Technip Energies, along with GE Vernova and construction partner Balfour Beatty – and with the support of technology partner Shell Catalysts & Technologies – received a notice to proceed by NZT Power Limited to execute a major contract for the Net Zero Teesside Power (NZT Power) project in the United Kingdom.

NZT Power, a joint venture between bp and Equinor, could produce up to 742 MW of dispatchable low-carbon power. Start-up is expected in 2028, supporting the UK Government’s Clean Power 2030 ambition. The project aims to be the world’s first gas-fired power station with carbon capture and storage. Up to 2 million tons of CO₂ per year could be captured at the plant and transported and permanently stored by the Northern Endurance Partnership, the companies said.

NZT Power has reached financial close and has issued a full notice to proceed to the Technip Energies-led consortium to start the full engineering procurement and construction (EPC) package for the onshore power, capture and compression contract. Financial close follows the UK government’s recent announcement of a £21.7 billion pledge for projects to capture and store carbon emissions from energy, industry and hydrogen production.

A “major” award for Technip Energies is a contract award representing above €1 billion of revenue. The award will be included in backlog in Q4 2024, the company said.

Technip Energies and GE Vernova, with the support of infrastructure group Balfour Beatty, plan to deliver a combined cycle plant and associated carbon capture system. Technip Energies will lead the integration of a carbon capture system using its Canopy by T.EN solution, powered by Shell’s CANSOLV CO₂ Capture System. The plant will be powered by GE Vernova’s 9HA.02 gas turbine, a steam turbine, a generator, a heat recovery steam generator, and an exhaust gas recirculation (EGR) system.

“We believe CCUS technology can be crucial to help decarbonize the planet, and we welcome the commitment from the UK government to invest in its implementation as well as NZT Power’s trust in our technology,” said Maví Zingoni, CEO, Power at GE Vernova. “Flagship projects like Net Zero Teesside Power can give the industry foundations to grow. We look forward to powering the station with our advanced H-Class combined cycle technology, as well as proceeding with the first commercial use of our Exhaust Gas Recirculation system and integration technologies, which aim to support carbon abatement by boosting the efficiency and performance of carbon capture.”

Under the terms of the MOU, the parties plan to conduct feasibility studies on locating NET Power’s facilities in proximity to CTV’s underground storage vaults, which the companies say could reduce carbon dioxide (CO₂) transportation costs and midstream investments for CTV’s operations. The parties plan to facilitate the initial deployment of up to 1 gigawatt (GW) of power capacity from NET Power’s new modular plants in Northern California, which could result in up to 3.6 million metric tons per annum (MMTPA) of CO₂ emissions for permanent sequestration in CTV’s nearby reservoirs. Each of NET Power’s utility-scale modular plants is expected to require less than 20 acres, generate up to 250 MW, and be deployable in multi-plant configurations, the company said.

NET Power claims its plants will be designed to eliminate “substantially all” carbon emissions with near-zero air particulate and gaseous pollutants, including nitrogen oxides (NOx) and sulfur oxides (SOx).

This MOU marks NET Power’s initial entry into California’s power market and positions CTV as an early strategic partner in the deployment of NET Power’s power technology. Including this agreement, CTV’s carbon capture and sequestration (CCS) projects under consideration total approximately 7.8 MMTPA of CO₂ emissions and if successful, would enable up to 2.1 GWs of new, low-carbon power capacity in California.

The NET Power capture system utilizes the Allam-Fetvedt Cycle, combusting natural gas with oxygen, as opposed to air, and uses supercritical carbon dioxide as a working fluid to drive a turbine instead of steam. This theoretically eliminates all air emissions, including traditional pollutants and CO2 and inherently produces pipeline-quality CO2 that can be sequestered underground.

In 2021, NET Power claimed a global first when its test facility in Texas generating zero-emission electricity from natural gas delivered electricity onto a power grid. In November 2022 the company announced a plan to develop and build its first utility-scale natural gas-fired plant with carbon capture and sequestration (CCS). NET Power has a “backlog of utility-scale power plant projects,” with initial commercialization expected in 2026.

