What’s Causing Nuclear Plant Closures?
Nuclear power faces considerable economic challenges in the current market. The near-term is of par- ticular concern for the industry and those who support nuclear generation. A variety of factors—such as pressures from competing energy sources and relatively low growth in electricity demand—are chal- lenging the future of U.S. nuclear power. As a result, plants that are otherwise viable have been forced to close prematurely.
Three nuclear plants—Fort Calhoun in Nebraska, Vermont Yankee in Vermont and Kewaunee in Wiscon- sin—have closed due to economic factors. Another seven reactors at six power plants—the Clinton and Quad Cities plants in Illinois, the Pilgrim plant in Massachusetts, the Palisades plant in Michigan, and the Ginna and FitzPatrick plants in upstate New York—are scheduled to follow by 2019. Due to policy changes in Illinois and New York, it is likely that plants in those states will remain in operation.
Generally, the small, single-unit facilities that produce less than 1,000 megawatts (MW) in restructured states are the most vulnerable. Kewaunee had a capacity of around 550 MW, while Vermont Yankee had a capacity of just over 600 MW. Fort Calhoun was the nation’s smallest reactor, with a capacity of 476 MW. According to industry reports, the average total generating cost at single-unit plants was $44.52 per megawatt-hour, while at multi-unit plants the cost was $32.90. Several larger facilities, such as the two- unit Byron and Quad Cities plants in Illinois, also have struggled in recent years, according to their owner, Exelon Corp.
Industry representatives and policymakers have questioned the value of allowing the near-term market environment to affect the closure of nuclear assets that may offer long-term benefits, and have called for policies that value the positive attributes of nuclear power, given that it is carbon-free baseload genera- tion that maintains a large and highly paid workforce with little price volatility.
Low-Cost Natural Gas
Although the price of natural gas has come down considerably since 2008 it has historically been a volatile commodity, with prices spiking to over $13 per million British thermal units (Btu) in October 2005 before dropping to just under $5 per million Btu within a year. In more recent years, it has generally fluc- tuated between $2 and $5 per million Btu due to weak demand and robust production.
On average, natural gas spot prices—the price at which it was bought and sold for immediate delivery across the country—fell over 30 percent across the nation in 2015, according to FERC. Given that natural gas-fired generation sets marginal prices in a number of markets, electricity spot prices also fell by around 30 percent in that same year.
More than two-thirds of the retail electricity price for fossil fuel-based technologies is linked to the cost of fuel. Therefore, these price fluctuations will affect electricity prices considerably as natural gas overtakes coal as the largest source of electricity generation in the United States. Natural gas has become the fuel of choice for many utilities due to its low price and the fact that natural gas power plants are cheaper and easier to site than coal or nuclear plants. In addition, natural gas plants meet current U.S. Environmental Protection Agency (EPA) air regulations and can be built in as little as 20 months. In 2013, half of power plant capacity additions were natural gas.
By comparison, nuclear plants require high capital investments that are not included in wholesale prices. They also take longer to build—in some cases, a decade or more. In fact, the application for a 20-year license extension from the NRC often takes 30 months to complete.
The cost of fuel accounts for around 25 percent of total generating costs for most nuclear power plants, compared to more than 80 percent for most natural gas plants. A reliability benefit of nucle- ar plants is that they store fuel on-site, so they are not subject to fuel delivery issues that limit some other technologies.
Low Growth in Electricity Demand
Electricity demand in the United States has been relatively flat since 2007. While this can be partially attributed to the effects of the Great Recession, the low growth in electricity demand has continued through a period of significant economic growth. In fact, net electricity generation has decreased in three of the past five years, and remains lower than in pre-recession years.
The slowdown can be attributed to several factors, including reduced population growth, energy efficien- cy improvements of electric appliances, and the continued adoption of state energy efficiency measures. In addition, the growth of distributed generation has reduced the demand for delivered electricity to residential and commercial buildings, which accounted for around 70 percent of electricity demand in 2013, according to the U.S. Energy Information Administration’s 2015 Annual Energy Outlook.
This slower growth has benefited smaller scale generation projects. In the 1950s, electricity use grew nearly 10 percent annually, requiring significant capacity additions that benefited large power plants. The past decade has seen an annual growth rate of around 0.5 percent. The slower growth has meant that low-capacity distributed resources can largely cover the demand.
