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.

Five years after Gov. Mike DeWine signed House Bill 6 into law, Ohio citizens and ratepayers are still paying the price. 

Ohio lawmakers still haven’t taken steps to repeal the rest of the nuclear and coal bailout bill, which is the focus of what prosecutors say was a roughly $60 million bribery scheme by utility FirstEnergy and its affiliates. Cases continue to wind through the courts, and two men implicated in the scandal have apparently taken their own lives. 

“It’s been really painful, and we’re still living with the consequences of House Bill 6,” said Catherine Turcer, executive director of Common Cause Ohio.

Shepherded by former Ohio House Speaker Larry Householder, the bill swept through the legislature in 2019, passing just 3 and a half months after its first introduction and despite massive opposition from consumer advocates, environmental groups, renewable energy interests and others.

The law called for more than $1 billion in subsidies for two nuclear plants for which FirstEnergy had been seeking bailouts since 2014. Additional provisions included subsidies for two 1950s-era coal plants known as the OVEC plants, along with gutting of the state’s renewable energy and energy efficiency standards. A referendum effort that would have let voters reject the law under Ohio’s constitution was ultimately thwarted amid claims of misleading ads, harassment of signature collectors and other problems.

One year after the bill passed, federal agents arrested Householder and others on charges under the Racketeer Influenced and Corrupt Organizations Act, known as RICO. The complaint outlined a $60 million criminal enterprise scheme funded by dark money, most of which came from FirstEnergy or its affiliates — roughly four times as much as the Energy News Network and Eye on Ohio had been able to track before the arrests.

Sam Randazzo resigned his position as chair of the Public Utilities Commission of Ohio months later, following an FBI raid on his home in November 2020. In July 2021, FirstEnergy entered into a deferred prosecution agreement with the Department of Justice, admitting it had bribed Householder and Randazzo.

Neil Clark, a lobbyist indicted in the scandal, apparently committed suicide in Florida in March 2021. Randazzo did the same in a Columbus warehouse he owned in April of this year, as he faced indictments on both federal and state criminal charges, along with loss of his license to practice law.

Calls for a full repeal of HB 6 came immediately after the 2020 arrests, but languished for months. Months after the next election, lawmakers finally repealed the law’s nuclear subsidies and a provision for guaranteed utility revenue, but left the rest of the law intact.

Bills to repeal the coal plant subsidies still have not gotten a full vote, and the state’s clean energy standards remain gutted. And full information about the corruption scandal has yet to come out, including answers to questions about Gov. Mike DeWine’s and Lt. Gov. Jon Husted’s involvement.

“The legislature hasn’t done anything to create greater transparency, to address dark money, to ensure we aren’t ripped off,” Turcer said.

“There’s this interesting intersection of dark money and gerrymandering and general decision-making and accountability at the statehouse,” Turcer continued.

Dark money refers to political spending that can’t be readily traced, and gerrymandering is the drawing of voting districts to advantage one political party over another. Together, both can undermine democracy and have delayed progress on climate change.

Still subsidizing coal

“The fact that we’re still bailing out the coal plants is just insane to me,” said Neil Waggoner, Midwest campaign manager for the Sierra Club’s Beyond Coal program. The Kyger Creek plant is in Cheshire, Ohio, and the Clifty Creek plant is in Madison, Indiana. Both plants consistently lose money.

“Those coal subsidies are costing consumers $500,000 per day,” said Ohio Consumers’ Counsel Maureen Willis. Her office estimates Ohioans have paid more than $330 million since January 2020. RunnerStone, a consultant for the Ohio Manufacturers’ Association Energy Group, projects the HB 6 coal subsidies could reach $1 billion by 2030.

The utilities that own the plants defend their continued operation.

“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,” said Scott Blake, a spokesperson for American Electric Power, which owns the largest share of OVEC, with other utilities inside and outside ofn Ohio owning shares. More than 500 employees work to make sure the plants operate as efficiently as possible, he added.

Since 1999, however, Ohio law has generally let consumers choose their electricity supplier. “And recent testimony by Duke executive [Amy] Spiller confirms the coal plants will continue to operate even if the subsidy ends,” Willis said.

The question comes down to whether the companies that made bad business decisions to keep noncompetitive plants running should pay their expenses, “as opposed to the public eating the cost,” Waggoner said.

Higher bills

HB 6 not only added subsidies to consumers’ electric bills. It also axed clean energy standards whose net savings for Ohioans had been about $9 per month.

