Financial Challenges of Operating Nuclear Power Plants in the United States
Congressional research reportDec 14, 2016
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Financial Challenges of Operating Nuclear
Power Plants in the United States
(name redacted)
Specialist in Energy Policy
(name redacted)
Specialist in Energy Policy
December 14, 2016
Congressional Research Service
7-....
www.crs.gov
R44715
Financial Challenges of Operating Nuclear Power Plants in the United States
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, federallevel 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
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Financial Challenges of Operating Nuclear Power Plants in the United States
industry has been advocating that the Federal Energy Regulatory Commission (FERC) institute
changes to electricity price formation in competitive power markets.
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Financial Challenges of Operating Nuclear Power Plants in the United States
Contents
Introduction ..................................................................................................................................... 1
Caveats and Limitations ............................................................................................................ 2
Overview of U.S. Nuclear Power Generation ................................................................................. 4
Actual, Planned, and Possible Reactor Closures ............................................................................. 6
Recent Reactor Retirements ...................................................................................................... 9
Announced Retirements and Potential Shutdowns ................................................................. 10
FitzPatrick and Ginna ....................................................................................................... 10
Clinton and Quad Cities ..................................................................................................... 11
Palisades............................................................................................................................. 11
Pilgrim .............................................................................................................................. 12
Oyster Creek ..................................................................................................................... 12
Diablo Canyon .................................................................................................................. 12
Other Potential Closures ................................................................................................... 13
Merchant Nuclear Power Plant Economics ................................................................................... 14
Nuclear Power Generation Costs ............................................................................................ 14
How Are Competitive Wholesale Electricity Prices Determined? .......................................... 15
How Natural Gas and Coal Impact Wholesale Electricity Prices ........................................... 17
Locational Marginal Prices ..................................................................................................... 19
Other Revenue Sources ........................................................................................................... 20
Power Purchase Agreements (PPAs) ....................................................................................... 22
Case Study: Quad Cities Nuclear Generating Station ............................................................. 22
Plant-Level Analysis of Electricity Sales Revenue and Fuel and O&M Costs ....................... 24
Policy Options and Considerations ............................................................................................... 25
Power Market Price Formation Changes ................................................................................ 26
Tax Incentives ......................................................................................................................... 26
Carbon Price ............................................................................................................................ 27
Federal Power Purchase Agreements (PPAs) .......................................................................... 28
Figures
Figure 1. Operational Nuclear Power Generation Facilities in the United States ........................... 3
Figure 2. Illustrative Example of Wholesale Electricity Price Formation in a Competitive
Power Market ............................................................................................................................. 16
Figure 3. Fuel Costs for Natural Gas Power Generation and Average Total Costs for
Nuclear Power Generation ......................................................................................................... 18
Figure 4. Competitive Power Market LMPs for U.S. Nuclear Power Plants ................................ 19
Figure 5. Comparison of All-in Prices in Different Markets ......................................................... 21
Figure 6. Quad Cities Revenue and Cost Information................................................................... 23
Figure 7. Analysis of Electricity Sales and Fuel and O&M Costs for 33 Nuclear Power
Plants .......................................................................................................................................... 24
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Financial Challenges of Operating Nuclear Power Plants in the United States
Tables
Table 1. History of U.S. Power Reactor Orders, Startups, and Shutdowns ..................................... 6
Table 2. Actual, Announced, and Potential U.S. Commercial Reactor Shutdowns Since
2000 .............................................................................................................................................. 7
Table 3. Price-Setting Fuel Type Used by Real-time Marginal Generating Units......................... 17
Table A-1. Plant-Specific Analysis of Electricity Sales Revenue and Fuel and O&M Costs ........ 30
Appendixes
Appendix. Plant-level Analysis of Electricity Sales Revenue and Fuel and O&M Costs ............. 30
Contacts
Author Contact Information .......................................................................................................... 31
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Financial Challenges of Operating Nuclear Power Plants in the United States
Introduction
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.1 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.2
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.3 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 years4 (see Figure 1); and 10
1
Generating capacity is reported as net summer capacity; see Energy Information Administration, Monthly Nuclear
Utility Generation (MWh) by State and Reactor, August 2016.
2
The Ft. Calhoun reactor shutdown in Nebraska, discussed later in this report, is an example of a fully rate-regulated
nuclear plant located in a competitive power market. Ft. Calhoun regulators decided that early shutdown of the reactor
was in the best financial interest of the rate payers.
3
For more information about RTOs and ISOs, see the ISO/RTO Council website, http://www.isorto.org/about/default.
4
Nine of the 10 reactors announced their intent to close in the past two years. One, Oyster Creek, announced in 2010
(continued...)
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Financial Challenges of Operating Nuclear Power Plants in the United States
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.5
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).6 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.
Caveats and Limitations
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.
(...continued)
its intent to close.
5
See Table 2. Calculation is based on net summer capacity as reported by the Energy Information Administration.
6
There are several nuclear power plants that are located in the footprint of a competitive market but are rate-regulated
by a state entity. These plants have guaranteed rates for electricity generation and are thus not subject to wholesale
price dynamics. In Figure 1, these plants are located in the competitive power market area (green shaded area) and are
indicated by a yellow dot (rate regulated).
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2
Figure 1. Operational Nuclear Power Generation Facilities in the United States
Announced Plant Closures Indicated by Labels
Source: Map by CRS using data from S&P Global Platts geospatial data layers, 2016; and Esri Data & Maps, 2014.
Notes: The eight plant sites labeled on this map represent 10 nuclear reactors. Diablo Canyon and Quad Cities are both two-reactor sites. No nuclear power plants are
located in Alaska or Hawaii.
* The Fitzpatrick and Ginna plants in New York may continue to operate based on successful implementation of the New York Clean Energy Standard, which includes
Zero Emission Credits (ZECs) for at-risk nuclear facilities. Quad Cities and Clinton plants located in Illinois may also continue operating as a result of the state legislature
passing a similar ZEC program in December 2016.
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Financial Challenges of Operating Nuclear Power Plants in the United States
Overview of U.S. Nuclear Power Generation
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.7 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.8
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”9 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.10
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 1973.11
7
Hewlett, Richard G., and Jack M. Holl, Atoms for Peace and War, 1953-1961, University of California Press, 1989, p.
421. Shippingport’s total per-megawatt capital costs were estimated at about 10 times those of a conventional
generating unit of that time. The Shippingport plant constituted a major milestone in the U.S. government’s nuclear
reactor development efforts that began during World War II and continue today. For a description of historical federal
energy research and development expenditures, see CRS Report RS22858, Renewable Energy R&D Funding History:
A Comparison with Funding for Nuclear Energy, Fossil Energy, and Energy Efficiency R&D, by (name redacted)
.