Federal and State Renewable Energy Incentives
Federal tax credits and state renewable portfolio standards (RPS) have driven much of the growth in renewable generation in recent years. The cost of generating electricity from these renewable resourc- es has dropped considerably in recent years, to the point that they have reached grid parity in several regions. Wind capacity grew by 12 percent in 2015, and is forecast to grow by around 10 percent over the next two years. Meanwhile, utility-scale solar photovoltaic capacity is forecast to increase by over 13 gigawatts (GW) during the same period. While these policies have achieved their goal of deploying
renewable resources, there is ongoing debate about whether, and to what degree, these types of policies and subsidies are affecting nuclear power’s competitiveness. For example, the federal Production Tax Credit (PTC) is believed to have contributed to lowering wholesale power prices in some markets—most notably in the Midwest and Texas. The PTC’s structure has led to periods of negative pricing, when power generators have to pay for the grid to take their electricity. This theoretically could place a strain on nucle- ar plants because they cannot simply shut off at times of low demand.
At the state level, 29 states and the District of Columbia have mandatory renewable portfolio stan- dards that outline carbon-free or low-carbon mandates, while another eight states have voluntary standards. These policies require that a certain percentage of a utility’s retail electricity sales come from renewable resources by a certain date. Two states include nuclear power in the eligible technology mix. Along with new technologies like solar and wind, Indiana’s voluntary target allows for 30 percent of its target to be met by nuclear, clean coal and natural gas. Ohio’s mandatory RPS was es- tablished in 2008. In 2014, the legislature froze the standard for three years, and a recent bill to extend the freeze was vetoed by Governor John Kasich. Unless it is overridden, Ohio’s RPS will snap back into place in 2017. It currently is divided into two categories: renewable energy resources and advanced energy resources. Nuclear power is included in the advanced energy resources category, along with cogeneration and clean coal.
It is worth noting that most of these standards were established to support development of new renew- able energy projects in each state, with carbon reduction treated as an assumed byproduct of the poli- cies. However, as nuclear has come under pressure, some states are considering measures that include nuclear in their RPS or nuclear-specific low-carbon portfolio standards. In 2015, a bill to add nuclear to the state RPS failed in the Arizona Senate, and in Illinois, the General Assembly considered legislation to create a low-carbon standard, which would have benefited all forms of low-carbon generation, including nuclear. However, the legislature adjourned before addressing the measure.
RTOs and ISOs in the United States
Source: Federal Energy Regulatory Commission
The restructuring of electric utility markets in certain states has dramatically shifted the manner in which nuclear plants operate. Traditionally, electric utilities in the United States operated as regulated monopolies, with the state public utilities commission exertingoversight and regulatory authority over investor-owned utilities’ rates and other issues. Except in a few states, publicly owned and cooperatively owned electric utilities are regulated by locally appointed or elected governing boards. In vertically integrated states with traditional markets—those in which utilities are responsible for system operations and management, along with providing power to retail customers—utilities own and operate power plants and then sell electricity to end-users.
In strictly restructured states, utilities had to divest ownership in generation and transmission and focus on distribution and billing. There are many types of restructuring, however, and some states have allowed utilities to own generation. In restructured states, investor-owned merchant power plants operate in the wholesale power market, which is run by grid operators—ISOs and RTOs—to ensure reliability. While billing rates for utilities in traditional states are generally calculated as a total of all costs to a utility plus a small profit, rates in wholesale power markets are not required to cover utility expenses. These markets are operated differently, offering day- ahead and real-time pricing, which allows utilities to know the price of electric- ity at any given time and to make cost-conscious purchasing decisions based on that information. Some regions also have capacity markets that operate with a longer outlook, allowing merchant power producers to compete in capacity auctions designed to ensure resources will remain available if needed at any given time through a certain date. PJM’s capacity market, for instance, aims to ensure the grid operator secures adequate resources for three years into the future. A three-year outlook, however, generally fails to support investments in costly assets with potential lifetimes of over 40 years.
Traditional vs. Restructured Markets
Traditional electricity markets were built around self-supply and bilateral contracting. In these markets, which still operate largely in the Southeast and Western United States, a vertically integrated utility delivers electricity to its customers at a rate approved by a state utilities commission. It supplies electricity
through the operation of its own power plants, and through contracts with third-party power plants for the purchase of electricity.
In wholesale electricity markets, electricity generators offer to sell power and ancillary services on a competitive, open market. Utilities can then purchase power and ancillary services to meet their demand.
In most states that have restructured their electricity markets, the majority of generated electricity is sold through competitive wholesale markets.
A number of states, especially those served by MISO and SPP, have hybrid markets, with both traditional and wholesale elements. In these states, utilities can self-supply, engage in bilateral contracting, and purchase electricity on the wholesale market.
