In the U.S., most power plants begin increasing their coal stocks in the spring to prepare for the higher demand in the summer and winter. Additionally, U.S. power plants typically stockpile much more coal than they consume in a month, EIA said, with more than 90% of coal-fired power plants currently having enough coal to generate electricity for 60 days or more.

Coal-fired electricity has declined in the U.S. over the past decade, and coal plant stockpiles have been declining as well, EIA said. Coal consumption by the electric power sector totaled 385 million tons in 2023, 43% less than in 2016. Coal stockpiles reached 131 million tons by the end of 2023, 19% less than stockpiles at the end of 2016.

The amount of coal transported in the United States decreased 8% in 2023, continuing a trend in which coal shipments have generally decreased over the past two decades as coal’s share of power generation has declined in the United States. The amount of coal transported to power plants, which are often located far from mines, decreased by more than half, falling from 957 million tons in 2010 to 422 million tons in 2023.

However, EIA expects the decline in coal consumption to reverse this year. In its recently published July update to the Short-Term Energy Outlook, EIA forecast an increase in use of coal to generate electricity in the United States this year, with use dropping back to about 2023 amounts in 2025.

Although the amount of coal being transported closely follows the coal consumption rate, the two measurements can differ from year to year. During 2023, U.S. coal producers shipped 35 million more tons (9%) than U.S. power plants consumed. Surplus deliveries last year boosted inventory levels at power plants by 48%, reducing deliveries in early 2024. Conversely, coal shipments to power plants in 2021 and 2022 were 59 million tons less than the amounts consumed during those two years, and inventories dropped to less than 100 million tons.

Also, in late 2023, EIA projected that coal-fired power plants will generate less electricity in 2024 (599 billion kwh) than the combined generation from solar and wind (688 billion kWh) for the first time on record.

However, the U.S. Energy Information Administration (EIA) expects the decline in coal consumption to reverse this year. In its recently published July update to the Short-Term Energy Outlook, EIA forecast an increase in use of coal to generate electricity in the United States this year, with use dropping back to about 2023 amounts in 2025.

Although the amount of coal being transported closely follows the coal consumption rate, the two measurements can differ from year to year. During 2023, U.S. coal producers shipped 35 million more tons (9%) than U.S. power plants consumed. Surplus deliveries last year boosted inventory levels at power plants by 48%, reducing deliveries in early 2024. Conversely, coal shipments to power plants in 2021 and 2022 were 59 million tons less than the amounts consumed during those two years, and inventories dropped to less than 100 million tons.

American Electric Power (AEP) recently issued a request for proposal (RFP) for the supply of coal to one or more of its generating stations in multiple coal regions. AEP is seeking proposals for the following regions and terms, but will consider longer-term proposals should the parties be able to agree on mutual terms and conditions.

The RFP was issued for the following regions:

• Central Appalachian Basin (Term: 2025, 2026)
• Illinois Basin (Term: 2025, 2026, 2027)
• Powder River Basin (Term: 2025, 2026)
• Northern Appalachian Basin (Term: 2025, 2026, 2027)
  

Proposals are due by 5 p.m. ET, Friday, Aug. 2, 2024. Proposals will be kept open until 5 p.m. ET, Friday, Sept. 6, 2024, AEP said.

AEP issued a similar request in 2021 seeking fuel for its coal-fired power generation plants to supply through 2024. Overall, the RFP sought contact on more than 19 million metric tons of coal from the Central Appalachian, Illinois, Powder River and Northern Appalachian basins. These four mining regions produce most of the nation’s coal.

Like many U.S. utilities, AEP has been retiring and replacing a large part of its coal-fired generation portfolio. The company still generated 42% of its power from coal-fired plants in 2023.

AEP’s operations span across several states, many of which are within the PJM Interconnection. Use of coal-fired power in PJM territory has dropped over the last decade, largely driven by the buildout of natural gas combined-cycle (NGCC) plants and higher relative fuel costs, according to the U.S. Energy Information Administration (EIA).

