The portfolio includes 100 MW of geothermal power from Zanskar and 600 MW of solar paired with 600 MW of battery storage from Primergy. Amazon said the projects will be used to help power its planned data center operations while adding new generation resources to the Nevada grid.

The Zanskar agreement is structured as a 20-year PPA with NV Energy, subject to approval of the utility’s 2026 Integrated Resource Plan by the Public Utilities Commission of Nevada. The agreement runs through 2050 and covers multiple geothermal projects that Zanskar expects to construct, own and operate as a portfolio.

Unlike wind and solar resources, geothermal can provide carbon-free baseload generation, a feature that has become increasingly valuable as data center developers, utilities and large power users look for firm capacity that can support high-load operations.

Salt Lake City-based Zanskar said it will deliver the 100 MW of geothermal power to NV Energy by 2030. The company has already announced Nevada geothermal sites including Pumpernickel and Big Blind, and said the new agreement builds on its expanding greenfield geothermal portfolio in the state.

“Geothermal is one of the few energy sources uniquely positioned to deliver affordable, around-the-clock power,” said Ryan McGraw, chief development officer of Zanskar. “Not only can it deliver reliable, carbon-free power with existing technologies, but it’s also uniquely suited to scale and meet growing electrical needs for years to come.”

McGraw said the agreement represents “a significant step” in scaling Zanskar’s portfolio as demand for carbon-free power increases.

Amazon said this is its first data center project powered in part by dedicated geothermal generation. The company said geothermal’s ability to use the Earth’s internal heat to generate electricity around the clock makes it a potential fit for data center loads, which require high reliability and continuous power.

The solar and battery portion of the portfolio is also intended to support capacity needs in Nevada. Amazon said the 600 MW solar project paired with 600 MW of battery storage would allow solar production to be captured during peak output periods and dispatched when needed. That structure could extend the operational value of solar beyond daylight hours and provide additional flexibility to the grid.

Amazon said it will cover all costs associated with powering its data centers, including new energy infrastructure and generation, so those costs are not passed on to residents and businesses in the region.

The Nevada investments add to Amazon’s global carbon-free energy portfolio, which the company said includes more than 700 projects totaling more than 40 GW. The company said the portfolio is enough to power more than 12 million U.S. homes.

Zanskar uses artificial intelligence, modern drilling and computational geoscience to identify and de-risk geothermal resources. The company operates the Lightning Dock geothermal power plant in New Mexico, which it says includes the most productive pumped geothermal well in the United States.

The Nevada PPA follows several recent Zanskar announcements, including $115 million in Series C funding, $40 million in development capital and a GEODE agreement with CC Power. The company said those moves support its effort to scale naturally occurring geothermal resources for U.S. power demand.

The agreement is expected to cover about C$300 million (roughly USD $220 million), in early-stage activities including community engagement, workforce planning, pre-construction planning and site preparation work. The province said those activities could be completed by 2030.

Bruce C, if ultimately approved and built, would add up to 4,800 MW of new nuclear generating capacity at the existing Bruce Power site on Lake Huron. The project would be Ontario’s first large-scale nuclear build in more than 30 years.

No reactor technology has been selected at this point. Bruce Power has said the project is being advanced through a technology-neutral planning process, allowing the company and province to evaluate multiple reactor options before making a final selection.

While the decision moves Bruce C from long-term concept toward more formal early development, the project still faces a multi-year approval process, including federal impact assessment and nuclear regulatory review.

Ontario first signaled support for exploring new nuclear generation at the Bruce site in July 2023, when then-Energy Minister Todd Smith announced the province’s backing for long-term planning and consultation work. In 2024, Bruce Power began the federal Impact Assessment process, an early step in the approval pathway for large-scale nuclear projects in Canada. That review is expected to be completed in 2028.

The proposed project comes as Ontario prepares for a major increase in electricity demand. The IESO’s 2026 Annual Planning Outlook projected baseline electricity demand growth of 65% by 2050, with a high-demand scenario reaching as much as 92% growth. The higher case reflects stronger economic expansion, electrification, electric vehicle adoption, commercial growth and data center development.

Nuclear power already anchors Ontario’s electricity system, providing more than half of the province’s electricity supply. Bruce Power currently operates Bruce A and Bruce B, which together include eight CANDU reactors. The Bruce site is one of the largest operating nuclear facilities in the world and a major source of non-emitting baseload power for the province.

Bruce C is part of a broader nuclear expansion strategy that also includes refurbishment of the existing Bruce, Darlington and Pickering fleets, as well as small modular reactor development at Ontario Power Generation’s Darlington site. The province has positioned nuclear power as central to meeting rising demand while maintaining grid reliability and limiting emissions.

Brandon Mulder is a journalism fellow at the University of Texas Energy Institute.

A decade ago, wind power was surging in popularity and attracting huge investments that made Texas a national leader in renewable energy. But today, gas generation is making a big comeback, driven by a wave of data centers flooding into the state.

For the last six months, the volume of gas generation in the Texas grid’s interconnection queue — the yearslong waiting list for electric generators wanting to connect to the grid — has surpassed wind. It’s the first time since January 2016 that gas has overtaken wind in the queue, a shift that reflects the policy and economic headwinds facing the wind industry and data centers favoring gas power as they seek to cash in on the artificial intelligence boom.

