The pair of 1950s-era coal plants bailed out under Ohio’s House Bill 6 law are likely to remain unprofitable even after a surge in grid operator payments to generators, experts say. 

The PJM Interconnection grid market makes capacity payments to line up power to meet expected demand in the years ahead. Aging, uneconomical coal plants are being retired at a time when data centers and manufacturers are starting to use more electricity, causing future power generation prices to rise.

But even record-high prices in PJM Interconnection’s recent capacity auction won’t cover the hundreds of millions of dollars in subsidies paid by ratepayers to cover Ohio utilities’ costs for the Ohio Valley Electric Corporation’s Kyger Creek and Clifty Creek power plants.

“Even with a super high price, OVEC is still going to be in the red,” said Neil Waggoner, Midwest manager for the Sierra Club’s Beyond Coal campaign.

The ratepayer subsidies are a result of HB 6, the 2019 state law at the heart of the largest corruption scheme in Ohio’s history. Republican legislative leaders have blocked all efforts to repeal the coal subsidies from coming to a floor vote.

This year alone, ratepayers are on track to pay nearly $200 million to prop up the two plants, one of which is in Indiana. By 2030, total ratepayer costs from the bailout could exceed $1 billion, according to RunnerStone, a consultant for the Ohio Manufacturers’ Association.

Starting next summer, the payments for generators to be ready to supply electricity when PJM Interconnection needs it will jump to about nine times the current rate for most of the grid operator’s service region. 

“Put simply, the market pays participants for the promise to produce electricity when called upon by PJM,” said Daniel Lockwood, a spokesperson for the regional grid operator. An auction sets the levels for each year’s capacity payments, and the payments go to generators that bid the clearing price or less.

A spokesperson for the power plants did not directly answer the Energy News Network’s question about whether both cleared the latest PJM auction, although he described the auction results as “positive.”

“The auction results were a positive development for the OVEC plants and are more broadly a signal to the market that additional generation resources are needed in the PJM region,” said Scott Blake, a spokesperson for American Electric Power and Ohio Valley Electric Corp. While the HB 6 rider charges depend on multiple factors, the impact of the 2025/2026 capacity pricing “is expected to be positive for customers,” he said.

AEP is OVEC’s largest shareholder, along with other utility companies in Ohio and other states.

HB 6’s OVEC subsidies currently require Ohio’s residential utility customers to pay between $1.30 and $1.50 per month, depending on whether their utility is owned by AEP, AES Ohio, Duke Energy or FirstEnergy, according to PUCO data from spokesperson Brittany Waugaman. Businesses pay for the rider, too. The HB 6 rider’s net total costs last year were more than $148 million.

Doing the math

While capacity payments will reduce the OVEC plants’ total costs to Ohio ratepayers, the revenue won’t, in itself, make the plants profitable.

Expert testimony from a Michigan case last year found the OVEC plants would need capacity payments averaging about $418/MW-day for several years to become economical. Last month’s record-high price that will take effect next summer was about $270/MW-day.

Economic analyst Devi Glick of Synapse Energy Economics testified in the case on behalf of the Sierra Club.

“To massively oversimplify the economics of the OVEC plants, there are two categories of costs and two categories of revenues,” Glick told Energy News Network. “Costs are on one side of the equation and revenues on the other.”

Based on then-current projections for costs and energy market revenue, Glick calculated what the plants’ capacity revenues would have to be for the equation to balance out.

Several caveats would apply, Waggoner acknowledged, including any differences from last year to this year that could affect projected energy revenues. Nonetheless, he noted, a significant gap would remain.

Glick’s estimate of about $418 as a break-even capacity price for the OVEC plants is realistic and may even be conservative now, said John Seryak, managing partner for RunnerStone.

“PJM is no longer paying for a coal plant’s full power capacity anymore under new rules it created just prior to this capacity auction,” Seryak explained. “That could mean that OVEC needs even higher-priced capacity and energy to be profitable.”

“Future energy market prices, OVEC’s future coal costs, and OVEC’s environmental compliance costs will also be important factors determining the extent of its losses or profitability,” Seryak continued. “All that said, we do not anticipate OVEC operating at a profit without further price increases.”

