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When you think of innovative advancements in nuclear power technology, places like the Idaho National Laboratory and the Massachusetts Institute of Technology probably come to mind. But today, some very exciting nuclear power development work is being done in West Texas, specifically, at Abilene Christian University (ACU). That’s where Natura Resources is working to construct a molten salt–cooled, liquid-fueled reactor (MSR).

“We are in the process of building, most likely, the country’s first advanced nuclear reactor,” Doug Robison, founder and CEO of Natura Resources, said as a guest on The POWER Podcast.

Natura has taken an iterative, milestone-based approach to advanced reactor development and deployment, focused on efficiency and performance. This started in 2020 when the company brought together ACU’s NEXT Lab with Texas A&M University; the University of Texas, Austin; and the Georgia Institute of Technology to form the Natura Resources Research Alliance. In only four years, Natura and its partners developed a unique nuclear power system and successfully licensed the design. The U.S. Nuclear Regulatory Commission (NRC) issued a construction permit for deployment of the system at ACU last September.

Called the MSR-1, ACU’s unit will be a 1-MWth molten salt research reactor (MSRR). It is expected to provide valuable operational data to support Natura’s 100-MWe systems. It will also serve as a “world-class research tool” to train advanced reactor operators and educate students, the company said.

Advantages of MSR Technology

The technology is not new. It was actually proven decades ago. “A molten salt reactor was built at Oak Ridge in the 1960s—the Molten Salt Reactor Experiment or the MSRE—and that reactor functioned for about five years, then was shelved in favor of solid-fuel or light-water reactors [LWRs] that we’re all familiar with,” Robison explained. “That was really a decision made because the customer in the 1960s was the Department of Defense, and Admiral Rickover was building a nuclear Navy, and they needed to enrich uranium to plutonium for warheads, and solid fuel reactors are more suited for those purposes,” Robison added.

The coolant is one of the main differences between LWRs and MSRs. As the names imply, an LWR is cooled by water, while an MSR is cooled by molten salt.

LWRs require thick pressure vessels and high-pressure piping to safely contain pressurized water, provide radiation shielding, and ensure long-term structural integrity. Today, there are no U.S. manufacturers with the capability to forge a large nuclear reactor vessel, so they must be sourced overseas.

Notably, molten salt turns from a solid to a liquid at about 450C, but it doesn’t turn to a gas until about 1,400C, which is above the melting point of stainless steel. “What that means is you can never get to the point to where the salt flashes to a steam, so we operate at very, very high temperatures, which is a big advantage because the high process heat—from an efficiency standpoint and manufacturing standpoint—is incredibly valuable, but we operate at atmospheric pressure, because the salt never transfers into a gas. It goes from a solid to a liquid. And, if you were to have some kind of leak or release, once you drop below 450 degrees C, it immediately freezes back into a solid, so kind of picture candle wax, if you will. So, it’s called ‘walk-away safe’ for that reason. You don’t need a containment dome,” explained Robison.

These factors significantly reduce the cost of MSR facilities compared to LWR plants. MSR reactor vessels, for example, can be manufactured by Teledyne Brown Engineering in Huntsville, Alabama, and perhaps elsewhere in the U.S. Robison said everything needed to construct an MSR can be made in America, and he expects much of it to be manufactured in Texas. “Governor Abbott has said, ‘We want Texas to capture this industry,’ ” noted Robison. “Houston, Texas refers to itself as the energy capital of the world. So, we’ve been working with the Greater Houston Partnership and the Houston Energy Transition Initiative [to answer the question] ‘How does that manufacturing happen not just in the U.S., but how does it happen in Texas?’ ”

Liquid fuel also provides an advantage for MSRs versus the LWR’s solid-fuel design. “[In] the solid-fueled reactor, you have the fuel inside the fuel rod. And under current technology, when you burn 3% to 5% of the fuel, then at that point, the rod begins to decay. That is your first level of containment, so you have to pull the rod. That now becomes ‘spent nuclear fuel’ and enters into the waste stream. You still have 95% to 97% of perfectly good fuel inside that fuel rod. And now the problem becomes: ‘What do we do with this nuclear waste that’s going to be around for 100,000 years?’ ”

In an MSR, the fuel is dissolved in the salt. “What that means is we burn practically 100% of the fuel. We do not throw unspent nuclear fuel away, and so our efficiency goes way up. We do not generate the waste that you see with a light-water reactor,” said Robison. “In fact, molten salt reactors can utilize current stockpiles of spent nuclear fuel that is sitting in storage at different nuclear reactors around the nation, and we can take that fuel, and re-utilize that as fuel for a molten salt reactor.”

Commercial Projects Announced

Natura is not only focused on its ACU project, but it is also moving forward on commercial reactor projects. In February, the company announced the deployment of two advanced nuclear projects, which are also in Texas. These deployments, located in the Permian Basin and at Texas A&M University’s RELLIS Campus, represent significant strides in addressing energy and water needs in the state.

“Our first was a deployment of a Natura commercial reactor in the Permian Basin, which is where I spent my career. We’re partnering with a Texas produced-water consortium that was created by the legislature in 2021,” said Robison.

“Produced water” is the water brought to the surface during oil and gas extraction processes. It is a byproduct of hydrocarbon production and typically consists of formation water that was originally present in the underground reservoir, along with additional water introduced during extraction operations. It typically has a salinity that is three times that of seawater, but it can be double or triple that in some instances. In any case, it cannot be released on the surface and must currently be reinjected back into the formation, which can create additional problems.

One of the things that can be done with the high process heat from an MSR is desalinization. “So, we’re going to be desalinating produced water and providing power—clean power—to the oil and gas industry for their operations in the Permian Basin,” said Robison.

Meanwhile, at Texas A&M’s RELLIS Campus, which is located about eight miles northwest of the university’s main campus in College Station, Texas, a Natura MSR-100 reactor will be deployed. The initiative is part of a broader project known as “The Energy Proving Ground,” which involves multiple nuclear reactor companies. The project aims to bring commercial-ready small modular reactors (SMRs) to the site, providing a reliable source of clean energy for the Electric Reliability Council of Texas (ERCOT).

Robison believes the Stargate Project, a massive $500 billion initiative aimed at building advanced hyperscale data centers across the U.S. to power next-generation artificial intelligence (AI) models, could also present an opportunity for Natura. “The very first deployment of Stargate is scheduled to be in Abilene, Texas. We can actually see the data center that’s being constructed from the windows of our offices,” he said. “We may see something happen there just given the proximity of what they’re doing and what we’re doing,” Robison envisaged.

To hear the full interview with Robison, which contains more about the creation of Natura Resources, the selection of MSR technology for its design, its collaboration with ACU, the work done to license the reactor, and much more, listen to The POWER Podcast. Click on the SoundCloud player below to listen in your browser now or use the following links to reach the show page on your favorite podcast platform:

For more power podcasts, visit The POWER Podcast archives.

—Aaron Larson is POWER’s executive editor (@AaronL_Power, @POWERmagazine).

LG&E, KU Propose $3.7B Power Buildout: 1.3 GW of New Gas Plants, $153M Coal Unit Upgrade

March 5, 2025

Jeff Prescott

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PPL subsidiaries Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Company (KU) have proposed to upgrade environmental controls at a 1974-built coal unit, build two new gas-fired power plants at a combined cost of $2.8 billion, and add 400 MW of battery storage. The measures seek to significantly boost the companies’ capacity to ready the region for a dramatic surge in power demand.

LG&E and KU on Feb. 28 requested approval for a certificate of public convenience and necessity (CPCN) from the Kentucky Public Service Commission (KPSC) for the additional generation capacity and battery storage. The commission is expected to rule on the regulatory permit request by November 2025.

The companies’ joint application proposes four major projects.

Construction of Brown 12, a new 645-MW (net summer rating) natural gas combined cycle (NGCC) unit at KU’s E.W. Brown Generating Station in Mercer County. The filing suggests that the project is expected to be in service by 2030 at an estimated cost of $1.38 billion.
Construction of Mill Creek 6, a 645-MW NGCC unit at LG&E’s Mill Creek Generating Station in Jefferson County, to be in service by 2031 at an estimated cost of $1.42 billion. (Not affiliated with the proposal, Mill Creek 5, a 645-MW 7HA.03 gas turbine plant announced last year to replace two coal units, is separately progressing.)
Construction of Cane Run BESS: A 400-MW, 4-hour (1,600 MWh) lithium ion battery energy storage system at LG&E’s Cane Run Generation Station in Jefferson County, to be in service in 2028. Project costs are estimated at $775 million.
Construction of a system for Ghent 2 at KU’s coal-fired Ghent Generating Station in Carroll County, to be operational by 2028. Project cost is estimated at $153 million.

Massive Buildout Targets Surging Demand from Data Centers and Industry

The companies said the massive $3.7 billion capacity expansion is required to meet a sharp increase in annual energy requirements in Kentucky—from 32,808 GWh in 2025 to 48,129 GWh in 2032. Seasonal peak demand could rise from 6,230 MW (summer) and 6,146 MW (winter) in 2025 to 8,034 MW (summer) and 7,930 MW (winter) in 2032, the filing suggests.

Nearly all projected load growth can be attributed to economic development from emerging industries, the companies added. While traditional load (non-economic development) will decline slightly in the short term, with only modest growth expected in the late 2030s, at least 1.8 GW of additional load could come from large-scale, high-load-factor data centers, and another 250 MW from the BlueOval SK Battery Park, which a Ford-SK joint venture is developing in Hardin County. Other economic development projects, including automotive and industrial expansion, could add another 40 MW.

LG&E and KU’s estimates are partly rooted in a Kentucky General Assembly measure enacted under HB8 in 2024 that includes tax incentives to attract data centers to Jefferson County. “The General Assembly finds and declares that the authority granted in Sections 37 to 41 and the purposes accomplished are proper governmental and public purposes for which public moneys may be expended, and that the inducement of the location of data center projects within the Commonwealth is of paramount importance to the economic well-being of the Commonwealth.” the legislation declares.

On Jan. 16, LG&E announced it secured its first hyperscale data center customer: A joint venture between PowerHouse Data Centers, an American Real Estate Partners (AREP) division, and Louisville-based Poe Companies will develop a 402-MW data center campus in Louisville, Jefferson County, with the first 130 MW coming online by October 2026. The site will be supported by a new LG&E switch station, scheduled for completion in September 2026, and a dedicated on-site substation to ensure reliable power delivery.

In testimony filed with the CPCN request, John Bevington, senior director of Business and Economic Development for PPL Services Co., said LG&E and KU are fielding more than 8 GW of economic development load potential, based on a list of prospective customers. “More than 6,000 MW is related to data centers,” he said. “A primary driver of data center development is the availability of power. As noted above, without certainty of available generation and transmission capacity, it will be difficult to fulfill the initiatives of the General Assembly and Governor Beshear in marketing Kentucky to data centers and other large load customers.”

Bevington noted Kentucky’s location and resources, including an abundant water supply, make the state attractive to data centers. “Additionally, Kentucky is located in close proximity to major data centers in neighboring states. Based on my discussions with data center developers, I understand there are advantages in latency and redundancy to locating data centers near other data centers. Land in Kentucky is also relatively inexpensive when compared with other markets where data center development has been thriving and reaching a point of market saturation,” he said.

On Friday, LG&E and KU underscored the significance of the new power projects. “This is an exciting time for Kentucky as the interest in locating new and expanding businesses continues to grow,” said John R. Crockett III, LG&E and KU president and PPL chief development officer on Friday. “These investments in our system will allow us to continue serving our customers safely and reliably while meeting our regulatory obligation and the growing economic interest in the commonwealth—all while maintaining affordability.”

*Mill Creek Generating Station in Louisville, Kentucky. Courtesy: GE Vernova*

EPA Rules Could Still Impact Coal-Fired Ghent 2, Despite Good Neighbor Exemption

LG&E and KU’s existing dispatchable generation resources are approximately 7,264 MW in 2025, with coal still a majority of its portfolio. To comply with environmental requirements and energy efficiency measures, as of December 2024, the companies had retired approximately 1,500 MW of coal power since 2010. At the end of 2024, the companies retired Mill Creek 1, a 300-MW coal-fired power unit. Mill Creek 2 is slated for retirement after 2027. Retirements are also planned for two simple-cycle gas-fired plants: the 47-MW Haefling 1-2 in 2026, and 47-MW Paddy’s Run 12 in 2026.