“The data center explosion and their desire for 24/7 power probably excited a lot of gas developers, and that gas queue got bigger,” said University of Texas professor of energy regulation David Spence.

Like every power grid operator in the U.S., the Electric Reliability Council of Texas, or ERCOT, uses the interconnection queue to manage and plan for new power generation coming online. But not all projects in the queue ultimately reach completion. According to the Lawrence Berkeley National Laboratory, or LBNL, only 22% of projects in ERCOT’s queue actually get built, which is still the highest percentage of any grid in the nation.

Still, the queue gives an early indication of how the grid is projected to evolve in the future. Solar and battery projects dominate, accounting for 75% of the 458,000 megawatts in the queue, with gas and wind projects making up the rest.

But over the last three years, the volume of gas projects in the queue has jumped by more than 400%, from 12,500 megawatts in March 2023 to nearly 64,000 megawatts as of last month, according to ERCOT data. Meanwhile, wind projects have grown at a much slower clip, increasing by 87% from 25,700 to 48,000 megawatts over the same period.

The gas queue is getting a boost from the Texas Energy Fund, a program passed by the Legislature in 2023 that provides low-interest loans to developers of so-called dispatchable power that can easily be ramped up or down according to grid demand, such as gas-fired power plants.

About 9,000 megawatts worth of projects in the queue are getting loans from the TEF, a large portion of which are “near-term gas projects we expect to come online,” an ERCOT spokesperson said.

But the strongest driving force behind the gas ramp-up is the long list of companies looking to build data centers in Texas.

ERCOT data shows around 360,000 megawatts of power demand tied to prospective data center projects — a volume that would by itself more than quadruple the grid’s record peak demand of 85,500 megawatts set in August 2023.

If anything close to that number actually gets built, ERCOT CEO Pablo Vegas told a Senate committee earlier this month, “then we’re going to clearly need a lot more of [gas] generation in order to have a balanced and reliable grid.”

ERCOT’s gas embrace

Vegas sees the growth of gas projects on the queue as a welcome trend. For too long, he said, ERCOT’s energy market hasn’t been attracting dispatchable energy generation like gas plants.

It’s a symptom of how the market was designed 25 years ago, when the Texas Legislature passed sweeping reforms that deregulated the market. Restructuring in 1999 created a competitive wholesale and retail power market and introduced a renewable energy requirement.

That incentivized bringing cheap electricity to the grid, Vegas said, and it kick-started renewable energy development that boomed through the late 2000s and early 2010s.

But Vegas said the new market design failed to value the different strengths of power sources, and those differences matter for grid reliability.

Renewables provide cheap, clean electricity but are only intermittently available when the sun is shining and wind is blowing. Battery power — which pulls electricity from the grid during off-peak hours then sends it back to the grid during peak hours — can be dispatched when needed, but it has duration limitations.

Thermal generators like gas and coal don’t have similar limits as long as the fuel is available to run them.

“We’ve seen this explosion of wind and solar, and now batteries, to the complete exclusion of growth in the natural gas system, because economically we’re not valuing the characteristics of gas generation that is so important for long-term reliability,” Vegas said. “We need to change that somewhere in the market design to recognize the reliability characteristics of the generating source.

But bringing gas-fired power onto the grid faces its own hurdles. For the last several years, the supply chain for gas turbines — the engines that power plants use to generate electricity — has seen a major bottleneck caused in large part by surging demand from data centers outstripping manufacturing capacity. According to Wood Mackenzie, an energy research and consulting firm, orders for a turbine today may take until 2031 to arrive.

However, data centers and gas power developers are finding creative ways around this problem, including repurposing turbines originally designed for aircraft or cruise ships, according to a recent report from the energy data company Cleanview.

In El Paso, for instance, the city’s electric utility is planning to build a gas plant using a novel design that will tie together 813 small gas generators, which are typically used as backup power units at hospitals or manufacturing facilities, to produce 366 megawatts for a data center being built by Meta. And in Mississippi, Elon Musk’s AI company xAI purchased and revived a dormant power plant last year to power a data center that helps train xAI’s chatbot Grok.

“The perceived economic loss of not getting your data center up and running in a year is valued in the billions of dollars,” said University of Texas grid researcher Joshua Rhodes. “That will drive people to very out-of-the-box solutions for these types of things.”

Wind’s slowdown

On the other side of the equation is wind’s shrinking market share. Since its peak in 2018, when wind composed around 50% of the megawatts in the interconnection queue, wind has now fallen behind every other major generation source.

The headwinds facing wind today are multifold, experts say, and extend beyond the recent cuts to tax credits for renewable projects.

Wind’s primary challenge stems from its earlier success. After two decades of immense growth across the state, all of the prime development locations have been taken. Parcels across West Texas and the coastal region — where winds are strong, land is accessible, and transmission lines are available to send the electricity to the grid — have mostly been developed already.

“Texas has a lot of land, but the low-hanging fruit has been picked over by all the wind development that has happened there,” said Joseph Rand, an energy markets researcher at LBNL.

