The POWER Podcast

There are several obstacles to overcome when building a clean-energy project, but perhaps the biggest is getting through the generator interconnection queue (GIQ). Every regional transmission organization (RTO) and independent system operator (ISO) in the U.S. has a significant backlog in its GIQ and processing interconnection requests can take years to complete. This has created a significant barrier to deploying renewable energy, as companies often face long wait times, and high costs for new transmission lines and other upgrades when the local grid is near or at capacity. Part of the problem is the complexity of the interconnection process, which involves multiple studies. The Midcontinent Independent System Operator (MISO) reports that historically about 70% of projects submitted to its queue ultimately withdraw, resulting in extensive rework and delays, as studies must be redone when projects withdraw. MISO recognizes change is necessary and has implemented some reforms. On Jan. 19, 2024, the Federal Energy Regulatory Commission (FERC) accepted MISO’s filing (ER24-340) to increase milestone payments, adopt an automatic withdrawal penalty, revise withdrawal penalty provisions, and expand site control requirements. These provisions were designed to help expedite the GIQ process, and maximize transparency and certainty. MISO said the filing was developed through extensive collaboration in the stakeholder process, including multiple discussions in the Planning Advisory Committee and Interconnection Process Working Group. MISO expects these reforms to reduce the number of queue requests withdrawing from the process. It said the fewer projects in studies, the quicker the evaluations can be completed, and the fewer projects that withdraw, the more certain phase 1 and 2 study results are. Still, it’s likely that more needs to be done to improve the GIQ process. The Clean Grid Alliance (CGA), a nonprofit organization that works to advance renewable energy in the Midwest, conducted a survey of 14 clean energy developers who’ve had solar, wind, hybrid, and battery storage projects in the MISO interconnection queue over the last five years to better understand the challenges they’ve faced. Aside from interconnection queue challenges, the CGA survey also identified other hindrances to clean-energy project development. Soholt explained that a lot of development work is done face to face. COVID prevented that, which was a big problem that had a ripple effect. Some leases that developers had negotiated began to expire, so they had to go back out to communities and renegotiate. “Siting in general is getting more difficult, as we do more volume, as we do transmission in the MISO footprint,” said Soholt. “We need new generation to be sited, we need new transmission, and we have to find a pathway forward on that community acceptance piece,” she said. Among other challenges, Soholt said some projects saw generator interconnection agreements (GIAs) timing out and needing MISO extensions. Meanwhile, transmission upgrade delays also presented problems, not only the large backbone transmission upgrades, but also the transmission owners building interconnections for individual projects to connect breakers, transformers, and other equipment. Soholt said longer and longer component lead times presented timing challenges, which were also problematic for developers. These were all important takeaways from the CGA survey, and items the group will work to resolve. Yet, for all the difficulties, Soholt seemed optimistic that MISO would continue to find ways to improve the process. “When we get overwhelmed, we really step back and say, ‘What’s going to be the best thing to work on to really make a difference?’ So far, that really has been the big things like transmission planning. We feel good about where that’s at in MISO—they are doing good long-range planning,” Soholt said.