“The elimination of the energy efficiency programs never made sense because they helped customers reduce their electricity usage,” said Rob Kelter, an attorney with the Environmental Law & Policy Center. “They lowered their bills. And they reduced pollution.”

Yet a legislative analysis claimed cutting those programs to pass HB 6 could save Ohioans’ money, a position that was further buttressed by testimony from then-PUCO chair Randazzo. Those arguments left out customers’ savings from avoiding wasted energy and lower overall capacity costs, Kelter said.

A bill to allow some permissive energy efficiency programs finally passed in the Ohio House last month, but passage in the state Senate isn’t guaranteed.

Regulatory scrutiny

Randazzo not only played a key role in shaping HB 6 and getting it passed. He also shaped the PUCO’s piecemeal response after Householder and others were arrested. That approach has continued, even after criminal charges were brought against Randazzo in federal and state court.

“Even after the revelations of what former PUCO Chair Sam Randazzo did for FirstEnergy in the halls of the PUCO, the agency itself has not had to answer to the public,” Willis said. “Case decisions issued while the former Chair led the agency have not been examined.”

“Why has there not been a management audit at the commission?” asked Ashley Brown, a former PUCO commissioner who subsequently headed the Harvard Electricity Policy Group. “Something clearly went wrong. We know that the chairman was bribed. We know that the other people went along.”

Agency spokesperson Brittany Waugaman noted the PUCO has four ongoing investigations in cases relating to FirstEnergy, but did not respond to questions about whether regulators plan to conduct an internal review of its own operations or otherwise review decisions in which Randazzo had participated.

Moreover, “the PUCO too often has made it difficult to get to answers for consumers,” Willis said. “Adverse discovery rulings, unrealistic case schedules, and limited audits, are a few of the problems for consumers.”

Who else?

The federal Department of Justice asked for three delays in discovery for the state regulatory cases, but after the initial 2020 arrests Randazzo was the only additional individual to face federal criminal charges, and he is now deceased. Meanwhile, Ohioans remained on the hook for charges. So in Brown’s view, the delays made sure consumers continued to be victimized by the crime.

The state did file criminal charges earlier this year against former FirstEnergy executives Chuck Jones and Mike Dowling, along with Randazzo and companies he controlled, as well as Householder. Company lawyers previously identified Jones and Dowling as having paid the bribes behind HB 6. But it remains unclear whether they or others will ever face federal criminal charges, said Dave Anderson, policy and communications manager for the Energy and Policy Institute.

Anderson and others also have questions about the involvement of American Electric Power, which paid $900,000 to dark money groups that supported HB 6.

Blake, the AEP spokesperson, said “management does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.” 

Anderson rejects that notion.

“While AEP has not been charged with any crime in connection with HB 6, disturbing new details about the financial relationship between Householder and the utility emerged during the convicted former Ohio House Speaker’s trial last year,” Anderson responded. And the company also has acknowledged it may face civil penalties from a SEC investigation, he added.

“I don’t how AEP defines wrongdoing, but common sense should tell AEP’s customers and regulators that something stinks here,” Anderson said. “AEP owes ratepayers answers, and unfortunately the PUCO has completely failed to investigate AEP’s role in the HB 6 scandal.”

Some bright spots

As consumers continue to face consequences from HB 6, so do Householder and lobbyist Matt Borges, Turcer said. Both are in federal prison while they appeal their criminal convictions in federal court from last year.

FirstEnergy might have to allow some credits or pay penalties as a result of the four pending PUCO cases, Anderson noted. That would be in addition to a $230 million penalty paid to the federal government and class action settlements in a few court cases.

Quarterly reporting requirements under the deferred prosecution agreement of donations to nonprofit groups also may have reined in some of FirstEnergy’s political influence in Ohio, Anderson said. FirstEnergy spokesperson Jennifer Young said the company plans to continue reporting donations, even after the deferred prosecution agreement’s term ends.

Young also highlighted other company reforms including enhanced controls, separation of functions for its top ethics and legal officers and better transparency to stakeholders.

“Today, FirstEnergy is a different, stronger company with a sound strategy, a highly effective compliance program and a companywide culture of ethics, integrity and accountability,” Young said.

Yet the company’s claims about transparency have fallen short, Willis said. “Lawyered-up FirstEnergy… continues to block efforts to publicly disclose their internal investigation reports produced in the wake of the HB 6 scandal.”

Energy policy

Ohio’s energy policy continues to feel impacts from HB 6 as well.

