The POWER Podcast

In mid-January, scientists who maintain the world’s temperature records announced that 2023 was the hottest year on record. NASA researchers say extreme weather across the planet, including heat extremes, wildfires, droughts, tropical cyclones, heavy precipitation, floods, high-tide flooding, and marine heat waves, will become more common and severe as the planet warms. That’s a big problem for power grids, because extreme weather often causes outages and damage to grid assets. Michael Levy, U.S. Networks lead and Global Head of Asset Resilience at Baringa Partners, a global management consulting firm, is highly focused on extreme weather risks and developing plans to help mitigate the threats. He suggested accurately forecasting dollars of risk at the asset level from extreme weather events is very important to his clients. “Every facility all across the U.S. is having a heightened awareness of some of these extreme weather events, and more importantly, how they can protect themselves and their customers against those in the future,” Levy said as a guest on The POWER Podcast. “Utilities have always been really good, generally, at keeping the lights on and maintaining a fair level of reliability,” said Levy. “In general, they’re making the right investments—they have the right ambitions—but what’s challenging about these extreme weather events is that because they’re so infrequent at individual locations, and the impacts are so severe, what we find is that utility clients often are really challenged to estimate those high-impact, low-frequency events, and integrate them into their investment plans.” However, Levy said advances in attribution climate science are helping utilities overcome some of the challenges. “Scientists are now able to associate, with reasonable level of accuracy, what increasing warming means physically for the rest of the world in terms of how the frequency and severity of these extreme weather events may change,” he explained. “One of the big things that we focus on with our utility clients is converting those climate forecasts into dollars of risk, and that way, it gives them an adjustable baseline that they can substantiate spend against,” said Levy. “If you’re undergrounding lines to protect them against wildfire, elevating substations to protect them against flooding, all of those things cost money, and we’re increasingly seeing regulators—they want to see the benefits, they want to see that the money is being spent prudently. So, that’s what we’re talking to our clients about today,” he said. And utilities have proven that sound planning does pay off. Levy pointed to actions taken in Florida following particularly active and intense hurricane seasons in 2004 and 2005. Soon thereafter, the Florida Public Service Commission adopted extensive storm hardening initiatives. Wooden pole inspection and replacement programs were adopted, and vegetative remediation solutions were implemented, vastly improving grid reliability. Additionally, investor-owned electric utilities were ordered to file updated storm hardening plans for the commission to review every three years. However, the proof is in the pudding, and for Florida, grid hardening has tasted very good. Levy compared the effects experienced from Hurricane Michael in 2018 to those of Hurricane Ian in 2022. “When Ian came, despite being a bigger and stronger hurricane, they had no transmission lines down, which, of course, are very costly and time intensive to replace, and they were able to restore customers three times as fast, despite having more customers out. So, they’re experiencing what we like to call at Baringa ‘the rewards of resilience,’ because investing in resilience is a fraction of restoration costs,” said Levy.

