The POWER Podcast

Building a nuclear power plant is a difficult job. It takes years of planning and sometimes more than a decade to complete. The risk of schedule delays is great, especially on first-of-a-kind projects, and the financial implications of such setbacks can ruin a company. Yet, the Tennessee Valley Authority’s (TVA’s) president and CEO, Jeff Lyash, suggested the risk is worth taking, that is, if lessons learned from one project can be parlayed into success in future projects. That’s why TVA is studying the addition of a small modular reactor (SMR) at its Clinch River site. Lyash envisions using that first unit as a template to eventually make Clinch River a four-unit site, and then replicating that design in at least four other locations within TVA’s service territory. “I’ve said very vocally, I [want] nothing to do with building one reactor, unless I can build 20—and 20 is the low estimate—and so, this is what Clinch River is about,” Lyash said as a guest on The POWER Podcast. While TVA continues to support and examine all of the various SMR designs being proposed, and it is also following the development of Generation IV advanced nuclear technology, it has selected GE-Hitachi’s (GEH’s) BWRX-300 design for its Clinch River site. “We picked the BWRX-300 technology because the X stands for the 10th generation. We know this fuel works. We know this technology works,” Lyash said. Lyash noted that there are 50 years’ worth of experience behind the GEH design. He said engineers have applied modularization processes and advanced manufacturing techniques to advance the design, but the technology behind it all is well-established. “This allows us to focus on what I think the risk is that’s yet to be proven, and that is, can we finish a first-of-a-kind on schedule and on budget, and can we demonstrate the movement to nth-of-a-kind rapidly, and can we turn that into a fleet?” Lyash said. “We intend Clinch River to be a four-unit site,” Lyash explained. “There’s an optimum way to build four units. It includes a lot of overlap—supply chain, labor, etc. That’s what we want to develop, but we’re going to ‘unlap’ the first unit so that we can learn all those lessons, identify all those risks, and make units two and three and four look significantly better and different, so that when we build site two, three, and four, we’ve got that,” he said. TVA is a wholly owned U.S. government corporation created by Congress in 1933. It is the largest public power company in the country, providing electricity for 153 local power companies serving 10 million people in Tennessee and parts of six surrounding states, as well as directly to 58 large industrial customers and federal installations. Because of TVA’s unique position as an entity of the federal government, Lyash believes it should be a leader for the power industry. “Because of TVA’s special role, we’re really doing it to support the nation, because what we’d really love to happen is fast followers,” he said. In other words, he hopes once TVA proves that an SMR can be constructed on time and on budget, other power companies will jump on the new nuclear construction bandwagon. Still, nuclear is not the only new generation TVA is pursuing. It also has plans to add at least 10,000 MW of new solar, as well as battery and pumped-hydro energy storage, and even some natural gas–fired generation to help bridge the gap as it phases out its coal generation by 2035. “We at TVA are very outcome focused, so we spend a lot of time talking about: ‘At the end of this trail, where is it we want to arrive at?’ ” Lyash said. “It’s about affordable energy that’s reliable and resilient, and low-carbon.” To reach the desired outcome, Lyash said it would take renewables, nuclear, storage, demand-side management, and energy efficiency all in the right mix.