However, in a pivotal decision in November 2023, the Kentucky Public Service Commission denied the companies’ proposed retirement of KU’s 486-MW Ghent Unit 2, citing a need for additional clarity regarding environmental compliance regulations. The KPSC had previously approved other major generation changes, including a 640-MW NGCC at Mill Creek, a 125-MW battery system, and multiple solar projects. In August 2024, the companies announced they would replace two aging coal generation units at Mill Creek—a combined 600 MW—with a 645-MW GE Vernova hydrogen-ready 7HA.03 gas turbine.

Fuel Source	LG&E (GWh)	KU (GWh)	Total (GWh)	% of Total Generation
Coal	10,046	14,276	24,322	78.6%
Gas	1,586	4,483	6,069	19.6%
Hydro	235	54	289	0.9%
Solar	8	12	20	0.06%
Total	11,875	18,825	30,700	100%

At the end of 2024, LG&E and KU had a combined owned generating capacity of 7,264 MW (LG&E: 2,466 MW, KU: 4,798 MW). The companies’ 2024 electricity generation by fuel source is reflected in the table above. Source: PPL (10-K, Feb. 2025)

KU’s Ghent 2 is part of the larger 2-GW, four-unit Ghent Generating Station, the largest coal-fired power plant in the LG&E and KU system. The plant, which began commercial operation in 1973, uses subcritical coal combustion technology, and is already equipped with electrostatic precipitators and flue gas desulfurization (FGD) systems on all units to control emissions. A $600 million FGD installation project completed in 2009 equipped all four units with scrubbers. New 662-foot chimneys were built for Units 1 and 4, including monitoring systems to measure air quality and ensure regulatory compliance.

The $152 million project to install an SCR system will ensure Ghent 2 will control its nitrogen oxide emissions and comply with the federal National Ambient Air Quality Standards (NAAQS) for ozone, the filing suggests.

As Philip Imber, director of Environmental Compliance at PPL Services, explained, Kentucky is no longer subject to the 2023 Good Neighbor Rule due to legal challenges and subsequent court rulings that invalidated the U.S. Environmental Protection Agency’s (EPA’s) disapproval of Kentucky’s State Implementation Plan (SIP). In December 2024, the U.S. Court of Appeals for the Sixth Circuit vacated the EPA’s denial of Kentucky’s SIP and remanded it to the agency, effectively blocking the application of the Good Neighbor Plan in the state. The decision has meant that Kentucky reverts to compliance under the earlier Revised Cross-State Air Pollution Rule (CSAPR) Update, rather than the more stringent requirements imposed by the 2023 Good Neighbor Plan, Imber said. However, the EPA “remains obligated to drive compliance with the 2015 Ozone NAAQS, and adding an SCR to Ghent 2 is an obvious target for such compliance efforts. Thus, adding a Ghent 2 SCR now will help ensure the ongoing year-round availability of Ghent 2, which is part of the least-cost resource plan,” he said.

Beyond the Good Neighbor Plan, the EPA’s regulatory framework includes additional rules that could affect coal-fired generation. Most notable are the Greenhouse Gas (GHG) Rule and the Effluent Limitation Guidelines (ELG). The GHG Rule, finalized in May 2024 under Clean Air Act Sections 111(b) and 111(d), imposes strict emissions limitations on coal plants, requiring them to implement carbon capture by set deadlines. However, the rule’s future is uncertain owing to legal and political opposition, including directives from the Trump administration aimed at rescinding it. “President Trump’s day-one executive orders, coupled with his campaign commitment to undo the GHG Rule, cast serious doubt on the near-term need to comply with the GHG Rule,” he said.

Likewise, the 2024 ELG Rule imposes stringent zero-discharge requirements for FGD wastewater, bottom ash transport water, and combustion residual leachate. Compliance deadlines extend to 2029, but facilities that cease coal operations by 2034 can qualify for exemptions. The rule builds on previous ELG standards but significantly tightens discharge limitations. “As with the GHG Rule, it is reasonably possible and perhaps likely that the Trump administration will seek to rescind the 2024 ELG standards. Importantly, although the EPA had the legal authority to implement the 2024 ELG standards, it was not obligated to implement revised standards,” said Imber. “Indeed, I am unaware of any reason the EPA could not rescind the 2024 ELG standards.”

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

China’s Belt and Road Initiative Is Reshaping Global Power Infrastructure

March 4, 2025

Jeff Prescott

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Since 2013, when China launched its Belt and Road Initiative (BRI), interest in the measure has been sharply divided. Proponents in Beijing and across the Global South view the BRI as a transformational platform for economic cooperation that delivers much-needed infrastructure, energy security, and industrial modernization to developing nations. Parts of the West view it more skeptically, framing it as a geopolitical tool or an expansive strategy designed to extend China’s economic and political influence through debt-laden projects and strategic energy investments.

1. China’s Belt and Road Initiative (BRI) spans over 140 countries, cutting across Asia, Africa, the Middle East, and Latin America. The U.S. Government Accountability Office (GAO) estimates China has committed $679 billion in global infrastructure financing under the BRI—far surpassing the $76 billion invested by the U.S. during the same period. Source: GAO

What is clear is that the BRI has made rapid gains in helping developing economies bulk up on energy infrastructure. In January, Wood Mackenzie noted that Chinese companies have installed 156 GW of power projects in participating countries since the BRI’s launch (Figure 1). “Between 2013 to 2024, these companies completed 369 overseas power projects, representing an investment of approximately US$281 billion,” said Yanqi Cao, managing consultant, Asia Pacific power research at Wood Mackenzie.

The bulk of these projects—70%—have been based in Asia, followed by Africa at 15%, Wood Mackenzie reported. “The top five [BIR] markets—Pakistan, Indonesia, Vietnam, Saudi Arabia, and Malaysia—are expected to see substantial growth in wind and solar installations over the next decade, with a projected 120 GW requiring an investment of US$73 billion,” it said. “Among these nations, Saudi Arabia is projected to have the highest demand, with plans to install 41 GW of solar power and 13 GW of wind power.”

According to Boston University’s China’s Global Power Database, if Chinese foreign direct investment (FDI) and investment from China’s two policy banks—the China Development Bank and the Export-Import Bank of China—are considered, the number of power projects China has supported outside its borders ramps up dramatically. “As of mid-2022, Chinese capital has supported 648 power plants overseas, representing 1,423 individual power generating units providing a total of 171.6 GW of power generation capacity,” it says. “Among these power plants, Chinese capital participation includes FDI in the form of greenfield investments or mergers and acquisitions (M&A), and debt finance,” it explains.

China’s Global Power (CGP) Database tracks 648 power plants worldwide financed through Chinese foreign direct investment (FDI) and policy bank loans, totaling 171.6 GW of generation capacity as of mid-2022. Source: Boston University Global Development Policy Center.

What Has Driven the Rapid Expansion?

To delve deeper into why the BRI has flourished so rapidly over its decade-long existence, it helps to understand what the BRI is and how it has evolved into a major global power play. As Beijing-based think tank Xinhua Institute explains, when President Xi Jinping announced the measure, it was framed as a modern-day revival of the ancient Silk Road—an extensive network of trade routes that historically connected China to Europe, the Middle East, and Africa. Its core mission was to promote global trade, infrastructure expansion, and economic cooperation, particularly in developing nations that lacked the financial capacity to modernize their economies.

Initially, the BRI primarily focused on transportation and logistics for enhanced connectivity, including financing large-scale projects such as ports, highways, and railways. In recent years, its scope has expanded to include energy development, digital infrastructure, and industrial growth. At the Third Belt and Road Forum for International Cooperation in 2023, President Xi Jinping introduced the “Eight Major Steps,” a policy framework that seeks to enhance BRI investments by expanding clean energy and low-carbon development. Essentially, it prioritizes “small and beautiful” projects with greater social benefits.

A key pillar is the “Green Silk Road,” which reflects Beijing’s concerted focus on solar, wind, hydro, and grid modernization. Chinese firms, backed by state-owned banks, have quickly gained traction in global clean energy supply chains, and today, China is the largest supplier of solar panels, wind turbines, and lithium-ion batteries. The policy framework, meanwhile, strengthens the “Digital Silk Road,” which is focused on expanding China’s global influence in digital infrastructure through artificial intelligence (AI), smart grids, 5G networks, cloud computing, and data-driven energy solutions.

2. The 3,444-MW Ilha Solteira Hydropower Station, one of Brazil’s largest hydroelectric plants, is located on the Paraná River at the junction of São Paulo and Mato Grosso do Sul. The plant, modernized by Sinohydro Bureau 11 Co., a subsidiary of POWERCHINA, underwent a major technological upgrade, with Unit No. 20 completing water commissioning and beginning operation in December 2020. It features 20 Francis turbines. Courtesy: POWERCHINA

Among the many major power infrastructure projects completed under the BRI in recent years are the 3,444-MW Ilha Solteira Hydropower Plant in Brazil (Figure 2), a project that is majority-owned by China Three Gorges Corp., and the 2,290-MW Karachi Coastal Nuclear Plant in Pakistan, which was financed by China Exim Bank. In Indonesia, Shenhua Group developed the 2,100-MW PLTU Jawa 7 coal plant, while Harbin Electric built the 2,400-MW Hassyan gas plant in the United Arab Emirates (UAE). In Sweden, China General Nuclear Power Group holds a 75% stake in the 644-MW Markbygden Wind Farm, one of the nation’s largest wind farms.

Under the more recent “Green Silk Road” initiative, the 950-MW Maktoum Solar Park Phase IV in Dubai became fully operational in February 2024, spearheaded by a China-UAE collaboration. Chinese firms last year also put online Côte d’Ivoire’s 112.9-MW Gribo-Popoli Hydropower Station and the 600-MW Karuma Hydropower Station in Uganda.

“Chinese companies are more and more involved in investing in renewable power in the top five [BRI] markets,” said Cao. “Five years ago, they accounted for only 7% of the wind and solar capacity in these markets. However, this share has risen to over 60% in 2024, and it could reach 80% by 2030, if the current trend continues.”

Geopolitical Contention

As the U.S. Government Accountability Office (GAO) explains, the BRI is a state-backed financing model, which relies heavily on loans and direct investments from Chinese financial institutions such as the China Development Bank (CDB) and the Export-Import Bank of China (EXIM Bank). The banks provide long-term, low-interest loans to BRI partner countries to allow them to fund large-scale infrastructure projects that could otherwise be financially unfeasible. However, unlike traditional foreign aid models, BRI projects are often executed through engineering, procurement, and construction (EPC) contracts—an approach that ensures Chinese state-owned enterprises (SOEs) maintain direct control over key aspects of project development, from construction to operation. It means that, often, even when a project is in a partner country, Chinese companies own, manage, and profit from its operations.

That aspect has drawn controversy. Supporters argue that the BRI fills critical infrastructure gaps in developing economies, particularly in sub-Saharan Africa, South Asia, and Latin America, where Western financing has historically been insufficient or slow-moving. China, notably, points out that its efforts to provide immediate capital for power plants and other infrastructure has helped unlock economic growth opportunities for developing countries. That holds true in Africa. While 80% of the 685 million people without electricity live in sub-Saharan Africa, China has emerged as a key infrastructure partner, investing in solar power, microgrids, and school and healthcare facilities’ electrification. Challenges persist: As the World Research Institute points out, electricity consumption still remains critically low due to high costs, limited industrial development, and financial constraints.