“It does make me wonder where we would be with renewable energy if HB 6 had been completely repealed, or if there hadn’t been this orchestrated campaign, not just to bail out nuclear plants or subsidize coal plants, but also to diminish our commitment to renewable energy and our funding for renewable energy,” Turcer said. Yet now, “the air we breathe is actually dirtier.”

HB 6 “cast such a long shadow over energy policy in Ohio,” said Tom Bullock, executive director for the Citizens Utility Board of Ohio. The energy industry is going through the greatest change in a century, with technological innovations in how energy is produced and stored, as well as new business models, he noted.

“We need to be thoughtful, so that we can grow industry and keep prices affordable and convert to clean and smart and distributed energy,” Bullock said. Otherwise, “We’ll be the last in the Midwest to get there if the way we make energy policy decisions is based on the wish list from traditional energy interests.”

Consequences continue as bill at center of Ohio utility corruption scandal marks fifth anniversary 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.

COLORADO SPRINGS — Head first in a dust-choked coal pulverizer, a heavy wrench knocking against a balky part hidden out of sight, body encased in an insulated safety suit as temperatures soared to 140 degrees, Chris Cox’s mind could have wandered to other career paths. 

How about a switch to an easier job without imminent risk of fire, assault by machinery or suffocation? 

In Cox’s telling, though, moving away from fossil fuels was the furthest thing from his mind when immersed in the ancient complexities of the Martin Drake coal-fired power plant. 

What Cox was thinking was, “How cool is this?” 

Cox, a coal operations mechanic at Martin Drake with 10 years at one of the most visible working power plants in the West, loved his job. Fixing things at a 96-year-old power plant meant the constant brain-and-hands exercise of keeping the good fires burning and keeping the bad fires from starting. 

Every day seemed to bring a new piece of machinery, Cox said, whether tightening the bolts on the latest gas-fired turbine technology, or inserting himself up to his ankles in a coal-pulverizing invention from a half-century ago and seeing how craftily it employed spinning hammers against metal plates. 

“There are no given things,” Cox said. “It’s a different thing every day. It was never the same day.” 

As Cox’s coal stories make the transition from “are” to “was,” he is standing next to Martin Drake where the 100,000-ton coal pile used to sit. A colleague in the distance cleans up the now-idled conveyor entrance where spinning jaws swallowed coal into the plant. For nearly 100 years, the conveyor entrance was buried dozens of feet beneath the coal, with front-end loaders constantly pushing the pile of carbon from the edges toward the jaws. 

The last of that coal was burned up right at dinner time on Aug. 27, some 30,000-plus days after Martin Drake first started turning coal dust into electricity for El Paso County. Colorado Springs still operates the Ray Nixon coal-fired plant, but is transitioning to solar arrays, natural gas and other electricity sources. 

Cox is now a former coal plant mechanic. 

He is not, however, a laid-off employee. Colorado Springs Utilities, the city-owned agency that runs power, water and other essentials for nearly half a million residents, made a commitment early on that when Martin Drake stopped burning coal, no one who wanted to stay would lose a job. Of the 80-odd positions it took to keep the plant running on coal, about 45 people have already transitioned to other jobs within the utility. 

Some will be kept on to install and operate new gas boilers to continue running the steam-generated electrical turbines at Martin Drake through the end of 2022. Colorado Springs needs generation at the downtown power plant in order to propel the overall grid, until new transmission lines are completed to even out the flow of electricity from other power sources. 

Cox is taking a job with Colorado Springs Water, fixing and maintaining dozens of pump houses that keep water flowing across hundreds of square miles. 

Gone now are the days he would take two showers after a shift, to rid himself of coal dust that felt like he’d spent the day rolling in black talcum powder. But coal was never a political object to Cox. 

“Coal was not nearly the four letter word it is today,” said Cox, who joined the utility in 2011. “It was necessary. I mean it was never a great thing, but it was necessary. We knew there was a way it would go away, but at that time, we had to have something. So, there was never a thought of like, ‘Oh, I can’t work for this evil company.’”

What would haunt others as nightmares are some of his favorite work memories. Standing underground beneath that massive coal chute, for example, known as “The McLanahan.” 

“So you have a door that goes into the underground, then to work in the lower motor of the actual feeder, you have to crawl down under the muck of coal and water and everything else down at the bottom and you’re just covered,” Cox said. 

