• A spate of recent retirement announcements from nuclear facilities could reduce generation from existing nuclear reactors by more than 10% by 2025
  • As nuclear represents the largest source of low-carbon electricity in the U.S., large-scale nuclear retirements threaten U.S. carbon reduction goals
  • In the short term, low natural gas prices, electricity market design, and a lack of CO2 prices threaten the most economically inefficient nuclear reactors
  • Longer term, the technical and market effects of growing renewable energy could exacerbate these challenges, threatening most of the existing nuclear fleet


Recent developments suggest the very real possibility that the U.S. risks losing its largest source of low-carbon electricity: existing nuclear power plants.

In the last two months, six nuclear reactors have announced that they plan to retire within the next nine years. They join five reactors that have already retired in the last four years as well as three reactors that plan to retire in the next four years. In total, almost 12 GW of nuclear reactors have either retired or plan to retire soon, representing ~12% of U.S. nuclear capacity at the beginning of 2011.

Retired and Retiring U.S. Nuclear Reactors

A total of 14 reactors at 8 nuclear power plants have retired or will retire in the next ten years

Source: SparkLibrary compiled from multiple sources

In many ways nuclear energy is the backbone of clean energy in the U.S. electricity system. In 2015, the nuclear fleet generated 20% of electricity in the United States, a level it has provided for decades. Today, despite the rapid and continuing growth of wind and solar, U.S. nuclear still constitutes more than half of carbon free electricity generation in the country.

From a climate change perspective, the closure of nuclear plants thus constitutes a major threat to U.S. carbon reduction goals under both the Clean Power Plan and the U.S.’s international commitment at the Paris climate accord. Many recent articles have highlighted this concern. Despite the potential climate ramifications, relatively little progress has been made on addressing the core economic challenges facing the nuclear fleet.

This article lays out the economic and technical challenges facing the existing nuclear fleet in both the short and the long term. It raises important questions about electricity market design as well as the feasibility of inflexible nuclear generation in a high renewable world. Parts 2 and 3 examine potential solutions.

One point deserves highlighting when discussing nuclear plants: the challenges facing existing nuclear power plants are very different from those facing new plants. In particular, cost and time overruns in the construction of new reactors are not a risk so much as they are a certainty. To construct a new nuclear unit is to bet that electricity policy, regulation, and markets will be able to support the facility through at least the 2060’s. Understandably, there are very few new builds in the U.S. and even these are found in increasingly less prominent rate-regulated markets. This article focuses only on the existing nuclear fleet and their challenges.

U.S. Nuclear Backbone of U.S. Clean Electricity

Commercial nuclear power has been around since the 1960’s, playing a key role in the nation’s electricity mix. Almost all of the nation’s 99 operating reactors were built decades ago. Although they originally suffered severe cost and time overruns, the capital expenditures for these plants have largely been paid off. Many of them are now approaching the end of their original 40-year licensing period and now require re-licensing if they are to continue operations for an additional 20 years.

Geography is critically important to understanding electricity in the United States; the situation is no different for the nuclear fleet. As most reactors began construction in the 1960’s and the 1970’s, they are concentrated in the eastern half of the country (reflecting population concentrations of the time).

100 us nuclear reactors concentrated in eastern U.S.

Source: NRC

Overall, nuclear power plants are some of the largest individual power plants in the country. The smallest nuclear reactor in the country is 478 MW, larger than most natural gas or coal units. Meanwhile, most nuclear reactors are 1,000 MW or larger.

While some nuclear power plants consist of only a single reactor, most nuclear power plants have two reactors while several have three. The largest nuclear power plant in the country (the massive three-reactor 4.2 GW Palo Verde Nuclear Generating Station) is the second largest power plant in the entire country. Singlehandedly, it generated almost 1% of total U.S. electricity generation in 2011.

Nuclear reactors have exceptionally high capacity factors, usually exceeding 90%. U.S. reactors were originally built to meet baseload demand – when a reactor is running it is almost always generating at full capacity, with very limited ability to scale output up or down.

The only reason nuclear capacity factors are not 100% are outages: plants need to shut down every 18-24 months for maintenance and refueling, with plants also occasionally suffering forced outages due to various operating issues. Severe and lasting forced outages can greatly impact a plant’s revenue, meaning a lower than average nuclear capacity factor could indicate an economically struggling reactor.

These high capacity factors mean that despite only constituting ~10% of U.S. electricity generating capacity, the ~102 GW nuclear fleet generates ~800 TWh of nuclear generation every year, 20% of U.S. electricity needs. Over the last fifteen years, nuclear generation has been relatively flat, unlike most other power sources.

Existing Nuclear Plants Face Economic Headwinds

Fundamentally, existing nuclear power plants face two major challenges:

  1. In the short term, electricity market design, low natural gas prices, and a lack of effective climate policy pose significant obstacles for large portions of the fleet.
  2. In the long term, market impacts from high penetrations of renewables, increasing age of the U.S. nuclear fleet, and the need for an increasingly flexible system threaten the economics of almost all remaining nuclear reactors.

