Category: Engineering

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

Battery storage Business coal coal power data centers Engineering Environmental environmental compliance epc projects Full Coverage Gas gas power Kentucky Utilities KU LG&E Markets News Power Power Demand Technology Trends No Comments

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).

GE Vernova, AWS Address Energy Demand With Collaboration Agreement

March 4, 2025

Jeff Prescott

Amazon Web Services Business cloud data centers electrification energy demand Engineering GE Vernova News Power Power Demand Research and Development software Technology No Comments

GE Vernova and Amazon Web Services announced the companies have signed a strategic framework agreement aimed at supporting AWS’s data center scaling. The groups on March 4 said they would collaborate to address increasing global energy demand, advance grid security and reliability, and decarbonize electric power systems.

GE Vernova as part of the deal will provide AWS with new offerings across a broad scope of solutions to electrify and decarbonize data centers across North America, Europe, and Asia. Financial terms of the agreement were not disclosed. The companies in a news release outlined the details, which include:

Electrification Systems: GE Vernova will continue to provide AWS with turnkey substation solutions to enable connectivity of AWS data centers to the grid, including expansion of major electrical equipment, project management, and construction support, across multiple sites globally. AWS and GE Vernova engineering teams will continue to work together to optimize data center substation design and delivery.

Renewables: GE Vernova will collaborate with AWS to enhance the path for commercializing onshore wind development projects.

Power Generation, Innovation and Services: GE Vernova and AWS will also explore additional opportunities for GE Vernova to provide power generation equipment and services to AWS as well as work with GE Vernova’s accelerator businesses—Advanced Research, Consulting Services, and Financial Services—to advance energy transition innovation, research, project development, and financing.

Pablo Koziner, chief commercial officer of GE Vernova said, “We are excited to work in collaboration with AWS as they advance their computing capabilities and data center capacity. We believe that GE Vernova is well positioned through its broad portfolio of energy products and services to help AWS obtain reliable, cost effective, and more sustainable electricity for its data centers in support of their growth objectives. We appreciate the opportunity to work strategically with a company that embraces innovative solutions and values strong collaboration.”

AWS will provide GE Vernova cloud services solutions to advance its cloud migration and digital innovation efforts, including through generative AI. AWS’s cutting-edge capabilities will support GE Vernova’s continued transformation as a standalone, public company as it enhances its systems and processes and further embeds sustainability and innovation into its core operations. The extended collaboration will introduce new potential technologies and cloud services, including AWS High Performance Computing.

The collaboration will also help GE Vernova accelerate development cycles and optimize operations for advanced digital technology solutions through large computational power and cloud elasticity. AWS and GE Vernova will further work together to identify opportunities to accelerate GE Vernova’s operational goals, leveraging AWS technologies in artificial intelligence, big data, and data analytics.

Additionally, AWS will continue to collaborate with GE Vernova’s Electrification Software business to help support AWS Cloud deployments of software for the electric grid, power generation, and manufacturing industries.

“Through this expanded collaboration with GE Vernova, we’ll be able to accelerate data and energy efficiencies, driving reliable and more sustainable operations,” said Howard Gefen, general manager, energy & utilities, for AWS. “Our shared goals of addressing increased global energy demand, advancing grid security, and decarbonizing electric power systems will help our customers across the globe.”

GE Vernova previously announced agreements to collaborate with AWS to help support cloud deployments of software to benefit electric utilities, energy organizations, manufacturers, and other industrial businesses. Through these collaboration arrangements, several of GE Vernova’s software solutions—including various applications within its GridOS orchestration software portfolio, as well as Asset Performance Management—are hosted in the AWS Cloud.

—POWER edited this content, which was contributed by GE Vernova’s communications team.

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.

Software, Hardware, Innovation All Needed to Upgrade the Power Grid

February 24, 2025

Jeff Prescott

AspenTech Business Cybersecurity Engineering hardware Instrumentation & Controls News O&M Power power grid reliability Research and Development Safety software T&D Technology No Comments

Enhancing the transmission and distribution of electricity is a priority to ensure a reliable and resilient power supply, as demand increases and grid challenges mount.

Providing more electricity to meet growing global demand for power has put a spotlight not only on adding more generation to the grid, primarily through construction of new power plants, but on improvements to the grid itself. Enhancements to support power grid reliability include investments for a variety of technologies, such as battery energy storage systems (BESS), advanced transmission lines, smart grid infrastructure, and distributed generation. Upgrades also focus on improved grid monitoring and control systems that allow for better and faster response to fluctuations in demand and disruptions caused by weather, equipment, or other issues.

“Needed enhancements span across condition monitoring, advanced data analytics, fire mitigation, and improved system control mechanisms,” said John Russell, senior director, Solution Consulting at AspenTech, a provider of software and services for the process industries. “Reliability in these systems is crucial not only for preventing downtime but also for ensuring that power is consistently delivered to consumers with minimal disruptions. Specifically, key areas for enhancement include the implementation of condition-based maintenance, improved data collection with smart meters, AI [artificial intelligence]-powered asset management, and advanced control technologies for both transmission and generation systems. By integrating modern technologies, these systems can proactively address failures, optimize performance, and respond to real-time conditions.”

“Reliability is central to the modern power grid, especially as we integrate more renewables and electrify transportation and heating. Much work has been done in generation and distribution, driven by smarter hardware, predictive software, and data analytics,” said Brandon Young, CEO at Payless Power, a Texas-based electricity group. “On the generation side, predictive maintenance technologies become game-changers. IoT [Internet of Things] sensors and AI are monitoring equipment like turbines and transformers in real time to pinpoint potential failures before they occur. That way, downtime is kept to a minimum, and power generation stays efficient.”

