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In this episode of The POWER Podcast, Sandeep Kumar Gupta, sales director with Siemens Energy Gas Services, and Naira Elsayed, a senior project manager with Elsewedy Electric Power Systems Projects (PSP), discuss the Rabigh Reinforcement Combined Cycle Power Plant, a finalist for a 2026 POWER Top Plant Award. The 1,179-MW plant sits on Saudi Arabia’s Red Sea coast, about 135 kilometers north of Jeddah, in a region that carries some of the Kingdom’s heaviest summer load. The project reached first fire in July 2025, roughly 14 months after the engineering, procurement, and construction (EPC) contract was awarded, and logged 12 million man-hours with no lost-time injuries. Gupta and Elsayed describe how early execution activities moved ahead while broader contractual arrangements were still being finalized, and what that took in trust and risk management among Siemens Energy, Elsewedy Electric PSP, and the Saudi Electricity Company. They explain how the team responded when Red Sea shipping disruptions made vessels hard to find, arranging a special voyage for the gas turbine generators and rerouting a 380-ton steam turbine generator around the Cape of Good Hope. They also cover recruiting and training skilled labor in a crowded market, building a safety culture around shared responsibility, the project’s F-class gas turbines and 3x1 multi-shaft configuration, Siemens Energy’s expanded EPC role, and the lessons they say other projects can take from Rabigh. For more on the project, read POWER’s article, “Beyond the Contract: How Rabigh Reinforcement Reached First Fire 14 Months After Award,” at https://www.powermag.com/beyond-the-contract-how-rabigh-reinforcement-reached-first-fire-14-months-after-award.

Utilities and independent power producers have spent years adding sensors to their generating fleets and creating dashboards to view what they relay. But visibility into how a plant is operating isn’t the same as knowing what to do about it—and that gap is where Siemens Energy’s Omnivise Energy Management System is increasingly shedding light, explained two of the company’s experts as guests on The POWER Podcast. “Monitoring is just telling you what’s happening,” said Sarah Dietrich-Smith, Siemens Energy’s commercialization manager for Omnivise Energy Market and Fleet Management Solutions, “and Energy Management is telling you what should happen next, and it helps you to execute that decision,” she explained. The distinction, she said, is the real difference between tracking a plant’s condition and actually optimizing it—moving “from just this visibility to true optimization that you can actually take action on, and optimization that’s based and tied to measurable business outcomes.” From Single Assets to Whole Fleets Katie Hanley, head of Siemens Energy’s Omnivise Energy Market and Fleet Management Solutions team, framed Energy Management as fundamentally a question of business outcomes. Given a plant’s generation commitments, gas hedging position, and access to additional electricity markets, “What are the optimized economics for running your plant or your fleet?” she asked. “Historically, assets were managed individually. They really only cared about the question, ‘How can we get the single asset to perform better?’ ” Dietrich-Smith said. “We want to move into a fleet optimization mindset.” One plant might be constrained while another has more flexibility—sometimes for regional reasons, such as differing prices or curtailment risk in different markets. “This fleet-level approach is what’s going to help operators allocate flexibility, manage this risk, and ultimately optimize the commercial performance across the full portfolio,” she said, “instead of just making that isolated asset or site-level decision.” Dietrich-Smith also pushed back on a common assumption about where the value comes from. “I think the most common misconception is that the only value we’re bringing is efficiency improvement,” she said. Customers also see fewer penalties, more effective participation in electricity markets, and faster response to changing conditions—benefits she summed up simply: “Time is money.” Renewables Complicate the Math A growing share of that fleet-level complexity traces back to renewables, Hanley said, whether a customer operates a hybrid portfolio directly or simply competes in a market where renewable penetration is rising. She described thinking in terms of dispatchable versus non-dispatchable generation: as more renewables come online, dispatchable options become scarcer, making it harder to maintain grid stability—and more important to predict when instability might occur. That prediction problem pulls in weather and market data alike, from cloud cover and wind speeds at different altitudes to real-time electricity prices. For a hybrid site with battery storage, the same data informs decisions about when to charge from onsite generation versus the grid, and when to discharge—sometimes purely to arbitrage low prices rather than to support the site’s own generation. “These batteries are creating dispatchable flexibility when normally we would only be able to do that with some of our large gas assets,” Hanley said, adding that customers are increasingly weighing a battery discharge against ramping up a plant or duct burning, based on which is the better economic call in the moment. Hanley closed the conversation on a practical note for listeners still weighing where to start. “Everything is only getting more complex, so give us a call,” she said.

