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The USA is 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 807 billion kWh in 2018, 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 programmes 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.
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 2016 it was a record 92.5%, compared with wind 34.7% (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 $40/MWh in 2012 to $34/MWh in 2017.
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 utilisation through improved refuelling, 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.
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 profitmaking 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.
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 favouring 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 favours 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 carbon‐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.
Capital expenditure on existing nuclear plants peaked in 2012 due to post-Fukushima upgrades, and it declined 26% to 2015 when capital investment in operating plants was $6.25 billion, according to the Nuclear Energy Institute.
The USA was a pioneer of nuclear power development.a Westinghouse designed the first fully commercial pressurised water reactor (PWR) of 250 MWe capacity, Yankee Rowe, which started up in 1960 and operated to 1992. Meanwhile the boiling water reactor (BWR) was developed by the Argonne National Laboratory, and the first commercial plant, Dresden 1 (250 MWe) designed by General Electric, was started up in 1960. A prototype BWR, Vallecitos, ran from 1957 to 1963.
Nuclear developments in USA suffered a major setback after the 1979 Three Mile Island accident, though that actually validated the very conservative design principles of Western reactors, and no-one was injured or exposed to harmful radiation. Many orders and projects were cancelled or suspended, and the nuclear construction industry went into the doldrums for two decades. Nevertheless, by 1990 over 100 commercial power reactors had been commissioned.
Operationally, from the 1970s the US nuclear industry dramatically improved its safety and operational performance, and by the turn of the century it was among world leaders, with average net capacity factor over 90% and all safety indicators exceeding targets.
This performance was achieved as the US industry continued deregulation, begun with passage of the Energy Policy Act in 1992. Changes accelerated after 1998, including mergers and acquisitions affecting the ownership and management of nuclear power plants.
About 54 GWe of US nuclear capacity is in regulated markets, and 45 GWe in deregulated merchant markets, with power sold competitively on a short-term basis. In these liberalized markets, regional transmission organisations (RTOs) and independent system operators (ISOs) operate the grid, using free-market auctions and longer-term power purchase agreements under federal arrangements and rules. See NEI listing.
In states with deregulated electricity markets, nuclear power plant operators have found increasing difficulty with competition on two fronts: low-cost gas, particularly from shale gas developments, and subsidized wind power with priority grid access. The imposition of a price on carbon dioxide emissions would help in competition with gas and coal, but this is not expected in the short term. Single-unit plants which tend to have higher operating costs per MWh are most vulnerable. The basic problem is low natural gas prices allowing gas-fired plants to undercut power prices. A second problem is the federal production tax credit of $23/MWh paid to wind generators, coupled with their priority access to the grid. When there is oversupply, wind output is taken preferentially. Capacity payments can offset losses to some extent, but where market prices are around $35-$40/MWh, nuclear plants are struggling. According to Exelon, the main operator of merchant plants and a strong supporter of competitive wholesale electricity markets, low prices due to gas competition are survivable, but the subsidized wind is not. In 2016 the subsidy (production tax credit) is $23/MWh. Though wind is a very small part of the supply, and is limited or unavailable most of the time, its effect on electricity prices and the viability of base-load generators “is huge”.
Entergy’s six merchant units benefited from unusually cold weather and tight power supplies during the two winters to 2014, but the company warned that the power supply situation in the Northeast remained uncertain.
In February 2014 the Nuclear Energy Institute (NEI) warned: “Absent necessary changes in policies and practices, this situation has implications for reliability, long-term stability of electricity prices, and our ability to meet environmental goals.” In April 2014 the heads of the NEI, Edison Electric Institute and Electric Power Supply Association urged the Federal Energy Regulatory Commission (FERC) to continue its efforts to improve US electricity and capacity markets. While the nation’s electricity supply and delivery system largely passed the 'stress test' imposed by extreme cold weather from the polar vortex earlier in the year, the weather events raised reliability and market design issues that should be addressed, they said. Grid operators found that problems in bringing coal and gas capacity online had brought the North Atlantic grid close to breakdown. The situation was saved by a very high level of nuclear availability. “FERC reforms of competitive wholesale power markets as to market design, tariff rules and grid operator practices” are needed to improve investment signals and provide the portfolio of resources necessary to maintain grid reliability.
A significant ISO for nuclear plants is PJM Interconnection which serves all or parts of 13 mid-Atlantic states and DC. In May 2014 five Exelon reactors at three plants – Oyster Creek, Quad Cities and Byron – for the first time failed to clear the PJM capacity auction for three years ahead, 2017-2018, so will not receive capacity payments or an assured market for 12 months then, despite having been a reliable basis of supply in New Jersey and Illinois for decades, and zero-carbon sources. The clearing price was $120/MWe-day (except for part of New Jersey: $215/MWe/day). This was for 167 GWe, which included a 19.7% reserve margin. About 4.8 GWe of new combined cycle gas plant was successful in the auction, along with almost 11 GWe of demand-side response. PJM said that capacity prices account for about 10 to 15% of retail bills – the above price nominally being 0.5c/kWh.
In August 2015, three Exelon merchant plants (four reactors) failed to clear the capacity auction for 2018-19 – Oyster Creek, Quad Cities and Three Mile Island. Byron did clear it. The clearing price was $167/MWe-day (except for two small areas: $215 and $225/MWe-day) under new rules offering bonuses for reliability and penalties for failure to supply. Exelon noted: "This auction was the first held under FERC’s new 'capacity performance' reforms designed to spur investments in power plants that will improve their performance and strengthen electric grid reliability." This is a "step in the right direction to recognize nuclear energy's high reliability," and "while three of our plants in the PJM did not clear, we view the auction results as an encouraging sign that these reforms will begin to level the playing field." Total supply commitments rose to $10.9 billion.
In September 2015 all Exelon’s Illinois nuclear plants in the PJM region cleared the transition capacity auctions for the 2016-17 year and for the 2017-18 year. These are supplementary to the earlier base auctions for those years and designed to boost reliability. The May 2015 PJM auction cleared at $216/MWe-day. As a result, the company deferred any decisions about the future of its Quad Cities and Byron nuclear plants and will bid Quad Cities, Byron, Three Mile Island and all eligible nuclear plants into the 2019-2020 PJM capacity auction in 2016. Exelon said that deferring any decision on Quad Cities and Byron was “only a short-term reprieve. Policy reforms are still needed to level the playing field for all forms of clean energy and best position the state of Illinois to meet EPA's new carbon reduction rules." The Illinois EPA calculated the incremental societal cost of losing two plants at more than $10 billion – excluding the major cost of higher energy bills, reduced electric reliability and lost jobs.
In April 2016 Exelon announced that Clinton had cleared the Midcontinent Independent System Operator (MISO) capacity auction for 2016-17 (clearing price $72 per megawatt day), which would take it to May 2017, albeit unprofitably. In May 2016 Exelon’s Quad Cities and Three Mile Island plants failed to clear the PJM capacity auction for 2019-20 (clearing price $202.77/MWd). Exelon’s other Illinois plants in the PJM region cleared the auction: Braidwood, Dresden and La Salle, with part of Byron’s capacity, along with over 5000 MWe of gas-fired combined cycle capacity which reduced the price.
In May 2017 Exelon’s Three Mile Island (TMI) unit 1 and Quad Cities 1&2 failed to clear the PJM Interconnection capacity auction for 2020-21. Its other plants did clear in the auction, which cleared about $25 below last year and $15 below market expectations at $76.53/MWd for the majority of the PJM footprint due to lower load forecasts and other factors. Exelon said that its nuclear units cleared a total of 13,275 MWe of capacity in the auction. Clearing prices for that capacity ranged from $188/MWd in the ComEd region serving Chicago, where Quad Cities is located, to $77/MWd in the RTO region. In TMI’s region, the price was $88/MWd. Exelon said that TMI 1 has not cleared the past three PJM auctions and has not been profitable in five years. While the continued operation of Quad Cities is ensured by newly-introduced legislation in Illinois, Exelon said that the TMI reactor, which entered service in 1974, was at risk of early retirement.
In May 2018, PJM's 2021-22 capacity market auction cleared at $140/MWd, an 83% increase over the 2017 auction. Despite the higher price, just 19 GWe of nuclear cleared, a decrease of 7.4 GWe from last year. Exelon said that TMI 1, Dresden and "all but a small portion" of its Byron plant failed to clear. FirstEnergy, despite announcing retirement plans for 4 GWe of nuclear capacity in March, was required to offer the units into the auction – but none cleared.
Following the 2014 auction, FERC said it was actively considering ways it can ensure that base-load power sources, such as nuclear plants, are appropriately valued and their viability maintained in wholesale electricity markets. FERC’s focus is on capacity markets and how they should take into account the full value of a base-load power plant. Also whether there are appropriate incentives for plants that contribute to the country’s electric reliability to survive and continue providing those services.
The Nuclear Energy Institute (NEI) presented figures from the Electric Utility Cost Group on generating costs comprising fuel, capital and operating costs for 61 nuclear sites in 2012. The average came to $44/MWh, being $50.54 for single-unit plants and $39.44 for multi-unit plants (all two-unit except Browns Ferry, Oconee and Palo Verde). The $44 represented a 58% increase in ten years, largely due to a three-fold increase in capital expenditure on plants which were mostly old enough to be fully depreciated. Over half of the capital expenditure (51%) in 2012 related to power uprates and licence renewals, while 26% was for equipment replacement.
The US Energy Information Administration forecast in April 2014 that the country will lose 10,800 MWe of nuclear generation by 2020 because of lower prices of natural gas and stagnant growth in electricity demand. This will have significant implications for CO2 emissions, and it projected that early retirement of nuclear capacity, instead of coal, could see annual CO2 emissions be 500 million tonnes higher by 2040.
In June 2014 PPL decided to spin off all its merchant plants including the two-unit Susquehanna nuclear plant (2520 MWe net) and combine them with those of a private equity company Riverstone Holdings, to form Talen Energy, which will operate over 15 GWe of capacity in the USA. This move underlines the very different market situations of merchant and regulated plants. About 8.1 GWe of regulated capacity in Kentucky will remain with PPL. Talen will have a major presence in the PJM Interconnection region.
