WNA updated the webpage in May, 2020 and self-updates in the future. This updates reports that the U.S. is still the world's largest producer of nuclear power, accounting for more than 30% of worldwide nuclear generation of electricity. The country's nuclear reactors produced 809 billion kWh in 2019, about 20% of total electrical output. There are two reactors under construction. Following a 30-year period in which few new reactors were built, it is expected that two more new units will come online soon after 2020, these resulting from 16 licence applications made since mid-2007 to build 24 new nuclear reactors.
Government policy changes since the late 1990s have helped pave the way for significant growth in nuclear capacity. Some states have liberalized wholesale electricity markets, which makes the financing of capital-intensive power projects difficult, and coupled with lower gas prices since 2009, have put the economic viability of some existing reactors and proposed projects in doubt.
The first zero-emission credit programs have commenced, in New York, Illinois and New Jersey, with corresponding provision in Connecticut.
In 2018, US electricity generation was 4178 TWh (billion kWh) net, 1468 TWh (35%) of which from gas, 1146 TWh (27%) from coal-fired plant, 807 TWh (19%) nuclear, 292 TWh from hydro, 275 TWh (6.6%) from wind, 67 TWh (1.6%) from solar, 63 TWh from biomass, and 60 TWh from geothermal and other sources (US Energy Information Administration data). Annual electricity demand is projected to increase to 5000 TWh in 2030, though in the short term it is depressed and has not exceeded the 2007 level. Annual per capita electricity consumption in 2017 was about 12,300 kWh. Total net summer capacity is about 1080 GWe, less than one-tenth of which is nuclear. In 2019, 809 TWh was produced from nuclear.
Nuclear power plays a major role. The USA has 98 operating nuclear power reactors in 30 states, operated by 30 different power companies. Since 2001 these plants have achieved an average capacity factor of over 90%, generating up to 807 TWh per year and accounting for about 20% of the total electricity generated. The average capacity factor has risen from 50% in the early 1970s, to 70% in 1991, and it passed 90% in 2002, remaining at around this level since. In 2019 it was a record 93.5%, compared with wind (34.8%) and solar PV (24.5%) (EIA data). The industry invests about $7.5 billion per year in maintenance and upgrades of the plants. Average nuclear generation costs have come down from $42/MWh in 2012 to $30/MWh in 2019.
There are 65 pressurised water reactors (PWRs) with a combined capacity of about 65 GWe and 33 boiling water reactors (BWRs) with a combined capacity of about 34 GWe – for a total capacity of 99,221 MWe (see Nuclear Power in the USA Appendix 1: US Operating Nuclear Reactors). Almost all the US nuclear generating capacity comes from reactors built between 1967 and 1990. Until 2013 there had been no new construction starts since 1977, largely because for a number of years gas generation was considered more economically attractive and because construction schedules during the 1970s and 1980s had frequently been extended by opposition, compounded by heightened safety fears following the Three Mile Island accident in 1979. A further PWR – Watts Bar 2 – started up in 2016 following Tennessee Valley Authority's (TVA's) decision in 2007 to complete the construction of the unit.
Despite a near halt in new construction of more than 30 years, US reliance on nuclear power has grown. In 1980, nuclear plants produced 251 billion kWh, accounting for 11% of the country's electricity generation. In 2008, that output had risen to 809 billion kWh and nearly 20% of electricity, providing more than 30% of the electricity generated from nuclear power worldwide. Much of the increase came from the 47 reactors, all approved for construction before 1977, that came online in the late 1970s and 1980s, more than doubling US nuclear generation capacity. The US nuclear industry has also achieved remarkable gains in power plant utilization through improved refueling, maintenance and safety systems at existing plants. Average generating cost in 2014 was $36.27 per MWh ($44.14 at single-unit sites and $33.76 at multi-unit sites), including fuel and capital, and average operating cost was $21/MWh.
While there are plans for a number of new reactors (see section on Preparing for new build below), no more than two more new units will come online by 2021. Since about 2010 the prospect of low natural gas prices continuing for several years has dampened plans for new nuclear capacity. In May 2016 the Energy Information Administration (EIA) said that nearly 19 GWe of new gas-fired generation capacity was expected online by 2019, mostly using shale gas. It later reported that 9 GWe of gas capacity had come online in 2016, along with 8.7 GWe wind and 7.7 GWe solar. There was a net capacity gain in 2016 of 15 GWe after about 12 GWe retirements.