Utilities and grid operators are studying a variety of ways to improve the reliability of power generation and delivery, with data at the heart of much of the research.

Want to learn more about innovation that supports reliability and resiliency of the power grid? Read this POWER Interview with professionals from Engineering Design & Testing Corp., a forensic engineering group that works with a range of clients in the power industry. The company offers technical expertise to solve technical and often complex problems associated with power generation and delivery.

“Reliability enhancements should be approached as a comprehensive, multi-pronged strategy that addresses design concerns and utilizes new and emerging technologies for improved data analytics,” said Michael Bennett, chief transformation officer at Powin, a battery energy storage company. “Up front, suppliers need to design and engineer components with reliability as a core principle. This includes using advanced materials, robust designs, and high-quality manufacturing processes.”

Bennett added, “Ensuring transmission, distribution, and generation assets are equipped with IoT sensors for real-time data collection, monitoring, and reporting capabilities has become a core focus over the past few years as well. These sensors provide operators with actionable insights into system performance and potential issues, allowing them to leverage both cloud and on-premise data to uncover complex insights, correlations, and predictions.”

Thomas L. Keefe, vice chair and U.S. Power, Utilities & Renewables Sector leader for Deloitte, said, “Increasing visibility and control through advanced grid technologies” is a major part of increasing grid reliability. “Sensors embedded throughout the network, including smart meters, automated control systems, and advanced monitoring tools, can provide real-time data on energy flow, equipment health, and grid stability,” said Keefe. “Analyzing sensor data can allow operators to anticipate equipment failures before they happen, preventing outages, enhancing the utilization of existing resources, and ultimately increasing grid reliability.”

Efficiency a Key Part of Upgrades

Upgrades to transmission infrastructure (Figure 1) are just part of the work being done to improve power grids. The need for maintenance, particularly during a period of transition to digitization of energy systems, is evolving as well.

1. Power grids across the U.S. and throughout the world are in need of upgrades to handle increased loads. Those enhancements also are needed to help integrate more renewable energy resources into electricity transmission and distribution systems. Courtesy: Salvatore Ventura / StockSnap

“There are several proactive maintenance solutions to improve grid reliability, such as implementing distributed intelligence [DI] systems for real-time monitoring and diagnostics,” said Matt Smith, who leads the global business and product strategy for the grid management business at Itron, a global group helping utilities develop innovative solutions for their operations. “Additionally, predictive analytics and edge intelligence can identify trouble spots below the substation, enabling utilities to automate fault isolation and repair processes, reducing the need for manual intervention, which leads to faster recovery times and improved grid stability. This integrated approach allows for a more efficient, resilient power grid, especially during times of increased demand or extreme weather events.”

Actalent is a global company specializing in engineering and sciences services, along with talent solutions. Amanda Neuenfeldt, an energy management systems modeling lead engineer with the group, provided POWER with insight into emerging technologies that support the power grid. Learn more in this POWER Interview.

Smith listed what he called “key enhancements” to improve the overall reliability of electricity transmission and distribution, including decentralizing grids.

“Traditional centralized grids are vulnerable to cascading failures during extreme weather events, like major hurricanes and heatwaves, which are becoming more prevalent. Switching to a decentralized model, which includes incorporating distributed generation resources [such as renewables] closer to demand points, improves resilience,” said Smith. The Itron executive also noted the importance of leveraging intelligent grid edge solutions. “Integrating distributed intelligence into utility systems enables grid sectionalization, allowing power to be rerouted automatically. This reduces outages by leveraging real-time data to detect anomalies more efficiently than manual inspections.”

The use of distributed generation is helping provide additional power apart from centralized power plants. Advanced metering infrastructure is helping monitor power usage in real-time, and supporting demand response programs. And then there are efforts to combat the problems associated with keeping the lights out during extreme weather events.

“At the top of the list for transmission and distribution is grid hardening and modernization,” said Young. “Utilities are replacing aging infrastructure with weather-resilient materials, and deploying smart grid technologies such as automated reclosers, which isolate faults and reroute power almost instantly, reducing outages. The growth in smaller energy sources, such as rooftop solar and batteries, has been supported by distributed energy resource management systems [DERMS] that aggregate them to provide stability to the grid in times of peaks or emergencies. Future technologies, like grid-forming inverters, will stabilize grids with high renewable penetration, controlling voltage and frequency independently and acting as virtual power plants.”

Itron’s Smith said, “EV [electric vehicle] charging stations are an increasingly valuable resource that can be quickly repurposed before and during grid failures to provide grid services and backup power, respectively. Additionally, EV batteries within vehicles, specifically within larger vehicles like buses, offer a robust source of energy storage. These batteries can be tapped during outages to enhance grid resilience and maintain power for critical operations, making them an essential component in modernizing grid infrastructure to cope with outages.”

Deloitte’s Keefe said that reinforcing physical infrastructure is another important step. “Strengthening, upgrading, and hardening key components, such as power lines, substations, and transformers, can not only help handle higher loads but also reduce transmission losses and improve resiliency and energy delivery efficiency,” said Keefe. “A few states have signed bills mandating that utilities consider grid-enhancing technologies as a shorter-term solution in their IRPs [integrated resource plans]. Replacing outdated transformers with high-efficiency models can cut energy consumption by up to 12%, further boosting grid efficiency.”

Keefe added, “Deploying grid-enhancing technologies and advanced conductors to add capacity and flexibility to the existing transmission system [improves] transmission reliability. These technologies offer a cost-effective way to expand capacity compared to rebuilding transmission lines. Upgrading to high-efficiency conductors can minimize transmission line losses by 10% to 20%.”