Meeting energy demand

Blake emphasized the OVEC plants’ role as a “reliable generation resource for our customers and for our region,” adding that the HB 6 rider “ensures that customers in Ohio receive electricity from OVEC for what it costs to produce it and the funds are used to pay down debt with no proceeds going to shareholders.”

That’s not exactly correct, said attorney Kimberly Bojko at Carpenter Lipps, who represents the Ohio Manufacturers’ Association in cases at the Public Utilities Commission of Ohio. “Customers pay the cost to operate and run OVEC and the power produced from OVEC is then sold into the wholesale electric market,” she said. Any revenue offsets the costs of HB 6’s coal subsidy.

The Ohio Manufacturers’ Association also has disputed the use of the HB 6 rider to pay down the OVEC plants’ debt in cases before the PUCO.

“By using ratepayer funds to pay down its debt, AEP Ohio is essentially shifting its bad debt to the Ohio ratepayers,” Seryak said. “It’s akin to if a person forced their neighbor to pay for their mortgage payment.”

“Customers pay for more than just OVEC’s debt, though,” Seryak added. “Customers also pay for losses in the energy market OVEC incurs. When this occurs, it means the electric grid does not need OVEC for reliability. Instead, OVEC is burning coal pointlessly at a loss and charging it to Ohio’s ratepayers.”

Ohio coal plant subsidies still a bad deal for ratepayers despite growing generation demand, experts say is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Inflation Reduction Act incentives are expected to help accelerate states’ clean energy transitions, but a new bottleneck is emerging that may blunt the federal law’s benefits over the next few years.

A new report by the Natural Resources Defense Council finds that states partially or entirely in PJM regional transmission territory may not be able to achieve their renewable portfolio standard, or RPS, targets through 2027 because of the long queue for connecting projects to the electric grid. 

“Given the lack of wiggle room between estimated PJM supply and statewide demand, states should be concerned about having enough renewable energy to meet their needs,” the study says. 

Meanwhile, more ambitious energy decarbonization goals that many cities and states have adopted are even more precarious because of the delays. 

“The RPS is a very old-school policy that most states have in place, and even those standards are at risk,” said NRDC policy analyst Dana Ammann, lead author of the report. “Greenhouse gas targets that states have worked so hard to implement will require so much more renewable development” than will be able to get online in coming years because of the interconnection delays. 

Illinois, for example, will likely struggle to meet its RPS goal of 40% clean energy by 2030 and 100% clean energy by 2050 regardless of interconnection problems, and the long queue will likely exacerbate the situation. Ohio has already met its lackluster 8.5% RPS, but interconnection delays will likely stymie wind and solar development that would have been driven by the market and other targets, experts say.

Major backlog 

PJM is the nation’s largest regional grid operator, with a territory that spans all or parts of 13 states from the Midwest to the Mid-Atlantic, plus the District of Columbia. Of nearly 2,500 utility-scale projects totaling 250 gigawatts of capacity waiting in interconnection queues nationwide today, 95% of them are in PJM’s queue, according to PJM and the NRDC report.

The NRDC report cites predictions by the Princeton ZERO Lab that PJM will see an additional gigawatt of renewable energy projects entering the queue annually going forward. 

In a 2022 company Q&A, PJM vice president of planning Ken Seiler said that the influx of renewable proposals means the projects PJM needs to study before interconnecting to the grid has “basically tripled in four years,” and “in 2020, PJM performed more studies than all other regional transmission organizations combined.”

The NRDC report quantifies the estimated solar and wind in the PJM interconnection queue for each PJM state, taking into account the rate of projects likely to be withdrawn from the queue and the typical capacity factor of projects — how much energy would actually be generated. 

The report shows that for PJM states to meet their renewable portfolio standard goals, 150,000 total gigawatt-hours of solar and wind would be needed by 2028. Meanwhile, incentives in the Inflation Reduction Act could spark demand for more than 225,000 gigawatt-hours by 2028, and more than 150,000 by 2025. 

Currently, less than 100,000 gigawatt-hours of renewables are available in PJM states. Illinois alone will need almost 30,000 gigawatt-hours of renewables by 2028 to meet its RPS goals. 

