Highlights:

1. While states have a major role to play in preventing nuclear retirements, regional and federal solutions offer alternative avenues to keep nuclear plants operating.
2. For ISOs, capacity market reform can reduce retirement pressure by more fully valuing the long-term benefits of nuclear generation in the overall electricity mix.
3. Direct subsidies, like tax credits, may provide further revenue but are a blunt instrument and face major political headwinds.
4. Carbon prices are an effective market-based solution but existing cap and trade systems have so far failed to support sufficiently high prices.
5. Finally, nationalizing parts or all of the nuclear fleet could prove a major long term strategy to keep plants open.

Regional or National Policy Action Offers Possibility of Broader Reform

Since mid-2016, the challenges facing the nation’s nuclear fleet have only grown more pressing. Natural gas prices, despite recent volatility, remain very low, keeping nuclear revenues in competitive electricity markets low.

Nuclear plants continue to announce retirement decisions, with the 2.2 MW 2-unit Indian Point retirement by mid-2021 being especially notable considering its current profitability. More than 10% of the U.S.’s 2010 nuclear fleet is now retired or scheduled to retire within the next 8 years.

Faced with the loss of the largest zero carbon electricity source in the country, states are taking the lead in maintaining struggling nuclear facilities. Since New York finalized its ZEC program, Illinois has provided similar targeted nuclear support as part of broader energy legislation. Other states are considering following suit.

While state action may be the most likely policy solution for struggling nuclear units, regional or federal policy solutions offer different and more comprehensive changes. Increasingly, regulatory power over utility-scale electricity generation has shifted from the states to FERC.

The evolving regulatory roles of state commissions, ISOs, and FERC constrain and inform any major policy efforts to address the challenges facing the nation’s nuclear fleet. As we discussed in Part 2, this shifting regulatory landscape limits how state legislatures and PUCs address nuclear retirements in individual states.

At the same time, the new regulatory landscape provides the opportunity for policy solutions at the regional and federal level. The U.S. Congress, ISOs, regional programs, and FERC together can all play unique roles in limiting retirements of existing nuclear facilities.

In key ways, regional and federal solutions are qualitatively different from the state solutions analyzed in part 2:

• Regulatory and policy decision making happens in different venues with larger oversight and scrutiny. Decision makers need to balance more competing interests.
• Any policy or regulatory actions above the state level are likely to affect more than just vulnerable nuclear units, creating the potential for windfall profits for non-threatened nuclear units.
• Compared to the states, these venues are not currently major policy focuses of efforts to save nuclear units.

Critically, the ‘higher’ the regulatory avenue used, the more nuclear facilities and general power plants that are effected.

Most states only have a handful of nuclear reactors, making it possible to micro-target struggling nuclear reactors even if it brings charges of favoritism.

Comparably, regional and federal regulatory authorities have many nuclear reactors under their oversight. Due to political and regulatory constraints, any actions these regulators take may have to benefit all nuclear units, potentially increasing retirement prevention costs.

Nuclear Capacity Subject to Certain Jurisdictions/Quasi-Jursidictions

Source: SparkLibrary, based on data from EIA

The effects of any policy will be different for deregulated and rate-regulated nuclear units. Parts 1 and 2 highlighted the key differences between these two types of reactor compensation. A quick recap:

1. Deregulated reactors receive revenues from wholesale electricity markets, where they face significant competition from natural gas and coal units. In practice, revenues and profits for these reactors vary along with energy prices. Low natural gas prices now and high renewable energy growth in the future will lower revenues by lowering power prices.
2. Rate-regulated (or cost-of-service regulated) reactors receive revenues based on traditional average cost compensation. Natural gas or renewable energy do not compete directly with these reactors. Rather, any decision to close these reactors is based on utility and commission decision making.

Of the two, deregulated reactors face the most pressing retirement risks. Nevertheless, many rate-regulated reactors face major retirement risks in 5-15 years without policy action.

In this article, we review four potential energy policies that operate primarily on the regional or federal level that could stem the tide of nuclear retirements:

1. Capacity market reform to increase (or create) capacity revenues
2. Existing nuclear subsidies
3. Carbon price
4. Nationalization of the existing private nuclear fleet

This is the third article in a three-part series on existing nuclear electricity generation in the United States. Part 1 discusses major economic and policy challenges. Part 2 examines several specific actions states can take to prevent nuclear retirements. This article (Part 3) examines potential regional and federal policy solutions.

1. Capacity market reform

Of the seven competitive wholesale electricity markets (ISOs) in the United States, four have some type of capacity market construct: PJM, ISO-NE, NYISO, and MISO. These markets only emerged relatively recently and are still being actively designed.