Critics—among them the U.S. government—warn of financial risks associated with BRI loans, cautioning “debt-trap diplomacy” could overburden countries with Chinese debt and ultimately force them to cede strategic assets as collateral. The GAO points out that 31 of the 36 nations most at risk of debt distress are BRI participants. However, beyond debt concerns, some Western analysts are concerned that the BRI is furnishing China with long-term economic, political, and geopolitical influence. As a major energy and digital infrastructure provider, China is positioned to shape the rules of global economic engagement—albeit in ways that could undermine (or leave out) Western interests, the GAO writes.

The concern rests on the country’s growing influence over energy supply chains, project financing, and equipment and services. Some projects also open new opportunities for Chinese firms to embed digital solutions, such as AI-driven energy management solutions, into energy infrastructure, raising new questions about China’s influence and control of energy data.

For now, China appears to have assumed the role of the primary architect of energy systems across the developing world, and it has moved concertedly to provide assurance that it plans to work collaboratively to deliver progress. The BRI is “not a modernization that China seeks to achieve in isolation, but rather one that aims for joint modernization with other developing countries and the world at large,” writes Xinhua Institute. The unilateral endeavor is a shared responsibility where all parties benefit equally, it argues.

“Without shared growth and prosperity, true global peace and stability cannot be achieved, and the results of global modernization will be difficult to sustain,” it says. “In the face of widening global gaps between the Global North and South, increasing challenges for developing countries to catch up, and worsening income inequality within nations, the BRI offers a realistic path to modernization for developing nations. The BRI reflects China’s deep understanding and unique perspective on modernization, encompassing not only material improvements but also comprehensive social progress.”

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

AI Boom Reshapes Power Landscape as Data Centers Drive Historic Demand Growth

March 4, 2025

Jeff Prescott

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The power industry was once considered slow-moving and perhaps even boring. That is no longer the case as technology has expanded and power demand projections skyrocket. New reports released by analysts at Enverus and Deloitte are examined to provide insight on what’s likely to evolve in the power industry over the coming year and beyond.

The artificial intelligence (AI) revolution is dramatically transforming power demand forecasts, with data center expansion emerging as the dominant force shaping energy markets in 2025. This seismic shift in energy demand comes at a pivotal moment for the U.S. power sector, as it grapples with competing priorities around reliability, environmental impact, and cost. The new Trump administration’s energy priorities and policies should not be overlooked either, and innovative advances in technologies under development could be game-changing for the industry. Despite all the uncertainties, industry analysts offer valuable insights into likely developments.

AI Data Centers Drive Load Growth

Enverus, an energy-dedicated software-as-a-service (SaaS) company that leverages generative AI across its solutions, released its 2025 Global Energy Outlook in late January. Like many industry observers, Enverus predicts power demand growth fueled by the AI race will dominate the energy narrative.

“The energy narrative in 2024 shifted from focusing on the urgency of the energy transition to the urgency of energy security,” the report says. “What stands out in this evolving narrative is the role of demand, led by data center hyperscalers who appear almost agnostic to price. For this group, the energy trilemma prioritizes reliability as No. 1, environmental concerns as No. 2, cost as No. 3. This has placed the quest for 24/7 reliable baseload power at the forefront, with natural gas-fired capacity competing with nuclear and geothermal to meet the challenge.”

Enverus forecasts U.S. load to increase 1.2% in 2025 compared to 2024, and 38% by 2050. It says accelerated AI adoption, and several energy transition and electrification themes, foster expansion. “Two of these levers—data centers and residential solar—impact the future in complex ways,” the report says. “Installed residential solar will rise from 45 GW to 56 GW in 2025 and 557 GW by 2050, vastly contributing to intraday volatility in load and offsetting load growth from all non-data center demand drivers. Data centers are the largest driver of load growth, with the highest requirement for reliability and most risk to the upside.”

Experts at Deloitte agree that data centers represent the proverbial “elephant in the room.” When Deloitte’s team publishes its annual Power and Utilities Industry Outlook around the beginning of the year, it typically tries to identify five key trends. However, this year, Thomas L. Keefe, vice chair and U.S. Power, Utilities & Renewables sector leader with Deloitte, suggested there was really one key trend and four others that support it. “Clearly, data centers is the biggie,” he told POWER.

“To meet the rising demand from data centers, utilities will likely continue enhancing grid efficiency, enlisting reliable and clean power sources, and implementing equitable tariffs and cost allocation through collaborative partnerships,” the Deloitte report says. Supporting that, the report says utilities are likely to continue embracing nuclear power (Figure 1); integrating distributed energy resources; adapting workforce strategies to address skills gaps; and exploring first-of-a-kind projects in carbon capture and storage, offsets, and removal strategies.

1. Talen Energy’s Susquehanna nuclear power plant, located near Berwick, Pennsylvania, has a power purchase agreement to supply power for at least 10 years to a data center campus Amazon Web Services (AWS) purchased near the site from a subsidiary of Talen. Courtesy: Talen Energy

Of course, the biggest challenge surrounding the data center boom is supplying the potentially explosive load growth. “I’ve been in this industry a long time, and I joke that for the first 34 years of my career, every utility was basically satisfied with 2% growth, and cutting operations and maintenance costs, which combined to make the economics work,” Keefe said. “Now, some utilities are talking 100% growth in the next five years. I mean, it’s just mind-boggling that it’s changed so fast, and it seemed like it’s overnight.”

Tax Incentive Changes Could Put Projects at Risk

Meanwhile, the inauguration of a second Trump administration has raised concern over the potential rollback of renewable energy incentives. Enverus says tax credits are foundational to the economics of the U.S. renewable energy sector.

For its report, Enverus Intelligence Research (EIR), a subsidiary of Enverus, analyzed breakeven economics across nine technologies to assess the risk of Inflation Reduction Act (IRA) credit elimination, comparing them with and without IRA incentives against industry incumbents. Of the credits analyzed, EIR suggested the 45Q tax credit for blue hydrogen and enhanced oil recovery (EOR) projects, as well as the production tax credit (PTC) and investment tax credit (ITC) for solar and onshore wind, are least at risk for elimination.

“Across the Lower 48 [the continental U.S.], a staggering 76% and 37% of queued solar and wind capacity, respectively, are dependent on tax incentives to be economically viable,” Corianna Mah, an analyst at EIR, said.

Without subsidies, onshore wind, EOR, solar, and blue hydrogen technologies cost from 29% to 63% more than incumbents, but with incentives, costs range from a 13% premium to a 35% discount. “The tax credits enable them to compete with industry today, with the hope that further buildout will reduce costs and increase their unsubsidized competitiveness,” the report says. Mah added, “On average, we see that solar projects have a higher reliance on tax credits because of higher average LCOEs [levelized cost of energy] and lower average capacity factors than wind.”

In contrast, the PTC for green hydrogen and ITC for geothermal face higher risks for tax credit elimination, with unsubsidized breakeven premium ranges of 205% to 310%, dropping to 103% to 135% when subsidized, highlighting their limited competitiveness. Landfill and manure renewable natural gas projects outcompete the voluntary market without credits, potentially making credits unnecessary for these technologies.

“In our analysis, we find the most competitive projects are those with before-tax levelized cost of energy that are already below the average power price and are viable without the boost from RECs [renewable energy certificates] and tax credits. Projects with an after-tax levelized cost of energy below the average power price and average REC price are only viable because of the existence of tax credits,” Mah said.

Marlene Motyka, Deloitte’s U.S. Renewable Energy leader and a principal in Deloitte Transactions and Business Analytics LLP, felt the coming year would be a good one for renewables. “Renewables are generally expected to retain momentum in 2025,” she told POWER. “They’re really in a race with other clean generation options to fill this growing resource gap, but they offer technology maturity, lower cost, higher modularity, and so I think those are all very good things and very positive things,” she said.

While Motyka acknowledged hearing discussion around terminating the IRA, she didn’t think a full repeal is likely. “There’s a possibility that certain provisions of IRA could be modified or repealed, but I think many areas of the country are seeing the positive impact of broader economic goals and benefits from IRA, and the expectation is that it’s unlikely that it will be completely repealed,” Motyka said. She specifically cited nuclear and carbon capture and storage as areas that may be less impacted than others.

Potentially Disruptive Developments

Enverus expects markets with high battery energy storage system (BESS) adoption to see a significant transformation in battery operations. Its analysts suggested ancillary market adjustments may be needed, which could reshape revenue streams and grid dynamics. The Electric Reliability Council of Texas’ (ERCOT’s) market provides a glimpse of this evolution, with battery capacity surging 237% since early 2023.

“While battery revenues traditionally depended on ancillary services and energy arbitrage, growing storage saturation is changing the landscape,” the Enverus report says. “As capacity outpaces ancillary market eligibility, operators will shift toward arbitrage-driven models, competing with dispatchable capacity such as natural gas-fired generation. Negative pricing hours will further enhance batteries’ competitiveness, allowing them to outbid natural gas plants and lowering bid prices.”

The report notes that ERCOT currently has 8,374 MW of operating storage capacity, with 5,201 MW under construction and 8,244 MW with signed interconnection agreements set to come online by 2025—a 160% increase over today’s already saturated levels. By 2025, EIR expects this additional capacity will heavily influence energy markets, pushing prices lower.

Enverus also sees positive prospects for advanced nuclear reactors and direct air capture (DAC) carbon capture projects. While its analysts recognize that nuclear projects will require significant regulatory reforms to streamline integration into the energy grid and address operational barriers, Enverus believes the ADVANCE Act of 2024 has boosted momentum for advanced nuclear technologies, especially small modular reactors.

Concerning DAC, the report says momentum stems from the commissioning in 2024 of Climeworks’ Mammoth project in Iceland (Figure 2). While it was the world’s largest DAC facility at 36,000 tons of CO₂ per year (tpa) when it opened, it will be dwarfed by 1PointFive’s 500,000 tpa Stratos facility when it comes online in Ector County, Texas, this year.

2. Climeworks began operations of its direct air capture and storage plant, Mammoth, in Iceland last year. The plant is designed for a nameplate capture capacity of up to 36,000 tons of CO₂ per year by filtering CO₂ from the air and storing it permanently underground. Courtesy: Climeworks

Yet, DAC faces growing challenges associated with its energy-intensive nature, as highlighted by the withdrawal of Project Bison in Wyoming. Additionally, the future of the U.S. Department of Energy’s Regional DAC Hubs program and any future funding for DAC is uncertain under the new administration. Meanwhile, high capital costs and energy demands remain significant hurdles as DAC approaches the peak of inflated expectations, Enverus said.

Deloitte’s Keefe noted that carbon capture technology is not new or unproven, it’s just not cost-effective at the present time. However, if incentives are offered and investments are made in the technology, the costs will likely come down. Keefe reflected on solar and wind cost curves and how they’ve declined over the past 20 years. “Pick your source,” he proposed. “Whether it’s geothermal or hydrogen or carbon capture, I’m hopeful that we can get there, and smart people continue to find ways to make it more cost-effective.”

—Aaron Larson is POWER’s executive editor.

The SMR Gamble: Betting on Nuclear to Fuel the Data Center Boom

March 3, 2025

Jeff Prescott

advanced nuclear artificial intelligence Business data center power demand data centers energy infrastructure Energy Security Fuel Full Coverage hyperscalers News Nuclear Power Power Demand regulatory challenges SMRs Sustainability Technology Workforce No Comments

Data center power demand is accelerating, pushing the grid to its limits and prompting tech giants to bet on next-generation nuclear reactors. But given steep costs, regulatory hurdles, and uncertain scalability, is nuclear the future of data center energy—or just another high-stakes gamble?

At the end of January, Chinese artificial intelligence (AI) startup DeepSeek unveiled two large language models (LLMs)—DeepSeek-R1 and DeepSeek-R1-zero. Unlike previous generations of AI models, DeepSeek’s breakthrough reduced the compute cost of AI inference by a factor of 10, allowing it to achieve OpenAI GPT-4.5-level performance while consuming only a fraction of the power. The news upended future electricity demand assumptions, rattling both the energy and tech sectors. Investment markets reacted swiftly, driving down expectations—and share prices—for power generation, small modular reactor (SMR) developers, uranium suppliers, gas companies, and major tech firms.