In 2023, the use of coal-fired generation in PJM fell to 34% of capacity. Yet coal generators were dispatched less frequently last year, contributing 14% of PJM’s generation, while making up 18% of its generating capacity. By comparison, in 2013, the capacity factor of coal-fired power in the market was 56%, when coal made up 44% of the market’s generation and 38% of its capacity, EIA said.

PJM is the largest wholesale electricity market in the nation and includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and Washington, D.C.

COLSTRIP, Mont. (AP) — Actions by President Joe Biden’s administration that could hasten closures of heavily polluting coal power plants and the mines that supply them are reviving Republican rhetoric about a so-called “war on coal” ahead of the November election.

The front line in the political battle over the fuel is in the Powder River Basin of Wyoming and Montana, a sparsely populated section of the Great Plains with the nation’s largest coal mines. It’s also home to a massive power plant in Colstrip, Montana, that emits more toxic air pollutants such as lead and arsenic than any other U.S. facility of its kind, according to the Environmental Protection Agency.

The EPA last month finalized a suite of rules that could force the Colstrip Generating Station to shut down or spend an estimated $400 million to clean up its emissions within the next several years. Another proposal, from the U.S. Interior Department, would end new leasing of taxpayer-owned coal reserves in the Powder River Basin, clouding the future of mines including Westmoreland Mining’s Rosebud Mine that provides about 6 million tons of fuel annually for Colstrip.

Eight years ago during his first White House run, Donald Trump stoked populist anger against government regulation by highlighting anti-coal measures taken under former President Barack Obama. The latest moves against coal have teed up the issue again for Republicans seeking to unseat Biden in the November election. Some coal-state Democrats also raised concerns.

“This onslaught of new rules is going to kill jobs and will kill communities like Colstrip,” Montana Republican Sen. Steve Daines said during a visit to Rosebud Mine this week with Republican Gov. Greg Gianforte. “What will change this outcome is an election and a new administration.”

U.S. coal consumption dropped precipitously over the past decade as cheap natural gas and renewables expanded. Yet coal’s political potency endures as detractors try to further curb burning of the fuel that’s a major contributor to climate change and air pollution.

It remains an economic mainstay in communities such as Colstrip, generating jobs where workers can earn $100,000 annually, according to union officials.

The Biden administration defended the latest restrictions on coal as necessary to reduce harmful pollutants, improve public health and address court rulings over climate change.

A Biden campaign representative noted that coal’s decline continued during Trump’s presidency.

“There is no war on coal, there is only a fight for our energy future,” campaign spokesperson James Singer said. “Under President Biden, the United States is closer to energy independence than we have been in decades.”

Even with the ban on new coal leases, companies already hold leases on more than 4 billion tons of coal on taxpayer-owned lands. And administration officials say that’s enough to sustain mining for decades.

Supporters said the crackdown on pollution from coal plants was long overdue. Its origins trace to 1990 amendments to the Clean Air Act that directed the EPA to set standards for pollution reduction technologies.

Dr. Robert Merchant, a pulmonologist from Billings, Montana, said research data is clear that pollution from Colstrip and other plants is linked to medical problems including cancers, developmental delays in children and heart attacks.

“The problem with Colstrip or any large industry like that is they’re very good at understanding the economics as it impacts their balance sheets and bottom line,” Merchant said. “Unfortunately, the health effects are not appearing on their bottom line.”

Representatives of the Northern Cheyenne Tribe had urged the Biden administration to adopt the pollution rules to protect air quality on their reservation just south of Colstrip.

The plant opened in the mid-1970s and was later expanded. It towers over Colstrip, a town of about 2,000 people. It’s linked to the Rosebud Mine by miles of conveyor belts that transport a steady supply of coal to the 1,480 megawatt plant, where it is burned to generate electricity for distribution across the state.

Brian Bird, president of Colstrip co-owner NorthWestern Energy, said the characterization of Colstrip by EPA Administrator Michael Regan during Congressional hearings as the “highest emitter in the country” was deceptive because of the plant’s size — one of the largest coal plants west of the Mississippi River. Bird said Colstrip was “in the middle of the pack” in terms of the amount of pollution per megawatt of power generated.