Today, molten salt reactors (MSRs) are experiencing a resurgence of interest worldwide, with numerous companies and research institutions actively developing various designs. MSRs offer several potential advantages, including enhanced safety, reduced waste generation, and the ability to utilize thorium as a fuel source, as previously mentioned. “There are several molten salt reactor companies that are in the process of cutting deals and getting MOIs [memorandums of intent] with foreign countries,” Mike Conley, author of the book Earth Is a Nuclear Planet: The Environmental Case for Nuclear Power, said as a guest on The POWER Podcast. Conley is a nuclear energy advocate and strong believer in MSR technology. He called MSRs “a far superior reactor technology” compared to light-water reactors (LWRs). The thorium fuel cycle is a key component in at least some MSR designs. The thorium fuel cycle is the path that thorium transmutes through from fertile source fuel to uranium fuel ready for fission. Thorium-232 (Th-232) absorbs a neutron, transmuting it into Th-233. Th-233 beta decays to protactinium-233 (Pa-233), and finally undergoes a second beta minus decay to become uranium-233 (U-233). This is the one way of turning natural and abundant Th-232 into something fissionable. Since U-233 is not naturally found but makes an ideal nuclear reactor fuel, it is a much sought-after fuel cycle. “The best way to do this is in a molten salt reactor, which is an incredible advance in reactor design. And the big thing is, whether you’re fueling a molten salt reactor with uranium or thorium or plutonium or whatever, it’s a far superior reactor technology. It absolutely cannot melt down under any circumstances whatsoever period,” said Conley. Conley suggested that most of the concern people have about nuclear power revolves around the spread of radioactive material. Specifically, no matter how unlikely it is, if an accident occurred and contamination went airborne, the fact that it could spread beyond the plant boundary is worrisome to many people who oppose nuclear power. “The nice thing about a molten salt reactor is: if a molten salt reactor just goes belly up and breaks or gets destroyed or gets sabotaged, you’ll have a messed-up reactor room with a pancake of rock salt on the floor, but not a cloud of radioactive steam that’s going to go 100 miles downwind,” Conley explained. And the price for an MSR could be much more attractive than the cost of currently available GW-scale LWR units. “The ThorCon company is predicting that they will be able to build for $1 a watt,” said Conley. “That’s one-fourteenth of what Vogtle was,” he added, referring to Southern Company’s nuclear expansion project in Georgia, which includes two Westinghouse AP1000 units. Of course, projections do not always align with reality, so MSR pilot projects will be keenly watched to validate claims. There is progress being made on MSR projects. For example, in February 2022, TerraPower and Southern Company announced an agreement to design, construct, and operate the Molten Chloride Reactor Experiment (MCRE)—the world’s first critical fast-spectrum salt reactor—at Idaho National Laboratory (INL). Since then, Southern Company reported successfully commencing pumped-salt operations in the Integrated Effects Test (IET), signifying a major achievement for the project. The IET is a non-nuclear, externally heated, 1-MW multiloop system, located at TerraPower’s laboratory in Everett, Washington. “The IET will inform the design, licensing, and operation of an approximately 180-MW MCFR [Molten Chloride Fast Reactor] demonstration planned for the early 2030s timeframe,” Southern Company said.

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.”

During President Biden’s first year in office, his administration published a document titled “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050.” The document says all viable routes to net-zero involve five key transformations. They are: • Decarbonize electricity. • Electrify end uses and switch to other clean fuels. • Cut energy waste. • Reduce methane and other non-CO2 emissions. • Scale up CO2 removal. Which of the key transformations will play the biggest role in reaching the U.S.’s net-zero goal is still up for debate. “The first step—decarbonize electricity—is critical and may be one of the most important steps in achieving net-zero emissions,” Brendan O’Brien, business development manager, and strategy and sales leader with Burns & McDonnell, said as a guest on The POWER Podcast. “That transition is going to include a lot of things that we’re probably familiar with today, like clean energy driven by solar and wind, but also it’ll look to the future for decarbonized technologies and decarbonized solution.” O’Brien noted that the U.S. is targeting 100% clean energy by 2035, and he suggested the transition is already well underway. “It’s been occurring and even accelerating in recent years,” he said. “It’s been driven by plummeting costs in key technologies, like solar, onshore wind, offshore wind, and batteries, which you’re seeing more and more as deployed technology of the utilities in the United States. All that’s being bolstered by policies and regulation that has been enacted by various governments. And then also—the final—the big push is really coming from the consumer. More and more consumers are demanding clean energy and clean power, and the power generation market in the United States has been reacting to it.” Complexity is added to the equation with the second key transformation, that is, electrifying end uses. O’Brien said the transportation sector’s shift from internal combustion engines to electric vehicles will require a 65% increase in power generation. That’s on top of other load growth from manufacturers reshoring operations, as well as the need to replace retiring power generation units, specifically coal plants. “I think there’s going to be quite a fun challenge of figuring out what the energy mix is going to look like over the next 10 to 25 years to meet these targets,” said Megan Reusser, hydrogen technology manager with Burns & McDonnell, who also participated on the podcast. “What we really need to be looking at is the whole picture,” she said, noting that there are many sectors trying to electrify including industrial applications, agriculture, and forestry, among others. “Transportation is one piece, but when we start putting all the pieces together, it’s going to be large amounts of generation required,” said Reusser. Meanwhile, cutting energy waste is a no-brainer. Likewise, reducing methane and other non-CO2 emissions follows a similar thought pattern. Lastly, scaling up CO2 capture is important. “We cover a wide range of these different technologies. So, we’re looking at carbon capture and sequestration, whether that is amine technology or membrane technologies—doing a lot of work in the direct air capture, or DAC, markets. So, looking to essentially remove CO2 from the atmosphere that’s already there, and then sequester that with various technologies,” Reusser explained. In the end, it’s likely an integrated approach will be necessary to reach the U.S.’s net-zero target successfully. “There’s not just going to be a single solution that’s going to get us there. If you dive a little bit more into the U.S. strategy that we were talking about today, it really lays out the groundwork of how to get there. And as you dive into that, you’ll see that it doesn’t just focus on one single industry or one single technology, it’s really across the value chain on how we can accomplish this by working together,” concluded Reusser.