Although the rules behind each capacity market are complex, the concept is simple:

While energy only markets compensate generators for energy provided to the grid, capacity markets compensate generators for promising to provide capacity when dispatched by the ISO.

Effectively, capacity markets substitute for the traditional role of state regulators in long term system planning.

Capacity markets work to maintain long term grid reliability and adequate resource supply. Energy-only markets maximize for short term operation and, due to price volatility and market cycles, will often not provide sufficient revenue to keep power plants open in the short term even if they are economic in the mid or long term.

By providing revenues up to three years in the future, existing capacity markets provide some long-term certainty for market revenues (the extent is debated).

In the markets where they exist, prevailing capacity prices can thus shape overall market outcomes.

Indeed, they already have. Around half of retired or retiring nuclear reactors are in the three ISOs with the most developed capacity markets: PJM, NYISO, and ISO-NE. Most states in these three ISOs are deregulated. These nuclear units almost exclusively receive revenue from energy and capacity markets.

Capacity markets are still being developed, are somewhat controversial, and have notable limitations.They are not markets as most people think of them; rather, they are administrative auctions.

Based on ISO-developed and FERC-approved rules, grid operators run their own capacity auction processes. They determine the amount of capacity needed in the target year, receive bids for supplying that capacity, and determine the ultimate capacity clearing price.

Source: NREL

Typically, if a generator clears the auction, they are required to generate electricity when called upon by the grid operator. They receive capacity revenues in a $/MW-time period format.

The rules governing capacity auctions often play as much role in setting prices as competitive bids do. The ISOs determine what level of capacity needs to be procured, generator eligibility, under what conditions suppliers can provide the capacity, how the auction price is determined, and more.

In most capacity auctions, most plants plan on continuing to operate no matter what. They are price takers, meaning that there are only a handful of plants bidding competitively into the auctions. Hence the rules of the auction effectively determine the revenues the generators receive.

ISO-NE provides a stark example: in the first seven capacity auctions in ISO-NE, ISO-wide capacity prices cleared at the administrative floor. Two of the retired or retiring nuclear units in the country are in ISO-NE, making low capacity revenues a key factor in those specific retirements. New England’s remaining plants face some of the highest retirement risks in the country.

There are several ways that capacity markets could be reformed to help address existing nuclear retirements:

1. Increasing overall capacity prices. Ultimately higher capacity revenues should address the revenue shortfall that deregulated nuclear units suffer due to low energy market revenues. ISOs do not determine capacity prices but through specific rule changes (such as price floors, eligibility, and performance) capacity price signals may rise. Recent capacity market reforms in PJM, ISO-NE, and MISO were all intended to have this effect due to a widespread perception capacity prices were not high enough for all units.
2. Lengthening the time frame of auctions. The three mandatory capacity markets in the country (PJM, ISO-NE, and NYISO) all have relatively short auction periods. Capacity periods go at most three years into the future. Extending the length of the capacity auction periods could provide more certainty to nuclear operators; they would likely also raise prices as some plants cannot make long term commitments. However, lengthening the timeframe alone does not necessarily guarantee higher revenues and increases non-capacity market related generator risks.
3. Change capacity markets to value more than just capacity. In long-term system planning, resource diversity, generator reliability, and other factors are just as important as available dispatchable capacity. On a systemic level, nuclear energy provides a hedge against overreliance on natural gas, keeps prices down through a nuclear ‘merit order effect’, and has exceptionally high reliability (supporting high capacity factors). These systemic issues go beyond just capacity markets but are closely tied to the non-energy value tied to the grid.
4. Expanding capacity markets to remaining ISOs. Capacity markets are still being developed and not all existing ISOs use them. New mandatory capacity markets could be established in CAISO, SPP, and ERCOT (MISO’s voluntary capacity market is currently being redesigned albeit slowly). However, CAISO will be nuclear free after Diablo Canyon closes in 2025 and SPP lacks nuclear units after the retirement of Fort Calhoun. Despite robust debate, ERCOT has not yet adopted a capacity market and seems unlikely to do so. Notably, MISO’s capacity market is currently only token, with efforts underway to design a more robust, higher priced capacity system.

Any changes that occur in capacity markets need to recognize the rapidly changing technologies in electricity. Existing capacity markets are still young and developing, focused on economic efficiency, and were (effectively) limited to only thermal units. New and emerging energy technologies, particularly renewable energy and energy storage, will challenge overall market design and capacity markets specifically.

Due to their major economic ramifications for generator revenues and customer costs, the policy process to drive changes in capacity markets is complex and contentious.

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2. Direct subsidies

The economic challenges facing some nuclear reactors in the short term and most reactors in the long-term boil down to one problem: insufficient cost competitiveness with non-nuclear plants due to both ‘true’ competition and market design.