Exelon’s single-reactor Oyster Creek plant in New Jersey was shut down in September 2018, eleven years before its operation was due to end, so as to avoid the expense of state environmental regulations that would require the construction of $800 million cooling towers. Entergy’s 677 MWe single-reactor Pilgrim plant in Massachusetts is to be shut down in May 2019, due to market conditions and increased costs, the same situation as caused Entergy to close its 635 MWe Vermont Yankee reactor at the end of 2014, and plan to close its 852 MWe Fitzpatrick reactor in January 2017. In November 2015 Exelon said that its Clinton, Ginna and Quad Cities plants were at greatest risk of early retirement for economic reasons, with a question mark also over Byron. In May 2016 Exelon said it would close Clinton in June 2017 and Quad Cities in June 2018 unless the state of Illinois made provision for them to be profitable, by means of zero emission credits, likely to be capped at 20 TWh/yr for the 2884 MWe. New York state is making similar provision for its upstate plants (see below). In June 2016 Omaha Public Power decided to close Fort Calhoun in Nebraska, the smallest US nuclear power plant, at the end of the year. PG&E in June 2016 announced that the Diablo Canyon units would close in 2024 and 2025.
In September 2017 Entergy announced that it will keep its Palisades nuclear plant in Michigan open until 2022. The company had previously announced in December 2016 that it planned to close the 789 MWe net unit in October 2018 due to economic factors in the partly deregulated market.
Early in 2017 Entergy and the state of New York agreed that unit 2 of the Indian Point plant would close by the end of April 2020, followed by unit 3 in April 2021. Energy cited “sustained low current and projected wholesale energy prices that have reduced revenues, as well as increased operating costs” coupled with political pressure. The reactors have been operating since 1974 and 1976, and Entergy had invested over $1.3 billion in them over the 15 years it owned them. Its application for licence renewal of the two units was proceeding very slowly through the NRC review. Entergy requested that the NRC shorten the term of renewed operating licences for units 2 and 3 to 2024 and 2025 respectively. The renewed operating licences were approved in September 2018.
In June 2014 the US Environmental Protection Agency (EPA) announced that it would use its authority under the Clean Air Act to require a reduction in carbon emissions from US power plants of 25% below 2005 levels by 2020, and more by 2030, with states to be responsible for achieving this. There has already been a 16% drop since 2005. In August 2015 the EPA issued its Clean Power Plan to curb greenhouse gas emissions from existing fossil fuel-fired power plants under section 111(d) of the Clean Air Act and to reduce CO2 emissions by 32% from 2005 levels by 2030. The Plan became effective in December 2015, and states were to have until September 2018 to submit their plans to comply with the emission reductions, using various means including increased thermal efficiency by 2.1 to 4.3%, greater use of nuclear power and renewables, and greater use of gas.
The Clean Power Plan was heavily biased to wind and solar renewables, but allowed credit for new nuclear power plants and uprates to existing units, but would not credit the role of existing nuclear capacity, some of which is marginal economically in present market conditions. Nor would it credit nuclear licence extensions on the same basis as new capacity. Nuclear power produces 63% of US carbon-free electricity, nuclear plants are already the main carbon-free generation source for over half of US states, and they avoid the emission of over 750 million tonnes of CO2 per year relative to coal. It is accepted that the 32% CO2 reduction by 2030 will be impossible without at least the present level of nuclear contribution. About one-third of the nation’s 300 GWe of coal-fired base-load capacity is expected to be retired by 2030. Some states were preparing legal challenges to the Plan, others remain committed to it.
In November 2014 the National Association of Regulatory Utility Commissioners urged the EPA, in its proposed Clean Power Plan, to adopt regulations which “encourage states to preserve, life-extend, and expand existing nuclear generation.” The EPA proposal in its original form would not have achieved what is intended in respect to nuclear power, and Exelon applauded the NARUC resolution. In January 2015 the NEI said that a top priority was for nuclear plant operators to be fully compensated in competitive wholesale US electricity markets for the value they provide as the main source of reliable, carbon-free, 24/7 base-load power.
In March 2017 President Trump signed the Energy Independence Policy executive order which aimed to roll back the 2015 EPA Clean Power Plan, and called for the EPA to review it to remove what may “unduly burden the development of domestic energy resources.” The impact of this could not be immediate, and may be more in tone than substance. It would take several years under notice and comment rulemaking processes, and the main timeline under the Plan was 2030 in any case. Nuclear energy is likely to be unaffected directly. US electricity should be "affordable, reliable, safe, secure, and clean,” presumably in that order of priority. The executive order rescinded several climate change measures but did not mention the 2016 Paris climate change agreement, which the new administration considered to be essentially a treaty that needs to be ratified by the Senate. In October 2017 the EPA issued a notice of proposed rulemaking (NOPR) to repeal the Clean Power Plan on the grounds that it exceeds the EPA’s authority under the Clean Air Act and sets emission standards that power plants could not reasonably meet. Repeal of the plan, which was premised on a “novel and expansive view of Agency authority,” would save $33 billion in compliance costs by 2030 according to the EPA.
The Regional Greenhouse Gas Initiative is a 2009 cap-and-trade programme for reducing carbon dioxide emissions, covering the nine northeast states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont. Carbon dioxide emissions allowances are auctioned quarterly, with current prices around $3/tonne. With the threatened repeal of the EPA Clean Power Plan, the states have announced a plan to cut power plant emissions by 30% from 2020 to 2030. If approved by individual states, emissions would be reduced by 65% from 2009 levels.
A number of states are taking action to counteract problems with the markets, which the states do not control, to preserve values not recognized in the markets.
In December 2015 the New York state governor directed its Department of Public Service (NYDPS) to develop a clean energy standard (CES) that calls for a 40% reduction in greenhouse gas emissions from 1990 levels by 2030 and a longer-term decrease of 80% by 2050, while not losing carbon reduction gains achieved to date. The state intended to comply with the EPA Clean Power Plan, and its six nuclear reactors provided nearly one-third of the state’s electricity in 2015. Entergy had announced the premature closure of its FitzPatrick nuclear plant in upstate New York by January 2017, and Exelon had warned its Ginna and Nine Mile Point plants are at risk of closure for similar economic reasons. The governor said that closing nuclear facilities “would eviscerate the emission reductions achieved through the state’s renewable energy programmes, diminish fuel diversity, increase price volatility, and financially harm host communities.” The New York independent system operator later warned that to preserve the reliability of the grid, the state must keep all of its nuclear plants operating while slowing renewable energy growth.
The NYDPS issued a white paper in January 2016 proposing 'zero-emission credits' (ZECs) for nuclear generators that would work in parallel with the tax credits that renewable sources receive, and provide the market signals necessary to warrant continued operation of these non-emitting plants. The Nuclear Energy Institute noted that the proposal “establishes a mechanism that can ensure nuclear operators receive the market signals necessary to warrant continued operation of these non-emitting assets.” In addition, a cost study issued by the NYDPS in April 2016 as a supplement to the white paper shows the “outstanding value” that including nuclear in the clean energy standard would provide to New York citizens. The study pointed out that the zero-emission credits would generate $2.8 billion in benefits, or two-thirds of the entire clean energy standard programme’s $4.4 billion – for $270 million, or less than 8% of the programme’s costs.
In July 2016 the NYDPS put forward a proposal which would value the zero-emissions attributes of the upstate nuclear power plants, based on the social cost of carbon and requiring the distribution utilities “to pay for the intrinsic value of carbon-free emissions from nuclear power plants by purchasing zero-emission credits.” The department said that there is a "public necessity" for subsidies for the Fitzpatrick, Ginna and Nine Mile Point plants (four reactors, total 3371 MWe). The benefits of paying such subsidies would far outweigh the costs, the department said. During the first two years of the program, the state’s economic and environmental benefits associated with carbon reductions, supply cost savings and property tax benefits were estimated to be about $5 billion, against total payments of up to $965 million – a net benefit of $4 billion.
New York's zero-emission credits (ZEC) programme is being implemented in six tranches over a period of 12 years from April 2017. For the first two-year period nuclear generators receive ZECs of $17.54/MWh, paid by the distribution utilities (and hence eventually ratepayers) but otherwise similar to the federal production tax credits (PTC) applying to renewables since 1993 on an inflation-adjusted basis, though at a lower rate than its $23/MWh for wind. ZECs will escalate to $29.15/MWh over subsequent years. Later, in July, Entergy’s Indian Point plant was included in the proposal, adding 2061 MWe to it, albeit not for the first two years. The NY Public Service Commission on 1 August 2016 approved the CES plan, but excluded Indian Point. The majority vote was reported to be on three main criteria: grid reliability, reducing carbon emissions, and maintaining jobs. The governor’s announcement said: “A growing number of climate scientists have warned that if these nuclear plants were to abruptly close, carbon emissions in New York will increase by more than 31 million metric tons during the next two years, resulting in public health and other societal costs of at least $1.4 billion.” The Environmental Defense Fund and Natural Resources Defense Council have supported the legality of New York's ZEC scheme.
The broader CES requires that NY state’s utilities source at least half their electricity from renewables by 2030, less than it gets now from all clean energy sources: nuclear 32%, hydro 19%, wind 3%, and solar (less than 1%). Gas supplies 40% of power. The CES also requires distribution utilities to obtain a targeted number of renewable energy credits each year for new wind developments on a similar basis, at about $22/MWh.
In August 2016 Exelon reached agreement to buy the 838 MWe Fitzpatrick plant from Entergy for $110 million in anticipation of the NYPDS CES proposal being implemented. Also it confirmed that it will now proceed with investing about $200 million in Nine Mile Point and Ginna plants early in 2017 and will "invest hundreds of millions of dollars in Fitzpatrick in January to refuel the plant and upgrade systems needed to reverse the shutdown decision." Fitzpatrick is licensed to 2034. Entergy said it plans “to move away from merchant power markets and toward a company operating exclusively as a utility in regulated markets.” Entergy has announced that Indian Point 2&3 will close in 2020 and 2021.
