Correction: An earlier version of this story did not include that the advocacy groups’ modeling included one new natural gas plant. The story has been updated.

Xcel Energy’s latest long-range plan for meeting electricity demand in Minnesota includes six new natural gas peaker plants that critics warn could be obsolete before customers are done paying for them.

Comments filed last month by clean energy advocates and the state attorney general’s office push back on the utility’s plan to build a fleet of small fossil fuel plants as it otherwise ramps up clean energy investments. The facilities would operate sparingly, just a few hours at a time on days when the grid is strained and wind, solar and other clean power can’t keep up with demand.

More economical options exist, though, according to a coalition of clean energy groups that hired experts to model alternatives. The study commissioned by the groups concluded Xcel could save ratepayers as much as $3.5 billion by opting for a single new gas plant, and relying more on existing plants, energy storage, efficiency and demand response, and buying surplus power on the regional power grid.

The clean energy groups include Fresh Energy, which publishes the Energy News Network (Fresh Energy’s leadership and policy staff do not have access to ENN’s editorial process.)

The debate is over the utility’s latest integrated resource plan — the first submitted to state regulators since Minnesota Gov. Tim Walz signed legislation last year requiring electric utilities to use 100% clean energy by 2040. Xcel Energy supported the legislation and has proposed various scenarios for achieving the target, but disagreements remain among stakeholders about how to get there, particularly when it comes to cost and equity issues.

Different approaches to modeling

Allen Gleckner, executive lead for policy and programs at Fresh Energy, said Xcel’s gas plant proposal is similar to one in its last integrated resource plan that asked regulators to approve two new peaker plants that would provide as much as 800 megawatts of electricity. Xcel eventually agreed to an open, fuel-neutral bidding process allowing clean energy companies to propose alternatives. That process is still underway, with an administrative law judge expected to make recommendations.

The clean energy groups’ consultants used the same software program as Xcel to arrive at a plan to add a new 374 megawatt gas plant, 3,800-4,800 megawatts of wind, 400 megawatts of solar, and 800 to 1,200 megawatts of energy storage resources by 2030. Extending contracts at existing peaker plants could add 970 megawatts, and energy conservation initiatives could reduce use during high demand times. 

Gleckner said Xcel has taken an exceptionally conservative approach by mostly creating scenarios that did not consider electricity being available from neighboring systems or the MISO regional transmission grid. Gleckner said Xcel does not and has never operated as an island, with MISO delivering power to its customers through a shared resource pool.

“Xcel is using a sort of fiction of modeling because the reality is we’re part of a regional grid,” he said. 

The result is a plan to “build a bunch of new resources that we know are either not compatible with our state laws or are going to be costly and likely to retire early,” he said.

Amelia Vohs, climate program director for the Minnesota Center for Environmental Advocacy, praised Xcel for not asking regulators to extend the life of existing fossil plants, unlike its counterparts in other states. Unlike previous long-range plans, Xcel’s latest imagines a future in which large gas and coal power plants are not the backbone of the system. 

What that grid will look like remains challenging, Vohs said. Adding to the challenge is rising power demand from data centers, manufacturing, and the electrification of buildings and transportation. Even so, Vohs believes clean energy is ready for a leading role.

“It’s a much better solution that’s flexible in this time of uncertainty without making this big commitment to gas resources for the next 40 years,” Vohs said.

Patty O’Keefe, senior field strategist for the Minnesota Sierra Club, said proposed combustion turbine peaker plants pose “significant environmental and public health risks” because they potentially emit more carbon and nitrous oxide than larger, more common combined cycle gas plants. They also tend to be built in communities already suffering higher pollution levels.

The Sierra Club would like Xcel to focus more on energy efficiency than electricity generation in its planning. Efficiency reduces demand and makes “the transition to clean energy smoother and more cost-effective,” O’Keefe said.

Managing risk

Meanwhile, the office of Minnesota Attorney General Keith Ellison has also weighed in, warning that investments made now may become obsolete “stranded assets,” meaning the plants may become uneconomical or forced to retire before they have delivered projected benefits to customers. 

Xcel has acknowledged the risk of stranded assets generally in Securities and Exchange Commission filings, though not specifically in relation to its proposed gas peaker plants.

Utilities are incentivized to build power generation because investors earn a return on capital investment. The attorney general argues that if plants become obsolete or transition to other forms of energy, such as hydrogen, Xcel ratepayers should not have to pay for retrofits and other investments it might have to make to reduce emissions.

In its filings to state regulators, Xcel said it is concerned about having enough firm dispatchable power to meet rising demand quickly during certain times of the day. By 2030, the company will have ended its use of coal for energy generation after closing four coal-burning facilities this decade. The proposal suggests Xcel may need to add even more peaker plants between 2030 and 2040.