The study looks only at delays in interconnection request processing, not the process of building new transmission lines often needed to get renewable energy to load centers. The interconnection process is aimed at studying transmission needs when new power plants or renewables are proposed, and allocating the costs for that transmission to the power producers. 

PJM spokesperson Susan Buehler said PJM is working hard to clear its queue, but delays in renewable construction are also being caused by other factors. “Currently there are 44,000 MW mostly renewable generation resources that have cleared the PJM study process but have yet to be built due to factors unrelated to PJM, including supply chain and siting,” Buehler said by email. 

Smaller distributed generation — rooftop and community solar — does not need to interconnect through PJM, but NRDC included estimated growth of such distributed generation in its projections about whether states would reach their RPS. 

“There is a limited role for [distributed generation] because of the efficiency of utility-scale” versus rooftop solar, Ammann noted. “And there are still interconnection processes for utilities, which are not without their delays.” 

Ambitious Illinois goals at risk 

Illinois’ renewable portfolio standard stipulates that almost all the renewable generation needs to be in the state, as opposed to out-of-state renewable energy credits. 

The NRDC report indicates that even once wind and solar already in the queue are connected and start generating, Illinois will be short of its RPS goals by about 5,000 gigawatt-hours. 

Only northern Illinois, utility ComEd’s service territory, is in PJM. The rest of the state is part of the MISO regional transmission organization. Ammann noted that wind and solar projects proposed “deep in MISO territory” are also seeking to connect to PJM’s grid. 

“They can get the benefits of connecting to the PJM grid,” Ammann said. “Interregional transmission, deep coordination between the RTOs” — regional transmission organizations — “will definitely be necessary, especially in a multi-RTO state like Illinois.” 

David Kolata, executive director of the Citizens Utility Board in Illinois, noted that the state has no problems with energy supply, especially given its nuclear plants. But it has an important role to play as a clean energy supplier for the region. 

“We’re in the midst of an energy transition that potentially has really tremendous consumer and environmental value, and we’ve made a lot of strides in this direction, but in order to keep the progress going we need to make sure we’re building more renewables,” he said. “There are a lot of projects ready to go, but they can’t get connected to the grid. Especially as we have transportation electrification and as buildings electrify, it’s going to be important that we build new renewables.” 

Other states 

Illinois’ renewable portfolio standard could make it harder for nearby states to meet their goals, as Illinois will prioritize building new wind and solar resources and accounting for those renewable credits in-state, rather than allowing credit for that renewable energy to be exported to states that allow out-of-state renewables to count toward their goals. 

In 2021, Illinois wind was credited toward RPS compliance in PJM states Delaware, Maryland, New Jersey, Ohio, and Pennsylvania, according to the NRDC report. 

In PJM, Virginia has comparable goals to Illinois — 100% renewables by 2050, but a quarter of the credits can come from out-of-state generation.

States with more flexible RPS policies may find it easier to meet their targets even with the interconnection delays, but without the real emissions reductions that come from rigorous RPS standards. 

Ohio is likely to continue exporting renewables — or rather, credits for them — to other states to help meet their targets. The queued utility-scale solar proposed in Ohio could almost double the state’s total renewable output, according to the NRDC report. 

Pennsylvania has already far surpassed its RPS of 8% renewable energy, in part thanks to its hydroelectric generation. Pennsylvania has a relatively small amount of wind energy and a sizable chunk of utility-scale solar proposed in the interconnection queue. 

Reforms coming 

In 2022, PJM came to an agreement with the Federal Energy Regulatory Commission to reform its interconnection process, including by reviewing interconnection requests in batches rather than individually. 

The reforms will also prioritize proposals that are more developed and more likely to proceed, to reduce withdrawals from the queue that slow down the process. The PJM independent market monitor estimates that less than 13% of megawatt capacity in the queue will actually reach fruition because of project withdrawals. 

“PJM advanced landmark reforms to speed the interconnection queue that were overwhelmingly approved by PJM stakeholders and the Federal Energy Regulatory Commission,” Buehler said. “PJM will continue to work constructively with all of our stakeholders, including the NRDC, on ways to go even faster. Reliability of the grid is our focus and priority.”