Good times? Absolutely, he said. “I’m the classic power geek of this energy department. I can go absolutely nuts. I can bore you for hours. This job was really hard if you don’t like learning.”

In recent years, Cox and other utility employees knew of the protests and legal action against Martin Drake’s intense air pollution and greenhouse gas emissions. They knew city leaders were under great pressure to keep moving up the date the coal burning would stop. 

“We still had a job to do,” he said Friday. “So we couldn’t put a lot of time into thinking about who’s going to be closed down because even up until today, there was still a job to do right.”

Assurances about job transitions were huge for the employees, he added. He’s had plenty of friends telling stories about oil rig jobs that come and go, or even jobs with renewable energy manufacturers like Vestas wind turbines, where layoffs and consolidations are regular events. 

Cox’s time off these days is taken up renovating and rewiring the hazards presented by his 1920s-era house in downtown Colorado Springs. 

As he continues to train into the water utility job and travels central Colorado to keep clean water moving,  he realizes he’ll be able to repeat the daily wonders of the coal plant job, discovering an old and innovative mechanical solution to a timeless physics problem.

At the Skaguay Reservoir near Victor, Cox mentions, a hydroelectric plant was taken offline in the 1960s. But the guts of the mechanical operation are still there. They built 10 miles of wooden pipeline, out of California redwood, banded with steel every 12 inches. Much of it is remarkably intact, he said. 

“People back in the day could really build stuff,” Cox said. 

He said he will always be proud of the power station work. 

“You don’t think about it, but you go home and you don’t think you’re not gonna have power today,” he said. “You’re gonna turn on a light switch, it’s going to be there,” he said. 

One thing he will miss from Martin Drake is taking a late-shift break on the roof of the main power plant, on a hot summer night.

From five stories up, he would look out at twinkling yard lights on Cheyenne Mountain, or streetlights down below near Fountain Creek, or brightly lit restaurants to the north on Academy Boulevard. 

And he would think, “You’re welcome, everyone.”  

How workers at Colorado Springs’ shuttered power plant are transitioning to new careers 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.

This article was originally published by Georgia Recorder.

Sometime next year, Pam Wolff hopes to stop lugging heavy five-gallon jugs of clean water into her home every week so she can cook meals, brew her coffee and her grandkids can brush their teeth.

And she is looking forward to taking a shower without worrying over what’s in the polluted well water raining down on her.

Wolff says next year is probably as soon as she can expect to connect her home to a new Monroe County water line being rolled out on the county dime to give residents living in the more than 850 homes near Plant Scherer the choice of clean water. About 300 homes have been connected so far.

But Wolff says the $20 million county water line won’t be enough to quiet her. She said she remains concerned about Georgia Power’s plans to leave about 16 million tons of toxic coal ash in an unlined pit, where it sits in as much as 25 feet of groundwater.

“I’m sure there will be some people who will get complacent with it. ‘Oh well, I’m good now’ kind of thing,” she said. “The ones who have been so long-term medically and financially hurt by it will not be backing off. We’ll be fighting it to the end.”

Wolff was among the dozens of Juliette residents who showed up at the state Capitol last winter — before the COVID-19 pandemic upended life — to pressure lawmakers to require the state’s largest electric utility to excavate all its coal ash waste and move it to lined landfills.

Republican lawmakers have resisted those calls. And this year, a GOP measure requiring utilities to monitor the groundwater near coal ash ponds for 50 years after closure — as opposed to 30 years — cleared the House before stalling in the Senate. The bill remains alive for next year.

Wolff says she is baffled by Georgia Power’s decision to move coal ash to lined landfills at some locations, like Plant Branch in Milledgeville, but not all.

“I get that it is more cost involved and all that but when you’re talking about people’s lives and having viable water, money shouldn’t be a thing – especially for a power company that has massive forces behind them,” she said.

The state’s first close-in-place permit gets a public airing

Coal ash is the toxic waste left behind after decades of burning coal to generate electricity at power plants. And the national reckoning over what to do with this waste is entering a new chapter as states begin to issue permits to utility companies for specific sites.

Here in Georgia, the state Environmental Protection Division has issued the first proposed permit allowing Georgia Power to press forward with plans to leave more than 1 million tons of coal ash in an unlined pit at Floyd County’s Plant Hammond near the Coosa River.

The state is seeking the public’s input now. A virtual hearing is set for 6 p.m. Tuesday, and written comments can also be submitted. More details on the proposed permit and how to weigh in can be found here.