In June last year, NET Power announced the completion of its previously announced business combination with special purpose acquisition company Rice Acquisition Corp. II.

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.

Virginia’s air regulators are awaiting data from Dominion Energy to further process the utility’s air permit request for the natural gas plant they’re proposing to build to meet rising energy needs, as pushback over the location and potential environmental impact of the facility continues.

“We are expecting to receive air quality monitoring data … in the next couple of weeks or so,” said Mike Dowd, director of air and renewable energy at the Department of Environmental Quality, in an update to the State Air Pollution Control Board Thursday. “As soon as we get the air quality modeling data, we will be processing the permit.”

Dominion spokesperson Jeremy Slayton confirmed to The Mercury that the utility is “currently planning to submit our modeling report to DEQ in early 2025.”

Dominion Energy, Virginia’s largest utility, is proposing the Chesterfield Energy Reliability Center to meet increased energy demands expected to hit the state as a result of data center development. After local opposition, Dominion moved the proposed location from an industrial site on Battery Brooke Parkway to its former coal-fired Chesterfield Power Station on Coxendale Road. 

Construction is expected to start in 2026. It’s expected to be operational in 2029.

Environmental and community groups have staunchly fought against the project, saying it runs counter to the state’s 2020 Virginia Clean Economy Act that mandates the retirement of fossil fuels by 2045, unless there’s a concern over being able to reliably send electricity to the grid. 

Critics also are concerned about the air pollution impacting the surrounding community.

The update on the timeline means next year “is going to be pretty busy in terms of the public engagement,” said Mason Manley, a field manger with Clean Virginia, an advocacy group formed by millionaire Michael Bills to oppose Dominion’s influence in the legislature. The public will likely have the chance to weigh in on both the air permit for the Chesterfield Energy Reliability Center, as well as a separate Certificate of Public Convenience and Necessity from the State Corporation Commission, which regulates Virginia’s utilities, Manley said.

The air permit is expected to be issued by July 28, according to DEQ’s permitting website, with public engagement opportunities occurring before then. The CPCN is going to be requested “in the first quarter of 2025,” said Slayton, with Dominion.

Andy Farmer, a spokesperson for the SCC, said “It is too early to discuss an SCC public engagement process when an application hasn’t been filed.”

“After Dominion files the application, the SCC will issue an Order for Notice and Hearing that will include a hearing schedule and public comment opportunities,” Farmer said. 

Manley said the public engagement opportunity is when community members can make their case for a denial or express their concerns necessitating controls for emissions be put in place. Last month, community members held a “People’s Hearing” to collect public testimony that will be submitted to DEQ during the public engagement period.

“(The air permit) is extremely important, (Dominion) can’t actually begin construction until that is issued,” Manley said.

The timeline update comes as opposition continues over local approval of the land use for the project, which is considered one of the first requirements before the DEQ and SCC processes can finish.

On Monday, the Friends of the Chesterfield, a group formed to oppose the plant, filed another appeal with the Chesterfield County Board of Zoning Appeals over a decision to use a 2010 conditional use permit for the Coxendale Road site for the proposed plant.

Previously, the friends group challenged a zoning determination from Chesterfield County Deputy Administrator Jesse Smith, but the zoning board said that determination was made as part of the air permitting process under the air board’s authority, not its own. 

After the rejection, the friends group followed up with Chesterfield County Chesterfield County Planning Director Andrew Gillies with their own request for a zoning determination on using the conditional use permit for the new site. Gillies responded on Oct. 18 saying that the previous letter stating the existing conditional use permit applies to the proposed plant, “fully answers your letter.” 

Evan Johns, an attorney with Appalachian Mountain Advocates, which filed both appeals on behalf of the Friends group, said the second appeal is a response to a determination by Gillies, a zoning official, which the groups says is reviewable by the zoning board.

