On August 27th, 2020, Exelon Corp., one of the largest providers of nuclear power in the United States, announced that it would close two of its nuclear plants in northern Illinois, called Byron and Dresden, in roughly one year’s time, even though the plants are licensed to operate for decades more. The plants “face revenue shortfalls in the hundreds of millions of dollars,” Chicago-based Exelon said at the time.
Exelon also said it may need to bring forward the closure dates of two other northern Illinois plants, LaSalle and Braidwood. Altogether, Exelon’s announcement suddenly meant that an additional nine gigawatts of nuclear power capacity — close to 10% of the nation’s total — might close long before they would otherwise need to. It would be an extraordinary loss of low-carbon power and a blow to President Joe Biden’s plan to decarbonize the nation’s power sector by 2035.
Exelon had warned repeatedly that the two plants, Byron and Dresden, faced the possibility of early closure. A deluge of cheap natural gas unleashed by America’s fracking boom has pushed power prices steadily lower in recent years, meaning nuclear plants bring in far less revenue than they once did. One late 2018 study found that more than one-third of the 90-plus nuclear reactors throughout the U.S. were unprofitable or scheduled to close. Another study in 2017 by Bloomberg New Energy Finance found that more than half were losing money. “The outlook today is pretty similar,” the author of that report, Nicholas Steckler, told Forbes.com.
Still, several state and local officials reacted incredulously, arguing that Exelon’s plants were viable and that it was trying to pressure lawmakers in a bid to win subsidies. After all, Exelon had made it clear in its announcement that it was open to keeping Byron and Dresden online if changes are made in the way regional electricity markets pay out money to power plants in ways that would benefit nuclear and other low- or zero-carbon power sources. Nor would it be the first time that nuclear power companies, Exelon included, had seemed to threaten to close a plant unless new financial aid was granted — and won it.
One of these accusations, from Illinois state senate president Don Harmon, cut deep. Harmon pointed out that an independent economic analysis of nuclear plants in Illinois and other states had concluded Exelon’s plants were, in fact, economically viable in the long-run and not at risk of early retirement.
“Independent market monitors believe these plants can be profitable,” Harmon said in a statement, referring to the independent companies tasked with performing regular reviews of competition and revenues inside power markets. Harmon added that he might seek to write legislation that would require Exelon to sell the plants before they could be closed down.
Harmon had a point. A federally chartered outside group had indeed concluded in its then-latest report that Byron and Dresden were financially sustainable and wouldn’t be justified in retiring. The finding directly contradicted Exelon’s announcement.
Even to close observers of America’s nuclear industry, it might have been hard to know whom or what to believe: the independent experts, or the company that actually runs the plants?
This investigation, based on scores of interviews with industry insiders and a review of industry reports and data, unpacks key arguments in this controversy. With little prospect of a big recovery in electricity prices in coming years, it is all but certain that more nuclear plants will seek early retirements in coming months and years unless lawmakers bail them out. When that happens, lawmakers will turn to the experts known as “Independent Market Monitors” around the country — such as the one cited by Harmon — to help determine how credible the industry’s claims are. Their decisions will determine whether America’s nuclear plants have decades more to live, or whether the industry will shrink in size far earlier than anticipated.
Independent Market Monitors, of course, aren’t the only expert groups who study the profitability of nuclear plants. At least one other recent study, by analysts at investment bank Morgan Stanley, has suggested that Exelon’s Byron and Dresden plants are indeed money-losing. But Independent Market Monitors arguably matter more in that they are federally chartered and continually review power plants’ revenues and costs rather than perform one-off studies.
For now, the battle over the industry’s profitability resides squarely in Illinois, which has the most nuclear plants in the U.S.
State lawmakers there are already scrambling to save the plants. One piece of legislation, introduced in December, would grant Byron and Dresden a version of the financial aid that Exelon has asked for. Such support would be similar to financial aid that already supports two of Exelon’s other Illinois nuclear plants, Clinton and Quad Cities, approved after a similar high-stakes showdown that ended in 2016 when Illinois approved ratepayer subsidies as part of the Future Energy Jobs Act. Also on the table is Exelon’s preferred option: broader legislation that would involve the state’s taking over responsibility for a portion of the power market for northern Illinois and ultimately causing more revenue to flow to Exelon’s nuclear plants. A group of environmental and consumer groups called the Illinois Clean Jobs Coalition is also a supporter of that option.