This first permit in northwest Georgia will kick off a series of permitting decisions centered on four other plants: Scherer in Juliette, McDonough in Smyrna, Wansley in Heard County and Yates in Newman.

Georgia Power plans to excavate and move 19 ash ponds and cap-in-place 10 others in unlined pits that have been drained of water.

But here’s where things become complicated: At all five plants where the utility plans to seal-in-place, the toxic coal ash is sitting in groundwater.

The bottom of the coal ash sits in as little as a foot of groundwater to more than 50 feet of groundwater at the five plants, although these numbers are estimates, said Kevin Chambers, EPD spokesman. The coal ash plunging the deepest into groundwater is at Plant Wansley just south of Carrollton.

At Hammond, the work to close the coal ash in place wrapped up three years ago. Because the work is already done, Chris Bowers, a senior attorney with the Southern Environmental Law Center, called the permitting for Hammond “a paperwork exercise.”

“What they’re proposing to do is let Georgia Power Company, essentially, self regulate,” he said. “Does this groundwater belong to the state of Georgia and its citizens? Or is this natural resource just basically to be occupied indefinitely as a waste pit.”

Chambers said Georgia Power was operating under federal and state requirements to close the ponds when it capped-in-place Hammond’s site in 2018. He said the division still has the authority to require Georgia Power to relocate the coal ash. But for now, the state is poised to sign off on the utility’s close-in-place plans.

“This permit will ensure that the pond was properly closed and is monitored and maintained for 30 years,” Chambers said.

Chambers said there will be a “robust groundwater monitoring system to detect if groundwater is affected by the ash remaining in place” at Hammond. The cover system, he added, is meant to stop rainwater from pouring onto the coal ash.

Georgia Power has long argued there’s no evidence their coal ash ponds have endangered public health or the state’s drinking water. But when asked if coal ash is submerged in the groundwater, a spokesman did not directly address the question.

“Our closure plans fully comply with the federal Coal Combustion Residuals (CCR) rule, as well as the more stringent requirements of Georgia’s state CCR rule,” Georgia Power spokesman John Kraft said in a statement Friday.

Kraft said more than 600 monitoring wells have been installed at Georgia Power’s facilities to monitor groundwater quality and the utility has hired third-party professionals to gather samples. The results are posted on the utility’s website and reported to the state. A plant-based remediation technology for groundwater will also be used at Hammond, Kraft said.

“Regardless of the method used, closure by removal or closure in place, we’re going to be sure that our closure plans are protective of the environment and the communities we serve,” Kraft said.

‘Let’s do it right the first time’

But environmentalists are sounding the alarm over the Hammond permit, which they argue will set a troubling precedent for the permits coming up soon for other sites in the state — including two much larger ponds holding 16 million tons of coal ash each.

And as one of the first states to implement its own coal ash permitting process, the decisions made in Georgia could have a ripple effect across the region, says Jesse Demonbreun-Chapman, executive director of the Coosa River Basin Initiative.

“The spirit of (federal) law is for the coal ash to be stored dry,” Demonbreun-Chapman said. “The whole point of this law was to end coal ash ponds because coal ash and water are a very dangerous combination.

“And capping a coal ash pond in place, where we know that the toe of the coal ash pond sits lower than the average water table height, is not dry storage of coal ash,” he added. “What they’re signing us up for is decades of slow pollution release into the groundwater and into the Coosa River.”

Demonbreun-Chapman pointed to a 2018 report from Earthjustice and the Environmental Integrity Project that reviewed data publicly reported by utilities and found several pollutants — such as arsenic, boron and cobalt — exceeding safe levels in the groundwater at Hammond. Georgia Power argues the groundwater testing around the pond meets federal drinking water standards.

Unlike Plant Sherer, there are not a lot of homes near Plant Hammond in northwest Georgia. But the Coosa River flows downstream into Alabama’s Weiss Lake, a popular fishing spot for crappie. There’s also a risk of sinkholes, said Demonbreun-Chapman.

Environmentalists argue that, if the close-in-place permits are approved, the utility will have to come back years from now and address the slow release of coal ash contaminants into the groundwater, and that ratepayers will have to pay twice for the cleanup.

Already, Georgia Power has been approved by the state to collect $525 million from ratepayers to pay for its coal ash site closure plans. The total costs could be as much as $8.1 billion, the utility has reported to state regulators.