“It seems like a determination that can be reviewed,” said Johns.

Chesterfield County spokesperson Teresa Bonifas said, “We do not comment on pending or potential litigation.” The next zoning board meeting is scheduled for Dec. 4.

Another requirement for the air permit process is a determination of “site suitability.” As Chesterfield County has declined to make that determination, Dowd said “there hasn’t been a full resolution.”

“I assume this is all part and parcel with (the appeal),” Dowd said.

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

In rural northeast Louisiana, known for its rice, sweet potato farms and poverty, an as-yet-to-be-named company has agreed to build a new data center with an investment of at least $5 billion. The development is being called a “godsend” and a “game changer” for the region, where one in five people lives in poverty.

Next to the site, off Interstate 20 in Holly Ridge, electric utility Entergy plans to build a 1,500-megawatt natural gas plant to power the data center. The data center, the power plant, or possibly both, will be built on a 1,400-acre site, called Franklin Farms, owned by the state, according to filings with the Louisiana Public Service Commission. Entergy would spend $3.2 billion on the plant, a related 754-MW gas plant to be built in South Louisiana and transmission lines.

Over the last several months, concern has arisen that the construction of fossil-fueled power plants to provide power to the proliferation of U.S. data centers will slow progress on the nation’s climate change goals.

“Entergy is proposing to add huge amounts of greenhouse gas emissions, with proposals to mitigate those emissions ‘in the future’ with largely unproven technologies,” said Whit Cox, regulatory director of the Southern Renewable Energy Association, which has filed to intervene in Entergy’s request. And a Louisiana utility consumer group questions whether the cost of the new plants will be passed onto residential customers.

Details about the data center are cloaked in secrecy and non-disclosure agreements. But Entergy Louisiana has filed hundreds of pages of redacted documents with state regulators about its dealings with the unnamed company. In its filings, Entergy says the data center will employ 300 to 500 people with an average salary of $82,000. The utility calls the development a “game changer” that will bring “an historic investment” to the region.

The utility is asking the Louisiana PSC to approve construction of the new power plant — where the primary customer will be the data center — within 10 months.

‘Skyrocketing’ demand driving data centers

With the development, Louisiana would join a cohort of states building natural gas power plants to meet the pressing demand for electricity to run data centers being built by Amazon, Meta, Google and others.

Data centers are forecast to account for up to 12% of all U.S. electricity demand by 2030, according to consulting firm McKinsey and Co., citing “skyrocketing compute and data demands.” Today that amount is 3% to 4%, McKinsey said. The firm estimates the need for 50,000 MW of new electricity to run the data centers over that time frame.

“We see (the gas buildout) as a huge threat — we are at a moment where we need to be phasing out fossil fuels and not locking it in for decades longer,” Gudrun Thompson, energy program leader for the Southern Environmental Law Center told Floodlight earlier this year.​​ 

The company building the Louisiana data center appears to be aware of those concerns and is working with Entergy to offset its emissions according to Entergy’s filings. The company wants Entergy to build or acquire 1,500 MW of solar power elsewhere to offset its emissions in Holly Ridge.

Additionally, the unnamed company is “expected to make a substantial contribution” toward the cost of carbon capture and storage at Entergy Louisiana’s new Lake Charles 994 MW gas power plant. The power plant in Holly Ridge also would have the capability of using up to 30% hydrogen — which doesn’t emit carbon when burned — as part of its fuel mix, according to Entergy. 

The utility said it evaluated other alternatives to provide electricity to the data center, including wind or solar, but concluded it would still have to build a natural gas power plant on site as backup generation because such renewable sources do not generate electricity around the clock.

But Michelle Solomon, an analyst with the nonprofit climate think tank Energy Innovation, says Entergy’s analysis is flawed. With battery storage — an affordable solution that is being used elsewhere — solar or wind could easily be deployed, she said.

