In June 2021, NRG told PJM it planned to retire Indian River 4 in 2022. PJM then conducted a reliability analysis, which indicated that the 411 MW unit’s removal would lead to grid reliability issues. The grid operator identified a series of transmission solutions to address those issues.

Delmarva Power, which owns the transmission in the region, has completed the needed transmission additions, PJM reported through its PJM Inside Lines publication. This means the coal plant in southern Delaware can retire 22 months before it was scheduled.

Indian River 4 has been under a Reliability Must-Run (RMR) arrangement. Now that Delmarva Power has completed the final segment of the necessary transmission upgrades, PJM has notified NRG of its intent to terminate the RMR arrangement.

The unit will officially be retired in February 2025. The final determination of the total savings will depend on FERC’s approval of a proposed settlement rate, PJM said.

“Delmarva’s good work to complete this project far ahead of schedule is a win for our customers, both from a reliability and affordability perspective,” said Mike Bryson, PJM’s Sr. Vice President for Operations. “PJM regards RMR arrangements as a last resort to keep units temporarily operational to maintain system reliability while we make transmission improvements to balance the system, so the sooner we can get the work done, the better.”

This has created headaches and financial implications for coal plant operators, according to the Institute for Energy Economics and Financial Analysis (IEEFA).

Over the last two years, U.S. utilities and power producers have collectively accumulated a 138-million-ton stockpile of unused coal at their plants, IEEFA cited from the U.S. Energy Information Administration (EIA) in a recent analysis.

The stockpile matches the entire amount of coal that Appalachia is expected to produce in 2025 and represents $6.5 billion of unused inventory at a time when coal is rapidly being displaced by renewables, IEEFA said.

The $6.5 billion figure is based on a $47.22 per ton average cost of coal delivered to plants (including transportation) from January through September of this year.

EIA expects stockpiles to remain high, staying well over 100 million tons throughout 2025.

Power producers just aren’t burning coal as often.

This year, utility-scale wind and solar will produce more power — 665.8 million megawatt-hours (MWh) — than coal for the first time, according to the EIA’s November Short-Term Energy Outlook.

Gas-fired generation, which became the dominant fuel in 2016 and now delivers more than 40% of the country’s power, continues to push coal out of competitive power markets.

High power demand during winter and summer extremes have historically been key seasons for coal, but utilities and power producers are now getting more of that electricity from renewables and gas.

U.S. coal plants now collectively burn just 1 million tons a day, half as much as in 2015, based on the 12-month average through September. At that rate, it would take power producers more than 4 months to use up all the coal sitting around, IEEFA reported.

When coal stockpiles previously soared, like in 2009, 2012, 2016, and again in 2020, plant owners worked hard to reduce them to a 50- to 60-day supply, but it took them anywhere from 16 months to almost three years to do it, IEEFA said. But rarely has so much coal lingered for so long as it has currently.

The analysis said power companies will need to buy a lot less coal to bring their stockpiles down, even if they keep burning it at the same rate. EIA forecasts coal production output to fall to just 469 million tons in 2025, down from 505 million tons in 2024 and 578 million tons in 2023.

Meanwhile, coal continues to fade from the U.S. generation mix. In 2025, IEEFA estimates that another 13 gigawatts (GW) of the remaining 173 GW of coal-fired capacity will either retire or be converted to gas, further reducing the market for coal.

The company said it now intends to run the Baldwin plant through 2027 instead of retiring in 2025, as previously announced, while still meeting federal Environmental Protection Agency retirement and pond closure obligations.   

“Vistra is committed to the responsible transition of our fleet in Illinois, and in this case, the most reasonable path forward is to continue to operate the plant as a reliable bridge to 2027, as we, and others, bring new generation assets online in the state,” said Jim Burke, president and CEO of Vistra. “As many organizations have recently raised concerns over reliability and resource adequacy in central and southern Illinois, we are taking action and delivering solutions that balance the needs of reliability, affordability, and sustainability.”

With the addition of a new 68 MW utility-scale solar and 2 MW/8 MWh energy storage system, which began generating power this month, Baldwin is now more of a power generation hub than a traditional power plant. The $135-million investment involved the placement of over 200,000 solar panels across 420 acres of property the plant has owned and maintained for decades. The solar generation facility will produce approximately 140,000 MWh annually over the next 20 years. 