Most propane used in the U.S. today is produced as a byproduct of natural gas processing and crude oil refining, which are not considered “green” technologies. However, renewable propane availability is growing. Renewable propane, like its conventional brother, is commonly made as a byproduct of other fuel production, in its case, often renewable diesel and sustainable aviation fuels (SAFs). Renewable diesel and SAF are primarily produced from plant and vegetable oils, animal fats, and used cooking oil. Renewable propane has the exact same features as conventional propane, which includes excellent reliability, portability, and power, as well as reduced carbon emissions on a per-unit-of-energy basis compared to many other fossil fuels. While the scale of renewable propane production is fairly small at present, most experts agree that it has the potential to ramp up quickly. “Looking at what we’ve done for the past five years is we were shipping about 40 million gallons [of renewable propane]. By the end of this year, we’re going to be close to 100 million gallons, and by the end of 2024, we should be close to 200 million gallons. So, the scalability is coming up—there’s more refineries coming on,” Jim Bunsey, director of commercial business development with the Propane Education & Research Council (PERC), said as a guest on The POWER Podcast. One way to judge the environmental impact of a fuel is through its carbon intensity (CI) score. The concept was brought to many peoples’ attention in 2009, when the California Air Resources Board approved the state’s Low Carbon Fuel Standard (LCFS) regulation. The LCFS set annual CI standards, or benchmarks, which reduce over time, for gasoline, diesel, and the fuels that replace them. CI is expressed in grams of carbon dioxide equivalent per megajoule of energy (gCO2e/MJ) provided by a fuel. CI takes into account the greenhouse gas (GHG) emissions associated with all of the steps of producing, transporting, and consuming a fuel—also known as the “complete lifecycle” of the fuel. According to Bunsey, conventional propane has a CI of about 79, but renewable propane is much lower. “We can have renewable propane having a carbon intensity of seven or up to 20.5,” he said. “There’s a range—it depends on the feedstock that’s available.” Notably, both conventional and renewable propane compare quite favorably to the U.S. power grid’s average CI, which is about 130, according to Bunsey. While California has been a leader nationally in the push for GHG reductions, other jurisdictions are following its example. The Pacific Coast Collaborative, a regional agreement between California, Oregon, Washington, and British Columbia is one example. Over time, collaborative member LCFS programs are expected to build an integrated West Coast market for low‐carbon fuels that will create greater market pull, increased confidence for investors of low-carbon alternative fuels, and synergistic implementation and enforcement programs. Other regions of Canada and Brazil are also using California as a model to develop LCFS‐like performance standards for transportation fuels. Suppliers are also finding interest for renewable propane in the northeastern U.S. The first delivery of renewable propane in Massachusetts was received with a ceremony at the NGL Supply Wholesale Springfield terminal in West Springfield on Sept. 12. “The cost is just very slightly more than traditional propane today, but we anticipate as more of it is produced that that cost is going to come down. And if you think about the added benefit that you get by knowing you’re helping the climate and helping the planet by using renewables, I think a lot of people are willing to spend just a little bit more to get that,” Leslie Anderson, president and CEO of Propane Gas Association of New England, told WWLP-22News, a western Massachusetts multimedia company.