Keefe also noted how model predictive control (MPC) technology can support reliability. “MPC uses a mathematical model to predict future system behavior within a set timeframe. It is popular in power electronics for managing constraints, multiple inputs and outputs, and nonlinearities. Unlike other control methods, MPC explicitly considers system constraints and optimizes control actions over a prediction horizon. This results in better performance, lower energy consumption, and increased reliability in power electronic applications. In renewable energy systems like photovoltaic [PV] and wind energy, MPC can optimize power extraction and facilitate maximum power point tracking [MPPT]. It also coordinates multiple energy sources, storage devices, and loads to ensure optimal performance and reliability.”

Grid Projects

Jersey Central Power & Light (JCP&L), a subsidiary of FirstEnergy Corp., in December began construction on infrastructure upgrades designed to enhance electric reliability for customers in three Morris County communities in New Jersey (Figure 2). The work, scheduled to be completed in October of this year, is part of JCP&L’s New Jersey Reliability Improvement Project, which is an element of the company’s rate review settlement approved by the New Jersey Board of Public Utilities in February 2024. Equipment enhancements will take place along more than five miles of power lines in Chester, Washington, and Roxbury townships.

2. Upgrades to the power delivery system in Morris County, New Jersey, got underway in December 2024. The construction is part of Jersey Central Power & Light’s New Jersey Reliability Improvement Project. Courtesy: First Energy / Jersey Central Power & Light

Doug Mokoid, FirstEnergy’s president for New Jersey, in a statement said: “The upgrades we’re making under the New Jersey Reliability Improvement Project are part of our commitment to providing safe, reliable electric service for all our customers. These improvements, in particular, target areas where customers have experienced some of the most frequent outages in recent years.”

The New Jersey Reliability Improvement Project is a two-phase effort to enhance reliability for customers on high-priority lines selected based on historical outage data. The first phase, which includes at least $95 million in upgrades, is set to be completed over the next three years, according to FirstEnergy. The second phase, which includes longer-duration projects, is expected to be completed by year-end 2028.

The upgrades include replacing existing infrastructure with thicker, stronger wires and poles that can carry more electricity and provide more resiliency in storms. The work also includes upgrading fuses, and installing additional devices and reclosers that allow power to be rerouted to adjacent lines when an outage occurs, minimizing the number of impacted customers.

Several projects are underway or planned to build new high-capacity transmission lines to facilitate power transfer across long distances, often to move renewable energy resources from remote, rural areas to the grid. Advanced conductor materials are being used to reduce transmission losses. Smart grid tech is being deployed for dynamic load management, and battery storage is being installed along the grid (often at substations) to help with grid flexibility and balancing.

The U.S. Department of Energy (DOE) last year awarded $2.2 billion to eight electric transmission and microgrid projects across 18 states, with a goal of adding electricity delivery capacity and strengthening the grid against extreme weather. Jennifer Granholm, the Energy Secretary during the Biden administration, at the time said the money was part of a program to add 1,000 miles of transmission lines and 50,000 MW of electricity to the grid. Granholm at the time said, “and there’s much more to come,” although it’s not known how the Trump administration will approach funding for electricity transmission and distribution (T&D).

The DOE said $700 million would go to the North Plains Connector project, a high-voltage direct-current power line that would create the first large-scale grid connection between the Eastern and Western interconnections, the U.S. grid systems divided by the Rocky Mountains. Minnesota-based Allete Inc. and transmission builder Grid United are developing the project.

3. Deployment of renewable energy across the U.S. has been slowed by issues with integrating wind, solar, and other clean energy resources to the power grid. Courtesy: Shutterstock.

The Utah Office of Energy Development was awarded nearly $250 million to install 250 miles of advanced conductor cables, increasing line capacity to support delivery of 500 MW of renewable energy (Figure 3) across six states.

Another grant, for $30 million, was made to the New York Power Authority for its Clean Path New York project. That strategy is designed to deliver 1,300 MW of renewable energy from upstate and western New York to New York City, which the DOE said would help reduce reliance on coal- and natural gas–fired power generation.

Handling Increased Demand for Electricity

Technology innovations to improve power generation, transmission, and distribution have brought more complexity into power networks. That means utilities and grid operators are rethinking some of their earlier practices to adapt to a changing energy landscape.

Jon M. Williams, CEO of Viridi, a battery energy storage company, said, “The energy system is on the brink of a paradigm shift that will profoundly reshape energy transmission and distribution. After decades of relatively stable demand [no load growth], the grid must now manage an enormous demand increase resulting from industrial onshoring, the growth of data centers and AI, and, perhaps most significantly, the electrification of heat and transportation. Complexity has also been added as distributed generation resources, like rooftop solar, complicate system management. These antiquated 19th-century grids are decentralizing, and the transition must be accommodated.”

Williams told POWER: “The solution to this challenge will not be to redesign and rebuild the grid of the 19th century. Instead, we must use new advances that prioritize safety, reliability, and enhancing system level efficiencies while focusing investments on technologies that provide layers of benefit. There is no greater technology to benefit power grids as we electrify everything than intelligently managed distributed energy storage. Distributed storage can enhance the value and operability of on-site generation. With advanced connectivity, it can be leveraged as a ‘virtual power plant [VPP]’ to better enable host facility loads for grid support through constraints and failures in real time.

“Behind-the-meter distributed energy storage has the potential to improve resilience, support decarbonization, shave peaks, enhance value of behind-the-meter generating assets, enable utilities to pursue beneficial ‘non-wires’ alternatives, and avoid the massive costs that a replacement of the old grid would entail,” said Williams.