Public power utilities have long promised lower bills, reliable service, and decisions made close to home—and the data still backs that up. But holding that ground is getting harder. In this episode of The POWER Podcast, Scott Corwin, president and CEO of the American Public Power Association (APPA), talks about the forces now testing the community-owned utility model. Corwin explains why resource adequacy, reliability, and affordability have converged into the defining challenge for APPA's roughly 2,000 member systems—a concern that once affected only certain regions but now stretches across nearly the entire membership. He breaks down the tools public power uses to keep rates down, including tax-exempt financing and elective pay credits, and why local control itself acts as a check on spending. The conversation also digs into the issues reshaping the sector: how smaller utilities are evaluating massive data center interconnection requests while protecting ratepayers; why Corwin describes public power's generation strategy as "any of the above" rather than "all of the above"; and the structural headwinds—permitting delays, an aging workforce, supply chain strain, and cybersecurity—that determine what utilities can build and how fast. Corwin closes with what he most wants policymakers to understand about community-owned utilities, and the value of 2,000 diverse communities speaking with one voice on affordability and reliability. Listen to the full conversation to hear how public power is navigating one of the most dynamic periods the industry has faced in years.

A perfect storm is brewing across the U.S. power generation fleet. Between 600 and 700 GE 7FA gas turbines installed during the bubble of 2000–2004—plus roughly 900 7EA units worldwide—are simultaneously approaching the OEM's 144,000-hour, 5,000-start end-of-life threshold. Superalloy forgings carry multi-year lead times. Only a handful of shops worldwide can service these machines. And the data center boom is pushing utilization higher than anyone planned for. In this episode, we sit down with three MD&A leaders driving the company's push to become an independent alternative for 7FA and 7EA rotor life extensions: • Dave Fernandes — Gas Turbine Program Manager • Kevin Roy — Principal Engineer, Parts • Jason Wheeler — Gas Turbine Rotor Repairs General Manager We trace the story from MD&A's early-2010s strategic pivot out of steam turbines and into gas turbines under then-CEO John Vanderhoef, through the acquisition of two never-fired machines—a 7FA.03 and a 7EA—that became the foundation of the reverse engineering effort. Kevin Roy explains why zero-hour components were essential, and why CMM and blue-light scanning only get you so far: coatings, shot peening, and surface finishes demand hands-on expertise no laser can replicate. We dig into the global hunt for vendors capable of producing high-temperature alloy forgings and holding tolerances on turbine-section components—a niche capability MD&A continues to expand for supply chain redundancy. Jason Wheeler walks through the quality regime: first-article scrutiny that carries into every production batch, with inspection standards more rigorous than what these vendors typically face elsewhere. The conversation turns to MD&A's seed rotor exchange program—modeled on its successful 7FH2 generator program—designed to compress customer downtime to removal, swap, and reinstall, with returned rotors entering the refurbishment cycle for the next customer. We also unpack what Fernandes calls "the three prongs": fleet-wide timing, multi-year forging lead times, and limited shop capacity worldwide. The conclusion is uncomfortable for operators who haven't started planning—parts needed three to five years from now must enter production today. Finally, we cover the milestone currently in MD&A's St. Louis shop: the first 7FA.03 rotor purchased specifically for the seed rotor program to complete the full production cycle, with newly manufactured wheels stacking perfectly alongside original serviceable components. And we discuss the 2026 delivery of a life-extended 7FA.03 rotor to a leading U.S. power producer—a vote of confidence from a famously risk-averse industry. Whether you're a utility planner staring down rotor end-of-life on your 7FA fleet, an asset manager weighing OEM dependence against supply chain risk, or an industry watcher tracking how independents are reshaping heavy-duty gas turbine services, this episode lays out where the bottlenecks are, what's been done about them, and why the window to act is narrowing fast.