And because the West Texas and coastal regions have become saturated, the existing transmission lines have grown congested, forcing generators to curtail their power output — which cuts into their profits.

To solve that issue, ERCOT is advancing plans to update its transmission system again, which will include three major 765 kilovolt lines capable of carrying more electricity than any existing line in Texas.

“If I were a wind developer, I might not want to build today and face that curtailment risk for the first few years of my project’s lifespan,” Rand said.

Wind’s challenges also stem from solar’s soaring success in Texas. While technology costs for wind and solar have both fallen over the last two decades, the cost of solar energy has fallen more rapidly, from around $160 per megawatt-hour in 2010 to around $70 in 2024, LBNL data shows.

“Because the cost of building a solar farm has gone down so dramatically over the last five to six years, it just becomes a better business decision to build solar and, increasingly, solar plus [battery] storage,” said Judd Messer, Texas vice president of the clean energy trade association Advanced Power Alliance.

Lastly, the wind industry faces policy uncertainty that has made it difficult for wind projects to attract financing. Trump administration policies that have slowed or paused federal approvals necessary for wind projects to reach completion have caused investors to shy away from the industry.

In Texas, which created a grid designed to avoid federal regulation by operating almost entirely within state lines, the federal government can still hamper renewables via the Federal Aviation Administration’s 200-foot rule, which requires construction permits for all structures over 200 feet tall, such as onshore wind turbines.

Last summer, for instance, the U.S. Department of Transportation announced that the FAA “will thoroughly evaluate proposed wind turbines to ensure they do not pose a danger to aviation,” indicating that the routine permit may become a hurdle for onshore wind.

“This kind of arbitrary executive-level uncertainty is really spooking people,” said Messer. 

Disclosure: Advanced Power Alliance has been a financial supporter of The Texas Tribune, a nonprofit, nonpartisan news organization that is funded in part by donations from members, foundations and corporate sponsors. Financial supporters play no role in the Tribune’s journalism. Find a complete list of them here. 

This article first appeared on The Texas Tribune.

Aimed at helping advance the world’s first “gas-plus-nuclear” power plant, the companies argue the project could deliver a new, near-term approach to help meet surging U.S. electricity demand driven by artificial intelligence and advanced manufacturing.  

The collaboration combines Blue Energy’s project financing and nuclear construction experience with GE Vernova’s reactor technology and flagship turbines. The companies plan to design and develop a nuclear power plant using GE Vernova Hitachi Nuclear Energy’s (GVH) BWRX-300 small modular reactor (SMR) at Blue Energy’s first planned site in Texas, subject to a final investment decision in 2027. To support project advancement, the companies signed a slot reservation agreement for site delivery in 2029 of two GE Vernova 7HA.02 gas turbines for early site energization.  

“By collaborating with GE Vernova, we’re bringing together critical infrastructure, safe reactor technology, and a financeable delivery model,” said Blue Energy CEO and Co-Founder Jake Jurewicz. “Blue Energy is focused on building safe, nuclear power you can plan around – with plants planned to be built on time, on budget, and at scale. Together, Blue Energy and GE Vernova can unlock a blueprint for how to scale nuclear energy, power American communities, and fuel global AI leadership faster, more affordably, and without burdening ratepayers.”  

“Innovative projects like this one will help advance the future of nuclear power and meet the surging demand for electricity. Together with our customers, GE Vernova currently generates nearly 50 percent of electricity produced in the U.S. today, and we are proud that our collaboration with Blue Energy and others in the entrepreneurial community will play an increasingly important role in accelerating America’s next era of energy leadership,” said Scott Strazik, CEO, GE Vernova.   

The companies are also exploring methods for contracting and offsite construction of large power plant modules consistent with GVH’s BWRX-300 design in an effort to reduce capital costs and to accelerate offsite pre-fabrication supply chains.

The NRC recently approved Blue Energy’s approach to resequencing major phases of nuclear plant construction that supports large module and gas-to-nuclear delivery schedules. As a result, Blue Energy argues it can accelerate deployment of new nuclear power with the potential to eliminate “at least half a decade” off the conventional ten year plus nuclear timeline. Additionally, the company maintains it can reduce time to power to 48 months or less by energizing turbines with a natural gas bridge that converts to nuclear power.

The companies will enter into further agreement in the near future under which GE Vernova, in collaboration with Blue Energy, will perform site preliminary safety analysis work as well as other development and characterization work to support Blue Energy’s nuclear construction permit application.   

​​Blue Energy said it could begin early site works on its first planned project in Texas in 2026, to support a final investment decision in 2027. The company then will ​apply to the U.S. Nuclear Regulatory Commission (NRC) for a construction permit in 2027. GE Vernova gas turbines are expected to provide approximately 1 gigawatt (GW) of power to the site as early as 2030 before the steam supply is switched and ramped up to approximately 1.5 GW of nuclear power as GE Vernova’s BWRX-300s come online as early as 2032. Blue Energy then plans to deliver nuclear energy to power a nearby data center campus.   

