At recent meetings in Center Township and Homer City, Homer City Redevelopment LLC Vice President (and former county commissioner) Robin Gorman said the company plans to convert the decommissioned plant to a natural gas facility, arguing that the change would allow the new plant to produce “at least double” its output as a former coal plant, the Indiana Gazette reports.

Gorman added that the company hopes new businesses would be attracted to the area by the increase in production, and it may consider adding hydrogen and solar generation to the site in future projects. For now, Homer City Redevelopment is focused solely on natural gas production, as that project will necessitate the “complete demolition and reconstruction” of the site’s infrastructure, according to the report.

Demolition is expected to kick off in February or March of next year, with an estimated project timeline of two years, Gorman said.

The 1,888 MW plant began generating electricity in 1969, when Units 1 and 2 entered service. Unit 3 was added in 1977. For 30 years, the plant operated almost continuously, achieving a utilization rate, called a capacity factor, near 90%.

According to the U.S. Energy Information Administration (EIA), the market landscape changed for the Homer City plant at the turn of the 21st century. New emissions standards for power plants under the Clean Air Act required the plant to install FGD scrubbers on Unit 3 in 2001 and on Units 1 and 2 in 2014. Pollution control upgrades in 2014 cost the plant owners a reported $750 million. Ownership of the plant changed after bankruptcy in 2017.

As more natural gas-fired plants were built, the Homer City plant was dispatched more for load following instead of for base load. EIA said this change increased annual maintenance costs for the Homer City plant, on top of the debt incurred from the pollution control upgrades. The Homer City plant was operated at an annual capacity factor of 82% in 2005, according to EIA data. The capacity factor dropped to 20% in 2022, contributing in the decision to retire the plant.

Ameren Missouri would spend more than $61 million to offset its past clean air violations under a joint proposal filed Wednesday in federal court.

The St. Louis-based electric utility, which serves 1.2 million customers, has been in litigation for more than a decade over its Rush Island Energy Center, which operated for years in violation of the Clean Air Act.

Ameren shut down Rush Island last month rather than install pollution controls to bring it into compliance with clean air standards. 

In the joint proposal with the U.S. Department of Justice and the environmental nonprofit Sierra Club, Ameren agreed to spend $25 million to provide vouchers for at least 125,000 Missouri households to purchase High Efficiency Particulate Air, or HEPA, filters, prioritizing low-income communities.

Ameren would spend the remaining $36 million to help St. Louis-area school districts switch to electric buses. 

Federal officials will accept comments on the proposal, filed Wednesday in U.S. District Court for the Eastern District of Missouri, before submitting it to the court for approval.

In a statement, Jenn DeRose, a senior field organizer for Sierra Club, said Ameren must pay for having broken the law but “cannot bring back the innocent lives that utility executives cut short or repair the environmental harms of the illegal and toxic air pollution spewed by the coal plant.” 

“I cannot stress enough that civic leaders need to understand that Ameren’s unethical business decisions harm our communities,” DeRose said, “whether it’s polluting our air and water, slow-walking the transition from coal and gas to clean energy, or disconnecting people from electricity that they desperately need to survive.”

A spokesperson for Ameren said in an emailed statement that the Department of Justice resolves the case and “will fund the implementation of two mitigation relief programs, in addition to retiring the energy center.”

Rush Island operated without pollution controls for years, releasing more than 250,000 tons of excess sulfur dioxide. Shutting down the plant will prevent future emissions, but the agreement with federal officials and the Sierra Club is meant to offset the ones Ameren can’t take back.

Ameren opened Rush Island in the mid-1970s, narrowly avoiding a 1977 update to the Clean Air Act requiring pollution controls at newly-constructed coal plants. As long as Ameren didn’t make any upgrades beyond routine maintenance, it wouldn’t have to install the controls.

But the company updated Rush Island’s two units in 2007 and 2010 without installing pollution controls, violating the 1977 Clean Air Act update and sparking a lawsuit by the U.S. Attorney’s Office.