Beginning in the 1990s, restructuring spread to a number of states before it was halted by the California electricity crisis of 1999-2000. The Northeast and Mid-Atlantic have the largest collection of restructured states. During the same time period, a number of regions formed centrally organized wholesale elec- tricity markets, spurred by FERC Order No. 888 and the Energy Policy Act of 1992, which required transmission access to be guaranteed. The New England ISO (ISO-NE) includes the six states in New England, while New York’s grid is op- erated by New York ISO (NYISO). PJM serves some or all of the seven states in the Mid-Atlantic and the District of Columbia. Aside from Vermont, these three markets are operated in restructured states. Several other states—including California, Texas and, to a lesser extent, Oregon—have also pursued some form of restructuring. Texas’ market administrator is the Electric Reliability Council
of Texas (ERCOT), while California’s is California ISO (CAISO). In 2015, California legislators passed Senate Bill 350, which could lead to expansion of CAISO into a larger, regional organization that would be responsible for market and grid operations across a number of Western states.
Two other regional wholesale power markets, the Midcontinent Independent System Operator (MISO) and the Southwest Power Pool (SPP), operate predominantly in states that have not pursued retail competition. MISO operates in all or part of 16 states in the Midwest and South, along with Manitoba, Canada. SPP oversees the wholesale power market in all of Kansas and Oklahoma and portions of 12 other states. These hybrid markets include traditional ratemaking that is regulated by state utility commissions along with wholesale energy markets similar to those found in restructured states.
This structure allows for both utility-owned and merchant-operated power plants that can contract to sell power directly to a utility through power purchase agreements and bilateral contracts, or that can sell on the wholesale market.
Power Purchase Agreements
Power purchase agreements (PPAs) between electricity generators and electricity buyers can offer sever- al benefits to both parties, such as predictability for markets and investors. Power producers benefit from the certainty of contracts and revenue, while offering utilities a means of hedging against price spikes.
These contracts also reduce the risk to developers and lenders that finance the construction of new power generation resources.
Every operating nuclear power plant in the United States was built when joint ownership, bilateral con- tracts or long-term PPAs were a common means of procuring electricity. In traditional markets, utilities relied on self-supply and PPAs to ensure they had the electricity they required. These arrangements guaranteed income and operational certainty to nuclear plants, reducing risk for plant owners.
A traditional PPA is negotiated between an electricity generator and an electricity buyer—a power plant and a distribution utility—on a voluntary basis. These contracts can vary in many respects, but they gen- erally commit a utility to purchasing a set amount of electricity from a power plant, with certain restrictions on price over a particular timeframe.
Several nuclear plants in vertically integrated states operate under traditional PPAs, including the Point Beach facility in Wisconsin. In 2006, the operator of the Point Beach nuclear plant signed a PPA with Wis- consin Electric Power Co., which runs into the 2030s. The state’s Kewaunee plant was unable to negotiate a similar agreement with utilities and has since shut down. In addition, the Iowa Utilities Board autho- rized the Duane Arnold Energy Center to extend a PPA in 2013 with Interstate Power and Light Co. In approving the agreement, the Iowa Utilities Board agreed that the PPA was in the long-term best interest of customers, noting that the nuclear plant offers safe and reliable electricity and contributes to maintain- ing a diverse energy supply in the state.
Utilities in vertically integrated states are generally able to enter into a PPA upon approval by the state public utilities commission. However, as evidenced recently in Maryland and Ohio—where a U.S. Supreme Court decision has reinforced FERC’s oversight authority and called into question a number of state-approved PPAs—these contracts tend to be harder to come by in restructured states.
There are a few notable attempts at entering into a PPA in restructured states, which demonstrate the difficulties, along with examples of how some states are attempting to circumvent these restrictions.
The most high-profile recent development in this area has been in Ohio, which is a restructured state within PJM’s service territory. The Public Utilities Commission of Ohio (PUCO) approved an eight-year PPA between a distribution utility, FirstEnergy Corp., and the Davis-Besse Nuclear Power Station—
a single-unit, 889 MW capacity power plant. The PUCO approved the agreement unanimously in early 2016, along with another similar agreement that offered PPAs to seven struggling coal plants in the state.
The plans called for ratepayers to subsidize Davis-Besse and these older coal plants, which are struggling to maintain profitability against gas-fired competition. Under the agreements, FirstEnergy’s distribution companies would have bought electricity directly from Davis-Besse at cost and then sold that capacity, energy and ancillary services back into the PJM wholesale markets. Where auction prices were below the PPA price, ratepayers would have needed to make up the difference. Where auction prices were higher than the PPA price, ratepayers would have received a credit on their bills. The PUCO justified its decision by saying the plan ultimately would have saved ratepayers millions of dollars over the life of the contract and offered market stability.