New technology is regularly being developed and enhanced to improve power delivery and incorporate more renewable energy into systems. ABB Energy Industries is among the companies investing large sums of money in research and development (R&D) programs to make future power systems better. Among its current projects are subsea power distribution and conversion concepts, which could benefit the offshore wind industry, and a Power-to-Ammonia pilot project. “We have a lot of experience—over 20 years—with this subsea equipment,” Asmund Maland, head of subsea and offshore power at ABB Energy Industries, said as a guest on The POWER Podcast. “Our intention is to put on the seabed what we call the ‘services substation and collector systems,’” he explained. Maland said the subsea equipment could replace or act as an alternative to a floating substation, which he expects will be more needed as the offshore wind industry moves to deeper waters. ABB has already tested these systems for the oil and gas (O&G) industry with great early success. Nearly a decade ago, the company initiated a $100 million Joint Industrial Project with Equinor (formerly Statoil), Total, and Chevron with support from the Research Council of Norway. As part of that project, ABB completed the development of an electrification system for transmission, distribution, and conversion of power, to subsea pumps and gas compressors, at a peak capacity of 100 MW, to water depths up to 3,000 meters, with transmission distances up to 600 kilometers, and with little or no maintenance for up to a lifetime of 30 years. “If you replace a floating substation with something on the subsea, you will reduce to one-fifth of the steel. So, by that, there is also then potential capex [capital expenditure] savings of maybe over 30%, and also, the opex [operating expense] savings of the year will also be quite good,” said Maland. ABB expects to be ready to take orders for subsea offshore systems by the end of 2024. On the podcast, Tom Zøllner, head of ABB Energy Industries for Denmark, talked about another innovative project ABB is involved in, which the company calls “the world’s first dynamic green Power-to-Ammonia plant.” ABB is working alongside Danish companies Skovgaard Energy, Vestas, and Haldor Topsoe to demonstrate Power-to-X (PtX) technology in Lemvig, northwest Denmark. The project is also being supported by the Danish government’s Energy Technology Development and Demonstration Programme, which provided about $12 million in assistance. “The reason behind the project is that in Denmark we have for some time been one of the lead countries when it comes to green energy, and it has been more and more clear that we need to figure out how to store all this additional energy that we may not be able to use all the time. Unfortunately, batteries are not strong enough, and therefore, we need to look into alternatives, and Power-to-X has become one of the solutions that we have been looking into for some time,” Zøllner said. The demonstration facility—scheduled to start operating in 2024—will be powered by renewables from 12 MW of existing wind turbines and 50 MW of new solar panels. ABB is responsible for electrical integration and advanced process control of the full Power-to-Ammonia plant operating in highly dynamic mode. The 10-MW plant is expected to operate at full capacity when excess wind and solar power are available, but will gear production down when neither renewable energy source is present, making it adaptable to fluctuations in energy supply and different from other types of PtX plants, which are directly connected to the grid. The pilot plant will produce about 5,000 tons of ammonia per year. While the project is small in the grand scheme of things, Zøllner said it will showcase the technology and should be scalable in the future.

It’s no secret that leaders around the world are searching for ways to decarbonize their electric power grids. While solar panels and wind turbines have been the main options utilized in this effort in recent years, both are intermittent resources. Therefore, backup generation is required to keep power grids reliable. In many situations, that means installing diesel-fueled power generators. In fact, there’s been a significant increase in diesel generator sales as wind and solar capacity have increased. “Right now, 90% of the backup power is diesel-powered,” Jim Bunsey, director of commercial business development with the Propane Education & Research Council (PERC), said as a guest on The POWER Podcast. “It’s been tremendous growth in diesel-powered backup power and that’s where we can really start to bring propane into play,” Bunsey said. Yet, even as propane is used to supplant diesel-fueled backup systems, it can also be used to displace other grid-connected power generators, thereby reducing carbon emissions. “As we look at decarbonization, we look at the carbon intensity, or the full lifecycle of a product, of where it’s generated, how it’s transmitted, and how it gets to its end source where it’s being used,” Bunsey explained. He noted the national average carbon intensity score for the U.S. power grid is 130. Propane, meanwhile, has a carbon intensity score of only 79. “So, right now, from switching from the electric grid to propane-powered power generation, we’ve now moved our carbon intensity score from 130 to 79. That’s a great savings. That’s available today with our infrastructure for developing propane, for storing propane, for moving propane, and gives that carbon intensity score—79 is really good,” he said. “It starts us on the path to zero. So, as we decarbonize, we look at the electric grid, we look at other products, we’re working our way down.” But Bunsey sees a future where propane is even less carbon intensive, and it’s not too far in the distance. “The most exciting thing that’s coming is renewable propane,” he said. “Renewable propane has been being used for about five, six years right now. It’s being delivered.” While quantities are still limited at present, and most of the renewable propane produced today in the U.S. is being shipped to California where carbon credits are making it more affordable, Bunsey expects the volume of renewable propane to increase as major suppliers start to come onboard. “That gives us a clear path to zero. We can step it down,” he said. “There’s renewable propane that’s being delivered today that has at-the-source carbon intensity of about 11. And then, delivered on-site, because that’s where you’ve got to look at the whole lifecycle—what does it take? We’re going to develop this fuel. We’re going to ship it. We’re going to go to the end-use. By the time it gets to the end use in California, they’re at 20.5 today. That was the last quarter. That’s what they’re using right now with renewable propane,” said Bunsey. “There’s a clear path right now for people, for their decarbonization, and we can get our path to zero.”