In October 2016 a coalition of non-nuclear energy companies and groups filed a lawsuit against the New York Public Service Commission challenging the PSC's authority to raise electricity rates to pay for the zero emission credits which will subsidize the continued operation of several nuclear power plants. The plaintiffs, led by the Coalition for Competitive Electricity, included Dynegy Inc, Eastern Generation LLC, Electric Power Supply Association, NRD Energy Inc., Roseton Generating LLC and Selkirk Cogen Partners LP. This legal challenge failed. An appeal to the Supreme Court challenging the ZEC programme was rejected in April 2019.
In February 2015 Illinois, another state with a deregulated market, took steps to enhance the competitiveness of nuclear power and renewables. The Illinois Low Carbon Portfolio Standard would require utilities to purchase low-carbon energy credits equivalent to 70% of their retail sales to customers within the state. This is congruent with the subsequent EPA Clean Power Plan. Eleven Exelon nuclear reactors at six sites supply almost half of the state’s electricity, but five of these are at risk of closure if the legislation is not enacted. In mid-2016 the legislation had lapsed. Following the failure of Illinois legislature to pass its Next Generation Energy Plan, in June 2016 Exelon said that it would move forward with plans to close down Clinton in June 2017 and Quad Cities a year later. It would terminate capital investment projects required for the long-term operation of both plants, and would immediately take one-time charges of $150 million to $200 million for 2016, and accelerate some $2 billion in depreciation and amortization. Three other Exelon plants – Dresden, Braidwood and Byron – remain at risk of early retirement.
In October 2016 Exelon confirmed that it would close the Quad Cities and Clinton plants if legislation was not passed by year end since they had lost more than $800 million in the past seven years. In November the Future Energy Jobs Bill was introduced, reflecting “a diverse set of interests, as well as agreement in important areas among environmentalists, consumer advocates, community leaders and energy companies.” A core feature of the legislation is the establishment of the Zero Emission Standard to preserve the state’s two at-risk nuclear plants, saving 4200 jobs, retaining $1.2 billion economic activity annually and avoiding increases in energy costs. The bill provides zero emission credits (ZEC) similar to those in New York – "a tradable credit that represents the environmental attributes of one megawatt hour of energy produced from a zero emission facility" such as the nuclear power plants which supply about 90% of the state’s zero-carbon electricity. The state legislature passed the bill in December 2016 and it was then signed into law. It will provide up to $235 million annually to support the two plants – 2884 MWe net – for ten years. The state utilities will purchase ZECs from the nuclear generators and collect payments from ratepayers. The legislation sets the value of a ZEC to be $16.50/MWh based on the social cost of carbon.
A legal challenge to the Illinois ZEC programme failed, but in January 2019 a coalition of power generation companies took the appeal to the Supreme Court, where it was rejected.
In February 2017 FirstEnergy announced that it was in dialogue with the Ohio state government to try to secure the future of its two nuclear plants in the state, Davis-Besse and Perry, a 894 MWe PWR and a 1256 MWe BWR respectively, owned by its subsidiary FirstEnergy Solutions (Beaver Valley just over the border in Pennsylvania is excluded). The company had earlier announced its intention to withdraw from competitive generation markets by mid-2018, and in the fourth quarter of 2016 recorded a $9.2 billion impairment charge as a result.
In October 2017 a new bill was introduced into Ohio legislature aiming to establish the Zero Emissions Nuclear (ZEN) programme to support the state's two nuclear plants. The bill stated an initial ZEC price of $17/MWh per credit. Each participating utility would be limited to purchasing one-third of its recorded 'total end user consumption' in MWh over the previous two calendar years. The bill did not proceed. A new bill with broader scope was introduced in April 2019 and establishes credits for clean power of $9.25/MWh.
FirstEnergy has 13,000 MWe of generating capacity operating in deregulated markets. It decided to relinquish all these assets by mid-2018, and withdraw from competitive generation altogether, maintaining only its generation assets in regulated markets. Due to competition from low-cost gas and subsidized wind power, the units are unlikely to be sellable if states fail to introduce legislation to provide zero emission credits. In March 2018, with the proposed Ohio bill stalled in a Senate committee, FirstEnergy filed a deactivation notice for its David-Besse and Perry plants, as well as its Beaver Valley plant in Pennsylvania. The deactivation notice set retirement dates of 2020 for Davis-Besse, and 2021 for Perry and Beaver Valley. FirstEnergy stated that it will continue to work with officials from the two states, and called on them to consider policy solutions to prevent early closure of the assets. Developments are expected in 2019.
In March 2017 Connecticut’s Energy & Technology Committee approved a bill supporting the continued operation of Dominion’s 2198 MWe Millstone plant in that deregulated market. The bill "would expand the state's existing renewable electricity procurements to nuclear power by directing state regulators to solicit up to half of the facility's annual generation (i.e. 8.3 TWh) for five-year power purchase agreements.” In October 2017, Connecticut's legislature passed the bill, supporting the continued operation of Millstone. After a 23:8 Senate vote, the lower house passed the bill 75:66. It will make Dominion eligible to bid for long-term supply contracts for up to half of Millstone's output as a clean-energy resource, at higher prices, subject to the state Department of Energy and Environmental Protection and Public Utilities Regulatory Authority determining that this is in the public interest. The plant is the largest in New England and its viability has been eroded by cheap natural gas. Closure of the plant, which provides half of the state's power and almost all of its zero-carbon power, would jeopardize the state's ability to meet its long-term goals for reducing carbon emissions. In December 2018, the Public Utilities Regulatory Authority agreed that the Millstone nuclear plant was at risk, allowing it to take part in zero-emission energy auctions. In March 2019 the plant obtained a 10-year contract for 9 TWh per year with two utilities. The two units operating at Millstone – units 2&3 – are licensed to 2035 and 2045.
In March 2017 Kentucky voted to end its moratorium on nuclear power in the state.
In March 2017 Pennsylvania set up a bipartisan, bicameral nuclear energy caucus to secure the role of nuclear energy in the state, where it provided 37% of the electricity and contributes $2.3 billion to the state GDP. There are several two-unit nuclear power plants in the state: Beaver Valley, Limerick, Peach Bottom and Susquehanna, plus Three Mile Island. Exelon said that the 890 MW Three Mile Island unit 1 "remains economically challenged as a result of continued low wholesale power prices and the lack of federal or Pennsylvania energy policies that value zero-emissions nuclear energy." It is set to close if no ZEC-type relief is forthcoming since it has been running at a loss for five years, and Exelon specified September 2019 as the provisional date for this.
A draft law updating the Pennsylvania Alternative Energy Portfolio Standards Act to include nuclear energy was introduced to the state's legislature in March 2019. Nuclear power plants generate 42% of its electricity and 93% of its zero-carbon power but are excluded from the AEPS programme. The Keep Powering Pennsylvania Act would offer subsidies to nuclear plants and was put forward as costing $500 million per year, significantly less than the cost if economically-challenged plants were to close. Plants applying to join the programme need to agree to operate for at least six years.
In April 2018, New Jersey legislators passed bills establishing a ZEC programme which was drafted by the state’s Board of Public Utilities in November with a decision due in April 2019. The programme is to be funded by a 0.4 c/kWh tariff imposed on retail distribution customers. The bill requires plants to be licensed to operate until at least 2030, so excluded Exelon’s Oyster Creek. Public Service Enterprise Group (PSEG), which operates the state's other reactors at Hope Creek and Salem plants, had previously warned that closures were likely without intervention. In April 2019 PSEG said that it needed a ZEC subsidy for the two plants – total 3.7 GWe – to remain in operation beyond 2020. The government expects that the two plants will receive about $253 million per year in revenue from ZEC sales to public utilities, apparently at around $10-11/MWh. The Oyster Creek plant (619 MWe net) closed in September 2018.
In June 2017 MIT's Center for Energy and Environmental Policy Research published a new study that found that saving US nuclear "would come at a cost of $4-7/MWh on average in these markets, which is much lower than the cost of subsidizing wind power." The current production tax credit (PTC) level for renewables is $23/MWh.
Using its legislated authority for the first time since 1979, in September 2017 the Department of Energy (DOE) directed the Federal Energy Regulatory Commission (FERC) through a notice of proposed rulemaking (NOPR) to ensure that the country's "diverse mix of resources must include traditional base-load generation with onsite fuel storage that can withstand major fuel supply disruptions caused by natural and man-made disasters." The DOE said that FERC had so far “not done enough to address the crisis at hand” caused by the premature retirement of reliable plants. "Immediate action is necessary to ensure fair compensation in order to stop the imminent loss of generators with onsite fuel supplies, and thereby preserve the benefits of generation diversity and avoid the severe consequences that additional shutdowns would have on the electric grid," the DOE said in the NOPR. In particular, “the continued loss of base-load generation with onsite fuel supplies, such as coal and nuclear, must be stopped."
In January 2018 FERC halted the NOPR and called on operators of regional wholesale markets to "provide information as to whether the FERC and the markets need to take additional action on resilience of the bulk power system." This removed the built-in incentives for coal and nuclear plants outlined in the September NOPR which would have required independent system operators and regional transmission organizations "to ensure that certain reliability and resiliency attributes of electric generation resources are fully valued." In particular, it stated that eligible "fuel-secure generation units", which are frequently relied upon for grid reliability and resilience, must be able to fully recover their costs.
The USA has a patchwork of grids which are often barely interconnected. The Western Interconnection includes about 11 states plus British Columbia and Alberta. ERCOT includes most of Texas, and Eastern Interconnection takes in the rest of the USA and Canada. There is very little grid capacity in the middle of the country. Exelon has temporarily curtailed off-peak output at one or more of its nuclear plants in Illinois numerous times for more than a year to late 2016 because of grid constraints. The company has previously said intermittent grid congestion has been occurring in the region around those plants because of transmission line outages for scheduled maintenance, large influxes of wind-generated power into the grid during off-peak hours, or a combination of those factors.
