As we turn the page toward 2025, we’re taking a look back at some of the biggest headlines throughout the year.

1. Oracle Designing Data Center Powered by Small Modular Reactors – Sept. 11
In a groundbreaking move, Oracle announced it would be designing a data center to be powered by three small modular reactors (SMRs). The company’s Chairman, Larry Ellison, highlighted this project as part of Oracle’s response to the growing electricity demands driven by AI and cloud services. Like other tech companies, Oracle is turning to next-generation nuclear power to support its massive data center operations globally.

2. Vogtle Unit 4 Reaches First Criticality – Feb. 14
Georgia Power announced a significant step with Vogtle Unit 4, marking the achievement of initial criticality, a key milestone in nuclear reactor startup. Unit 4 officially entered commercial operations on April 29. The long-awaited completion of Vogtle’s two new AP-1000 reactors (3 & 4) was a major development in the U.S. nuclear industry after decades without new nuclear units.

3. Here Comes the Gas Boom (Again) – June 19
Natural gas is back in the spotlight as utilities plan for a significant increase in gas plants to ensure grid reliability, amid growing demand for energy from data centers, AI and manufacturing. This re-published article from Burns & McDonnell highlighted long-lead times for equipment and that the gas sector’s role in the energy transition would remain critical in the coming years.

4. Corrosion Cracking at Palisades Nuclear Plant Exceeds Estimates – Oct. 3
The Palisades Nuclear Plant, which ceased operations in 2022, is on the path to unretirement. However, the U.S. Nuclear Regulatory Commission (NRC) found unexpected challenges with stress corrosion cracking in the plant’s steam generators. Despite these setbacks, Holtec International aims to restart the plant in 2025, marking the first-ever recommissioning of a retired U.S. nuclear plant. Holtec also has future plans to install small modular reactors on-site.

5. AWS Acquires Data Center Campus at Susquehanna Nuclear Station – Mar. 5
Amazon Web Services (AWS) acquired a data center campus connected to the Susquehanna Nuclear Station in Pennsylvania, with plans to expand its operations and consume up to 960 MW of power. The deal underscores the growing trend of tech giants and developers seeking reliable, carbon-free nuclear energy for their data centers. In November, the Federal Energy Regulatory Commission (FERC) issued an order denying a revised Interconnection Service Agreement (ISA) proposal that would have allowed expanded co-located load at the Susquehanna-AWS data center colocation site.

We appreciate the power generation and utility industry for their readership and support. We would like to remind you to register for POWERGEN International, the industry’s leading event, which is back in Dallas at the Kay Bailey Hutchison Convention Center, February 11-13, 2025.

Sincerely,

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.”

However, there are abundant potential use cases for AI in the nuclear sector, a theme of one panel at POWERGEN International, which is February 11-13, 2025, in Dallas, Texas.

The panel, “AI in Nuclear: Unfulfilled Promise or Just Getting Started?,” will explore how we can build a foundation for the next wave of AI innovation in nuclear power. It will feature Joshua Guzman Bell, Nuclear Technology & Innovation Consultant for Dominion Energy; Forrest Shriver, CEO of Sentinel Devices; and Greg Alder, Director of Plant Optimization for Curtiss-Wright.

Shriver, whose company offers OTAware, a monitoring platform designed to reduce equipment downtime, told Power Engineering he plans to discuss thecutting-edge applications being seen in the nuclear industry, as well as what Sentinel is doing to move AI-driven predictive maintenance forward.

“I think it’s very important for power producers to get an understanding of what’s out there and what’s being done at a high level in AI applications for industry, so they can better understand how to parse and judge the trends that are at the heart of the decisions they have to make every day,” said Shriver. “If you know the field, and know how the pieces move, you can be much more prepared to intelligently react and make decisions based on new information.”

Shriver highlighted the critical need for offline-first AI solutions to address the unique challenges faced by power producers. These companies often have strict cybersecurity requirements that prevent the use of standard off-the-shelf software, or they operate assets in remote locations where 24/7 data streaming is impractical.