8
Section 170 of the Atomic Energy Act of 1954, 42 U.S. C. § 2210—Indemnification and limitation of liability. Under
the Price-Anderson Act, liability for damages to the public from radioactive releases from nuclear power plants is
channeled to the operator of the power plant involved in a release. The plant operator’s liability is limited to the amount
of available insurance plus mandatory payments by all nuclear utilities. See “Nuclear Accident Liability” in CRS
Report RL33558, Nuclear Energy Policy, by (name redacted)
.
9
Under “turnkey” contracts, reactor manufacturers provided utilities with completed nuclear power plants that were
ready to operate, often at a fixed price. Overall, reactor manufacturers lost money on the turnkey contracts and stopped
offering them after 1966. See Burness, H. Stuart, et al., “The Turnkey Era in Nuclear Power,” Land Economics, May
1980.
10
Perry, Robert, et al., Development and Commercialization of the Light Water Reactor, 1946-1976, June 1977, Rand
Corporation, R-2180, NSF, p. xi.
11
Nuclear Energy Institute, Historical Profile of U.S. Nuclear Power Development, 1994 Edition.
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Financial Challenges of Operating Nuclear Power Plants in the United States
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 2.12 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.13
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 2.14 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)15
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.16 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.
12
On March 28, 1979, a pressure relief valve in Three Mile Island unit 2 stuck open, allowing reactor cooling water to
escape. Although control rods halted the nuclear chain reaction as designed, the nuclear fuel rods in the reactor core
continued to generate heat through radioactive decay. A substantial portion of the fuel rods melted before reactor
operators restored cooling water to the reactor core.
13
Nuclear Regulatory Commission, NRC Datasets, “Cancelled U.S. Commercial Nuclear Power Reactors,” updated
July 1, 2016, http://www.nrc.gov/reading-rm/doc-collections/datasets/, and Nuclear Energy Institute, Historical Profile
of U.S. Nuclear Power Development, 1994 Edition.
14
Watts Bar 2 had been ordered in 1970, but construction was suspended from 1985 to 2007. See NRC, “History of
Watts Bar Unit 2 Reactivation,” October 28, 2015, http://www.nrc.gov/info-finder/reactors/wb/watts-bar/history.html.
15
Energy Reorganization Act of 1974, P.L. 93-438.
16
Nuclear Regulatory Commission, “New Reactor Licensing Applications,” June 20, 2016, http://www.nrc.gov/
reactors/new-reactors/new-licensing-files/new-rx-licensing-app-legend.pdf.
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Financial Challenges of Operating Nuclear Power Plants in the United States
Table 1. History of U.S. Power Reactor Orders, Startups, and Shutdowns
Number of Reactors
Years
Orders
Cancellations
Startups
Shutdowns
Operating at
end of decade
1950s
16
0
3
0
3
1960s
87
0
21
8
16
1970s
153
57
58
7
67
1980s
0
58
48
4
111
1990s
0
5
3
10
104
2000s
8
0
0
0
104
2010s
0
6
1
6
99
Total
264
126
134
35
Source: Nuclear Energy Institute, Nuclear Regulatory Commission
Notes: 264 total orders minus 126 cancellations = 138 reactors that were not canceled. Of those 138, 4 are still
under construction, leaving 134 that have started up. Of the 134 startups, 35 have shut down, leaving 99
currently operating. “2010s” are through November 2016.
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.17 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 2015.18
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.19 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.20 Further
20-year renewals are also possible under the AEA, extending plant lives to 80 years or longer.
Actual, Planned, and Possible Reactor Closures
After experiencing no commercial reactor closures during the first decade of the 21st century, the
U.S. nuclear power industry has seen six reactors retire during the past five years, with at least 19
17
Nuclear Regulatory Commission, NRC Datasets, “Commercial Nuclear Power Reactors—Operating Reactors,” July
26, 2016, http://www.nrc.gov/reading-rm/doc-collections/datasets/.
18
Energy Information Administration, “Net Generation for All Sectors, Annual,” http://www.eia.gov/electricity/data/
browser/. Excludes biomass. “Zero carbon” and “zero emissions” refers to direct emissions from power generation.
19
Nuclear Regulatory Commission, “Reactor License Renewal” and “Fact Sheet on License Renewal,”
http://www.nrc.gov/reactors/operating/licensing/renewal.html.
20
Nuclear Regulatory Commission, Information Digest, 2016–2017, NUREG-1350, Volume 28, Appendix G,
“Commercial Nuclear Power Reactor Operating Licenses—Expiration by Year, 2013–2049,” http://www.nrc.gov/docs/
ML1624/ML16245A069.pdf.
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Financial Challenges of Operating Nuclear Power Plants in the United States
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.21
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 rateregulated 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.
Table 2. Actual, Announced, and Potential U.S. Commercial Reactor Shutdowns
Since 2000
(By Shutdown Date)
Reactor
State
Shutdown
Date
Net Summer
Generating
Capacity
(Megawatts)
Startup
Year
Major Factors
Contributing to Shutdown
Actual Shutdowns
Crystal River 3
Florida
Feb. 2013
860
1977
Cost of major repairs to
reactor containment
Kewaunee
Wisconsin
May 2013
566
1974
Operating losses
San Onofre 2
California
June 2013
1,070
1983
Cost of replacing new steam
generators
San Onofre 3
California
June 2013
1,080
1984
Cost of replacing new steam
generators
Vermont Yankee
Vermont
Dec. 2014
620
1972
Operating losses
Fort Calhoun
Nebraska
Oct. 2016
479
1973
Operating losses
Jan. 2017
828
1976
Operating losses; may
continue running with state
Zero Emission Credits
Announced Shutdowns
FitzPatrick
New York
21
Rorke, Catrina, Where Have All the Nuclear Plants Gone?, R Street Institute, Policy Study No. 70, October 2016, p.
5, http://www.rstreet.org/policy-study/where-have-all-the-nuclear-plants-gone/.