There is an evident need for major investment, and in August 2017 the DOE Staff Report to the Secretary on Electricity Markets and Reliability recommended that the Federal Energy Regulatory Commission (FERC) take a leading role in ensuring effective grid connections to meet base-load demand more widely and reliably. See above section on Department of Energy rulemaking.
More information on the US grid situation is in the information paper on Electricity Transmission Grids.
The US nuclear power industry has undergone significant consolidation in recent years, driven largely by economies of scale, deregulation of electricity prices and the increasing attractiveness of nuclear power relative to fossil generation. As of the end of 1991, a total of 101 individual utilities had some (including minority) ownership interest in operable nuclear power plants. At the end of 1999, that number had dropped to 87, and the largest 12 of them owned 54% of the capacity. With deregulation of some states' electricity markets came a wave of mergers and acquisitions in 2000-1 and today the top 10 utilities account for more than 70% of total nuclear capacity. The consolidation has come about through mergers of utility companies as well as purchases of reactors by companies wishing to grow their nuclear capacity.
In respect to the number of operators of nuclear plants, this dropped from 45 in 1995 to 25 in about 2010, showing a substantial consolidation of expertise.
Most of the of nuclear generation capacity involved in consolidation announcements has been associated with corporate mergers, some of which failed due to regulatory opposition. Another means of consolidation has been via management contracts, and other means of management rationalisation for single-unit plants have also occurred. Details are in Appendix 2: Power Plant Purchases.
In the 12 years from 1998, there were 20 reactor purchase deals involving 25 plants, usually in states where electricity pricing had been deregulated (see Nuclear Power in the USA Appendix 2: Power Plant Purchases). The plants acquired were often those with high production costs, offering the potential for increased margins if costs could be reduced. Of the 5,900 MWe involved to mid-2000, half was associated with plants having 1998 production costs above 2.0 cents per kWh. Sellers tended to consider the higher-cost plants as potential liabilities and were willing to get rid of them for a fraction of their book value, whereas the larger utility buyers considered the plants to be potential assets, depending only on their ability to lower the production costs. In many cases, large power companies acquired plants from local utility companies and at the same time entered contracts to sell electricity back to the former owners. Entergy Corporation, for example, bought two reactors from New York Power Authority in 2000 and agreed to make the first 500 MWe of combined output available at 2.9 cents/kWh and the remainder at 3.2 or 3.6 cents/kWh.
Along with Exelon, Entergy is a prominent example of the consolidation that occurred. Originally based in Arkansas, Louisiana, Mississippi and eastern Texas, Entergy doubled its nuclear generation capacity over 1999 to 2007 with the acquisition of reactors in New York, Massachussets, Vermont and Michigan, as well as a contract to operate a nuclear plant in Nebraska. Other companies that have increased their nuclear capacity through plant purchases are FPL Group based in Florida (four units), Constellation Energy based in Maryland (three units, since merged with Exelon) and Dominion Resources based in Virginia (two units).
However, some older plants acquired from their original owners for their value as ‘cash cows’ are now unprofitable in deregulated markets and threatened with closure due to the very low prices of natural gas. In addition, onerous safety requirements following the Fukushima accident compound the economic challenges with already tight NRC regulations. See comments above regarding some Exelon and Entergy plants in deregulated markets.
A decrease of 5,709 MWe, due to the premature shutdown of eight reactors, due to their having high operating costs.
A net increase of 6,223 MWe, due to changes in power ratings.
An increase of 3,470 MWe due to the start-up of two new reactors (Comanche Peak 2, Watts Bar 1) and the restart of one unit (Browns Ferry 1).
The Shaw Group has undertaken about half of the uprates so far, and early in 2010 it said that companies are planning more uprate projects and aiming for bigger increases than in the past. It perceived a $25 billion market.Further uprate projects are in sight, many being $250 to $500 million each.
The largest US nuclear operator, Exelon, has plans to uprate much of its reactor fleet to provide the equivalent of one new power plant by 2017 – some 1,300-1,500 MWe, at a cost of about $3.5 billion. The company has already added 1,100 MWe in uprates over the decade to 2009. In addition to increasing power, many of the uprates involve component upgrades. These improve the reliability of the units and support operating licence extensions (see below),which require extensive review of plant equipment conditiond.
Florida Power & Light added 450 MWe in uprates to four reactors over 2011-13: 12% for St Lucie 1&2, and 15% for Turkey Point 3&4.
A significant achievement of the US nuclear power industry over the last 20 years has been the increase in operating efficiency with improved maintenance. This has resulted in greatly increased capacity factor (output proportion of their nominal full-power capacity), which has gone from 56.3% in 1980 and 66% in 1990 to 91.1% in 2008. A major component of this is the length of refuelling outage, which in 1990 averaged 107 days but dropped to 40 days by 2000. In 2017 the average refuelling outage was 35 days. The record is now 15 days. In addition, average thermal efficiency rose from 32.49% in 1980 to 33.40% in 1990 and 33.85% in 1999.
All this is reflected in increased output even since 1990, from 577 billion kilowatt hours to 809 billion kWh, a 40% improvement despite little increase in installed capacity, and equivalent to 29 new 1,000 MWe reactors.
The Nuclear Regulatory Commission (NRC) is the government agency established in 1974 to be responsible for regulation of the nuclear industry, notably reactors, fuel cycle facilities, materials and wastes (as well as other civil uses of nuclear materials).
In an historic move, the NRC in March 2000 renewed the operating licences of the two-unit Calvert Cliffs nuclear power plant for an additional 20 years. The applications to NRC and procedures for such renewals, with public meetings and thorough safety review, are exhaustive. The original 40-year licences for the 1970s plants were due to expire before 2020, and were always intended to be renewed in 20-year increments.
In March 2019 the NRC renewed the licence for Seabrook, extending the unit’s operation by 20 years to 2050. This took the number of US power reactors that have renewed their licences to 94, four of which have since shut down. Another four licence renewal applications are pending. Hence, almost all of the US power reactors are likely to have 60-year operating lifetimes, with owners undertaking major capital works to upgrade them at around 30-40 years. The licence renewal process typically costs $16-25 million, and takes several years for review by the NRC.
The original 40-year period was more to do with amortisation of capital than implying that reactors were designed for only that operational lifespan. It was also a conservative measure, and experience since has identified life-limiting factors and addressed them. The NRC is now considering extending operating licences beyond 60 out to 80 years, with its subsequent licence renewal (SLR) programme. At the end of January 2018, Florida Power & Light submitted the first application by a US utility seeking a second licence renewal (to 80 years) for Turkey Point 3&4. In July 2018 Exelon submitted an application seeking a second licence renewal for its Peach Bottom nuclear plant (units 2&3) and in December 2018 Dominion applied for its two Surry reactors. It had earlier advised the NRC of its intention to apply for North Anna's two reactors in 2020. The Nuclear Energy Institute surveyed utilities in 2017 and found that about 20 nuclear power plants envisaged a second licence extension, but did not say how many reactors this involved.
The licence extensions to 60 years mean that major mid-life refurbishing, such as replacement of steam generators and upgrades of instrument and control systems*, can be justified. By 2017, 56 out of 65 US PWRs had replaced their original steam generators with more durable ones, involving a three-month outage. About 45 PWRs have also replaced reactor pressure vessel heads, mostly by 2010**, and BWRs may need to replace core shrouds. The owners of Davis Besse invested almost $1 billion for its mid-life refurbishment to take it to 2037. While active plant components such as pumps and valves are under continuous scrutiny for operability, passive components need to be assessed for ageing which may have weakened them. There are robust R&D programmes focusing on this run by DOE, EPRI and ASME.
* All US operating plants originally had analogue control systems. Duke Energy converted its three Oconee units to digital control systems over 2011-13.
** at about $150 million each in 2015 dollars, mostly due to corrosion cracking.
Beyond licence renewal to 60 years, some 55 GWe of new nuclear capacity will be needed by 2035 to maintain 20% nuclear share of generation if the current fleet is retired at 60 years. In total, 432 GWe of US generating capacity is 30-50 years old and 60 GWe of coal-fired capacity is expected to be retired by 2020 largely for environmental reasons.
The NRC has a new oversight and assessment process for nuclear plants. Having defined what is needed to ensure safety, it now has a better-structured process to achieve it, replacing complex and onerous procedures which had little bearing on safety. The new approach yields publicly-accessible information on the performance of plants in 19 key areas (14 indicators on plant safety, two on radiation safety and three on security). Performance against each indicator is reported quarterly on the NRC website according to whether it is normal, attracting regulatory oversight, provoking regulatory action, or unacceptable (in which case the plant would probably be shut down).
On the industry side, the Institute of Nuclear Power Operations (INPO) was formed after the Three Mile Island accident in 1979. A number of US industry leaders recognised that the industry must do a better job of policing itself to ensure that such an event should never happen again. INPO was formed to establish standards of performance against which individual plants could be regularly measured. An inspection of each member plant is typically performed every 18 to 24 months.
Following the Fukushima accident in 2011 which was exacerbated by inadequate outside assistance to the flooded reactors, the US nuclear industry has set up the FLEX accident response strategy. It has 61 centres across the country and two national centres which together provide the capacity to respond to nuclear power plant accidents anywhere in the country within 24 hours.
Today the importance of nuclear power in USA is geopolitical as much as economic, reducing dependency on oil and gas. The operational cost of nuclear power in existing plants is very competitive with alternatives. In 2012 it was 2.4 ¢/kWh, compared with gas 3.4 ¢/kWh and coal 3.3 ¢/kWh. But plans for new nuclear capacity are starting to take account of opportunities for small reactors as well as large ones.