Yet, amid the chaos, optimism abounded. Analysts pointed to Jevons paradox, the economic principle that efficiency gains can increase consumption, rather than reduce it. “Our model shows a ~90% drop in the unit cost of compute over a six-year period, and our recent survey of corporate AI adoption suggests increases in the magnitude of AI use cases,” said Morgan Stanley Research. The U.S. remains the dominant market for AI-driven data center expansion, with 40 GW of new projects under development, aligning with a projected 57 GW of AI-related compute demand by 2028. Already, that load is transforming the energy landscape. A recent POWER analysis shows that U.S. data center electricity consumption could reach between 214 TWh and 675 TWh annually by 2030, up from 176 TWh in 2023 (Figure 1).

1. U.S. data center electricity consumption began rising steadily in 2017, driven by an expanding server installed base and the growing adoption of graphics processing unit (GPU)-accelerated servers for artificial intelligence (AI). AI inference workloads and hyperscale data center expansions are expected to increase electricity demand sharply in coming years. Source: Lawrence Berkeley National Laboratory (LBNL 2024 United States Data Center Energy Usage Report)

That has dramatically raised the stakes, igniting a desperate frenzy across both the power industry—which must generate and deliver reliable electricity for a variety of emerging large load consumers—and the data center industry, which is scrambling to procure firm scalable energy to sustain its explosive growth, now and well into the future. The stakes are fueled by real fear. In November, research firm Gartner projected that power required for AI data centers could reach 500 TWh per year by 2027, a 2.6x increase from 2023 levels. It warned that power shortages could restrict 40% of AI data centers by 2027 and drive up energy costs.

The upfront cost of power is no longer the deciding factor for data centers, speakers at the Sustainable Data Centers Summit in Dallas, Texas, suggested in early February. “It’s crazy because we look at like the state of Oregon is about 6 GW, and you have these large hyperscalers [asking] ‘Can I get 6 GW too?’ ” said Mohammed Hassan, senior technical program manager for Amazon Web Services (AWS) Sustainability. Hassan suggested the industry has had to rethink how it approaches energy planning and procurement completely to align with incentives, address regulatory hurdles, and secure long-term reliability. “Solar and wind has taken off in the lead. But if you look at the needs of 2045, in trying to meet the Paris Agreement, solar and wind won’t be enough, so you have to look at what’s the next step.”

At the conference, speakers pointed to potential alternatives that could perform over the short term: natural gas as a “bridge fuel,” carbon capture as a potential future solution, energy storage solutions for flexibility and to promote grid resilience, and renewable diesel as a cleaner backup power option. But to meet long-term goals, the industry is willing to bet on nuclear power for its many benefits—despite the significant challenges that remain.

2. Advanced nuclear firm Last Energy is pursuing a business model that relies on long-term power purchase agreements (PPAs) to finance, build, and operate its fleet of small modular reactors (SMRs). The company in February announced it would build 30 microreactors at a site in Haskell County, Texas, to power data centers across the state.Courtesy: Last Energy

Advanced nuclear developers are overwhelmingly on board. “The overwhelming sentiment nuclear has received from the data center industry is gravitation, not reluctance,” Matt Fossen, vice president of Communications at Last Energy (Figure 2), told POWER. Data center developers recognize that nuclear is uniquely well-positioned to provide the kind of clean energy abundance and 24/7 reliability they need to meet demand. And, in particular, they’re gravitating toward solutions like microreactors because they enable fast delivery, on-site installation, and efficient scalability to meet demand today and tomorrow.”

Why Data Centers Are Turning to Advanced Nuclear

Progress to cement supply to data centers has been fluid over the past year, ushering in a wave of mega-deals, with many more still in development. While many have involved power purchase agreements (PPAs) to procure power from renewables and natural gas power plants, several have focused on existing nuclear plants.

In September, Microsoft and Constellation Energy committed $1.6 billion to restart Three Mile Island Unit 1, now rebranded as the Crane Clean Energy Center, with a targeted 2028 reopening. Other deals are under discussion by Vistra for Comanche Peak in Texas; Public Service Enterprise Group, possibly for Salem and Hope Creek in New Jersey; and Constellation Energy, possibly for Calvert Cliffs in Maryland. Meanwhile, though AWS has sought to expand the Cumulus data center’s load, co-located with Talen Energy’s Susquehanna nuclear station in Pennsylvania, to 480 MW, the proposal was blocked by the Federal Energy Regulatory Commission (FERC), which cited concerns about grid cost allocation and reliability impacts, and the dispute has moved to the U.S. Fifth Circuit Court of Appeals. So far, according to trade group the Nuclear Energy Institute (NEI), 45% of the 95 existing units in the U.S. have expressed interest or planning in data centers, with at least 25 sites looking to fulfil power requirements ranging from 400 MW to 1,920 MW.

Deals have also abounded for advanced nuclear, including SMRs and microreactors, even though their commercial viability hasn’t yet been demonstrated. In September, Oracle announced plans to build a gigawatt-scale data center powered by three SMRs, securing building permits as part of a push to expand its cloud infrastructure. In October, Google signed a pioneering Master Plant Development Agreement with Kairos Power to develop a 500-MW fleet of molten salt reactors by 2035. That same week, Amazon unveiled plans to back 5 GW of new X-energy SMR projects, starting with a four-unit, 320-MWe Xe-100 project in Washington with Energy Northwest, alongside a Dominion Energy partnership to explore a 300-MW SMR near Virginia’s North Anna Power Station. In December, Oklo partnered with Switch, a Las Vegas-based data center designer, builder, and operator, to deploy 12 GW of Aurora powerhouses through 2044 in a historic deal hailed as “one of the largest corporate clean power agreements ever signed.”

“When it comes to producing electricity, I wouldn’t say there’s any one advanced reactor technology that jumps out as being optimized solely for data center applications,” said Patrick White, research director of think-tank Nuclear Innovation Alliance (NIA). “But what we’re seeing is that these reactors have the potential to provide the kind of high-reliability, cost-stable, and emissions-free power that data centers are increasingly seeking.”

The key reason SMRs are gaining traction over larger gigawatt-scale nuclear plants relates to siting flexibility, he explained. Industry is looking at deploying “tens or hundreds of megawatts at a time, which can make it a lot simpler in terms of siting it with whatever demand, wherever the electricity demand actually is,” he noted. But, in addition, he said many of these advanced designs will be engineered to have “a reduced water demand for cooling water or to eliminate the need for cooling water entirely, by looking at things like direct air cooling.” That also opens up a wider range of potential siting options, including the possibility of co-locating nuclear power plants directly with data centers, he noted.

The more concerning question surrounding the integration of advanced nuclear with data centers is whether nuclear can scale fast enough to meet the industry’s growing power demands. The first SMRs from companies like GE Hitachi and X-energy aren’t expected to be operational until 2029–2030, and while microreactors might arrive sooner—around 2027–2028—the scalability of the smaller units remains uncertain.

“The question is not whether nuclear can power data centers—it’s whether data centers are willing to wait for nuclear,” White noted. “Data centers could be nuclear’s first customers, pulling tech to commercialization—but will they commit for the long haul?”

The Data Center Dilemma: Weighing the Nuclear Bet

For Google, Amazon, Microsoft, and other data center developers, owners, and operators, recent nuclear deals or agreements signal clear interest to bolster the burgeoning advanced nuclear market. But they go well beyond reliability, as sources told POWER on the sidelines at the Sustainable Data Centers Summit in February. “It’s not just about doing a PPA and calling it a day,” explained Mohammed Hassan, senior technical program manager for Amazon Web Services (AWS) Sustainability during a fireside chat. “We’re willing to put our money where our mouth is and invest in the development of these technologies because we know they’re going to be critical to meeting our sustainability targets.”

Sources outlined a long list of key attributes that make nuclear an attractive option for data centers, but they also highlighted critical concerns that could hinder adoption.

Why Nuclear Is Drawing Interest

Decarbonization Goals. Nuclear energy provides a carbon-free alternative to fossil fuels and could help data centers meet aggressive sustainability targets and corporate sustainability targets.

Energy Density. AI-driven workloads demand unprecedented power levels, and nuclear’s high energy density makes it an attractive option for scaling capacity without requiring vast land footprints.

Grid Stability. The surge in AI workloads is creating volatile demand spikes, putting significant strain on grids. Nuclear’s steady 24/7 baseload power is seen as a potential solution to grid congestion and reliability issues. One industry expert emphasized, “You have to look at a source that can handle the [power needs], and where we need to go, and nuclear is the most sustainable.”

Long-term Energy Strategy. Nuclear power is seen as a potential solution to meet future energy demands.

What’s Holding Nuclear Back?

Public Perception. Historical concerns over safety, spent nuclear fuel management, and cost overruns continue shaping public resistance to nuclear development and could pose risks or affect siting and permitting for colocated data centers.

Regulatory Hurdles. Advanced reactors face lengthy approval processes that conflict with the data center industry’s rapid growth timelines.

Long Development Timelines. Nuclear projects often face delays and extended construction periods, which may not align with the rapid deployment needs of data centers “You’re looking at 15 to 20 years before you can actually get a nuclear plant up and running,” said one expert.

Technology Readiness. While SMRs show promise, they are not yet widely deployed.

Financial Risks. High upfront capital costs and first-of-a-kind deployment risks make the economics of SMRs uncertain. That has raised concerns about whether nuclear will be cost-competitive in time to meet AI-driven demand.

Grid Integration. As data centers expand, states are reworking utility policies to shift transmission costs onto large-load customers. Some regulatory structures do not yet accommodate nuclear-backed behind-the-meter solutions, adding complexity to grid planning.

Competing Clean Energy Options. Data centers are also exploring other clean energy sources. One expert told POWER: “Most companies are moving towards natural gas because of the flexibility that it offers.”

Skills Gap. The nuclear industry faces a shortage of skilled workers, which could affect the operation and maintenance of nuclear facilities for data centers.

Geopolitical Considerations. Nuclear power involves sensitive technologies and materials, which can complicate international data center operations and expansions.

Addressing the Timing Gap

How advanced nuclear scales up ultimately depends on market risks and scalability challenges, experts told POWER. The most prominent among them, predictably, involves regulatory bottlenecks. While the Nuclear Regulatory Commission (NRC) is shifting toward a more “performance-based and risk-informed” approach, developers remain frustrated by lengthy approval timelines and evolving safety requirements. While high regulatory costs are another considerable consideration, relief may be on the horizon. The NRC recently proposed a dramatic reduction in service fees—slashing them by more than 50%—for advanced nuclear reactor applicants and pre-applicants. The move, designed to incentivize innovation and accelerate next-generation nuclear deployment, proposes a two-tiered hourly rate system, is set to take effect in late 2025.

“The barriers for advanced reactor projects aimed at supporting data center capacity are similar to barriers to advanced reactor development and commercialization more broadly,” Elina Teplinsky, leader of the energy practice at Pillsbury Law, told POWER. “However, there is the added factor of timelines—data center operators need the power today, while it takes a number of years to license, develop, and deploy an advanced reactor, or any nuclear facility.”

So far, the NRC has begun adapting its framework to accommodate smaller, more flexible reactor designs. The approval of NuScale’s site-boundary emergency planning zone (EPZ)—which eliminated the traditional 10-mile evacuation zone requirement—marked a landmark decision that will allow nuclear plants to be located much closer to industrial facilities, including data centers, several experts pointed out.

“NRC already validated a risk-informed methodology for NuScale that allows that developer to adopt an EPZ limited to the site boundary,” Teplinsky explained. “This paves the way for other developers to use methodologies to demonstrate that smaller EPZs will provide the same level of protection to the public as the 10-mile EPZs currently mandated by the NRC for existing plants. This would allow the siting of advanced reactors closer to population centers, including data centers.”

In addition to the NRC licensing issues, regulatory concerns span “contending with the interconnecting utility and state regulations for behind-the-meter generation or the [independent system operators] and interconnection queues if connecting to the grid,” said Baker Botts partner Elaine Walsh. “Some regions are friendlier to these developments than others. Then they may have local water issues to deal with.”