It’s pretty easy to understand how the weather affects certain forms of power generation and infrastructure. Sunlight is obviously needed to generate solar power, wind is required to produce wind energy, and extreme storms of all kinds can wreak havoc on transmission and distribution lines, and other energy-related assets. Therefore, having accurate and constantly updated weather information is vital to power companies. “First and foremost, utilities need to understand as best as possible the forecast of the environmental resources that are supplying these generation sources. It’s ultra-critical, because even small, slight changes in wind speed or solar radiation can have pretty substantial impacts as far as the capacity factor that a renewable generator is operating at,” Nic Wilson, director of product management for weather and climate risk with DTN, said as a guest on The POWER Podcast. Wilson highlighted some of the weather-related applications that utilities are integrating into their operations. “One of the focal points for DTN is working with utility emergency preparedness teams in order to help them better understand and forecast at-risk weather environmental hazards that are going to impact their overhead distribution operations, and understanding and communicating appropriately the outage impact risks,” he said. “Another application is asset inspection,” said Wilson. “After a storm goes through, how does the utility prioritize where it’s going to do inspection along its lines for potential damage?” One way could be using DTN’s tools. Wilson suggested, for example, a company responsible for the operations and maintenance of wind farms could use DTN data to identify turbines that may have experienced blade damage during a weather event. With that insight, the company could proactively inspect for compromises to the fiberglass blades before the damage turned catastrophic. Load forecasting is another important use case for DTN’s data. Many things must be considered to develop load forecasts including historical trends and current events. Wilson suggested temperature, precipitation, cloud cover, time of day, time of year, and more will affect not only the renewable energy production, but also demand for electricity. With accurate forecasts, power companies can plan appropriately to take advantage of any given situation. If they anticipate a surplus, units could be taken offline for scheduled maintenance, but if the supply is expected to be tight, they can issue orders to increase plant readiness. “Then, there’s some emerging applications, such as capital planning, where utilities are trying to climate-adjust the age, and understand the performance and condition monitoring of their assets in order to prioritize resiliency investments,” Wilson said. DTN’s products are constantly being refined too. Wilson said artificial intelligence and machine learning are behind many of the improvements. “We are consistently doing what we call retraining. So, as new data becomes available from the utility, whether that’s outage management system data, or condition monitoring information, or satellite- or LIDAR [light detection and ranging]-derived vegetation datasets, we’re incorporating that into our models and updating them as frequently as possible in order to ensure that our predictions are as representative of the current environment as possible,” he said. Wilson said DTN is making some forays into climate modeling and trying to understand how different environmental factors of interest to utilities are going to evolve in not only the next three to six months on a seasonal basis, but also out to 30 years in the future. This is important information for power companies because they are often making investments with a 50-year time horizon in mind.

The U.S. Department of Energy (DOE) defines environmental justice as: “The fair treatment and meaningful involvement of all people, regardless of race, color, national origin, or income, with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies.” It says “fair treatment” means that no population bears a disproportionate share of negative environmental consequences resulting from industrial, municipal, and commercial operations or from the execution of federal, state, and local laws; regulations; and policies. “Meaningful involvement,” meanwhile, “requires effective access to decision makers for all, and the ability in all communities to make informed decisions and take positive actions to produce environmental justice for themselves,” according to the DOE. Environmental justice (EJ) has become a very important consideration when it comes to siting and/or expanding energy projects, including power plants. While many people associated with the power industry tend to focus on the benefits provided to communities when a project is developed, such as well-paying jobs and an increase in the tax base, people in the affected community may have a different view. They may be more focused on the negative effects, which could include an increase in harmful emissions, water usage, and heavy-haul traffic. “Communities are weighing the pros and cons of having industry there—having a job creator—and that, of course, generating additional economic activity. On the flip side, there are actual or perceived environmental or health issues,” Erich Almonte, a senior associate with King and Spalding, said as a guest on The POWER Podcast. King and Spalding is a full-service law firm with more than 1,300 lawyers and 23 offices globally, including a large team focused on energy-related matters. “It’s important to note that there really isn’t any ‘Environmental Justice Law.’ What we have instead are a use of current statutes and regulations that were perhaps designed for something else to try to achieve environmental justice ends,” Almonte said. The impact EJ could have on a project is quite substantial. “A company could meet all of its environmental permitting requirements, but still have a permit denied, if there were disparate impacts that weren’t mitigated properly, under Title VI of the Civil Rights Act,” Almonte explained. “This came out in a guidance document in April 2022, and since, it’s featured a couple of times in subsequent guidance documents that the administration has put out,” he added. While Almonte said he wasn’t aware of a permit being denied in that fashion to date, it’s a major consideration for companies when planning projects. Another potential show-stopper could be trigger through Section 303 of the Clean Air Act. This section provides “emergency powers” to the Environmental Protection Agency (EPA). “When there’s an environmental threat that poses an imminent and substantial endangerment to the public, or to the environmental welfare, then EPA can essentially stop that activity or file a lawsuit against it,” Almonte explained. “This is true even if the activity that’s causing the supposed endangerment is allowed by the permit.” According to Almonte, the EPA has only used this authority 14 times in the past five decades, but four of those occurrences have been in the past two years. This suggests it could become a regular tool used by the administration to achieve its EJ goals.