The 1,185-MW Baldwin Power Plant produces enough electricity to power approximately 592,500 homes. Approximately 120 employees operate the Baldwin plant. Union employees are represented by IBEW Local 51.

Reusing plant sites

Across the country, Vistra is undertaking a “methodical, site-by-site analysis” of its coal fleet to determine the economic feasibility of repurposing the sites by retiring some technologies and renewing the plants with less carbon-intense generation, including solar and energy storage. 

The investment at the Baldwin plant site is part of the State of Illinois’ Coal-to-Solar and Energy Storage Initiative, which encouraged the development of renewable energy assets at existing power plant sites. Along with Baldwin, Vistra continues to make progress on other Coal-to-Solar sites, including:  

• The 44-MW solar and 2 MW/8 MWh energy storage facility at the Coffeen Power Plant site is generating power.
   
• Construction of the 52 MW solar and 2 MW/8 MWh energy storage facility at the Newton Power Plant will begin in 2025. 

Separately, construction has begun on a 405 MW utility-scale solar facility that will interconnect at the company’s retired EEI-Joppa Power Plant through a to-be-constructed approximate 8-mile transmission line. 

Since its merger with Dynegy in 2018, Vistra has taken steps to operate, retire, and transform its coal plant fleet in Illinois. The company has committed to retiring these plants by the end of 2027 to comply with existing federal EPA regulations.   

Economic impacts

Vistra argues that the Baldwin Power Plant provides “significant direct and indirect” economic benefits to the region and state. An economic impact study projected the plant’s direct, indirect, and induced economic benefits and concluded that within Randolph County, the existing Baldwin plant: 

• Sustains approximately 298 full-time direct, indirect, and induced jobs in the area;
• Generates more than $41 million in income for local workers in the county; and
• Has a total regional economic output of $262 million 

The new solar facility is expected to generate $6 million in total property tax payments over the project’s life, Vistra said.

Vistra and data centers

Last month, Vistra said it was engaged in discussions with large load customers for the potential sale of power from its nuclear and gas plants through long-term agreements. Stacey Doré, Vistra’s Chief Strategy and Sustainability Officer, told investors the company was pursuing deals based around multiple plants in its portfolio. She said one approach being discussed would be pursuing co-location deals at multiple sites in combination with building new generation. Doré said Vistra specifically in discussions with two large companies about building new gas plants to support a data center project. Gas plants in both PJM and ERCOT are drawing interest, she said.

The company is also in early discussions with some of the hyperscalers about nuclear uprates, Doré said. The hyperscalers are considered the companies that are predominately driving large-scale buildout of AI data centers, like Amazon, Google and Microsoft

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.

Canada-based TC Energy has withdrawn from Project Tundra, according to Politico’s E&E News. TC Energy was a primary sponsor, along with Minnkota Power Cooperative.

TC Energy played a pivotal role as a partner in the development of Project Tundra, and their contributions provided tremendous value,” a Minnkota Power Cooperative spokesperson said in a statement provided to Power Engineering. “While we remain optimistic about advancing the project, securing capital resources will be essential to reaching a final investment decision.”

Project Tundra aims to capture carbon from the Milton R. Young Station, a coal-fired plant near Center, North Dakota. The project would use Mitsubishi Heavy Industries’ KS-21 solvent to capture CO2, which would be permanently stored in saline geologic formations beneath and surrounding the power plant. The storage site is approved for a Class VI well permit.

Minnkota had said it plans to retrofit the coal-fired plant’s 430 MW Unit 2 to capture up to 90% of its CO2 emissions. Unit 2 is a cyclone-fired wet bottom boiler from Babcock & Wilcox. The project could capture an annual average of 4 million metric tons of CO2, according to project leaders said.

Project Tundra received federal funding from the U.S. Department of Energy (DOE) last year through two separate totaling nearly $400 million. This was in addition to another $43 million received from the federal government in 2020.

Carbon capture is seen by proponents as an emerging technology that could keep fossil-fired plants viable while reducing emissions. Under the Biden Administration’s EPA Power Plant Rule, coal- and new natural gas-fired plants would have to capture their carbon or close by various compliance dates in the 2030s.

Opponents of the rule, which may not survive the first few weeks of the new Trump Administration, have expressed that CO2 capture systems are costly and energy-intensive.