Meanwhile, policy remains a risk. “It’s not clear that policymakers have fully appreciated the challenges with meeting this new expected demand growth, and policy often trails market trends,” noted Eli Hinckley, a partner at Baker Botts. “Uncertainty is a massive hurdle for infrastructure investors—long lives and relatively low yields need certainty as it relates to off-take and policy. An unstable policy position undermines actual investment,” he said.

Permitting is also still evolving—and recently suffered a setback when FERC rejected an interconnection service agreement between PJM Interconnection and Susquehanna Nuclear that would have increased the load sent from the Susquehanna nuclear plant to AWS’s Cumulus data center co-located with the plant. “FERC’s position on interconnection service agreements that allow for direct power sales from nuclear power plants to data centers will be a key permitting issue in the potential co-location of data centers with advanced reactors,” Teplinsky noted. Meanwhile, states like Ohio and Georgia have introduced new policies requiring data centers to cover infrastructure costs upfront. Tha may signal another broad shift in how utilities and regulators plan to manage the financial burden of rapid energy demand growth.

Overall, regulatory complexity will remain a major challenge, several sources suggested. “Developers face technical, political, and regulatory hurdles, including NIMBYism and complicated processes for securing state and federal permits to build new nuclear facilities,” law firm Vinson & Elkins told POWER. The law firm, however, noted that critical issues are partially addressed in the bipartisan ADVANCE Act, passed in 2024, which directs the NRC to streamline licensing, cap fees for advanced reactor applicants, and accelerate approvals for coal-to-nuclear conversions. The law also expands funding for workforce development, strengthens domestic nuclear supply chains, and mandates a faster permitting framework. And, as notably, it introduces prizes to incentivize first-of-a-kind reactor licensing. Those measures, designed to ease financial burdens and spur deployment, are slated to cover NRC fees for the first advanced reactor to secure regulatory approval for flexible operations, nonelectric applications, or the use of spent nuclear fuel.

Behind-the-Meter Nuclear: A Direct Power Solution?

A much-explored approach gaining traction as hyperscalers seek dedicated, reliable, and carbon-free power to meet AI-driven energy demand involves behind-the-meter (BTM) configurations—the so-called “colocation” option in which load co-colates with a generator that is interconnected to the grid, but is situated behind the generator’s meter. Compared to traditional power purchase agreements (PPAs), where electricity flows through transmission and distribution networks, a BTM setup connects the data center and power plant on site. In the case of nuclear power, this means a data center could draw electricity exclusively from a co-located nuclear plant, rather than purchasing power from the broader transmission system.

A key advantage cited by data centers is that BTM integration offers cost efficiency, generally because they eliminate transmission and distribution charges, but also because they could potentially bypass wholesale power markets, and offer more energy security by shielding data centers from grid congestion, price volatility, and curtailment risks associated with renewable-heavy grids. In addition, proponents argue that co-locating data centers with advanced nuclear could allow faster deployment, given that facilities can be built closer to the load center without lengthy transmission upgrades. However, this comes with a risk: if the nuclear plant goes offline, the data center must rely on on-site backup power, as grid service may not be immediately available.

For now, BTM arrangements remain under considerable regulatory scrutiny. Maryland’s Senate Bill 1 (SB1) is actively assessing how colocated projects at the Calvert Cliffs Nuclear Plant would impact ratepayers and grid stability, while Texas, through Senate Bill 6 (SB 6, filed on Feb. 12), is exploring the costs and planning required for integrating massive loads like data centers. If passed, SB6 could impose new requirements on large BTM loads after December 2025, including mandatory transmission charges, financial commitments, and potential deployment of on-site backup generation, and observers suggest it could make BTM arrangements with advanced nuclear more expensive and administratively complex.

At the federal level, the Federal Energy Regulatory Commission (FERC) is moving swiftly to define how co-location fits within wholesale electricity markets, particularly in the PJM region. On Feb. 20, FERC initiated a show cause proceeding directing PJM and its transmission-owning utilities to propose tariff changes that govern the rates, terms, and conditions for co-location arrangements. While PJM has projected a dire need for more than 30 GW of additional peak load over the next five years, FERC’s intervention seeks to address critical questions around jurisdiction, cost causation, reliability, and capacity market participation. If FERC imposes new transmission or market requirements, it could alter the economics of BTM nuclear projects, potentially affecting financing models and deployment timelines. From a grid perspective, PJM has flagged concerns over planning and reliability risks. While traditional network loads are integrated into long-term planning, BTM configurations can create blind spots, as they aren’t accounted for in regional capacity planning, it says.

According to a February 2025 paper from Duke University’s Nicholas Institute for Energy, Environment, and Sustainability, additional considerations must be weighed when evaluating BTM nuclear projects. One key factor is load flexibility —large colocated loads, such as AI data centers, could be required to provide grid services, such as demand-side response, to help maintain system reliability. The paper also highlights grid utilization impacts, noting that while some BTM loads may avoid grid transmission charges, they may still impose costs on system planning and resource adequacy. Additionally, it warns, market pricing structures may shift, potentially forcing BTM users to contribute to shared grid infrastructure costs. Uncertainties also extend to technical and operational aspects, given that SMRs and microreactors remain untested at scale for continuous high-demand applications. Hybrid models—where BTM nuclear remains partially grid-connected for redundancy—could require new regulatory frameworks to establish pricing, reliability obligations, and backup provisions, it notes.

Emerging Business Challenges

Still, beyond regulations, the actual business of running co-located nuclear plants remains uncertain. While recent discussions highlight tech companies as potential investors in advanced nuclear facilities, data center sources confirmed most aren’t attracted to the prospect of owning and operating nuclear plants.

“Data center operators are not in the business of running power plants,” said Walsh. “They want reliability and cost certainty, but they don’t want to deal with regulatory oversight, fuel procurement, or reactor maintenance.”

For now, long-term PPAs look like the preferred model. “Looking across all fuel and technology types, we’re seeing a variety of structures to accommodate data center load, including PPAs and retail energy supply agreements, as well as data centers, hyperscalers, and real estate developers actually taking equity in these projects,” she added. “I would expect fewer data center and real estate developers will be holding equity in nuclear assets.”

Teplinsky, however, noted that along with recent tech giant investments in nuclear development, some companies are exploring partial ownership stakes to secure guaranteed energy supply. “Deals with hyperscalers also present an opportunity to secure some equity investment into these projects,” she said. “The demand from data centers is less a barrier than an opportunity—it allows developers to secure firm and bankable offtake for these projects—potentially at a premium.”

From an operational standpoint, co-located facilities can pose new risks, as Nina Sadighi, professional engineer and founder of Eradeh Power Consulting told POWER. “Who’s going to insure these plants?” she asked. “That’s a huge unknown. Right now, insurance providers are hesitant because of the regulatory and operational complexity. The traditional nuclear liability structures are built around large reactors with established operational histories, and when you introduce something novel like SMRs or microreactors, you’re dealing with a very different risk profile.”

Sadighi, though generally optimistic about nuclear’s suitability for data centers, also pointed to potential workforce-related challenges that hinge on timely deployment. “If we train nuclear workers now, but deployment gets delayed, those workers won’t wait around,” she said. “The nuclear workforce pipeline is not like a tech workforce, where people can pivot between roles quickly. These are specialized skills that require years of training, and if there’s uncertainty about job stability, we risk losing them to other industries entirely,” she said. Sadighi also raised concerns about the stringent operational protocols that add to labor inefficiencies.

Finally, while the data center industry isn’t solely bent on economics—and told POWER sustainability with a long-term vision is a bigger priority—scaling up will require significant investment. That has sparked all kinds of debate. Lux Research estimates first-of-a-kind (FOAK) SMRs could cost nearly three times more than natural gas ($331/MWh versus $124/MWh) and more than 10 times more when factoring in cost overruns and delays. The firm projects SMRs won’t be cost-competitive before 2035. “Cheap nuclear just isn’t in the cards in the next two decades,” it says.

However, a recent Idaho National Laboratory study suggests costs could decline as SMRs move to Nth-of-a-Kind (NOAK) production. It suggests modular construction, factory fabrication, and standardized deployment could drive efficiencies, potentially reducing costs as more units are built. Notably, the study describes an “economies-of-scale penalty crossover point” where SMRs achieve cost parity with large reactors if enough units are deployed. Deploying four 300-MW SMRs could drop costs by 20% compared to a single 1,200-MW reactor, it suggests. For now, the first real-world test of this cost curve will be Ontario Power Generation’s BWRX-300 SMR fleet, which is expected to start operating by 2029.

The fundamental debate is rooted in several uncertainties—which is not uncommon for emerging sectors, experts also generally pointed out. “Tax credits—especially the clean electricity production tax credits and investment tax credits—will be vital to the commercial viability of these projects, especially considering the FOAK risk,” said Teplinsky. “DOE [U.S. Department of Energy] loan guarantees and direct financing from the Federal Financing Bank at low rates are also essential to companies’ ability to secure debt and reduce cost of capital. Grant funding to support commercial demonstrations and high-assay low-enriched uranium support are also key.”

However, Teplinsky cautioned that these incentives were in place before AI-driven data demand soared. “[T]hey will need to remain in place in order for data center-driven advanced reactor projects to be viable,” she said. “In fact, these incentives need to expand and address some of the key issues still inhibiting large-scale advanced reactor deployment despite data center demand, such as FOAK deployment and cost overrun concerns.”

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

NAES, Gecko Robotics Launch $100M AI Partnership Amid Energy Crisis; Shapiro Questions PJM Future

February 28, 2025

Jeff Prescott

AI in energy Business energy modernization energy policy Energy Security Full Coverage Gas Gecko Robotics Josh Shapiro NAES News O&M PJM Interconnection Power Demand power grid power plants robotics No Comments

In a bid to stave off an escalating power crisis, NAES, one of the largest independent power plant operators in the U.S., and Gecko Robotics, a leader in AI-driven robotic inspection and predictive maintenance, have moved to champion a prominent role for the nation’s existing fleet, launching a $100 million strategic partnership to bolster their modernization and improve their efficiency. The unprecedented collaboration, announced on Feb. 27, comes amid growing concerns over grid reliability and is strongly backed by Pennsylvania Governor Josh Shapiro, who warned that sluggish energy project approvals are hindering economic growth and could force the state to reconsider its role in the PJM power grid.

The partnership between NAES and Gecko Robotics, which could expand beyond $250 million as demand warrants, seeks to deploy advanced AI and robotic technologies initially across the 65 GW of power generation assets managed by NAES to enhance efficiency, reliability, and workforce capabilities.

At the heart of the partnership is Gecko’s AI-driven Cantilever platform, an ecosystem of mobile robots, drones, robotic dogs, and fixed sensors that continuously monitor and optimize power plant equipment by collecting real-time data, applying advanced analytics to predict and prevent failures, extending asset lifespans, and uncovering new ways to boost output. While the primary focus is on NAES-operated facilities, the companies are also exploring opportunities to expand Gecko’s Cantilever platform to other power producers through potential licensing agreements or joint ventures, with a broad goal of transforming the entire power generation industry.

In an exclusive interview with POWER, NAES CEO Mark Dobler and Gecko Robotics CEO Jake Loosararian underscored the urgent need for technology-driven solutions to meet rising power demands. While energy projections vary, energy policy consulting firm Grid Strategies has found the 5-year load growth forecast has increased by almost a factor of five, from 23 GW to 128 GW—and that nationwide, power demand is forecast to increase by 15.8% by 2029 (over the next four years). Data center growth forecasts range from 65 GW to over 90 GW, while manufacturing demand could add up to 20 GW, and electrification and other sources may contribute another 20 GW to overall load growth.

The looming power crisis has been exacerbated by a series of new hurdles, directly impacting the performance of existing power plants. As POWER reported as part of its February Operations and Maintenance (O&M)-focused special report issue, these challenges include the accelerated retirement of fossil-fueled capacity, sluggish progress on new resource additions, rising O&M costs, workforce shortages, regulatory uncertainties, and the growing complexity of integrating renewables into an aging grid. All are straining reliability and forcing operators to rethink maintenance and modernization strategies.