Utilities have developed programs to support a reliable power supply. The American Public Power Association (APPA) has a Reliable Public Power Provider, or RP3, program “that recognizes utilities that demonstrate high proficiency in reliability, safety, workforce development, and system improvement.” The group’s list includes utilities, both large and small, from across the U.S.

Said Young, “Real-world examples show the benefits: Florida Power & Light’s ‘Storm Secure’ program—undergrounding power lines and deployment of smart grid—has reduced outage durations after a hurricane like Irma. Similarly, Pacific Gas & Electric is now using AI to predict the risks of wildfires by analyzing weather, vegetation, and grid conditions in order to take action before disaster strikes.

“This brings, in short, today’s enhancements in reliability toward the goal of making the grid smarter and more resilient as AI and other power-hungry needs increase the demand for energy. Advanced software, durable hardware, and data-driven systems are revolutionizing how we manage and distribute electricity for future needs,” he said.

“The process of monitoring and setting up a system to proactively maintain assets to extend their lifecycle and prevent malfunctioning is also known as ‘asset lifecycle management (ALM)’,” said Terry Saunders, Worldwide Utilities and Industry leader at IBM. “As organizations continue to look for ways to conduct more efficient, cost-effective, and sustainable operations many are turning to ALM. For energy equipment specifically, ALM practices may include installing sensors and using cameras for immediate eyes on equipment to identify factors affecting performance, and using AI-infused software that recommends specific maintenance directed by the data. By approaching maintenance and operations management from a preventive, data-driven approach companies can ensure that their systems are performing optimally for longer, ultimately maximizing their return on investment.”

Tyler Lancaster, partner at Energize Capital, a group that invests in climate technology, including renewable energy, told POWER: “A big shift in the power sector has been moving away from cycle-based maintenance programs to data-driven, proactive maintenance programs. Some aspects can also be automated to drive further efficiency and reliability. This is true across every form of power infrastructure.

“For example, historically, utility poles were inspected on a cycle once every five to 10 years. Over time, utilities and their service providers have built up a large amount of data and information on common failure modes for utility poles,” said Lancaster. Increasingly, analytical models can be applied to estimate the probability of failure for each pole based on the type of wood, environmental factors like moisture, location, etc., and can tailor maintenance activities to inspect and repair higher risk poles sooner.

Lancaster said it’s difficult to standardize operations to improve reliability. “This is a key challenge for the power sector, as operations tend not to be ‘one-size-fits-all.’ Different grids, with different environmental factors and natural systems, with different power infrastructure configurations—generation mix, T&D system setup, consumption segmentation and load profile, etc.—require tailored operations to ensure reliability. Where operations can be standardized is through the use of modular and adaptable technologies which can be easily configured to the unique needs of a specific power plant or grid operator’s context.”

“Standardization can play an important role in power system reliability as it promotes consistency, predictability, and interoperability,” said Keefe. “It can help reduce human error, and improve communication and coordination—especially during emergencies, with faster response times, etc.”

Combating Failure

Working to eliminate grid failures, or at least mitigate their impacts, is a goal of those working with utilities and grid operators. That can involve gathering data, knowing how to interpret it, and also having systems in place to deal with issues as they arise.

“Reliability at the equipment or component level is driven by two key factors—probability of failure and impact of failure. Enhancements that address one or both these factors are key to improving reliability,” said Steve Morris, a managing director with FTI Consulting’s Construction, Projects & Assets practice. “Whether it’s a power plant or the grid, reducing the probability of failure comes down to maintaining the assets in good operating condition through preventive and condition-based maintenance. Reducing the impact of failure is reliant on having redundancy in the system so that the failure of a single asset or component doesn’t reduce plant or system performance.”

Morris said, “For a power plant or electric substation, this is typically achieved by having spare capacity that can be used if there is a failure. For example, instead of having one power transformer in a substation running at full capacity, you would have two running at 50% or less capacity. If one fails, you can switch the other with no impact on the system. For the transmission grid, in most cases, if a single transmission line fails, there is sufficient capacity to switch to another transmission line, which has spare capacity. For the distribution grid, redundancy is achieved by interconnecting circuits and having auto reclosers, which can automatically restore after a fault is cleared, and sectionalizers that can section off parts of the system to reduce the number of customers impacted by an outage.”

Sally Jacquemin, vice president and general manager, Power and Utilities at AspenTech, told POWER: “Redundancy plays a vital role in maintaining the reliability and stability of both power plants and power grids. As the energy landscape shifts toward greater integration of renewable sources like wind and solar, the variability of these resources increases the importance of backup systems. Redundant infrastructure, including reserve generation and microgrids, ensures that power continues to flow smoothly during both planned and unexpected disruptions, such as outages or system failures, minimizing the risk of blackouts.”

Jacquemin said, “Historically, utilities maintained excessive reserve generation to protect against worst-case scenarios, ensuring power availability in case of failure. Today, however, there is a balance between maintaining enough redundancy to prevent outages and avoiding over-investment in reserve capacity. Modern systems focus on understanding the critical threshold of necessary redundancy, ensuring operational efficiency while still providing reliability in the face of unexpected events like sudden generation loss or extreme weather conditions.”

Jacquemin added, “Microgrids and localized redundancy solutions are increasingly important as they allow certain areas to maintain power even when the larger grid is disrupted. Powered by local generation sources like solar or batteries, microgrids can operate independently, providing resilience during storms or grid failures. The integration of renewable energy further highlights the need for redundancy, as renewables introduce variability that requires additional backup systems, such as storage or traditional generation, to ensure a reliable and stable power supply.”