Officials with the National Rural Electric Cooperative Association (NRECA) noted in court filings earlier this year that Project Tundra sits atop ideal geology for storage, has been in planning for nearly a decade, and has used government funding for two-thirds of the costs so far, yet still would not meet the 90% capture rate.

They also said other variable factors that could further delay the project include labor and supply chain constraints.

The Minnkota Power spokesperson said the co-op continues to assess federal funding opportunities, potential EPA compliance obligations and ongoing supply chain and inflationary pressures. The spokesperson said the co-op looks forward to a final investment decision “when the necessary conditions align.”

We have reached out to TC Energy for comment and will continue providing updates to this story.

When Utah lawmakers passed legislation aimed to prevent what they considered the premature closure of the state’s fossil fuel generators, they thought that would effectively keep Intermountain Power Plant coal units open past their 2025 retirement date.

Now they’re looking to make sure it happens. 

The Legislature earlier this year approved SB161, which would block closing two coal-fired generators that are part of the Intermountain Power Plant located near Delta — to the dismay of the Intermountain Power Agency and some Utah municipalities, while threatening the approval of federal air quality permit — and allow the state to buy the generators. That bill was drafted after the Legislature commissioned a study on the plant’s potential and its environmental regulations through HB425, which passed in 2023. 

Lawmakers are now planning to consider a bill to cover a spot they missed, Rep. Colin Jack, R-St. George, said Wednesday — potential switchyard equipment disconnections that could make existing coal units “unusable.” 

“You could say, ‘why do we even need this bill? We had HB425 that said that we have to leave the coal plants functional and usable,’” Jack said. “And without station power and without the switchyard access, they’re not functional and usable. But this just clarifies that, since there was apparently a gap in that understanding.”

Titled Decommissioned Asset Disposition Amendments, the legislation would prohibit an entity from “altering facilities that provide power to station service, disconnecting from or modifying existing interconnections and critical switchyard equipment; and taking actions that would require a new plant owner to make an interconnection request.”

Cameron Cowan, general manager of IPA, told the state-appointed Decommissioned Asset Disposition Authority that the agency won’t take any action to prevent the functionality of the coal units, in compliance with HB425. However, there are some exceptions related to the IPP Renewed project, a multibillion-dollar natural gas facility that was meant to replace the facility’s fossil fuel generation.

“IPA is obligated under existing requirements to cease operation of the coal units permanently in 2025,” Cowan wrote in a letter. “Also, the coal units will no longer be interconnected with a transmission system because the positions at the IPP switchyard will be repurposed consistent with plans for the IPP Renewed project that were developed years ago.”

However, Cowan said, any changes to the design of IPP Renewed since the enactment of HB425 will not prevent the functionality of the coal units.

Two Democratic lawmakers questioned why the bill is making the issue a priority now, when IPA’s intent to drop its coal units has been known for over a decade.

“I was probably here (10 years ago), and I probably should have raised more questions, but I didn’t,” Jack said. “I thought things were going in a good way, but evidently, they’re not.”

While most lawmakers in the Public Utilities, Energy, and Technology Interim Committee recommended the bill for the general session, outgoing Senate Majority Leader Evan Vickers, R-Cedar City, successfully requested that the bill doesn’t bypass any committee hearings in 2025, as there are still concerns and questions to be answered about IPA’s capacity to run its natural gas project, and the timing to issue new permits if coal plants were to be disconnected.

“I want my cake and I want to eat it, too,” Vickers said. “I want them to be able to go through with their new project. But I also want to keep those coal plants open and running. The only question I have is strictly on the process.”

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 X.

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 energy landscape is undergoing a seismic shift, driven by federal regulations and increasing demand for more efficient power generation with fewer carbon emissions. For the first time ever the U.S. Energy Information Administration was unable to forecast the amount of new capacity for 2024, because the demand was changing so rapidly with the influx of onshoring, data centers, electric vehicles and coal retirements.

In today’s hot market, getting new generation online can be challenging due to permitting delays, interconnection queues and the limited availability of original equipment manufacturers. However, coal-fired power plants are increasingly being converted to natural gas. A wave of fuel conversions and gas additions is expected over the next five to seven years, with some of these projects serving as temporary solutions for future combustion turbine projects. As coal-fired power plants face growing pressure to retire or comply with stringent EPA restrictions, converting to natural gas offers a viable solution.