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Financial Challenges of Operating Nuclear Power Plants in the United States
State
Shutdown
Date
Net Summer
Generating
Capacity
(Megawatts)
Startup
Year
Ginna
New York
March 2017
581
1970
Operating losses; may
continue running with state
Zero Emission Credits
Clinton
Illinois
June 2017
1,065
1987
Operating losses; may
continue running with state
Zero Emission Credits
Quad Cities 1
Illinois
June 2018
908
1972
Operating losses; may
continue running with state
Zero Emission Credits
Quad Cities 2
Illinois
June 2018
911
1972
Operating losses; may
continue running with state
Zero Emission Credits
Palisades
Michigan
Oct. 2018
784
1971
Operating losses, end of
power purchase agreement
Pilgrim
Massachusetts
May 2019
685
1972
Operating losses, rising capital
expenditures
Oyster Creek
New Jersey
Dec. 2019
614
1969
Agreement with state to
avoid building cooling towers
Diablo Canyon 1
California
Nov. 2024
1,122
1985
Settlement with labor and
environmental groups
Diablo Canyon 2
California
Aug. 2025
1,118
1986
Settlement with labor and
environmental groups
Reactor
Major Factors
Contributing to Shutdown
Reactors Identified at Risk of Closure
Beaver Valley 1
Pennsylvania
NA
892
1976
Operating losses
Beaver Valley 2
Pennsylvania
NA
885
1987
Operating losses
Byron 1
Illinois
NA
1,164
1985
Operating losses
Byron 2
Illinois
NA
1,136
1987
Operating losses
Davis-Besse
Ohio
NA
894
1978
Operating losses
Nine Mile Point 1
New York
NA
630
1969
Operating losses; may
continue running with state
Zero Emission Credits
Nine Mile Point 2
New York
NA
1,143
1987
Operating losses; may
continue running with state
Zero Emission Credits
Perry
Ohio
NA
1,240
1987
Operating losses
Three Mile Island 1
Pennsylvania
NA
803
1974
Operating losses
Source: Nuclear Regulatory Commission, International Atomic Energy Agency, Energy Information
Administration, plant owner news releases, media reports, “Announced shutdowns” are reactors whose owners
have announced specific shutdown dates. “Reactors identified at risk of closure” are from Deloitte, “Power and
Utilities Accounting, Financial Reporting, and Tax Update,” January 2016, p. 27, which listed reactors that had
been identified as being at risk of retirement by at least one of the three major financial ratings agencies. Nine
Mile Point 2, Perry, and Beaver Valley 1 and 2 are listed because of statements released by the plant owners.
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Financial Challenges of Operating Nuclear Power Plants in the United States
Notes: Plants that have closed or are at risk because of “operating losses” may be affected by a combination of
low regional power prices, high costs caused by relatively small size, rising capital expenditures, and other cost
factors, as discussed in the text. NA=not applicable.
Recent Reactor Retirements
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.”22 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.23
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.24 Most steam generators have required replacement
after 20-30 years of service, a capital expenditure of several hundred million dollars per reactor.25
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
22
Hiruo, Elaine, “Kewaunee Closure Shows Impact of Natural Gas Prices: Analysts,” Nucleonics Week, October 25,
2012.
23
Carr, Hously, “Duke Decision to Retire Crystal River-3 Positive, Financial Analysts Say,” Nucleonics Week,
February 7, 2013.
24
These are called “pressurized water reactors,” or PWRs, because the reactor cooling water is kept under pressure to
prevent boiling. The remaining third of U.S. commercial reactors are called “boiling water reactors,” or BWRs, because
their cooling water is allowed to boil, with the resulting steam flowing directly to the turbine generators. The BWR
design eliminates the need for steam generators.
25
For example, replacement of the two steam generators at the Waterford 3 reactor in Louisiana was estimated by the
plant’s owner at $550 million. See Entergy Corporation, “Entergy Louisiana Seeks Approval to Replace Waterford 3
Steam Generators,” news release, June 27, 2008, http://www.entergy.com/News_Room/newsrelease.aspx?NR_ID=
1203.
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Financial Challenges of Operating Nuclear Power Plants in the United States
SCE to design flaws.26 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.27
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 singlereactor 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.28 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 gasfired generation, the relatively high cost of operating a single-unit nuclear plant, and “artificially
low energy and capacity prices in the region.”29
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.30
Announced Retirements and Potential Shutdowns
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.
FitzPatrick and Ginna
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
26
Dolley, Steven, “SCE Aims to Hold Mitsubishi Accountable for San Onofre Generators,” Nucleonics Week, July 25,
2013.
27
Hiruo, Elaine, “Benefit of San Onofre Restart Dependent on No Delays: SCE Paper,” Nucleonics Week, November
21, 2013.
28
Beattie, Jeff, “Vermont Lawmakers Oppose Longer Life for Entergy Nuke,” IHS The Energy Daily, February 25,
2010, http://www.theenergydaily.com/vermontlawmakers/.
29
Hamilton, T.L., “Vermont Yankee Closure Seen Boosting New England Gas Demand,” Nucleonics Week, August 29,
2013. For various viewpoints on the New England capacity market, see Turmelle, Luther, “Power Producers Gaming
the System, David Cay Johnston Says,” New Haven Register, February 27, 2015, http://www.nhregister.com/article/
NH/20150227/NEWS/150229516.
30
“Fort Calhoun Will Close October 24, OPPD Says,” Nucleonics Week, September 1, 2016.
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Financial Challenges of Operating Nuclear Power Plants in the United States
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.31 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.32
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 2029.33 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.34
Clinton and Quad Cities
The next two shutdowns currently scheduled are Exelon’s single-unit Clinton plant and the twounit Quad Cities plant, both in Illinois. “Quad Cities and Clinton have lost a combined $800
million in the past seven years, despite being two of Exelon’s best-performing plants,” the
company said in announcing the shutdowns.35 The two plants must sell their power into wholesale
electricity hubs at consistently lower prices than at adjacent hubs, a situation that has been
attributed to chronic transmission congestion.36 The Illinois General Assembly passed a bill (S.B.
2814) on December 1, 2016, that would provide ZECs to the Clinton and Quad Cities plants,
along the lines of the New York ZEC program. Exelon had previously indicated that such
assistance could keep the plants operating beyond their planned shutdown dates.37
Palisades
Entergy announced on December 8, 2016, that it would close its single-unit Palisades plant in
Michigan on October 1, 2018. Palisades is in a competitive wholesale power market but earns
nearly all its revenue under a PPA with Michigan utility Consumers Energy. The PPA, scheduled
31
Entergy, “Entergy to Close James A. FitzPatrick Nuclear Power Plant in Central New York,” news release, February
23, 2016, http://www.entergynewsroom.com/latest-news/entergy-close-jamesfitzpatrick-nuclear-power-plant-centralnew-york-1829/.
32
Ostroff, Jim, “Outlook for Exelon’s Ginna Uncertain after 2018, Analysts Say,” Nucleonics Week, February 26,
2015.
33
State of New York Public Service Commission, Order Adopting a Clean Energy Standard, Issued and Effective
August 1, 2016, available at http://www3.dps.ny.gov/W/PSCWeb.nsf/96f0fec0b45a3c6485257688006a701a/
56c58a580d2cf2e185257fd4006b90ce/$FILE/Order%20Adopting%20a%20Clean%20Energy%20Standard.pdf. See
page 143.