“Louisiana is far from the clean electricity mix of even one of its closest neighbors, let alone cleaner grids around the world, indicating that it can easily integrate even large amounts of new renewable resources,” she said, noting that less than 1% of Louisiana’s energy comes from wind and solar, combined.

The utility said in its filings it has committed to the data center to explore other lower emission power options, such as wind and even nuclear, to help the company meet its sustainability goals.

Cox, of the Southern Renewable Energy Association, said its members could provide renewable power to the data center at a lower cost with no greenhouse gas emissions. If the PSC grants Entergy’s request, that would avoid competitive bidding, shutting renewable and other energy developers out of the process — potentially further driving up costs, he said.

In a bid to reduce greenhouse gas emissions, several large tech companies are supporting efforts to develop small modular nuclear reactors. A recent report from Moody’s Ratings says small reactors face regulatory and cost barriers, but large tech companies with strong balance sheets, such as Google and Amazon, might be best positioned to push such developments forward.

Could project drive up ratepayers’ bills?

In addition to concerns about how more gas-fired power plants will impact the world’s climate, Louisiana residents have more localized worries.

Costs not paid by the data center, either through electricity rates or separate agreements, would be spread across Entergy’s 1.1 million Louisiana customers, although the utility says the proposed deal “largely insulates (Entergy’s) other customers from paying for the upgrades required” for the data center.

“We’ve got a lot of questions regarding cost allocation, but also concerns about how much this has been fast-tracked,” the Alliance for Affordable Energy said in a recent newsletter.

On Nov. 20, the PSC will take up the project for the first time as it considers hiring outside consultants to help evaluate the proposal. In addition to the Southern Renewable Energy Association, the Large Energy Users Group, consisting of major industrial energy users including Chevron and Dow, has requested to intervene in the case.

Commissioner Foster Campbell, a Democrat who represents North Louisiana, has been consistently skeptical of plans for new power plants and additional charges on electricity bills. This time, he is championing the new development in his home territory.

“I’m always interested in what it’s going to cost,” he said. “But this is a different program, because it delivers so much, so many jobs, good paying jobs for North Louisiana,” Campbell said. “I mean, I want to keep everything in perspective, but I can’t help but thank God. Northeast Louisiana needs help more than any part of Louisiana. So, it’s a godsend.”

Floodlight is a nonprofit newsroom that investigates the powerful interests stalling climate action.

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 cooperative recently purchased 100 acres outside Naples, Texas, where it plans to break ground in 2026 on a $850 million gas plant. The plant will be AECC’s biggest generating facility, and its first outside Arkansas, once built. The Naples plant is a 900 MW, two-turbine, simple cycle plant, and it will be located near three existing pipelines and electric transmission. Commercial startup is expected by November, 2028, AECC said, and the facility will operate in the Southwest Power Pool’s wholesale electricity market.

Additionally, AECC is investing $93 million in an effort to expand its Thomas B. Fitzhugh Generating Station from 170 MW to 270 MW, spurred by a forecasted SPP capacity shortage expected to begin next year. The plant will receive two new units, and is expected to reach commercial operation by the end of 2025, AECC said.

AECC said the new generation was necessitated by “steady, normal consumer load growth” of around 1.5% to 2% in the region each year, in addition to the planned retirement of about 1,200 MW of coal by 2030.

“Natural gas is an accessible, dispatchable resource we can rely on, and it gets full accreditation in SPP to meet capacity to serve the market,” said Jonathan Oliver, AECC’s chief operations officer. “Plus, gas prices are fairly stable now, offering members a least-cost reliable resource.”

In addition to new gas generation, AECC has been introducing new solar as well. The 122-MW Woodruff County Solar Project, interconnected through existing infrastructure at the adjacent and retired Carl Bailey Generation Station, began operations in October.

Due to an “unprecedented increase” in projected customer demand seen in its fall load growth forecast, Duke Energy provided state regulators with supplemental modeling on Jan. 31, 2024.