While power outages are not uncommon in the U.S., widespread blackouts that last more than a couple of hours are pretty rare. However, this summer marks the 20th anniversary of one of the most significant blackouts in North American history. The incident didn’t just affect the U.S., but also major parts of Canada. The blackout occurred on Aug. 14, 2003. The History Channel reports it began at 4:10 p.m. EDT, when 21 power plants shut down in just three minutes. Fifty million people were affected, including residents of New York City, Cleveland, and Detroit, as well as Toronto and Ottawa, Canada, among others. Although power companies were able to resume some service in as little as two hours, power remained off in other places for more than a day. The outage stopped trains and elevators, and disrupted everything from cellular telephone service to operations at hospitals and traffic at airports. “It was close to quitting time in the afternoon, and given the warm weather in the middle of the summer and thunderstorm season, our system was holding up well. I was looking forward to actually leaving on time for a change,” Paul Toscarelli, senior director of Electric Transmission and Distribution (T&D) Operations for the Palisades Division with Public Service Electric and Gas (PSE&G), New Jersey’s largest utility, said as a guest on The POWER Podcast. Toscarelli was an engineer assigned to one of PSE&G’s regional distribution divisions at the time and was in the distribution dispatch office when the incident occurred. He recalled the event quite vividly. “We were coming up around the second anniversary of 9/11, as I recollect, and just about everyone’s gut feel—instinctive feel—was this was another kind of terrorist attack,” Toscarelli said. “Looking back at it, it was very strange to recollect how relieved we were to find out it was just a widespread system outage of epic proportions.” Of the 750,000 PSE&G customers that lost power that day, nearly three-quarters were back online within five hours and virtually all had service by noon the next day. PSE&G said diversification and design protections helped to contain the outage, and the company was safely able to reenergize the system circuit by circuit. “The industry learned a lot about the electric system vulnerabilities,” said Toscarelli. Based on studies of the incident, the North American Electric Reliability Corporation (NERC) enhanced its standards in an effort to prevent future blackouts. Since the 2003 blackout, PSE&G has spent billions of dollars to further enhance the reliability and resiliency of its T&D systems with the aim of mitigating future outages. In fact, the company’s planned capital expenditures this year are the largest in the utility’s history—more than $3.5 billion. Among the projects PSE&G expects to complete in 2023 is a Newark Switch Rebuild Project. The Newark Switching Station is the heart of the company’s Newark T&D network. The $350 million project will modernize aging infrastructure that was put into service in 1957. Another example is the $550 million Roseland-Pleasant Valley Project, which was completed in May and was one of PSE&G’s largest transmission projects to date. The 51-mile undertaking replaced transmission facilities that were, on average, about 90 years old. “Infrastructure continually ages. It’s our job as the stewards of our system to monitor the usage of our equipment, inspect it, maintain it, and replace it where it’s deemed necessary, in a timely manner, and continuously repeat that process,” said Toscarelli. “We have an asset management model that involves risk assessment and risk scoring, and it lets us stay in the forefront of this.”