Xcel spokesperson Kevin Coss said the company will be “adding a significant amount of wind and solar power to our energy mix” and complementing that generation “with always-available generation — power we can supply any time it’s needed — to reinforce the reliability of the grid.”

Coss said Xcel identifies generation sources in a technology-neutral way so it can decide not to use natural gas combustion plants in the future. The current integrated resource plan calls for fewer firm dispatchable resources than the 2019 version, he said.

The conservative modeling “avoids overreliance on the energy market, which could expose our customers to excessive risk,” Coss said.

Residents, businesses and organizations have until Oct. 4 to send comments on the integrated resource plan to the Public Utilities Commission. The commission is expected to make a decision on the plan in February 2025. 

Minnesota advocates say their alternative to Xcel’s plan for new gas plants could save customers up to $3.5 billion 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.

Indiana ratepayers spend hundreds of millions of dollars per year for power from coal plants that are operating despite the availability of cheaper sources, including wind and solar.  

The state is emblematic of a larger problem, as electricity market rules typically allow utility-owned power plants to essentially cut in line even when they are not the most economical option for customers.  

A recent report commissioned by the Natural Resources Defense Council examined how this phenomenon plays out in the Midcontinent Independent System Operator (MISO) regional transmission organization specifically, building on previous research by RMI, the Union of Concerned Scientists and others — all of which show that uneconomic coal plant dispatch takes a huge toll on ratepayer wallets and public health. 

The problem happens primarily with vertically integrated utilities or municipal utilities and cooperatives, which can recoup costs of fuel and operations from ratepayers even if they are operating at a loss. In most of MISO territory, energy markets have not been restructured as open markets, making such cost recapture the norm. 

The NRDC study showed that Indiana ratepayers bore the second-highest burden in MISO, paying $338 million for uneconomic coal power from 2021-2023, just behind Louisiana’s $341 million. North Dakota ratepayers spent an extra $120 million, Wisconsin $69 million, and Minnesota $54 million, the study found. 

Indiana’s R.M. Schahfer plant, run by utility NIPSCO, cost ratepayers more than $100 million in such uneconomical dispatch from 2021-2023, the NRDC study found. 

In an ongoing rate case, Duke Energy is seeking to increase reliance on its Gibson and Cayuga plants in Indiana. These plants were responsible for $29 million and $7.6 million in uneconomic dispatch costs to consumers in 2023, according to RMI’s economic dispatch dashboard. 

“This has been a problem plaguing Indiana coal plants for many years, it’s costing our consumers in Indiana millions of dollars and it’s one of the factors driving rates higher and driving clean energy off the grid,” said Ben Inskeep, program director for Citizens Action Coalition in Indiana. “It’s a tale of utilities making bad decisions as part of their profit motive and then utility regulators failing to hold them accountable as they’re supposed to. Certainly utilities should be operating their plants efficiently and economically, and when they fail to do so, they shouldn’t be getting cost recovery.” 

Duke spokesperson Angeline Protogere said the study misses important context. 

“There are a lot of considerations that go into plant dispatch decisions, and the priority is always reliability of service and economics,” Protogere said. “We weren’t able to replicate the NRDC data, but it appears it’s based on incomplete information. For example, there are times when MISO calls on a unit because of grid reliability needs. There’s a bigger picture that’s not reflected here.”

Skewed markets

The NRDC study found that over three years across MISO, about 400 MW of wind power was curtailed in favor of power from coal plants generating at higher-than-market costs. 

Power producers bid into regional energy reverse-auctions for real-time and next-day power, offering the price for which they can produce their electricity. Grid operators like MISO and PJM are supposed to dispatch the power starting with the most affordable option, until demand is met. 

Even if vertically integrated utilities are not selling their power on the open market but rather serving their own customers, they still need to be dispatched by the grid operator to send their energy onto the grid. 

But under the rules for MISO and other grid operators, coal plants can “self-commit” to run for a given time period even if they cannot produce power below the market rate. The idea is that coal plants can’t ramp up or down quickly, so they may need to keep running at a certain level to be ready to provide more power when needed.  

If this relatively expensive coal power weren’t on the grid, more wind power would be purchased and demand for new renewables would likely be created. 

“That increment of power would be filled through the market selecting the next highest bidder,” providing “an accurate picture of what electricity should cost that gives a signal that incentivizes newer generation,” explained James Gignac, Union of Concerned Scientists Midwest senior policy manager. 

The lower the energy prices at a given time and the lower the demand, the worse the coal plant dispatch problem gets. Data from RMI and a 2020 report by the Union of Concerned Scientists shows that ratepayer losses due to uneconomic coal dispatch were lower in 2022, because Russia’s invasion of Ukraine caused natural gas prices to spike, making coal more competitive by comparison. Conversely, when energy demand plummeted in 2020 because of the pandemic, uneconomic dispatch of coal plants soared. 

Since 2015, the uneconomic dispatch of coal plants has cost Indiana ratepayers $1.9 billion and ratepayers nationwide $20 billion, according to RMI’s dashboard. 

