ongoing Energy Price Formation initiative to evaluate electricity price formation in RTO and ISO markets. In June 2016 FERC issued a rule requiring RTOs/ISOs to change their settlement procedures and shortage pricing triggers in order to more accurately compensate generation resources. FERC is also evaluating other price formation issues (e.g., uplift payments); future rules could potentially impact electricity price formation in wholesale markets. Congressional action in this area could include oversight of how FERC's Energy Price Formation initiative might impact nuclear power generators. This effort is consistent with the Future of Nuclear Power task force recommendation referenced above. A federal production tax credit (PTC) is currently available for the generation of electricity by new, advanced nuclear power facilities during their first eight years of operation. However, no federal tax incentives are available for existing nuclear power plants. Generally, currently available energy tax credit incentives are designed to encourage construction and operation of new energy production facilities and are based on either energy/electricity production (i.e., production tax credit or PTC) or investment (i.e., investment tax credit or ITC). In addition to the nuclear PTC for new plants mentioned above, two specific energy tax credits currently available to renewable energy technologies are (1) the Renewable Electricity Production Tax Credit, and (2) the Investment Tax Credit for renewable energy. Legislation making existing nuclear power generation eligible for either of these existing tax credit incentives would provide some financial value and could potentially support continued operation of at-risk plants. However, since the financial condition across the entire U.S. nuclear fleet is not uniform there would likely be plants that capture the tax credit value as a windfall, without actually needing it to justify continued operations. Because of the low-carbon attributes of nuclear-generated electricity, a price on carbon emissions could potentially benefit existing nuclear power plants if the carbon price were reflected in wholesale electricity prices. However, the design of such a carbon price policy could determine whether or not existing nuclear power would be financially advantaged. A carbon price policy could take many forms, including a carbon tax, a cap-and-trade approach, or an environmental regulatory approach such as the Clean Power Plan (CPP). A carbon tax would place a value on carbon emissions that, all else being equal, would increase the cost of producing electricity from carbon emitting fuels. To the extent that such costs are included in marginal-unit price offers from coal and natural gas generators, a carbon tax could effectively increase wholesale market clearing prices that determine electricity sales revenue for existing nuclear power plants. However, a regulatory approach such as the CPP, which would likely result in an effective carbon price in many states, may have varied effects for existing nuclear facilities, depending to some degree on whether states achieve CPP compliance with a rate-based or mass-based target. A CPP rate-based standard (metric tons of carbon per megawatt-hour of electricity generation) does not include existing nuclear in the calculation of megawatt-hours. Therefore, if an existing nuclear plant closes, there will be no change in a state's carbon emissions rate under the rate-based approach. Under the rate-based standard, replacement of an existing nuclear plant with a gas-fired plant could reduce a state's calculated emissions rate, if the emissions rate from the new gas-fired capacity were lower than the state average. By comparison, states using a mass-based approach would likely have a stronger incentive to maintain existing nuclear power. Under a mass-based approach, if an existing nuclear plant shut down and was replaced by gas-fired generation, the total carbon emissions in the state would rise, making it more difficult for a state to achieve its CPP reduction goals. According to EPA's analysis of the CPP, "existing nuclear generation could be slightly more competitive under a mass-based implementation than under a rate-based implementation, because the former tends to create more wholesale price support for those generators." Power Purchase Agreements (PPAs) established between at-risk nuclear power plants and federal agencies are a policy option that could potentially provide a degree of electricity price certainty for both parties. PPAs have been used by the federal government to purchase power from renewable electricity projects over multiple years. A federal agency could potentially contract with a nuclear plant to purchase power at an agreed-upon price over a multi-year period. One possible contractual mechanism might be a Contracts for Difference (CfD) contract model. A CfD contract essentially sets a price level for electricity and requires/entitles the parties to make up the difference between the actual market price and CfD contract price. This contract structure provides price certainty to both the buyer and the seller while eliminating the requirement to physically deliver nuclear electricity to a federal facility. Table A-1 below contains analysis of electricity revenues and fuel and O&M costs for 33 nuclear power plants operating in competitive power markets within the United States. For each plant, 2015 fuel and O&M costs are subtracted from electricity sales revenue. Both revenue and cost data used to perform this analysis are at the plant level, with revenues represented by the nodal electricity price paid to each power plant and plant-level fuel and O&M cost information as reported by third-party sources. The analysis in Table A-1 is unique in that it compares plant-level electricity sales revenue with plant-level costs. Published material reviewed for this report included nodal electricity prices compared with industry average costs as well as plant-level costs compared with regional hub prices. Although this combination of plant-level data sets is a unique attribute of this analysis, nevertheless it provides a limited view of the financial state of U.S. nuclear power plants and does not consider other cash expenses such as capital expenditures or additional revenue sources such as capacity payments—where available—and PPA contracts. Additionally, CRS is not assessing whether or not plants are at risk of closure. Estimates included in the table indicate only whether or not electricity sales generate enough revenue to cover fuel and O&M costs. However, total plant-level profitability, and therefore the economic viability of each plant, can be influenced by other cost and revenue considerations that are not included in the estimates presented. Data-access limitations prevented CRS from performing such analysis for this report.