The National Renewable Energy Laboratory (NREL) explains that community solar, also known as shared solar or solar gardens, is a distributed solar energy deployment model that allows customers to buy or lease part of a larger, off-site shared solar photovoltaic (PV) system. It says community solar arrangements allow customers to enjoy advantages of solar energy without having to install their own solar energy system. The U.S. Department of Energy says community solar customers typically subscribe to—or in some cases own—a portion of the energy generated by a solar array, and receive an electric bill credit for electricity generated by their share of the community solar system. It suggests community solar can be a great option for people who are unable to install solar panels on their roofs because they are renters, or because their roofs or electrical systems aren’t suited to solar. The Solar Energy Industries Association (SEIA) reports 6.5 GW of community solar capacity has been installed in the U.S. through the 1st quarter of 2024. Furthermore, SEIA predicts more than 6 GW of community solar capacity will be added over the next five years. It says 41 states, plus the District of Columbia, have at least one community solar project online. “These programs are very attractive and provide a lot of benefit to a whole range of consumers,” Nate Owen, CEO and founder of Ampion, said as a guest on The POWER Podcast. Ampion currently manages distributed generation projects for developers in nine states, with new states being added as more programs become active. “It’s fundamentally a different way of developing energy assets,” Owen said. “These things [community solar farms] are their own asset class. They produce a very significant value because they are generally located closer to load, and so, they fortify and strengthen local distribution networks quite a bit. And right now, they are very popular—there’s quite a bit of development going on in states across the country that have put programs in place.” Owen specifically mentioned Colorado, Illinois, Maine, Maryland, Massachusetts, Minnesota, New Jersey, and New York as states with active community solar programs. “There’s a lot of activity going on in a lot of states right now,” he said. According to Owen, community solar saves customers money. “The contract structure of community solar means that, ultimately, everybody’s guaranteed savings,” he said. “Nearly every community solar contract we’ve ever done has been provided at a percent off the value of the utility bill credit. So, at its essence, we are selling dollars’ worth of utility bill credits for 90 cents, and so, you automatically save money.” Contract terms often vary from project to project and state to state. “I think residential customers these days are generally signing contracts that are at least a year, if not three or five in some cases,” explained Owen. He noted that some states, such as Maine and New York, have a statutory 90-day termination notice clause for residential customers, so it doesn’t really matter how long the term is because subscribers have the right to terminate deals when they choose. In such cases, Owen said the “replaceability feature” of community solar is vital to success. “We can drop a customer and replace them—and we do,” he said.

If you have paid any attention to nuclear power plant construction projects over the years, you know that there is a long history of cost overruns and schedule delays on many of them. In fact, many nuclear power plants that were planned in the 1960s and 1970s were never completed, even after millions (or billions) of dollars were spent on development. As POWER previously reported, by 1983, several factors including project management deficiencies prompted the delay or cancellation of more than 100 nuclear units planned in the U.S.—nearly 45% of total commercial capacity previously ordered. Yet, at least one construction expert believes nuclear power plants can be built on time and on budget. “To me, nuclear should be far, far more competitive than it is,” Todd Zabelle, a 30-plus-year veteran of the construction industry and author of the book Built to Fail: Why Construction Projects Take So Long, Cost Too Much, and How to Fix It, said as a guest on The POWER Podcast. Owners have a big role to play in the process. “The owner has to get educated on how to deliver these projects, because the owner gets the value out of any decisions that are made,” Zabelle said. “You cannot just hand it over to a construction management firm and hope for the best, or EPCM [engineering, procurement, construction, and management firm]. It’s just not going to work.” “What it boils down to is a lot of people doing a lot of administrative work—people watching the people doing the technical work or the craft work—and we become an industry of bureaucracy and administration,” said Zabelle. “Everyone’s forgot about ‘How do we actually do the work?’ That has huge implications because of the disconnect between those two.” According to Zabelle, the problem can be solved by implementing a production operations mentality. “My proposal in all this is: we need way more thinking about operations management, specifically operations science,” he said. “Not that it’s what happens after the asset’s delivered, but it’s actually a field of knowledge that assists with how to take inputs and make their outputs. The construction industry doesn’t understand anything about operations—they don’t understand the fundamentals.” In Zabelle’s book, he provides a more thorough explanation of the concept. “Operations science is the study of how to improve and optimize processes and systems to achieve the desired objectives. It involves the use of mathematical models and other techniques to analyze and optimize systems,” he wrote. “It is used to improve efficiency and reduce costs, while ensuring that the quality of the output remains high. Operations science is used to improve the effectiveness of operations, while also reducing waste and improving customer satisfaction.” Near the end of his book, Zabelle noted that the time for business as usual is rapidly closing. “The pain of the status quo in construction is going to increase exponentially as our capacity to develop and execute projects falls short of expectations,” he wrote. “Until we recognize projects as production systems and use operations science to drive project results, we are doomed to failure. We need to free ourselves from the prior eras and instead focus on a new era of project delivery, one in which projects will be highly efficient production systems that utilize the bounty of the technology (AI [artificial intelligence], robotics, data analytics, etc.) we are privileged to have access to.” Zabelle sounded hopeful about the future of nuclear power construction. “I truly believe—I would actually throw down the gauntlet—we can make the Westinghouse AP1000 financially viable,” he said. “I’m happy to work with anybody on how to make nuclear competitive because I think it should be and could be.”