But it’s unclear whether such efforts will succeed. Exelon and one of its subsidiaries, the utility Commonwealth Edison or ComEd, lost favor and political clout in the state last year after it agreed to pay $200 million to federal prosecutors to avoid criminal liability in an alleged bribery scheme, a scandal that rocked the state’s political class. ComEd was accused of steering jobs, contracts and payments to people connected to former Illinois House Speaker, Michael Madigan, in exchange for legislation benefiting ComEd.
Nor does Exelon enjoy the support of Illinois governor J.B. Pritzker. Shortly after Exelon’s late-August 2020 announcement that it would close the Byron and Dresden plants in September and November 2021 respectively unless additional financial aid is approved, Pritzker’s office declared acerbically that “the utility companies will not write the legislation to get the state” to its clean energy goals. The governor has instead said he would prefer implementing a carbon fee and other measures that would generate some extra revenue for Exelon’s but not as much as the company is calling for. Pritzker put forward that proposal on August 21st, just one week before Exelon said it would shut Byron and Dresden. It’s far from clear that such a proposal is still viewed as doable.
To vet Exelon’s claims that its plants aren’t economically sustainable and need financial aid to avoid closure, the government’s Illinois Environmental Protection Agency has now finalized a $215,000 contract with Synapse Energy Economics, a research and consulting firm, to report on the current and projected costs and revenues of Exelon’s nuclear plants over the next five years, Crain’s Chicago reported three weeks ago. That report is due on April 1st.
Based on Exelon’s closure timetable, the governor and other Illinois lawmakers would have just two months beyond that point to decide whether to take action to rescue the plants or let Exelon wind them down.
***
Few disagree that the nuclear power industry, both in Illinois and throughout the nation, is in worse shape than it was five or 10 years ago. Study after study has shown that nuclear plants are bringing in far less revenue than they did a decade ago, largely as a result of declining electricity prices.
Some three-quarters or more of the roughly 20 active nuclear plants in the Midwest and Northeast that sell electricity directly into power markets have either announced early retirements or are receiving financial credits to stave off early retirement, according to a review of public documents.
Yet there is controversy over just how poorly nuclear plants are faring, and if they are faring poorly enough to have no choice but to close down or receive subsidies.
Normally, a simple examination of plant costs and revenues would clear this up. But as a rule power generation companies don’t disclose plant-by-plant data, citing fiduciary obligations and the marketplace edge such information would give to rivals. That leaves outsiders to take nuclear companies at their word. (Exelon has said that it will let policymakers have a look at some plants’ detailed data upon request.)
This is where specially appointed “Independent Market Monitors” play a big role. By decree of the nation’s main energy markets authority, the Federal Energy Regulatory Commission (FERC), each of the seven regional electricity markets in the U.S. must be regularly reviewed to ensure they are fair and competitive. The companies that perform these reviews are called Independent Market Monitors (IMMs). They are typically private companies staffed by energy experts.
Each IMM produces dense, statistics-packed reports whose bottomline takeaways are relied upon by regulators and policymakers to craft market policies.
IMM reports have occasionally offered up powerful ammunition to lawmakers seeking to counter the nuclear industry’s claims that it is losing too much money to keep plants up and running without subsidies. In New Jersey, one December 2017 report by an IMM — incidentally, the same IMM that oversees Exelon’s jeopardized nuclear plants in Illinois — said that energy company PSEG’s nuclear plants were in fact financially sustainable and not at risk of early retirement, contrary to PSEG’s claims. (Lawmakers did eventually approve subsidies for the three plants despite the report’s finding, but they weren’t happy about it. As one member of New Jersey’s Board of Public Utilities put it: “The board is being directed to pay a ransom and the hostages are the residents of New Jersey.”)
The electricity market that includes Exelon’s Byron, Dresden, LaSalle and Braidwood plants is called the PJM, and it stretches from northern Illinois all the way to Washington, D.C. In the PJM, the role of the IMM has for years been performed by a Pennsylvania-based company called Monitoring Analytics. Monitoring Analytics officially reports to PJM (which is also the name of the market operator) but since 2008 it has operated externally and enjoys complete independence.
Every quarter, Monitoring Analytics publishes several hundred pages of numbers and analysis known simply as the “State of the Market” report. It was almost certainly a few pages of the then-latest “State of the Market” report, published in mid-August, that drew the attention of Harmon, the Illinois senate president who threatened to write legislation to force Exelon to sell Byron and Dresden before it could shut them down. Buried inside hundreds of dense pages in the report was a striking finding: Byron and Dresden remained financially viable in the long run and were not at risk of early retirement.