Summary: Some of the 60 operating nuclear power plants (comprising 99 nuclear reactors) in the United States have experienced financial stress in recent years due to a combination of low wholesale electricity prices and escalating costs. Six nuclear reactors have permanently shut down during the past five years, and 19 others have announced their intention to close or have been identified as "at-risk" of closure by financial consultants and ratings agencies. Generally, U.S. nuclear plants are located in one of two market areas: (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. Most of the U.S. plants considered vulnerable to shut down before expiration of their operating licenses are "merchant plants" that sell all or most of their power into competitive wholesale power markets. The price paid to merchant plants for electric power varies by location and is influenced by the price-setting fuel (usually natural gas and coal), transmission congestion, and other factors. Wholesale electricity prices in certain locations have fallen and electricity sales revenue may be below the fuel and operating and maintenance (O&M) costs of some plants, not considering capital expenditures that may also be incurred. CRS analysis of third-party data indicates that 19 of 33 power plants operating in competitive power markets may incur fuel and O&M costs that exceed electricity revenues for each plant in 2016. However, this number declines to seven in 2017 due to rising forward electricity prices as reported by Bloomberg. While merchant generators do have other revenue sources (i.e., capacity payments where available, power purchase agreements, and hedging positions) and additional costs (e.g., capital), CRS was not able to locate plant-specific information about these revenues and costs that would allow for a holistic financial assessment at the plant level. The nuclear power industry and its supporters have proposed that Congress take action to prevent currently operating U.S. reactors from shutting down before their licenses expire. 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 and that federal incentives should focus instead on renewable energy and efficiency. Nuclear power plants annually provide about 20% of total U.S. electricity generation. To date, all of the policy action related to financial support for existing nuclear plants has been at the state level. New York has implemented a Clean Energy Standard (CES) that includes payments to qualified nuclear power plants in the state starting at approximately $17 per megawatt-hour in 2017. The CES has been challenged on legal grounds. A similar program was recently approved by the Illinois legislature, and Ohio has also considered nuclear support. Since each nuclear power plant is subject to a unique combination of financial variables, federal-level incentives are challenged because some nuclear plants are expected to continue operating without federal financial support. Should Congress choose to debate financial incentives for existing nuclear plants, several options may be considered. Tax incentives based on capital investment or electricity production could potentially provide financial support for existing nuclear plants. Establishing a carbon price—carbon tax, cap-and-trade, emissions regulations—could also provide some financial assistance to nuclear power, depending on how a carbon price mechanism was designed and implemented. Finally, Congress could authorize and require the federal government to enter into power purchase agreements with nuclear power plants that would provide a guaranteed price for nuclear-generated electricity. Additionally, the nuclear industry has been advocating that the Federal Energy Regulatory Commission (FERC) institute changes to electricity price formation in competitive power markets.