It seems everywhere you go, both inside and outside of the power industry, people are talking about hydrogen. Last October, the U.S. Department of Energy (DOE) announced an investment of $7 billion to launch seven Regional Clean Hydrogen Hubs (H2Hubs) across the nation and accelerate the commercial-scale deployment of “low-cost, clean hydrogen.” Hydrogen is undoubtedly a valuable energy product that can be produced with zero or near-zero carbon emissions using renewable energy and electrolyzers. The Biden administration says it “is crucial to meeting the President’s climate and energy security goals.” “Hydrogen is one of the hottest topics in the energy transition conversation right now, and that’s because it really is a super versatile energy carrier. A lot of folks refer to it as ‘the Swiss Army knife of decarbonization,’ including our founder, Mr. Gates,” Robin Millican, senior director of U.S. Policy and Advocacy at Breakthrough Energy, said as a guest on The POWER Podcast. Breakthrough Energy is a network of entities and initiatives founded by Bill Gates, which include investment funds, philanthropic programs, and policy efforts linked by a common commitment to scale the technologies needed to achieve a path to net-zero emissions by 2050. “If you think about the ways that you can use hydrogen, you can use it as a feedstock for industrial materials, you can combine it with CO2 to make electrofuels [also known as e-fuels], you can use it for grid balancing if you’re storing it and then deploying that hydrogen when it’s needed, so it can be used a lot of different ways, which is great,” Millican said. “But actually, to us, the more salient question that we should be asking ourselves is: you can use hydrogen in a lot of these different ways, but should you be using hydrogen in all of those different applications?” Millican said there’s a simple framework that she uses to answer that question. “If there’s a way that you can electrify a process, in almost all cases, that’s going to be cheaper and more efficient from an energy conversion standpoint than using hydrogen,” she said. Millican suggested electrification is a better option than hydrogen for most building and light-duty transportation applications. While noting that hydrogen could be a suitable option for aviation e-fuels, she said biofuels might be an even better fit. However, when it comes to fertilizers and ammonia, clean hydrogen is very likely the best pathway to reducing emissions in that particular sector, she said. Breakthrough Energy isn’t the first group to think about hydrogen in this way. Millican noted that Michael Liebreich’s “Hydrogen Ladder” has been focusing on the best possible uses for hydrogen for years. According to Liebreich, hydrogen shouldn’t routinely be used in power systems to generate power because the cycle losses—going from power to green hydrogen, storing it, moving it around, and then using it to generate electricity—are too large. However, he says, “The standout use for clean hydrogen here is for long-term storage.” Yet, Millican said there is a scenario where hydrogen could be extremely affordable at scale. She said “geologic hydrogen” is something Breakthrough Energy is very interested in. “There are companies out there that are working on identifying where hydrogen exists naturally in the subsurface, and then trying to extract that hydrogen, which could be super affordable, because again, it’s abundant in some areas,” she explained. “If we’re thinking about hydrogen in that scenario, we might want to use it a lot more ubiquitously.”