In deregulated markets, lower electricity prices greatly reduce revenues for existing nuclear plants; in rate-regulated markets, low natural gas and renewable prices can offer lower cost (and potentially lower risk) alternatives.

Government subsidies for nuclear plants could address nuclear plants’ lack of cost competitiveness in both types of electricity markets.

In energy world, the term “subsidies” is often used widely with many definitions depending on the context. For purposes of this article, we refer to subsidies in a narrow sense: a subsidy is a direct government transfer from taxpayers used to meet some specific public policy objective. This definition includes direct grants or tax credits but would not include something indirect or intangible, like the debated Price Anderson ‘subsidy’.

In both deregulated and rate-regulated markets, subsidies increase plant revenues.

In deregulated markets, subsidies directly increase a plant’s competitiveness in the market; at current market prices and nuclear costs, the most vulnerable nuclear plants would be profitable at a moderate subsidy.

In rate-regulated markets, subsidies increase the relative cost competitiveness of existing nuclear reactors during commission and utility decision-making.

A nuclear subsidy can be implemented at either the state or federal level. Either the relevant state legislature or Congress would need to pass legislation.

Administratively, subsidies are relatively straightforward with limited technical complications.

The government decides on what basis to provide money: the plant’s capacity, its generation, or some financial metric like investment or operating costs. Most likely, any nuclear subsidy would probably be in $/MWh, like existing production tax credits.

Subsidies face significant political headwinds

Perhaps more than any other potential nuclear solution, subsidies for existing nuclear generation are likely to face significant political opposition. There are several major considerations that likely make subsidies infeasible:

1. They are VISIBLY expensive. A $10/MWh existing nuclear subsidy would cost federal taxpayers $8 billion per year.
2. Unlike new RE and new nuclear tax credits, a subsidy to address existing nuclear facilities would likely have to be permanent.
3. The limited number of nuclear facilities and owners in the country raise serious concerns about corporate welfare, favoritism, and fairness.
4. Subsidies can significantly distort market signals (lessened to a degree by nuclear’s price-taking nature).
5. Subsidies shift system costs from ratepayers to taxpayers.

Of these five, the last is a major limitation.

A general principle of US energy regulation (derived from the broader economy) is that consumers should be responsible for all costs associated with their service. Reality is far from this ideal. Nevertheless, this principle underlies the rate-shifting concerns of the net metering debates as well as environmental regulations that internalize external costs.

Unlike every other solution presented in this series (excepting perhaps nationalization), subsidies would violate this principle by shifting the cost burden to taxpayers.

Subsidies are often more visible and transparent than regulatory actions as they come directly from the legislature, as opposed to PUCs or the ISOs. The prospect of taxpayers subsidizing ratepayers is likely to engender significant political opposition to any existing nuclear subsidy.

From a legal standpoint, additional obstacles come into focus; planners must be careful in crafting government-sponsored subsidies. Where subsidies are found to be discriminatory, they are potentially illegal, and so basic risk management could require that subsidy programs be applied to every nuclear plant in a jurisdiction.

For states, this might mean a nuclear plant or two would receive unnecessary subsidies to keep other plants online. A national nuclear subsidy would similarly provide revenues to the whole nuclear fleet, even though only nuclear units in restructured markets are most at risk.

3. Carbon pricing

As existing nuclear plant’s current challenges are largely economic, increasing energy prices indirectly via imposing a carbon tax on fossil generation could be ideal:

1. It is technology neutral and directly addresses a primary reason why nuclear plants are struggling (GHG damages are not internalized)
2. A pollution price, via taxes or tradeable permits, is a well-established energy policy tool
3. While politically unlikely at the federal level in the short term, the mechanism enjoys significant industry and regulator support

Carbon pricing can be implemented at almost any level of energy policymaking: state, regional, and federal. There are two major carbon pricing schemes in the US today: California’s cap and trade system and the Northeast’s Regional Greenhouse Gas Initiative.

Unlike subsidies, the financial effects of carbon pricing can depend on a nuclear plant’s regulated environment. In all deregulated wholesale markets, carbon prices increase fossil prices which are on the margin, increasing energy prices and driving higher revenues for nuclear facilities.

Meanwhile, in rate-regulated markets, carbon prices make fossil generation less attractive compared to existing nuclear units but do not directly affect plant revenues. Whereas subsidies in a rate-regulated market lead to more revenue for nuclear units, a carbon price would not.

Over the short to mid-term, a moderate carbon price would likely be sufficient to keep all but the most uneconomic reactors online. Brattle Group recently estimated a $12-20/ton CO2 tax would be sufficient to prevent most additional retirements.

