A market fix for nuclear30 November 2017
Ed Kee looks at the reasons behind the premature retirement of US nuclear plants and whether recent initiatives could help secure a nuclear future in the country
There are 99 reactors in commercial operation in the USA. All were built by regulated investor-owned or government utilities, but 46 reactors now operate as merchant generators that rely on electricity market revenue.
Since 1990, 16 reactors in the USA have retired early. Six closed in the last five years. One unit entered commercial operation: Watts Bar 2, which started construction in the 1970s.
Most of the reactors retired early since 1990 were shut down because they were not financially viable. For some, the high cost and risk of major maintenance was a factor. For some, generating costs were higher than electricity market revenue. If the value of nuclear electricity were higher, many of the reactors retired since 1990 would have remained in operation.
The same economic factors may result in early retirement at other US reactors. In particular, merchant nuclear plants face market economics that may lead to early retirement. Regulated plants also face pressure from low electricity market prices, as shown by the early retirement of the Fort Calhoun plant in 2016.
The nuclear early retirement issue can be illustrated by showing the size of the nuclear fleet under three cases:
- 60-year-life case – this assumes that the financial issues facing the US nuclear power industry were resolved by 2010, so that all operating reactors in commercial operation in 2010 operate for their original 40-year licence life plus an additional 20-year licence renewal period (in fact, the US NRC is working with the industry to examine the issues related to a subsequent licence renewal period of 20 years). This case also assumes that all four reactors at the Vogtle and Summer sites are completed and operate for 60 years.
- Early retirement case – this assumes that the financial issues facing the US nuclear power industry are not resolved, and 48 operating reactors retire between 2010 and 2025, including the six reactors that actually retired early. The nuclear power plants that do not retire early operate for a total of 60 years. This case assumes that the Vogtle and Summer plants are both abandoned. (In fact, Summer was abandoned earlier this year, Vogtle is under review by the Georgia utility commission.)
- Early retirement case with ZEC – as case two, but with seven reactors that were provided with Zero Emissions Credits (ZEC) payments for avoided carbon emissions in New York and Illinois assumed to operate for a total of 60 years.
The chart shows the total nuclear capacity under each of these three cases between 2010 and 2085.
Retired reactors could be replaced by a new fleet of nuclear power plants, but this is not expected to happen. The market approach and market conditions that are driving the early retirement of operating reactors will deter new nuclear power investment in the USA.
The three cases discussed above assume that no replacement nuclear capacity is built, except completion of Watts Bar 2 in 2015 and the four reactors under construction that are included in the 60-year life case.
The three exceptions (Vogtle, VC Summer, and Watts Bar 2) were all the result of decisions made before 2007, when market conditions in the USA were expected to be favourable.
Investment decisions for these projects were made before the factors leading to low electricity value in the US had become clear. The Vogtle and Summer projects face higher than expected cost to build and VC Summer has been abandoned. At Vogtle, the project was restructured in mid-2017. The Georgia Public Service Commission, the state utility regulator, has approved continued construction but it is conducting a detailed review of the project and is expected to reach a decision in February 2018.
A number of other proposed projects, including several that have received NRC approval for construction and operation, are on hold or have been cancelled.
The early retirement of US reactors is a failure of the US market approach to nuclear power, in which ownership and investment in nuclear power plants is linked to financial performance in the electricity market.
The same factors that led to six US reactors retiring early in the last five years still apply. These factors may lead to the early retirement of more reactors and deter investment in new nuclear power plants.
The early and permanent retirement of nuclear units, with no replacement, means that significant public benefits provided by nuclear power will be lost. As nuclear power’s contribution falls, the USA will have higher emissions of carbon and other pollutants, less reliable baseload capacity, lower grid and system reliability, more volatile electricity prices linked to the short-term price of natural gas, and no domestic market for US nuclear power industrial companies.
Market failure is when market participants decide not to undertake activities that increase public good because they are not profitable, with early retirement of US operating reactors being market failure.
Failing electricity markets
The recent decline in US nuclear plant profitability is not caused by poor operation. Nuclear generating costs have been declining since about 2012 and nuclear power plant capacity factors have been high.
Instead, it arises because the value of electricity from nuclear units is lower, both in electricity markets and for regulated utilities. This is the result of low natural gas prices, low electricity demand growth, increased penetration of renewable generation (based on state and federal incentives and tax credits), negative electricity market prices and other factors. Adding renewable generating capacity without demand growth, using out-of-market incentives that distort electricity market prices, have reduced the value of electricity in the USA.
US electricity markets focus on short-run marginal costs, with no reflection of fixed generating costs or guaranteed return on investment for generators. The electricity markets cover short-term dispatch of existing generating assets but do not manage long-term planning of generation investments.
At some times, electricity has negative prices in the spot market, and in the USA the number of hours at a negative price is increasing. Negative prices are linked to the large amounts of renewable generation supported by out-of-market state and federal incentives on the system.
US electricity spot markets are undermined by a range of out-of-market payments, including payments arising from capacity markets, renewable generator incentives, reserves and ancillary services agreements, and regulatory must-run contracts. Ideally, the objective of the electricity industry is to provide reliable service at the lowest long-term total cost. US wholesale electricity markets may be failing to achieve this objective.
The owners of US nuclear plants make decisions based on the market value of the commodity electricity and capacity of these nuclear power plants. When electricity and capacity prices are low (as they are today and are expected to be in the future), merchant plants lose money and regulated or utility-owned plants are seen as less valuable. No new nuclear plant looks profitable.
Generic responses to market failure include introducing costs on negative externalities, providing compensation to support positive externalities and taking sectors likely to experience market failure into government ownership.
New York and Illinois approved programmes to help keep nuclear power plants from retiring early by paying them for the zero-emissions attributes of nuclear power based on the social cost of carbon dioxide. The resulting Zero Emissions Credit (ZEC) payments provide direct compensation to selected nuclear power plants and have helped keep them in operation.
Capacity markets were developed in most US regions to help resolve the shortcomings of the electricity markets with respect to long-term planning. These capacity markets provide some compensation to power plants for their capacity, perhaps including nuclear power plants, and the plants compete in an auction to provide the capacity. These capacity payments are outside of the electricity spot market, but affect it indirectly by reducing price increases or spikes that occur when capacity is scarce. These capacity markets have contract terms of only a few years.
The PJM capacity market in the northeastern USA was modified as a result of the 2014 cold weather event (referred to as the Polar Vortex). This included a requirement to maintain on-site fuel and stronger penalties for power plants that were not available when needed.
In September 2017, the US DOE put forward a new market rule to the Federal Energy Regulatory Commission for consideration. It would establish payments for certain power plants to increase electricity system reliability and resilience in extreme events. Resilience payments would be made to power plants that maintained a 90-day on-site fuel supply, including nuclear power plants. The so-called Notice of Proposed Rulemaking (Docket No RM18-1-000) is in the FERC regulatory process now.
Responses have been divided. The opposition has come from those opposed to coal and nuclear generation. Some electricity market operators and institutions assert that resilience payments will undermine the market. But the resilience payment has some similarities to the PJM capacity market already in operation that is seen as a successful feature.
Even if Docket RM18-1-000 is not implemented in full, it has started a debate about how and why the electricity markets are not working and how to fix them.
About the author
Edward Kee is an expert on nuclear power economics. He is the CEO and principal consultant at Nuclear Economics Consulting Group (NECG) and an Affiliated Expert at NERA Economic Consulting.