The POWER Podcast

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.

As electricity demand from data centers continues to surge, a persistent question has dogged the industry: Are residential ratepayers footing the bill for massive tech infrastructure? According to Amazon Web Services (AWS) and an independent study it commissioned, the answer is a definitive no.
As a guest on The POWER Podcast, Mandy Ulrich, senior manager of energy and water for Americas East at AWS, outlined the company’s energy strategy and discussed findings from a study by Energy and Environmental Economics Inc. (E3) that examined how Amazon data centers impact local power systems.
Study Finds Data Centers Generate Surplus Revenue
The E3 study evaluated Amazon data centers across a diverse set of utility territories, including large investor-owned utilities such as Pacific Gas and Electric (PG&E) and Dominion Energy, mid-size utilities like Entergy, and cooperatives such as Umatilla Electric Cooperative in the Pacific Northwest.
“The simple answer is that Amazon data centers are not being subsidized by other utility customers,” Ulrich said. The study projects that Amazon’s data centers will generate $33,500/MW of surplus value in 2025, increasing to $60,650/MW by 2030.
For a typical 100-MW Amazon data center, that translates to $3.4 million in surplus revenues in 2025 and approximately $6.1 million by 2030. These surplus funds—revenues above the utility’s regulated rate of return—can be used by utilities to modernize grid infrastructure, improving reliability for all customers.
Grid Investment Benefits All Customers
The study found that Amazon data centers are driving investments in grid infrastructure that support not just their own operations but also local residential and commercial growth. Ulrich pointed to Entergy Mississippi as a prime example, where the utility is using investments from Amazon and other large customers to fund a $300 million “Superpower Mississippi” grid reliability campaign—at no cost to residential customers—targeting a 50% reduction in outages within five years.
Innovative Rate Structures Prevent Cost-Shifting
While the E3 study validates that existing rate policies have been effective in preventing cross-subsidization, Ulrich emphasized that AWS continues to work with utilities on innovative approaches to ensure large industrial customers pay their fair share.
She highlighted a Northern Indiana Public Service Co. (NIPSCO) project as a “groundbreaking model.” Under this first-of-its-kind agreement, Amazon is investing in 3 GW of electrical capacity, with 2.4 GW dedicated to data center operations and 600 MW reserved specifically to support grid reliability for all NIPSCO customers.
The structure creates a separate generation company (GenCo) that operates under a “commercial contract term,” Ulrich explained. By operating as a separate entity, GenCo isolates the cost of new growth to data centers. “The data center companies that drive new demand for electricity will fund the generation and transmission infrastructure they require, ensuring that regular customers don’t shoulder those costs, even if the customer leaves before contract completion,” NIPSCO said in a Nov. 24 press release.
“NIPSCO’s existing customers will have no financial responsibility for powering Amazon data centers,” Ulrich said. NIPSCO said, “This structure is expected to provide value to customers by generating approximately $1 billion in cost savings that will be returned to current NIPSCO customers as credits on monthly electric bills over the project’s 15-year duration.”

As the global demand for clean energy intensifies, nuclear power is enjoying a resurgence not seen in decades. However, this renewed interest has exposed a critical vulnerability in the U.S. energy sector: a massive disconnect between uranium consumption and domestic production. As a guest on The POWER Podcast, Thomas Lamb, president and CEO of Myriad Uranium, discussed some of the complexities of the nuclear fuel cycle and how junior exploration companies are racing to secure America’s energy future.
The Great American Supply Deficit
To understand the urgency of the current uranium market, one must first grasp the sheer scale of consumption. A single large-scale nuclear reactor consumes approximately 400,000 to 500,000 pounds of uranium oxide concentrate (U3O8) annually, depending on design, capacity, and operating efficiency. The U.S. operates 94 commercial reactors today, resulting in a national consumption of roughly 37 million to 47 million pounds of U3O8 per year.
The domestic production figures, however, paint a starkly contrasting picture. “The United States consumes, for very round numbers, 50 million pounds of uranium per year, and produces a million pounds of uranium per year,” Lamb explained. To be more specific, the U.S. Energy Information Administration reported that domestic production of U3O8 was 677,000 pounds in 2024, and it’s been much lower than that in the not-too-distant past.
This imbalance creates a precarious reliance on foreign imports. Lamb noted that Kazakhstan alone produces more than 40% of the world’s uranium. More concerning for U.S. national security is the country’s reliance on Russia, where a surprisingly high percentage of U.S. reactor fuel bundles are sourced.
“You have a worldwide supply deficit, and then you have an enormous domestic production deficit in the United States relative to consumption. That makes the U.S. vulnerable,” Lamb said. “What if Kazakhstan, China, [and] Russia kind of work together? What if they cut off the United States? What if some other things happen? The U.S. could be short of uranium.”
Revitalizing History: The Copper Mountain Project
Myriad Uranium is positioning itself to fill this gap by revitalizing past assets rather than starting from scratch. The company’s flagship asset, the Copper Mountain Uranium Project in Wyoming, was a focal point of Union Pacific’s energy subsidiary in the 1970s.
Union Pacific invested approximately CA$117 million (in 2024 dollars, US$84.7 million) into the site, planning a large-scale mine to fuel reactors in Southern California that were ultimately never built due to the post-1979 nuclear freeze. Because the project was abandoned due to external market forces rather than a lack of resources, it represents a “brownfield” opportunity.
“In our case, we already know it’s there because a lot of the work was done,” Lamb said. “Now, we just have to … bring the information current,” he added.

The power industry is experiencing unprecedented demand growth, driven largely by data centers and artificial intelligence (AI) applications. This surge is creating both opportunities and challenges for utilities, equipment manufacturers, and the broader power generation ecosystem.
As a guest on The POWER Podcast, Seth Harris, growth director for Emerson’s Power business in North America, discussed how the company is helping the industry navigate this transformative period. With 20 years at Emerson across various roles, Harris brings a comprehensive perspective on the evolving needs of power generation facilities.
The Data Center Effect
The conversation around power generation has fundamentally shifted. Data centers are forcing utilities to rethink everything. “I’m focused on the power markets, but I can’t tell you the last time I was able to have a conversation about power without somehow referencing the data center aspect of it,” Harris said.
This demand is affecting multiple stakeholders simultaneously. Manufacturers of turbines, heat recovery steam generators, control systems, valves, and instruments are all facing unprecedented orders. The challenge extends beyond simply meeting demand. Companies must rapidly scale up manufacturing capabilities and engineering resources that have been stagnant for years.
Extending Plant Lifespans
Among the things that must be rethought are decisions on existing plant operations. In some cases, power plants that were previously scheduled for retirement are now being extended. “The ability to deliver power as quickly as possible is certainly top of mind as this kind of race to deliver on the technology promises coming from AI and the various use cases for data centers has really put those existing assets in a place where they have to focus on driving the most efficiency and reliability they possibly can,” said Harris.
However, many owners haven’t been investing in these plants beyond the necessities, which means upgrades are often needed to keep the plants operating efficiently. “The technology has come a long way since those facilities were originally built,” Harris explained. Furthermore, operational expectations are changing. Rather than operating as baseload units, these legacy facilities may now only be called on to provide peaking or backup power, which means control systems may need upgrades to accommodate for that as well. Harris said retrofitting existing plants “has been a bit of a boom from an Emerson standpoint.”