Duke Energy operates 11 nuclear units across six sites in the Carolinas — a fleet that produces more than half of the region's electricity year in and year out. In 2025, that fleet posted its best capacity factor on record, north of 97%. In this episode of The POWER Podcast, Steven Capps, Duke Energy's senior vice president and chief nuclear officer, walks through what's behind that performance and what comes next. Capps frames Duke Energy's nuclear strategy as "today, tomorrow, and the future," and the conversation moves through all three. Topics covered: • How Duke Energy pushed its fleet capacity factor above 97% in 2025, and the role of risk management alongside maintenance and capital investment. • The subsequent license renewal program now extending Oconee and Robinson to 80-year operating lives, with Brunswick next in line and the rest of the fleet to follow. • Capacity uprates underway at McGuire and Catawba that, combined with measurement-uncertainty-recapture work at Oconee and Brunswick, will deliver roughly 300 MW of additional nuclear capacity — what Capps describes as "the equivalent of a small modular reactor." • The mechanical reality of an uprate: increased thermal megawatt ratings, more highly enriched fuel, and the secondary-side components — feedwater heaters, moisture separator reheaters, large pumps and motors — that have to be replaced to accommodate the change. • Duke Energy's decision-making framework for new nuclear, tentatively reflected in the integrated resource plan in 2037, and why economics, not technology choice, is the gating factor. • Career advice for engineers considering nuclear, from someone who has held more than 10 different roles across his own engineering career. Capps grew up about 10 miles from Oconee Nuclear Station, earned a mechanical engineering degree at Clemson, and joined Duke Energy after graduation. Twenty years at Oconee, a decade at McGuire, and most recently roles in Duke Energy's corporate organization have shaped his view of where the fleet — and the industry — go from here.

Nuclear energy is back — and this time, the momentum may be here to stay. In this episode of The POWER Podcast, Executive Editor Aaron Larson sits down with Dagmar Thien, who manages conventional island equipment for nuclear power plants at Siemens Energy, to explore what's driving the industry's renewed optimism and how the company is positioning itself at the center of the action. Thien, a physicist with two decades at Siemens Energy, breaks down the forces fueling the nuclear resurgence: surging global electricity demand, the need for reliable baseload power to back up intermittent renewables, and nuclear's strong climate credentials as a low-lifecycle-emission energy source. The explosive growth of data centers, which require uninterrupted power around the clock, has added particular urgency. The conversation spans the full spectrum of reactor technology — from gigawatt-scale plants that benefit from economies of scale, to small modular reactors (SMRs) promising faster, cheaper deployment through factory standardization, to Generation IV designs like high-temperature gas-cooled and molten salt reactors that could unlock industrial heat applications beyond electricity. Thien explains how Siemens Energy's broad turbine portfolio allows it to support virtually any reactor type. She highlights the value of whole-system optimization — collaborating with reactor developers to find the best overall plant performance rather than optimizing each side independently. The episode also covers the critical but often overlooked work of lifetime extension and modernization. With some U.S. plants pursuing 80-year operating licenses, upgrading turbines, generators, and control systems is essential. Thien discusses the Palisades Nuclear Generating Station — a landmark example of a decommissioned plant being brought back online — and the complex process of managing obsolescence in safety-qualified instrumentation and control systems used in roughly 23% of the world's reactors. Regulatory challenges, international harmonization efforts between the U.S., UK, and Canada, and the growing role of nuclear heat for industrial decarbonization round out a wide-ranging discussion on where the industry is headed next.

Corporate energy buyers have quietly become one of the most consequential forces shaping the U.S. electricity system. By the end of 2025, members of the Corporate Energy Buyers Association (CEBA) had procured more than 130 GW of carbon-free electricity in the U.S.—a footprint comparable to the combined generating capacity of California and Texas—and roughly double that globally. In this episode of The POWER Podcast, CEBA CEO Rich Powell joins POWER Executive Editor Aaron Larson for a wide-ranging conversation on how hyperscalers, manufacturers, retailers, and other large electricity users are responding to unprecedented demand growth and reshaping corporate procurement in the process. Topics covered include: • Why CEBA is "big tent" on clean technology, and how solar, nuclear, wind, geothermal, hydro, gas with carbon capture, and even fusion PPAs all figure into the mix • How AI-driven data center growth—and the chip fabs supplying them—are layering onto existing trends in electrification and internet expansion • The four-pronged nuclear revival: reactor restarts, license renewals, uprates, and advanced reactor bets on X-energy, Kairos, TerraPower, Oklo, and light-water SMRs • The Ratepayer Protection Pledge and how large buyers are addressing concerns that data centers push costs onto residential customers • Why ERCOT remains CEBA's "North Star" market, and how hybrid deals combining firm capacity with clean energy attributes are changing PPA structures • The rise of flexibility as a corporate procurement category, including demand-side management, on-site storage, and virtual power plants • How rising tariffs and supply chain inflation are squeezing solar, wind, and gas project economics • Powell's top policy ask: fundamental, legislatively codified reform of federal permitting and transmission planning A candid look at where the corporate clean energy market stands today—and what it will take to keep pace with the AI era.