The two AP1000 reactors under construction at Vogtle are eligible for subsidies similar to but significantly less than those applied to wind power generation. Under the Energy Policy Act (EPA) 2005, up to 6000 MWe of new nuclear is eligible for production tax credits (PTCs). PTCs are divided pro rata among those applicants which had filed combined construction and operating licence (COL) applications by the end of 2008, commenced construction of advanced plants by 2014, and which enter service by 2021. At the start of 2018, an extension to the PTC was passed by the US Senate and Congress. This was critical for the Vogtle plant, where unit 3 is not expected to enter operation until 2021, with unit 4 a year later. The level of the PTC is 1.8 cents per kWh, for eight years, and cannot be claimed until an asset is producing electricity. There is an annual payment limit of $125 million for each 1000 MWe of capacity.
In addition to granting an extension, the new act passed in February 2018 allows non-profit and municipal owners of the new Vogtle units to trade their credits to a profit-making company involved in the construction of the reactors. (Non-profit and municipal power companies do not pay taxes and therefore could not benefit from the credits.) The largest owners of each project are for-profit utilities, Georgia Power for Vogtle and South Carolina Electric & Gas for Summer. Allowing the municipal and non-profit owners to transfer their tax credits to a company involved in the ownership or construction of the units will save ratepayers money and would “correct a disparity of current law.” For more information, see section on Financial incentives below.
In February 2013 Duke Energy's 860 MWe Crystal River PWR in Florida was decommissioned due to damage to the containment structure sustained when new steam generators were fitted in 2009-10, under previous owner Progress Energy. Its 40-year operating licence was due to expire in 2016. Some $835 million in insurance was claimed. Dominion Energy's 566 MWe Kewaunee PWR in Wisconsin was decommissioned in May 2013, after 39 years operation. Then in June 2013 the two 30-year old PWR reactors (1070 & 1080 MWe) at San Onofre nuclear plant in California were retired permanently due to regulatory delay and uncertainty following damage in the steam generators of one unit.* In August 2013 Entergy announced that its 635 MWe Vermont Yankee reactor would be closed down at the end of 2014 as it had become uneconomic, and this was done.
* An economic study claimed that Californian generating costs rose by $350 million in the following year and carbon emissions by 9 million tonnes per year as a result.9
Ten other nuclear plants (13 reactors) were considered (at the start of 2014) to be at risk of closure, all but one of these in the northeast of the country, in deregulated states. The factors giving rise to uncertainty are high costs with low power prices, regulatory issues, and local concerns with safety and reliability. The Nuclear Energy Institute (NEI) said in December 2015 that "total electric generating costs at US nuclear plants have increased 28% – to an industry average $36.27 per MWh – over the past 12 years," including fuel, capital and operation and maintenance costs. It announced an initiative coordinated with the Nuclear Regulatory Commission (NRC) to cut electricity production costs by 30% by 2018.
Coal is projected to retain the largest share of the electricity generation mix to 2035, though over 2002-16, while about 20 GWe of coal-fired capacity was added, more than 53 GWe was retired according to the EIA, due to environmental constraints and low efficiency, coupled with a continued drop in the fuel price of gas relative to coal, and tax policies favoring renewables. A further decrease to 2020 is expected, and most operating coal-fired plants are older than 35 years. Coal-fired capacity in 2015 was 280 GWe. The EIA projects 13 GWe of new gas-fired capacity, mostly CCGT, coming online in 2017, adding to the existing 431 GWe, and with 2 GWe to be retired. This trend is expected to continue to about 2020. The predominance of CCGT is driven by low gas prices, strict regulation of coal-fired plants, though the need to back up intermittent renewables input favors less-efficient OCGT. Natural gas prices over 2015 to March 2017 ranged from $1.50 to $3.80/million BTU.
Given that nuclear plants generate nearly 20% of the nation’s electricity overall and 63% of its carbonâ€free electricity, even a modest increase in electricity demand would require significant new nuclear capacity by 2025 in addition to the two nuclear reactors currently under construction in order to maintain this share. If today’s nuclear plants retire after 60 years of operation, 22 GWe of new nuclear capacity would be needed by 2030, and 55 GWe by 2035 to maintain a 20% nuclear share.
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