34
For more information, see CRS Report R41836, The Regional Greenhouse Gas Initiative: Lessons Learned and
Issues for Congress, by (name redacted)
.
35
Exelon, “Exelon Announces Early Retirement of Clinton and Quad Cities Nuclear Plants,” news release, June 2,
2016, http://www.exeloncorp.com/newsroom/clinton-and-quad-cities-retirement.
36
Rorke, op. cit., p. 4.
37
Freebairn, William, “Exelon Sees Chance of End-of-Year Action to Save Illinois Units: Official,” Nucleonics Week,
October 20, 2016.
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Financial Challenges of Operating Nuclear Power Plants in the United States
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.”38 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.39 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.
Pilgrim
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.40 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.41
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.42
Oyster Creek
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.43
Diablo Canyon
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 rateregulated 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
38
Entergy, “Palisades Power Purchase Agreement to End Early,” news release, December 8, 2016,
http://www.entergynewsroom.com/latest-news/palisades-power-purchase-agreement-end-early/.
39
Beatie, Jeff, “Entergy Retiring Michagan Nuclear Plant Early Due to Financial Pressures,” IHS The Energy Daily,
December 9, 2016.
40
Entergy, “Entergy Intends to Refuel Pilgrim in 2017; Cease Operations on May 31, 2019,” news release, April 14,
2016, Frequently Asked Questions, http://www.pilgrimpower.com/operational-update/.
41
Rorke, op. cit.
42
Rorke, op. cit., p. 5.
43
Dolley, Steven, “Exelon, New Jersey Agree To Shut Down Oyster Creek by 2019,” Nucleonics Week, December 13,
2010.
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Financial Challenges of Operating Nuclear Power Plants in the United States
low-cost, carbon-free energy” and is a “vital energy resource for California.”44 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.”45 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.
Other Potential Closures
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.46 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.47
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.48
44
Pacific Gas and Electric Company, “Diablo Canyon,” website, viewed November 10, 2016, https://www.pge.com/
en_US/safety/how-the-system-works/diablo-canyon-power-plant/diablo-canyon-power-plant.page.
45
Friends of the Earth, “Shutting Down Diablo Canyon,” viewed November 10, 2016, http://www.foe.org/projects/
climate-and-energy/nuclear-reactors.
46
Knauss, Tim, “Nine Mile Point Nuclear Plant Faces Financial Peril, Exec Says,” Syracuse.com, March 31, 2016,
http://www.syracuse.com/news/index.ssf/2016/03/
nine_mile_point_nuclear_plant_faces_financial_peril_exelon_exec_says.html.
47
Funk, John, “FirstEnergy to Sell or Close Power Plants if Ohio, Pennsylvania Do Not Return to Regulated Rates,”
Plain Dealer, November 8, 2016, http://www.cleveland.com/business/index.ssf/2016/11/
firstenergy_to_sell_or_close_p.html.
48
Deloitte, Power and Utilities Accounting, Financial Reporting, and Tax Update, January 2016, p. 26,
https://www2.deloitte.com/content/dam/Deloitte/us/Documents/energy-resources/us-er-power-utilities-accountingfinancial-reporting-and-tax-update.pdf.
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Financial Challenges of Operating Nuclear Power Plants in the United States
Merchant Nuclear Power Plant Economics
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 pricesetting 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,49 as are the economics and levelized cost of
electricity (LCOE) considerations associated with constructing new nuclear plants.50 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.
Nuclear Power Generation Costs
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.51 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.52 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
49
Bloomberg New Energy Finance (BNEF) published a report that evaluated the financial conditions of nuclear power
plants that operate in competitive power markets. For more information, see BNEF, “Reactors in the Red: Financial
Health of the US Nuclear Fleet,” July 7, 2016.
50
For background on LCOE calculations for nuclear and other electric power technologies, see Energy Information
Administration, “Levelized Cost and Levelized Avoided Cost of New Generation Resources in the Annual Energy
Outlook 2016,” August 2016.
51
Nuclear Energy Institute, Nuclear Costs in Context, April 2016.
52
Ibid.
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Financial Challenges of Operating Nuclear Power Plants in the United States
this difference is in the “operating” cost category.53 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.54 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.55
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.56 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).57
How Are Competitive Wholesale Electricity Prices Determined?
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 Dispatch58 (SCED), which takes into account costs, transmission
limitations, and reliability requirements.59 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.60 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.
53
Ibid.
Nuclear Energy Institute, Delivering the Nuclear Promise: Advancing Safety, Reliability and Economic Performance,
February 2016.
55
Some economic analysts may argue that the decision to continue operating is based on revenues covering O&M and
fuel costs only, since capital expenditures are amortized over multiple years. Average total generation costs are
reflected in this report because capital expenses are cash expenditures that must be paid for through revenue/cash
generation.
56
Plant-level fuel and O&M costs from Rorke, op. cit.
57
Nodal electricity prices from Bloomberg New Energy Finance, Reactors in the Red: Financial Health of the US
Nuclear Fleet, July 2016.
58
The Energy Policy Act of 2005 (P.L. 109-58) defines the term “economic dispatch” to mean “the operation of
generation facilities to produce energy at the lowest cost to reliably serve consumers, recognizing any operational limits
of generation and transmission facilities.”
59
It is beyond the scope of this report to fully explain the concept of Security Constrained Economic Dispatch (SCED).
For additional information about SCED, see Federal Energy Regulatory Commission, Security Constrained Economic
Dispatch: Definition, Practices, Issues and Recommendations, July 31, 2006.
60
See text box below, Wind Power and Negative Electricity Prices: What Is the Relationship?, for a discussion of how
these offers may be zero or even negative.
54
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Figure 2. Illustrative Example of Wholesale Electricity Price Formation in a
Competitive Power Market
Source: CRS
Notes: Not representative of actual RTO/ISO market clearing results. Actual values for electricity prices and
electricity supply are not indicated in this figure, as they will vary by market, generation mix, time-of-day, and
location.
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.61 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.62 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 2015.63 Also, nuclear
61
Nuclear Intelligence Weekly, “Utilities: Exelon Moves Reactors Toward Load-Following,” September 16, 2016.
The Federal Energy Regulatory Commission (FERC) evaluates various issues associated with price formation in
RTO/ISO power markets. A compilation of FERC’s energy price formation work is available at http://www.ferc.gov/
industries/electric/indus-act/rto/energy-price-formation.asp.
63
Nuclear Energy Institute, Nuclear Costs in Context, April 2016.
62
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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-ofmarket 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.64
How Natural Gas and Coal Impact Wholesale Electricity Prices
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.