“Let’s do it right the first time and that way we can minimize the absolute number of costs overall to not only the ratepayers in Georgia, but then also protect their health and environment as well,” said Neil Sardana, the Georgia organizing representative for the Sierra Club’s Beyond Coal Campaign.

Some environmentalists have questioned whether Georgia Power’s plans even amount to a cleanup of coal ash.

“There’s no point of doing any of this if you’re going to leave that waste in the aquifer,” said Fletcher Sams, executive director of the Altamaha Riverkeeper, which has advocated for the coal ash at Plant Scherer to be relocated to a lined landfill.

“The whole point in cleaning it up and closing these ponds is that coal ash and water don’t mix and you need to store it permanently in a place where that’s not happening to protect human health,” he said. “In the state of Georgia, that means nothing. What it means is we’ll spend $7, $8 billion so that we can say that we are in compliance but actually not do anything to help the environment or the people living on our fence lines.”

Georgia Recorder is part of States Newsroom, a network of news outlets supported by grants and a coalition of donors as a 501c(3) public charity. Georgia Recorder maintains editorial independence. Contact Editor John McCosh for questions: info@georgiarecorder.com. Follow Georgia Recorder on Facebook and Twitter.

State regulators poised to set Georgia Power’s toxic coal ash storage legacy 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.

When Dominion Energy broke ground in 2008 on the largely coal-fired Virginia City Hybrid Energy Center, then-Lt. Gov. Bill Bolling called it “the largest economic development project in the history of Southwest Virginia.” 

Today, the facility, the last coal plant to be built in Virginia, remains a local economic force, tipping more than $8.9 million in property taxes into Wise County’s coffers in 2020. But that investment comes at a price. According to Dominion’s own calculations, the continued operation of Virginia City is expected to cost utility ratepayers — none of whom live in Wise County — $472 million through 2029. 

Those numbers have become key touchstones in a struggle over how fast Virginia should wind down its coal fleet, with the utilities pushing to keep their remaining large investments in service through 2040 or 2045 and many environmental and consumer groups arguing that closures should happen far sooner, preferably by the end of the decade. 

“From a utility’s perspective I think the question to be asked is, ‘Do the benefits of continuing to operate this facility outweigh the costs to the customers?’” said Will Cleveland, an attorney with the Southern Environmental Law Center. 

Both sides have emphasized different costs and different benefits. Advocates for faster closure highlight the declining use of coal plants to provide customers with energy, the additional costs ratepayers will have to shoulder to keep them running and the need to stop emitting carbon. Utilities meanwhile point to their power reserve obligations, local economic impacts and the cost of rapidly rolling out renewables to replace shuttered coal generators. 

Keeping Virginia City afloat, said Dominion spokesperson Rayhan Daudani, “helps us provide reliable power for our customers and also plays an important role in Southwestern Virginia with hundreds of jobs and significant local revenue while helping clean up millions of tons of waste coal and thereby improving regional water quality.” 

Cleveland, however, described Virginia City as “a power plant in search of a reason to exist.” 

“I think you can both close the coal plant and provide the necessary assistance to Wise County all for less money than it now costs Dominion customers to keep the thing open,” he said. 

The last coal plants

Once the driving force behind Virginia-produced electricity, coal has over the past decade found itself steadily losing its corner of the market. 

Part of the reason is purely economic: The shale revolution ushered in a glut of cheap natural gas that has been able to undercut coal as electric utilities’ fuel of choice. Capacity factors — an indicator of how often plants are run, with a factor of 100 percent indicating constant usage at maximum output — show declining usage of coal plants in favor of natural gas. Between 2017 and 2019, Virginia City’s capacity factor fell from about 62 percent to 22 percent, while that of the Clover Power Station in Halifax County dropped from about 43 percent to 17 percent.

Clover “used to provide about 25 percent of our power, and last year it was about 5 percent of our power,” said Kirk Johnson, ODEC’s senior vice president for member services. 

Appalachian Power’s use of its Amos and Mountaineer plants, which are located in West Virginia but serve the company’s Virginia customers, have also fallen. According to utility data, capacity factors dropped between 2017 and 2020 from an average of 54 percent to 40 percent for Amos and from 62 percent to 46 percent for Mountaineer, with a spike in use at the latter in 2019. 

Natural gas isn’t the only force exerting pressure on coal, however. Heightened environmental regulation has also played a role. Rules introduced by the U.S. Environmental Protection Agency in 2015 to govern coal ash and coal wastewater disposal are forcing plants to either make costly upgrades or shutter; last Monday, the agency announced it plans to begin strengthening them further. And rising concern about climate change-causing carbon emissions has led a growing number of states to pass laws to phase out fossil fuels. Coal plants, which are generally older and produce more carbon dioxide than their natural gas counterparts, tend to be first on the chopping block. 