The claim ran directly counter to Exelon’s own assertions that the plants are now inherently unprofitable as a result of low power prices.
As economist Joe Bowring, the president of Monitoring Analytics and the report’s main author, explained in an interview, the purpose of this section of the report is to determine whether markets are sending any nuclear plants inside the PJM a “retirement signal,” which is what happens when the costs of running them exceed the revenues. And in the report’s projections for 2021, that simply wasn’t the case for Byron and Dresden. Using the prices of future-year electricity market contracts (or “forward” prices) to derive a revenue projection, and using average nuclear industry cost data to derive a cost projection, the plants’ revenues were still projected to turn out higher than costs.
Since then, Monitoring Analytics has published another of its quarterly “State of the Markets” reports. It reaches similar conclusions. On page 371 it finds that only two of the 16 nuclear plants inside the entire PJM, and neither Byron nor Dresden, are projected to lose money in 2021. (That is to say, only two plants — Ohio’s troubled Davis Besse and Perry plants — are expected to have revenues exceeding core or “avoidable” costs.) In fact, the report says, the Byron and Dresden nuclear plants are on track to have “surpluses” (where revenues exceed core costs) in 2021 of as much as $89.7 million and $95.3 million respectively, more than most other nuclear plants in the PJM.
Of course, the report does find that in 2020 the Covid-induced economic downturn likely caused net revenue losses at all 16 of the plants. But in 2021 as well as 2022, it suggests, things are looking much better.
“In the first half of 2020, they [Byron and Dresden] are not covering their costs,” Bowring said. “But the fact that prices were really low in the first half of 2020 doesn’t mean they need subsidies….these are 40-50 year assets at least. Long-lived assets are not valued over the short run.”
Exelon has big problems with much of this.
The company argues that, because of faulty methodology that underestimates the true costs of running nuclear plants, Monitoring Analytics’ reports overstate nuclear unit profitability by between $7 and $18 per megawatt-hour of electricity sold from the plants. That’s not trivial. Monitoring Analytics’ latest report estimated Byron would have a $4.77 “surplus” per megawatt-hour in 2021 while Dresden would have a $6.49 surplus per megawatt-hour, so an error of the magnitude Exelon alleges is more than enough to make its unprofitable plants seem perfectly viable, according to the company’s logic.
“The continued operation of Byron and Dresden is uneconomic under current energy market policies,” said an Exelon spokesman, Bill Gibbons. “[T]hese emissions-free plants are facing shortfalls in the hundreds of millions of dollars.”
How could Monitoring Analytics’ accounting of nuclear costs and revenues have produced such a different view of things than the one Exelon says is the case? There are a handful of areas of disagreement.
To include or not to include capacity market revenues?
In the dead of winter, or in the heat of summer, demand for electricity can sometimes surge as households and businesses crank up the heat or the air-conditioning. On such occasions, there is a risk that not enough power plants will be available on short notice to supply all the needed power, creating the possibility of a power shortfall and, ultimately, blackouts.
To ensure this doesn’t happen, governments direct market operators — the firms that run regional electricity markets — to pay money to power plants in exchange for the plants’ guarantee that they will be standing by, ready to respond to power surges, during these specified high-risk periods. (On any given day, some power plants will be offline, either to perform maintenance or because they simply have no reason to be online. But in the event of a power demand surge those plants and all other plants are needed to meet the surge.)
The contest to earn a share of that money is called a capacity market auction. These auctions are highly competitive, and for a good reason: the “commitments” to provide capacity (akin to contracts) can be worth tens of millions of dollars, in exchange for an obligation that may never arise.
Exelon’s Byron and Dresden plants, plus most other nuclear plants, have traditionally been consistent winners of the annual capacity market auctions run by the PJM. (While nuclear plants have high fixed costs, such as their construction, their day-to-day operating costs are typically quite low.) But in recent years, Byron and Dresden have either lost out entirely or won only partial commitments, costing them huge amounts of revenue. Crucially, in 2018 Dresden and all but a portion of Byron did not clear that year’s capacity auction, depriving them of revenues they would have received in exchange for standing by to provide power in 2021-22 and a major reason why Exelon has said they are unprofitable. (Capacity market auctions are typically held several years ahead of when the obligations would actually take effect.)