From 1992 to 2005, some 270,000 MWe of new gas-fired plant was built, and only 14,000 MWe of new nuclear and coal-fired capacity came on line. But coal and nuclear supply almost 70% of US electricity and provide price stability. When investment in these two technologies almost disappeared, unsustainable demands were placed on gas supplies and prices quadrupled, forcing large industrial users of it offshore and pushing gas-fired electricity costs towards 10 ¢/kWh. Today, due to the advent of shale gas, costs are much lower.
The reason for investment being predominantly in gas-fired plant was that it offered the lowest investment risk. Several uncertainties inhibited investment in capital-intensive new coal and nuclear technologies. About half of US generating capacity is over 30 years old, and major investment is also required in transmission infrastructure. This creates an energy investment crisis which was recognised in Washington, along with an increasing bipartisan consensus on the strategic importance and clean air benefits of nuclear power in the energy mix.
The Energy Policy Act 2005 then provided a much-needed stimulus for investment in electricity infrastructure including nuclear power. New reactor construction got under way from 2012, with first concrete on two units in March 2013, and two more in December 2013.
Continued low gas prices depress the prospects for commitment to further construction, and it is generally considered that natural gas prices need to recover to $8/GJ or /MMBtu before there is renewed confidence in deregulated states. In regulated states, a longer-term outlook is possible. Small modular reactors provide possible relief from major upfront finance burdens, but these are some way off having design certification from the NRC.
There are three regulatory initiatives which in recent years have enhanced the prospects of building new plants. First is the design certification process, second is provision for early site permits (ESPs) and third is the combined construction and operating licence (COL) process (‘Part 52’) as an alternative to the ‘Part 50’ two-step process of construction permit followed by operating licence. All have some costs shared by the DOE.
B&W PWR (partly built) 2 x 1263 Nuclear Development LLC (sale pending from Tennessee Valley Authority) 30/10/07 for units 3&4h but COL withdrawn 2016 Seeking loan guarantee; now 2024.
Of the above, for the first four AP1000 units, construction is well underway at Vogtle, Georgia, with about $4 billion invested in the project before it was technically 'under construction'. Construction was also well underway at Summer, South Carolina, but has been put on hold – see section below.
In addition to sites listed above, Southern Company is evaluating several possible sites, including existing plants and greenfield locations, for additional AP1000 reactors.
However the economic outlook since 2013-14 suggests that merchant plants are not prospectively viable, and that some kind of assured market is necessary to underwrite the high capital costs on nuclear plants. A February 2013 white paper published by NEI addresses The Cost of New Generating Capacity in Perspective.
As part of the effort to increase US generating capacity,government and industry have worked closely on design certification for advanced Generation III reactors. Design certification by the Nuclear Regulatory Commission (NRC) means that, after a thorough examination of compliance with safety requirements, a generic type of reactor (say, a Westinghouse AP1000) can be built anywhere in the USA, only having to go through site-specific licensing procedures and obtaining a combined construction and operating licence (see below) before construction can begin. Design certification needs to be renewed after 15 years.
The GE Hitachi advanced boiling water reactor (ABWR) of1300-1500 MWe. Several ABWRs are now in operation in Japan, with more under construction there and in Taiwan. Some of these have had Toshiba involved in the construction, and more recently it has been Toshiba that promoted the design most strongly in the USA.k Both the Toshiba and the GE Hitachi versions need to have their design certification renewed from 2012, but NRC shows both as "applicant delayed, not scheduled". Toshiba withdrew its design certification renewal application in mid-2016.
The Westinghouse AP1000 is the first Generation III+ reactor to receive certificationl. It is a scaled-up version of the Westinghouse AP600 which was certified earlier. It has a modular design to reduce construction time to 36 months. The first four of many are being built in China, and four more in USA.
GE Hitachi's Economic Simplified BWR (ESBWR) of 1600 MWe gross, developed from the ABWR. The ESBWR has passive safety features and is currently included in the COL applications of two companies in USA. GE Hitachi submitted the application in August 2005, design approval was notified in March 2011, and design certification was in September 2014. The first COL with it was approved in May 2015.
The Korean APR1400 reactor, which is operating in South Korea since 2016 and under construction in the United Arab Emirates. Following 11 pre-application meetings, Korea Hydro & Nuclear Power submitted a design certification application to the NRC in October 2013. However, further detail was requested, and the revised submission was accepted by the NRC in March 2015. The final safety report was published in September 2018 and design certification is expected in May 2019.
The Mitsubishi US-APWR, a 1700 MWe design developed from that for a 1538 MWe reactor planned for Tsuruga in Japan. The application was submitted in December 2007 and certification was expected to be completed in February 2016, but Mitsubishi delayed the NRC schedule for “several years”. European certification for the almost identical EU-APWR was granted in October 2014. Two US-APWR reactors were proposed in the Luminant-Mitsubishi application for Comanche Peak, but Mitsubishi has withdrawn from this project.
The Russian VVER-1200 reactor, which is operating at Novovoronezh II and at Leningrad II, may be submitted for US design certification through Rusatom Overseas, according to Rosatom.
The US Evolutionary Power Reactor (US EPR), an adaptation of Areva's EPR to make the European design consistent with US electricity frequencies. The main development of the type was to be through UniStar Nuclear Energy, but other US proposals also involved it. The application was submitted in December 2007 and the design certification rule was expected after mid-2015, with delays due to the complexity of digital instrumentation and control systems. Areva then delayed the NRC schedule and in March 2015 indefinitely suspended the application. The 1600 MWe EPR is being built in Finland, France, and Guangdong in China, and is planned for UK.
A demonstration unit of the 160 MWe Holtec SMR-160 PWR (with external steam generator) is proposed at Savannah River with DOE support, and a construction permit application is likely, or a similar application in Canada. In September 2016 Mitsubishi Electric Power Products and its Japanese parent became a partner in the project, to undertake the I&C design and help with licensing. In 2017 SNC-Lavalin joined the project. South Carolina and NuHub also back the proposal.
A demonstration unit of the NuScale multi-application small reactor, a 50 MWe integral PWR planned for the Idaho National Laboratory. Subsequent deployment of 12-module power plants in western states is envisaged under the Western Initiative for Nuclear. The NRC accepted NuScale's design certification application in 2017 and a COL application is planned for mid 2020. Nuscale had spent some $170 million on licensing to mid-2015, and expects the NRC review to take 40 months, with the first unit operating in the mid-2020s. In 2013 NuScale secured up to $226 million DOE support for the design, and applied for the second part of its loan guarantee in September 2017. Further details under the section on UAMPS below.
SCEG is evaluating the potential of X-energy’s Xe-100 pebble-bed SMR (50 MWe, a high temperature gas-cooled reactor) to replace coal-fired plants, in 200 MWe ‘four-pack’ installations.
In August 2015 Russia's AKME-Engineering received a US patent for its modular SVBR-100 lead-bismuth cooled integral fast reactor. The company said that it wanted to protect its intellectual property as it prepared for the construction of a prototype SVBR-100 unit at Dimitrovgrad. However the project was then abandoned in 2018.
In February 2014 the NRC said that its most optimistic scenario for awarding design certification for small reactors such as SMRs was 41 months, assuming they were light water types (PWR or BWR).
A fuller account of new reactor designs, including those certified but not marketed in the USA, is in the information page on Advanced Nuclear Power Reactors, or for the small modular reactors, in the page on Small NuclearPower Reactors.
The 2001 early site permit (ESP) program attracted four applicants: Exelon, Entergy, Dominion and Southern, for Clinton,Grand Gulf, North Anna and Vogtle sites respectively – all with operating nuclear plants already but room for more. In March 2007, Exelon was awarded the first ESP for its Clinton plant in Illinois, after 41 months' processing by the NRC and public review. The NRC then awarded ESPs to Entergy for its Grand Gulf site, Dominion for North Anna, and Southern for Vogtle. No plant type is normally specified with an ESP application, but the site is declared suitable on safety, environmental and related grounds for a new nuclear power plant. The last three of these 2001 ESPs were replaced by COL applications.
In March 2010, Exelon applied for an ESP for its Victoria County, TX, site and withdrew the COL application for that project. In 2012 it withdrew the ESP application. PSEG Nuclear lodged an application for an ESP for a new reactor at its Salem/Hope Creek site on the Delaware River in New Jersey in May 2010, and this was granted in May 2016.
The seventh ESP application was for small reactors. The Tennessee Valley Authority (TVA) submitted an ESP application to the NRC for its Clinch River small reactor project (for four units) in May 2016. The application was based on a plant parameter envelope encompassing the light-water SMRs currently under development in the USA by BWX Technologies, Holtec, NuScale Power and Westinghouse. It envisages that the emergency planning zone need extend only to the plant boundary. TVA then plans to submit a combined licence application with a view to building up to 800 MWe of capacity there. The DOE is supporting TVA's ESP application, and the NRC expects to complete its review of it by August 2019.
In 2003, the Department of Energy (DOE) called for combined construction and operating licence (COL) proposals under its Nuclear Power 2010 program on the basis that it would fund up to half the cost of any accepted. The COL program has two objectives:to encourage utilities to take the initiative in licence application, and to encourage reactor vendors to undertake detailed engineering and arrive at reliable cost estimates. For the first,DOE matching funds of up to about $50 million are available, and for the second, up to some $200 million per vendor, to be recouped from royalties.
Several industry consortia were created for the purpose of preparing COL applications for new reactors. By mid-2009, COL applications for 26 new units at 17 sites had been submitted to the Nuclear Regulatory Commission. A summary of submitted and expected applications is given in the Table above (New US nuclear power reactors), and further information is given in Nuclear Power in the USA Appendix 3: COL Applications.
However, the only construction of new plants in the short term is in regulated markets, where costs can reliably be recovered.
Several companies have ordered heavy forgings and other long lead time equipment for building new plants, in advance of specific plans or approvals. Some have even proceeded to full engineering,procurement and construction (EPC) agreements while the relevant COL applications are being processed, thus indicating a strong probability of actually building the plants concerned. These are indicated in the above Table and further details are given in Nuclear Power in the USA Appendix 3: COL Applications.