Capacity Factors and Operational Implications

A power plant’s capacity factor, which measures its efficiency and reliability, is a crucial consideration when planning a conversion. Improving a plant’s capacity factor may trigger a new source review under current regulations, raising concerns among utilities about compliance and operational risks. Because of these concerns, it is essential to verify that increasing the capacity factor would not inadvertently trigger a new source review, as such a review could introduce additional regulatory and operational challenges.

Coal-fired plants frequently grapple with forced outages due to issues such as slagging or fouling. Soot blowers clear ash and slag during power generation, though frequent use may create operational inefficiencies.

Switching to natural gas reduces the frequency of maintenance and lowers the risk of equipment failures. Gas-fired plants provide greater reliability and efficiency, especially during peak demand, making them a more dependable option for modern energy production.

Addressing Grid Demand and Regulatory Challenges

Technologies such as data centers and electric vehicles are driving higher energy consumption, which is putting increased stress on the electric grid. While coal-fired power plants have been a significant contributor to grid capacity, maintaining them will become more challenging due to stricter EPA regulations. When coal-fired power plants are retired, they leave a significant gap in both base load and dispatchable power, unlike weather-dependent renewable energy sources. Converting coal-fired plants to natural gas has become an attractive solution to fill this void, as natural gas is well-positioned to meet current demand with fewer emissions, greater operational efficiency and quicker dispatching.

Interconnection and Permitting Advantages

One of the significant advantages of converting existing coal-fired plants to natural gas is that the interconnection to the grid is already in place. This eliminates the need for a new interconnection agreement or costly upgrades to transmission lines, which is often a major concern for greenfield development. In addition to this, many of the necessary environmental permits are likely to be retained, bypassing the lengthy process of securing new approvals. With these foundational elements already addressed, utilities can focus on prioritizing long-lead-time equipment, streamlining the conversion process.

Improved Efficiency, Reliability and Cost Savings

Additionally, converting a coal-fired plant to natural gas allows utilities to re-use significant portions of their existing equipment, thereby reducing capital costs. Equipment like steam turbines, condensers and transformers can often be retained, while new components, such as gas or dual-fuel burners and controls, are installed to facilitate the fuel switch. By leveraging existing infrastructure, utilities can also save on long-lead procurement items, shortening project timelines compared to building a new plant from the ground up.

Dual-fuel or co-firing conversions, which enable power plants to run on both coal and natural gas, offer utilities a way to keep using assets. These conversions provide operational flexibility by enabling plants to switch between coal and natural gas or use a combination of both fuels, depending on market conditions. This capability allows utilities to manage operational costs more effectively when fuel costs fluctuate. Additionally, dual-fuel systems help power plants meet stricter environmental regulations by burning cleaner natural gas to reduce emissions while maintaining some or all of their original coal capacity.

Potential for Staff Retention

Another benefit of converting existing plants is the potential to retain staff, as many operational and maintenance roles remain relevant after the switch to natural gas. Maintaining a skilled workforce supports local economies by preserving jobs, while also protecting institutional knowledge and reducing retraining costs. After coal operations end, plant staffing can often be adjusted, allowing clients to reassign employees to other roles within the company. This approach helps address the challenge of finding new employees to step into roles left by retiring staff.

Converting coal-fired power plants to natural gas represents a forward-thinking strategy for utilities navigating a rapidly evolving energy landscape. This transition not only addresses regulatory compliance and operational efficiency but also supports a reliable power supply to meet increasing grid demands. As the pressure to meet increasing power demands while reducing carbon emissions intensifies, natural gas plays a pivotal role in shaping a sustainable and resilient power generation sector.

Originally published by Burns & McDonnell.

About the Author: Brian King joined Burns & McDonnell in 1999, launching a career focused on improving boiler performance for energy clients. His experience includes project development, construction management and process design. Brian has technical knowledge in tuning and commissioning low-NOx burner systems, overfire air systems, selective noncatalytic reduction (SNCR) systems and activated carbon injection systems. Brian also brings his skills to coal-to-gas conversion projects, adapting coal-fired boilers for modern applications.