Exelon has said this is because its competitors, such as natural gas power plants, now routinely out-compete them thanks to falling natural gas prices and the absence of a tax or other penalty on carbon emissions inside the PJM market. If there were a carbon tax, it would have the effect of raising the costs of gas power production while leaving untouched the costs of nuclear power production, which emits very little carbon. (Exelon also blames a 2019 rule implemented by FERC that restricts the amount state-subsidized resources are allowed to bid, limiting their competitiveness against non-subsidized power sources, such as coal or gas plants. The rule could change under the Biden administration.)
Monitoring Analytics, the Pennsylvania-based firm tasked as the IMM with overseeing the PJM electricity market, does not dispute that Exelon’s Byron and Dresden have not won commitments. But it does argue that whether a given plant “clears” (or wins a commitment in) the capacity market auction is a result, technically speaking, of the “offer behavior” of the plants, and not of the economic viability of the plants, unless they offer accurate costs. (“Offer behavior” simply refers to how much money a given power plant chooses to ask for from the market operator, PJM, in return for accepting one of the commitments. A plant may choose to “offer” to take one of the capacity market commitments in exchange for a certain amount of money.)
For that reason, when tallying up nuclear plant revenues to determine whether the markets are sending any of the plants a “retirement signal,” Monitoring Analytics assumes that Byron and Dresden won full capacity market revenues, even when they have not won or won only partially. This makes them seem more profitable than Exelon acknowledges.
“It would be a mistake to treat the units as being financially challenged based on their own decisions,” Bowring, the Monitoring Analytics head, explained. “This is especially true when units are covering their costs based on capacity market revenues but are not covering costs without capacity market revenues” — as seems to be the case with Byron and Dresden. “Arguing that a subsidy is needed because owners chose not to clear [win commitments to provide capacity] in a capacity auction does not make sense.”
Exelon has said there isn’t any way to bring down its plants’ costs any further than it already has, and that the current cost levels are too high to make the plants consistently competitive in the auctions.
By including the capacity market revenues in its revenue projections even for plants that didn’t actually secure capacity market revenues, Monitoring Analytics is overstating revenues at some nuclear units by as much as $8 per megawatt-hour, Exelon has said. That would work out to something like a quarter or more of the revenue at the average Exelon nuclear plant, based on industry revenue data: enough to tip an otherwise money-losing plant back into the green, at least on paper.
Byron and Dresden were far from the only nuclear plants in 2018 to fail to clear the capacity market auction. As many as 10.6 gigawatts of nuclear power — the equivalent of four or five nuclear plants, or a third of the entire nuclear fleet inside the PJM power market — failed to clear the 2018 capacity market auction. (See pages 95 and 96.)
Do other studies of nuclear plants’ profitability also assume that plants could have won capacity market commitments even when they did not win?
At least two other recent studies of the nuclear industry’s profitability did not.
One study by an analyst at Morgan Stanley did not include in its revenue assumptions any capacity market revenues for nuclear plants that failed to win commitments in given years. The author of the report, Stephen Byrd, discussed the study’s findings at a virtual conference held by PJM, the market operator, earlier this year.
In an interview, Byrd said that he wasn’t familiar with the methodology used by Monitoring Analytics, but that in general plant owners have a strong incentive to bid their lowest costs. “Plant owners want their plants to live,” he said. “So they bid their costs, and if they weren’t selected [as winners in the auction], it means their costs were higher than other bidders.”
The Morgan Stanley study found that Exelon could increase its earnings before interest, tax, interest, depreciation and amortization (EBITDA) by $260 million in 2022 if it closed the Byron and Dresden plants. (EBITDA is a profitability metric that focuses on the efficiency of a company’s assets before financial considerations, such as amounts paid on interest.)
Another analysis took a similar approach. For an October 2018 study of the profitability of nuclear plants across the U.S., the Union of Concerned Scientists (UCS), a non profit research outfit, used projections of plant operating costs and revenues from S&P Global Market Intelligence, a division of the market research firm S&P Global.
In the study, Market Intelligence did not include capacity market revenues for Byron and Dresden for the years in which they failed to win capacity market commitments, according to Steve Piper, one of the study’s coauthors. (In 2018, Dresden and all but a portion of Byron did not clear that year’s capacity auction.)