Table 3. Price-Setting Fuel Type Used by Real-time Marginal Generating Units
MISO
ERCOT
PJM
2007
2015
2007
2015
2011
2015
Natural Gas
27.5%
76.0%
92%
50%
25.8%
35.5%
Coal
67.8%
22.7%
8%
45%
68.7%
51.7%
Other
4.7%
1.3%
0%
5%
5.5%
12.8%
Source: Potomac Economics provided, via email, price setting information for MISO and ERCOT at the request
of CRS. PJM price setting information from Monitoring Analytics, State of the Market Report for PJM, 2011 and
2015.
Notes: Potomac Economics is the Market Monitor for MISO and ERCOT. Monitoring Analytics is the PJM
Market Monitor. MISO and ERCOT price setting information was made available for 2007 and 2015. These years
were selected to be consistent with other figures contained in this report. PJM price setting information reflects
2011 and 2015. CRS was not able to locate the same price-setting information for 2007. The integration of MISO
South by MISO in 2013 contributed to an increase in natural gas power generation and price setting.
MISO = Midwest Independent System Operator. ERCOT = Electric Reliability Council of Texas. PJM was an
acronym for Pennsylvania, Jersey, Maryland; however, today it is not an acronym and is simply a brand name for
the system operator.
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
64
Heat rates for combustion technologies such as a steam, gas turbine, internal combustion, and combined cycle unit
indicate the amount of energy—measured in British thermal units or BTUs—needed by each respective technology to
produce one kilowatthour of electricity. The Energy Information Administration (EIA) publishes average heat rates in
the Electric Power Annual publication. See http://www.eia.gov/electricity/annual/html/epa_08_02.html.
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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.”65
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.
Figure 3. Fuel Costs for Natural Gas Power Generation and Average Total Costs for
Nuclear Power Generation
Dollars per Megawatthour (MWh) of Electricity (Nominal)
Source: Natural gas power generation marginal cost range: CRS, using heat rate and monthly natural gas for
electric power price information from Energy Information Administration, Natural Gas Prices, available at
http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm, accessed December 2016 with data through
September 2016. Nuclear power average total costs and range: Nuclear Energy Institute, Nuclear Costs in Context,
April 2016.
Notes: Nuclear power average total costs include fuel, O&M, and capital.
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.66 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
65
Potomac Economics, 2015 State of the Market Report for the ERCOT Wholesale Electricity Markets, June 2016.
Fleet-wide Average Total Costs are used to compare against general gas price and electric power market trends in
this report. However, plant-level analysis included in this report compares electricity prices/revenues with fuel and
O&M costs only.
66
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Financial Challenges of Operating Nuclear Power Plants in the United States
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.
Locational Marginal Prices
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.67 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 Is 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.
Figure 4. Competitive Power Market LMPs for U.S. Nuclear Power Plants
LMP Ranges and Nuclear Power Average Total Costs (Nominal)
Source: CRS. LMP ranges from Bloomberg New Energy Finance, Reactors in the Red: Financial Health of the US
Nuclear Fleet, July 2016. Nuclear average total costs from Nuclear Energy Institute, Nuclear Costs in Context, April
2016.
67
Federal Energy Regulatory Commission, Energy Primer: A Handbook of Energy Market Basics, November 2015.
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Notes: LMPs for each nuclear plant were obtained from the Bloomberg terminal, which also includes forward
price projections through 2019. Nuclear power average total costs through 2015 are from NEI, with 2016 to
2018 projections calculated based on NEI’s “Delivering the Nuclear Promise” stated goals.
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.
Wind Power and Negative Electricity Prices: What Is the Relationship?
The presence of wind electricity generation in certain locations has been an item of concern for some nuclear power
operators due to its effect on locational marginal prices (LMPs) and, therefore, the nodal electricity price that is paid
for nuclear generation. Under certain conditions and in some specific locations, real-time LMPs can drop below zero
for limited periods of time. These temporary negative prices generally result from power generation being in excess
of demand during a particular time interval (e.g., an hour late at night when wind generation is high and power
demand is low). Since there is limited electricity storage capacity in the electric power system, the transmission
operator must constantly balance supply and demand in order to maintain the operational integrity of the system.
Negative prices generally reflect transmission congestion at a location and are a signal to incentivize generators to
lower production in order to balance supply and demand at a specific location. In certain areas, northern Illinois for
example, there can be large amounts of wind power and nuclear generation serving the same demand node through a
common transmission system. During low demand hours (i.e., late night and early morning), there can be times when
electricity supply might exceed demand, and price signals are used to alter generator behavior and bring the system
back into balance.
The role of wind power and the occurrence of negative wholesale power prices are related to federal tax incentives
that are available to wind power generators. According to the American Wind Energy Association (AWEA), wind
power projects that are still in the 10-year production tax credit (PTC) eligibility window will typically offer electricity
between -$20 and -$35 per Megawatthour.68 This price offer essentially means that these units are willing to continue
producing electricity until the applicable LMP drops below the offer price.
In practice, it is not common for generators to pay money in order to generate electricity—which is what negative
prices imply. Reported negative prices generally occur in the real-time market, which makes up only 5% of electricity
transactions. Additionally, negative prices in real-time markets are infrequent. Nevertheless, real-time prices and dayahead prices (95% of electricity transactions) typically converge over time. As a result, periods of negative real-time
LMPs can have a price depression effect on day-ahead wholesale prices that are paid to generators and therefore
impact generator revenue.
A quantitative example of how wind power and transmission congestion affect pricing is the Quad Cities nuclear
power plant in Illinois. In 2015 the Northern Illinois Hub power price—the hub or regional price relevant to Quad
Cities—was $27.93 per MWh.69 However, the nodal electricity price—which reflects the actual price paid for
electricity—for Quad Cities was $19.60 per MWh in 2015.70 This price difference indicates how the presence of wind
generation and its contribution to transmission congestion can have a noticeable impact on electricity sales revenue.
Exelon, the owner and operator of Quad Cities, has indicated its intention to start operating its nuclear fleet in a way
that follows electricity demand—load following. This could potentially reduce transmission congestion in certain areas
and result in nodal prices becoming more normalized with regional hub prices.
Other Revenue Sources
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,
68
American Wind Energy Association, “Negative Prices Still Rare, Mostly Caused by Other Energy Sources,” April
15, 2016, available at http://www.aweablog.org/negative-prices-still-rare-mostly-caused-by-other-energy-sources/.
69
R Street Institute, Where Have All the Nuclear Plants Gone?, October 2016.
70
Bloomberg New Energy Finance, Reactors in the Red: Financial Health of the US Nuclear Fleet, July 2016.
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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.