The issue has real impacts on the growth of renewables, experts note. If the practice was prevented, market prices would be higher and there would be more incentive for renewable developers to build projects to sell their power on the open market. Meanwhile if vertically-integrated utilities were not allowed to recoup their costs for uneconomic dispatch, they would be motivated not to run coal plants and might decide to invest in building renewables instead, or at least buy wind power on the open market.    

“I’ve talked with [wind] developers who say they look at where coal plants self-commit uneconomically, and they avoid those transmission lines because they know they will be curtailed,” said Joseph Daniel, principal in RMI’s Carbon Free Electricity team and lead author of the Union of Concerned Scientists report. 

That report shows that if uneconomic coal dispatch was avoided, Indiana customers would save money — but not as much money as ratepayers in other states, because there is less wind power available around Indiana. Over time, a market unfettered by uneconomic coal plants might correct this situation. 

“The greatest immediate savings for customers from stopping uneconomic coal plant operations are in areas where there are existing low-cost resources such as wind power being curtailed by that behavior,” said Gignac. “If the replacement for the uneconomic coal generation is something like a relatively higher-cost gas plant, then the market clearing price is higher and customer savings are not as significant. However, that higher clearing price is a signal and an incentive for low-cost renewables to locate projects in that area and deliver further cost savings. 

“Removing the market distortion of uneconomic coal operations helps move us toward the cleaner, lower-cost energy system we need.” 

Solutions   

Studies show that coal plants that sell their power on the open market – known as “merchant” plants – rarely decide to operate when they are not getting market prices at least equal to their cost of operating – the way vertically-integrated or publicly-owned coal plants do when they know they can recoup their costs from ratepayers, without compensation from the market. In other words, merchant plants do not ask grid operators to be uneconomically dispatched. 

These merchant plants nonetheless seem to ramp up in time to operate when their power is needed, experts note, indicating that vertically-integrated plant operators in MISO are understating their ability to ramp up and down quickly, as noted by NRDC policy analyst Dana Ammann and other experts.  

“There’s so little incentive to ramp up quickly, because the market really accommodates their inflexibility,” said Ammann, lead author of the recent NRDC study. The vertically-integrated coal plants in MISO are “much less flexible than coal plants in other markets. In PJM you see coal plants turning on much more quickly, since the merchant plant operators are reliant on the price signals to turn a profit. They don’t have the guaranteed rate recovery, so they’re very responsive to price signals.” 

State utility commissions can prevent regulated utilities from recouping costs when coal plants are dispatched uneconomically. Michigan regulators did exactly this last year in a rate case for Indiana Michigan (I&M) Power, preventing the utility from passing on such costs for its share of the Rockport coal plant, located in Indiana.  

Daniel said Indiana regulators should likewise protect Indiana customers from paying for uneconomic power from the Rockport plant. The RMI dashboard shows that plant dispatched $142 million worth of such power last year. Meanwhile the Michigan ruling could be considered precedent for Michigan utilities like DTE and Consumers Energy in future rate cases. 

Ammann noted that states can also use the Integrated Resource Plan process to curb uneconomic dispatch, as Minnesota’s utility commission did when it recently decided that Otter Tail Power’s Coyote coal plant can only recoup costs during a designated power emergency.

“It’s an interesting approach for getting ratepayers basically off the hook for coal plants that aren’t retiring, that might still be economic to run for a small number of hours,” Ammann said. 

Grid operators like MISO may have the most important role to play in better managing markets, refusing to dispatch coal plants that aren’t necessary and doing deeper analysis to figure out exactly how much power is needed. Experts say multi-day markets – rather than just real-time and day-ahead ones – could better match supply with demand and avoid unnecessary coal plant dispatch. 

MISO’s Independent Market Monitor has recommended such measures, including de-committing coal power producers who sold into the day-ahead market if it turns out that others – including renewables – could sell power more efficiently in the real-time market once the time comes. 

“MISO works closely with our members, state regulators and our independent market monitor to ensure our markets are efficient,” said MISO spokesperson Brandon Morris. MISO’s June 2024 monthly operations report shows that in June, 18% of coal-fired power dispatched in the region was uneconomic self-committed dispatch. 

Experts note that fuel delivery contracts often include a minimum purchase, so utilities committed to buying a certain amount of fuel might as well burn the fuel even if they are not making a profit on the power. This might not have been an issue in years past when coal plants operated at high capacity most of the time, but as coal plants have become increasingly uncompetitive, the NRDC study notes, they are more likely to be committed to buy fuel they actually don’t need. Fuel contracts are usually of short duration, with 88% of those reviewed by the federal Energy Information Administration expiring by 2025, meaning there is ample opportunity for fuel delivery contracts to be revised, the NRDC study said. 