Some Democrats said federal agencies were moving too fast and too aggressively against coal.

Montana Democratic Sen. Jon Tester said the EPA rules “missed the mark” since it could cost hundreds of millions of dollars for Colstrip to come into compliance. In West Virginia — the second largest coal producer behind Wyoming — Sen. Joe Manchin accused Biden of trying to “score short-term political points” by issuing the new rules in an election year.

Manchin announced Friday that he was leaving the Democratic party and registering as an independent, citing the “partisan extremism” of the two major political parties.

Tester is considered one of the most vulnerable Democrats in the Senate heading into the election, with Republicans needing to pick up just two seats to retake control of the chamber.

His Republican challenger, Tim Sheehy, railed against the “Biden Tester climate cult” following announcement of the ban on new coal leases. Tester spokesperson Eli Cousin said the lawmaker was still reviewing the administration’s proposal.

Manchin is not seeking reelection when his term ends in January. Republican Gov. Jim Justice is running for the seat, and the EPA rules could help push voters into his corner as he faces Democrat Glenn Elliott, the mayor of Wheeling, West Virginia.

Elliott has advocated for more green energy in West Virginia but hasn’t commented on the EPA rules.

EPA officials pledged to work with the Colstrip plant’s owners “to help them find a path forward” in response to concerns from by Tester and other lawmakers. Agency officials said 93% of coal-fired plants had shown they could comply with the new air pollution standards.

“We gave plants the maximum amount of time to comply with the standards we are allowed to under the Clean Air Act — three years plus the possibility of a one-year extension,” EPA spokesperson Shayla Powell said in a statement.

___

Associated Press reporters Matthew Daly in Washington and Leah Willingham in Charleston, West Virginia, contributed to this story.

The Utah Legislature will hold a special session likely in June to discuss a controversial bill that would extend the life of the coal-fired Intermountain Power Plant, Utah Gov. Spencer Cox said Thursday.

“We did have some changes that needed to be made to the bill dealing with a phased-out power plant in Millard County. So, as I mentioned when I signed that bill, we would be working with the sponsor and others for some changes,” Cox said during his monthly news conference on PBS Utah. 

He referred to SB161, Energy Security Amendments, a bill that would prevent plans to close two coal-fueled generators at the Intermountain Power Plant, located near Delta. 

The bill would require the Intermountain Power Agency, owned by 23 Utah municipalities, to allow the state to buy the generators. Ultimately, Utah would try to find a third party interested in purchasing them. 

Those municipal owners opposed the legislation, asking the governor to veto SB161 citing a “rushed” approval process in the House and Senate, risks for the construction of a multibillion-dollar natural gas facility, and the potential of heavier federal regulations. 

The agency also argued that as California, its largest client, moves away from fossil fuels, costs to keep the coal plants running would move to Utah municipalities and ratepayers. However, for the majority of Republican lawmakers, retiring the generators would take a toll on Utah’s energy supply. 

When asked about the possibility of a special session, Sen. President Start Adams said the Legislature is committed to making Utah energy independent and investing in innovative solutions without abandoning reliable and affordable energy sources.

“We are having discussions with the governor’s office regarding SB161 and a possible special session to ensure the best possible path for our state’s long-term prosperity that will benefit all Utahns and keep our energy sector strong,” Adams said in a statement.

A House spokesperson also confirmed they are working on a special session to address some technical changes. But, details are still uncertain.

The state is trying to avoid litigation with Intermountain Power Agency, Cox said on Thursday. But, the state acknowledges that “might not be possible.”

Cox signed the bill in March, but included some remarks about it in his veto letter. 

“We signed these bills with the express understanding that we will work together to address those concerns,” he wrote about SB161 and SB273, which would require the Salt Lake County District Attorney’s Office to track time spent on criminal cases and provide an annual, written report to a legislative committee. 

During his March PBS conference, Cox said the state would exhaust every possibility to keep the power plant running while ensuring environmental regulation compliance.