“Redundancy is most important for the transmission system as North American Electric Reliability Corporation [NERC] requires that the transmission system must be able to handle the failure of a single component without causing a significant outage,” said Morris. “Therefore, transmission lines and substations are designed with redundancy. Redundancy is less important for power plants as typically a single unit of a power plant only produces a small portion of the power on the grid. In addition, power grids are required to have reserve capacity to be able to handle unit unavailability, maintenance, and higher than normal demand. The distribution system is similar to power plants in that most equipment serves a small number of customers, so a failure has little impact on the overall grid. Therefore, there is little redundancy in the system, other than in substations.”

Morris listed several ways to enhance reliability of power generation and the transmission and distribution system. He noted that advanced distribution management systems can automatically detect faults, and also identify the impacts of anomalies. He also noted a distributed energy resource management system “monitors, optimizes, dispatches, and manages all types of distributed energy resources including black start for grid shutdowns. Dynamic line rating calculates real-time transmission capacity of a line to optimize capacity usage to reduce congestion.” Meanwhile, an “asset performance management system monitors real-time equipment condition to identify [any] need for maintenance or indicate increasing risk of failure.” Morris also noted what he called “non-intrusive inspection,” which can help operators “understand power plant equipment condition without taking it apart. [This] includes technologies such as ultrasonic, radiography, eddy current, magnetic particle, acoustic emission, dye penetrant, leak testing, vibration analysis, and thermography.”

Lancaster said there are programs that can be implemented to enable proactive replacement and/or restoration of older equipment—both software and hardware—in power plant and power grid systems. He referenced his earlier comments about power poles, and said, “Another example is for transformers. Transformers are a key piece of equipment for the electric transmission and distribution system. They convert high-voltage electricity down to the lower voltages, eventually to the 120V type that we commonly use in our homes and businesses.

“There are several methods that have emerged to predictively identify transformer failure through sensor technology and data science or machine learning techniques,” said Lancaster. “For example, sensors that measure the accumulation of dissolved gas particles in the oil contained within a transformer can prevent transformer failure before it causes broader damage to other power grid equipment nearby.”

Utilizing Digital Twins and Energy Storage

Ildi Telegrafi, a policy fellow at the Alliance for Innovation and Infrastructure, said digital twins—often used to study power generation equipment—can also be a vital part of understanding electricity transmission and distribution.

Cybersecurity and Grid Reliability

Shankar Somasundaram is CEO at Asimily, a risk management platform that secures Internet of Things (IoT) devices for healthcare, manufacturing, public sector, and other industries that depend on numerous connected devices. Somasundaram talked with POWER about how enhancements to support grid reliability also should address cybersecurity issues (Figure 4), especially with more digitization in power plants and along the transmission and distribution system.

4. Global and U.S. energy infrastructure, particularly the power grid, has become a major target for both physical attacks and cyber threats. Grid operators and utilities are responsible for protecting their systems from risk, with the federal government and national laboratories supporting those efforts as part of their mission to protect national and economic security. Courtesy: Asimily

“Cybersecurity has become an increasingly fundamental variable for power system reliability as utilities digitize operations and add more network-connected devices and equipment,” said Somasundaram. “As headlines in this industry continue to show, a more interconnected power infrastructure—particularly its operational technology [OT] systems that directly control physical equipment—means that cyber vulnerabilities can directly impact system reliability.

“In transmission and distribution systems, cybersecurity measures need to protect essential OT components like supervisory control and data acquisition [SCADA] systems, smart meters, and automated switches through authentication, encrypted communications, and continuous network monitoring,” said Somasundaram. “Power plants require additional protection for their digital control systems, including distributed control systems [DCS] and programmable logic controllers [PLCs]. This necessitates network segmentation, regular security patching, and strict access controls to prevent equipment damage or forced outages.”

Somasundaram told POWER, “Supply chain security and the human element are equally crucial for reliability. Utilities must verify the integrity of software updates and new internet-connected equipment while maintaining comprehensive training programs for personnel who operate and maintain OT systems. Building a culture of cybersecurity awareness cannot be glossed over.”

Somasundaram said as more automation enters maintenance programs, more vulnerabilities to cyberattacks are exposed. “From a cybersecurity perspective, every component in a power plant and the grid is potentially vulnerable if it has an access port. Historically, physical protection and maintenance have provided a strong defense. However, as network access and its many benefits are deployed more, this physical security is becoming less effective,” said Somasundaram. “Cybersecurity maintenance for power plants is like the price of democracy—it requires constant vigilance. This vigilance involves always detecting potential and current attacks. This requires processes backed by software that continually look for evidence of such weaknesses and attacks. When evidence is found, it’s important to act quickly to close security gaps or, in the worst-case scenario, terminate a successful attack.”

Somasundaram added, “Fortunately, much of this has been automated by the software industry. Implementing people and processes to leverage this technology effectively and act quickly, however, is not always in place. Ensuring this implementation is key to maintaining automated maintenance and reliability.”

“The clean energy transition is driving the energy industry toward a new dynamic with vast renewable energy resources that can supply a high volume of energy over the year but with high intermittency,” said Telegrafi, who is also an analyst for New York-based utility Con Edison. Telegrafi said the need for bidirectional power flow management, and the inclusion of energy storage onto the grid “to stabilize intermittency and flatten the peak,” means “the tools necessary to manage this continually changing dynamic are digital. Balancing an ever-increasing power dynamic that must satisfy inconsistent load with intermittent generation supported by storage components requires the creating of a digital twin of the grid.” Of course, cybersecurity must also be considered whenever digital technology is added to a system (see sidebar).