The reforms take effect this summer, and renewable projects put on an expedited fast track will be considered under the new rules. The backlog of proposals filed before 2021 still need to be dealt with under the old procedures. Most new projects — like the expected “onslaught” incentivized by the Inflation Reduction Act, as NRDC phrased it — can’t be considered until the interconnection backlog is gone, likely in 2026, according to PJM and advocates’ estimates. 

“The great thing about the IRA is the money doesn’t expire,” Ammann said. “But we’re all familiar with the urgent messaging around climate change. Time is of the essence.”  

Planning ahead 

Ammann said there’s not much that stakeholders can do to reduce the current backlog, but PJM can avoid future delays by doing proactive transmission planning, which is not a part of the reforms. 

“Status-quo interconnection processes exacerbate these challenges through piecemeal transmission upgrades rather than through long-term, proactive planning,” the report says. 

States can also help by enacting their own transmission planning processes and paying for new long-distance transmission, rather than leaving the payments to individual companies and utilities. The state is likely to then recoup costs from ratepayers or taxpayers. New Jersey has such a process in place, and Maryland recently adopted the concept. 

“That shifts the cost to states, and lets construction start earlier,” said NRDC senior advocate Tom Rutigliano. “It’s more about the timing than who pays. The state is capable of stepping up in the short-term and funding a project that’s out of reach of developers.” 

There are about 30 GW of offshore wind projects in the queue off the coasts of New Jersey, North Carolina, Virginia and Maryland. But these projects are expected to face particular delays related to lawsuits, permitting and technology. 

Offshore wind does not currently figure into interconnection requests in the Midwest. Illinois legislators proposed a bill last year to support offshore wind, with a proposal floated for a wind farm off the coast of Chicago’s Southeast Side, but the idea faced opposition and the bill has not progressed. 

Ultimately, Ammann and Rutigliano said, state transmission planning, more offshore wind, and other ways to maximize renewable development, speed the interconnection process and promote transparency are all crucial. 

“Renewable growth smashes every expectation for how much it’s going to increase,” Ammann said. “So we need to be thinking creatively and outside the box.”

A line too long: Grid interconnection delays threaten states’ clean energy goals is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

As advocates highlight the urgency of expanding interstate transmission capacity in the wake of last month’s energy crisis in Texas, a novel Midwest project is facing delays, but not for the reasons that typically dog overhead power lines.

The Direct Connect Development Company is betting that the higher cost of burying its proposed transmission line along railroad corridors will be offset by the lack of expenses from dealing with legal and legislative challenges. So far, despite a handful of objections from neighbors, that bet appears to be paying off. 

Instead, it’s another innovation that has led to the project’s delay.

The 350-mile Soo Green Renewable Rail line would originate in Mason City, Iowa, and go to Plano, Illinois. The 2,100-megawatt, 525-kilovolt direct current line would be buried underground following a Canadian Pacific railroad right of way, relieving it of the need to secure the right of way from private landowners or invoke eminent domain.  

Soo Green would bring power from the MISO market to PJM and use advanced converters that PJM could control to dispatch the power when and where it’s needed, a capability that is not in use at a large scale anywhere else in the country, according to Joe DeVito, president of Direct Connect. 

But, as DeVito puts it, this has created confusion over whether it should be designated as a generation or transmission project. Because of this and related aspects of the project, Soo Green is in PJM’s clogged queue for generation awaiting study before it can be approved, a process that could take years. 

The converters “can react to instructions from the grid operator in 1/100 of a second,” DeVito said. “If you look at what happened in Texas, you see the need for lifelines between regional grids. The benefits this cutting-edge technology can give to grid operators is the bridge into the digital age.” 

(DeVito, along with Direct Connect Vice President Raj Rajan, are volunteer board members of Fresh Energy, which publishes the Energy News Network.)

Soo Green would be a merchant transmission project, a relatively novel approach where generators would pay to send their power to market on the line. DeVito said he is in talks with multiple prospective customers who would build new large-scale renewable generation and pay to send their power on the line, as well as customers — like companies and utilities — in the PJM footprint who need renewable power to meet their clean energy goals.

“We’re trying to open it up to as many parties as possible, let them get comfortable that there is a market,” he said. “We’re trying to get broad geographic scope on generation that can feed into the line. That gives you more geographic diversity, and means more renewable energy more of the time. There is not a product like this that exists in the marketplace.” 

