A little known fact about "The Hobbit"--the famous fantasy novel by J.R.R. Tolkien--is that it has a subtitle: "There And Back Again." The plot of the novel follows a hobbit named Bilbo Baggins in his quest to win a share of the treasure guarded by the dragon, Smaug. Legend has it that through the subtitle, Tolkien was conveying that Bilbo would face turmoil in his journey ("there") but would survive, be wiser from his experience, and get "back again" to the safe havens of the Shire. Tolkien was also suggesting that such cycles repeat, as it does later when Frodo Baggins has to confront Sauron in the sequel "The Lord of the Rings."

That was Tolkien's interpretation of mean reversion.

Mean reversion in commodities isn't just a statistical condition, it's an economic reality—whether high or low, prices are their own solution. However, reversion to the mean is one of the most common stories in history. It's the main character in economies, markets, and industries.

The nuclear industry has endured its own version of "there and back again" periods. After more than a decade of headwinds, the nuclear power industry received a game-changing impetus with the approval of the federal production tax credits (PTC) late last year, as part of the Inflation Reduction Act.

Here, we're updating our views on U.S. nuclear generation. In a report to be published soon--"What's A Nuclear Power Plant Really Worth?"--we present our views on nuclear distressed and going-concern valuations.

What A Long, Strange Trip It's Been

About 16 years ago the nuclear industry was at its peak as natural gas prices, the fuel that set the price for power, headed way north. Recently deregulated nuclear generation plants were earning abnormal returns from the relative benefits of fuel price differentials. Also, the industry's renaissance was at its zenith and new technologies--from Westinghouse's Advanced Pressurized (AP) 1000 to Areva's European Pressurized Reactor (EPR) to General Electric's Enhanced Simplified Boiling Water Reactor (ESBWR)--were being bandied around. As natural gas prices went on a tear, a new generation of nuclear plants was pitched as the perfect response to fuel volatility and emissions control. Everything appeared beautifully teed up for the U.S. nuclear industry's expansion.

Then, by 2010, these generation assets of past robust growth were faced with a reality check. With a sharp drop in natural gas prices after the global financial crisis and surging supply of shale gas in the U.S., gas-fired power became extremely competitive against nuclear power, and decimated the benefits of the economics of new nuclear construction. Even as these relative economics were evolving, the 2011 Fukushima nuclear disaster in Japan drove the proverbial dagger through the industry's heart. Capital costs started adding up as the U.S Nuclear Regulatory Commission (NRC) required legacy plants and new designs to incorporate lessons learned from Fukushima's meltdown.

A Slew Of Plant Retirements Ensued

Shifting energy markets and other economic factors have resulted in the early closure of 12 commercial reactors across the U.S. since 2013. Ironically, one could almost make the argument that with new nuclear construction costs so much more expensive than anticipated, the value of legacy assets should be higher, not lower, given the importance of nuclear power generation in curbing carbon emissions.

Per government guidelines, original expectations assumed these units would last for 60 years but economic challenges were driving a few early decisions. Six nuclear plants with an aggregate capacity of 4.6 gigawatts (GW; 4.7% of operating fleet as of 2013) have closed. The initial closures were related to operational issues. Two units--Crystal River and San Onofre--shut down due to failed steam-generator replacements. At the time of their respective closures, we considered these unique situations unlikely to be repeated (65 plus reactors in the U.S. have successfully undertaken steam-generator replacement since the Surry nuclear power plant replaced its generators in the early 1980s).

However, a combination of sustained low natural gas prices, penetration of zero-marginal-cost resources, and a slowdown in electricity demand growth rate, significantly eroded the economics of base-load nuclear generation. An additional 5.0 GW of capacity was subsequently retired (see table 1), while more were on the chopping block due to weakening economics.

Table 1

The problem was that market developments that were independent of each other were eroding both the energy and capacity revenues so that neither market was adequately compensating nuclear units. Specifically, changes in market supply curves, induced by changes in fuel costs and the supply mix, lowered the gross margins earned by nuclear units, and this reduction occurred because of changes along both axes of the generation supply curve.

Stated simply, let's assume the cumulative generation supply capacity along the horizontal x-axis and the marginal power generation costs of these units along the vertical y-axis. Then a plot of power dispatch costs (i.e., power prices bid by the units in the day-ahead market) represents the generation supply stack. What's happening is that along the horizontal axes, the entry of new, near-zero marginal-cost renewable resources has pushed the curve to the right, resulting in lower clearing price at the same level of demand, all else equal. At the same time, reductions in marginal fuel costs of natural gas have lowered the slope of the curve.

Not only has the curve flattened, but it has also effectively flipped: Less-flexible units, like coal-fired and nuclear generation, formerly committed as base or mid-merit power supply are now more regularly the marginal resources needed to meet demand. With a flattened generation supply curve, energy prices stay lower most of the time, unless there are weather-related price spikes, making it difficult for the energy market to fully capture the economic rent for profitable nuclear base-load generation.