Over time, the carbon price would likely need to rise:

• The marginal unit gets cleaner as coal continues to retire. Higher prices are needed to maintain CO2 reductions and provide sufficient energy revenue for nuclear units.
• Energy market revenues are likely to fall over time as renewable generation grows and the merit order effect reduces nuclear energy market revenue.

While carbon pricing is promising, it has so far proven ineffectual at prevent nuclear retirements.

More than half of retired or retiring nuclear reactors are already located in areas subject to cap-and-trade (RGGI and California C+T). With natural gas (not coal) dominating the margin in these markets, carbon prices in both of these trading schemes have been too low to sufficiently increase power prices to benefit struggling nuclear facilities.

Source: EIA

The low carbon prices in RGGI and California arise from differing circumstances. In RGGI, policymakers have consistently set the cap too high, making CO2 permits especially cheap. In California, complementary policies reduce carbon reductions required from the cap and trade scheme, also reducing CO2 permit prices.

Politically, carbon pricing may be the most promising regional or federal solution presented in this article. Unlike other policies, it offers a strong opportunity for nuclear owners to coalition build with non-nuclear interests. It is favored by regulators, industry, and many politicians. It will not happen nationwide in the current administration, but regional efforts may continue and a national carbon price may be inevitable.

While carbon pricing may be a more politically acceptable solution, it still faces political opposition that make it unlikely in the short term. Tightening RGGI or California’s carbon cap could help nukes in those specific markets but may be politically unviable; excess existing permits may keep prices depressed regardless.

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4. Nationalizing the nuclear fleet

Perhaps the most radical policy proposal to keep the U.S.’s nuclear fleet online calls for government ownership and management of the U.S. nuclear fleet. In short, this option involves nationalization of private nuclear facilities in varying degrees. Although this idea generated considerable interest, there has been limited discussion as to what it would look like in practice.

Nationalization occurs when a national government takes control of an existing private entity. In modern times, the US has practiced both temporary nationalization (AIG and General Motors) and permanent nationalization (Amtrak and TSA).

To use nationalization as a policy solution for struggling nuclear units, the federal government would purchase or take ownership of one or more existing nuclear units.

Critically, nationalization does not mean the government is forcing a mandatory purchase of a nuclear facility. The federal government (via an appropriate agency) could negotiate with a nuclear plant owner on a fair price to purchase the plant voluntarily.

If such negotiations proved unsuccessful, the federal government could seize ownership of one or more existing nuclear reactors using its power of eminent domain. In such a case, the government would need to compensate the owner of the nuclear reactor at a market rate.

Either a voluntary or mandatory nationalization program almost certainly require an act of Congress to grant authority and supply any necessary funding.

To a certain degree, nationalizing the nuclear fleet is not as radical as it might first sound. The federal government has significant technical, operational, and even institutional expertise in nuclear power:

• Nuclear safety, a consideration very much alive at every step of the nuclear development and generation process, falls entirely within NRC’s Federal jurisdiction.
• As of late 2014, the US Navy operated 86 nuclear-reactor powered vessels (75 of which are submarines).
• The Federal government, via TVA and BPA, already owns and operates 8.9 GW of nuclear power at four plants, generating nearly 10% of US nuclear generation.

One of these units, Watts Bar 2, was the first new nuclear unit to come online in two decades in the US last year.

Beyond nuclear power, the federal government already owns and operates much of the nation’s hydropower. Four Federal Power Marketing Administrations marketed 42% of the nation’s existing hydropower in 2012.

Source: EIA

Once the government owns some (or all) existing nuclear facilities, the key question is how markets compensate these plants for their generation.

The economic challenges facing nuclear do not just disappear if the plants are owned by the federal government. Reduced profit incentives (and reduced borrowing costs) only somewhat reduce required market revenues.

Most likely, nationalized nuclear plants would need to be compensated through some sort of cost of service regulation (without a need for a rate of return). If the plants just received market revenues, they would lose money, which would ultimately come from the federal taxpayer. As noted above, regulatory principles generally call for ratepayers to be responsible for compensating electricity costs, not taxpayers.

Since Congressional legislation is required for nationalization, Congress could well mandate in that same legislation that nationalized nuclear facilities receive cost of service compensation from wholesale power markets (i.e. ISOs/RTOs).

As with other potential solutions, timing is a critical factor. Mandatory nationalization is a longer term option for the nuclear fleet but highly unlikely to occur in either the short or the mid-term (energy and cultural norms would have to change before policy).

However, it is possible that a voluntary nationalization program could occur relatively quickly at a targeted scale. Under such a voluntary program, federal power agencies could purchase and then operate select nuclear power plants that would otherwise retire. If structured well, such legislation could minimize direct costs to the taxpayer while also ensuring that nuclear facilities are fully valued for the public goods they provide.

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