Perhaps the most devastating thing that could happen in any developed country would be widespread catastrophic damage to its electric power grid. Nearly everything in an industrialized nation relies on electricity to function. Without it, normal water supplies, sewer systems, and communication services are cut off. Furthermore, things like food and transportation are quickly affected when power is down for extended periods. A severe electromagnetic pulse (EMP) or geomagnetic disturbance (GMD) event could take the power grid down for months, and possibly even for years. An EMP is a very intense pulse of electromagnetic energy, typically caused by the detonation of a nuclear bomb or other high-energy explosive device. A GMD, meanwhile, can be caused when a solar eruption produces a coronal mass ejection (CME) that travels from the sun to the Earth. A direct hit by an extreme CME would cause widespread power blackouts disabling everything that uses electricity. Some experts have suggested that a major EMP or GMD hit could result in the death of up to 90% of the U.S. population. What makes the event so devastating is that the U.S. power grid is not well-protected from such a strike, and the country is not prepared to recover quickly. Dr. William R. Forstchen, author of more than 40 books including the groundbreaking novel One Second After, which has been credited with raising national awareness to the potential threat posed by an EMP strike, explained the situation as a guest on The POWER Podcast. Forstchen noted that the U.S. power grid is vulnerable to such an event for a number of reasons. “The average component in our electrical grid is 40 to 50 years old. We are running our electricity on a 1970s, early-1980s industry. We’re not modernizing it,” he said. A few years ago, the federal government began to address the problem. “The Trump administration finally started taking action about six months before the election in 2020. They mandated DOD [the Department of Defense], DOE [the Department of Energy], all the different agencies to submit a comprehensive analysis of what needs to be done that would then follow by legislative action in the next Congress,” Forstchen explained. However, when Trump lost the election, President Biden immediately killed the initiative, he said. Forstchen said relatively minor investments could vastly improve the situation. He suggested stockpiling key components is an important first step. “A large transformer for a major substation can cost several million dollars. From the time of ordering one until the big truck pulls up and we start to unload it is two or more years,” Forstchen said. Furthermore, he noted that most of the equipment and components that might be needed to repair the grid are now sourced from other countries, mainly China, which means the U.S. may not be able to get supplies, especially if the attack was initiated by one of those countries. “We should be building a strategic reserve of key electrical components,” he said. Additionally, Forstchen said the U.S. should focus on a “lifeline to recovery.” He suggested hardening 10% of the grid could act as an insurance policy for the nation. “Let’s say the rest goes down, but we have those lifelines out there that can be used to start repairing things, bringing supplies, and communicate—big thing, communication and transportation,” said Forstchen. Risks could be substantially reduced with relatively minor investments. “I argue $20 to $30 billion a year would at least start ensuring some responsible response to this problem,” Forstchen said.