The Energy Policy Act (EPA) of 2005 introduced a production tax credit (PTC) of 1.8 cents per killowatt hour of electricity produced by new nuclear plants. The tax credit is available only for the first 6000 MWe of new nuclear capacity, and lasts only for the first eight years of operation. Companies cannot claim the PTC until assets begin generating electricity.
For further discussion see information page on US Nuclear Power Policy.
While the focus is on new technology, TVA undertook a detailed feasibility study which led to its decision in 2007 to complete unit 2 of its Watts Bar nuclear power plant in Tennessee. The 1165 MWe (net) reactor was expected to start up in October 2012 and come online in 2013 at a cost of about $2.5 billion, but this schedule slipped substantially, with major budget overrun to $4.7 billion. Construction had been suspended in 1985 when 80% complete and (after parts were cannibalized to reduce that figure to 61%) resumed in October 2007 under a still-valid permit. The construction permit has been extended to September 2016, and in October 2015 TVA received a 40-year operating licence from NRC. Grid connection was early in June and commercial operation commenced in October 2016. Its twin, unit 1, started operation in 1996.
Completing Watts Bar 2 utilized an existing asset, thus saving time and cost relative to alternatives for new base-load capacity. It was expected to provide power at 4.4 ¢/kWh, 20-25% less than coal-fired or new nuclear alternatives and 43% less than natural gas. It is a regulated plant, with guaranteed cost recovery.
In 2014, before start-up, TVA ordered new steam generators for the unit and plans to change them over after 7-10 years operation. The early 1980s ones are made of an alloy that is prone to stress corrosion cracking. Those in unit 1 were replaced after nine years of operation, and the vast majority of US PWRs have had replacements. In 2017 unit 2 was shut down for five months to replace a condenser that failed.
Westinghouse filed for chapter 11 bankruptcy reorganization on 29 March 2017, after struggling to find cash to fund growing cost overruns at its two US nuclear plant projects (see below). The company listed assets of $4.3 billion and liabilities of $9.4 billion in the filing, and asked permission to pay about $50 million in employee salaries and benefits as well as $87.3 million to critical vendors during bankruptcy proceedings. Westinghouse and 30 affiliated companies filed for bankruptcy protection, listing about 35,000 creditors involved. Westinghouse said that its operations in Asia, Europe, the Middle East and Africa are not affected by the bankruptcy filings. Interim financing of $800 million was provided by Westinghouse parent company Toshiba and a New York private equity company, Apollo Capital Management. Toshiba said that it anticipated a new entity to be found by Westinghouse would take a leading role in bringing that company out of bankruptcy, and that its own control of Westinghouse had ended.
Westinghouse said its largest creditors were US construction company Fluor Enterprises – which was brought into the US nuclear plant projects in 2015 to take over construction management, and Chicago Bridge & Iron – in connection with the acquisition by Westinghouse of CB&I’s Stone & Webster construction business in late 2014. Fluor is owed almost $194 million, and CB&I is owed $145 million. In March Toshiba said it would not provide additional funding without collateral, according to the bankruptcy protection filing. That resulted in the development of the debtor-in-possession financing, under which Westinghouse will fund continuing operations. Westinghouse said it will work with the several owners of the nuclear plant projects in Georgia and South Carolina to “explore the continued feasibility of those projects in a manner that is cost-neutral and cash-neutral" to Westinghouse and its affiliates. Those owners of the Vogtle and Summer plants agreed to pay costs to continue construction themselves for a transition and evaluation period while final arrangements on future plant work were developed. The continued involvements of Westinghouse in the projects “remains uncertain”.
Westinghouse said that it remains committed to the AP1000 technology and will continue to support plants being built in China, and planned for China, USA, India, Turkey, the UK and elsewhere. Its nuclear fuel business had revenues of $1.48 billion in fiscal 2015 (to end March 2016), and its operating plant business had revenues of $1.65 billion in the same period, while the new nuclear plant services business lost money.
In April 2008, Georgia Power signed an EPC contract with Westinghouse and The Shaw Group (now CB&I) consortium for two 1200 MWe Westinghouse AP1000 reactors which will be licensed and operated by Southern Nuclear Operating Company (SNOC). Both Georgia Power and SNOC are subsidiaries of Southern Company. JSW in Japan sent forged components to Doosan in South Korea for fabrication. The COL was issued by the NRC in February 2012. Construction start (first concrete) was delayed to late 2012, and then to March 2013, after NRC issued a licence amendment allowing use of a higher-strength concrete that permits the company to pour the foundation of the new reactors without making additional modifications to reinforcing steel bar. At that point ten million working hours had been invested on the site. Shaw (now CB&I) agreed with China's State Nuclear Power Technology Corporation (SNPTC) to deploy engineers with experience in building China's AP1000 units to provide technical support. Following early delays, construction of unit 3 started in March 2013 and unit 4 in November. Fluor joined the project as construction manager in January 2016, taking over part of the CB&I role, and in January 2017 Bechtel became involved with the nuclear islands. The units were expected online late in 2019 and September 2020. It is a regulated plant, with guaranteed operational cost recovery.
Reactor pressure vessels and steam generators are from Doosan in South Korea.
Georgia Power as 45.7% owner reduced its earlier cost estimate for building its share of the new plant from $6.4 billion to $6.1 billion as a result of being able to recover financing costs from customers during construction, but this increased to $6.2 billion in 2012 due to delays. Over the life of the plant, the utility's customers will save about $1 billion through federal loan guarantees, production tax credits and the early recovery of financing costs in the rate base. The Georgia Public Service Commission in February 2013 approved Georgia Power's costs for the project and said that the project "remains more economically viable than any other [energy] resource, including a natural gas-fired alternative."
The initial cost estimate for the project was $14 billion. Delays to mid-2014 resulted in a cost increase of $381 million but this was offset by lower interest rates than budgeted. When further delays were announced in January 2015, the company said that cost escalation was about $10 million per month plus financing cost of about $30 million per month. Minority equity in the project is held by Oglethorpe Power (30%), the Municipal Electric Authority of Georgia – MEAG Power (22.7%), and Dalton city (1.6%).
In mid-April 2017 Westinghouse said that about $1.5 billion was required to complete the construction of both units, though other estimates are higher. In June Toshiba agreed with the owners that its liability under its 2008 parental guarantee would be capped at $3.68 billion for the completion of the Vogtle units. The sum is part of an $8.9 billion provision in Toshiba’s accounts announced in mid-May, covering all four US reactors.
In mid-May 2017 Georgia Power announced that from June, Southern Nuclear Operating Company (SNOC) would take over project management to complete the Vogtle units, leaving Westinghouse simply as the vendor, though supporting EPC and licensing as well as providing access to intellectual property. Southern said that productivity at the site had improved significantly in 2017, with the reactors now two-thirds complete. SNOC will also be the operator. The company said it would "take all actions necessary to hold Westinghouse and Toshiba accountable for their financial obligations."
After a review of options and contingencies, at the end of August 2017 Georgia Power, supported by the co-owners, recommended to the state public services commission (PSC) that construction of both units should be completed, this being the most economic choice for customers. The total rate impact of the project remains less than originally estimated, it said. The recommendation was unanimously approved by the PSC in December 2017.
At the same time Georgia Power announced it had contracted with Bechtel to manage daily construction efforts under the direction of SNOC. Bechtel has been involved with the project since January, correlated with “a marked increase in productivity” providing “every indication that we can do a better job than Westinghouse alone as we move forward to complete the project." Vogtle 3&4 would begin commercial operation in November 2021 and November 2022 respectively, under a new construction schedule.
Georgia Power (45.7% owner) said it had invested about $4.3 billion in capital costs in the project to June 2017 and in August 2018 announced that it had revised its forecast for the cost of its 45% share of the project up to $8.4 billion. The estimated total price for the project at that time was then expected to be $18.7 billion.
In May 2008, South Carolina Electricity & Gas (SCANA subsidiary) and state-owned Santee Cooper signed an EPC contract with Westinghouse and the Shaw Group (now CB&I) consortium for two 1200 MWe Westinghouse AP1000 reactors. The total forecast cost of $9.8 billion included inflation and owners' costs for site preparation, contingencies and project financing, though the last was reduced and the total estimated in April 2012 was $9.2 billion. In October 2014 the cost was estimated at over $11 billion, and in 2015 SCEG amended the EPC contract to choose a fixed price option for completion of the units. In November 2016 the state public service commission agreed for SCEG’s 55% share to be $7.66 billion, excluding financing, with the company’s return on equity reduced to 10.25%. "These delays and related cost increases are principally due to design and fabrication issues associated with the production of submodules used in construction of the units," according to SCANA. Fluor joined the project as construction manager in January 2016, taking over the CB&I role. In February 2017 the anticipated completion dates for the two units were April 2020 and December 2020.
The COL was issued by the NRC at the end of March 2012, and construction of unit 2 commenced in March 2013, with first main concrete. That for unit 3 was in November 2013. (In September 2011 SCEG had started to assemble the containment vessel for the first unit – 43 mm thick, from Chicago Bridge & Iron – and was starting construction on the four low-profile forced-draft cooling towers.) Reactor pressure vessels and steam generators are from Doosan in South Korea. A crane capable of lifting 6800 tonnes is installed onsite, though the heaviest component was 1550 tonnes. The units were expected to enter commercial operation late in 2019 and late in 2020. SCEG's loan guarantee application was accepted by the DOE and the project was short-listed in May 2009, though nothing has happened since then. It is a regulated plant, with guaranteed operational cost recovery.
In 2014 it was announced that SCEG’s stake in the project would be increased to 60% by acquisition of 5% from Santee Cooper after the plant starts up, for about $500 million, leaving it with 40%. Duke Energy Carolinas had been seeking up to 10% of the project from Santee Cooper, but this plan was dropped in January 2014.