As Dobler noted, workforce shortages pose a major concern.“If the 100 to 400 GW of additional generation we need had to be met with new plants, that’s 15,000 to 20,000 incremental O&M people needed just to run those facilities,” he said. “And we’re already fighting a retirement wave.” An estimated “25% of plant O&M [personnel] across the country will be retiring in the next five to 10 years. That’s a lot of talent leaving the industry, a lot of experience leaving the industry at the same time where you’ve having a lot of new generation coming online,” he said. “So, it’s a bit of perfect storm, related not only to sourcing the new plant and equipment and getting it installed and constructed, but then also the startup and commissioning, and then the O&M of these 25- to 30-year assets,” he added. “There’s really no other way to fill the gap without using technology.”

Loosararian emphasized the gravity of the crisis, warning that its challenges extend beyond grid reliability. “This isn’t just about efficiency or reliability—it’s about national security, global competitiveness, and the future of our entire energy system,” he said. “The time for incremental change is over. It’s time to go big, and go fast.” He added: “We don’t have the people or the capacity to keep the lights on using the old playbook. Artificial intelligence and robotics are the only way we’re going to be able to meet this moment.”

*NAES CEO Mark Dobler and Gecko Robotics CEO Jake Loosararian discuss the deployment of AI and robotics for power plant modernization at a NAES facility. Courtesy: NAES/Gecko.*

Revolutionizing Power Plant Operations with AI and Robotics

Both NAES and Gecko view the $100 million initiative as a transformational imperative for power plant operations. “We want to kill the way that plants are run today,” said Loosarian bluntly. “We’re replacing the old way with a fundamentally new approach, built from first principles using AI and robotics.”

The executives told POWER both companies have commitments to the financial investment, though NAES and Gecko are still working to engineer the structure of the partnership for maximum impact, and declined to share the types of investments it will include, the sources of financing, and assets they will affect. “We really don’t want to box ourselves in in terms of doing what’s right for both businesses and giving the industry a solution,” said Dobler.

Meanwhile, though the scale on which the partnership intends to deliver is unprecedented, it may still encounter industry-wide challenges that have stymied the wider uptake of AI and robotics in the power industry. That includes regulatory hesitance and industry skepticism. “There’s been some resistance from operators, regulators, and utilities,” Loosararian acknowledged. “But the reality is, this isn’t optional. The technology works. If we don’t do this now, we’re going to be left behind.”

Dobler agreed, stressing that the NAES-Gecko partnership goes beyond developing technology. Ensuring its adoption at scale is the primary objective, he said. “We’re not AI experts. We needed a partner who could take a solutions-based approach—not just a tech company selling a product, but someone who understands our industry and works with us to implement real change. That’s what makes Gecko different.”

Loosarian predicted progress over the next year, driven by the partners’ goal to turn power plants into self-optimizing AI-driven systems that will set a new standard for reliability, efficiency, and cost-effectiveness. “Within the next 12 months, we’ll start seeing major gains at these facilities, and those without this technology will be left behind,” he said.

*A Gecko Robotics wall-climbing inspection robot in action at a power plant, showcasing the AI-driven technology at the core of NAES and Gecko’s new partnership. Courtesy: NAES/Gecko.*

An Energy Strategy with Federal and State Backing

Beyond transforming plant operations, the partnership aligns with federal energy priorities. “White House officials are closely monitoring the initiative,” Loosararian said. “We are working closely with key members of the administration to ensure this moves forward as a national priority,” he revealed. “This is a national security issue, not just an industry one. AI’s ties to national security mean defense agencies are paying attention, too.”

During a press briefing on Thursday to shed light on the partnership, Pennsylvania Governor Josh Shapiro also expressed solid support for the collaboration. Shapiro noted the innovative measure, led by Pittsburg-headquartered Gecko, is pivotal in setting the stage for both the future of technology and energy. “I have an economic development strategy here in Pennsylvania that leans heavily on robotics and technology as a key pillar of opportunity, alongside energy—another pillar of opportunity—and obviously, we’ve got a long legacy of leadership there,” he noted.

While Pennsylvania has long pursued an “all-of-the-above” energy strategy—supporting coal, natural gas, nuclear, and renewables—Shapiro suggested that adopting cutting-edge solutions like AI-driven robotics would modernize the power sector while attracting investment and high-skilled jobs. “I have a plan to increase generation here in Pennsylvania, while creating jobs, fostering innovation like the kind that occurs over at Gecko every day, so we can both cut costs and take action on climate change and ensure people have reliable, affordable energy all across Pennsylvania and across this great country,” he said.

Shapiro Suggests Pennsylvania Considering Leaving PJM

Shapiro on Thursday, however, framed the state’s energy challenges within a broader economic and technological race, warning that Pennsylvania must take decisive steps to expand power generation.

While the state ranks third nationally in electricity production, it relied on natural gas for nearly 60% of its power in 2023 (up from 22% a decade ago). The state’s four nuclear plants provided about 32%. At least one reactor, the Crane Energy Center (formerly Three Mile Island 1) is undergoing recommissioning to meet soaring data center demand. Coal power has dramatically declined from 39% of generation in 2013 to just 5% in 2023, while renewables provided 4%. For now, three electric-transmission zones in Pennsylvania are expected to see sharp increases—of up 60%—in power demand due to current and new data centers

“We’ve got to have more generation here in the Commonwealth of Pennsylvania, across the PJM states, and across this country, if we’re going to win the race on AI, if we’re going to continue to be able to provide affordable, accessible, reliable power to all Pennsylvanians,” Shapiro said.

He stressed that PJM’s protracted interconnection process has slowed critical investments in energy infrastructure, delaying new power plants at a time when electricity demand is projected to surge. “It has proven over the last number of years, too darn hard to get enough new generation projects off the ground because of how slow PJM is,” Shapiro added.

The governor’s frustration with PJM comes after months of escalating tensions. In December, Pennsylvania filed a formal complaint with the Federal Energy Regulatory Commission (FERC), arguing that PJM’s capacity market design had led to volatile electricity prices without ensuring the development of new generation. The complaint cited PJM’s July 2024 Base Residual Auction, which saw capacity prices jump nearly tenfold—from $28.92/MW-day to $269.92/MW-day—amid a worsening supply-demand imbalance.

Shapiro’s administration contended that the grid operator’s interconnection backlog, which includes 3,300 pending projects, has exacerbated the state’s energy shortfall. Pennsylvania warned that if no corrective measures were taken, consumers could face up to $74 billion in avoidable costs over the next two years. A settlement reached in January between Shapiro and PJM resulted in a significant reduction of the auction price cap, lowering it from more than $500/MW-day to $325/MW-day.

On Thursday, the governor explicitly suggested that if PJM cannot adapt, Pennsylvania may seek an independent energy strategy. “We are exploring all options here in Pennsylvania, including removing ourselves from PJM, going in alone and determining if that is a better course for both consumer pricing and power generation in our common market,” he said.

Shapiro’s remarks come as Pennsylvania looks to ramp up energy investments through tax incentives and regulatory reforms. His newly proposed Pennsylvania Reliable Energy Siting and Electric Transition (RESET) Board seeks to fast-track new power plant construction and accelerate permitting for large-scale energy projects. The RESET Board is a key component of Shapiro’s broader “Lightning Plan,” an ambitious, all-of-the-above energy strategy designed to attract investment, create jobs, and strengthen Pennsylvania’s position as a national energy leader.

As part of this initiative, Shapiro’s administration is also revamping Pennsylvania’s Economic Development for a Growing Economy (EDGE) tax credit program, unlocking billions in untapped economic opportunities through targeted incentives, including up to $100 million per facility for new power plants, $49 million annually for clean hydrogen projects, and $15 million per year to boost sustainable aviation fuel (SAF) investments. “We need shovels in the ground now, not in the years to come,” the governor reportedly said during a speech on Thursday morning.

As Dobler noted, the imperative has been broadly echoed by key Trump administrators. Interior Secretary Doug Burgum in a speech to the Conservative Political Action Conference on Friday called for commitment to utilize and maximize all available energy resources. “The fastest way to get incremental power to the grid today is to further optimize the installed plant that already exists,” Dobler said. “Can we get another 10% to 15% out of the 1,300 GW that exist in the country today? That’s exactly what NAES and Gecko are working toward—deploying technologies that push efficiency limits without compromising reliability.”

Dobler emphasized that NAES has already developed technologies to optimize plant performance, and they are actively being deployed at customer sites to improve turbine efficiency at gas plants. “Being able to integrate that with Cantilever, to augment those capabilities with AI-driven automation, wasn’t even on our radar 30 days ago.” While the power sector faces formidable challenges, Dobler suggested that tackling these hurdles head-on could unlock new opportunities. “It’s such a dynamic time,” he reflected.

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

Kemmerer 1—TerraPower’s Pioneering Fourth-Generation Nuclear Project—Hits Key NRC Milestone Ahead of Schedule

February 27, 2025
Jeff Prescott
advanced reactors Business Energy Storage Engineering Full Coverage Kemmerer 1 licensing modernization Markets Natrium reactor News Nuclear nuclear power nuclear regulation sodium-cooled fast reactor Technology TerraPower U.S. NRC No Comments

The U.S. Nuclear Regulatory Commission (NRC) has completed its draft safety evaluation (SE) a month ahead of schedule—albeit with open items—for TerraPower’s Kemmerer Power Station Unit 1, a pioneering 345-MW sodium-cooled fast reactor (SFR) under development in Wyoming.

The NRC’s draft SE was initially expected by March 2025, but productive engagement between the regulatory agency and TerraPower’s subsidiary, US SFR Owner, LLC (USO), allowed for earlier-than-anticipated completion, the regulatory body said in a letter on Feb. 26. According to the NRC, the final SE is now targeted for June 2026, two months ahead of the previous August 2026 timeline. The environmental review remains separately on track for completion in May 2026. TerraPower has told POWER it anticipates receiving NRC approval in late 2026, which could allow nuclear construction to begin in early 2027—potentially sooner if processes move efficiently.

Kemmerer 1 is taking shape in Lincoln County, Wyoming, about 3 miles from PacifiCorp’s three-unit 604-MW coal and gas–fired Naughton Power Plant, furnished with up to $2 billion in authorized funding under the Department of Energy’s (DOE’s) Advanced Reactor Demonstration Program (ARDP). While the demonstration will be a fully functioning commercial power plant, it will showcase TerraPower’s first Natrium reactor, an 840 MWth pool-type Natrium SFR reactor. Kemmerer 1 will be a hybrid nuclear facility that will integrate the fourth generation reactor with a nitrate molten salt-based energy storage system that could boost the system’s output to between 100 MWe and 500 MWe of power for more than 5.5 hours when needed, ramping at 10% a minute.

While the NRC’s draft SE represents a crucial step in the licensing process—signaling the NRC’s thorough review of the Natrium reactor’s safety features and design—the agency has identified several outstanding issues that TerraPower must address. These include materials qualification for environmental compatibility, special treatment requirements for safety-significant structures, systems, and components, and the seismic/structural design approach for non-safety-related systems. The NRC has also requested additional documentation on the PRA’s use within the Licensing Modernization Project (LMP) and other licensing programs.

The LMP is designed to modernize the regulatory process for non-light water reactors by incorporating risk-informed approaches. The NRC’s request for further PRA documentation suggests that it is closely evaluating how TerraPower is applying risk insights to safety classifications and regulatory decision-making, a key factor in the licensing of first-of-a-kind (FOAK) reactors like Natrium.

When asked how the identified open items compare to issues typically encountered in licensing reviews for conventional nuclear plants, the NRC told POWER that open items are an expected part of draft safety evaluations, particularly for complex topics requiring additional analysis before final technical decisions. “The TerraPower application used the Licensing Modernization Project approach, which means some topics can apply to several review areas. When those topics are resolved, multiple parts of the evaluation will be addressed simultaneously. Issues such as materials qualification and PRA documentation have been open items in the past,” agency spokesperson Scott Burnell said.