In 2021, Idaho National Laboratory (INL) Director John Wagner set a lofty goal for the lab to achieve net-zero carbon emissions within 10 years. An uninformed observer might think that would be an easy task for an organization as focused on energy as INL, but it’s important to recognize that the lab is spread over nearly 900 square miles—about three-quarters the size of the state of Rhode Island. To shuttle the lab’s nearly 5,400 employees everywhere they need to go across that vast territory, INL has a fleet of about 85 motor coaches with an operating schedule that runs 24 hours a day, seven days a week. With all the transportation and 357 buildings to heat and cool throughout the year, achieving net-zero is a significant challenge. Jhansi Kandasamy, INL’s net-zero program director, explained that more than half of the lab’s carbon emissions come from purchased electricity. That means INL has to work with Idaho Power to cut much of its emissions. “Probably 60 to 80% is already pretty clean—carbon-free—because they have hydro as a majority electricity generation,” Kandasamy said as a guest on The POWER Podcast, but that still leaves a fairly large gap to fill. “With my background in nuclear and nuclear being dependable, secure, 24/7, we’ve worked with Idaho Power to say, ‘We’d like to include nuclear as the generation,’ ” Kandasamy said. “If we accomplish that—if we get nuclear—that addresses the 54% of carbon emissions that we get from purchasing electricity. Without doing anything else, we would have reduced our carbon emissions by 70%.” The Carbon Free Power Project, spearheaded by Utah Associated Municipal Power Systems (UAMPS), with NuScale Power’s VOYGR small modular reactor technology at its heart, seems like a logical fit for Idaho Power’s needs. The six-module plant will be built on INL property. Kandasamy said INL helped get some potential project partners, including folks from UAMPS, NuScale, Idaho Power, Idaho Falls Power, and the Department of Energy (DOE), in a room to talk about the project and what needed to be done to ensure it is operational within the next decade. “It’s a collaboration effort instead of competition. It’s all collaboration—getting all the people that are the experts in the room and kind of working through it. And it’s been great in that they’re all coming up with these different ideas,” she said. In addition to motor coaches, INL also has more than 600 other vehicles in its transportation fleet. Kandasamy suggested there are plans to electrify much of INL’s fleet, as well as adding some hydrogen-fueled vehicles and using carbon-free fuels, such as R99 (renewable diesel), in others, which will all help to cut carbon emissions. Still, getting the vehicles poses a challenge. INL is required to source its vehicles through the DOE, and the DOE’s supply of electric and hydrogen-fueled models is lacking. “The Executive Order says by 2027 we need to have all of our light-duty vehicles transition to electric. That’s not far away. We have 240 vehicles—light-duty vehicles—that we need to transition. We’ve gotten 24,” Kandasamy said. Yet, employees may be the real key to success. Kandasamy said the staff at INL has really gotten behind the initiative. “The big push is really the cultural shift across the entire laboratory. So, the communication becomes a really huge part of saying, ‘Here’s what we’re doing for each scope. Here’s how each of the employees contributes to getting us to net-zero,’ ” she said. “We’ve been putting in all these communications about how we’re transitioning. The other part is for the employees to tell their story on how they are achieving net-zero,” said Kandasamy. “That has been huge. Now, it’s like, everybody wants to have their story. So, they start talking about how they are transforming in their personal life, as well as how they’re commuting to work, and so on, with net-zero stories.”

The Combustion Turbine Operations Technical Forum (CTOTF) is the longest continuously active gas turbine industry organization driven by users, for users. CTOTF offers week-long conferences twice annually in the spring and fall. The conferences provide a balance of technical information, user-to-user interaction, and professional development and mentoring for the group’s nationwide user base. CTOTF’s 2023 Fall Conference will be held September 24–28 at the Mystic Lake Casino Hotel in Prior Lake, Minnesota. As a guest on The POWER Podcast, Dave Tummonds, senior director of Project Engineering with Louisville Gas and Electric (LG&E) and chairman of the board for the CTOTF, talked about the group and some of the things he’s looking forward to during the upcoming event. “The biggest thing for me is, when you look at our agenda and what we strive to accomplish over the course of a week-long conference, we hit a lot of things that admittedly some other conferences hit, but we tend to be the best one-stop shop to hit it all,” Tummonds said. Sessions encourage interaction from all attendees and offer an intimate setting where newcomers don’t get lost in the crowd. The agenda begins with opening presentations that often dive into industry trends, among other things. This fall, Aron Patrick, director of Research and Development (R&D) with PPL Corp., parent company of LG&E, will give a presentation focused on the energy transition. “On our kickoff day—Monday morning—we’re going to have an update from my company’s R&D director, who’s going to go over some of the things that are being done in the heart of coal country—in Kentucky and similar areas—in preparation for the decarbonization effort,” said Tummonds. “What makes this interesting, I believe, is his analysis, and his group’s analysis, which really points out that as we seriously look to decarbonize, we’ve got to do that with more backup from gas-fired megawatts as opposed to less. It’s just a necessity to make up for the times when those renewable megawatts are not available. “The other thing I would mention associated with his presentation is he’s going to touch on some efforts in the area of hydrogen blending that his group is specifically looking at, as well as carbon capture and sequestration, that again, when you look at the unique perspective of the heart of coal country, I think serves as an important note for us all.” On the podcast, Tummonds touched on many of the other sessions and activities that are planned this fall too. Among the highlights are presentations by original equipment manufacturers, topical discussions with third-party suppliers and other experts, technical education sessions, leadership development roundtables, environmental updates, and plenty of time for networking and fun.