The U.S. Gulf Coast offers some of the greatest potential for renewable energy development in the country. According to a National Renewable Energy Laboratory (NREL) study, Florida, Texas, and Louisiana rank second, third, and fourth, respectively, in net technical energy resource potential for offshore wind. The large energy resource in these three southern states is attributed to a large quantity of ocean area that encompass relatively long coastlines and wide continental shelves. Greater New Orleans Inc. (GNO) is the regional economic development nonprofit organization serving the 10-parish region of Southeast Louisiana that includes Jefferson, Orleans, Plaquemines, St. Bernard, St. Charles, St. James, St. John the Baptist, St. Tammany, Tangipahoa, and Washington parishes. GNO is keenly focused on developing a thriving offshore wind industry in its region. Among the initiatives it oversees is the GNOwind Alliance, which is comprised of more than 180 organizations that GNO says “provide the expertise to grow the region and state as an energy leader.” “[The GNOwind Alliance] was really launched with the understanding that there was a lot of activity and a lot of interest in the forthcoming leases in the Gulf of Mexico around wind development, and recognizing that not only do we have this lease potential in the Gulf of Mexico, but we also have this incredible industrial base across south Louisiana to connect some of this green energy to,” Lacy McManus, executive director of Future Energy at GNO Inc., said as a guest on The POWER Podcast. McManus suggested that south Louisiana’s history with the oil and gas industry positions it to quickly adapt and capitalize on the offshore wind potential. She said many of the services that are going to be needed—the labor profiles, the workforce, and even some of the policy and regulatory experience necessary to develop the wind sector—borrow from the oil and gas industry. “We have a lot of that already in our landscape,” said McManus. “It’s where we are fortunate because I think that’s going to really catalyze a lot of our activity, and add to the momentum, and the speed and efficiencies with which we’re able to deliver to companies and industries coming in.” GNOwind Alliance is already supporting workforce programs that train workers to transfer skills from oil and gas to wind energy through a partnership with academic and industry allies. “We work hand in glove with our higher education landscape here in Louisiana, but specifically at GNO Inc., we have a fantastic relationship with both LCTCS, which is the Louisiana Community and Technical College System, as well as with the Board of Regents, who oversees all of our higher education institutions,” McManus said. GNO leadership made the decision about a decade ago to have all of the presidents of the four-year schools in the Greater New Orleans region, and all the chancellors of the two-year community colleges in the region, on its board of directors. “For the last 10-plus years, all of that higher ed leadership has been sitting in the same room with all of the business leadership in the region on a monthly basis at our board meetings. They get the scoop and the understanding, and hear straight from the horse’s mouth on new announcements that we have coming in,” said McManus. Beyond offshore wind, McManus sees opportunity for southeastern Louisiana in the green hydrogen economy. “Louisiana and our industry base actually consumes one-third of the nation’s hydrogen. So, that’s a lot of gray hydrogen that’s currently going into our industrial footprint,” said McManus. “With the opportunity to develop more wind in the Gulf, we have a really unique, in my view, sort of once in a generation chance to shift some of that gray hydrogen that we’re currently using in our industrial footprint over to green hydrogen.”