Shriver said current AI solutions tend to be cloud-centric, with no clear middle ground between fully on-premises infrastructure and full cloud dependence.

“I’ll be talking a bit about how we’re solving that challenge,” he continued, “but I really do think it’s one of the wider unanswered questions at the moment for power producers that are sensitive about cybersecurity.”

“AI in Nuclear: Unfulfilled Promise or Just Getting Started?” is scheduled for Thursday, February 13 at 11:30 am – 12:30 pm as part of the Nuclear’s Evolution track.

Register for the POWERGEN technical conference program here.

The 370 megawatt (MW) Great Plains Power Station is now online near Moose Jaw, Saskatchewan. The plant is powered by Siemens Energy’s SGT6-5000F6.3 gas turbine, SGEN6-1000A generator, SST700-900 steam turbine and SGEN6-100A steam turbine generator.

Construction on the plant began in March of 2021. At the peak of construction in July 2023, there were more than 600 workers on site each day. Now up and running, the plant is operated by 25 full-time employees on site.

Burns & McDonnell was SaskPower’s engineering, procurement, and construction (EPC) partner for the Great Plains project.

We reported back in May that SaskPower planned to invest in new generation as part of a $1.6 billion modernization plan during the 2024-25 fiscal year.

The $710 million in investments includes the construction of the Aspen Power Station Project and the Ermine and Yellowhead expansions.

The Aspen Power Project will be a 370 MW natural gas combined-cycle (NGCC) plant. The project is expected to come online by Spring 2028. Burns & McDonnell was also announced as the EPC.

SaskPower is adding a simple cycle natural gas turbine to the Ermine Power Station. This will be the facility’s third turbine and will produce an additional 46 MW of power. It is expected to be in-service in May 2025.

The utility is also adding 46 MW at the Yellowhead Power Station through the facility’s fourth turbine. The unit is expected to be in service in December 2025.

The $1.6 billion modernization plan also covers grid maintenance and upgrades, growth projects, smart meter deployments and more. The capital investment represents an increase of $433 million over 2023-24.

The projects include wind, solar and renewable natural gas facilities (RNG) as well as battery storage capacity.

Solar and wind projects announced this year are a mix of company-built and owned projects and power purchase agreements (PPAs).

Consumers Energy also worked with farmers to announce construction of multiple RNG facilities across the state following expansion of the utility’s MI Clean Air program. In many cases, RNG is considered carbon negative, as it captures and prevents more emissions than it emits.

Consumers Energy’s clean energy goals include bringing 8,000 MW of solar online by 2040 and achieving net-zero carbon emissions from its electric generation and distribution systems.

The Michigan utility’s Clean Energy Plan also calls for eliminating coal as an energy source in 2025 and meeting 90 percent of customers’ energy needs through clean sources.

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 American Electric Power (AEP) subsidiary has proposed adding a 450-Megawatt (MW) natural gas plant to be located at the previously retired H.W. Pirkey Power Plant site in Hallsville, Texas. The new Hallsville plant is expected to come online in 2027, pending approval from utility regulators in Arkansas, Louisiana and Texas. According to regulatory filings submitted December 17, the facility would feature two GE combustion gas turbine generators and utilize existing water intake structures and site infrastructure to minimize project costs, SWEPCO said.

The utility is also planning a coal-to-gas conversion project at the Welsh Power Plant, located northwest of Cason, Texas. The 1,053 MW project would convert the existing coal-fired boilers of Units 1 and 3 to burn natural gas, with Unit 1 conversion anticipated in 2028 and Unit 3 in 2027.

Natural gas currently accounts for 48% of SWEPCO’s existing power generation portfolio. Due to the evolving reserve requirements set by the Southwest Power Pool, SWEPCO anticipates an increasing capacity need.

In addition to the projects mentioned above, SWEPCO has selected a short-term capacity agreement with a natural gas-fired plant in Texas as part of a competitive bid process. The company said this agreement would serve as a bridge to more permanent resource additions.