In July this year, prior to the NCUC’s evidentiary hearing on the plan, Duke Energy, the NCUC Public Staff, Walmart and the Carolinas Clean Energy Business Association reached a broad settlement on most topics at issue in the Carolinas long-range plan. The settlement committed Duke Energy to increasing the amount of solar energy and battery storage on its system through 2030, provided the opportunity to upgrade existing small solar facilities that are approaching the end of their contract terms with Duke, and committed Duke Energy to continued reform of its transmission planning process.

Duke Energy originally filed its proposed Carolinas Resource Plan with the North Carolina Utilities Commission (NCUC) On Aug. 17, 2023, two days after filing the same plan with the Public Service Commission of South Carolina (PSCSC). The Carolinas Resource Plan is Duke Energy’s proposed road map for its dual-state system serving North Carolina and South Carolina.

“We believe this is a constructive outcome that allows us to deploy increasingly clean energy resources at a pace that protects affordability and reliability for our customers,” Duke Energy said in a statement. “The order confirms the importance of a diverse, ‘all of the above’ approach that is essential for long-term resource planning and helps us meet the energy needs of our region’s growing economy. We look forward to thoroughly reviewing the NCUC order and incorporating it into our future resource planning.”

After gathering input from public hearings, evaluating Duke’s proposal, modeling, and settlement – along with modeling from Public Staff and targeted recommendations from intervenors – and conducting an extensive evidentiary hearing across two weeks, the NCUC issued its decision late last week. The order accepts the July settlement in its entirety.

Specifically, the order directs Duke Energy to pursue the following:

Near-Term Resources

• Solar: 3,460 megawatts (MW) of new solar generation, beyond the NCUC’s 2022 order – 6,700 MW total by 2031.
• Battery: 1,100 MW of battery energy storage, beyond the NCUC’s 2022 order – 2,700 MW total by 2031.
• Onshore Wind: 1,200 MW of onshore wind in operation by 2033, including at least 300 MW in operation by 2031.
• Combustion Turbines (CTs): Four CTs by 2030 – 900 MW of additional CTs (two units) beyond the 800 MW (two units) in the NCUC’s 2022 order.
• Combined Cycles (CCs): Three CC units by 2031 – 2,720 MW of additional CC capacity (CC2 and CC3) beyond the 1,200 MW (CC1) in the NCUC’s 2022 order.

Long-Term Resources

• Bad Creek II: Approved continued development work, including requested $165 million in early development costs.
• Nuclear: Approved continued development work, including requested $440 million in early development costs, targeting 300 MW of advanced nuclear capacity on line by 2034 and a total of 600 MW by 2035.
• Offshore Wind: Approved continued development work through the Acquisition Request for Information (ARFI) to advance the evaluation of offshore wind’s role in future resource plans, with results filed no later than July 30, 2025, and targeting between 800 and 1,100 MW of offshore wind by 2034 and 2,200 to 2,400 MW by 2035.

Modeling, Reserve Margin, Interim Carbon Reduction Target and Other Key Findings

• Confirmed Duke Energy’s recommended portfolio, P3 Fall Base, as the “reference portfolio.”
• Approved increase in the minimum planning reserve margin to 22% by 2031.
• Waived the requirement to model 70% carbon reduction by 2030, agreed that the evidence in the case supported the decision to extend the date for achieving 70% carbon reduction beyond 2032, and ordered Duke Energy to continue pursuing “all reasonable steps” to achieve 70% carbon reduction by the earliest possible date.
• Confirmed proposed coal retirement dates.
• Noted that “The Commission must be mindful of the impacts to customers when determining the appropriate action to take … to ensure that Duke, and North Carolina, continue this trajectory of rates that are at or below the national average,” highlighting the inflation-adjusted bill impact of the plan as a 0.9% increase by 2038.