That mismatch has put much of the industry’s attention on gas turbines, aeroderivative machines and reciprocating engines. But Babcock & Wilcox (B&W) is making a different case: in some situations, large blocks of dispatchable power may also come from a more traditional steam-cycle configuration: natural gas-fired boilers paired with steam turbines.

The company received full notice to proceed in March on a $2.4 billion design-build agreement with Base Electron, an independent power producer backed by Applied Digital, to deliver 1.2 gigawatts (GW) of new generation capacity for Applied Digital AI factory campuses. The project includes four 300-MW natural gas-fired boilers and steam turbine generator systems, according to B&W.

For B&W, the large project order is an example of how constrained equipment supply chains are changing the early power decisions behind data center development.

“We came up with a solution,” said Brandy Johnson, chief technology officer at Babcock & Wilcox, in an interview with Power Engineering. “We put some options on the table with them that looked like gas-fired boilers and steam turbines, which, frankly, they hadn’t really thought about before, because they were seeing all the lead time issues.”

The data center power market has moved rapidly over the past two-plus years as AI growth, cloud expansion and grid interconnection delays have pushed large-load customers and their power suppliers to consider dedicated generation. Many of those discussions have focused on combustion turbines and engine packages. Those technologies still dominate much of the near-term conversation.

But the availability of major equipment is now part of the technology selection process.

Johnson said the case for boiler and steam turbine packages starts with that constraint. Steam turbines, she said, have been more readily available than gas turbines. B&W also sees an advantage in the existing boiler supply chain, including fabrication capacity and designs that have already been engineered.

“Boilers are built every day,” Johnson said. “There’s been this need for boilers continuously. And so there’s a supply chain and the manufacturing and fabrication capability.”

That does not mean the equipment is sitting in inventory. The advantage, Johnson said, is that B&W can bring forward boiler designs it has built before, reducing the amount of custom engineering needed at the front end of a project.

For customers facing compressed schedules, that can change the tradeoff. Rather than optimizing every steam condition or plant detail around a custom configuration, some buyers may be willing to accept a more standardized package if it can move sooner.

Johnson compared the approach to gas turbine procurement, where customers select from established frame sizes rather than redesigning the machine around each project.

“That’s what the gas turbine guys do anyway,” she said. “They say, this is your frame size, and you get it. So we’re able to do some of that similar thing — this is what we have, this is what we can bring.”

B&W is working with Siemens Energy on the Base Electron project’s steam turbine supply. Johnson said the companies have a long working relationship, though B&W is not limited to Siemens Energy on future projects.

Johnson said B&W is already having additional discussions.

“Our pipeline for this power for the AI data center market is quite robust,” she said. “It’s in the billions. There are multiple customers we’re in conversations with.”

Existing plants are being asked to run longer

B&W’s role in the current market is not limited to new data center generation, of course. Johnson said the same demand environment is also affecting the existing thermal fleet, particularly coal units that owners expected to retire but are now preparing to run longer.

That trend is already showing up in B&W’s order book. In late April, the company said it had secured more than $21 million in U.S. fuel-switching technology awards, while also citing continued strength in its parts and services business as coal and natural gas plants run more often to meet baseload demand.

“Some of those customers were on the downhill side of getting ready to close, when they are now going to push out their closure date,” Johnson said. “And so that does bring more parts and service our way.”

That work is showing up in life-extension projects, replacement parts and field service activity. Johnson said customers are looking at multi-year extensions with reliability in mind after deciding on new retirement dates.

The scopes vary by plant, she said. Some units need pressure-part work. Others need burner updates, igniter work, ash system repairs, soot blower work or pulverizer support. For older coal units, the work can be highly specific to how the plant has operated and where wear is showing up.

“Especially the coal units — upgraded pulverizer parts, in particular, are a place that, as they run the units harder and longer, they’re going to need continued pulverizer support,” Johnson said.

That is the plant-level reality behind a broader reliability discussion. Keeping a unit available requires condition assessments, outage work, replacement parts and an understanding of where the unit is most likely to fail as it runs beyond the retirement schedule previously assumed.

Coal-to-gas work also remains part of B&W’s backlog and customer discussions. In the April announcement, B&W said it was executing 1,200 MW of coal-to-gas conversion projects scheduled for completion this year, following a 100-MW utility boiler conversion completed in the fourth quarter of 2025.

Johnson said some customers are considering full conversions, while others are looking at additions that preserve the ability to burn coal while adding gas capability.

“Sometimes it’s not a conversion, sometimes it’s an addition,” she said. “They’re keeping the ability to still burn coal, but also the optionality to burn gas — doing that conversion to keep both of those optionalities out there.”

That word, optionality, runs through much of the current power generation market. Data center developers want power sooner. Utilities and IPPs are reassessing retirement schedules and deciding whether to maintain, convert, replace or extend older assets. EPCs and equipment suppliers are trying to work around long lead times while still delivering reliable plants.

For B&W, those dynamics are creating openings in both directions: new steam-cycle capacity for large-load customers and aftermarket work for existing units that are being asked to stay available.

The common thread is not a return to old assumptions about baseload power, but more a practical question now facing many power generation decision-makers: what can be built, repaired or extended in time to meet the load that is already arriving?