Following Westinghouse filing for Chapter 11 protection from creditors in March 2017, SCANA reviewed the project and initially expected resources from Westinghouse and Toshiba – including a so-called parental guarantee from Toshiba – to be adequate to compensate for the additional costs. These, together with a surety bond and an escrow of AP1000 intellectual property and software, were considered. SCANA and Santee Cooper had intended to take over project management to complete the Summer units, leaving Westinghouse simply as vendor, though supporting EPC and licensing as well as providing access to intellectual property, as with Vogtle. In mid-April Westinghouse told SCANA that about $1.5 billion was required to complete construction of both units – $829 million more than it was entitled to charge under the EPC contract, but less than the liability amount for it and Toshiba for breach of EPC contract. SCE&G and Santee Cooper reached agreement with Westinghouse and Toshiba to settle for $2.168 billion. Of this $1.192 billion will go to SCE&G for its 55% ownership of the project, with $976 million to Santee Cooper, which owns 45%. Analysis of detailed schedule and cost data provided by Westinghouse and EPC subcontractor Fluor showed unit 2 would not be completed until December 2022 and unit 3 not before March 2024 – four years after the most recent completion date provided by Westinghouse. The overall project was 64.1% complete at the end of March 2017, and "about two-thirds" complete in July.
At the end of July Santee Cooper decided to halt construction in the light of “significant challenges” in completing the two reactors, notably uncertain costs, the uncertain availability of production tax credits, and reduced demand forecast. Also "the current political landscape has reduced the urgency for emissions-free base-load generation." It found that completing the project would cost the company $8 billion plus about $3.4 billion in interest, with schedule delays contributing to the increased interest. It had already spent $4.7 billion on construction and interest to date for its 45% share of the project. SCE&G had been evaluating options, including completion of only one unit, but concluded that completion of both units would be “prohibitively expensive” – about $9.9 billion for its 55% share of the project. SCANA said that completing only unit 2 would have resulted in a combined cost that was less than that previously approved by the South Carolina Public Services Commission under the fixed price option for completing the two nuclear units, but Santee Cooper’s decision ruled this out. “Ceasing work on the project was our least desired option, but this is the right thing to do at this time," and would accordingly apply to the state public services commission to permit this and allow it to recover from ratepayers about $4.9 billion it has spent.
Santee Cooper said that during the project wind-down it will continue to investigate the potential for federal support or "additional partners" that might make the project economic, and SCE&G echoed this. The state government then considered trying to sell Santee Cooper or take other action to revive the project, and SCE&G said in mid-August that it would withdraw its petition to the state public services commission, to allow for possible new partners. Duke Energy said it was not interested.
Westinghouse said: "The South Carolina economy is sure to feel the negative impact of losing over 5000 high-paying, long-term jobs, as well as not having available the reliable, clean, safe and affordable energy these units would provide. Also, at a time when other nuclear plants are being retired, the US energy sector is sure to feel the stunting impact of walking away from these two nuclear units."
In September 2017 the state governor released a report written 18 months earlier by Bechtel, highlighting eight significant contractual and management problems that required resolution*. The report detailed numerous recommendations, but suggested that the most important step for the consortium was to create a new "more achievable" project schedule.
Later in September 2017, SCANA and its subsidiaries received a federal subpoena for a broad range of documents related to the Summer plant expansion.
While the consortium's engineering, procurement and construction plans and schedules are integrated, the plans and schedules are not reflective of actual project circumstances.
The consortium lacks the project management integration needed for a successful project outcome.
There is a lack of a planned vision, goals and accountability between the owners and the consortium.
The contract does not appear to be serving the owners or the consortium particularly well.
The detailed engineering design is not yet completed, which will subsequently affect the performance of procurement and construction.
The issued design is often not constructible, resulting in a significant number of changes and causing delays.
The oversight approach taken by the owners does not allow for real-time, appropriate cost and schedule mitigation.
The relationship between the consortium partners (Westinghouse Electric Company and Chicago Bridge & Iron) is strained, caused to a large extent by commercial issues.
Tennessee Valley Authority had a pair of uncompleted 1213 MWe PWR reactors: Bellefonte 1&2. Construction on these units was abandoned in 1988 after $2.5 billion had been spent and unit 1 largely (88%) completed and unit 2 about 58% completed. In February 2009, the NRC reinstated the construction permits for these (and later the status of the reactors classified as 'deferred'). Today unit 1 is considered no more than 55% complete due to the transfer or sale of many components and the need to upgrade or replace others, such as the instrumentation and control systems, reactor pressure vessel, steam generators and main condenser tubing. In August 2011 TVA opted to complete unit 1 at a cost of about $4.9 billion rather than building a new AP1000 reactor as unit 3* (see Appendix 3: COL Applications). TVA then asked the NRC in 2011 to defer consideration of its COL for units 3&4 (AP1000 option), and in February 2016 it withdrew the COL application.
* In August 2010, TVA had committed to spending $248 million in the year to September 2011 towards work at Bellefonte8 and an engineering contract was awarded to Areva SA in October 2010 for work on unit 1, including engineering, licensing and procurement of long-lead materials in support of a possible start-up date in the 2018-19 timeframe. Following TVA's 2011 decision to proceed, the Areva contract included construction and component replacement work on the plant's nuclear systems, a digital instrumentation and control (I&C) system, a modernized control room, a plant simulator for personnel training plus fuel design and fabrication. Areva contracts amounted to some $1 billion, with heavy construction to start when Watts Bar 2 was completed. In late 2013 TVA revised the estimated cost to $7.4 to $8.7 billion.
However, TVA’s 20-year integrated resource plan in 2015 did not have Bellefonte 1&2 as a firm prospect, and it projected 2028 completion of unit 1 as having the effect of increasing system costs. Later in 2015 the company said it would defer consideration of completing unit 1 for a decade. In May 2016 the TVA board decided to offer the plant for sale at auction, and in November Nuclear Development LLC agreed to buy it for $111 million.
Nuclear Development said it intended to invest up to $13 billion from 2017 to complete the plant, and it was lobbying for a $5 billion loan guarantee. Bellefonte is a regulated plant, with guaranteed cost recovery. In mid-2018 the company signed an agreement with SNC-Lavalin to finish building the plant once the purchase is completed. Completion of unit 1 was then anticipated in 2024.
Duke Energy lodged a COL application in December 2007 for two Westinghouse AP1000 units for its William States Lee III plant at a new site near Charlotte in Cherokee County, South Carolina, to provide power for North Carolina. The company was seeking a loan guarantee and was considering regional partnerships to build the plant. The environmental review for NRC was completed in December 2013, showing no problems, the safety evaluation review was completed in August 2016 and the COLs issued in December 2016. Duke told NRC in 2012 that it was revising its COL application to move the nuclear island of both Lee units by some 20 metres to make excavation and construction easier. Duke had spent $471 million on licensing, planning and pre-construction activities for the plant to February 2016. If proceeding, the 1117 MWe (net) units were then expected online in 2024 and 2026. In August 2017 the company announced: "The risks and uncertainties to initiating construction on the Lee nuclear project have become too great, and cancellation of the project is the best option for customers." It is seeking approval from the North Carolina Utilities Commission to cancel the project, while maintaining its licence to build at the site in the future.
NextEra Energy subsidiary Florida Power & Light (FPL) applied in June 2009 for a COL for two Westinghouse AP1000 reactors at Turkey Point in Florida where two 693 MWe PWR units (3&4) are operating and were uprated in 2012-13. (Unit 5 is a 1190 MWe combined cycle gas plant; units 1&2 are 400 MWe oil/gas units.) In 2011 the Florida Public Service Commission approved a levy towards construction of the reactors, and in May 2014 the state government approved the project, with new transmission lines.
The NRC safety review was scheduled to be completed late in 2013, and the NRC website early in 2015 showed COL completion early in 2017. FPL will then make a decision about proceeding. The company said in April 2014 that it expected to start operation of the first new unit in June 2022 and the second a year later, but in January 2015 changed this to 2027 and 2028, due to “NRC licensing schedule adjustments and changes to the Florida nuclear cost recovery law,“ which delay the start of site works.
Units 3&4 at South Texas Project (STP) were envisaged as a merchant plant with two 1356 MWe Advanced Boiling Water Reactors (ABWR)m. The COL application was submitted in September 2007 by site operator STP Nuclear Operating Company (STPNOC) on behalf of the project owner, which was then a 50:50 partnership between NRG Energy and the City Public Service Board (CPS Energy) of San Antonio. Ownership of STP units 1&2 (Westinghouse PWRs) is NRG Energy (44%), CPS Energy (40%) and Austin Energy (16%).
In March 2008, NRG with Toshiba subsidiary Toshiba America Nuclear Energy (TANE) formed Nuclear Innovation North America (NINA – 88% NRG; 12% TANE) to develop the project. In February 2009, TANE entered into an engineering, procurement and construction (EPC) agreement that would convert into a turnkey contract once the final decision to proceed with the project had been taken. Following TANE's later announcement that the project would cost $4 billion more than the $13 billion that was previously estimated, in February 2010 CPS Energy decided to reduce its stake to 7.625%, with NINA increasing its share to 92.375%.
In May 2010, Japanese utility Tokyo Electric Power Company (Tepco), which had been acting as technical consultant to the project, agreed to take 10% of NINA's stake for $155 million, with an option to later double its holding. The deal was conditional on a DOE loan guarantee being awarded to the project. However, in April 2011, based largely on low natural gas prices in Texas compounded by the March 2011 accident at Tepco's Fukushima Daiichi plant in Japan, NRG decided to pull out of the project and write off its $331 million investment in it. Toshiba had spent $150 million and persevered with the project, though it wrote off $305 million (JPY 31 billion) on NINA in 2014. NINA was dissolved in 2018.
COLs for each of the two units were issued in February 2016.n However, Toshiba’s withdrawal of the application for design certification renewal in mid-2016 effectively put the project on hold. In May 2018, Toshiba announced its withdrawal from the project, stating that it was no longer financially viable. Toshiba said its decision to exit the project was in line with its policy "to eliminate risk from the overseas nuclear power business, particularly from construction-related cost overruns in nuclear power plant construction projects." Toshiba stated it had sought, but failed to find investors to participate in the project.