After decades of flat electricity demand, the U.S. power sector is suddenly racing to keep up—and rural electric cooperatives are on the front lines. In this episode of The POWER Podcast, Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA), joins executive editor Aaron Larson to discuss how roughly 900 co-ops serving 42 million people across 48 states are navigating surging data center load, supply chain pressures, and a shifting regulatory landscape. Matheson explains what makes the co-op model distinctive—not-for-profit, consumer-owned, and locally governed—and why affordability isn't a talking point but an operational imperative for utilities that serve 92% of America's persistent poverty counties. He then digs into the generation debate, drawing a key distinction between always-available sources like coal, gas, and nuclear, and intermittent resources like wind and solar, and makes the case for local flexibility over federal one-size-fits-all mandates. Other topics covered in the conversation include: • Why Matheson believes viable power plants shouldn't be retired before replacement capacity is in place. • The long-term outlook for nuclear, the status of small modular reactors, and a notable Michigan plant restart driven by two co-ops. • Where energy storage fits today—and what a true long-duration breakthrough would unlock. • How global supply chain pressures and tariffs are driving up costs on everything from turbines to meters. • NRECA's 2026 policy priorities, including EPA rule rollbacks, permitting reform, raising the USDA Rural Utilities Service lending cap, and FEMA reform. • The contractual and operational complexity of onboarding hyperscale data center loads, and why existing consumers shouldn't subsidize them. • How roughly 200 co-ops are now bringing broadband to underserved rural areas—a modern echo of 1930s rural electrification. Whether you're tracking the AI-driven load boom, policy developments in Washington, or the unique role cooperatives play in the U.S. electric sector, this conversation offers a clear-eyed view from someone who represents member-owned utilities covering 54% of the nation's land mass.

Cassidy DeLine has spent more than 16 years developing renewable power plants. As the founder and CEO of Linea Energy, she's built an independent power producer with a pipeline exceeding 7 GW in roughly two years—a pace she calls "a bit unrivaled" for a company of its size and age. On this episode of The POWER Podcast, DeLine sits down with executive editor Aaron Larson to explain how Linea got there and where it's headed next. At the core of Linea's approach is a commitment to better information, earlier. Most developers don't get detailed site data, such as wetland boundaries, topography, and transmission characteristics, until after leases are signed and field teams are deployed. Linea has built proprietary simulations to surface that information before a single landowner conversation takes place, giving its team a sharper picture of risk before committing capital. That discipline extends to how the company handles offtake. Unlike most developers, Linea is comfortable advancing projects without a power purchase agreement (PPA) locked in. DeLine explains why signing a PPA too early can actually create risk, particularly in a market where tariff volatility and shifting capital costs have burned developers who fixed the revenue side before they had certainty on expenses. The conversation also covers Linea's growing role in the data center space. The company is doing bespoke energy development for data center operators and, in some cases, developing the data center itself. But DeLine is candid about the engineering challenges: artificial intelligence (AI) inference workloads cause demand to swing on a microsecond basis, which is fundamentally different from what the grid was built to handle. Linea has developed battery-and-inverter solutions to smooth those rapid fluctuations, guided by a simple principle: the lights have to stay on. DeLine shares her perspective on battery storage as a grid resource, the maturing but still incomplete renewable energy capital markets, the interconnection queue bottleneck, and what it means to commit to communities for a 40-year ownership horizon. She also discusses why Linea is evaluating small modular reactor technology—not because the economics work today, but because projects started now won't come online until the 2030s, and she wants to be ready for where the market is heading. Whether you're in development, finance, policy, or just following the energy transition, this is a conversation worth hearing.