The PSCSC continues to deliberate on the resource plan and will issue an order on or before Nov. 26, 2024. Following that order, Duke Energy said it will begin executing the plan while simultaneously developing the modeling required for its 2025 plan update in North Carolina, which must be filed by September 2025. As outlined in North Carolina law, the plan must be checked and adjusted every two years, incorporating technology advances, updated cost forecasts and applicable federal funding that could help customers save money over time.

In it’s 2024 filing to the NCUC, Duke said “new economic development wins, including manufacturing and technology projects across the Carolinas” make up the primary driver of the increased electric demand. The utility said annual demand expects to increase 22% by 2030 and 25% by 2035 from 2022 planning cycles — driven by significant additional economic development activity that took place during 2023. Notably, according to the Census Bureau, South Carolina’s population grew faster than any state’s in 2023.

Duke Energy put forth its original resource plan to regulators in August 2023. The company presented three portfolio scenarios but recommended one that achieves 70% CO2 emission reductions from 2005 levels by 2035. The “Portfolio P3 Fall Base,” introduced almost 6.8 GW of additional resources.

The Castle Bluff Energy Center is expected to be ready to serve as a backup source of energy in 2027, and represents an investment of approximately $900 million. The center is designed to deliver energy on the coldest winter days, the hottest summer afternoons and back up the grid when renewable energy generation is otherwise unavailable.

On-site construction at Castle Bluff is expected to start next month and create hundreds of construction jobs and several permanent jobs, as well as produce additional tax revenue for the region. The project will take advantage of existing infrastructure and transmission line access on the site which the company already owns, which Ameren Missouri claims will help to reduce overall construction time and costs to customers.

Ameren Missouri also announced it has acquired the Huck Finn Renewable Energy Center, a 200-MW solar facility in Audrain and Ralls counties in Missouri. Huck Finn is the third utility-scale solar facility Ameren Missouri has acquired this year. The Boomtown and Cass County Renewable Energy Centers were acquired earlier this year. Together, the three solar facilities have a combined capacity of 500 MW and represent a total acquisition cost of approximately $900 million. All three are in the later stages of development and are expected to begin producing energy for customers by the end of this year. 

“We’re delivering on our strategy to invest in energy infrastructure for the benefit of our customers with these three facilities representing the next step in providing our customers with a diverse generation portfolio of low-cost energy,” Birk said.

Ameren Missouri acquired the 150-MW Cass County Renewable Energy Center in June. Located in Cass County, Illinois, it will serve Ameren Missouri’s Renewable Solutions program. The 150-MW Boomtown Renewable Energy Center is in White County, Illinois, and will also serve the Renewable Solutions program. The Boomtown Renewable Energy Center was acquired in late September. 

“As final testing wraps up on Huck Finn, Cass County and Boomtown, we are also working toward the successful construction of another 400 MW of solar generation across three additional projects,” Arora said. “We expect these Missouri projects, located in Bowling Green, Vandalia and Warren County, will be ready to serve customers in late 2025 and in 2026.” 

Last September, Ameren released its 2023 Integrated Resource Plan, which included investments in natural gas, renewables and battery storage. One of the highlights of the IRP included building an 800 MW simple-cycle plant. Others included:

• Moving back the previously announced addition of a combined-cycle energy center to 2033. This 1,200 MW facility is now scheduled to go in service following the retirement of the Sioux Energy Center in 2032.
• Accelerating Ameren Missouri’s planned renewable energy additions by four years. The company plans to add 4,700 MW of new renewable energy by 2036. This represents a total potential investment of approximately $9.5 billion. The company maintains its goal of 2,800 MW by 2030.
• Adding 800 MW of battery storage, including 400 MW by 2030 – five years earlier than previously planned – with an additional 400 MW of battery storage by 2035. This represents a total potential investment of $1.3 billion through 2035.
• Planning 1,200 MW of clean, on-demand generation to be ready to serve customers in 2040 and an additional 1,200 MW by 2043.

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.

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