In order to make the proposition viable, generators also want the ability to sell into PJM’s capacity markets, a measure that also needs specific PJM approval, and which Soo Green is seeking through its own filings. 

“The ironic thing is in order to put more generation online we need to build more transmission, but what’s blocking this transmission is too much generation in front of it in line,” he said. “At the end of the day it is because we have a lot of interest in solar. Solar has become very cost-competitive and it is overwhelming [PJM’s] queue.” 

A path around landowner opposition

The situation stands in sharp contrast to another proposed merchant transmission project, Grain Belt Express, an overhead line that still faces strong organized opposition from landowners in Missouri despite winning approval from state regulators two years ago.

Last month, the Missouri House of Representatives approved a bill by a margin of 123-33, aimed at killing the Grain Belt Express by prohibiting the use of eminent domain to acquire necessary easements. It is now before the Senate’s Committee on Commerce, Consumer Protection, Energy and the Environment.

Soo Green’s path is much clearer in this respect. While the project needs a franchise agreement from Iowa regulators to proceed, only 11 neighboring property owners — out of more than 2,000 along the corridor — have filed comments to the Iowa Utility Board objecting to the project.

Some said they think Direct Connect should offer them more compensation – like an upfront payment as well as monthly royalty. Spokesperson Sarah Lukan said the company has offered neighbors “a premium to fair market property value based on the 2019 Iowa State University Land Value study,” but notes that the company didn’t need to offer anything because the project will fall completely within the railroad right of way.

Several landowners and their lawyers also contend that electricity transmission does not comport with the right of way agreements that the railroad now known as Canadian Pacific signed with landowners along the route about 150 years ago. However, Lukan says legal precedents both in Iowa and at the federal level make clear that railroads may allow this activity on their right of way. 

The state’s Office of Consumer Advocate filed a motion on Nov. 30. asking Direct Connect to prove its claim that it has all of the property rights needed to develop the line.

Jeff Cook, an attorney with the Office of Consumer Advocate, said in an email that the responses from Direct Connect in January satisfied the office, and that no other issues have been found. 

Because Direct Connect is not considered a utility, it will not need to obtain a franchise from the Illinois Commerce Commission, according to the company.

‘Unique capabilities’ — and challenges

Beth Soholt, executive director of the Clean Grid Alliance, said, “We really really really need this project and many like it,” to facilitate the development of renewable energy and to avoid situations like the massive outages during the winter storm in Texas, by interconnecting regional grids. 

“I would hope PJM is looking at the favorable capabilities that Soo Green has — the line is dispatchable, controllable, it has these other bells and whistles that can help the PJM market, rather than looking at it as ‘it’s a lot of new generation being plopped into the PJM,’” Soholt said. “I’m hoping the leadership and folks doing the day-to-day work are thinking, ‘Here’s an opportunity to really maximize the capabilities that line can bring.’”

“Soo Green does have some unique capabilities — it’s a unique project,” Soholt continued. “There are some challenges in how to categorize and study it. I think there are benefits and challenges of seeing the line either way, but we have a big problem with the queues whether it’s transmission or generation and we have for a long time.” 

“The rules for connecting to the grid were designed 20 years ago, at the time grid operators were connecting large centralized fossil fuel power plants,” DeVito said. “The world has changed, to state the obvious. We have a large number of small low-cost resources seeking to connect to the grid.”

Fresh Energy staff, board members and funders do not have access to or oversight of the Energy News Network’s editorial process. More about our relationship with Fresh Energy can be found in our code of ethics.

Underground Midwest transmission project is hung up in PJM’s generation queue is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Sweeping “minimum offer” rule will likely cut into the competitive edge for renewables as a hedge against fossil fuels.

Motions filed this week are asking the Federal Energy Regulatory Commission to change a ruling that could price many renewables out of the PJM capacity market, while driving up prices for consumers.

FERC’s Minimum Offer Price Rule, or MOPR, calls for PJM to set minimum bids for state-subsidized electricity generators in those auctions. The rule could indirectly give coal-fired power plants an extra lease on life in the country’s largest capacity market, while making it harder for new wind or solar plants to enter the market and compete.