Kevin Clark

Kevin Clark is the editor of Factor This Power Engineering, where he covers power generation, grid reliability, and emerging trends shaping the electric sector. He also leads editorial strategy for the POWERGEN conference. Kevin’s reporting examines the practical and strategic issues shaping the power industry, including load growth, plant performance, new generation development, and the policy and market shifts influencing investment decisions. Before joining the energy trade press, Kevin spent a decade as an Emmy Award-winning television and digital journalist covering complex stories across fast-moving news environments. His work includes interviews with industry leaders, coverage of major energy events and analysis of the trends and developments affecting utilities, owner-operators and the broader power generation market. Have a story idea? Email Kevin at kevin.clark@clarionevents.com.

Brookfield’s global asset management and energy infrastructure development experience combined with TNC’s nuclear project delivery will serve as the foundation for the project development company. The business will offer execution capabilities for the deployment of nuclear projects based exclusively on Westinghouse reactor technology, including AP1000 and AP300, in addition to end-to-end project management, licensing support, and oversight of engineering, procurement, construction and commissioning activity.

As part of efforts to potentially develop two partially constructed AP1000 units near Jenkinsville, S.C., Brookfield has selected the new company as the project manager for the Fairfield County, S.C., nuclear project, formally known as V.C. Summer Nuclear Units 2 and 3.

The new company will support due diligence activity for the project and oversee the delivery should it move forward to a final investment decision. Development of the project remains subject to further evaluation, regulatory approvals, and the execution of definitive agreements, the companies noted.

“This joint venture reflects Brookfield’s disciplined approach to large-scale infrastructure investment and focus on partnering with experienced operators,” said Wyatt Hartley, Managing Partner, Brookfield. “By combining our global infrastructure development capabilities with nuclear project delivery expertise, we believe this platform has the potential to accelerate the American nuclear resurgence, building on the momentum of the Westinghouse partnership with the U.S. Government.”

“Our team was built on the field of Vogtle and on some of the most complex energy projects in the world,” Joe Klecha, Chief Nuclear Officer of The Nuclear Company said. “We know what it takes to deliver nuclear. What’s been missing is a model that brings together the people, the capabilities, and the capital to do it at speed and scale. That’s what this partnership creates.”

In 2024, TNC came out of stealth mode and announced plans to develop a 6 GW nuclear fleet by the mid-2030s. The company aims to re-define how large-scale nuclear infrastructure projects are delivered, working as a project developer, collaborating with private equity, hyperscalers, utilities, independent power producers and nuclear technology suppliers to execute fleet-scale projects. TNC argues this framework spreads risk and value more evenly among the partners.

In June 2025, Palantir Technologies and TNC announced a strategic partnership to launch a first-of-its-kind AI-powered software platform designed to streamline and modernize nuclear power plant construction across the nation. Built on Palantir’s Foundry platform, the Nuclear Operating System (NOS) is designed to transform nuclear reactor projects, historically plagued by cost overruns and scheduling delays, into fast, predictable and cost-effective infrastructure efforts. The platform brings real-time data integration and AI-driven decision-making to all aspects of nuclear construction, including scheduling, supply chain, site management and regulatory compliance.

PJM names Mills permanent president and CEO

David E. Mills became PJM Interconnection’s fifth permanent president and chief executive officer on May 1, stepping into the role he had held on an interim basis since January.

Mills had served on the PJM Board of Managers since 2021 and as board chair since May 2025 before transitioning to the interim CEO role. His background spans strategic leadership in both power and natural gas. Mills is the former senior vice president of policy and energy supply at Puget Sound Energy, where he also served as chief strategy officer. He previously worked at the U.S. Department of Energy’s Bonneville Power Administration (BPA).

With his appointment, Mills resigned his voting seat on the board, though he continues as a non-voting member by virtue of his office. Board member Paula Conboy was elected chair-elect on April 29 and will serve as chair until the board’s annual meeting on May 15.

“Reliability remains our absolute north star,” Mills said in a statement, “and I’m hopeful that by working together with our members and state and federal officials, we will meet this critical moment.”

The appointment comes as PJM faces significant pressure on both supply and demand, with record capacity auction results and interconnection queues stretched well into the next decade.

The regional transmission organization (RTO), whose purview spans parts of 13 states and Washington, D.C., reopened its interconnection queue last week with 811 projects. PJM’s queue had previously become so backlogged that the organization effectively shut it down in 2022 to rework its processes.

TVA taps former COO as interim chief

The Tennessee Valley Authority (TVA) Board of Directors named Mike Skaggs interim president and CEO on April 24 as the federal utility’s permanent search continues.

Skaggs brings more than 40 years of utility industry experience, including more than 25 years at TVA, where he served as chief operating officer from 2018 to 2021 before retiring in January 2022. The utility said he played direct roles in the completion and startup of Watts Bar Nuclear Plant Unit 2, the recovery of Browns Ferry Unit 1 to full three-unit operation, and the management of two major steam generator replacement projects. He also led TVA’s effort to modernize its transmission grid, the nation’s second largest.

“Mike’s leadership and deep knowledge of nuclear generation aligns directly with TVA’s strategic focus on expanding and modernizing its nuclear fleet,” said TVA Board Chair Mitch Graves.

