Show Notes
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.
More from The POWER Podcast
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.
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.
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