Climate change has led many states and countries to set targets for reducing greenhouse gas (GHG) emissions from power systems. Oregon, for example, has set targets for all power sold to retail customers in the state to have GHG emissions cut by 80% by 2030, 90% by 2035, and 100% by 2040. It’s a challenging task, but Portland General Electric (PGE), a fully integrated energy company that generates, transmits, and distributes electricity to roughly half of Oregon’s population, and for about 75% of its commercial and industrial activity, is working hard to achieve those objectives. As the first utility in the U.S. to sign The Climate Pledge, an initiative co-founded by Amazon and Global Optimism in 2019, which has since had 464 signatories join, committing to reach net-zero carbon emissions by 2040, PGE is leading the way toward a cleaner energy future. Kristen Sheeran, senior director of sustainability, strategy, and resources planning at PGE, said the process is pretty straightforward in some ways. “In order to reduce carbon on our system, we have to back out fossil fuels that we currently rely on to generate power for our customers, and we have to replace that with non-emitting alternatives,” she said as a guest on The POWER Podcast. Up to this point in time, that has primarily been done with wind, solar, and batteries, and it’s not a new thing for PGE. The company’s first wind farm—the Biglow Canyon site—began operation in 2007. Meanwhile, in 2012, PGE opened the Camino del Sol Solar Station, an interstate highway solar project. Since then, the company has partnered with schools, government agencies, and corporations to grow solar energy throughout Oregon. In partnership with NextEra Energy Resources, it also opened North America’s first major renewable energy facility to combine wind, solar, and battery storage in one location—the Wheatridge Renewable Energy Facility in Morrow County. Today, PGE boasts having more than 1 GW of wind power capacity in service in the Northwest, and it aims to procure between 3.5 GW and 4.5 GW of new non-emitting resources and storage between now and 2030. Perhaps more difficult than decarbonizing the system, however, is doing so while also maintaining reliability, affordability, and an equitable system for all its customers. “It’s a very interesting point in time—an inflection point for the industry,” Sheeran said. “How do you balance affordability? How do you balance reliability with emissions reduction?” she asked. PGE closed its last Oregon-based coal-fired power plant in October 2020, 20 years ahead of schedule, as part of an agreement with stakeholders, customer groups, and regulators to significantly reduce air emissions from power production in Oregon. PGE still receives a small amount of coal-fired power from the Colstrip plant, which is located near Billings, Montana. The company has an ownership stake in the facility, but it plans to exit its ownership in Colstrip no later than 2029. Brett Greene, PGE’s senior director of clean energy origination and structuring, suggested striking the right energy balance will take more than just wind and solar, however. “We are supportive of all technology. We really think it takes a lot of innovation and creativity to hit that net-zero goal in 2040,” he said. Greene noted that resources such as hydro, pumped storage, offshore wind, and even nuclear, hydrogen, and carbon capture technologies may ultimately be needed to fully decarbonize PGE’s power mix.

Boilers obviously play an important role in the power generation industry, providing the mechanism to convert heat produced by burning fuel into steam that can be used to drive a turbine to generate electricity. But many other industries also use boilers to produce steam for a variety of purposes. Boilers are commonly used for space heating in industrial facilities, including in factories, warehouses, and office buildings, as well as on university campuses and in large medical complexes. Boilers often provide hot water or steam, which is then distributed throughout buildings using radiators, convectors, or underfloor heating systems, to heat the air. Many industrial processes utilize high-temperature steam for manufacturing operations. Boilers are regularly used for processes such as chemical manufacturing, food processing, paper production, and textile manufacturing. Boilers are also essential in petroleum refineries for processes like distillation, cracking, and reforming. Steam can also be used as a source of energy for industrial processes such as sterilization, cleaning, and drying. In some cases, cogeneration (also called combined heat and power) systems are utilized to first generate electricity, and then, extraction steam is diverted for other purposes. This can greatly improve the overall system efficiency, saving money and reducing emissions. Rentech Boiler Systems Inc. is one of the leading manufacturers of custom water tube and waste heat recovery boilers. The company is headquartered in Abilene, Texas, but sells its boilers around the world. “We have shipped boilers to about 35 countries in the world. So, we’re a company known globally,” Gerardo Lara, vice president of Fired Boiler Sales with Rentech, said as a guest on The POWER Podcast. “I think our best feature at Rentech is that we build only custom solutions,” Jon Backlund, senior sales engineer with Rentech, said on the podcast. “We don’t have a catalog of standard sizes or standard designs. So, we will basically custom fit the application, and that means, we will read the specifications carefully, talk to the client about special needs, special fuels, any kind of space constraints, delivery issues, and design our system to fit exactly what they require.” Rentech typically manufacturers boilers with capacities ranging from about 40,000 lb/hr to 600,000 lb/hr of steam. Moving boiler systems of that size—which can weigh up to half a million pounds—from a manufacturing facility to a site can be challenging, but Lara suggested Rentech is very proficient at the task. “There is a wide range of logistics that have to be studied, and yes, we live in the middle of Texas, but we certainly are very well versed on how to get a big boiler to Australia, if need be,” he said. “If we can do that, we certainly can get one to any state here within the U.S., or even Canada or Mexico.” The fuel used to fire boilers can vary widely. Natural gas is very common in the U.S. because it is highly available and relatively inexpensive, but many other fuels are also suitable for industrial boilers. Backlund said there are a lot of “opportunity fuels” available in different locations. For example, landfill gas can be captured and utilized at many landfills. Likewise, biogas from brewing or sewage treatment processes are also usable. Many experts believe hydrogen will be an important fuel as the world transitions to greater carbon-free energy resources. Backlund said hydrogen has been burned in boilers for decades. “There’s a lot of talk about equipping our boilers to burn hydrogen in the future, but this is not a new technology in the boiler business,” he said. “Those kinds of plants have been around for generations.” Where the hydrogen comes from and how it is produced may change, but today’s boilers are already capable of utilizing hydrogen efficiently.