Skaggs will take the reins from Don Moul, who announced his retirement weeks after learning of a directive from the Trump Administration capping the TVA CEO’s salary at $500,000, regional news outlets reported. Moul took over as TVA’s chief executive in April 2025.

Skaggs joined TVA in 1994 as a project manager at Watts Bar and held executive roles across the Browns Ferry, Sequoyah and Watts Bar nuclear stations over the course of his career.

Westinghouse confirms Sumner as permanent CEO

Westinghouse Electric Company named Dan Sumner president and CEO on April 27, formalizing a role he had held on an interim basis for the past 12 months.

Sumner has been with Westinghouse since 2010 and previously led the company’s Global Operating Plant business before stepping into the interim role. Earlier, he served as Westinghouse’s chief financial officer from 2017 to 2023, a period the company credits with its financial repositioning and growth. His appointment arrives as Westinghouse advances an $80 billion partnership with the U.S. government to build AP1000 reactors and works to meet growing demand for both operating plant services and new nuclear construction.

AEP places experienced utility executive at Indiana Michigan Power

American Electric Power (AEP) named Maryam S. Brown president and chief operating officer of Indiana Michigan Power, effective April 27.

Brown most recently served as president and CEO of Southern California Gas Company, where she led the Sempra subsidiary through a major operational modernization and advanced the Angeles Link hydrogen pipeline proposal. She began her career as a maintenance and reliability engineer at Amoco Oil Company before earning a law degree and building an extensive background in energy regulatory law.

She succeeds Steve Baker, who moves to a senior advisory role focused on AEP’s nuclear development strategy in Indiana before retiring at year-end following 35 years with the company.

AEP CEO Bill Fehrman described I&M as “one of our fastest growing operating companies,” citing load growth and potential nuclear development as key opportunities ahead.

PSO names generation operations veteran to fleet leadership role

Public Service Company of Oklahoma appointed Bryan Walsh vice president of generation transformation, strategy and growth, effective April 20.

Walsh brings more than 15 years of power generation leadership across hydropower, combined-cycle and simple-cycle facilities. He most recently served as assistant vice president of hydroelectric operations at American Municipal Power, where he oversaw fleet operations, dam safety, regulatory compliance and capital projects. Earlier roles included oversight of natural gas generation assets and long-term service agreement administration.

PSO, an AEP subsidiary, operates approximately 4,400 megawatts (MW) of generating capacity in Oklahoma, primarily natural gas complemented by wind.

Wayne most recently served as Vice President of Industry Outreach and Strategy at Danovo Energy Solutions, a Quanta Services company. He brings more than three decades of senior leadership experience across marketing, executive management, and strategic planning, including leadership roles at OMICRON Electronics and Doble Engineering Company. A Senior Member of IEEE, Wayne has been active with the IEEE Power & Energy Society (PES) for more than a decade, including serving as Vice President of Meetings and Conferences (2019–2024). He is a frequent speaker, panel moderator, and published author in leading industry publications.

Bishop will oversee Clarion Events North America’s Energy portfolio, including POWERGEN, DTECH, DTECH regional events, as well as the Factor This media properties.

Liz Irving, CEO of Clarion Events North America, welcomed Bishop to the leadership team, “Wayne is a highly respected leader with an exceptional track record of building meaningful industry connections and translating strategy into long-term impact. His depth of experience, credibility with industry stakeholders, and passion for advancing professional communities make him a tremendous addition to our leadership team. We’re excited to welcome him to Clarion as we continue to invest in growth, innovation, and customer value.”

“I am thrilled to join Clarion Events North America and contribute to an organization with such a strong reputation for leadership and customer focus,” said Wayne. “Clarion plays a critical role in convening communities, sharing knowledge, and driving progress, and I look forward to working alongside an incredibly talented team to support the industries we serve.”

This appointment reinforces Clarion Events North America’s focus on delivering customer value through deep industry knowledge and long-standing market engagement.

Wayne will report directly to Clarion Events North America CEO, Liz Irving.

About Clarion Events

Clarion Events is the world’s largest privately owned event and exhibition organizer, producing and delivering innovative and market-leading events and digital products across the globe. Since its inception in 1947, the company has grown into a truly international organization, with a portfolio of 125 events and media brands across a range of vertical markets. Clarion Events employs nearly 2,000 people in 12 countries around the globe.

The organization aims for each of its products to become a market leader in customer satisfaction and delight while retaining talented people and loyal partners. The business constantly strives to increase its value across long-term vertical industries with significant international growth potential. Clarion Events is presented as a best-in-class, customer-centric, and digitally enabled partner.

By applying a customer-first approach across the organization, Clarion Events creates outstanding platforms and products that help customers and partners grow their businesses.

Not anymore.

If you develop, own, or operate IBRs with an aggregate capacity of 20 MVA or more (roughly 16 MW to 20 MW) connected at 60 kV or higher, you are now required to register as a Generator Owner (GO) and/or Generator Operator (GOP) under NERC Category 2. Developed in response to a 2022 Federal Energy Regulatory Commission (FERC) order, the initiative aims to improve visibility and oversight of previously unregistered facilities, providing a stronger foundation for planning, operations, and risk management. 