The UAMPS Carbon-Free Power Project, a 12-module Nuscale SMR plant, would be owned by Utah Associated Municipal Power Systems and operated by Energy Northwest in Idaho, supported by six western states. UAMPS plans to submit a COL application in mid-2020. NuScale expects the first unit to be operating in the mid-2020s. In 2013 NuScale secured up to $226 million DOE support for the design. In January 2017 UAMPS started soliciting power sales contracts for the 600 MWe plant and wants 150 MWe committed for the lifetime of the plant before proceeding. The DOE has granted permission to site the plant on the 2300 square km Idaho National Laboratory estate, and recent reports put this in the southern part of it. Under this agreement UAMPS has ten years to begin operating the first module, and this will trigger a 99-year lease for the plant. If Idaho state does not welcome the project, Wisconsin would do so, though it is a long way from UAMPS.
This is a reference unit for GE Hitachi's ESBWR design, proposed by Detroit Edison in Michigan, but the company has not yet committed to proceeding. A COL application was made in 2008 and environmental approval was received in January 2013. Full design certification of the ESBWR in 2014 allowed the safety evaluation to proceed, and the COL was approved in May 2015.
Site works started for two 1200 MWe Westinghouse AP1000 reactors on a greenfield site in Florida, and to January 2012 some $860 million had been spent on this. The company expected to have spent about $1 billion on the design, acquisition of heavy equipment and site works by the time it secures NRC approval. In September 2008, Progress Energy Florida signed an EPC contract with Westinghouse and The Shaw Group (now CB&I) consortium. The contract is for $7.65 billion ($3462/kWe), of an overall project cost of about $14 billion.
In August 2013 Duke Energy resolved to terminate the 2008 EPC contract as "a result of delays by the NRC in issuing COLs for new nuclear plants, as well as increased uncertainty in cost recovery caused by recent legislative changes in Florida.” It continued to pursue the COLs in order to keep the option open. In April 2014 Duke announced plans to build 2745 MWe of gas-fired capacity by 2021 instead of proceeding with the Levy County nuclear plant in the original timeframe. Duke Energy Florida was planning to sell all the long-lead time equipment it had ordered by the end of 2014, but it was in dispute with Westinghouse over EPC contract termination. In October the Florida Public Service Commission ordered Duke to repay to ratepayers $54 million it had collected in advance to fund the 'cancelled' project. In October 2016 the NRC approved the COLs – the eighth and ninth it had issued.
The last estimated operational dates were 2024-25, the delay being due to "lower-than-projected customer demand, the lingering economic slowdown, uncertainty regarding potential carbon regulation and current low natural gas prices." The revised cost was $19-24 billion. It would be a regulated plant, with guaranteed cost recovery. In August 2017 Duke Energy cancelled the project, citing the Westinghouse bankruptcy and slowing energy demand, and said it would not maintain the licences.
In December 2010, Dominion announced that it had agreed with Mitsubishi Heavy Industries to build a US-APWR unit, but in April 2013 Dominion announced that it had reverted to the ESBWR as preferred technology (as originally selected in 2005), and would amend its COL application accordingly. The COL for the ESBWR was issued in June 2017. Dominion quotes 1453 MWe net (summer capacity) for the unit there. In May 2013 it agreed a construction contract with GE Hitachi and Fluor, conditional upon proceeding. Dominion said it will make a decision on building in due course, and hence it remains as 'proposed' according to the World Nuclear Association. Dominion suggests start-up in 2028 if it proceeds. It had spent $345 million on the project to early 2016. It is a regulated plant, with guaranteed cost recovery. A consultant to the state has estimated the cost of the plant as $19.3 billion including financing, or $13,283/kW, and Dominion has said that such a figure would not be unreasonable.
Babcock & Wilcox (B&W) has set up B&W Modular Nuclear Energy LLC to market the mPower small modular reactor design of 180 MWe. In February 2013 B&W signed an agreement with TVA to build up to four units at Clinch River, with design certification application intended to be submitted to the NRC in 2015. Bechtel has joined the project as an equity partner to design, license and deploy it. As well as TVA, First Energy and Oglethorpe Power are involved with the proposal. TVA submitted an early site permit (ESP) application in May 2016, with no particular technology specified.
Progress Energy lodged a COL application for two AP1000 units at its Shearon Harris site at New Hill in North Carolina in February 2008. This was proceeding towards being granted at the end of 2014. Expansion of the plant would require raising the water level of Harris Lake by 6 metres, and relying on the Cape Fear River as backup cooling water. However, in May 2013 Duke Energy (which had taken over Progress) asked NRC to suspend the COL review due to projected electricity demand being low for next 15 years.
Luminant planned to use two US-APWR units for its merchant plant in Texas, and in May 2011 remained positive about the prospects for these by 2109-20. The World Nuclear Association lists the plant as "proposed" pending progress with design certification and COLs. However, design certification has been extended by several years and the COL suspended. In May 2011 the NRC concluded that there were no environmental considerations that would hinder the project. Luminant's loan guarantee application was accepted by DOE and it was understood that this was the first alternative to the four short-listed projects, two of which are now not proceeding for the time being. Meanwhile Mitsubishi has withdrawn as a joint venture partner.
Unistar, now owned by EdF, planned to build a 1710 MWe Areva US-EPR alongside Constellation's units 1&2, as a merchant plant. The NRC design certification for US-EPR was due early in 2013, but the COL – originally scheduled in mid-2013 – required a new US partner for the project. At the end of August 2012 the NRC said that it would terminate the COL application in 60 days if Unistar did not have majority US ownership by then, and it did so. In May 2011 the NRC concluded that there are no environmental considerations that would preclude issuing the COL for construction and operation of the proposed US-EPR at the site. The NRC was now completing the safety evaluation. Unistar's loan guarantee application was accepted by DOE and the project was short-listed in May 2009.
In the light of equity developments the World Nuclear Association has moved the project from "planned" back to "proposed". Exelon, merging with Constellation (owner of units 1&2 there, and in which EdF has 49.9% equity) said in November 2011 that with the advent of shale gas, a new nuclear plant at Calvert Cliffs was "utterly uneconomic" by a factor about two.
Calvert Cliffs 3 will have a closed-loop cooling system using a single hybrid mechanical draft cooling tower, giving it a much larger footprint than units 1&2 together. It will also have a reverse osmosis desalination plant for potable water, producing 4700 m3/day.
PSEG has an application for an early site permit for up to two new Salem reactors at Hope Creek, NJ. This is scheduled for awarding early in 2016, and a positive environmental review was reported in November 2015. No reactor technology is specified.
TVA upgraded and restarted Browns Ferry 1 in May 2007. The unit had originally commenced commercial operation in 1974 but all three Browns Ferry reactors were shut down in 1985 to address management and operational concerns. Units 2&3 were returned to service in 1991 and 1995, respectively. The five-year refurbishment program of unit 1 also increased its power to 1,155 MWe, similar to the newer units 2&3.
In April 2010, Areva signed an agreement with Fresno Nuclear Energy Group for a clean-energy park near Fresno in California,including a 1600 MWe EPR and concentrated solar power plant. Possible locations were investigated.
Other planned or proposed new US nuclear capacity is described more fully in Appendix 3: COL Applications.
After 20 years of steady decline, government R&D funding for nuclear energy is being revived with the objective of rebuilding US leadership in nuclear technology.
In an effort that brings together government research laboratories, industry and academe, the Federal government has significantly stepped up R&D spending for future plants that improve or go well beyond current designs. There has been particular attention to the Next Generation Nuclear Plant (NGNP) project to develop a Generation IV high-temperature gas-cooled reactor, which would be part of a system that would produce both electricity and hydrogen on a large scale. The DOE has stated that its goal is to have a pilot plant ready at its Idaho National Laboratory (INL) by 2021.The total development cost has been estimated at $2 billion. See also information page on US Nuclear Power Policy.
Savannah River Nuclear Solutions (SRNS), which manages the Savannah River Site (SRS) in South Carolina on behalf of the DOE,has proposed a demonstration complex with prototype or demonstration models of up to 15 small reactors (up to 300 MWe, but mostly smaller). Hyperion has signed an agreement to build the first, and SRNS has approached several other small-reactor developers, including General Atomics (re GT-MHR or EM2), GE Hitachi (re PRISM) and Terrapower (see section on Hyperion Power Module in the information page on Small Nuclear Power Reactors). It is understood that the DOE has the authority to build and operate such small reactors if they are not supplying electricity to the grid.
i. Dominion's North Anna COL application referenced the ESBWR, but in March 2009 it issued a new request for proposals from reactor vendors and in May 2010 it selected the Mitsubishi US-APWR. Then in April 2013 it reverted to the ESBWR, and agreed on an EPC contract for it with GEH and Fluor, though this will not be signed unless it decides to proceed. The COL review by NRC in now expected to be complete in 2015.
m. Since the decision to go ahead with South Texas Project (STP) units 3&4 was first announced, there have been a number of developments. The combined construction and operating licence (COL) application was prepared by STP Nuclear Operating Company (STPNOC) together with GE Hitachi Nuclear Energy and Bechtel and submitted in September 2007.3 Just before submittal of the COL application, NRG Energy and STPNOC signed a project services agreement with Toshiba to support the design, engineering, construction and procurement of the units. Fluor was then enrolled to support Toshiba4. In November 2010, Nuclear Innovation North America LLC (NINA, the nuclear development company jointly owned by NRG Energy and Toshiba) announced that it had awarded the engineering, procurement and construction (EPC) contract to a "restructured EPC consortium" of Toshiba's US subsidiary Toshiba America Nuclear Energy Corporation (TANE) and The Shaw Group5 (later CB&I). Following CB&I's sale of its CB&I Stone & Webster subsidiary to Westinghouse (then owned by Toshiba), in May 2016 Toshiba and CB&I dissolved their 2010 partnership in relation to all ABWR plans, leaving TANE as the sole EPC contractor for the project.

industry_corpus2: Power & Energy