“The decision is really the worst case scenario” of possibilities considered during the period leading up to the ruling, said attorney Christie Hicks at the Environmental Defense Fund.

PJM’s capacity auctions pay generators to guarantee they will provide power at a future date, usually about three years out. Lower-priced energy resources clear the auction ahead of higher-priced ones. All who clear get paid the same rate as the highest successful bidder. 

Most coal and natural gas plants in the PJM footprint won’t be subject to the rule, outside of a few that get state subsidies, as under Ohio’s House Bill 6. However, the rule includes indirect benefits from state policies that could be deemed to provide an advantage.

Viewed in that way, renewable portfolio standards would fall under the rule, largely because utilities can meet those standards by buying renewable energy credits, or RECs.

“RECs are simply a form of subsidy,” said Joseph Bowring of Monitoring Analytics, who serves as PJM’s Independent Market Monitor. “So RECs are paying above-market prices for certain attributes.” In his view, FERC’s rule is an “internally consistent, coherent, logical” approach to the relationship of subsidized resources and competitive capacity markets.

Hicks and others disagree. A REC for solar or wind power isn’t a subsidy, but rather compensation for the environmental attribute of being clean, non-polluting energy, she said. By that view, REC payments account for the market’s failure to charge coal and natural gas plants for the pollution they cause.

Analysts don’t yet know what the minimum offer price will be for wind and solar power. Nonetheless, a combination of factors suggests that new, non-grandfathered resources would have a hard time clearing the capacity auction.

Squeezed out

FERC’s rule does provide a categorical exemption for renewable projects that already exist or are in development. In Bowring’s view, that should minimize the impact on renewables. In practice, the exception may be very narrow.

About 8.7 GW of planned renewables appear to be grandfathered, said Eamon Perrel, senior vice president of business development for Apex Clean Energy. Another 92 GW of projects have submitted interconnection requests to PJM and have had millions invested so far. Yet they probably wouldn’t be considered far enough along to fit within the exception, he said. 

And while there would be minimum offers for different types of generators, such as wind or solar, the minimum price would be “based on a proxy unit that doesn’t really have any relationship to whatever your individual costs are,” said Jeff Dennis, managing director and general counsel for Advanced Energy Economy.

Currently, companies’ bids depend on how much revenue they need, considering all other revenue streams, Dennis said. Operators of solar and wind farms generally use long-term power purchase agreements to recover capital costs and profits over an extended time period. So, their capacity auction bids are generally low.

In contrast, the minimum offer for most solar and wind farms subject to the FERC rule would be based on a new plant entering the market. That offer would likely build in capital and construction costs along with other expenses.   

Meanwhile, most coal and natural gas plants could submit bids based on their avoidable costs for staying open. FERC’s rule will create a persistent “bias for current resources versus new entrants” in the market, said Tom Rutigliano, a senior advocate for the Natural Resources Defense Council.

Bowring had pushed to have the minimum offer for all sources under the rule based on net avoidable costs, but FERC rejected that suggestion. If FERC had gone that route, the impact on renewables would be “probably zero,” he said. That’s because “the net avoidable cost of renewables is likely to be zero.”

A second problem for the renewable industry is that the PJM capacity auction already discounts wind and solar resources from their nameplate capacity, on the grounds that those are intermittent resources. Yet the grid operator likely won’t discount its calculations of the total revenue that a wind or solar farm would need to offer that nameplate capacity into the auction. So, those revenue requirements would wind up being spread out over the fraction that winds up being “counted.”

“You’re taking the entire cost of the project, and you’re wedging it into a smaller number of megawatts because of the way PJM discounts the value of renewables,” Dennis said. “It’s a rule that doesn’t reflect the economics of renewable energy.”

Already discounted

Companies shut out of the capacity market would need to make up the revenue somewhere else — possibly through higher prices for long-term power purchase agreements.

A typical wind project might need to increase its 12- to 15-year power purchase agreement price anywhere from $3 to $7 per megawatt-hour, Perrel said. The price for a typical solar project might need to increase by roughly $5 to $9 per MWh. (Companies don’t generally disclose power purchase agreement amounts while deals are in the process of negotiation.)

“You’re looking at a 10% to 20% increase on PPA rates for wind, maybe 15% to 25% for solar,” Perrel said. That shift could make power purchase agreements less attractive to potential customers as a hedge against future changes in prices, he added.