According to a guidebook issued by Sandia National Laboratories, a U.S. Department of Energy (DOE) multi-mission laboratory, microgrids are defined as a group of interconnected loads and distributed energy resources (DERs) that act as a single controllable entity. A microgrid can operate in either grid-connected or island mode, which includes some entirely off-grid applications. A microgrid can span multiple properties, generating and storing power at a dedicated/shared location, or it can be contained on one privately owned site. The latter condition, where all generation, storage, and conduction occur on one site, is commonly referred to as “behind-the-meter.” Microgrids come in a wide variety of sizes. Behind-the-meter installations are growing, especially as entities like hospitals and college campuses are installing their own systems. Where some once served a single residence or building, many now power entire commercial complexes and large housing communities. “Today, there’s a whole new way to do DER management, which is a significant component of microgrids,” Nick Tumilowicz, director of Product Management for Distributed Energy Management with Itron, said as a guest on The POWER Podcast. “There is a way now to do that in a very local, automated, and cost-effective way just by leveraging what utilities have already deployed—hundreds of thousands of meters and the mesh networks that are communicating with those meters.” Tumilowicz said a variety of factors can influence if and/or when a microgrid gets deployed. Sometimes, a company is focused on running cleaner and greener operations. Other times, the grid a company is connected to may have reliability challenges that are affecting business adversely, or the company may just want to be energy independent, so the decision is frequently case specific. “The customer has this motivation to have this backup concept known as resiliency—if the grid’s not there for me, I’ll be there for me,” he said. “Generally speaking, nationally, we’re well above 99.9% grid reliability,” Tumilowicz noted. Yet, even when power outages are rare, a microgrid can still provide value. “It can provide flexible services, such as capacity or resource adequacy, or energy services back to the distribution and the transmission up to the market operator level,” explained Tumilowicz. “So, this is a whole other way to be able to start thinking about how we participate with microgrids when 99-plus percent of the time they’re grid connected, but they’re also there for when the grid is not connected—in that very low probability of time.” However, the return on investment for microgrid systems is highly affected by location. “If you’re in Australia, the equation is different than if you’re in Hawaii, versus if you’re in the northeast U.S.—one of the better-known accelerated paybacks to do this,” said Tumilowicz. For example, in areas where the market operator, such as an independent system operator or regional transmission organization, places a high value on peak power reductions within its system, the economics for microgrid owners can be greatly improved. But regardless of what may have driven the initial decision to create a microgrid, Tumilowicz said being flexible is important. “You might deploy your microgrid to satisfy three use cases and market mechanisms that exist in the beginning of 2024, but you need to be open and receptive—and this is where the innovation comes in—to add use cases over time, because the system is going through a significant energy transition, and you need to be dynamic and accommodating to do that,” he said.