The decision to approve these PPAs was highly controversial, with consumer advocacy groups and com- peting utilities arguing that ratepayers should not be forced to prop up uncompetitive plants. At the same time, the PPAs were viewed as an infringement on FERC’s jurisdiction over wholesale markets. A similar agreement in Maryland was at the heart of a case before the U.S. Supreme Court, Hughes v. Talen Energy Marketing, LLC. In April, the Supreme Court ruled unanimously against the agreement in Maryland, not- ing that wholesale markets are the domain of FERC alone. The decision immediately called into question the validity of the PPAs approved in Ohio.
Soon after the Supreme Court’s decision, FERC moved to block the agreements in Ohio, saying the PPAs would have to undergo an affiliate abuse test, which requires companies to prove that other buyers would be willing to pay similar prices. FERC limits utilities with captive customers from buying wholesale electricity from affiliate generators without first undergoing such a review to ensure that prices are fair to customers.
FERC’s decision could have a ripple effect—especially in restructured states—in terms of whether PPAs could serve as a viable mechanism for supporting nuclear assets. Already, supporters of the PPAs and the utilities involved have said they plan to push for legislation in the Ohio General Assembly that would re-regulate parts of the electricity market in the state. It is unclear whether there is enough political
momentum to support such a move, but in the meantime, FirstEnergy moved to withdraw its proposal to avoid the FERC review.
FirstEnergy filed a modified plan with PUCO that would avoid FERC oversight by removing the PPA. However, the plan sought many of the same benefits, including the customer surcharges to compen- sate Davis-Besse. In the new proposal, the surcharges would be based on estimated power production costs—not the PJM wholesale market. In October, the commission rejected FirstEnergy’s proposal in favor of a $131 million annual distribution modernization rider that would last between three and five years in order to provide the utility with credit support. The rider would not offer the financial support FirstEnergy was seeking, and the utility has said it will appeal the decision.
The Connecticut General Assembly offers another approach, which could ultimately prove effective and replicable so long as there is support within a state legislature. Connecticut is restructured and within ISO-NE, so the state and its power plants face some of the same issues seen in Ohio. The state’s electricity consumption is split nearly 50-50 between nuclear and natural gas. The state is home to the Millstone Power Station—a two-unit, 2,037 MW capacity nuclear plant in Waterford, Connecti- cut—that is the largest power plant in New England. Millstone also supplies nearly all of the state’s carbon-free electricity.
In March 2016, the General Assembly’s joint Energy and Technology Committee opened discussion on the threats to nuclear power in the state with a special public hearing on whether the legislature should take action to make Millstone more profitable.
From that forum, the Energy and Technology Committee developed Senate Bill 344, which would have al- lowed Millstone to bypass the competitive wholesale markets and enter into PPAs for up to 50 percent of its capacity. The bill also would have granted similar concessions to other energy sources—such as Class
I renewables and large-scale hydropower—although all such proposals would have to be approved by the state commissioner of Energy and Environmental Protection, with oversight from the state Attorney General and Office of Consumer Counsel. Proposals would be evaluated based on the best interests of ratepayers, the reliability of the system and the forecasted price of energy. If approved, the commissioner could direct electric distribution companies to enter into agreements for energy, capacity or any environ- mental attributes for a period of not more than 10 years.
In essence, the bill would have allowed the state to direct its utilities to enter into PPAs with Millstone— something they currently cannot do.
Senate Bill 344 passed the Senate but was tabled in the House. The legislature adjourned on May 4, 2016, although there is some discussion that they will consider a similar measure in the 2017 legislative session.
Capacity Markets and Reliability Contracts
Capacity markets are a relatively new development within RTOs and ISOs. Their purpose is to ensure that a system will have a required amount of capacity at a given point in the future. These markets provide revenue to power plants in exchange for assurances that the power plants will be ready when called upon to supply power. MISO, ISO-NE, PJM and NYISO operate capacity markets, although each of these functions differently and operates based on different sets of load projections. NYISO’s market operates six months into the future; its primary intent is to cover capacity that is not fulfilled through self-supply or bilateral contracts. MISO’s capacity market is voluntary and projects one year into the future, allowing its various load-serving entities to project their own demand needs and fulfill those needs with their own generation resources.
ISO-NE and PJM operate mandatory capacity markets that project three years into the future. In these regions, all capacity must be attained through these markets, notwithstanding self-supply or ownership considerations of load-serving entities. In parts of Illinois and Michigan, MISO is considering adoption of this type of capacity market due to concerns about capacity shortfalls.