You may not expect to hear names like Henry Ford and J.P. Morgan mentioned when studying the history of hydropower. You might know that President Franklin Delano Roosevelt signed the Tennessee Valley Authority Act in 1933, establishing the Tennessee Valley Authority (TVA), which has 29 power-generating dams in its power system, but you may not realize how much of a role FDR played in other hydropower projects. It’s frankly an understatement to say all three of these men were hugely important in the development of U.S. hydropower. “I almost guarantee that most people do not realize that Henry Ford was such a significant player. He was a strong proponent of hydropower. He looked at water as free,” Bob Underwood, author of the book DAM IT! Electrifying America and Taming Her Waterways, said as a guest on The POWER Podcast. “He was experimenting with hydropower from the time he was a kid. He went on to develop 30 different hydroelectric facilities—small and large.” Underwood explained that Ford was also part of a major hydropower battle. It involved the Wilson Dam near Muscle Shoals, Alabama, a small town located on the southern bank of the Tennessee River. President Woodrow Wilson had authorized construction of the Wilson Dam in 1916. The hydropower plant was intended to provide electricity for a munitions facility that was supporting the war effort during World War I, but the war ended before the dam was completed. Construction on the project languished after the war while Congress debated what to do with the property. Some senators wanted to sell the dam to a private company while others thought the government should retain public control of the property. Henry Ford made a surprise inspection tour of the Muscle Shoals facilities and the Wilson Dam site in June 1921. A month later, he submitted a bid for all the federal properties associated with the site. “And that’s where he got into it with Senator Norris [from Nebraska], and that went on for four or five years,” said Underwood. Norris was one of the biggest public power advocates around. Although technically a Republican, Norris was fiercely independent and regularly collaborated with FDR, a Democrat. “[Ford] lost, but that sure elevated the view of hydropower in this world,” said Underwood. Although J.P. Morgan passed away a little over a year before World War I began, he played an important role in the history of hydropower during his lifetime. Underwood said even he didn’t realize how influential J.P. Morgan was to the electric power generation industry before he started doing research for his book. He said Morgan was pulling strings behind the scenes, not only in the electrical business, but in everything else that was going on in his day. “He was always trying to build a monopoly in whatever industry it was,” said Underwood. “He manipulated Edison to merge another company of the time—a big competitor, Thomson-Houston—into Edison General Electric to form General Electric, essentially shoving Edison aside and out of his own company. And J.P. Morgan kept having huge influence through the financing of the industry—both the hydroelectric side of it, as well as the coal-fired side of it,” Underwood explained. But when it comes to big hydro projects, FDR gets much of the credit for making them happen. “He changed the industry,” Underwood said on the podcast. “Very influential.” Among FDR’s significant hydropower accomplishments are two projects on the Columbia River: Bonneville and Grand Coulee. Four months after taking office in March 1933, FDR was able to cut through years of conflicts to get construction underway. Underwood wrote in his book, “His actions clearly established federal authority over the waters of the West."

Microgrids are localized power grids that can be disconnected from the traditional grid to operate autonomously. Because they are able to operate while the main grid is down, microgrids can strengthen resilience and help prevent grid disturbances. They also function as a reliable resource for faster system response and recovery. Microgrids enable the integration of more distributed energy resources, including renewable energy such as rooftop solar and batteries. Additionally, the use of local energy resources to serve local loads helps reduce energy losses in transmission and distribution, further increasing efficiency of the electric delivery system. Furthermore, microgrids provide vital service during emergencies and after severe storms. When power was knocked out in many parts of Texas during Winter Storm Uri in 2021, many of H.E.B.’s grocery stores were able to keep the lights on, and refrigerators and freezers operating, because they had invested in microgrids. “This may not seem like a big deal, but for the local communities where they may not have access to the basics, like food and water, having that store continue to operate and provide services for customers is huge in order to help them get through those kinds of events,” Paul Froutan, Chief Technology Officer with Enchanted Rock, said as a guest on The POWER Podcast. Enchanted Rock is a company that was founded in 2006. It calls itself “a leader in electrical resiliency-as-a-service, powering companies, critical infrastructure, and communities to ensure operational continuity during unexpected power outages from extreme weather, infrastructure failures, cyberattacks and other grid disruptions.” Enchanted Rock’s dual-purpose microgrids use natural gas and renewable natural gas (RNG) offsets to produce significantly lower carbon emissions and air pollutants than diesel generators. Additionally, the company’s end-to-end microgrid software platform, GraniteEcosystem, provides real-time 24/7/365 system monitoring and optimization, including forecasting of electricity market conditions, to ensure reliable power is delivered to customers. Microgrids can provide value even when there’s not an emergency. “In other situations that may not be as severe, offering the capability to remove loads off the grid essentially creates additional capacity for everyone,” Froutan said. “So, you can look at it in the sense that, if we can get big loads off the grid, that power can go and serve the rest of the users in the community that don’t have that capability.” Among the technology utilized in Enchanted Rock’s microgrids are solar panels, fuel cells, and batteries. But perhaps what adds the most reliability to the system is natural gas–fired generators. “We end up relying on the natural gas generator because they’re one of the few elements available on demand but you can run it indefinitely, effectively, even in situations where there are major events,” said Froutan. Notably, the use of RNG allows a microgrid to remain “green.” Froutan said RNG is “the most interesting thing not talked about” when people discuss a carbon-neutral future. “There is a very good option of renewable natural gas out there that is available today, and depending on the approach, you can actually get a negative carbon index on use of those fuels,” he said. “So, it’s a very appealing option … that is easy, makes sense, and can be implemented right away.”