Figure 5. Comparison of All-in Prices in Different Markets
Source: Potomac Economics, ERCOT 2015 State of the Market Report, June 2016.
Notes: Numbers in this figure represent RTO/ISO averages and may not reflect the actual value received by a
specific power generator. Uplift payments are essentially compensation paid to some generators in the event
that revenue received from the wholesale power market is less than marginal operating costs. While these
payments do not guarantee dispatch, a price for electricity generated, or a threshold rate of return, uplift
payments, in essence, do provide some degree of assurance that generators might not operate at a loss. Ancillary
services include services such as frequency regulation and voltage control that are used to help balance the
transmission system.
ERCOT = Electric Reliability Council of Texas. NYISO = New York Independent System Operator. ISO-NE =
Independent System Operator-New England. MISO = Midwest Independent System Operator. CAISO =
California Independent System Operator. SPP = Southwest Power Pool.
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.71 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
71
For additional capacity market background, see Federal Energy Regulatory Commission, Centralized Capacity
Market Design Elements, August 23, 2013.
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Financial Challenges of Operating Nuclear Power Plants in the United States
scarcity pricing72 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.73 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.74 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.
Power Purchase Agreements (PPAs)
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.75 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.
Case Study: Quad Cities Nuclear Generating Station
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.76 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.
72
ERCOT uses a Scarcity Pricing Mechanism (SPM) to provide economic signals that would motivate development
and construction of new generation assets that would satisfy demand expectations. The SPM essentially sets caps for
price offers from generators. As of June 2015, the ERCOT system-wide offer cap was $9,000 per MWh. The SPM also
has cost containment mechanisms as part of its design that are based on net margins for “peaker” plants that provide
incremental generation during peak demand times.
73
PJM, for example, is in the process of transforming its Reliability Pricing Model auction to deliver a Capacity
Performance product, which could result in higher capacity payments to some generators, including nuclear. For more
information, see http://www.pjm.com/~/media/documents/reports/20150720-capacity-performance-at-a-glance.ashx,
accessed October 26, 2016.
74
PJM, 2019/2020 RPM Base Residual Auction Results, available at http://www.pjm.com/~/media/markets-ops/rpm/
rpm-auction-info/2019-2020-base-residual-auction-report.ashx, accessed October 17, 2016.
75
Identified in a confidential spreadsheet provided to CRS from an industry source, power plants that have some or all
of their capacity subject to a PPA are (1) Cooper (3%), (2) Duane Arnold (70%), (3) Palisades (100%), (4) Point Beach
(100%), (5) Ginna (100%), and (6) Seabrook (4%). The Ginna plant in New York is under a Reliability Support
Services Agreement (RSSA), which supports continued operations of power generators that want to retire but are
needed to ensure system reliability.
76
Exelon, “Exelon Announces Early Retirement of Clinton and Quad Cities Nuclear Plants,” news release, June 2,
2016, http://www.exeloncorp.com/newsroom/clinton-and-quad-cities-retirement.
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Figure 6. Quad Cities Revenue and Cost Information
Dollars per Megawatthour (MWh) of Electricity (Nominal)
Source: Nodal Electricity Price: Bloomberg as reported in Bloomberg New Energy Finance, Reactors in the Red:
Financial Health of US Nukes, July 2016. Capacity Payment: CRS analysis of PJM capacity prices for the COMED
zone as reported by Monitoring Analytics, LLC, Quarterly State of the Market Report for PJM: January through June,
2016. Production cost information for 2015 as reported in Nucleonics Week, “US Utility Operating Costs,” June
2, 2016.
Notes: Production cost estimates for 2013-2019 are assumed to be at 2015 levels. Cost estimates do not
include any capital expenditures. Such expenditures for the Quad Cities plant were not available to CRS.
Capacity values were calculated by starting with PJM COMED capacity prices as reported by the market
monitor. It is assumed that the Quad Cities plant cleared the capacity market for the years 2013 to 2017. Exelon
officially announced that Quad Cities did not clear the capacity market for the years 2018 and 2019. Since 25% of
Quad Cities is rate regulated and the power is provided to Iowa, the total Quad Cities net summer capacity and
electricity production was reduced by 25% for the purpose of calculating the $/MWh capacity payment values
included in this figure.
* Capacity auctions in PJM are for years that start on June 1 and end on May 31. Quad Cities did not clear the
2018/2019 or 2019/2020 capacity auctions. The table does not include capacity revenues for 2018, but Quad
Cities is to receive capacity payments through May 31, 2018, as a result of clearing the 2017/2018 capacity
auction.
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.
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Financial Challenges of Operating Nuclear Power Plants in the United States
Plant-Level Analysis of Electricity Sales Revenue and Fuel and
O&M Costs
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 2019.77 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.
Figure 7. Analysis of Electricity Sales and Fuel and O&M Costs for 33 Nuclear Power
Plants
2015-2019
Source: CRS using data from third-party reports. Bloomberg New Energy Finance, Reactors in the Red: Financial
Health of the US Nuclear Fleet, July 11, 2016. R Street Institute, Where Have All the Nuclear Plants Gone?,” October
2016.
Notes: Nodal prices at each power plant location were used for plant-level revenue. Fuel and O&M costs, as
presented in the R Street report, were used for cost estimates. Fuel and O&M costs were held constant at 2015
levels. Additional assumptions regarding the calculations made for this chart are included in the Appendix.
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,
77
Plant-level fuel and O&M costs from Rorke, op. cit. Nodal electricity prices from Bloomberg New Energy Finance,
Reactors in the Red: Financial Health of the US Nuclear Fleet, July 2016.
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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.
Policy Options and Considerations
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,78 low-carbon electricity.79
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-Level 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.80 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):
78
Nuclear plants consistently have a high capacity factor, averaging close to 90% for the years 2013 to 2015. Capacity
factor indicates what percentage of the 8,760 hours in each year a power generating facility is operating at full capacity.
For a comparison of capacity factors for different power generating technologies in the United States, see Energy
Information Administration, Electric Power Monthly, Table 6.7.B. Capacity Factors for Utility Scale Generators Not
Primarily Using Fossil Fuels, January 2013-September 2016, November 29, 2016.