What are the Stakes?

The deadline for registration and compliance is right around the corner, May 15, 2026, and there’s no grace period. Penalties can reach up to $1 million per day.

“What aren’t people more worried about this?” Kellie Macpherson wondered aloud at the annual Solar + Wind Finance & Investment Summit in Phoenix, Arizona.

Macpherson is the executive vice president of compliance and security at Radian Generation, a technical advisory and engineering firm focused on assets in development through operations. Her company offers two tailored options to help Independent Power Producers (IPPs) get their stuff in order.

Based on Energy Information Administration (EIA) data, 874 existing or operating IBR sites with a total capacity of 20 MW or higher, connected at 60 kV, are on the hook for compliance with NERC, plus another 156 projects in development. Many weren’t designed with NERC in mind.

That means Kellie has been busy lately. Radian has contracted with dozens of those customers; when we spoke, she had her eyes on potentially hundreds of projects that may not have even been aware they needed to comply. Fortunately for the bulk electric system (BES), it looks like someone tipped them off.

Who Still Needs to Comply?

On Wednesday, NERC reported that it had filed its IBR registration work plan update with the FERC, which reports that NERC and the Regional Entities have processed registration for 100% of applicable entities with identified inverter-based resources (IBRs), closing what the agency deems a “critical reliability gap.” 

“This work improves industry’s ability to understand and address emerging reliability risks as the resource mix continues to evolve,” said Howard Gugel, NERC senior vice president of regulatory oversight. “Our efforts do not stop here. The ERO Enterprise remains committed to continuing this work, supporting newly registered entities, and working alongside industry to maintain a reliable, secure, and resilient bulk power system.”

NERC’s filing concludes its FERC-approved three-year work plan, but efforts to identify and register applicable entities will continue. As new IBRs are developed and interconnected, the ERO Enterprise will continue to identify and register entities that meet the registration criteria and support those entities as they transition to compliance with NERC Reliability Standards. The stakes are too high, otherwise.

Public Safety and Project Viability

Macpherson cited a couple of well-documented instances of grid disturbances that highlight the potential risk of fault-induced tripping of solar photovoltaic (PV) systems, both in Western Interconnection territory. The August 2016 Blue Cut Fire resulted in approximately 1200 MW of PV resources tripping offline or momentarily ceasing output in Southern California, much to the chagrin of the grid. Just over a year later, the Canyon 2 Fire, also in Southern California, resulted in approximately 900 MW of solar to trip similarly.

“A bunch of these smaller solar sites weren’t playing nice,” she explained. “That whole situation changed it,” she added, referencing increased regulatory focus on smaller-scale IBRs.

NERC compliance is also a prerequisite to participation in ancillary service market revenue streams, she pointed out. If you don’t play ball, you’re effectively locked out of some of the most valuable upsides your assets can deliver long-term.

“If you’re building a new site, as soon as earth is moving on the site, we need to be thinking about compliance,” Radian Generation’s Macpherson recommended. “It’s really hard, 18 months down the road, to be like: ‘Hey, inverter manufacturer, oh yeah, these also need to be NERC compliant.’ Unfortunately, that happens a lot of the time.”

Compliance can’t be put on the back burner anymore, she continued. It needs to be baked into investment decisions, financial modeling, and ultimately, the capital stack. So does cybersecurity.

Cybersecurity Concerns

Critical Infrastructure Protection (CIP) standards, enforced by NERC and FERC, are evolving (and increasingly complex) mandatory cybersecurity requirements designed to secure the BES against threats. Cyber attacks on utilities and critical infrastructure have recently drawn the wrong sort of headlines, and IBRs are grid access points that need to be battened down.

Ubiquitous utility technology supplier Itron confirmed a cyberattack last month in an 8-K form filed with the US Securities and Exchange Commission. Unknown actors managed to access parts of its IT network; the attack was blocked, the perpetrators were kicked out, and so far, it doesn’t look like anything bad happened that might compromise the company’s 8,000+ utility customers.

It is imperative to strengthen cybersecurity standards across distributed generation assets, Macpherson concurs. While the inclusion of cybersecurity measures in NERC requirements marks an important step forward, she believes many current standards lack the prescriptive rigor needed to fully safeguard the U.S. electrical grid against evolving threats.

“The stakes are especially high for Category 2 assets, as these sites play a critical role in supporting local communities, hospitals, and essential services. In some cases, critical infrastructure operates without properly configured firewalls or other foundational safeguards, exposing them to preventable risks,” Macpherson remarked.

The bar for such “preventable risks” is pretty low, Macpherson admits. Some developers, owners, and operators slip up in the simplest ways when it comes to cybersecurity, including forgetting to update their equipment when they install it.

“EPC equipment can sit on the shelf for 24 months, and they just go try to plug and play on a site,” she chuckled. “Think about your phone. If you didn’t update it at least fairly consistently, you’d be in a lot of trouble, right? Same thing for these devices.”

Common sense ain’t so common, perhaps. Fortunately for Macpherson, that means business is good. She expects the ERO Enterprise will also stay busy, keeping up with new IBRs as developers race to bring generation online.