Such fuel contracts have meant massive stocks of unneeded coal piling up at Duke plants in Indiana, Inskeep said, forcing the company to burn it even if the power isn’t needed.

Protogere said the coal supplies are necessary, as “the goal is to ensure a reliable supply in an increasingly uncertain market. The aim is to manage volatility as well as maintain long-term supply reliability and security, so that we don’t have to resort to higher cost options in the market.”

Inskeep hopes state regulators deny requests by Duke and other utilities to increase coal-fired generation and the recouping of the costs from ratepayers. 

“The bottom line with this uneconomic dispatch situation is it means utilities are keeping their old expensive coal plants open longer than they should,” Inskeep said. “Utilities should be rapidly transitioning to a renewable energy-based portfolio of resources. Instead, utilities are feeling pressure to justify a lot of the bad economic decisions they’ve made in the past, foolish decisions to invest millions or even billions of dollars to keep these plants open.”

Indiana’s dependence on coal is costing ratepayers millions and holding back clean energy growth 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.

Duke Energy is already under fire in North Carolina for its plan to blow off a state deadline to curb carbon pollution while also building a massive new fleet of fossil fuel plants.

Now, the company’s blueprint is locked on a collision course with fresh rules from the Biden administration, which target coal and new natural gas plants and take effect in eight years.  

“Duke is going to have to go back to the drawing board,” said David Neal, senior attorney with the Southern Environmental Law Center, “and come up with an alternative that is compliant with the rules.” 

While much focus on the long-awaited Biden rules has centered on coal, their impact on natural gas is arguably more significant. Duke isn’t alone among American utilities in being forced to re-examine long-term generation plans as a result. 

“We think it’s important for every utility and every commission to take a step back,” said Amanda Levin, director of policy analysis with the Natural Resources Defense Council. 

But even as the federal regulations underscore a law unique to the state, it’s not clear if North Carolina regulators will take a beat – or even if there’s time for them to corral Duke and an array of stakeholders to rework, vet, and approve a new carbon reduction and long-range plan due by the end of the year. That’s why many advocates say debate over the utility’s immediate next steps will be crucial. 

“It’s going to be important to adopt a near-term action plan that really is ‘least regrets,’” said Neal, who’s representing numerous clean energy groups in the proceeding on Duke’s generation plans. “The new rules just put further emphasis on what we already knew was true: we’re going to have to accelerate the adoption of clean resources.”

‘Not… achievable on the timelines presented…’

Duke’s existing fleet of natural gas-fired plants aren’t affected by the new Biden rules. Nor are the smaller gas plants Duke proposes to occasionally satisfy peak demand and serve other limited roles on the electric grid.

But the company plans at least five large, combined-cycle plants in the Carolinas that are impacted by the rules. The four projected for North Carolina include a 1,360-megawatt plant in Roxboro, about an hour north of Durham, for which state regulators are now weighing a permit application.

Natural gas is a fossil fuel, but Duke deems the Roxboro plant and others like it essential to the zero-carbon electricity future that state law mandates by 2050. These baseload generators can back up sources like wind and solar to ensure reliability. At the point of combustion, they produce about half the carbon pollution of coal. And in theory, hydrogen molecules separated from chemical compounds could ultimately supplant gas as a fuel, bringing the plants’ carbon emissions down to almost nothing. 

“Natural gas is available 24/7 — with fewer emissions than coal and at a lower cost than renewables alone,” Duke said on its website this year, around the time it asked regulators for permission to build the Roxboro plant. “The new [Roxboro] units would be designed to operate on carbon-free hydrogen in the future.”

But critics say this rationale is flawed in virtually every respect. The cost of natural gas is on the rise, and one recent study showed it was a major driver of recent Duke rate hikes in parts of North Carolina. In December 2022 during Winter Storm Elliott, gas plants failed when they were needed most — in the wee, frigid hours before the sun rose — helping to cause rolling blackouts that impacted half a million customers in the state. Drilling and transporting gas leaks methane, a greenhouse gas 80 times more powerful than carbon, nearly canceling out reduced carbon pollution from smokestacks.

As for hydrogen, experts believe it can serve a small role in a zero-carbon economy — but mostly not in the power sector. Even if it’s carbon-free when burned, hydrogen made from fossil fuels is hardly nonpolluting and also inefficient. Hydrogen fuel produced from renewables should be reserved for limited applications, they say, such as long-distance aviation fuel or to power the few gas plants still running in the middle of the century. 

“In our modeling,” said Levin, “hydrogen in the power sector is used just for that last 5% of the decarbonization of the entire grid.” 

Still, the power plant rules promulgated by Biden’s Environmental Protection Agency don’t wrestle with reliability, ratepayer impacts or even methane leakage. They cover carbon dioxide pollution alone, and they’re designed to reduce what’s emitted from the smokestack by 90% beginning in 2032. 