The NRC noted the early draft evaluation stems from the agency’s extensive pre-application discussions and ongoing technical exchanges with TerraPower. Burnell added that the agency expects that lessons learned during this review will “lead to efficiency improvements down the road, whether for additional TerraPower applications or for other vendor submissions. For example, this continuous improvement effort bore significant results in completing review of the second Kairos construction permit application several months faster than the first Kairos review,” he said.

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

Editor’s Note: This story is being actively updated. We encourage you to revisit this article or check our website for the latest updates.

Geothermal Energy Storage: The Clean Power Solution You Haven’t Heard Of

February 24, 2025
Jeff Prescott
Business district heating Energy Storage Full Coverage Geothermal geothermal energy hot dry rock International News Plant Design Power POWER Podcasts Renewables Research and Development Sage Geosystems Sustainability The POWER Podcast No Comments

Geothermal energy has been utilized by humans for millennia. While the first-ever use may be a mystery, we do know the Romans tapped into it in the first century for hot baths at Aquae Sulis (modern-day Bath, England). Since then, many other people and cultures have found ways to use the Earth’s underground heat to their benefit.

Geothermal resources were used for district heating in France as far back as 1332. In 1904, Larderello, Italy, was home to the world’s first experiment in geothermal electricity generation, when five lightbulbs were lit. By 1913, the first commercial geothermal power plant was built there, which expanded to power the local railway system and nearby villages.

However, one perhaps lesser-known geothermal concept revolves around energy storage. “It’s very much like pumped-storage hydropower, where you pump a lake up a mountain, but instead of going up a mountain, we’re putting that lake deep in the earth,” Cindy Taff, CEO of Sage Geosystems, explained as a guest on The POWER Podcast.

Sage Geosystems’ technology utilizes knowledge gleaned from the oil and gas industry, where Taff spent more than 35 years as a Shell employee. Like her, most of Sage’s team previously worked in the oil and gas industry. Today, the Houston, Texas–based company is working to advance three product lines: baseload power generation, district heating, and energy storage. The same subsurface technology platform is used for all three.

“What we do is we drill a well. We’re targeting a very low-permeability formation, which is the opposite of what oil and gas is looking for, and quite frankly, it’s the opposite of what most geothermal technologies are looking for. That low permeability then allows you to place a fracture in that formation, and then operate that fracture like a balloon or like your lungs,” Taff explained. “When the demand is low, we use electricity to power an electric pump. We pump water into the fracture. We balloon that fracture open and store the water under pressure until a time of day that power demand peaks. Then, you open a valve at surface. That fracture is naturally going to close. It drives the water to surface. You put it through a Pelton turbine, which looks like a kid’s pinwheel. You spin the turbine, which spins the generator, and you generate electricity.”

Unlike more traditional geothermal power generation systems that use hot water or steam extracted from underground geothermal reservoirs, Sage’s design uses what’s known as hot dry rock technology. To reach hot dry rock, drillers may have to go deeper to find desired formations, but these formations are much more common and less difficult to identify, which greatly reduces exploration risks.

Taff said traditional geothermal energy developers face difficulties because they need to find three things underground: heat, water, and high-permeability formations. “The challenge is the exploration risk, or in other words, finding the resource where you’ve got the heat, the large body of water deep in the earth, as well as the permeability,” she said. “In hot dry rock geothermal, which is what we’re targeting, you’re looking only for that heat. We want a low-permeability formation, but again, that’s very prevalent.”

When it comes to geothermal energy storage, the needed geologic formations exist just about everywhere in the continental U.S., including in the Northeast where the rock is a lot older and the heat is a lot deeper. “Once you get below about 5,000 feet, low-permeability formations are going to be prevalent for storage,” said Taff. “We’re wanting the surface temperature of the water to be less than 100 degrees C, so we don’t want to drill too deep where we’re getting too hot of water to surface.”

For district heating and power generation, on the other hand, Sage’s process requires both heat and pressure. “So, you’re going to have to drill deep enough to get those minimum temperatures that you need, and again, for geothermal, we’re looking for 150, 160 degrees minimum formation temperature. So, that limits you to where those hot spots are,” said Taff. She noted that geothermal energy could be used for district heating and power generation across about 35% to 40% of the lower 48 states.

Notably, the oil and gas industry has the know-how and experience to support geothermal well drilling today. “We’re using drilling rigs just like oil and gas. We’re using completion techniques such as fracturing—a little bit different from oil and gas because we use something called gravity fracking, but the equipment, the people, the skills, they’re pretty much a direct overlay to what we’re doing. Instead of drilling, though, for hydrocarbons, we’re drilling for heat,” said Taff.

Sage Geosystems completed a full-scale commercial energy storage pilot project and released findings in September 2023. The results show the company’s energy storage technology can provide power at a cost that is lower than lithium-ion battery storage and traditional pumped-storage hydro, and is also competitive with natural gas peaker plants.

The demonstration system reportedly produced 200 kW for more than 18 hours (long-duration) and 1 MW for 30 minutes (load-following), limited only by the small-diameter rental surface equipment piping. Measured subsurface system efficiencies were between 88% and 94%, with an estimated round-trip efficiency of 70% to 75%. Measured fluid losses were less than 2%, decreasing to 1% by the end of the five-week test period. The pilot demonstrated the ability to generate 2 MW to 3 MW net output in a single well.

Sage is now in the process of commissioning its first commercial energy storage project in Texas. “We’re testing the piping, and we’re function testing the generator and the Pelton turbine, so we’ll be operating that facility here in the next few weeks,” Taff said. Meanwhile, the company has also signed an agreement with the California Resources Corporation to establish a collaborative framework for pursuing commercial projects and joint funding opportunities related to subsurface energy storage and geothermal power generation in California. It also has ongoing district heating projects in Lithuania and Romania, and Taff said the U.S. Department of Defense has shown a lot of interest in the company’s geothermal technology. Additionally, Meta signed a contract for a 150-MW geothermal power generation system to supply one of its data centers.

To bring costs down even further, Taff said scale is needed. She suggested Sage Geosystems was only a few years away from scaling commercially. “I think there’s a lot of tailwinds that are helping us get there and helping us get there faster.”

To hear the full interview with Taff, which includes more discussion about Sage’s technology, progress on projects, how the oil and gas industry fits with the geothermal sector, government policies and incentives that are helping advance the geothermal industry, and much more, listen to The POWER Podcast. Click on the SoundCloud player below to listen in your browser now or use the following links to reach the show page on your favorite podcast platform:

For more power podcasts, visit The POWER Podcast archives.

—Aaron Larson is POWER’s executive editor (@AaronL_Power, @POWERmagazine).

The Evolving State of Power Plant O&M

February 23, 2025
Jeff Prescott
asset management Business Digital Transformation electrification energy infrastructure Energy Security Full Coverage grid modernization News O&M operations and maintenance Power power grid reliability power plant efficiency predictive maintenance renewable energy O&M Safety Supply Chains Technology Trends Workforce No Comments

As power plants confront aging infrastructure, surging demand, and the sweeping changes of rapid electrification, operations and maintenance (O&M) are being redefined to tackle unprecedented challenges and seize new opportunities.

In December 2025, the North American Electric Reliability Corporation (NERC), the region’s designated electric reliability organization, issued a sobering assessment of the power sector’s outlook for the next decade. More than half of North America may be at risk of electricity shortages, it warned. The scenario is exacerbated by the accelerated retirements of 78 GW of aging, fossil-fueled capacity—with an additional 37 GW announced but not yet confirmed—and sluggish progress on new resource additions. Compounding the challenge, power demand is projected to soar by 15% over the next decade, driven by rapid electrification, industrial growth, and the increasing energy needs of the data-driven economy.

In this context, the region’s existing fleet will play an outsized role, underscoring a role for their sound operations and maintenance (O&M). However, NERC also flagged forced outages as a critical and growing concern for the power sector, noting that unplanned outages caused by equipment failures, insufficient maintenance, and resource shortfalls pose significant reliability risks, most prominently during extreme weather events. Without robust O&M practices, these issues could further undermine the grid’s ability to meet rising demand, particularly as winter peaks begin to outpace summer peaks. That has exposed new vulnerabilities in resource adequacy planning, it said.

But as experts told POWER, the realm of O&M is itself rapidly evolving to address new complexities and expectations introduced by the rapid transformation. As IHI Power Solutions Director of Business Development Doug Machon notes, O&M emerged historically as a straightforward business function managed internally by utilities operating within regulated monopolies. The realm began a shift in the 1990s, as competition, introduced by electricity deregulation, ushered in third-party O&M services that offered basic maintenance, compliance support, and operational oversight. Today’s landscape adds a growing involvement from private equity investors, a decline in long-term power purchase agreements, and the rise of diversified energy portfolios—including renewables, distributed energy resources (DERs), and hybrid configurations.

No longer limited to routine tasks, modern O&M necessitates “a higher level of expertise and innovation in plant operations,” says Machon. The significant shift has catalyzed “the development of comprehensive O&M strategies designed to maximize efficiency, reliability, and profitability in an ever-changing energy landscape.” Providers today are expected to integrate advanced technologies, foster flexible plant cultures, and navigate stringent regulatory landscapes, he notes. Essentially, O&M today functions both as a critical lever for optimizing performance and enabling grid reliability in an increasingly dynamic energy environment, but it must also simultaneously mitigate risks and seize opportunities, he says.

Tackling New O&M Challenges

According to Ricardo Guerrero, general manager for Global O&M at GE Vernova, O&M advancement varies by region. “It’s different in every part of the world, but I would say the main factor that is affecting O&M services at this moment is the penetration of renewables,” he says. Plunging costs for renewables have ushered in new operational demands for traditional thermal power plants, including combined cycle gas turbine (CCGT) power plants, which were historically designed as baseload workhorses. “Cycling is a big issue,” Guerrero acknowledges. “Cycling is associated with how you are going to react, how you are going to accommodate your team, how you are going to accommodate your strategy, your planning—everything associated to O&M services—to be really productive, take care of cost, and be efficient.”

Cost pressures amid inflation and market demand further compound these challenges. Power sector O&M costs typically fall into fixed costs and variable costs. Fixed costs cover consistent expenses like routine maintenance, staff salaries, and long-term equipment contracts, while variable costs fluctuate based on fuel prices, material needs, and unexpected repairs. Over the past five years, cost fluctuations have hinged emphatically on rising material costs for critical resources such as steel, copper, and silicon, with particular implications for aging thermal power plants that require frequent and costly repairs.

Table 1. A December 2023 U.S. Energy Information Administration (EIA) cost and performance survey conducted by Sargent & Lundy summarizes costs for most technologies, including overnight capital cost information, fixed operating and maintenance (O&M) costs, and variable non-fuel O&M costs. Notes: USC = ultrasupercritical; CTs = combustion turbines; CC = combined cycle; SS = single shaft; BFB = bubbling fluidized bed; MWAC = megawatt alternating current; WTG = wind turbine generator; BESS = battery energy storage system. Source: EIA, Capital Cost and Performance Characteristic Estimates for Utility Scale Electric Power Generating Technologies, January 2024.

Renewable O&M costs, while generally lower than those of thermal power plants, have been steadily decreasing due to technological advances, economies of scale, and experience-driven efficiencies. However, they remain sensitive to material price volatility and the growing demand for specialized maintenance services. Offshore wind, in particular, faces higher O&M costs compared to onshore wind, driven by logistical challenges, harsher environmental conditions, and the need for specialized vessels and remote monitoring systems. Meanwhile, costs for advanced technologies such as biomass and small modular reactors remain comparatively high. A cost and performance analysis conducted by engineering firm Sargent & Lundy compared 19 different technologies based on their capital and O&M costs (Table 1). Even as these emerging technologies promise operational efficiencies and decarbonization benefits over time, their high upfront investments and significant ongoing O&M expenses can pose serious feasibility challenges.