“For the study UCS phased out capacity payments for Byron and Dresden based on knowledge that those plants in particular didn’t clear [the auction] held in 2018 for the 2021/2022 reliability year and holding that assumption constant going forward,” Piper said in an email.
Nevertheless, Market Intelligence does in general assume that nuclear plants clear capacity market auctions. The reason, Piper explained, is that PJM, which runs the auctions, doesn’t disclose auction results at the level of individual bidders, so it is impossible to know which plants won commitments and which didn’t — unless the plants’ owners publicly declare the results, which is what Exelon did in 2018.
“In the data we publish, we assume everybody clears and leave it to the portfolio holders” to do further calculations of the data, Piper said in an interview.
Of course, prior to 2018 there would not have been much of a need to consider whether a nuclear unit that failed to clear should be assumed to have been capable of winning the revenues. Back then, it was much less common for a nuclear unit to fail to win capacity commitments.
* For an additional point about the IMM’s capacity market methodology, see the bottom of this story.
Costs of running a plant vs. running a plant and managing the business
When calculating the costs of running nuclear plants, the IMM says it includes only those costs incurred in running a given plant, leaving out any involved in managing the overarching business. Expenses that are left out, for example, include property taxes, depreciation of assets through wear-and-tear, spent fuel costs, interest paid on debt, and market risks such as arise when prices of power contracts fluctuate.
Monitoring Analytics (the IMM) is not alone in its approach. Steve Piper of Market Intelligence, the S&P unit that helped the Union of Concerned Scientists with its October 2018 study of all US nuclear plants, said they also chose to focus on the costs of operating individual plants rather than the costs of managing the overarching business as well.
“In terms of costs, our cost projections don’t take into account expense categories that are reported at the owner or holding company level, which would include management expenses and property taxes,” Piper said. “Our expense estimates tie back to cost categories reported at the plant level in annual FERC Form 1 filings, and these generally map back to cost categories used in the NEI surveys.” (Form 1 filings are separate disclosures of costs by the Federal Energy Regulatory Commission.)
Exelon officials and other nuclear industry players say that by relying solely on costs incurred in running — or indeed simply powering on — a nuclear plant, while excluding costs involved in managing the overarching business, Monitoring Analytics is under-estimating true expenses.
When doing its own cost and revenue projections, Exelon accounts for a number of risks that Monitoring Analytics does not include; it does this mainly by assuming higher costs. (The risks fall into one of two categories, Exelon says. “Operational risks” include everything from the risk that a nuclear outage will occur to the risk that actual operating costs will be higher than projected costs. “Market risks” include, for instance, the risk that market prices of electricity for future years will turn out lower than the market currently expects.)
The Nuclear Energy Institute (NEI), which publishes the annual aggregate costs that Monitoring Analytics uses, acknowledges that these costs alone are not sufficient for determining profitability of individual plants. “These costs are not intended to represent a full financial analysis on the profitability of the plane alone,” said NEI’s Matt Crozat, senior director of policy development at NEI, in emailed comments. The costs the IMM excludes are “critical factors in making business decisions for a particular plant,” he said.
Bowring rejects the characterization of these expenses as essential. The IMM’s job is to determine whether markets are sending plants a “retirement signal,” which is what happens when the costs of running a given plant — Monitoring Analytics calls them “going forward costs” — exceed the revenues generated from running it, Bowring said. Bowring doesn’t deny that there are costs involved in managing the overarching business, but for the purpose of sussing out whether a given plant is sending a retirement signal, they are simply beside the point, he suggested.
“We are focusing on going forward costs…which do not include the return on and of capital (depreciation, interest, returns),” Bowring wrote in an email. “Those costs are real, but they are not going forward costs, and not relevant to the retirement decision.”
Assume future costs are stable, or increasing?
The average cost of running a nuclear plant in the U.S. has decreased in almost every year since 2011.
Data collected by the Nuclear Energy Institute (NEI), an industry body, document this gradual erosion of costs. Charts in the NEI’s 2019 data release (pages 4 and 5) show that the industry’s annual capital costs have decreased between 2012 and 2019 in every year except 2014 when they were little changed. Likewise, they show that annual operating costs have also fallen in every year during that span, with the exception of 2014, when they rose slightly. (Operating and capital costs are two of the industry’s primary cost categories.)