Power-intensive data centers will drive growth in electricity demand in the near future, says the utility serving the most Kentuckians. It plans to meet that demand by continuing to replace coal-fired power with natural gas while potentially adding up to 1,000 megawatts of solar power by 2035.

Investor-owned Louisville Gas and Electric and Kentucky Utilities (LG&E and KU) outlined those steps and others in an integrated resource plan filed Oct. 18 before the Kentucky Public Service Commission (PSC), the state’s utility regulator. Kentucky utilities are required every three years to file plans for how they will meet demand at the “lowest possible cost,” although they are not bound to follow them.

The new plan anticipates adding no new coal-fired generation while building as many as four new natural gas-fired plants plus battery storage systems for solar energy — in addition to a natural gas plant already slated for construction. 

The PSC will consider the new plan as environmentalists in Kentucky push for a faster pivot to renewables and amid urgent calls from climate scientists to halt the burning of fossil fuels to mitigate the worst impacts of climate change. 

There’s also uncertainty over whether new Biden administration regulations that seek to curb nearly all heat-trapping greenhouse gas emissions from power plants will withstand court challenges from utilities, coal advocates and Republican attorneys general including Kentucky’s Russell Coleman. 

Data center growth reflects nationwide boom

The utility’s plan says Kentucky is “well-positioned” to participate in the nationwide boom in data centers thanks to a lower risk of severe weather, available telecommunications infrastructure and water to cool equipment, as well as “favorable tax incentives.” 

Data centers are essentially computer hubs that power the internet, ranging from storing data on the “cloud” to processing credit card transactions and the surge of artificial intelligence services. They need a tremendous amount of electricity, sometimes on par with what an entire coal-fired power plant produces. The Lantern previously reported the parent company of LG&E and KU was in talks with data centers interested in locating to Kentucky, and Kentucky lawmakers passed tax breaks this year to incentivize data centers to locate in Jefferson County. 

“The Companies’ Economic Development team is working with a growing number of data center projects that vary in stages of development, but which mostly have very large power requirements,” the utility states in its planning documents. 

The utility currently needs about  30,000 megawatts of electricity a year. Models forecast that could increase by 30% to 60% by the early 2030s. 

Data centers could increase the utility’s load by 1,050-1,750 megawatts, according to the utility’s modeling. For reference, its forecast peak load in the summer of 2024 was 6,115 megawatts. 

Seeking more natural gas and no new coal 

Burning coal generated 68% of Kentucky’s electricity in 2023, down from more than 90% a decade earlier, according to the U.S. Energy Information Administration. Only two other states, West Virginia and Wyoming, were as reliant as Kentucky on coal for power generation, making Kentucky an outlier in a nation that has generally transitioned to lower-cost natural gas and renewable energy. 

LG&E and KU coal-fired power plants make up over 60% of the utility’s capacity during the summer. The utility anticipates moving away from coal-fired power in favor of new natural gas-fired combined cycle plants. 

Depending on future demand, the utility foresees building two or three new natural gas-fired combined cycle plants to be paired with several utility-scale battery storage systems between 2028 to 2035. The natural gas plants would generate about 1,935 megawatts of summertime load — energy needed to meet demand at a given time — by the early 2030s.  That includes power from another natural gas-fired combined cycle plant the utility already is slated to construct by 2027 after receiving permission from the PSC. 

That new natural gas-fired plant was opposed last year by environmentalists as a costly investment that would lock in ratepayers to decades of fossil fuel instead of pivoting to renewables that don’t create greenhouse gas emissions. Similar opposition has met other utilities’ plans to build natural gas-fired plants including the Tennessee Valley Authority. LG&E and KU’s coal-fired Mill Creek Generating Station in Louisville in September 2024. One of its four units is scheduled to be retired by the end of the year, resulting in an expected small savings for consumers. (Kentucky Lantern photo by Liam Niemeyer)

The Kentucky utility’s plans for investing in natural gas-fired plants conflict with a call last year by the leader of the United Nations for carbon-free electricity generation in developed nations by 2035 and a phase out of coal-fired power by 2030 in order to prevent the worst harms from climate change. The call was based on research from climate scientists including U.S. institutions such as NASA. LG&E and KU has previously pointed to goals set by its parent company to have net-zero emissions by 2050. 