“We’ll continue working very closely with IPP, we’ll be continuing to work closely with regulators,” Cox said in March. However, he added, he doesn’t expect any “monumental” changes.

Utah News Dispatch is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Utah News Dispatch maintains editorial independence. Contact Editor McKenzie Romero for questions: info@utahnewsdispatch.com. Follow Utah News Dispatch on Facebook and Twitter.

WEC Energy Group in southeastern Wisconsin is planning to significantly expand its capacity for natural gas electricity generation, even as it has vowed to reach net-zero carbon emissions by 2050.

In recent filings by its subsidiary WEPCO (also known as We Energies), the company has asked state utility regulators for permission to bill ratepayers for two new natural gas power plants, a liquified natural gas storage facility, and a 33-mile pipeline to supply the proposed new plants.

Altogether, the projects represent a more than $2 billion investment the utility says will be critical for balancing growing wind and solar generation but advocates say could leave customers unfairly paying for facilities that are likely to be obsolete before mid-century. 

“We hope the commission will reject these proposals, and rather direct WEC to invest in cleaner technologies as well as energy efficiency,” said Ciaran Gallagher, energy and air manager for Clean Wisconsin.  

WEC spokesperson Brendan Conway countered that the company is on track to meet its decarbonization goals, and that the gas plants play a role.

“The key to the renewable energy transition is to have quick start gas plants available for those times when zero carbon generation cannot meet customers energy needs,” Conway said by email. “As we transition our baseload power to renewable energy, these proposed plants will support our customers when solar and wind are not able to provide enough power. We have a number of options, including hydrogen, renewable natural gas and new technologies that will help us meet our 2050 goal. We expect these [new gas] plants will serve customers for decades.”

Demand and reliability

The first indication of the utility’s gas expansion plans came in a Feb. 1 filing in which WEC asked state regulators to let it start collecting $200 million from ratepayers now for supplies it expected to need later for constructing two new gas plants and an LNG facility.

That filing also cites WEC’s plans to convert two coal plants to burn natural gas: its Elm Road Generating Station in Oak Creek, and Unit 4 at its Weston plant near Wausau. 

The company said it needs more gas capacity for three main reasons. Its coal plants are retiring, driven by Clean Air Act regulations. The regional transmission organization, MISO, is giving renewables less credit toward utilities’ capacity obligations. And demand is growing, driven largely by a boom in data centers in the area. 

That means the utility needs more renewables “paired with dispatchable natural gas” and related infrastructure, the filing says. This spring, WEC proposed a 1,100 MW natural gas plant with five simple cycle combustion turbines on the site of its Oak Creek coal plant 15 miles south of Milwaukee and a 128 MW gas plant near the town of Paris in Kenosha County. 

Cover letters for the Oak Creek and Paris gas plant proposals before the Public Service Commission say each project is “a key component” of WEC’s “continued transformation of its generation fleet to ensure reliability and resiliency” and comply with MISO and EPA rules.

Critics counter that gas is not the way to increase reliability, especially since natural gas supplies have been disrupted during extreme weather in the MISO region, including with winter storms Uri in 2021 and Elliott in 2022.

“There are reliability claims dotted throughout these applications,” said Gallagher. “There’s the expectation that MISO is going to devalue or lower accreditation of gas plants because they are increasingly not showing up during these winter [weather] events. Continuing to build out the dispatchable gas plants in WEC’s portfolio is leading us to a potentially more precarious position during these winter storms, as opposed to investing in wind and storage and solar.”

Until recent years, coal made up the bulk of Wisconsin’s power supply.

An 8K form filed April 15 with the Securities and Exchange Commission (SEC) notes that WEC plans to stop burning coal entirely by 2032. The form notes that 1,100 MW of coal units at Oak Creek and 300 MW at its Columbia plant will retire by 2026, and 328 MW at its Weston plant by 2032.

The Elm Road coal plant was built in 2011, at a cost of more than $2 billion plus recent spending on upgrades. Watchdogs point to its imminent conversion to gas as a warning sign about investing in fossil fuels that may soon become unviable. Ratepayers often continue paying for power plants even after they close, as much as hundreds of millions of dollars, as with We Energies’ Pleasant Prairie plant.