That limit is based on carbon capture — in which carbon dioxide is sequestered underground rather than released into the atmosphere — a technology widely viewed as infeasible in North Carolina because of its geology. And while other techniques that would achieve the same pollution cuts are allowed under the federal rules, none are yet ripe. 

One candidate is now being developed at utility scale in Texas but won’t be deployed until at least three years from now. As for hydrogen, it would have to fuel 96% of Duke’s new baseload gas plants beginning in 2032 to meet the emissions limit — an impossible feat according to the company’s own communications with regulators.

Duke’s current forecast shows its gas fleet running on about 3% hydrogen beginning in 2041, then “holding steady until significantly more hydrogen is required to meet carbon-neutral by 2050,” to comply with state law. And in a brief discussion of the impending federal power plant rules in its August draft of its long-term plan, Duke noted: 

“Hydrogen is an important and potentially transformational fuel for the future of the resource portfolio, [but] the volumes necessary to utilize the hydrogen compliance pathway are not thought to be achievable on the timelines presented.” 

‘It’s a pretty huge gap’

Thus, if regulators allow Duke to build large new baseload gas plants, the company can only run them 40% of the time or less, beginning in 2032 and until technology becomes viable to slash their emissions.

The Roxboro plant, which Duke plans to put into service at the beginning of 2029, would operate at its planned capacity for just three years in that case. Afterwards, its vaunted ability to provide around-the-clock electricity would be severely curtailed. 

Multiply the Roxboro conundrum by five, and the mismatch between the Biden rules and Duke’s gas ambitions becomes clear. 

In its August discussion of the expected Biden rules, Duke said it considered running its new combined-cycle baseload plants at 50%. Making up for the resulting difference between demand and supply, including building another large gas plant that would run at half-speed, would require an extra $3.6 billion, the company estimated.

Tyler Norris, a former vice president at Cypress Creek Renewables and a PhD candidate at Duke University, estimates that if the 6,800 megawatts of baseload gas plants Duke announced in January were planned to run at 75% and had to ratchet down to 40% operations, the difference would be greater still. Filling it only with solar could require 9,500 megawatts of capacity in a single year — nearly double what’s online in Duke’s territory today. 

“That’s probably on the high end,” said Norris, but, “it’s a pretty huge gap. Something’s going to have to change in the plan.”

Then, there’s the question of whether it makes sense for ratepayers to pay to fill that gap, especially if they’re also shelling out full price for underutilized plants. 

“We’re all paying for these plants that admittedly have to sit idle more than half of the time?” asked Dave Rogers, deputy director for the Sierra Club’s Beyond Coal campaign. “Should customers really be forced to pay for those?”

Adhering to the Biden rules on coal plants appears more straightforward.  

Duke must shut down its entire coal fleet by the start of 2039, and any plants still running in 2032 must be fired partially with gas. The utility already plans to meet that deadline for eight of its 12 remaining coal smokestacks, covering six sites. Two outliers in Belews Creek, just outside Winston-Salem, can already be fueled with gas. That leaves two units in Roxboro, about an hour north of Durham, that the utility now plans to keep online until 2034.

“The logical thing is to retire that coal plant at least a couple of years earlier. Whatever replaces it will be lower cost,” said Rogers. “That’s the big thing in front of the commission as it pertains to the [coal plant] rules.”

Timing also looms large. State law requires Duke to curb carbon emissions 70% by 2030, with two years’ wiggle room. If regulators authorize a nuclear or wind project that causes logistical delays beyond Duke’s control, the postponement could be indefinite. The company now hopes to exploit the latter loophole, with its preferred path to net zero achieving the 70% benchmark by 2035 or even 2037. 

With their deadline of 2032, however, the Biden rules help bolster the case for Duke to rein in its carbon emissions sooner. Doing so wouldn’t just make it easier for the utility to meet the ultimate goal of near-zero emissions by midcentury. It would also significantly reduce overall carbon levels in the atmosphere. 

“The thing about climate is it’s not just about achieving net zero in one year and one year only,” said Levin. “Climate is a cumulative emissions problem. If you’re doing status quo until the year you’ve made a net zero commitment, you’re not consistent with a 1.5 or 2 degree warming trajectory.”

No change to the ‘path forward’? 

Still, while advocates have long pressed Duke to build more battery storage, solar, and wind in place of gas and coal, making the switch in the complex utility modeling tools is no simple task, with a host of variables involved — from transmission capacity to reliability to siting.  

“Duke has already submitted its modeling twice now. I doubt that either North or South Carolina commissions will want to do another round of that at this point,” said Maggie Shober, research director for the Southern Alliance for Clean Energy, on a recent webinar about the Biden rules. But, she added, “this will absolutely come up in the process before the [North Carolina Utilities] commission.”

For its part, Duke hasn’t indicated any plans to re-do its projections.  