In 2019, U.S. District Court Judge for the Eastern District of Missouri Rodney Sippel ordered Ameren to obtain a permit, install scrubbers and lower its sulfur dioxide emissions. Sippel also ordered Ameren to install scrubbers to temporarily lower sulfur dioxide emissions at its larger Labadie Energy Center in Franklin County to make up for the excess emissions at Rush Island.

The 8th Circuit U.S. Court of Appeals in 2021 upheld Sippel’s order requiring Ameren to install scrubbers, but struck down the requirement at Labadie.

Later in 2021, Ameren announced it would retire Rush Island. It argued the retirement should mark the resolution of the lawsuit. But Sippel ordered Ameren and prosecutors to negotiate potential mitigation measures to make up for the sulfur dioxide emissions, which he said “harm public health and the environment, contribute to premature deaths, asthma attacks, acid rain and other adverse effects in downwind communities, including the St. Louis Metropolitan Area.”

Sippel’s order, issued in June, said over the 14 years since Rush Island’s second unit was updated without scrubbers installed, it has released 275,000 tons of sulfur dioxide. Ameren argues the figure is closer to 256,000 tons.

Missouri Independent is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Missouri Independent maintains editorial independence. Contact Editor Jason Hancock for questions: info@missouriindependent.com. Follow Missouri Independent on Facebook and X.

Repowering is estimated to save customers approximately $281 million over a 20-year period by eliminating the additional O&M costs associated with operating Petersburg as a coal-fired resource, AES said. The repowering is also meant to maintain reliability and reduce carbon intensity by an estimated 70% by 2030 compared to 2018 levels, and repowering to natural gas could reduce hourly CO2 emissions by half.

Repowering Petersburg Units 3 & 4 aligns with AES Indiana’s 2022 Integrated Resource Plan (IRP) and the 2024 IRP updated analysis, which included a third-party reliability analysis confirming that repowering to natural gas is as reliable as coal, AES said. Additionally, AES Indiana is adding 1,300 megawatts (MW) of wind, solar and battery storage through competitive projects.

“For more than a decade, AES Indiana has taken significant steps toward reducing our carbon footprint by planning for a future that includes generation investments focused on cleaner, more efficient energy options,” said Brandi Davis-Handy, AES Indiana President. “We’ve transitioned to a more balanced energy portfolio that aligns with the state’s all-of-the-above energy policy while also maintaining affordability and reliability for our customers. With this approval, we can continue reliably serving central Indiana and meet the growing and evolving energy demands of tomorrow.”

AES Indiana originally filed the request in March of this year. 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.

AES Indiana recently announced plans to invest $1.1 billion in the future of Pike County from 2024-2026. In addition to the repowering of Petersburg Units 3 & 4, the Pike County Battery Energy Storage System and the Petersburg Energy Center will add 250 MW of solar and 180 MW of battery storage to AES Indiana’s portfolio. AES Indiana plans to start construction by the end of 2025 and anticipates completing the project by the end of 2026.

The proposal is the first step in a two-phase regulatory process, which sets the stage for the company to seek new project bids, likely beginning by the end of 2025. The proposal, called a Just Transition Solicitation, proposes additional value for locating future new power generation in former coal plant communities.

Xcel Energy-CO’s Clean Energy Plan – approved by the Colorado Public Utilities Commission – includes the retirement of Xcel Energy’s last remaining coal generation plants in Hayden and Pueblo. Hayden Station would retire by 2028 and Comanche Generating Station in Pueblo would retire by the end of 2030, with reduced operations beginning in 2025. 

The new generation will support the company’s 2050 carbon-free goal by targeting continued emissions reduction. As of 2023, Xcel Energy cut carbon emissions by 53% from 2005 levels in Colorado and plans to achieve nearly 85% reductions by 2030 with new solar, battery storage and wind as part of its Clean Energy Plan.  