While these two challenges have considerable overlap, it is important to conceptually separate them as they have different implications for the future of U.S. energy and climate policy.

Market Design and Short Run Marginal Cost

The high capital, low marginal cost nature of nuclear plants directly translates into the short term economic challenges facing existing nuclear power plants. There are two primary causes: electricity market design and low natural gas prices.

During the last twenty years, the United States has been in the process of significant regulatory restructuring. Large parts of the electricity industry transitioned to competitive wholesale electricity markets, operated and overseen by seven non-government Independent System Operators (ISOs) overseen by the Federal Energy Regulatory Commission.

U.S. Competitive Wholesale Electricity Markets (ISOs/RTOs)

US has seven ISOs/RTOs: CAISO, ERCOT, MISO, PJM, NYISO, ISO-NE, and SPP. Together they cover all of the US except the Rocky Mountains, the South, and the Northwest

Source: FERC

While these ISOs each have different market designs and varying levels of market competition, a key feature of each are day-ahead and real-time energy markets, which dispatch electricity on the basis of lowest marginal costs.

Electricity sources with zero (or near zero) marginal operating costs are almost always dispatched first – nuclear, solar, wind, hydro, and geothermal. Meanwhile, the two major energy sources with high and variable marginal costs, coal and natural gas, compete with each other to meet whatever residual load is remaining. As coal or natural gas are almost always the marginal units, they usually set electricity prices.

From a short term perspective, this makes perfect sense: for any specific hour, energy markets ensure that electricity demand is met using the cheapest available resources. The fundamental challenge, however, arises when compensation of generators is directly tied to revenues from these energy markets.

Importance of Natural Gas in a Short Run Marginal Cost Market

Natural gas prices are notoriously volatile – a result of annual variations in seasonal winter demand and general commodity cycles. Accordingly, as natural gas plants are often the marginal unit, day-ahead electricity prices generally reflect prices needed to balance the natural gas market in the short term. They do not reflect the longer term prices to maintain reliability, resource adequacy, or generation diversity. Nor, of course, do energy market prices reflect carbon emissions from different electricity sources.

Since the beginning of the shale revolution, natural gas prices have fallen significantly and are usually below $4/MMBtu. Electricity prices have similarly fallen – in many cases they are half of what they were in the mid-2000’s. These lower electricity prices directly affect nuclear reactor revenues in restructured electricity markets.

To be sure, nuclear power plants outside of competitive wholesale markets face economic challenges due to market competition with natural gas. Yet the majority of recent retirements or announced retirements (at least 12 of 14) have occurred in restructured markets, where nuclear generators are exposed to more direct competition with natural gas.

The most heavily impacted nuclear power plants are those with only one reactor at the plant. Of the 29 single reactor sites that existed in 2010, 8 (28%) have either retired are or are slated for retirement. Comparably, multi-unit nuclear power plants as a group have been less affected, with only 6 of 75 rectors (8%) at dual-reactor plants retiring or announcing retirements.

Capacity and Capacity Factors of Segmented U.S. Nuclear Fleet

Nuclear retirement risk partially depends on number of reactors per plant, capacity per unit, and capacity factors

Source: SparkLibrary, based on data from EIA (CF is 2010 and 2011 average)

This difference between single-units and multi-units comes down to economies of scale. When there are multiple units at one site the plant operator can reduce ongoing capital cost outlays and operating costs per MWh generated. NEI estimates that 2015 all-in generating costs for single-unit plants averaged $44.52/MWh while multi-units averaged only $32.90/MWh. There is likely to be large variations across the fleet from these averages as a result of plant-specific considerations and periodic large capital outlays.

Importantly, four of the seven ISOs have established capacity markets designed to provide revenue to generators outside of the day-ahead electricity market. Not only are these markets controversial, they have not managed to stem the tide of nuclear retirements. Of the 14 reactors that retired or announced retirements half were located in ISOs with well-developed capacity markets.

In the short term, low natural gas prices means electricity prices will remain very low, hurting profitability at most nuclear plants and threatening some with retirement. Nevertheless, a large majority of the fleet remain competitive, particularly the largest multi-unit power plants.

Longer Term: Renewable Energy Growth and the Need for Flexibility

However, in the long term, the future of the entire nuclear fleet is more questionable. In many ways, PG&E’s recent proposal to retire the 2.2 GW Diablo Canyon nuclear power plant was game changing; it is the first clear illustration of the long term challenges facing the nuclear fleet.

Diablo Canyon’s retirement is qualitatively different from almost all retirements announced to date. It will not occur for almost a decade when the operating licenses for the reactors expire in 2024 and 2025. The two units retiring are the largest nuclear retirements capacity-wise to date. The economics of the plant appear sound in the short term. The answer lies in this analysis that accompanied PG&E’s retirement proposal.