Meanwhile, forcing high minimum bids on wind or solar resources will let more coal and natural gas plants clear the auction than otherwise would be the case, critics say.

“Right now you have renewable energy resources that offer into the capacity market at very low prices,” said Sierra Club attorney Casey Roberts. But remove that competitive pressure, and the supply curve shifts. “A coal plant that may have been on the margin, that may not have cleared, is now more likely to clear,” she said.

PJM’s Jan. 21 filing with FERC also notes that if states procure capacity that doesn’t clear the auction, the grid operator would then need to arrange alternative capacity. “Such a result would clearly be inefficient and detrimental to consumers and, further, is not necessary to ensure an efficient price signal nor a just and reasonable rate,” the filing said.

A shift at FERC

“FERC was designed to be an independent agency that was insulated from the executive branch,” Roberts said. Yet now the December ruling seems poised to indirectly give coal plants at least some of the financial support they had repeatedly sought from the Trump administration.

“I don’t think it’s sunk in just how political this was from FERC,” said Dick Munson, director of Midwest clean energy for the Environmental Defense Fund. Over the years, the commission had been a technical, science-focused institution, he noted.

“But it has been politicized, as much as Washington has been,” Munson said. “And this is clearly a decision to pick technology favorites and advance them.”

Challenged federal rule could price many renewables out of PJM’s capacity market is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.

Nuclear and coal subsidies mean state consumers will likely pay more than $1 billion per year more, an analysis shows.

Ohio regulators are among dozens of challengers asking the Federal Energy Regulatory Commission to reconsider a ruling that could bump Ohio’s electricity costs up more than $1 billion per year to counter state subsidies for various kinds of electricity generation.

Those expenses would be in addition to amounts customers will already pay under Ohio House Bill 6. The law, passed last year, will primarily subsidize two FirstEnergy Solutions/Energy Harbor nuclear power plants and two 1950s-era coal plants. A much smaller amount is earmarked for a handful of already permitted solar projects.

“Ohio is actually the single state that will be most torn by this decision,” said Dick Munson, director of Midwest clean energy for the Environmental Defense Fund. Yet FERC’s Minimum Offer Price Rule, or MOPR, will affect ratepayers throughout all or part of the 13 states and the District of Columbia that make up the PJM grid region.

The MOPR rule is intended to level the playing field in PJM’s capacity auctions, which reward generators for guaranteeing they will be able to provide power at a future date, usually about three years out. Generators bid their costs, and all that clear the auction are paid the same rate for their guarantees.

FERC has decided that PJM should set minimum bids for for any generators that receive state subsidies. The rule will apply to plants benefiting from HB 6 and similar ones that also produce subsidized nuclear power, as in Illinois. More broadly, it would consider state renewable portfolio standards to be subsidies, so it would apply to most new wind and solar projects as well.

As a result, most generation subject to a minimum offer will likely fail to clear the PJM capacity auctions. That would exclude 23,975 megawatts of generation in places like Ohio, New Jersey, Illinois and Maryland, according to an August 2019 report by Grid Strategies, a clean energy consulting firm in Bethesda, Maryland. That’s roughly one-seventh of the total that cleared PJM’s 2018 auction for 2021/2022.

Meanwhile, PJM would still procure capacity for the full amount of the demand it expects across the region, plus a margin. For the last auction in 2018, that margin was 22%.

Because the rule will prevent many plants from bidding in at relatively low levels, more expensive, higher-cost coal and natural gas plants that would have been on the fence financially would now clear the auction. And the price for all sources clearing the auction would be greater.

“Essentially the rule takes capacity payments from carbon-free sources and gives them to fossil units, while consumers are required to pay for both,” said Rob Gramlich, president of Grid Strategies.

Taking exception

Ohio’s subsidies under HB 6 are an anomaly. They include rate hikes to help pay costs for two OVEC coal plants, the Kyger Creek plant in Cheshire, Ohio, and Clifty Creek in Madison, Indiana. Most other sources subject to FERC’s MOPR rule won’t be emitting greenhouse gases. 