Hydrogen demand throughout the world reached 94 million metric tons in 2021, according to the International Energy Agency’s (IEA’s) Global Hydrogen Review 2022, an annual report issued by the IEA in late September last year. Demand for new applications grew to about 40,000 metric tons (up 60% from 2020, albeit from a low base). Notably, the IEA said some key new applications for hydrogen are showing signs of progress. Announcements for new steel projects are growing fast, according to the agency, just one year after the startup of the first demonstration project using pure hydrogen in direct reduction of iron. Furthermore, the first fleet of hydrogen fuel cell trains started operating in Germany. There were also more than 100 pilot and demonstration projects reported using hydrogen and its derivatives in shipping, and the IEA noted that major companies have already signed strategic partnerships to secure the supply of these fuels. In the power sector, the use of hydrogen and ammonia is also attracting a lot of attention. The report says announced projects stack up to almost 3.5 GW of potential capacity by 2030. With the future for hydrogen looking so bright, it’s no wonder companies are moving quickly to take advantage of the opportunity. Accelera, a new brand launched in March this year as part of Cummins’ New Power business segment, is among the companies hoping to cash in on the growth in hydrogen. It opened its first U.S. electrolyzer manufacturing plant in Fridley, Minnesota, with a ribbon-cutting ceremony on May 19. “Fridley was basically the fastest way for us to get capacity on stream quickly,” Alex Savelli, managing director of Hydrogen Technologies for Accelera, said as a guest on The POWER Podcast. “We announced it in October and we had the ribbon-cutting in May, so within six months.” While the Fridley site was a “brownfield” project, meaning it was built where Cummins already had an existing facility, Accelera is also building “greenfield” projects in other parts of the world. “There are a couple of sites that we’ve actually selected 18 months ago to be built in Spain and China,” Savelli said. “They’re greenfield sites, and from beginning to completion, it probably will take two years before they’re up and running.” President Biden visited the Fridley facility on April 3 this year as part of a tour intended to showcase how the Bipartisan Infrastructure Law and Inflation Reduction Act (IRA) are benefitting American manufacturing jobs. It was just two months after Biden signed the IRA that Cummins announced it would begin manufacturing electrolyzers at its Fridley location, which now has about 89,000 square feet dedicated to electrolyzer manufacturing. “Quite a bit of that decision in a lot of ways was supported by some of the good policies that the current administration has put in place with the Infrastructure Bill as well as the Inflation Reduction Act,” said Savelli. “They have certainly underpinned our decision even more strongly. Since then, we have seen demand really pick up.” Most of the hydrogen used around the world today is produced through steam methane reforming using natural gas as the feedstock, which releases carbon dioxide in the process. This is often referred to as “gray hydrogen.” Electrolyzer technology offers a way to produce “green hydrogen,” which is carbon-free and could help hard-to-decarbonize industries become more sustainable. To produce green hydrogen, renewable resources are used to power electrolyzers. “We think with the challenges around climate change and what we need to achieve to actually get to net-zero, hydrogen would definitely be one of the big elements there,” said Savelli. “It will become a multi-billion-dollar opportunity—whether it’s here in the Americas, in Europe, or other places—between now and the end of the decade.”