“In the early 2000s, the writing was on the wall that coal was bad for our health, for the climate, and there were expected carbon regulations,” said Gallagher. Yet WEC “built some of the last coal plants in the U.S., and Wisconsinites are still paying for those coal plants with their pocketbooks as well as with their health. We’re concerned that this investment in gas power plants and infrastructure is just another cash grab for WEC and their shareholders, as likely the last large gas plants are built in the United States.” 

Grand gas plans 

In an April 5 filing, WEC seeks approval to charge ratepayers $1.2 billion for the Oak Creek gas generators. A separate filing proposes the 128 MW Paris RICE plant at a cost of $280 million. RICE refers to the seven reciprocating internal combustion engines that would make up the plant. 

The town of Paris, near the proposed plant, requested to intervene in the proceeding, noting that “while small in footprint, [the plant] may have a substantial long-term impact on the Town and its residents… The Town is already carrying a high burden of power generation for southeastern Wisconsin.” 

A proposed $456.3 million liquified natural gas facility, also at the Oak Creek site, would compress and liquefy gas delivered in pipelines, storing two billion cubic feet to be ready for gas delivery interruptions and ensuring adequate supply for the new plants, WEC says. 

The proposed new natural gas pipeline, known as the Rochester Lateral, would cost $186 million, WEC’s filing says. 

Conway said that WEC also needs advance permission to start purchasing supplies for the gas investments. 

“Due to long lead-time and high demand of some equipment, we have requested to be able to procure certain items to make sure they are available in a timely manner,” he said. Consumer advocates argue the company shouldn’t be allowed to bill ratepayers for these supplies before the new power plants are even approved. 

The company meanwhile has not yet filed with the Public Service Commission for the Elm Road and Weston gas conversions. In February, the Public Service Commission approved WEC to invest $100 million to increase its share in the combined cycle gas plant West Riverside Energy Center, which it co-owns with Alliant Energy. 

Financial costs, health costs   

Tom Content, executive director of the state’s Citizen Utility Board, said that bill increases for the new natural gas costs would come on top of a $418 million electricity rate increase that We Energies customers are already facing in 2025 and 2026, which could add up to a nearly 30% rate hike for residential customers between 2022 and 2026, according to CUB’s analysis. Those rate increases are in part to pay for three major solar farms as well as one natural gas conversion. 

In an April 12 letter to the Public Service Commission, WEC executive vice president of external affairs Robert Garvin pegged the rate increases to new wind and solar power, inflation, extreme weather, an emerald ash borer infestation that has forced tree removal near power lines, and forgiveness of low-income customer bills. 

Clean energy and consumer advocates lauded the increase in renewable investments, and said WEC Energy should focus on renewables and storage rather than spending more ratepayer money on gas. 

“Ultimately, our state needs a holistic approach to reducing carbon emissions and strengthening our electric infrastructure,” said RENEW Wisconsin Executive Director Sam Dunaiski. “New natural gas plants do not put us on a path toward a fully decarbonized economy. Other solutions to meet Wisconsin’s energy needs could include more distributed renewable generation, energy efficiency, performance-based rate-making, and the coupling of battery storage with solar and wind projects. Wisconsin needs transparent planning in order to make smart energy decisions for our future.” 

Gallagher echoed a long-time criticism of environmental and consumer advocates: that Wisconsin does not require utilities to file regular, long-range outlooks, known as Integrated Resource Plans, like those used by regulators in many states to help guide decisions. A bill introduced last fall would create such a process in Wisconsin. 

“The commission is forced into these more narrow decisions related to the need of one project or another, we’re not even seeing all four of the projects that WEC says are necessary at the same time,” Gallagher said. “There is this lack of comprehensive planning in our state, and we’re seeing the impact with these proposals.” 

Content called on the commission to protect ratepayers from being saddled with costs for unnecessary power generation, including the guaranteed return on investment that utilities get as profit. 