Concrete is the most widely used construction material in the world. One of the key ingredients in concrete is Portland cement. The American Concrete Institute explains that Portland cement is a product obtained by pulverizing material consisting of hydraulic calcium silicates to which some calcium sulfate has usually been provided as an interground addition. When first made and used in the early 19th century in England, it was termed Portland cement because its hydration product resembled a building stone from the Isle of Portland off the British coast. Without going into detail, it suffices to say that a great deal of energy is required to produce Portland cement. The chemical and thermal combustion processes involved in its production are a large source of carbon dioxide (CO2) emissions. According to Chatham House, a UK-based think tank, more than 4 billion tonnes of cement are produced each year, accounting for about 8% of global CO2 emissions. However, fly ash from coal-fired power plants is a suitable substitute for a portion of the Portland cement used in most concrete mixtures. In fact, substituting fly ash for 20% to 25% of the Portland cement used in concrete mixtures has been proven to enhance the strength, impermeability, and durability of the final product. Therefore, using fly ash for this purpose rather than placing it in landfills or impoundments near coal power plants not only reduces waste management at sites, but also reduces CO2 emissions and improves concrete performance. Rob McNally, Chief Growth Officer and executive vice president with Eco Material Technologies, explained as a guest on The POWER Podcast that the ready-mix concrete industry has been reaping the benefits of using fly ash for years. “In terms of economics, fly ash was typically cheaper than Portland cement. It also has beneficial properties that typically makes it stronger long term and reduces permeability, which keeps water out of the concrete mixture and helps concrete to last longer. And, then, it’s also environmentally friendly, because they’re using what is a waste product as opposed to more Portland cement—and Portland cement is highly CO2 intensive. For every tonne of Portland cement produced, it’s almost a tonne of CO2 that’s introduced into the atmosphere. So, they have seen those benefits for years with the use of fresh fly ash,” McNally said. However, as climate change concerns have grown, many power companies have come under pressure to retire coal-fired power plants. As plants are retired, fresh fly ash has become less and less available. “The availability of fresh fly ash is declining,” said McNally. “In some places—many places actually—around the country, replacement rates that used to be 20% of Portland cement was replaced by fly ash are now down in single digits. But that’s a reflection of fly ash availability.” Eco Material Technologies, which claims to be the leading producer of sustainable cementitious materials in the U.S., has a solution, however. It has developed a fly ash harvesting process and has nine fly ash harvesting plants in operation or under development to harvest millions of tons of landfilled ash from coal power plants. Locations include sites in Arizona, Georgia, North Dakota, Oregon, and Texas. “There are billions—with a b—of tons of impounded fly ash around the country, so we have many, many years of supply,” McNally said. Still, Eco Material is not resting its business solely on fly ash harvesting, or marketing fresh fly ash, which it has also done for years. “The other piece where we will fill the gap that fresh fly ash leaves behind is with the green cement products. Because with those, we’re able to use natural pozzolans, like volcanic ash, and process those and replace 50% plus of Portland cement in concrete mixes. So, we think there’s an answer for the decline in fly ash and that’s where the next leg of our business is taking.”

There is growing demand for cybersecurity professionals all around the world. According to the “2023 Official Cybersecurity Jobs Report,” sponsored by eSentire and released by Cybersecurity Ventures, there will be 3.5 million unfilled jobs in the cybersecurity industry through 2025. Furthermore, having these positions open can be costly. The researchers said damages resulting from cybercrime are expected to reach $10.5 trillion by 2025. In response to the escalating demand for adept cybersecurity professionals in the U.S., the Department of Energy (DOE) has tried to foster a well-equipped energy cybersecurity workforce through a hands-on operational technology cybersecurity competition with real-world challenges. On Nov. 4, the DOE hosted the ninth edition of its CyberForce Competition. The all-day event, led by DOE’s Argonne National Laboratory (ANL), drew 95 teams—with nearly 550 students total—from universities and colleges across the nation. This year the focus was on distributed energy resources including solar panels and wind turbines. “The CyberForce Competition comes out of the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response, which is CESER for short,” Amanda Theel, group leader for workforce development at ANL, said as a guest on The POWER Podcast. “Their main goal for this is really to help develop the pipeline of qualified cybersecurity applicants for the energy sector. And I say that meaning, we really dive heavily on the competition and looking at the operational technology side, along with the information technology side.” Theel said each team gets about six or seven virtual machines (VMs) that they have to harden and defend to the best of their ability. Besides monitoring and protecting the VMs, which include normal business systems such as email and file servers, the teams also have to defend grid operations and other energy resources. “We have a Red Team that’s constantly trying to either come into the system from your regular attack-defend penetration. We also have a portion of our Red Team that we like to call our ‘assumed breach,’ so we assume that adversary is already in the system,” Theel explained. “The Blue Team, which is what we call our college students, their job is to work to try to get those Red Team members out.” She said they also have what they call “our whack-a-mole,” which are vulnerabilities built into the system for the Blue Team members to identify and patch. Besides the college students, ANL brings in volunteers—high school students, parents, grandparents, people from the lab, and people from the general public—to test websites and try to pay pretend bills by logging in and out of the simulated systems. Theel said this helps students understand that while security is important, they must also ensure that owners, operators, and end-users can still get in and use the systems as intended. “So, you have to kind of play the balance of that,” she said. Other distractions are also incorporated into the competition, such as routine meetings and requests from supervisors, for example, to review a forensics file and check the last time a person in question logged into the system. The intention is to overload the teams with tasks so evaluators can see if the most critical items are prioritized and remedied. For the second year in a row, a team from the University of Central Florida (UCF) won first place in the competition (Figure 1). They received a score of 8,538 out of 10,000. Theel said the scores do vary quite significantly from the top-performing teams to lower-ranked groups. “What we’ve found is obviously teams that have returned year after year already have that—I’ll use the word expectation—of already knowing what to expect in the competition,” explained Theel. “Once they come to year two, we’ve definitely seen massive improvements with teams.”