After 22 years at IBM, where he rose to senior vice president and director of IBM Research, Dr. Dario Gil now leads one of the most ambitious science and technology initiatives in a generation. As the Department of Energy's (DOE's) Under Secretary for Science and director of the Genesis Mission, Gil is orchestrating a convergence of high-performance computing, artificial intelligence (AI), and quantum computing aimed at transforming how America does science and engineering. The Genesis Mission rests on a straightforward premise: a computing revolution is underway, and the U.S. should harness it to double the productivity of its trillion-dollar-a-year research and development engine within a decade. The initiative is built on three pillars: a platform for accelerating discovery anchored in high-performance computing, AI supercomputing, and quantum computing; a portfolio of national challenges in energy, physical sciences, and national security; and a university engagement effort to rethink how future scientists and engineers are educated in the age of AI. Gil offered fusion energy as a prime example of how AI can compress timelines. By training neural networks on validated simulation data, researchers can build surrogate models that run thousands to tens of thousands of times faster, allowing engineers to iterate on reactor designs in hours rather than months. AI is also being applied to real-time plasma control through collaborative work involving Google DeepMind and Commonwealth Fusion Systems. On the grid, Gil shared two striking examples. The DOE's Office of Electricity is developing AI agents to help developers fix deficient interconnection applications—which account for 80% to 90% of submissions—potentially accelerating studies by up to a year. Meanwhile, Brookhaven National Laboratory's Grid FM emulator can speed power flow calculations by 100x, compressing what would be 20 years of conventional analysis of the Texas transmission grid into roughly two months. Gil was candid about the tension between AI as an energy solution and AI as a source of surging electricity demand, noting that planned data centers now reach gigawatt scale. The path forward, he said, involves optimizing the existing grid, accelerating nuclear energy, investing in fusion, and driving major efficiency gains in AI hardware. New supercomputing infrastructure is already being built through the Genesis Consortium, a partnership of 27 industrial players. Argonne and Oak Ridge National Laboratories are each standing up large GPU clusters this year, with a 100,000-GPU system planned for Argonne in 2027—the largest science-oriented cluster in the world. Asked what success looks like, Gil pointed to the AlphaFold story: 50 years of work produced 200,000 protein structures, then AI predicted 200 million in two years. Success, he said, will mean 50 to 100 comparable breakthroughs across all domains of science within three to five years.

With federal tax credits under threat and regulatory stability in short supply, Bala Nagarajan, managing director of the energy investments team at S2G Investments, explained what he looks for in a company. "Is the product or the solution sold by this business cheaper, faster, better than the incumbent solution?" he asked. If so, it's worth considering. If not, the investment may not be a fit. His team heavily discounts any business case that depends on policy incentives. The message for entrepreneurs: build something that wins on its own economics first, and treat incentives as upside rather than a foundation. Speaking as a guest on The POWER Podcast, Nagarajan introduced the concept of "anti-fragile businesses"—companies whose value propositions can withstand geopolitical shocks, policy reversals, and economic downturns. His showcase example was Aerones, a portfolio company that uses robots to repair wind turbine blades. The thesis: there is an enormous existing fleet that needs maintenance, qualified technicians are scarce and expensive, and the work is dangerous. A robotic solution that is cheaper, faster, and safer represents exactly the kind of durable opportunity S2G seeks. For most of Nagarajan's 17-year career in energy, demand growth was gradual, tied to long-horizon electrification trends in homes, transportation, and manufacturing. AI data centers have compressed that timeline dramatically. The demand for new electrons "is knocking on our doors today," he said. This surge, combined with constrained supply, has created a dynamic that many believe will keep power prices high for a long time. S2G prefers skepticism. "What if things change?" Nagarajan asked. "How well will our underwrite hold up in the midst of potential changes?" Where is investor enthusiasm strongest? Grid-enhancing technologies. Rather than building new generation capacity, the market wants solutions that make the existing grid better—advanced conductors, grid-enhancing software, and solid-state transformers. Conversely, the "power-to-X" sector—green hydrogen, sustainable aviation fuel, and similar products relying on cheap clean electricity—is struggling as rising power prices undermine their economics. The gap between well-capitalized developers and smaller players is also widening. Only developers with deep balance sheets can afford to "Safe Harbor" equipment—purchasing materials early to lock in expiring tax credit incentives. Smaller developers are being forced to sell projects or abandon them, driving capital toward established brands. Nagarajan also suggested natural gas is no longer a bridge fuel. Given demand for gas turbines from hyperscalers and the signals from manufacturers like GE Vernova and Siemens Energy, gas is firmly embedded in the energy mix. The consequence, he argued, is that emissions will rise, driving significant demand for high-integrity carbon credits—a space he is personally bullish on. His overarching message is one of disciplined optimism. The energy sector is experiencing a rare convergence of rising demand, constrained supply, and deep pools of capital. But the winners will be those who resist underwriting to today's enthusiasm and instead back businesses that can thrive regardless of which way the policy winds blow.