79
Nuclear power plants are often referred to as having “zero emissions” of greenhouse gases, such as carbon dioxide,
because they do not directly combust fossil fuels to generate electricity. However, energy from fossil fuels is generally
used during the mining and processing of uranium to produce nuclear reactor fuel, and greenhouse gases are emitted
during the production of concrete and other materials for plant construction and during plant decommissioning. The
International Atomic Energy Agency (IAEA) estimates that such “life cycle” greenhouse gas emissions from nuclear
power generation are similar to the life-cycle emissions from wind, solar, and hydropower, which also are typically
classified as “zero emission” electricity sources. See IAEA, Climate Change and Nuclear Power 2016, p. 19,
http://www-pub.iaea.org/MTCD/Publications/PDF/CCANP16web-86692468.pdf. Other studies have found life-cycle
nuclear emissions of greenhouse gases to be higher than renewable sources but still a fraction of emissions from natural
gas, the lowest-emitting fossil fuel generation source. See Kleiner, Kurt, “Nuclear Energy: Assessing the Emissions,”
Nature Reports Climate Change, September 24, 2008, http://www.nature.com/climate/2008/0810/full/
climate.2008.99.html.
80
Environment and Energy Daily, Nuclear: Plant Closures Are ‘A State Issue’—Moniz, September 15, 2016.
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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. 81
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.82 Some of these
potential options are discussed in the following sections.
Power Market Price Formation Changes
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.83 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.84 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.85 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.
Tax Incentives
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.86 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.,
81
U.S. Department of Energy, Secretary of Energy Advisory Board Report of the Task Force on the Future of Nuclear
Power, September 22, 2016, http://www.energy.gov/seab/downloads/final-report-task-force-future-nuclear-power.
82
The American Nuclear Society published a report that outlines several policy options at the federal and state level
that would support nuclear power generation. For more information, see American Nuclear Society, Nuclear in the
States Toolkit: Policy Options for States Considering the Role of Nuclear Power in Their Energy Mix, June 2016.
83
Edison Electric Institute, Electric Power Supply Association, Natural Gas Supply Association, Nuclear Energy
Institute, and America’s Natural Gas Alliance, Letter to FERC Chairman and Commissioners, March 6, 2015, available
at http://www.nei.org/CorporateSite/media/filefolder/Policy/Market/Joint-Trade-Assns-Letter-to-FERC-on-PriceFormation-Principles.pdf?ext=.pdf.
84
Federal Energy Regulatory Commission, https://www.ferc.gov/industries/electric/indus-act/rto/energy-priceformation.asp, accessed November 2, 2016.
85
Federal Energy Regulatory Commission, 155 FERC 61,276: Settlement Intervals and Shortage Pricing in Markets
Operated by Regional Transmission Organizations and Independent System Operators, June 16, 2016.
86
Internal Revenue Code (IRC) Section 45J includes a non-inflation adjusted production tax credit of 1.8 cents per
kilowatthour for qualifying advanced nuclear power facilities.
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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,87 and
(2) the Investment Tax Credit for renewable energy.88 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.
Carbon Price
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.89 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).90 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.91 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,
87
For additional background, see CRS Report R43453, The Renewable Electricity Production Tax Credit: In Brief, by
(name redacted) .
88
For additional background, see CRS In Focus IF10479, The Energy Credit: An Investment Tax Credit for Renewable
Energy, by (na me redacted) .
89
Regional carbon markets, such as RGGI and California’s Cap-and-Trade program, exist in the United States. These
markets were not specifically designed to support nuclear power plants, and the existence of such markets has not
provided sufficient incentives to relieve the financial stress encountered by plants that operate within those market
regions.
90
Implementation of the Clean Power Plan has been stayed by the Supreme Court. For more information see CRS
Report R44341, EPA’s Clean Power Plan for Existing Power Plants: Frequently Asked Questions, by (name red
acted) et al.
Additionally, President-elect Trump has stated that his administration will eliminate the CPP. For more
information, see https://www.greatagain.gov/policy/energy-independence.html.
91
For additional background on a federal carbon tax, see CRS Report R42731, Carbon Tax: Deficit Reduction and
Other Considerations, by (name redacted), (name redacted), and (name redacted)
.
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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.”92
Federal Power Purchase Agreements (PPAs)
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.93 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.
State-Level Policy Action to Support Existing Nuclear Power Plants
In some states where nuclear power plants have indicated their intent to shut down as a result of challenging financial
conditions, state-level agencies and legislatures have taken action to provide financial support for existing nuclear
plants. Generally, the motives supporting such actions include the contribution of nuclear power to a state’s carbon
emission goals and the state and local economic and employment impacts that would result from the closure of an atrisk nuclear facility or multiple facilities. Three such states where policies to support existing nuclear power plants
have either been instituted or proposed are Ohio, Illinois, and New York. Policy approaches in each state vary but
have generally taken one of two forms: (1) a power purchase agreement that provides out-of-market payments to
nuclear power generators, and (2) a premium paid to nuclear power plants that is designed to reflect the low-carbon
attributes of nuclear electricity.
Ohio: An Electric Security Plan filed with the Public Utilities Commission of Ohio (PUCO) by First Energy included a
power purchase agreement (PPA) with the Davis-Besse nuclear power plant and the W.H. Sammis coal-fired power
plant. The plan was approved by PUCO on April 1, 2016. However, the PPA element of the plan was challenged
based on FERC restrictions on wholesale power sales transactions between “a franchised public utility with captive
customers and a market-regulated power sales affiliate.”94 FERC subsequently rejected the PPA and required First
Energy to submit the PPA to FERC for approval prior to any PPA-related sales transactions.
Illinois: Exelon, the owner and operator of the Clinton and Quad Cities nuclear power plants in Illinois, has been
advocating for the state to pass legislation for a Next Generation Energy Plan.95 The plan includes several
components, one of which is a Zero Emission Standard that would provide financial support to nuclear power plants
in the state that are at risk of early retirement. The energy plan includes a Zero Emission Standard that creates a
program to purchase zero emission credits (ZECs) from nuclear plants and pass along the ZEC acquisition costs to
ratepayers.96 On December 1, 2016, the Illinois General Assembly passed S.B. 2814, which included an amendment to
create a ZEC program for nuclear power plants in the state.97 The Illinois ZEC program is similar in nature to the
New York program, as described below, with the ZEC value being based on the U.S. Interagency Working Group
92
Environmental Protection Agency, Regulatory Impact Analysis for the Clean Power Plan Final Rule, August 2015.
U.S. Department of Energy, Federal On-site Renewable Power Purchase Agreements, http://energy.gov/eere/femp/
federal-site-renewable-power-purchase-agreements, accessed November 4, 2016.
94
Federal Energy Regulatory Commission, 155 FERC 61, 101.
95
An overview of the Illinois Next Generation Energy Plan is available at http://www.nextgenerationenergyplan.com/
about#page2.
96
Bloomberg New Energy Finance, US Nuclear Takes One Step Forward, Eight Steps Backward, June 30, 2016.
97
Complete text of SB2814 is available on the Illinois General Assembly website. See http://www.ilga.gov/legislation/
99/SB/PDF/09900SB2814ham003.pdf.