Burning natural gas, which consists primarily of the potent greenhouse gas methane, for electricity is considered to release less carbon dioxide into the atmosphere compared to the burning of coal, but environmental advocates have raised concerns that methane leaks during production and transportation of natural gas are wiping out progress made by the United States on curbing greenhouse gas emissions by phasing out coal-fired power. 

LG&E and KU already has approval to retire one of four coal-fired units at its Mill Creek Generating Station in Jefferson County by the end of this year and another coal-fired unit at Mill Creek in 2027. The utility estimates that retiring the first Mill Creek unit will shave some pennies from ratepayers’ bills starting in March.

LG&E and KU projections call for retiring the other two units at Mill Creek and a single remaining coal-fired unit at E.W. Brown Generating Station in 2035. 

That would leave Ghent and Trimble County generating stations as its only operating coal-fired plants by 2035. According to the utility, both of those plants would need upgrades to meet existing or anticipated federal regulations on ozone-producing nitrogen oxide emissions and water pollution. LG&E and KU stated it isn’t considering building any new coal-fired power plants because of “the high cost and environmental risk.”

More solar expected, but not until 2028

LG&E and KU’s plans also include more investments in utility-scale solar, potentially adding 500-1,000 megawatts, though the soonest it expects it could add more solar is 2028. The utility is currently planning to build two 120-megawatt solar installations in Mercer and Marion counties; it already has a solar installation in Mercer County at its E.W. Brown Generating Station.

The utility said its agreements to purchase solar power from private companies don’t appear to be moving forward due to issues with getting solar connected to the power grid and cost increases, though adding hundreds of megawatts of new battery storage “could help pave the way for additional new renewable resources in the future.” 

Other utilities across the country are investing heavily in solar installations and battery storage systems, with the Energy Information Administration estimating 58% of all power-generating capacity planned to be installed in 2024 to be solar power. The International Energy Agency considers solar and wind power to be the cheapest form of electricity in most markets in the world. 

Solar power is considered “intermittent,” meaning it produces electricity only during a portion of the day — such as when the sun is shining. But renewable energy advocates have touted battery storage systems paired with solar installations as a way to make the renewable power “dispatchable” and available around the clock.  Solar installations can charge batteries during the day to be used at night.

But LG&E and KU argued that pairing solar with battery systems would be a costly replacement for a“dispatchable” around-the-clock energy source such as coal-fired power. Thousands of megawatts of solar and battery storage would be needed to replace Mill Creek’s 391 megawatts of coal-fired power, the utility’s analysis said.

Advocates and the former PSC chair have expressed concern utilities aren’t able to be held accountable to follow the plans they outline. The last time LG&E and KU presented an integrated resource plan to the PSC, it was chastised by the regulator for not presenting plans that were “actionable” for the future.

LG&E and KU in its latest IRP filing writes the documents are a “snapshot of an ongoing resource planning process” that is “constantly evolving.””

Skepticism about carbon capture, future of greenhouse gas regulations

Looming over LG&E and KU and other coal-reliant utilities are new regulations from the U.S. Environmental Protection Agency that require coal-fired power plants and new natural gas-fired power plants to curb 90% of their carbon dioxide emissions by 2032 if utilities plan to operate them past 2039. 

Challengers are arguing in court that the technology proposed to comply with the regulation isn’t yet commercially viable at a utility scale. Carbon capture and sequestration is a controversial technology that tries to capture carbon dioxide emissions from power plants to prevent release into the atmosphere. LG&E and KU is planning to install and test a carbon capture system on an existing natural gas-fired plant. 

LG&E and KU in its planning documents wrote that implementing carbon dioxide transport and storage “is not achievable” in the timeline set by the EPA. The utility also wrote that converting coal-fired power plants into burning natural gas is also “questionable” because of the time it would take to establish gas pipelines. Retiring coal-fired power plants by 2032 is an option for compliance, LG&E and KU stated, but “retirements require reliable replacement capacity.” 

“Replacing generation at the scale necessary for compliance is not reasonable” under the EPA’s timeline for reducing greenhouse gas emissions, the utility wrote.

LG&E and KU’s integrated resource plan will likely come under scrutiny from a range of stakeholders during PSC review — the attorney general, renewable energy advocates, advocates for industrial and residential ratepayers and local governments in the utility’s territory covering Lexington, Louisville and parts of Eastern and Western Kentucky.

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