Virginia is no exception. The 2020 Virginia Clean Economy Act set a 2024 deadline for the closure of most of the state’s coal units, although it allowed Virginia City and the Clover Power Station jointly owned by Dominion and Old Dominion Electric Cooperative to stay open until 2045. 

“The economics are already showing that it doesn’t make any sense” to keep operating most coal plants, said Dori Jaffe, a senior attorney with the Sierra Club who is involved with current litigation before Virginia’s State Corporation Commission concerning two coal plants owned by Appalachian Power Company. 

Operators have in numerous cases agreed. Dominion has retired or converted 11 coal units in Virginia over the past three years and plans to close its last two coal units at the Chesterfield Power Station in 2023. Appalachian Power closed its last three Virginia coal units in 2015. Non-utility companies shuttered the Spruance coal plant near Richmond this January and announced plans to convert a King George coal plant to storage and solar in March. 

Nevertheless, a few large coal plants continue to operate for the foreseeable future. Virginia City is one. Clover may be another. Although Dominion has projected a 2025 retirement date for the plant in long-range planning, no firm commitments have been made, and the facility’s shared ownership means both Dominion and ODEC must agree to any closure plan. 

Appalachian Power’s Amos and Mountaineer coal plants present a curious problem due to their West Virginia location. While not subject to Virginia closure deadlines, both facilities face significant pressure from state law requiring utilities to source an increasing amount of their electricity from renewables through 2050. 

“The costs incurred to comply with the Virginia Clean Economy Act may be higher because of continued operation of Amos and Mountaineer than it otherwise would be,” said Cleveland.

When Appalachian Power intends to shutter those plants remains a question mark. During its 2020 rate review, the utility asked regulators to plan for accelerated retirement dates of 2032 and 2033 for the facilities rather than 2040, although the later date has resurfaced this spring in a fresh round of proceedings over environmental investments. 

The utilities acknowledge the declining use of coal plants but say that isn’t the whole picture. Serving daily load is just one of their obligations, they point out. Maintaining power reserves sufficient to meet year-round demand spikes is another, one that can’t be ignored. 

“We are required to have a certain level of capacity — in other words, we must be ready to provide our customers a certain amount of power at any given time,” said Appalachian Power spokesperson Jeri Matheney. Amos and Mountaineer represent nearly two-thirds of the company’s capacity, she said; retiring them early “would expose the company and our customers to an imprudent level of uncertainty and market volatility.” 

Johnson, the ODEC executive, also said that even though Clover is “not much of an energy source” for the cooperative, it is “a valuable capacity resource so we can meet our capacity obligations” within the regional electricity market. 

“We spend a lot of time talking about the future of Clover and what is in the best interest of our members,” he said. 

To invest or not invest

Dominion and ODEC remain in the driver’s seat when it comes to decision-making about Virginia City and Clover. But Appalachian Power’s hand is being forced this spring as it seeks state approval for several large investments to comply with tighter federal coal ash and coal wastewater disposal regulations at Amos and Mountaineer. 

The choices are stark. If Appalachian doesn’t comply with the coal ash rule, it will have to close both facilities by 2023 at the latest; not complying with the wastewater rule would trigger a closure date of 2028. 

The utility has asked regulators for permission to do both, allowing the plants to operate through 2040. The price tag for Virginia and West Virginia customers would be $250 million, split evenly between the two projects. As a result the average Virginia customer would see a monthly bill increase of $2.50. 

Appalachian has said continuing to operate the plants through 2040 is “the most economical solution for customers,” and that if it was forced to retire one or both by 2028, it would have to spend billions of dollars on replacements “much earlier than necessary.” 

“Virginia customers would bear the costs of this unprecedented capacity overhaul,” said Matheney. 

But while the company has faced no opposition to its coal ash investments, which are widely viewed as cleanup costs, both the Sierra Club and the Virginia Office of the Attorney General have disputed the wisdom of the wastewater investments that aim to prolong Amos and Mountaineer’s lives through 2040. 

“This is a moment when neither market nor regulatory trends favor coal generation. And yet the company is requesting recovery from ratepayers of additional capital that it wants to invest into West Virginia coal plants in the apparent hope that the plants will weather the economic and regulatory headwinds that are faced by other coal plants all over world,” said Sierra Club attorney Evan Johns during proceedings before the State Corporation Commission this June. 