A Question Of Efficiency As Well As Equity

Economic theory would suggest that deregulation works best when competitive markets are left to decide the lowest-cost reliable provider. But in electric markets there are other considerations such as fuel diversity, clean generation, impact on local economies, and also firm power generation. As a result, regulatory support has been forthcoming to the beleaguered nuclear industry. Examples of this are the nuclear zero-emission credits (ZEC) approved in New York and Illinois, through the states' Clean Energy Standard (CES) and Future Energy Jobs Bill, respectively, that acknowledged the clean attributes of nuclear generation. With the district courts' confirmations of the ZECs after appeals (circa 2018), the momentum shifted in favor of nuclear generators and more requests for ZECs were made. Table 2 presents nuclear units whereby retirements were likely averted due to state interventions.

Table 2

But we'd like to move beyond the details of specific decisions to a more philosophical level. Eventually, the debate on subsidies--for that is what they are--goes beyond just a question of revenue sufficiency versus reliability. It essentially becomes a question of efficiency--the lowest-cost method of achieving an outcome, pitched against a question of equity--the fairest way to achieve the outcome.

Efficiency demands that the price of power reflect the lowest cost of generating it. This was essentially the reason for deregulation in the first place. Based solely on the issue of efficiency, the move toward lower capital cost natural gas-fired generation and lower variable cost renewable generation seems rational. We note that the wholesale electricity markets have responded by effectively driving energy prices toward supplier short-run marginal costs.

Equity, however, is an altogether separate matter. Power is an essential commodity and its resiliency is important not just for commercial and industrial activities, but also for safety across local communities and also national (grid) security. Power generation is also important to communities because it's vital to local growth and opportunities. Decisions at the state level have been influenced by the need to preserve local generation assets and because of the impact they have on regional employment and tax base. The result has been, and remains, a market in which socioeconomic objectives also influence policy actions. Thus, seen through the prism of equity, markets sometimes reflect power prices (or preserves generation assets) that reflect what the local communities, and not just what the market, can bear.

Increasingly, A Question Of Resiliency

Clearly, unregulated rates shouldn't mean the higher of market prices or costs. But proponents argue that state actions weren't against competitive markets. Nuclear power currently provides about 50% of the nation's 100% clean electricity. Many participants saw the ZECs as no different from the PTCs, or renewable energy credits (REC), of which the renewable industry is itself a beneficiary.

We also think interruptible power has limitations and can hurt market economics. While as-produced renewable contracts deliver cheap and clean power, they don't deliver firm power. In the process, renewables have unwittingly discouraged baseload generation, especially those with relatively low variable operation costs but high fixed costs. There is now a growing sense that the rapid growth in variable resources has made the grid less resilient.

Some of this concern is valid. To fully supplant nuclear generation, renewable power has to be able to scale and become firm. Stated simply, renewables generation has not yet walked the walk. Similarly, in winter events, gas delivery to power units has often disappointed.

Milder Events Are Harbingers Of Impending Major Ones

A winter storm that may have been overlooked--but one that came close to major outages--is the Northeast cold snap in December 2017. The extended cold spell spiked demand for natural gas, and supply constraints (which often happens in New England) raised natural gas prices dramatically. However, the New England market is different than the Electric Reliability Council of Texas (ERCOT) in that it has plenty of dual-firing capability. These older assets with oil-fired capabilities are expensive but serve as physical options. From Dec. 1, 2017, until the cold spell ended, oil and coal plants contributed less than 1% of the energy generated by New England power plants. Between Dec. 26, 2017, and Jan. 8, 2018, oil contributed an astonishing 27% (see charts 1 and 2).

Chart 1

Chart 2

During those two weeks, New England generators burned through about 2 million barrels of oil. That's more than twice the oil used by New England power plants during all of 2016. Oil inventories declined to 20% of capacity from 70%. A blackout was averted only because the weather let up. Yet, diversity in generation sources, and storage of fuel supply helped--as did a quiet, heroic run by the Millstone nuclear unit. A subsequent New England Independent System Operator (ISO) briefing noted that electricity produced by the Millstone nuclear station during the December 2017 cold spell was equivalent to what could be produced by about 880,000 barrels of oil. The fact that Dominion Energy's (BBB+/Positive/--) owned Millstone nuclear unit's sturdy run potentially warded off a Northeast blackout isn't lost on us.

The Grid Has Tightened

While renewable resources have disrupted the grid by displacing baseload units, they are often able to provide only interruptible power that potentially jeopardizes the reliability of the grid. Wind generation appears to be highly correlated across regions and also binary--either available in plenty, or not blowing at all. To make matters worse, the uncertainty created by the Department of Commerce's (DOC) tariff circumvention investigation for solar panels manufactured in Southeast Asia during the first half of 2022 delayed the solar buildout last year, and affected panel orders for 2023. Firming renewable generation is a bit difficult anyway because energy storage is still in the early days of being built out.