93
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Financial Challenges of Operating Nuclear Power Plants in the United States
social cost of carbon (SCC). The base SCC value is $16.50 per MWh and ZEC values are adjusted annually based on
electricity prices and capacity payments that are applicable to nuclear power plants participating in the program.
New York: On August 1, 2016, the State of New York Public Service Commission (PSC) issued an order to adopt a
clean energy standard (CES). Among several stated goals, including additional support for renewable energy
deployment, the CES includes a ZEC requirement, which is an “obligation on load serving entities to financially
support the preservation of existing at-risk nuclear zero-emissions attributes.”98 Under the ZEC requirement, the
New York State Energy Research and Development Authority (NYSERDA) would purchase ZECs from qualifying
nuclear facilities during the period April 1, 2017, through March 31, 2029, in two-year tranches. In order to qualify for
ZEC purchases, nuclear facilities must demonstrate public necessity by opening their books and records for an
assessment by the Commission. For the first two-year tranche, the ZEC price has been calculated—based on the U.S.
Interagency Working Group July 2015 SCC equal to $42.87 per short ton—to be $17.48 per MWh.99 For the
remaining tranches, ZEC prices will be adjusted based on a formula that takes into account the social cost of carbon,
baseline Regional Greenhouse Gas Initiative (RGGI) carbon values, and the forecasted price of electricity and
capacity.100 The ZEC requirement is targeted to provide financial support to three nuclear plants in upstate New
York: (1) FitzPatrick, (2) Ginna, and (3) the two-unit Nine Mile Point facility. An annual MWh ZEC price cap is based
on the four-year average cumulative production from these three plants. Additionally, the PSC order indicates that
the 12-year duration of the ZEC program is contingent on the FitzPatrick power plant being sold and ownership
transferred by September 1, 2018. Should the FitzPatrick plant not be sold by this date the PSC would determine a
course of action, if any, for future ZEC tranches.101 A suit was filed with the U.S. district court in the southern district
of New York challenging the legality of the CES and ZEC program.102
98
State of New York Public Service Commission, Order Adopting a Clean Energy Standard, August 1, 2016.
Ibid. Both New York and Illinois use the same U.S. Interagency Working Group $/ton value for carbon emissions.
However, each state uses multipliers and discounts to convert the $/ton value into a $/MWh value. This explains why
the $/MWh values for each state is different.
100
Ibid.
101
Ibid.
102
http://www.epsa.org/forms/uploadFiles/3D17B00000014.filename.ZEC_Complaint_File_Stamped_101916.pdf.
99
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Financial Challenges of Operating Nuclear Power Plants in the United States
Appendix. Plant-level Analysis of Electricity Sales
Revenue and Fuel and O&M Costs
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 plantlevel 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.
Table A-1. Plant-Specific Analysis of Electricity Sales Revenue and Fuel and O&M
Costs
Dollars per Megawatthour
2015
2016
2017
2018
2019
Clinton
(2.63)
(0.70)
(2.55)
(2.80)
(3.53)
Quad Cities
(4.46)
(7.32)
(3.08)
(3.19)
(3.92)
Pilgrim
11.04
(2.50)
8.13
7.95
7.90
Beaver Valley
5.22
0.69
3.75
2.78
1.53
Braidwood
2.76
(0.59)
3.30
3.05
2.85
Byron
(2.30)
(5.64)
(0.13)
(0.17)
(0.97)
Calvert Cliffs
17.10
8.07
12.06
11.18
11.09
Donald C. Cook
4.24
(0.60)
1.54
1.35
0.39
Davis-Besse
7.47
2.67
6.40
5.52
4.59
Dresden
3.93
0.68
4.43
4.16
3.95
Hope Creek
8.05
(0.68)
7.02
6.30
5.42
LaSalle County
4.74
1.27
5.18
4.97
3.97
Limerick
9.12
0.48
7.88
7.16
6.28
Oyster Creek
5.31
(4.63)
2.15
1.37
0.85
Peach Bottom
8.60
(0.73)
5.80
5.06
4.95
Perry
6.79
3.31
7.88
6.29
4.73
Congressional Research Service
30
Financial Challenges of Operating Nuclear Power Plants in the United States
2015
2016
2017
2018
2019
Salem
8.62
(0.08)
7.61
6.90
6.02
Susquehanna
8.77
(0.66)
5.50
4.76
4.65
Three Mile Island
4.29
(4.03)
2.16
2.18
1.95
Duane Arnold
(8.43)
(9.81)
(6.46)
(6.69)
(7.40)
Fermi
(2.96)
(6.28)
(1.95)
(2.82)
(3.72)
Grand Gulf
4.58
5.59
8.34
7.27
7.04
Palisades
(1.63)
(4.06)
(1.88)
(2.08)
(3.00)
Point Beach
1.01
(2.63)
(0.15)
(0.37)
(1.22)
FitzPatrick
0.40
(4.33)
1.16
1.38
0.11
Ginna
7.38
2.92
8.34
6.58
4.88
Indian Point 2
12.35
2.96
14.15
12.29
11.49
Indian Point 3
8.90
(0.60)
10.65
8.79
7.98
Nine Mile Point
1.34
(3.46)
2.05
2.28
1.00
Millstone
16.03
2.99
13.07
12.92
14.33
Seabrook
7.05
6.83
10.58
10.44
10.40
Comanche Peak
0.66
6.42
4.50
3.60
3.35
South Texas Project
0.25
6.23
4.48
3.46
3.22
Source: CRS, using third-party data for revenue and cost. Revenue per MWh represents nodal prices for each
nuclear power plant that was provided by Bloomberg New Energy Finance as part of a July 2016 report, Reactors
in the Red: Financial Health of the US Nuclear Fleet. O&M cost per MWh (including fuel) for each plant was from an
October 2016 report by the R Street Institute, Where Have All the Nuclear Plants Gone?
Notes: Nodal prices from Bloomberg include forward electricity price projections through 2019, as of the date
of the report. Electricity forward price projections can change over time. Fuel and O&M costs for each plant
were only available for the year 2015. For the purpose of the analysis, it was assumed that fuel and O&M costs
stayed at 2015 levels. Generally, indications are that fuel and O&M costs are in a narrow range from year-toyear. However, plant-specific fuel and O&M costs can vary and impact the estimates presented above. Negative
numbers—indicated by parentheses—in the table suggest that fuel and O&M costs for the plant exceed the
nodal electricity price.
Author Contact Information
(name redacted)
Specialist in Energy Policy
[redacted]@crs.loc.gov, 7-....
Congressional Research Service
(name redacted)
Specialist in Energy Policy
r[ edacted]@crs.loc.gov
, 7-....
31
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