The company worked with community stakeholders and local officials to evaluate possible energy generation resources which could maximize local investments and economic benefits, support employees and communities impacted by plant retirements, and supports the company’s clean energy goals. Xcel Energy said it has a “solid track record” of making these types of transitions with no layoffs. It touts 23 coal unit closures — the most recent at the end of 2023 — without forced workforce reductions.

“For nearly sixty years, the dedicated employees at Hayden Station and Comanche Generation Station have provided reliable and safe service for our Colorado customers and communities. We are committed to transitioning our employees into new roles as needed, something we’ve done successfully at other Xcel Energy plants,” said Robert Kenney, President of Xcel Energy-CO.

The Colorado Public Utilities Commission will ultimately decide whether to approve the proposed Just Transition Solicitation portfolio, potentially in the fall of 2026, based on the energy project bids the company receives as part of the bid solicitation, Xcel Energy said.

Earlier this year, we reported that a Colorado advisory committee created by Xcel Energy recommended the utility consider replacing the Comanche Station Unit 3 coal plant with cleaner options, namely advanced nuclear. The Pueblo Innovative Energy Solutions Advisory Committee (PIESAC) was assembled to study and make recommendations regarding future plans at Comanche Generating Station, located in Pueblo, Colorado. The 11-member committee released its recommendations in a report.

After reviewing the clean energy technologies that could be available by 2031, the committee concluded that the scope should be expanded to 2034, citing the lack of resources available by 2031 that could also provide a satisfactory amount of jobs. PIESAC recommended top replacement options of “advanced nuclear” such as small modular reactors (SMRs), or a new combined cycle gas plant with carbon capture. But the committee clearly favored the SMR option, citing more jobs and tax benefits.

The powerful Indiana Utility Regulatory Commission can — and should — investigate early retirements of coal-burning power plants, Indiana Attorney General Todd Rokita wrote in a memorandum of legal guidance released Tuesday.

Rokita opined that the IURC is implicitly duty-bound to prevent such closures until a utility finds “dispatchable” replacement power. But the Statehouse, Rokita added, could add legal requirements.

Sen. Chris Garten, a Republican from Charlestown, requested Rokita’s help. He said lawmakers are considering changes.

Garten, who says he’s supportive of all energy sources, contacted Rokita about coal retirements specifically because “you don’t really see closures of other facilities right now.”

Coal plants have historically had 50-year lifespans, according to a 2019 article published in Nature Communications. But they can last longer with fixes and upgrades.

U.S. coal plants are about 44 years old, in a capacity-weighted average, according to an analysis by the U.S. Energy Information Administration. Plants scheduled for retirement this year averaged 54 years of age: almost a decade older.

But coal plants decommissioned amid their expected decades-long lives have become a political flashpoint.

Proponents maintain that early retirements are critical to avoiding the worst impacts of climate change, while opponents arguing the closures jeopardize affordable energy supply. Both sides offer contrasting views on whether keeping the plants online benefits utility customers.

Going local

Although Garten requested the legal guidance, Reliable Energy — an energy advocacy group focusing on coal, natural gas and nuclear power — distributed the resulting opinion on his behalf.

The organization kickstarted the search for clarification after observing shortage warnings from electric grid operators, according to a statement made to the Capital Chronicle. The group contacted lawmakers about the IURC’s “exclusive focus” on construction of new energy facilities over closures and conversions.

Lawmakers thought the agency had the authority to oversee closures and conversions, but commissioners told Reliable Energy they didn’t, the group said.

Garten said he asked Rokita for clarity to support development efforts in his district. The River Ridge Development Authority is charged with replacing revenue lost when the massive former U.S. Army manufacturing plant shuttered in 1972, after the Vietnam War.

“River Ridge has done a fantastic job of attracting and recruiting all types of businesses, all types of industry,” Garten said. But, he estimated, the development has lost two projects in the last year or two because a utility — Duke Energy Indiana — “couldn’t electrify them.”