Because of these steadily declining costs, Bowring believes, it is appropriate to assume that costs in the future will remain roughly the same as 2019 costs (the most recent year for which costs are now available), which is essentially the approach that Monitoring Analytics’ quarterly and annual reports take. Even better, according to Bowring, would be to expect costs to fall in subsequent years, just as they have in recent years. But he prefers not to push it.
“The costs face deflation and not inflation,” he said. “We chose to use the actual costs as reported by NEI [the Nuclear Energy Institute] as the most conservative approach.”
Exelon disputes this method of projecting future costs. By assuming that costs will remain stable in the future, it says, Monitoring Analytics’ reports are under-representing the likely future costs of operating huge and complex nuclear facilities. In its own projections of future costs, the company also accounts for expected inflation in the general economy as well as other market risks not reflected elsewhere.
The question of uniform data
Since Monitoring Analytics is not able to publish actual plant-by-plant costs — and, for the most part, it does not have access to them in a comprehensive fashion — it instead relies on average costs as published by the NEI and assumes each plant incurs this average cost.
The result is that 14 of the 16 active plants inside the PJM market in 2019 were all assumed to have the same base operating cost of $28.38 per megawatt hour. (See page 367.) (The two with different costs, Ohio’s Davis Besse and Perry, are single-reactor as opposed to dual-reactor plants and are assumed to have higher costs of $38.40 per megawatt hour. This is a major reason why those two plants are the only ones the IMM expects to lose money in 2021.)
There is an obvious downside to this approach. Even though each plant has unique characteristics that cause its running costs to be either higher or lower than the average, such differences are not reflected in the IMM’s approach nor in other studies that rely on similar, public data. That leads to understating of costs and revenues at some plants and overstating it at others.
Exelon will not say whether the running costs of its plants vary substantially, nor how much Byron and Dresden’s vary from the average. It is possible that the two plants’ costs are relatively lower than the industry average, since they are not as old as some other plants in the fleet, which would mean that the IMM’s reports are actually overstating expenses in this respect.
Monitoring Analytics does substantially differentiate the financials of plants in other ways, of course. For example, revenue from sales of electricity in the market, which are a factor of electricity prices on any given day, are adjusted to account for the geographic location of plants and other characteristics.
The consequences of jargon
These technical details can be mind-numbing. Yet what Illinois lawmakers make of them has tremendous real-world consequences.
If Illinois lawmakers reject the view that the plants are economically viable, they might decide to subsidize the plants through increases on utility bills, costing households tens or hundreds of millions of dollars at a time when budgets are already stretched. Conversely, if lawmakers believe the plants are financially sustainable and decline to subsidize them with scarce taxpayer dollars, the plants could well close, putting thousands of plant employees out of work and likely putting Illinois’ clean energy goals for the coming decade beyond reach.
One thing seems clear: Exelon means business. On perhaps the only occasion when an Exelon plant failed to obtain the bailout it said was needed to keep nuclear units online, involving a reactor in Pennsylvania, Exelon indeed shut the unit down as scheduled in September 2019.
* Continued from above section on capacity markets:
Another point of contention has to do with precisely what amount of capacity market revenues the IMM (or Monitoring Analytics) is projecting for the nuclear plants inside the PJM.
When building in capacity revenue assumptions for nuclear plants in the PJM for purposes of determining their potential profitability in a given year, the IMM uses the amount of revenue that resulted from the capacity auction’s “clearing” price, or the price at which the PJM’s auction ended. This amount of revenue is also projected for even those plants — such as Dresden — that didn’t clear in the auction. Yet if Byron and others had indeed cleared, the “clearing” price would have dropped further and the revenues assigned to all the plants, including Dresden, would be lower.
In other words, the IMM is assuming that nuclear plants could win revenues that in actual fact would vanish or shrink in size the moment they entered the capacity market to try to secure them.
This effect is not small. As the IMM noted in a review of the capacity market auction held in 2018 (for the procurement of capacity in 2021/22), assuming that all nuclear plants cleared that auction — technically speaking, that each offered $0 per MW-days — would have caused the resulting capacity market revenues to decrease by $4.1 billion, or 43.9 percent, compared to the actual results.
Although this method may not be completely ideal, Bowring said, the IMM pursues it because there is a lack of good alternatives. Any other method for apportioning the potential capacity market revenues for nuclear plants would involve, first, assigning capacity market revenues based on mere counterfactuals rather than actual outcomes and, second, artificially decreasing the capacity revenues for those nuclear plants that in fact did clear the capacity auction, thus introducing another distortion.