Together, the two OVEC plants and nuclear plants subsidized by HB 6 provide 4,212 MW of accredited capacity, or roughly 18% of the total likely to be subject to FERC’s MOPR, according to the Grid Strategies report.

Customers in states that are deemed to be subsidizing generation will pay once for the subsidy, and then again through higher capacity prices. However, the large capacity of Ohio’s subsidized plants means the state will likely wind up with the greatest total costs from the MOPR.

The Grid Strategies report estimated Ohio’s exposure at around $1.1 billion, out of a total $5.7 billion for the PJM grid region. The exact figures may need to be reevaluated based on specific policy calls from FERC, but “are likely in the range of previous estimates overall,” Gramlich said.

The possibility of paying twice for the same power “logically is correct. But the question is how big is the impact going to be,” said Joseph Bowring of Monitoring Analytics, who serves as PJM’s Independent Market Monitor. 

“As a general matter, nuclear units do not clear” the annual capacity auctions, he said. Data in his group’s 2019 State of the Market Report for PJM suggests that neither of Ohio’s two nuclear plants would have cleared PJM’s auctions since at least 2014.

“To the extent that Perry and Davis-Besse would not clear the capacity auction if offered competitively, then Ohio has taxed itself to pay for those units,” Bowring said. “That will clearly increase rates compared to what they are now.” But, he added, “it’s not going to affect the costs to everybody else.”

FERC’s rule is “inconsistent with the Department of Energy’s efforts to support nuclear facilities,” Director Lori Sternisha of PUCO’s Office of the Federal Energy Advocate told commissioners at the Jan. 15 meeting. In addition, she said, the rule encroaches on state policy and applies only to presumed state subsidies versus federal subsidies.

The rule is “ambiguous and presents factual errors” about plants subject to HB 6. It encroaches on state authority, she added. Also, FERC didn’t provide evidence of an actual problem in the competitive capacity market, but just presumed there was one.

Additional arguments are raised in other requests for reconsideration and clarification filed with FERC this week.

States have few other options for avoiding the impact of the FERC rule. One limited exception would let generation sources ask PJM to come up with an individual minimum floor. Various critics say that would be an administrative nightmare on a large scale. The minimum floor would also be much higher than many renewable plants would otherwise bid.

What’s next

FERC’s Dec. 19 ruling gives PJM 90 days to tell FERC how it plans to comply with the order. Some months after FERC approves that, PJM would then hold its next capacity market auction. Last year’s capacity market auction for 2022/2023 still has not taken place.

Technically, FERC has 30 days to respond to the requests for reconsideration or clarification that are filed this week. The commission often grants itself an extension of time, though, said Jeff Dennis, managing director and general counsel for Advanced Energy Economy. If that happens in this case, it could be months before FERC’s order becomes final for purposes of an appeal to the federal courts.

Meanwhile, one or more states might explore an exception for carving out all or part of a state’s geographic area from the capacity market. In Illinois, for example, the pending Clean Energy Jobs Act could give state regulators the authority to procure capacity for the part of the state within PJM’s grid area, explained Christie Hicks, a senior attorney at the Environmental Defense Fund. 

“This is the capacity market only that we’re talking about,” Hicks said. The part of the state currently within the PJM grid area would otherwise continue to participate in its energy market and other services. The Illinois bill’s long-term goal is to move the state to 100% renewable energy. The move could eliminate roughly $864 million in added costs, based on the 2019 Grid Strategies estimates, she said.

Whether Ohio would follow that path is uncertain, however. Any consideration could refocus attention on the HB 6 subsidies, which FirstEnergy Solutions/Energy Harbor and other beneficiaries very much want to keep, Munson suggested. Indeed, FERC’s MOPR rule will likely help additional coal-fired power plants clear the auction, such as the Sammis plant in Ohio, he said.

“FirstEnergy Solutions is monitoring the process and does not have any comment at this time,” said spokesperson Jason Copsey when asked for comment on the rule and impacts relating to the Davis-Besse, Perry and Sammis plants. The company did file a request for rehearing, noting that the “‘double payment’ problem … renders FERC’s entire order unreasonable.”

FERC’s ‘minimum offer’ rule adds to the already high price tag for Ohio HB 6 is an article from Energy News Network, a nonprofit news service covering the clean energy transition. If you would like to support us please make a donation.