“While we are analyzing the final rules, our view is that [they do] not change our path forward in North Carolina as we continue retiring our coal plants and supporting the state’s unprecedented growth with an all-of-the-above approach that’s designed to deliver affordability and reliability for customers,” company spokesperson Bill Norton said in an email. “Natural gas remains an essential resource in this diverse mix that can be dispatched to meet demand 24/7.”

If that position holds, and state regulators don’t seek to change it, it raises the stakes considerably for the “near-term action plan” expected as part of the plan due by the end of the year, as well as the permit application pending right now for the Roxboro plant.

That short-term plan, said advocates, shouldn’t just account for the risk of new gas resources and the timing of coal retirements, but also allow for more renewables by removing the annual connection caps Duke proposes for both battery and solar.

“I think this is an excellent opportunity,” said Norris, “to revisit the potential to achieve a higher interconnection rate for zero-carbon resources.”

Duke Energy’s plans for new gas in N.C. on a collision course with new Biden power plant rules 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.

A legal debate over semantics of the U.S. EPA’s 2015 coal ash rules could decide whether groundwater-soaked coal ash can remain in place next to an Ohio power plant.

In oral arguments before the U.S. Court of Appeals for the District of Columbia last week, power companies argued the rules don’t specifically ban coal ash contact with groundwater, and that as a result the federal agency overstepped its mandate in 2022 when it ordered the closure and cleanup of a coal ash impoundment at the General James M. Gavin Power Plant in Cheshire, Ohio.

Attorneys for the EPA and the environmental organization Earthjustice argued during the March 7 hearing that preventing such groundwater contamination is exactly the point of the federal rules. 

“We hope the judges come out with an opinion that’s clear and definitive that the rule says you cannot close when the waste is sitting in groundwater,” Gavin Kearney, deputy managing attorney for Earthjustice’s clean energy program, told the Energy News Network after the hearing. “We think the meaning of those words is clear already. But given what industry is pulling here, let’s just define it in a way that’s super duper clear so we can be done with that issue.”

There’s little debate about the existence of groundwater contamination from the 2,600 MW Gavin plant, one of the largest coal plants in the country. Its former owner, American Electric Power (AEP) bought the entire town of Cheshire in 2002, with most residents and businesses moving out, rather than address residents’ pollution concerns.

Two federal lawsuits, however, argue that the EPA’s recent demands essentially represent the unauthorized promulgation of a new rule, since they don’t believe that coal ash sitting in groundwater is explicitly identified as a violation of the 2015 federal coal ash rules. 

“I think it’s clear,” said industry counsel Stephen Gidiere during the oral arguments, “that EPA has issued a new legislative rule,” by demanding in its January 2022 enforcement action that coal ash not sit in groundwater. 

One of the lawsuits was filed by utilities that are wholly owned subsidiaries of AEP, which sold the plant to a private equity firm in 2017, but the plant still provides power to the utilities that are plaintiffs in the lawsuit. 

The other lawsuit is filed by a group of LLCs and holding companies affiliated with power generators including Vistra Corp., as well as the Utility Solid Waste Activities Group (USWAG), a trade organization representing over 100 utilities, electric cooperatives and related organizations. 

The 2015 coal ash rules mandate that at unlined coal ash impoundments that are infiltrated by water or causing contamination, the ash must be removed and placed in a lined landfill; an impermeable liner must be put in the impoundment; or engineering controls like pumps must be used to prevent contamination. 

The federal rules set a deadline of April 2021 for unlined impoundments to stop receiving coal ash and begin closing in such a way that they do not cause or present a future risk of contamination. At many sites including Gavin, companies requested extensions to this deadline. The rules offered extensions if closing by that deadline was not feasible, but only if the site was in compliance with other aspects of the rules. 

The EPA did little to enforce the rules until January 2022, when it issued a number of extension request denials, including for Gavin’s Bottom Ash Pond. Gavin’s extension request also triggered the EPA to review the site as a whole, and it found problems with contamination and compliance including with the Fly Ash Reservoir, an impoundment which was no longer receiving new coal ash. 

The EPA’s decision says that: “taking Gavin’s data at face value EPA estimates that the closed FAR [Fly Ash Reservoir] could be sitting in groundwater as high as 64 feet deep in some locations and that as much as 8.2 million cubic yards (or as much as 40% of CCR in the FAR) could still be saturated — and would remain so indefinitely.” CCR refers to Coal Combustion Residuals. 

In the oral arguments, Gidiere argued that the 2015 rules don’t necessarily mean that coal ash sitting in groundwater must be cleaned up.   

The oral arguments before a three-judge panel parsed the definition of a “free liquid” that could be separated from coal ash, with the EPA and Earthjustice attorneys arguing that groundwater indeed is a liquid that could and should be separated from toxic coal ash. 

“Once it becomes groundwater, it’s not a free liquid any more,” countered Gidiere, arguing that groundwater hence does not need to be kept separate from coal ash. 