Utility spokeswoman Angeline Protogere said the utility has worked with River Ridge to bring nearly 30 successful projects to the development.

“There are two issues being confused here — power supplies and power delivery through major power lines,” Protogere said of Garten’s comments. “There has never been a question of adequate power supplies to serve this area, and we will continue to work with any customer on the power delivery infrastructure they need to get electricity delivered to them. We can’t, though, build major new infrastructure until we are confident a customer is coming to an area because that is a cost that all our customers end up paying for.”

Garten, however, critiqued the utility’s decision to ask for higher rates.

The utility’s request would raise its annual revenues by about $492 million. The Indiana Office of Utility Consumer Counselor, a state agency, thinks only an increase of $185 million is “warranted,” according to its website.

“This data center is now going up in River Ridge and Duke has proposed to the IURC a 16% rate increase,” Garten continued. “And so I’ve got constituents contacting me who are concerned. They’re watching this … being built, and the rates are going to go up. They want to know what they’re getting for the rate increase, and rightly so.”

Duke’s Protogere said the company’s rate hike would pay for infrastructure improvements in southern Indiana.

Rokita’s guidance

Indiana Code requires that electric generation policy be made with reliability, resiliency, affordability, stability and environmental sustainability in mind, Rokita observed in his memorandum. The IURC, he wrote, is tasked with regulating how energy is provided.

The law also gives the IURC investigatory powers when utilities want to retire, sell or transfer facilities; in cases of inadequate service; and when the agency believes “any matters relating to any public utility” should be probed, Rokita noted.

“These factors all lead to the reasonable conclusion that the IURC has not only the statutory authority, but an obligation, to investigate and evaluate proposed retirements of thermal generation facilities in the state,” he opined.

That includes denying early retirements “if they are determined to have a negative impact on grid reliability and resilience.”

Rokita said the IURC doesn’t need explicit authority, but that lawmakers could give it anyway. They could also go further, and clarify that such action is mandatory and not discretionary.

House Bill 1382, introduced last session, would’ve spelled that out. It also laid out conditions utilities would’ve had to meet in order to apply for permission to close any “fossil fuel fired” plant. The proposal never got a hearing and died.

The Hoosier Environmental Council said that bill would slow Indiana’s transition away from coal, a dirty fossil fuel, to greener energy sources.

“Besides adding an unnecessary burden to the Indiana Utility Regulatory Commission, this bill encourages our public utilities to keep their current energy generation sources running as long as possible, which are majority fossil fuels,” the council said on its website.

Garten said he’s working with the utility committee heads of both chambers, as well as legislative leadership, on a “holistic approach.”

“We’re having those conversations now, because I do not think this is a one-off,” Garten said.

He said a proposal reflecting Rokita’s guidance could be part of the solution.

“If you go all the way back 20 years ago, electric rates in Indiana were the fifth-lowest in the nation. We’re now 32nd and so, you know, to me, this is basic supply and demand,” he continued. “I think there’s a case to be made that our utilities could be perversely incentivized to constrain supply, because when supply goes down, demand is going to go up, which means prices go up.

Garten said the IURC has “done a fair job.”

But when asked if the state’s current system of reimbursing utilities for their investments is working, Garten said, “That’s part of the conversation we’re having right now. Everything is on the table.”

“This is a big enough issue (that) I don’t think you can just change one thing. I don’t think there’s a silver bullet solution,” he added.

Indiana Capital Chronicle is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Indiana Capital Chronicle maintains editorial independence. Contact Editor Niki Kelly for questions: info@indianacapitalchronicle.com. Follow Indiana Capital Chronicle on Facebook and X.

The five-unit, 2,845 MW Gibson station is one of the largest coal-fired plants in the U.S. Duke Energy owns Units 1-4, while Wabash Valley Power Association and Indiana Municipal Power Agency co-own Unit 5.

According to the IRP, Gibson Units 1 and 2 would be converted to enable co-firing natural gas with coal, allowing them to continue to operate through 2038. The plant was previously expected to retire three years earlier.