Yet, no incumbent utility or power generator is investing new money in coal generation units or coal mines. Coal units are increasingly under-maintained and with eastern coal prices moving higher, the economics of coal-fired generation is deteriorating. In mid-March 2023, the Environmental Protection Agency finalized its Cross State Air Pollution Rules (CSAPR) rules. The rules will set nitrous oxide (NOX) levels beginning this year, becoming more stringent in 2026, and moving away from "banking allowances" by 2030.

Also, with effluent limitations guidelines (ELG) and coal combustion residuals (CCR) regulations to follow, along with 30% of the coal fleet in affected states not controlled for selective catalytic reduction (SCR) equipment, we think a next wave of coal-fired retirements by 2027 is likely. Against the run of play, however, increasing tightness of generation supply has pressured utilities in the Midwest-ISO (MISO) to extend the retirement dates for several coal plants (NiSource Inc., Alliant Energy Corp., WEC Energy Group Inc. and the Omaha Public Power District have all announced delays in closures). MISO is traditionally a bastion of surplus capacity but higher load and more retirements have eroded surplus. The tightness was reflected in market signals with MISO capacity auction clearing at $237/megawatts (MW) per day, up from $5/MW/d last year.

We've seen reliability issues in California ISO (Cal-ISO) and ERCOT regions each year since 2020. This is happening because baseload plants have been retired and replaced with intermittent renewables. In a recent analysis, the Cal-ISO pointed to the potential for 1.7 GW-1.8 GW supply shortage across 2022-2025 in extreme load scenarios even when accounting for the 11.5 GW new resource target. On Sept. 7, Cal-ISO declared a regional transmission grid energy emergency (EE) 3, which indicates high likelihoods of blackouts. Temperatures soared above 110 degrees but blackouts were avoided with help from demand response as the state experienced a load of 52 GW. In response to the increasing baseload shortage, California lawmakers have recently provided Pacific Gas & Electric Co. the option to extend Diablo Canyon's retirement by an additional five years from its previously planned shutdown of 2024-2025.

Arguably, the simultaneous advance of environmental regulations, and a tightening demand/supply can end up in bitter fashion for the grid. We think large base-load firm generation that also provides fuel diversity and clean attributes could be an important part of the transition away from fossil generation.

The Game-Changing Production Tax Credits

While much of the focus in the news recently has been on clean power, we think this is only part of the story. Firm power is where nuclear generation has delivered consistently and is increasingly supporting the grid. Clearly, Winter Storm Uri, which overran Texas in February 2021 came past the Midwest, where we saw nary a problem. Similarly, we saw nuclear generation delivered a strong run that vitally supported the grid during Winer Storm Elliott this past December in the PJM.

There is a growing understanding that inaction comes at a cost, including greater risks to reliability and higher emissions when it's more economical to burn oil than natural gas. However, all options for firming power are somewhat costly, whether a regional transmission organization chooses to invest in renewable energy with the related transmission, or fuel infrastructure with long-term contracts. In other words, a region can pay for its fuel-security risks periodically, in spiking wintertime prices and potential energy shortages, or it can pay the costs proactively and avoid reliability risks by investing in infrastructure, firming renewables, firmer fuel contracts, but also includes maintaining a diverse fuel mix, such as nuclear generation.

Replicating a firm renewable energy contract is illustrative. We've seen as-produced solar power contracts in the $25/megawatt per hour (MWh) area. By the time firming shape is included around generation, resource adequacy payments, RECs, and a risk premium, it all adds up. The Geysers--a network of 725 MW of geothermal assets owned by Calpine Corp. (BB-/Stable/--) in California--are probably among the best forms of firm renewable energy in the country. These contracts aren't contracted at $25/MWh; not even close. These contracts are significantly above market. We estimate those power contracts are north of $65/MWh.

All regulators appear to have noticed the importance of firm power delivery. Over the past two years, there was also a structural shift in the regulatory view of the distressed nature of the nuclear industry and their willingness to act to preserve this clean and firm source of power generation. Even before the passage of the Inflation Reduction Act, the Department of Energy established a $6 billion program to preserve the nuclear energy infrastructure. The law created the Civil Nuclear Credit (CNC) program, allowing owners or operators of commercial U.S. reactors to apply for certification and competitively bid on credits to help support their continued operations. Similarly, a clear goal of the Inflation Reduction Act is to decrease demand for fossil fuels while providing incentives for consumer and commercial users to switch to renewable energy sources. But it also focuses on firming up generation supply, specifically by helping merchant nuclear generation stay online by providing a floor price through the approvals of the federal PTC's. The inflation adder to the PTC could be a powerful driver of growth too.

Much like Tolkien's hobbit, the nuclear industry has fought its dragons and recovered. Well, at least through the PTC floor regime.

(In the accompanying commentary to be published soon, we discuss the PTCs and how they influence assumptions for asset values in our recovery analyses.)