The power industry's workforce crisis is well documented — an aging labor force, too few new recruits, and a surge of infrastructure investment that's only widening the gap. But on this episode of The POWER Podcast, two guests offer a practical blueprint for closing it. Derek O'Connor, Workforce Development Manager in the Office for Research and Innovation at Stony Brook University, and Rosalie Drago, Vice President for External Affairs and Strategic Engagement at Haugland Group, discuss the suite of workforce programs they've built together — from a paid summer experience for high school students called Taste of the Trades, to drone piloting certification, HVDC power systems training, an energy cybersecurity program, and EmpowerHER, a program designed to bring young women into the construction trades. Their model is built on a simple but powerful insight: many high school students need to earn income over the summer, which steers them toward retail and food-service jobs instead of career-building experiences. By braiding together government youth employment funding, industry sponsorship, and university research expertise, the Stony Brook–Haugland partnership pays students to explore energy and infrastructure careers — and then offers them a clear pathway from that first exposure all the way through college and into the workforce. O'Connor and Drago share real student success stories, explain how they've adapted their curriculum to a shifting energy landscape, and make the case that every community in the country already has the building blocks to replicate what they've done. They also discuss why investing in teacher training and community education delivers returns that go well beyond filling open positions.

S&P Global Energy's Global Power Markets Conference will be held April 13–15, 2026, at the Four Seasons Hotel in Las Vegas, Nevada. Learn more and register at: bit.ly/POWERPOD. Use the code POWERPOD at checkout to get a 10% discount on registration. The event returns at a pivotal moment for the energy sector. With national energy policy undergoing rapid transformation, federal incentives shifting, and geopolitical pressures reshaping global trade, the stakes for market participants have never been higher. From new tax structures to tariffs and a renewed emphasis on baseload generation, decision-makers are navigating profound changes that will impact the U.S. and global power markets. Join many of the industry's top experts in Las Vegas to network with energy executives from around the world and discuss the challenging volatility of the global financial markets, the opportunities available in transformative technologies, and all the latest topics impacting businesses. Get actionable insight from industry leaders, including: • Changing investor strategies as growing power demand transforms regional markets • Opportunities and advances in key technologies: new nuclear, renewables, battery storage, and carbon sequestration • Innovative financing models, M&A outlook, and public-private partnerships • New directions and critical changes in policy, impacting every energy industry. Be a part of the conversations shaping the future of power markets. Learn more and register at: https://bit.ly/POWERPOD. Use the code POWERPOD at checkout to get a 10% discount on registration.