Telegrafi said the digital twin “models the components individually and the systemic constraints binding operation via mathematical formulas. These mathematical formulas allow for optimization of the dynamic from the current dynamic to the future clean energy equilibrium that industry establishes. The digital twin can be manipulated freely to add or remove components into the digital emulation of the grid’s dynamics, enabling ‘what if’ scenarios for application toward strategically planning investment and policy.” Telegrafi said Optit S.r.l., an optimization and solutions group, has been working on these projects in the U.S.

Powin’s Bennett also noted the importance of digital twins to “enable continuous monitoring, simulation, and optimization of power plant or grid equipment, providing a real-time view of asset health.” Bennett said having “virtual replicas of physical assets” is just one of “several components of an effective, automated maintenance program to ensure the reliability of power plants and grid.” He cited condition-based maintenance, or CBM, which enables “transitioning from predefined maintenance schedules to dynamic, condition-based programs that rely on real-time monitoring and performance data. SCADA [supervisory control and data acquisition] systems and IoT devices provide the necessary data for this approach.”

Bennett said predictive maintenance also is important. “Using AI and machine learning algorithms to analyze historical and real-time data from sensors, enabling the prediction of failures before they occur… [where] data sources can include environmental conditions, operating history, and current performance metrics,” he said. There is also automation, where “automating data correlation in the cloud allows predictive insights to be seamlessly integrated into control systems or maintenance scheduling tools. This reduces response time and ensures resources are allocated efficiently to address the highest-priority issues.” Inspections of power plant assets, and the power grid, using robotic systems and drones “can automate inspections of hard-to-reach areas, reducing the risk to personnel and minimizing downtime,” said Bennett.

FTI Consulting’s Morris said, “To enable proactive replacement/refurbishment of older equipment requires understanding several elements. First, there is a need to understand the condition of the asset and what the probability of failure of that asset is. Second, there is a need to understand the consequence of failure in terms of its impact. Third, the probability and consequence of failure need to be combined to understand the amount of risk. Once risk is known, it can then be assessed against the cost of replacement/refurbishment to determine the appropriate time for an intervention.” For example, a well-informed user can plan to replace equipment when the risk value exceeds the cost of replacement.

Morris continued, “In order to understand the condition of the asset, there is a need to invest in condition monitoring hardware, which varies based on the application. These are typically wired or wireless devices, which can be placed on equipment to collect different types of data. In addition to the hardware, there is a need for asset performance management software, which takes the data from the monitoring devices and performs analysis to identify the risk of failure. It does this by creating a digital twin of the asset and analyzing the data being provided by sensors and monitors to simulate the impact on the asset’s condition. This software typically can also determine the consequence of failure and calculate the risk value.”

Viridi’s Williams said the use of BESS can address several grid-related issues. “By charging batteries when energy is abundant and lower cost—in many parts of the U.S., this occurs during peak solar production—and discharging when energy is at a higher price or when the grid is operating at a higher carbon intensity, distributed, behind-the-meter storage has the capacity to provide significant benefits to the host site,” said Williams. “These benefits include active management of on-site generation and cost reduction through peak shaving, while also supporting the grid by releasing energy when needed—all for the benefit of the battery owner. However, fulfilling these roles requires that the BESS be absolutely safe, and they must have advanced communications and controls capacity so they can be monitored and managed from anywhere and leverage real-time opportunities to provide forecasted return on investment.”

5. Twelve lithium-ion batteries, installed in a dedicated room, provide 500 kWh of usable power for resiliency backup and demand charge management for the Hauptman Woodward Medical Research Institute, located on the Buffalo Niagara Medical Campus. Courtesy: Viridi

“A good example of the diverse benefits from distributed storage is the 600-kWh Viridi BESS installation [Figure 5] in occupied space at the Hauptman Woodward Medical Research Institute (HWI) in Buffalo, New York,” said Williams. “HWI had an undersized interconnection to support installation of a new cryogenic electron microscope. This need was satisfied by installation of the Viridi BESS, which charges in moments of lower power draw and discharges when the building is peaking to provide adequate power for this equipment whenever it is needed. However, when not used for this purpose, HWI uses the BESS in an automated fashion to peak shave, setting a kW ‘ceiling’ on operations that results in cost savings and reducing local grid strain. In this way, the BESS fulfills the promise of energy storage, which benefits both the host and the overall electric ecosystem.”

—Darrell Proctor is a senior editor for POWER.

TVA, Type One Energy Ink Deal to Develop Commercial Fusion Power Plant

February 23, 2025

Jeff Prescott

Bull Run Business coal Engineering fusion News Nuclear Plant Design Power stellarator Technology Tennessee Valley Authority TVA Type One Energy No Comments

The pursuit of energy from fusion technology has taken another step forward, with the Tennessee Valley Authority (TVA) entering into a cooperative agreement with Type One Energy to jointly develop a fusion power plant project in TVA’s territory.

The companies announced plans to collaborate on a 350-MWe Infinity Two power plant that use Type One’s stellarator fusion technology. The groups on Feb. 10 said the project could offer baseload power generation by the mid-2030s.The project could support planned retirements of TVA power plants that burn coal and natural gas, potentially repurposing those sites. The technology also could be deployed at new locations.

The agreement expands on Project Infinity, which was launched by Type One Energy, TVA, and the Oak Ridge National Laboratory in early 2024. The original project centered on deploying Type One’s Infinity One stellarator prototype in TVA’s decommissioned 865-MW coal-fired Bull Run power plant. The companies on Monday said Project Infinity “now encompasses a deeper, broader engagement toward commercialization of fusion energy.” Bull Run was shut down in December 2023.