Enduring the Vast Realm of Policy and Regulatory Uncertainties

Still, the current power landscape is compelling more companies to adopt new technologies and approaches. A significant factor has been compliance with the evolving patchwork of government mandates, including regulations and incentives increasingly focused on accelerated decarbonization. The U.S. Environmental Protection Agency’s (EPA’s) April 2025–finalized Carbon Pollution Standards mandate carbon capture and sequestration (CCS) for existing coal units and new baseload combustion turbines, adding to rules regulating nitrogen oxides, mercury, effluent, and coal ash. Regional decarbonization differences and overlapping state-level policies are, meanwhile, creating additional complexity, driving operators to adopt tailored strategies to meet diverse compliance requirements.

Beyond emissions, regulations now also emphasize grid stability and reliability, compelling conventional generators to provide ancillary services such as fast frequency response and inertia. The need for resilience has also generally spurred mandates that require plants to bolster infrastructure to withstand extreme heat and cold events, floods, and droughts. Cybersecurity is another growing focus, with federal directives requiring power plants to implement stricter digital protections and incident reporting protocols.

“You must adapt to the market. If you don’t react, if you don’t change, if you don’t adjust yourself to the new conditions, you’re going to disappear,” notes GE Vernova’s Guerrero. GE Vernova’s approach has been to prepare customers for these transitions, including tailored maintenance strategies. “We take into account the specific operational stresses caused by renewables integration, ensuring that even older assets comply with regulatory thresholds while optimizing performance,” he explains.

Siemens Energy, a global provider of power technology, solutions, and services, shares a similar outlook. “Our O&M service is designed to manage and maintain various types of technology infrastructure or equipment. This approach is especially beneficial in diverse and complex operational settings such as carbon capture, where multiple types of technology coexist,” says Andrew Robson, Siemens Energy’s technical expert for O&M Solutions.

Best Practices for Maintenance in the Evolving Power World

While power plant maintenance is a cornerstone of reliable power generation, designing and maintaining an effective program will require careful consideration of modern challenges and strategies. Engineers at infrastructure solutions firm Gannett Fleming offer some pointers.

Understand Your Assets. Develop a detailed asset register to categorize and document critical assets, including electrical, mechanical, and civil infrastructure. Involve multidisciplinary experts to ensure a comprehensive understanding of maintenance needs.

Develop a Maintenance Strategy. Balance reactive, preventive, and predictive maintenance to address immediate needs while minimizing future risks. Document the rationale for each maintenance task based on regulatory requirements, manufacturer guidance, and risk analysis.

Leverage Technology. Invest in a computerized maintenance management system (CMMS) like Maximo or SAP CMMS to streamline scheduling, documentation, and data analysis, ensuring efficient resource allocation.

Stay Agile. Avoid static programs. Continuously assess and adapt maintenance strategies to reflect advancements in technology, changes in asset conditions, and best practices.

Prioritize Tasks. Prevent over-commitment by ranking maintenance activities based on risk to ensure critical tasks are executed effectively.

Address Challenges Holistically. Be wary of knee-jerk reactions to failures and aim for balanced solutions through root cause analysis and measured troubleshooting.

Foster Collaboration. Streamline decision-making by clearly defining roles while incorporating input from stakeholders to maintain agility in program updates.

“In the next decade, Siemens Energy will continue to offer expert O&M services to manage customer reliability risks, enhance efficiency, and centralize skills for consistent and reliable service supported by data-driven digital technologies,” Robson adds. While the need to decarbonize conventional power generation affects all utilities and is not specific to O&M, the company’s services “ensure that these technologies operate reliably and efficiently, contributing directly to meeting decarbonization goals,” he explains. Additionally, he underscores broader sustainability benefits, particularly through the use of a global network of remote operations and control centers. “Especially during COVID, it became clear that it is not always necessary to fly specialists around the world, but that a lot can be done remotely,” he says (see sidebar “Best Practices for Maintenance in the Evolving Power World”).

Solving the Workforce Puzzle

For now, experts agree the most urgent challenge facing the power sector is the shortage of skilled personnel. “O&M is all about people,” says Guerrero. “People tend to believe that in the future, power plants will be operated completely by robots, but we are really far away from that.” A key issue is that the workforce, traditionally the backbone of power plant operations, is aging, and with that comes the loss of decades of invaluable experience. “At the same time, we’re finding it increasingly difficult to attract younger talent, who are often drawn to tech-savvy industries like software and artificial intelligence [AI] rather than traditional fields like ours. It’s a problem we cannot afford to ignore because, without skilled workers, even the most advanced plants won’t function,” he says. To address these challenges, Guerrero explains that GE Vernova has developed structured knowledge-capture systems, including detailed playbooks created during contract mobilizations. “These are comprehensive guides that ensure when experienced team members retire or move on, their expertise doesn’t leave with them,” he says.

At the same time, GE Vernova, driven by its “lean” business philosophy, has already begun transitioning from traditional reliability-based maintenance approaches to more proactive, data-driven design-making enabled by AI and analytics. Guerrero said the company has developed autonomous robot technology capable of conducting inspections and identifying issues that human workers may miss. Demonstrating these technologies carries operational benefits, but a key intent is to transform the perception of O&M, positioning it as innovative, future-focused, and dynamic—attributes that could be attractive to a younger workforce, he says.

1. Completed in early 2025, the Leipheim Power Plant in Bavaria, Germany, is a cutting-edge gas turbine facility developed by Siemens Energy and German energy giant LEAG to bolster grid stability during renewable energy shortfalls. The plant, capable of ramping up remotely within 30 minutes to deliver 300 MW of power, is operated entirely from Siemens Energy’s ISO-certified Remote O&M Support Center in Erlangen. Courtesy: Stefan Hobmaier/Siemens Energy

Robson echoes Guerrero’s concerns. “Even utilities with extensive experience in power plant operation and maintenance are now seeking our O&M expertise due to the skilled workforce shortage,” he notes. Siemens Energy’s approach has been to double down on technology. “Remote services are key to maintaining reliable operation and efficient maintenance,” says Robson, citing Siemens Energy’s 72-hour unmanned operation of the 300-MW Leipheim Power Plant in Germany (Figure 1). “Our remote monitoring centers handle routine monitoring and data analysis, freeing up experts for tasks that cannot yet be fully automated.”

According to Emily Obenauer, global director of Product Marketing at SiteTracker—a software-as-a-service platform that provides end-to-end asset lifecycle management—emerging tools are also set to play a transformative role in streamlining O&M operations with tangible workforce benefits. “Tools like ours are also shown to increase the satisfaction and increase the effectiveness of those workers out in the field because we’re getting so clear on what needs to be done and validating that that work has been done correctly the first time around,” she said.

Shoring Up Supply Chains

While workforce challenges have long afflicted the sector, more recent global supply disruptions are posing new concerns, prompting companies to reassess the resilience of their O&M operations. Siemens Energy’s Robson notes that, while temporary bottlenecks for parts and consumables remain a concern, “The shortage of people is, so to speak, the biggest bottleneck in the supply chain,” he says. He explains that most original equipment manufacturers (OEMs) proactively approach supply chain challenges to mitigate risks, leveraging global networks for flexibility. “We can access stock that was originally planned for other projects in the longer term. Additionally, close monitoring allows for the identification of required parts at an early stage as part of predictive maintenance,” he says.

2. To bolster its supply chain and prepare for increasing demand for its heavy-duty gas turbines and upgrades globally, GE Vernova moved in November 2025 to acquire Woodward Inc.’s combustion parts business in Greenville, South Carolina. This image shows a 7HA.03 gas turbine at GE Vernova’s own facility in Greenville, where it manufactures and tests gas turbines to provide global engineering support and other activities. Courtesy: GE Vernova

GE Vernova’s strategy is similar, entailing a proactive, collaborative approach with its customers (Figure 2). The company closely monitors its customers’ equipment and provides advance warning of potential failures. In addition, Guerrero says it helps customers pre-position critical spare parts to minimize downtime in the event of an issue. For example, when GE Vernova identified that the generators at a 20-year-old power plant in Taiwan were nearing the end of their life, it advised the customer to purchase a spare stator and rotor in advance. Two years later, the rotor failed, but because the spare part was already on-site, GE Vernova was able to quickly replace the rotor, getting the customer back online in just seven days, he says.

The Rise of Third-Party O&M Services

In another important trend, given modern complexities and evolving risks in the power sector, many utilities and power companies are increasingly turning to value-driven partnerships, often through third-party O&M service contracts. These partnerships encompass project management, robust training programs, detailed plant assessments, and the adoption of tailored best practices to optimize operations. Many are designed to leverage economies of scale and advanced remote operations, providing utilities with cost efficiencies and enhanced reliability in managing diverse energy assets.

“For many plant owners, O&M is no longer a core focus,” Guerrero explains. “Their priority is on generating and selling energy, which opens the door for third-party providers like us to step in with specialized expertise. But it’s not just about taking over operations—it’s about adding value. By leveraging performance-based contracts and advanced technologies, we focus on aligning our services with plant owners’ goals for reliability, efficiency, and profitability.” Guerrero notes that performance-based contracts are increasingly becoming a defining feature of third-party O&M services because they play a pivotal role in aligning incentives with plant reliability, availability, and efficiency. The contracts ensure accountability by incorporating measurable metrics, such as performance guarantees, and often include penalties for underperformance as well as rewards for exceeding targets. “This model ensures that everyone is focused on the same goal: maximizing the plant’s performance,” he says.

Global renewable energy developer Invenergy— a company known for its extensive portfolio of wind, solar, and storage projects—also highlighted the value proposition. The company says it approaches O&M services with an “owner’s mindset,” a philosophy that ensures top-tier maintenance practices and builds trust within their communities. “In addition to prioritizing safety, Invenergy Services’ other O&M pillars deliver benefits to customers through innovation, flexibility, and cost savings,” it says.

O&M’s Future: Tech and Sustainability

According to experts, the future of O&M in the power sector will be shaped by two transformative forces: technological innovation and the global push for sustainability. Already, as power generation grows more complex, modern O&M practices are increasingly integrating cutting-edge technologies like predictive analytics, autonomous systems, and maintenance strategies. “The future of operations and maintenance will heavily depend on integrating AI with digital tools to analyze data in real-time. This allows us to predict issues before they occur, saving costs and improving asset performance across the board,” says Guerrero.

Obenauer echoes this point. “We know that the future lies in digital transformation, and AI is a major focus. By applying AI to fieldwork and O&M processes, we’re already testing how to enhance efficiency and reliability while aligning with the workforce and industry needs.” AI-driven solutions also promise to unlock new opportunities in lifecycle management, she notes. “By centralizing asset data, companies can use AI to optimize resource allocation and focus on long-term asset health while navigating complex operational challenges.”

3. Operational since June 2023, the Kela PV Plant Phase 1, located in Sichuan Province, China, stands as one of the world’s largest hydro-solar hybrid power plants, combining 1 GW of solar capacity with the 3 GW Lianghekou Hydropower Plant. The site exemplifies advanced O&M practices in a challenging environment. Given that it is situated at an altitude of 4,600 meters, the plant endures extreme cold and high winds. Using a smart O&M platform with features like remote monitoring, automated fault detection, and real-time diagnostics, the plant minimizes manual intervention and ensures reliability. Courtesy: Huawei

On the other hand, sustainability will support the general charge toward cleaner energy sources, such as accommodating new technologies and hybrid configurations (Figure 3). Companies are exploring how to integrate emerging solutions such as hydrogen retrofits, thermal energy storage, and batteries into power plants, all while keeping costs low, maintaining reliability, and minimizing environmental impact.

As Guerrero stresses, a key takeaway is that O&M will need to be flexible and responsive rather than rigid. “You can navigate the sea as a cruise ship, or you can be a motorbike on the beach moving quick, and that’s the idea, that’s what we are doing,” he explains. Ultimately, proactivity will be necessary for nimble adaptation to keep pace with the changing landscape, he says.

—Sonal Patel is a POWER senior editor (@sonalcpatel, @POWERmagazine).

Correction (Feb. 18, 2025): This article previously misstated that the Sargent & Lundy analysis examined hydrogen retrofits. A clarification in this version refines the discussion of cost comparisons for advanced technologies. The Table 1 citation has also been updated to January 2024 instead of 2025, as previously cited.

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