SWEPCO continues construction on multiple renewable energy projects. The largest one, the 598 MW Wagon Wheel Wind Facility, spans five counties in Oklahoma and is expected to be operational in December 2025.

The 200 MW Diversion Wind Farm, located in Baylor County, Texas, is scheduled to begin operations this month.

SWEPCO’s first utility-scale solar farm, the 72.5 MW Rocking R Solar Facility, is also nearing completion in Caddo Parish, Louisiana. SWEPCO will not own the facility and will instead purchase the electricity generated via a purchase power agreement.

The oil and gas giant is building a massive natural gas-fired plant which is already in early development stages, the New York Times reported. The company said its carbon capture and storage (CCS) system could trap and store over 90% of the plant’s CO2 emissions.

This would be the first time Exxon is developing a power plant that wouldn’t electrify its own operations. The company has developed 5.5 GW of power projects since 2001 in states like Texas and Louisiana.

Exxon believes data centers could account for up to 20 percent of the total addressable market for CCS in 2050, company executives said in a corporate plan update on Wednesday.

This particular gas-fired plant would not be connected to the grid, avoiding grid connection challenges and meaning it could come online faster. Executives said the company has previously developed 800 MW of islanded power generation.

The future adoption of CCS in power generation likely depends on a variety of factors, like changes in the cost to capture CO2, the availability of pipeline networks and storage capacity for transporting and storing CO2, federal and state regulatory decisions and the development of clean energy technologies that could affect the demand for CCS.

Earlier this week NET Power, with the help of several partners, said it plans to develop 1 GW of gas-fired power with its Allam-Fetvedt Cycle CO2 capture system.

Also this week, a new project in the UK was approved to proceed with its plans to create the world’s first gas-fired power station with CCS. NZT Power, a joint venture between bp and Equinor, could produce up to 742 MW of dispatchable low-carbon power. Start-up could be as soon as 2028.

According to a study published by EPRI in May, data centers could consume up to 9% of U.S. electricity generation by 2030 — more than double the amount currently used. Demand for computing power from data centers, fueled by artificial intelligence and other new technologies, requires enormous amounts of power.

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.

“We agreed that the leadership churn at PG&E was not serving our coworkers or our customers, and stability was a priority,” she said in a video posted to her LinkedIn.

Poppe joined PG&E as CEO in January 2021, after five years as President and CEO of CMS Energy and its principal subsidiary Consumers Energy. In her decade-long career with the Michigan company, she also served as Senior Vice President of Distribution Operations, Engineering and Transmission; Vice President of Customer Experience, Rates and Regulation; and Vice President of Customer Operations. She previously served as a power plant director at DTE Energy. Prior to joining DTE Energy, Poppe held a variety of plant management positions in the automotive industry.

Dominion Energy announced that Diane Leopold, the utility’s executive vice president and chief operating officer, would retire on June 1, 2025. Prior to June she will transfer utility and contracted energy responsibilities to Ed Baine, currently president of Dominion Energy Virginia, who will become president-utility operations and Dominion Energy Virginia; and Eric Carr, currently chief nuclear officer, who will become chief nuclear officer and president-nuclear operations and Contracted Energy. Leopold will retain operational oversight of all major construction projects including the Coastal Virginia Offshore Wind project (CVOW). She has spent the last 30 years at Dominion Energy.

John Thomas, Tennessee Valley Authority’s executive vice president and chief financial and strategy officer, has announced his plans to retire on March 7, 2025, after nearly 20 years of service. Thomas has been with TVA since 2005, leading its financial and strategic direction for nearly two decades. He oversees the utility’s strategy, financial planning, treasury, risk management, innovation and more. Thomas also oversees the pursuit of emerging technologies like battery storage.

The Ontario Power Generation (OPG) Board of Directors recently appointed Nicolle Butcher as President and CEO effective Jan. 1, 2025. She replaces current President and CEO Ken Hartwick, who is retiring after nearly nine years with the company. Butcher is currently OPG’s Chief Operations Officer, overseeing the crown utility’s generating fleet. She has also led company’s corporate business growth and development and commercial business functions, including energy trading and market affairs.