Kearney emphasized that the coal ash rules say unlined impoundments must be cleaned up if contaminated leachate is found in the groundwater monitoring required under the rules. 

“Maybe if groundwater never moves you could have an unlined impoundment and still be okay,” Kearney said. “But at Gavin, this water is flowing through the waste, that’s generally what water does. It doesn’t just sit in the ground, it moves,” carrying leachate out of the impoundment.   

Gidiere in the oral arguments said that if an impoundment is covered and rainwater or surface water no longer creates downward pressure on coal ash, the risk of contamination is removed. He argued that the EPA’s 2022 orders that coal ash cannot remain soaked with groundwater go beyond the requirements laid out in the 2015 rules. 

“What EPA said in January of 2022, is if there’s an inch of groundwater in the bottom of 100 feet of dry CCR, that you cannot close the unit,” Gidiere said. “If you have basically wet sand in the bottom, you have to remove all that CCR.”

In response to questioning from the court, Gidiere could not identify impoundments that have only an inch of water, or any with less than 10% of coal ash saturated with groundwater.

“There are lots of sites like this one,” Kearney told the Energy News Network. “The Gavin site is a pretty egregious example, but we know there are lots of sites where coal ash is sitting in water.” 

Earthjustice, the Environmental Integrity Project and other organizations have released analyses of groundwater monitoring data required under the rules, showing that the vast majority of coal ash impoundments nationwide are causing toxic leakage. 

“The whole overarching point (of the federal rules) is that groundwater contamination is a big problem, it’s really unsafe and we have to prevent it,” said Kearney. “You can’t let water in (to a coal ash impoundment), you can’t let water out, you can’t let water just sit inside the impoundment.”

Parsing legal definitions, power industry pushes back on EPA coal ash enforcement  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.

Wisconsin utility WEC Group announced to shareholders last month that its subsidiaries would phase out coal by 2032, three years earlier than previously planned. 

We Energies’ Oak Creek plants will close in 2024 and 2025. Columbia Energy Center — the state’s largest coal plant, co-owned by WEC and Alliant — will close by 2026. Weston Unit 3 — co-owned with Dairyland Power Cooperative — will close by 2031.

Advocates applauded the news but said it only increases the urgency of making sure that ratepayers aren’t saddled with the costs of coal plants for years after they close. Under current policy, utilities can keep recouping their investments in coal plants — including in expensive pollution controls — and even earn a rate of return on those investments, after coal plants have ceased producing energy. 

Advocates are calling for increased use of securitization, wherein a coal plant owner issues bonds to reduce the burden of debt after closure, similar to refinancing a mortgage. And they are arguing against the very premise that utilities are able to keep earning profits on coal plants that have closed.

Rate cases are proceeding before the state Public Service Commission for both We Energies and Alliant that include debate over the finances of closed coal plants. 

“We need to look at more options for saving people money, whether refinancing through securitization, or even the prospect of disallowing any profit from those plants, which would be a bold step,” said Citizens Utility Board Executive Director Tom Content. “Why should utilities be profiting from something that is already a brownfield site? Given all the investments the commission has approved for utilities that are natural gas, solar, battery storage, they’re doing well financially. Customers deserve a break.”

Denying profits?

Alliant is allowed to reap a 10% profit on its investments, including after coal plants are closed, and We Energies is allowed a 9.8% profit. 

Alliant’s Edgewater coal plant in Sheboygan will close by 2025. A Nov. 9 rate case hearing before the Public Service Commission included Alliant’s plans to keep charging ratepayers for its investments in the plant. 

Content said that while the commission didn’t mandate the utility reduce costs to ratepayers, he was glad commissioners expressed frustration with Alliant for failing to consider ways to reduce the burden of the closed plant. 

Alliant earlier reached a settlement with the Citizens Utility Board to use a method called levelization in recouping its investments for the Edgewater plant. This arrangement reduces the costs to ratepayers in the years right after the coal plant closes, but could increase what ratepayers fork out by $90 million total by 2045, CUB regulatory affairs director Corey Singletary said in testimony before the commission in September. 

Singletary argued that once a coal plant like Alliant’s Edgewater is no longer “used and useful,” a utility should not be able to charge ratepayers for profits on the initial investment or installation of pollution controls. While such a policy could theoretically cause utilities to run coal plants even after they are not needed, Singletary said the commission could charge a company trying to do so with being “imprudent.” 

“It’s important to consider that utility investors have been provided a return on Edgewater plant in service for years, returns that have reflected the risk of owning and operating a utility, including the risk that one day the utility’s investments may no longer be in the money,” Singletary testified.

He concluded that the commission could call for a “complete disallowance” of profits on closed coal plants, even though it did approve their construction in the first place.

In testimonies before the commission regarding both Alliant and We Energies, Singletary said the companies are treating securitization as the “floor” in reducing costs to customers for the retiring coal plant, when in reality the “floor” could be “zero” payments for the plant once it closes.