SCC staff too expressed hesitancy about the prospect of racking up further costs.

“It would appear to be inconsistent with market and industry trends to assume that the Amos and Mountaineer plants will be able to operate economically in the market through 2040,” said utilities policy specialist Earnest White in May testimony on the proposal.  

A hearing examiner sided with the skeptics earlier this month, saying she was “concerned about the validity of APCo’s conclusion that the [wastewater] investments will ultimately be beneficial to ratepayers” and recommending that the commission withhold approval of them until the utility could provide more detailed analysis. 

Kentucky regulators on July 15 took a similar stance, denying Appalachian’s proposal to make the same upgrades at its Mitchell plant on the grounds that it hadn’t proved the projects were “a reasonable, cost-effective alternative.” West Virginia regulators are still mulling the same proposal before the Virginia commission. 

A replacement for coal 

No accounting of coal’s costs can be complete, say both the utilities and advocates of early closure, without an accounting of what it will cost to replace it. 

“No party disputes that the company will have to acquire replacement capacity for the plants at some point in the future,” Appalachian Power wrote in a filing with the State Corporation Commission last week. 

When that point in the future should be is hotly disputed. 

Early closure advocates say that phasing out the plants sooner would be better not only for curbing air pollution but in some cases on economic grounds. 

Continuing to operate coal plants would be a matter of “throwing good money after bad,” said Cleveland of the Southern Environmental Law Center, pointing in particular to Virginia City’s projected 10-year losses of $472 million. (Appalachian Power doesn’t make similar valuations of its facilities publicly available.) The plants have been built, so “customers are on the hook for that regardless of whether it retires now or in 30 years.” 

But, he asked, “Is it beneficial to the customer to ask them to incur yet more cost to keep operating?” 

Appalachian Power has argued that pushing off replacement costs to the future while the coal plants finish out their lives would be better for customers. One Sierra Club proposal to procure 6.3 gigawatts of solar and storage as a replacement by 2028 at an estimated cost of $5 to $7 billion was described as “simply too much, too fast to be feasible” by James Martin, the director of resource planning strategy for Appalachian Power parent company AEP. 

“The only practical solution, and the most economic solution, is to preserve the dependable capacity that these units provide for our customers,” he testified to Virginia regulators. 

Much of the decision-making regulators will face in the Appalachian case, as well as any future case involving coal plant investments, comes down to whose accounting they accept. In the present proceedings, Appalachian contends early retirement of both plants would cost customers $1.5 billion by 2039, while the Sierra Club argues such a step would save ratepayers $670 million. 

Electric cooperatives like Old Dominion also face a separate set of challenges because of their non-profit structure, which gives them less flexibility in deciding how to handle early retirement costs. 

“We don’t have some tools like securitization that are available to investor-owned utilities,” said Johnson. “We can’t shove any of these costs or this depreciation on shareholders. It all has to come from those 1.5 million people that we serve at the end of the line.” 

Less abstract are the impacts the inevitable closures will have on plant employees. Appalachian spokesperson Matheney described the company’s facilities as “the primary employers and tax paying entities in many communities.”

“Our intent is to provide as much notice as is feasible, often as long as five years, to prepare for a closure,” she said. 

Other coal plants serve a similar function. 

“Our county has become very dependent upon the revenue from” Virginia City, Wise County resident David Rouse told a Senate subcommittee this winter. “It now provides about 20 percent of the county’s budget in terms of taxation. Not only would we suffer from the loss of employment but our schools would suffer significantly from the loss of revenue as would other county services.” 

Dominion has emphasized this financial contribution in regulatory testimony. Virginia City, it said during litigation over its 2020 long-range plan, “is expected to remain in the company’s fleet for reasons beyond the results of the economic analysis.” 

“In addition to serving customers’ energy and capacity needs, [Virginia City] support jobs, economic development and water quality improvements in the coalfield regions of the commonwealth, and reduces reliance on imported power,” the company wrote. 

Cleveland, who has consistently argued against the reasonableness of continuing to operate the plant, said that any early closure would need to be accompanied by “a very thoughtful companion effort to make sure that Wise County and its residents are not left out in the cold.” But, he added, “I think there are lots of ways to solve that problem.” 

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Coal fuels less and less Virginia electricity. But when should utilities pull the plug on plants? 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.