Reason 4 of 4 Underlying PG&E’s Announced Retirement of Diablo Canyon

DIablo Canyon retirement is a result of rising costs at the plant, regulatory risks, limited economic impacts, and renewable integration

Source: PG&E

Dramatic cost declines and corresponding growth in solar and wind are threatening to upend the economics of even the most cost efficient nuclear power plants. As we discussed recently, renewables greatly reduce power prices through the merit order effect. Already, solar may have reduced peak power prices in California in May by as much as half. These price reduction effects will only grow along with renewables, further reducing power prices.

When combined with day-ahead electricity markets and low natural gas prices, high renewable energy generation could spell the end for the existing nuclear fleet, assuming current market design remains unchanged. Even nuclear reactors surviving current low wholesale prices will be hard pressed if renewables drive prices lower.

CAISO SP-15 Average Hourly May Day-Ahead Energy Prices

Difference in electricity prices between 2012 and 2016 closely resembles the net load duck curve

Source: SparkLibrary based on data from CAISO

To a degree, the problem is technical and cost related. In addition to nuclear’s high fixed costs, its baseload and inflexible nature may not be compatible with a high renewable future. Nuclear has limited ability to change its output to offset renewable intermittency. Further, the zero marginal cost nature of renewables will make nuclear power plants uneconomic if they have to depend on energy markets alone for revenue.

Conversely, in many ways, natural gas and renewable energy are natural financial and technical complements:

  1. The ability of natural gas to quickly ramp generation up or down can balance renewables
  2. As natural gas costs are primarily fuel based (marginal), natural gas can usually recover its costs solely in energy markets, where it sets prices
  3. Natural gas’ price volatility increases renewable’s attractiveness as a financial hedge through long term contracts (which are possible with nuclear but uncommon)

In light of these synergies (as a result of the overall policy framework in the U.S.), natural gas and renewable energy have had very limited economic competition to date. Comparably, natural gas is directly competing with nuclear energy today and renewables will directly compete with nuclear in the future if policies remain unchanged.

This raises major questions:

  • Are renewables and nuclear energy fundamentally incompatible due to renewable’s intermittency and nuclear’s lack of flexibility?
  • Does it make sense to tie nuclear’s revenues to energy markets whose prices largely reflect short term natural gas markets?
  • Why are existing mechanisms (capacity markets, existing cap-and-trade) failing large portions of the existing nuclear fleet? Can they be corrected?
  • If not, what are the optimal solutions to nuclear’s woes?

Do Existing Nuclear Power Plants have a Future?

In our view, renewable energy and nuclear power are not fundamentally incompatible – rather, it is current market design that puts the two into conflict. Even in high renewable scenarios, nuclear baseload can play a key role, particularly in certain regional markets.

Timing is also a critical factor. Even with 20-year license extensions, we will still need to replace large portions of the nuclear fleet beginning in the 2030’s. Ideally, renewable growth in the interim will primarily replace coal and secondarily replace natural gas. By the time that renewable’s intermittency and nuclear’s inflexibility begin to conflict in an incompatible way (via large-scale technical challenges as opposed to prices), most existing plants will need to retire anyways.

We need to rethink the use of energy markets as primary compensation mechanisms for electricity generation. Day-ahead and real-time markets are excellent ways to maintain short term reliability and operations at the lowest cost.

However, despite broad assumptions to the contrary, energy markets are not technology neutral – they are based on short run marginal cost economics. In a shale driven world, such a basis inherently favors natural gas over all other energy sources. Most existing (and upcoming) renewable energy avoids this problem entirely by operating outside of electricity markets through long term contracts. Comparably, nuclear energy and even coal do not generally use such long term contracts.

This calls for energy market reform that maintains the benefit of ISO-based dispatch but more fully values other attributes of generation technologies: reliability, resource adequacy, fuel diversity, and environmental impacts.

This article was part one of a three-part series. The next two articles (Part 2 and Part 3) will explore in depth several recent proposals to help existing nuclear power plants:

  1. Maintaining or reinstating cost of service regulation
  2. Expanding state RPS policies into low carbon portfolio standards that include nuclear
  3. New York’s proposed backwards carbon price-based price floor
  4. Capacity market reforms
  5. A carbon price
  6. Nuclear tax credits or other subsidies
  7. Nationalization of the nuclear fleet

Read More

  1. Good discussion of the political challenges of nuclear with proposed solutions to recent economic woes: https://www.linkedin.com/pulse/saving-americas-nuclear-plants-jigar-shah
  2. Detailed look at the proposed nuclear retirements of Diablo Canyon 1+2 in California: http://www.vox.com/2016/6/21/11989030/diablo-canyon-nuclear-close
  3. Solid piece arguing that closing Diablo Canyon will save both money and carbon: http://www.forbes.com/sites/amorylovins/2016/06/22/close-a-nuclear-plant-save-money-and-carbon-improve-the-grid-says-pge/#3aa706c24cea
  4. A look at proposals to save Illinois’ nuclear power plants: http://www.citylab.com/politics/2016/05/illinois-exelon-nuclear-power-plants-renewable-energy-portfolio/484046/
  5. A higher level view of nuclear history and reactor technologies: http://mydocs.epri.com/docs/Email_Alerts/sowder.pdf