Under the plan, Duke Energy would retire Gibson Units 3 and 4, replacing them with a 2×1 NGCC plant by 2032. Gibson 5 is listed as being retired by 2030.

Duke would also retire Cayuga coal-fired units 1 and 2 by 2030 and 2031, respectively. Two 1×1 natural gas combined-cycle (NGCC) units would are added at the site, replacing the retiring coal and adding 440 MW of incremental capacity by 2031.

Finally, Edwardsport would be converted to operate on 100% natural gas by 2030. Renewables and energy storage would also be added in the late 2020s, according to the plan.

The IRP proposal caps off a series of stakeholder meetings held in 2024. The proposal is expected to be submitted to state regulators by November 1 and would then follow the usual approval process.

The announcement was made by plant owner Uniper, which confirmed the power station would cease operating at midnight.

The plant began generating power in 1967 and according to the Uniper release, has produced enough energy to make more than 21 trillion cups of tea since commissioning.

January this year saw all four of Ratcliffe’s 500MW units run together for the last time. Since then, operations have been slowing down, with the last delivery of coal by train arriving in June.

Michael Lewis, CEO, Uniper commented on the closure in a statement: “For me, Ratcliffe has always been more than just a power station—it has been a pillar of the UK’s energy security for decades. Built during a time when coal was the backbone of industrial progress, Ratcliffe powered over two million homes and businesses—equivalent to the entire East Midlands region.

“It played a crucial role in boosting economic growth and supporting the livelihoods of thousands of people. This will be the first time since 1882 that coal has not powered Great Britain. As we close this chapter, we honor Ratcliffe’s legacy and the people working here, while embracing the future of cleaner and flexible energy. In this context, Uniper aims to invest in technologies like CCS, Renewables and hydrogen. The goal is to decarbonize our remaining power assets and to deliver low carbon fuel as well as green and reliable energy to our customers.”

The UK’s last coal power plant was able to continue operating due to the technical advancements and modifications made over the years to reduce emissions. It was fitted with a Selective Catalytic Reduction (SCR) emission control facility to reduce NOx emissions and was equipped with a Flue-Gas Desulphurisation (FGD) plant to remove sulphur dioxide from the exhaust flue gases before they enter the atmosphere.

Peter O’Grady, plant manager, Ratcliffe-on-Soar power station commented on the impact of the closure on the team, emphasizing the mixed emotions that accompany the milestone.

Said O’Grady: “It is an emotional day for me as well as for the team. When I started my career 36 years ago, none of us imaged a future without coal generation in our lifetimes. I am incredibly proud of what we’ve achieved together over the years and to be part of this energy milestone as the country focuses on a cleaner energy future.”

Following closure, the site will go through a decommissioning process, which is expected to last around two years, before the site can be handed over to a demolition contractor.

The decommissioning process will remove hazards from each plant area such as bulk stored oils, chemicals and gases as well as removal of any bulk byproducts and wastes.

End of an era for the UK

Coal has been a mainstay of the UK’s economy since the 1800s, with the world’s first coal-fired power station set up in London in 1882.

In 2012, the UK was still generating around 40% of its electricity from coal, however, in 2017 the UK and Canada founded the Powering Past Coal Alliance (PPCA) to advance the transition away from coal, which was followed by the launch of the Clean Power Alliance by UK Foreign Secretary, David Lammy.

Ed Matthew, campaigns director at independent climate change think tank E3G, commented in a statement on the closure of Ratcliffe-on-Soar: “The UK was the first country to build a coal-fired power station. It is right that it is the first major economy to exit coal power. This is true global leadership, lighting the path for other countries to follow.

“The UK will now focus on rapidly eliminating unabated gas from its power system and oil from transport. The clean energy revolution is in full swing and the prize will be cheaper, more secure and less polluting power and a chance to end the climate crisis.”

Originally published in Power Engineering International by Pamela Largue.