“Type One Energy is an organization that understands the global power industry, a place where many of us got started,” Christofer Mowry, CEO of Type One Energy, told POWER. “We understand how hard it is to build, operate, and maintain power plants, so the opportunity to work together with TVA on a potential fusion power plant project is an opportunity for us to remain focused on designing Infinity Two while relying on a best-in-class partner to do the other hard things well. It de-risks the mission to deploy fusion energy on the grid by the mid-2030s for all stakeholders.”

*This is a rendering of Type One Energy’s fusion stellarator. Source: Type One Energy*

TVA and Type One Energy will jointly work on Infinity Two fusion power plant siting studies, environmental reviews, and licensing, as well as development of project plans and financing from various sources. Type One Energy will support TVA in its evaluation and review of the project.

“Unleashing America’s energy potential will take all forms of generation including fusion,” said Joe Hoagland, TVA vice president Innovation and Research. “Energy security is national security, and we are focused on developing a technology, supply chain, and delivery model to build an industry that can power America and the world.”

Type One Energy was founded in 2019. The company opened an office in Oak Ridge, Tennessee, in 2023. The company’s technology is touted as a stellarator fusion reactor, which is a different design than a tokamak fusion reactor. Examples of tokamak reactors include the Joint European Torus in the UK, and the ITER project under construction in France. A tokamak is based on a uniform toroid shape. A stellarator twists that shape in a figure-8 design.

The companies said the scope of the latest agreement aligns with a separate arrangement between the parties to access the capabilities of TVA’s Power Service Shops (PSS) in Muscle Shoals, Alabama. The PSS relationship enables Type One Energy to continue shaping its supply chain for stellarator fusion power plants, and the PSS will support modular manufacturing and assembly of Infinity Two. The groups emphasized that the arrangement enables TVA “to benefit from the subsequent scaling of fusion energy on a global basis, following the successful deployment of Infinity Two.”

Project Infinity also includes plans for workforce development, which includes assembling a team to build, operate, and maintain fusion stellarators.

“We are fortunate indeed to work together with an energy company like TVA,” said Mowry. “TVA brings us best-in-class power plant operations, maintenance, engineering, licensing, and even project planning and construction capabilities, all skills critical to success that we now don’t need to try and recreate. Instead, we can focus on completing the design of Infinity Two and testing it with the Infinity One prototype in TVA’s Bull Run plant. The ability for us to focus on developing and delivering the core stellarator technology materially derisks our path to fusion power plant commercialization.”

—Darrell Proctor is a senior editor for POWER.

Duke Researchers: Grid Flexibility Key to Accommodate Load Growth

February 23, 2025

Jeff Prescott

AEP American Electric Power Business data centers demand response Duke University Engineering flexibility grid load growth News Power Power Demand power grid Research and Development T&D Technology No Comments

Researchers from Duke University have said that integrating more flexibility into U.S. power grids could help provide the energy needed to power future load growth, particularly the electricity needed to support artificial intelligence and data centers.

The group in a Feb. 19 webinar discussed their findings, which are contained in their recent report titled “Rethinking Load Growth: Assessing the Potential for Integration of Large Flexible Loads in US Power Systems.” The report comes from Duke’s Nicholas Institute for Energy, Environment & Sustainability.

The study was coauthored by Tim Profeta, senior fellow at the Nicholas Institute and associate professor of the practice at the Duke University Sanford School of Public Policy; Dalia Patiño-Echeverri, associate professor at the Nicholas School of the Environment; Tyler Norris, a Ph.D student at the Nicholas School of the Environment; and Adam Cowie-Haskell, a graduate student at the Nicholas School.

The study looked at 22 of the nation’s largest balancing authorities, which together serve about 95% of the country’s peak power load. The researchers said that gigawatts of new load could be added to the U.S. grid in each balancing authority before the total load would surpass what system planners are prepared to serve. The key point of the study is grid flexibility, so that the new load can be temporarily curtailed as needed to avoid problems with power delivery.

Profeta said, “I think we’re really looking to use this analysis to inform the relevant decision-makers regarding how we service loads. That’s the regulators at the state level, at the regional level, and also the sources of load, and also the utilities, the federal policy-makers overseeing the system. I think that’s all relevant, but I think what we really want to do is introduce a process, to use this headroom in planning processes.”

Profeta added, “And then possibly maybe provide motivation for regulators to open proceedings to explore recommendations for how they should potentially enable this approach across their entire planning process. This [load growth] is presenting unique challenges to regulators. We want to show how flexibility can mitigate these additional loads.”

Curtailing Loads

The study found that 76 GW of new load, which is equivalent to about 10% of the nation’s current aggregate peak demand, could be integrated with an average annual load curtailment rate of 0.25%. In other words, that would mean new loads can be curtailed for 0.25% of their maximum uptime. The group also said that 98 GW of new load could be integrated at an average annual load curtailment rate of 0.5%, and 126 GW at a rate of 1.0%.

The report said the five balancing authorities with the largest potential load integration at 0.5% annual curtailment include PJM (Figure 1), which serves 13 states and the District of Columbia, at 18 GW; and the Midcontinent Independent System Operator, or MISO, which serves much of the Midwest, at 15 GW. The study said ERCOT, which oversees the Texas grid, could curtail 10 GW. The Southwest Power Pool, or SPP, serving the Southwest U.S., also could curtail 10 GW, while Southern Co.—the group that oversees several utilities in the Southeast U.S.—could curtail 8 GW.