Southern Nuclear, Southern Company’s nuclear power plant operations business, announced in late September that it had received “first-of-a-kind approval” from the Nuclear Regulatory Commission (NRC) to use advanced fuel—accident tolerant fuel (ATF)—exceeding 5% enrichment of uranium-235 (U-235) in Plant Vogtle Unit 2. The fuel is expected to be loaded in 2025 and will have enrichments up to 6 weight % U-235. The company said this milestone “underscores the industry’s effort to optimize fuel, enabling increased fuel efficiency and long-term affordability for nuclear power plants.” “5 weight % was deeply ingrained in all of our regulatory basis, licensing basis for shipment containers, licensing basis for the operation of the plants—it was somewhat of a line drawn in the sand,” Johnathan Chavers, Southern Nuclear’s director of Nuclear Fuels and Analysis, explained as a guest on The POWER Podcast. “Testing of the increased enrichment component has been a licensing and regulatory exercise to see how we would move forward with existing licensing infrastructure to install weight percents above that legacy 5 weight %,” Chavers told POWER. Chavers said ATF became a focal point for the industry in March 2011 following the magnitude 9.0 Tohoku-Oki earthquake and resulting tsunami, which caused a crisis at the Fukushima nuclear power plant. “In 2012, Congress used the term ‘accident tolerant fuel’ for the first time in an Appropriations Act, and that’s where it all began,” Chavers explained. “It was really for the labs and the DOE [Department of Energy] to incentivize enhanced safety for our fuel in response to the Fukushima incident.” In 2015, the DOE issued a report to Congress outlining details of its accident tolerant fuel program. The report, titled “Development of Light Water Reactor Fuels with Enhanced Accident Tolerance,” set a target for inserting a lead fuel assembly into a commercial light water reactor by the end of fiscal year 2022. Notably, Southern Company achieved the goal four years early. “We were the first in the world to install fueled accident tolerant fuel assemblies of different technologies that were developed by GE at our Hatch unit in 2018,” Chavers noted. The following year, Southern Nuclear installed four Framatome-developed GAIA lead fuel assemblies containing enhanced accident-tolerant features applied to full-length fuel rods in Unit 2 at Plant Vogtle. “This is the third set that we’re actually installing that is a Westinghouse-developed accident tolerant fuel, which also includes enrichments that exceed the historical limits of 5 weight %,” Chavers explained. While enhanced safety is perhaps the most significant benefit provided by ATF, advanced nuclear fuel is also important in lowering the cost of electricity. “Our ultimate goal is to enable 24-month [refueling] cycles for all U.S. nuclear power plants, to improve the quality of life for our workers, to lower the cost of electricity,” said Chavers. “Fundamentally, [nuclear power] is a clean green power source—carbon-free. The more we can keep it running—that’s something we’re trying to go after,” noted Chavers. “We see a lot of positives in this program in that not only are we improving safety, lowering the cost, but we’re also increasing the amount of megawatts electric we can get out of the nuclear assets.”