“We’re about to be on the verge of an electron crisis,” she implored. “We can’t fix it without renewables.”

Originally published in Factor This.

The Republican administration adopted this strategy after federal courts thwarted President Donald Trump’s efforts to stop offshore wind development through executive action. Three agreements have been announced.

U.S. Reps. Jared Huffman of California, the top Democrat on the House Natural Resources Committee, and Jamie Raskin, the ranking Democrat on the House Judiciary Committee, are demanding information about the first and largest of the three. Under a deal made public in March, French company TotalEnergies is getting $1 billion — essentially a refund of its leases for offshore wind projects off North Carolina and New York— if it invests the money in fossil fuel projects instead.

Huffman said that is a “scam” and the administration is going to “light a lot of federal taxpayer money on fire if we let them.”

In a letter sent Wednesday to TotalEnergies and provided to The Associated Press, Huffman and Raskin are letting the company know that Democrats have begun an investigation, are demanding documents and communications and are advising the CEO not to take the money. The letter outlines the ways they think the deal appears to be illegal.

“You can’t come into the United States and do a backroom deal like this, that just essentially treats the treasury as a slush fund, and walk away with a billion dollars,” Huffman said.

Asked for comment, TotalEnergies pointed to its news release when the payout was announced. CEO Patrick Pouyanné said at the time that TotalEnergies renounced U.S. offshore wind development in exchange for the reimbursement of the lease fees, “considering that the development of offshore wind projects is not in the country’s interest.”

Nearly $2 billion in payouts so far

In the latest deals announced Monday, the administration said Bluepoint Wind and Golden State Wind agreed to end their leases in exchange for reimbursements totaling nearly $900 million, provided they invest equally in fossil fuels. Trump has gone all in on fossil fuels for generating electricity, which he says will lower costs for families, increase reliability and help the U.S. maintain global leadership in artificial intelligence.

Both Bluepoint and Golden State are co-owned by Ocean Winds, a joint venture of EDP Renewables and French energy giant Engie. Michael Brown, CEO of Ocean Winds North America, said that when market conditions change, “we must adapt.”

Opponents of offshore wind projects praised the administration for being creative.

“This is the latest strategy and we think it’s a winner,” Robin Shaffer, president of Protect Our Coast New Jersey, said Wednesday. Shaffer said the administration “is well within their rights to do this and private businesses can’t be forced to build anything.”

But to the top Democrat in the U.S. Senate, Chuck Schumer of New York, it is a “bailout for fossil fuel donors dressed up as a deal.”

“Donald Trump spent years calling offshore wind subsidies a waste of taxpayer money,” Schumer said in a statement. “Now his administration is handing nearly $2 billion of those very same taxpayer dollars to companies to abandon clean energy projects that would have powered millions of American homes and created thousands of good-paying union jobs.”

Once the deals are complete, Ocean Winds will have one remaining U.S. offshore wind project, SouthCoast Wind off Massachusetts. Its development has slowed under Trump.

Amber Hewett, senior director of offshore wind energy at the National Wildlife Federation, said forcing developers to abandon offshore wind energy for more oil and gas sets the U.S. further behind in efforts to curb climate change. Burning coal, oil and gas is the largest contributor to global climate change by far.

Lease buyouts are part of a campaign against offshore wind

When Trump returned to office in January 2025 he ordered a temporary halt to leasing and permitting for wind energy projects. His administration has paused work wind farms under construction, canceled plans to use large areas of federal waters for new offshore wind development and added an extra layer of review for wind and solar projects.

Federal judges allowed construction on the wind farms to resume, struck down the Day One order blocking wind energy development, and stopped the administration from requiring that all solar and wind energy projects on federal lands and waters be personally approved by Trump’s interior secretary.

Energy law expert Kristoffer Svendsen said that after the administration’s losses in the courts, the lease buyouts appear to be a last attempt to close down as many offshore wind projects as possible. He was not aware of any other arrangements where energy projects owners have been paid to walk away.

“This saga never ends. They continue to surprise the industry and those of us following the industry,” said Svendsen, assistant dean for energy law at the George Washington University Law School.

Svendsen said he expects to see energy companies head to markets in Europe and Asia because the future for new offshore wind development in the United States is “quite bleak.”

“At this point if you’re interested in offshore wind, you’ll most likely go to a jurisdiction where they want you,” he said.

The global wind industry installed a record 165 gigawatts of onshore and offshore wind last year, with 138 countries now powering their economies with wind energy, the Global Wind Energy Council said last week in its annual report. That is enough to power 118 million households. The Asian market, led by China and India, had 80% of the global total.

David Carroll, CEO and chief renewables officer for Engie North America, also thinks offshore wind will not advance in the United States in the next few years. He cited the administration’s pulling of permits that were granted after years of work and much money spent, and the stopping of fully permitted projects under construction, eroding business certainty.

“The offshore wind industry does not have a strong future here in the U.S. And that’s unfortunate,” Carroll, who is chair of the board at the American Clean Power Association, said in an interview this month. “The Northeast needs more energy and that is one of the very key ways we can get energy in the Northeast.”