“It always comes back to the whole capital bias,” he said. “The build-build-build bias on the part of every public utility is front and center. The more they build, the more they earn.” 

Health concerns 

As a primary care doctor in Milwaukee, Victoria Gillet says she constantly sees patients in respiratory distress. She says she feels the pollution herself, with aching lungs when she bikes to work.  

“It really impacts people’s lives,” she said. “I know for sure when the air quality gets worse, my patients end up hospitalized.” 

Natural gas-fired plants emit far less particulate matter than coal-burning power plants, as well as less carbon dioxide. But gas plants emit other compounds harmful to public health, including nitrogen oxides and sulfur dioxide.

“When health is your number one focus, it has to be about just getting pollutants gone, not making them less,” Gillet said. “There is no safe number of kids having asthma attacks. The community around the Oak Creek plant fought so, so, so hard to be less impacted by the coal they’re exposed to. We shouldn’t be replacing that with something a little less worse. We should give that entire neighborhood a reprieve from being exposed to polluting industries.” 

She added that her patients include “the kind, wonderful people who want to mow their neighbors’ lawns,” or do healthy outdoor exercise, but air pollution can make such activities dangerous.  

“I’ve tried to be a lot more intentional, making people aware of how this will impact their health, looking at air quality indicators the same way you look at the weather,” she said. “That makes me sad.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

Additionally, coal’s market share in Texas fell below 10% for the first time, landing at 9%, the Institute for Energy Economics and Financial Analysis (IEEFA) noted. Coal’s share had been declining for more than a decade, the IEEFA said, but the trend accelerated in 2016-2017, when ERCOT’s data began to incorporate solar.

In 2017, solar accounted for 0.6% of ERCOT’s demand, the IEEFA said, at 2.26 million MWh. This year’s increase has pushed solar generation’s share to above 10% for the first time, and the growth is expected to continue throughout the year and beyond. Solar generation this March showed an increase of 1.17 million MWh compared to last March, a 56% increase, the IEEFA said. Additionally, while ERCOT currently has 22,710 MW of operational solar capacity, 7,168 MW is expected to be added by the end of the year, an increase of almost one-third.

Coal’s apparent decline in the ERCOT territory doesn’t seem to be an anomaly caused by a few months of low generation, IEEFA says. Even during the hot summer months, coal production never surpassed 20% in 2022, or 15% in 2023, and that trend is unlikely to change this year, IEEFA says.

Originally published in Renewable Energy World.

This was not unexpected, but the federal utility officially announced the decision Tuesday. Kingston’s nine coal-fired units at Kingston by the end of 2027. To replace that generation, TVA will build an energy complex that will house at least 1,500 MW of combined-cycle capacity with dual-fuel aeroderivative natural gas combustion turbines. The Kingston site would also include 100 MW of battery storage and up to 4 MW of solar generation.

TVA was originally considering either a natural gas plant or a solar + storage site, and said a combined-cycle plant paired with dual-fueled aero turbines would be the “best overall solution to provide low-cost, reliable energy to TVA’s power system, and could be built and become operational sooner” than the solar and storage. It ultimately decided to implement both, and the natural gas generation will be in operation prior to Kingston Fossil Plant’s retirement.

The idea was presented in TVA’s Final Environmental Impact Statement issued by the federal utility Feb. 16 after a public review process last year over how to replace the coal-fired units at Kingston.

“We have a detailed workforce plan in place to maintain coal plant expertise and provide opportunities for employees to evaluate options and prepare for next career steps,” said Kris Edmondson, TVA vice president of Power Operations. “The plan includes opportunities to transfer to other TVA locations where employee skillsets are needed, positions in other technologies offering training to support transition to a new job in TVA, and supporting employees interested in retiring.”

TVA says it will continue to evaluate the remaining coal fleet for retirement and replacement generation. To reduce operational, economic and environmental risks, TVA is anticipating retiring its entire coal fleet by the mid-2030s.

Kingston’s nine units can generate about 1.4 GW of electricity at capacity. The plant, located about 35 miles west of downtown Knoxville, entered operations in the 1950s.