ISO-NE and PJM hold annual capacity auctions in which power plants submit bids hoping that they will clear the market, which would require them to stay online and available through a certain date—al- though interim auctions and other processes enable bidders to effectively change their obligations. These auctions have proven to be hard on nuclear plants in recent years, especially since natural gas capacity increases and drives down clearing prices.
The clearing prices for PJM’s capacity auction for the 2019-2020 planning year were announced in May 2016; three nuclear plants failed to clear the auction. Exelon announced that its Quad Cities plant in Illinois and its Three Mile Island plant in Pennsylvania failed to clear, while a portion of Byron’s capacity also failed to clear. The clearing prices surprised many observers because they came in around 40 percent lower than the previous auction throughout much of the region. PJM said the lower clearing price was largely the result of efficiency and low natural gas prices, with over 5,000 MW of new gas-fired power bid into this auction.
The Pilgrim plant in Massachusetts is currently operating under a capacity contract with ISO-NE that obliges the plant to stay online through May 2019. For this reason, the plant’s owner, Entergy Corp., has announced that the plant will undergo refueling one more time to meet its obligations.
New York has worked hard to find another means of achieving a similar end for the Ginna plant. The plant is now operating under a reliability support services agreement that was negotiated between the power plant, the local utility, state regulatory staff, consumer advocates and large consumers. FERC ap- proved the settlement in early 2016. The agreement provides a lifeline to the plant by offering revenue in exchange for grid support services to Rochester Gas and Electric. However, this is only a two-year contract that will expire in 2017, at which point the facility would have faced the same problems and likely shut down. With adoption of a new policy in New York, the plant is expected to remain in operation.
Considerations as the Nuclear Fleet Ages
In general, the nuclear fleet is aging. While one new reactor recently came online and another four will come online during the next few years, the majority of the nation’s nuclear assets have already begun operating on a 20-year license extension. Fifty-two of these license extensions—representing over half the current fleet—will expire by 2040.
However, two facilities—the Surry plant in Virginia, and the Peach Bottom plant in Pennsylvania—intend to apply for a second 20-year license extension. In order to ensure that these facilities can continue to operate safely, the NRC requires that they clear significant regulatory hurdles. The relicensing process of- ten can take up to 30 months—longer than it generally takes to license and build a natural gas plant. It is expected that a number of other nuclear facilities will follow suit, which could see nuclear plants operate into the second half of the century.
With these license extensions come public concerns about safety. Recent NRC reports placed all but three of the nation’s operating reactors in the top two performance categories, with 85 reactors in the top cat- egory. The reactor oversight program focuses almost exclusively on safety issues, with three main focus areas: reactor safety, radiation safety and safeguards. Based on the NRC framework and performance indicators, the NRC places reactors in one of five performance categories that correspond directly with the level of oversight exerted by the NRC, placing reactors in the lower categories under much greater scrutiny than those in the highest.
According to the U.S. Energy Information Administration, the nuclear power industry also is operating aging plants very efficiently. Prior to 2000, nuclear plants were generally operating at a capacity factor of below 80 percent—producing electricity less than 80 percent of the time. Since that time, the nuclear industry’s capacity factor has risen steadily. In 2015, the U.S. nuclear fleet operated at a capacity factor of
92.2 percent—a significant record and milestone. Natural gas and coal, meanwhile, operated at capacity factors of around 55 percent in 2015.
Nuclear facilities operate under high scrutiny, and the level of scrutiny increases substantially in the wake of high-profile nuclear incidents, such as the recent accident at the Fukushima Daiichi power plant in Japan. In response to this incident, the NRC mandated safety and operational changes to the nation’s nuclear reactors.
In particular, the work done to prepare for license extensions and post-Fukushima upgrades has come at some cost to the industry. Capital expenditures have risen by 103 percent in real terms since 2002, with some of this also a result of power uprates to increase output. In fact, 92 of the nation’s operating reactors have been approved for uprates that have added over 7,000 MW of capacity. There is some expectation that, since most license renewals and post-Fukushima upgrades have been completed, the recent increase in capital spending should normalize to a more moderate level.
In some cases, these large-scale investments in capital improvements have proven insurmountable as plants find it difficult to recoup capital costs in restructured markets. This has led some operators to shut down rather than make the necessary investments. For example, the Oyster Creek facility in New Jersey has elected to shut down 10 years early in an agreement with the state, instead of investing in adding expensive cooling towers.
The nuclear industry is also leading efforts to increase efficiency and lower the cost of operations. A multi-year initiative, “Delivering the Nuclear Promise,” focuses on analyzing cost drivers and redesigning plant processes to increase efficiency, which can reduce costs and increase revenue. The goal is to reduce the cost of generating electricity at nuclear power plants by 30 percent by 2018.