Operators of aging F-class units face a narrowing window to plan for rotor life extensions as supply chains tighten and demand surges. The late 1990s and early 2000s marked a frenetic period in American power generation. Deregulation opened the floodgates for independent power producers racing to bring quick-build gas turbine plants online. GE’s 7FA and 7EA units became go‑to resources for this expansion, with the manufacturer more than tripling its annual heavy‑duty gas turbine production capacity to meet surging demand. Now, a quarter-century later, those turbines are approaching critical end-of-life thresholds—just as an artificial intelligence (AI)-driven surge in electricity demand is pushing them harder than ever. Industry experts warn that operators who fail to plan for rotor life extensions could find themselves in serious trouble. “If you’re not thinking two to three years down the road on your rotor, then you’re already behind, because that’s how long it’s going to take to manufacture those wheels,” Jason Wheeler, General Manager of Gas Turbine Rotor Repairs at MD&A, said as a guest on The POWER Podcast. A Perfect Storm of Constraints The urgency stems from a confluence of factors that have compressed the window for action. The 7FA fleet, which was deployed en masse during what industry veterans call “the bubble,” is now reaching the hour and cycle limits that the original equipment manufacturer (OEM) established for critical rotor components. At the same time, the power generation sector is experiencing a demand renaissance driven by data center construction and electrification. Dave Fernandes, MD&A’s Gas Turbine Program Manager, experienced the original boom firsthand as a GE field engineer specializing in 7F and 9F units from 1996 to 2001. He sees important differences between then and now. “There seems to be a lot more concrete reasons and a much stronger foundation for this current bubble than the previous one that took place two and a half decades ago,” Fernandes said. “There are a lot of things that are all stacking up at the same time that put more of an emphasis on getting out in front of extending the life of your current assets now, probably more than ever.” Supply chains have become particularly challenging. The specialized superalloy forgings required for turbine wheels are produced by a limited number of facilities worldwide, and those forging houses are simultaneously serving aerospace, military, and new power generation equipment markets. “You’re going to be competing with those new unit sales across various industries in an attempt to get in line with what is perceived from some angles as higher priorities,” Fernandes explained. “That further complicates the scenario that the customer base is facing when they’re trying to extend the rotor life of their existing assets.”

Rayburn Electric Cooperative faced three years of power costs in five days during the 2021 storm. The experience transformed the organization’s approach to risk, generation assets, and long-term planning. When Winter Storm Uri swept across Texas in February 2021, Rayburn Electric Cooperative found itself staring down a crisis that would reshape the organization’s entire operational philosophy. The generation and transmission cooperative, which serves approximately 625,000 Texans across 16 counties northeast of Dallas, incurred three years’ worth of power costs in just five days. “Bankruptcy was certainly one of the options on the table,” David Naylor, president and CEO of Rayburn Electric Cooperative, said as a guest on The POWER Podcast. “We were thankful we didn’t have to go that route. We were able to come up with a solution where we paid everything we owed—and then we took a hard look in the mirror and asked ourselves what we needed to do differently.” That self-evaluation led to strategic decisions that fundamentally shifted Rayburn’s power supply operations, transforming the cooperative from an organization with minimal owned generation resources into one that now owns and operates a major power plant—with another under construction. From Crisis to Acquisition Within two years of Uri, Rayburn acquired the Panda Sherman Power Plant, a 758-MW natural gas–fired combined cycle facility located just outside the cooperative’s service territory. The acquisition doubled Rayburn’s balance sheet, but Naylor said the plant checked critical boxes that emerged from the cooperative’s post-Uri analysis. “When we looked at who benefited from Uri—or at least came out of it in a solid situation—it was the people who owned generation assets, and whose units ran,” Naylor explained. “The Panda Sherman plant performed great during Winter Storm Uri. It had room for additional capacity if we wanted to expand in the future. And for someone that was staring bankruptcy in the face a couple years earlier, winning that auction over several private equity companies was a tremendous success.” Building for Growth One concern Rayburn had when acquiring the Panda Sherman plant—now called Rayburn Energy Station (RES)—was its size. Leadership initially projected the cooperative wouldn’t grow into the plant’s capacity until 2030 or later. That timeline proved wildly optimistic. “We’re projecting 25% growth over the next 10 years, and that’s not counting any data centers or large loads—just normal organic growth,” Naylor said. “We grew into Rayburn Energy Station a lot faster than we anticipated.” That rapid growth prompted Rayburn to begin construction on a second gas plant at the same site. The cooperative secured turbines and transformers under contract in late 2024, with a commercial operation date targeted for June 2028. According to Naylor, the timing proved fortuitous: suppliers indicated that waiting just a couple more months would have resulted in significantly higher costs and delivery dates pushed out by three to four years. The project is supported in part by the Texas Energy Fund, a $10 billion pool of low-cost loans created by the Texas Legislature after Uri to incentivize new dispatchable generation. Of more than 125 initial applicants, only 17 were selected to advance—and Rayburn is the only cooperative among them.