TVA said frequent cycling of Kingston’s coal units, reflected in start-up and shutdown events, are currently averaging more than 85 times per year, which the utility said is outside the intended design of the plant.

This is resulting in “increased wear and tear, which presents reliability challenges that are difficult to anticipate and expensive to mitigate.”

TVA also said Kingston has experienced a “significant decline” in material condition over the last five years, including the need for repairs to the lower boiler drum, which the utility said are symptomatic of age-driven material condition failures which are difficult to proactively address.

Merrimack Station has two coal-fired steam units and two kerosene-fueled combustion turbine units for a total of 482 MW (winter capacity). The two coal-fired units serve as seasonal and peak demand resources, while the two combustion turbine units primarily serve peaking roles.

Schiller Station has two, dual-fuel units capable of firing coal or fuel oil, a fuel oil-fired combustion turbine, and a biomass boiler, which reach a combined total output of 155 MW (winter capacity). The units serve mainly as peaking resources for the grid with the exception of the biomass boiler, which operates as a baseload unit, according the Granite Shoals Power website.

GSP says the plant closures will open the path to new renewable generation and battery storage at their sites.

“From our earliest days as owners and operators, we have been crystal clear; while our power occasionally is still on during New England’s warmest days and coldest nights, we were firmly committed to transitioning our facilities away from coal and into a newer, cleaner energy future,” said Jim Andrews, CEO of Granite Shore Power. “By pursuing and ultimately entering into this voluntary agreement with the U.S. EPA, we are keeping that commitment.”

As part of the redevelopment plan, Schiller Station is advancing a battery energy storage system, and for the Merrimack Station site, GSP plans to redevelop nearly 400 acres of land into a clean energy center.

“The New Hampshire Seacoast is an area of high-energy demand and through the repowering of Schiller Station, we will provide carbon-neutral power to support the businesses and families of New Hampshire,” Andrews said. “Our facilities are ideally situated near the infrastructure necessary to transition the region to the next generation of energy resources.”

Utah Gov. Spencer Cox signed a bill that would extend the life of the coal-fired Intermountain Power Plant, but amid pushback from the facility owner and the possibility of conflict with a federal agency, there’s a strong possibility the bill will need to be tweaked in a special session, Cox said.

SB161 would prevent a plan to close out two coal-fired generators, part of the Intermountain Power Plant located near Delta, which have a 1,900 MW rated capacity at the Intermountain Power Project by July 1, 2025. The bill would require IPA to allow the state to buy the coal generators. Utah’s ultimate goal is to find a third party that would be interested in purchasing them.

“If there are opportunities to keep those facilities running, we’re going to want to exhaust every potential, every possibility out there, making sure that we’re complying with environmental regulations that are in place and seeing if we could thread that needle,” Cox said in his March PBS news conference. “We’ll continue working very closely with IPP, we’ll be continuing to work closely with regulators.”

The bill is “very complicated” and there are opportunities to reevaluate steps moving forward, Cox said. However, he doesn’t expect any “monumental” changes.

The governor has been working with legislators to address the issues, he said. 

When asked whether he would support a special session, Senate President Stuart Adams said in a statement, “We are open to having further discussions to ensure the best possible outcome for our state’s long-term energy prosperity that will benefit all Utahns and keep our energy sector strong.” 

The Intermountain Power Agency asked Cox to veto SB161, Energy Security Amendments, citing a “rushed” process in the House and Senate, risks for the construction of a multi-billion natural gas facility, and the potential of heavier federal regulations.

Nick Tatton, board chair at the Intermountain Power Agency, an interlocal entity owned by 23 Utah Municipalities, called the last changes of the bill introduced in the House an “eleventh-hour ambush approach that has characterized legislation targeting IPA over the last few years,” and detailed the agency’s concerns in a letter to the governor, first obtained by The Salt Lake Tribune.

“If Congress imposed an unfunded mandate on the State of Utah, we would be hearing the hue and cry of the same legislators that have now done so to IPA,” Tatton wrote. “SB161 should be vetoed, at a minimum, to remind the Legislature that process matters and to hold it accountable for not having the Sixth Substitute (the latest version of the bill) vetted properly by the public and for not allowing input from those who stand to lose the most by letting SB161 become law.”