*Figure 1 – Source: Duke University / Nicholas Institute for Energy, Environment & Sustainability*

Norris said, “Our study demonstrates that existing U.S. power system capacity—intentionally designed to handle extreme peak demand swings—could accommodate significant load additions with modest flexibility measures. Overall, the findings suggest that load flexibility offers a promising near-term strategy for regulators and market participants to more quickly integrate new loads, reduce the cost of capacity expansion and enable greater focus on the highest-value investments in the electric power system.”

The study said the average duration of load curtailment would be about 1.7 hours at 0.25%, 2.1 hours at 0.5%, and 2.5 hours at 1.0%. The group said about half of the new load on the grid would be retained during about 90% of the time that curtailment is required.

“There’s gold in the hills, and we should be hunting for it,” said Profeta. “Load growth is really on a collision course with the grid … it’s really intensified with the rise of AI [artificial intelligence] and data centers. We need every tool in the toolkit to address this problem, and we need every tool to address the delays we might see.”

Georg Rute, CEO of Gridraven, a company focused on optimizing the power grid, noted it’s important to recognize the challenges that exist along the grid. “While the Duke study highlights that the existing U.S. power grid has significant untapped capacity, it doesn’t address existing transmission constraints that can limit power delivery. Congestion is a problem, so a majority of the potential could easily be wiped out if that’s taken into account,” said Rute.

Rute told POWER, “However, there are readily available solutions to reduce congestion and unlock that potential. For example, even a slight wind blowing around 4 mph can increase transmission line capacity by 30% through cooling. In Germany, grid operators have implemented sensor-less dynamic line ratings (DLR) across their networks, boosting capacity and saving billions in congestion costs. Combining flexible connections with DLR is a critical step to ensure we can power AI data centers without overwhelming the grid.”

Importance of Flexibility

Profeta said the Duke group “particularly wanted to look at load flexibility to see whether it could be a near-term solution to handle load growth in this country amid some of the [grid] constraints. We wanted to look at how we can stabilize the grid while handling this load growth.”

Norris noted that load factors during the winter were on average lower than during summer months (Figure 2). “The highest demand occurs during a very short period of hours … during extreme weather events, or the hottest parts of summer or the coldest parts of winter,” said Norris. “Our systems are planned around these peaks. It’s assumed that when new load is added, it will happen during those extreme events.”

*Figure 2 – Source: Duke University / Nicholas Institute for Energy, Environment & Sustainability*

The group said those periods are when flexibility (Figure 3) would be important, as end-use customers could temporarily reduce their electricity consumption from the grid through the use of on-site power and energy storage, temporal flexibility, spatial flexibility, and reduced operations.

Norris said some utilities and other groups already are making adjustments to account for power demand from data centers. American Electric Power (AEP), which last fall said it expects to bring 4.7 GW of new data center capacity online this year, wants new data center customers to pay for a minimum of 85% of the energy they say they need each month, even if they use less, to cover the cost of infrastructure required to bring electricity to those facilities.

*Figure 3 – Source: Duke University / Nicholas Institute for Energy, Environment & Sustainability*

Norris noted that AEP has said it expects 30 GW of new load from data centers in the next few years. Bill Fehrman, CEO of Ohio-based AEP, last week said “It continues to be full speed ahead” for his group, and said the company is considering adding $10 billion to its record $54-billion capital expenditure plan through the end of the decade.

Demand Response

The study noted that the number of hours during which curtailment of new loads would be necessary each year, on average, is comparable to the curtailment from existing U.S. demand response programs. The group said their research suggests the U.S. grid is sufficient to accommodate significant constant new loads, as long as those loads can be safely scaled back during some hours of the year. They also said there is the potential to use flexible load to complement investments in new power capacity, enabling the grid to grow while also mitigating the need for large expenditures on new capacity.

The researchers, citing the North American Electric Reliability Corp.’s 2024 Long-Term Reliability Assessment, said that aggregated U.S. winter peak load is forecast to grow by 21.5% over the next 10 years, from the 2024 total of 694 GW to 843 GW by 2034. The group said demand from large commercial customers, including data centers, would be responsible for much of that load growth.

Norris during Wednesday’s webinar was asked how load flexibility could be translated into system planning processes, such as interconnection studies and resource adequacy studies that actually allow for using the headroom on the transmission and distribution system.

“This is a really important point,” said Norris. “I want to emphasize that because we’ve been asked … how is this different from existing demand response programs. The existing demand response programs, and they’ve obviously made very meaningful contributions in some markets, is that most of the loads that participate, especially the large loads—which are about 70% of participants in demand response programs—most of those loads are treated as firm loads for the purposes of resource adequacy planning and interconnection and transmission planning. And they opt to participate in demand response for economic purposes given the associated economic incentives.”

Norris continued, “What we’re talking about here can include that, but it’s a little different that we’re talking about pulling up the considerations earlier in the planning process from the beginning and recognizing the profile of the load and its capabilities before an interconnection study. And [then] a transmission study and a capacity expansion plan is developed to accommodate that new load. And that is, we think, a bit different than the existing programs we’ve seen, and it does arguably require a little bit more of a sophisticated approach to system planning.”

—Darrell Proctor is a senior editor for POWER.

Advantages of MSR Technology

Commercial Projects Announced

Massive Buildout Targets Surging Demand from Data Centers and Industry

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

Efficiency a Key Part of Upgrades

Grid Projects

Handling Increased Demand for Electricity

Combating Failure

Utilizing Digital Twins and Energy Storage

Cybersecurity and Grid Reliability

Curtailing Loads

Importance of Flexibility

Demand Response

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