Expanding securitization

Currently, utilities are allowed though not required to use securitization to offset the costs of pollution control equipment. This measure was used to save ratepayers about $40 million regarding the 2018 closing of WEC’s Pleasant Prairie coal plant. 

A 2004 law allows such securitization, but Pleasant Prairie is the only time that it has been invoked.

A bill introduced by Republican state Sens. Robert Cowles and Duey Stroebel in October would expand the potential use of securitization, or environmental trust bonds, as the bill (LRB 4441) phrases it, in part by expanding the definition of “environmental control” to actually describe a coal plant closure.

The bill would let the Public Service Commission order a company to use environmental trust bonds after closure, a power the commission doesn’t currently have. 

Cowles also introduced a number of other bills demanding more transparency and ratepayer protections from the commission. The legislature will break for two months after Nov. 16, meaning the bills won’t likely move forward until 2024. 

Cowles’ co-sponsorship memo for the securitization bill argues that commission decisions “such as the early closing of a power plant, often do not even come before the Commission prior to the closure of the facility, despite the fact that ratepayers will still be responsible for paying the outstanding debt on a facility which is not creating any benefits for consumers.”

We Energies example

The Citizens Utility Board charges that We Energies did not adequately consider alternatives to reduce the cost burden on customers around the Oak Creek plant’s closing.

The company in its filings modeled recovering Oak Creek costs over 16 years and over 25 years, and also over 25 years with securitization of $100 million in retrofit investments. The longer cost recovery could save ratepayers in the near term but actually cost them as much as $153 million extra over time, CUB’s analysis found.

CUB told the commission that We Energies should consider securitization of the full $407 million outstanding for Oak Creek. CUB argued the commission should also simply not allow the company to recover certain costs once the coal plant is closed.

The Wisconsin Industrial Energy Group, which represents 25 large industrial energy users, also testified to the commission criticizing We Energies’ plans for the Oak Creek debt. It said securitizing $100 million is “too little and the interest rates and servicing fees too great,” and recommended a more comprehensive securitization plan.

The utility had argued that state law only allows securitization of investments in pollution controls. But the industrial group’s expert Lane Kollen argued that the question is open to legal interpretation, and securitization on all outstanding costs could be sought.

Kollen also stressed that savings from securitization should be shared with customers, which is not required by Wisconsin law, and the utility’s profit on investments in the coal plant should be reduced after it is retired.

The industrial organization compared We Energies’ proposal to securitization plans by Duke Energy Progress and Kentucky Power Company regarding their own coal plants, and noted that those utilities were proposing much more advantageous situations for ratepayers.

“Given the unprecedented rate increases that [We Energies] customers are facing as they support the necessary and enormously expensive transition to clean energy, more than ever it would be reasonable for the commission to determine that customers should not bear the full cost of a decommissioned” Oak Creek plant, CUB’s testimony said.

Similar to the We Energies case, Singletary and Kollen both said in testimony that Alliant should consider securitization on the full $473 million in outstanding costs for the Edgewater plant. Singletary said this could result in $80 million savings for ratepayers.

Kollen charged that in its rate case filings, the company miscalculated possible savings from securitization, making it look less attractive than it would actually be. 

Federal funds

The Inflation Reduction Act’s Energy Infrastructure Reinvestment Program could also provide relief around the costs of closed coal plants. The program provides low-interest loans if defunct energy infrastructure is retooled or repowered to meet clean energy goals. In all, the IRA created $250 billion worth of such loans.

Clean Wisconsin said in testimony before the commission that Alliant could tap the IRA program to refinance the Edgewater debt, then use those savings along with other IRA incentives to invest in 150 megawatts of solar and battery storage on the Edgewater site. That would help the utility invest in renewables without placing the burden on ratepayers. Clean Wisconsin’s analysis found leveraging IRA funds could save $168 million related to the coal plant retirement, compared to the planned levelization approach.

“These coal plants are already not economical to run, and when they have to compete against cheaper electricity from the wind they’ll run even less frequently and potentially accelerate their closure,” Clean Wisconsin energy and air manager Ciaran Gallagher told the Energy News Network.

An Alliant representative testified before the commission that they had previously discussed this idea with the Department of Energy, and were told the project would not be eligible. But such determinations could “change over time,” Clean Wisconsin’s testimony said, and the utility should revisit the possibility.

“To do any less would be squandering an opportunity to realize a win-win solution for the company and its customers, while ensuring Wisconsin benefits to the greatest extent possible from the Federal Government’s unprecedented investment in clean energy,” the testimony said. 

“The Commission should ensure [Alliant] does everything possible to take full advantage of this and other recently authorized federal funding opportunities to make Wisconsin’s transition to clean energy more cost-effective for the utility’s customers.”

Wisconsin coal plants are closing, but ratepayers are still on the hook 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.