Following market demands, Tatton wrote, IPA is in the process of building gas-fueled facilities, also known as IPP Renewed. 

“After years spent by IPA management and other interested parties, including members of the coal industry, searching for credible parties with the potential to purchase power from the IPP coal units, IPA and its advisors concluded that no such purchasers existed,” Tatton wrote.

As California moves away from fossil fuels, costs would move from IPP’s largest client, Los Angeles Department of Water and Power, to Utah municipalities and ratepayers.

Rocky Mountain Power has also declined legislative invites to enter negotiations to purchase power from IPP.

Bill sponsors have said the state must protect its energy resources to achieve energy security. 

“Now they want to close that plant because of California’s energy policy and you take 1,900 megawatts down to 800 megawatts for the new facility they’re building,” he said. “That’s 1,000 megawatts net decrease into our grid,” Rep. Carl Albrecht, R-Richfield, the bill’s House sponsor, said in a debate.

But, it would be “impossible” to pursue IPP Renewed without retiring the coal operations, Tatton said. Besides that, extending the life of the coal plants would require the acquisition and construction of support facilities, which would interfere with IPP Renewed’s construction.

Permits for the retirement of the coal generators were approved by the Legislature in 2012. Since then, IPA has issued nearly $2 billion in bonds and has committed to spending more in construction, service and sales contracts. All of those financial commitments would be at risk with the bill, the letter reads. 

Besides threatening IPP Renewed, Tatton said, SB161 “interferes with municipal control of assets that have been developed and operated without any public funds,” conflicts with environmental permit commitments made to the Environmental Protection Agency, which “most certainly lead to EPA intervention and litigation that will frustrate the goals of the legislation and cost Utah and IPA millions of dollars in legal fees.”

Not complying with commitments made to the EPA may result in an earlier closure of the coal generators and a “more stringent oversight of air permitting in Utah,” which would also translate to other industrial operators having to install more costly pollution controls.

“IPA is still eager to come to an arrangement that avoids the negative impacts of S.B. 161 while preserving the State’s ability to benefit from further development at IPP,” the letter reads.

Additionally, IPA stores coal ash from its combustion process in large ponds, which after a 2015 change of federal regulations would no longer be permitted to use without expensive upgrades. 

The EPA allows the IPA to continue using the impoundments taking into consideration its coal generation closure. EPA said in a letter to IPA, “IPP must cease operations and complete closure no later than October 17, 2028,” to comply with the regulations.

The EPA also oversees the Utah Division of Environmental Quality in its capacity to issue Clean Air Act permits, which could also be compromised under the bill.

“If Utah fails to implement the federally delegated CAA permitting program in accordance with the CAA, the EPA could rescind program authorization and administer the permitting program itself,” KC Becker, EPA’s Region 8 administrator, wrote in the letter. 

Utah News Dispatch is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Utah News Dispatch maintains editorial independence.

The refueling will result in a carbon intensity reduction of 70% by 2030 compared to 2018 levels, AES Indiana said. The coal-to-gas conversion is expected complete by the end of 2026, which would make AES Indiana the first investor-owned utility in the state to cease burning coal.

AES Indiana says converting Petersburg Units 3 & 4 aligns with its 2022 Integrated Resource Plan (IRP). In addition to repowering, the Company’s portfolio includes adding approximately 1,300 MW of wind, solar and battery storage through competitively bid projects.

Last week, AES Indiana announced it acquired the Hoosier Wind project, a 106 MW wind farm in Benton County, Indiana. Earlier this year, AES Indiana received IURC approval for a 200 MW, 4-hour standalone battery energy storage system, the largest in the MISO region.

Petersburg Units 3 and 4 each have a nameplate capacity of 690 MW and came online in 1977 and 1986, respectively. AES Indiana retired the 230 MW Petersburg Unit 1 in May 2021 and the 415 MW Petersburg Unit 2 in June 2023.