It seems like industry insiders have been lamenting the aging power workforce for decades. Yet, there is still a large percentage of workers in the current workforce that are retirement eligible—some studies suggest the percentage is as high as 40%. Meanwhile, the energy transition has created a large number of new jobs building and operating solar and wind farms, enhancing infrastructure, and developing and deploying energy efficiency programs. What that means is there are a lot of open positions to be filled throughout the power industry. “Right now, we have active close to 500 postings for positions,” Sheila Rostiac, senior vice president for Human Resources, Chief Human Resources Officer, and Chief Diversity Officer with Public Service Enterprise Group Inc. (PSEG), said as a guest on The POWER Podcast. “Those jobs run the continuum of opportunities at our company from skilled craftworkers, laborers, customer service representatives, engineers, project managers, and certainly IT [information technology] and cyber experts,” she said. PSEG is a diversified energy company headquartered in Newark, New Jersey. Established in 1903, the company’s principal operating subsidiaries are: Public Service Electric and Gas Co. (PSE&G), PSEG Power, and PSEG Long Island. PSE&G is New Jersey’s largest provider of electric and natural gas service—serving 2.3 million electric customers and 1.9 million gas customers. PSEG Power is an energy supply company that integrates the operations of its nuclear generating assets with its fuel supply functions. PSEG Long Island operates the electric transmission and distribution system of the Long Island Power Authority, which includes about 1.1 million customers. PSEG has approximately 12,500 employees. The jobs PSEG has available are open for a number of reasons. “I had a turnover rate on retirements of about 3% last year, and so backfilling those skilled workers is part of our opening and our routine operation,” said Rostiac. “At the same time, on the growth standpoint, you know the industry is going through an incredible transformation, and we—PSEG—are doing significant capital work across the state, upgrading our gas systems, upgrading and fostering resilience in our electric systems, and managing opportunities with our nuclear business. So, some of those jobs are providing new opportunities in growth of our business,” she said. Rostiac suggested interest in job openings has been good. “Our brand is well-known and our reputation as a great place to work really does afford us strong interest,” she said. However, there’s stiff competition for well-qualified candidates. “We are competing with hosts of other companies, both in the state and really across the nation, for some of those top skills that everybody is looking for—particularly in the technology areas of IT and cyber,” she said. PSEG has won a few awards to back up Rostiac’s claim that the company provides a great working environment. Earlier this year, PSEG was named one of America’s “Most JUST Companies,” an annual analysis from nonprofit JUST Capital ranking companies on issues that supposedly matter most to Americans when it comes to corporate leadership. PSEG ranked fourth overall out of 39 national utilities evaluated in the survey. PSEG ranked as the second-highest utility in employee work-life balance. And among all industries evaluated by JUST, PSEG ranked in the top 100 for workforce advancement. “It is an incredibly exciting time to come to work in the energy industry,” said Rostiac. “The range of career opportunities with life-changing wages and the ability to grow and be part of an industry that is essential, empowering the lives of the communities and businesses around, it’s certainly a high-calling purpose and I hope that future generations see themselves as wanting to be a part of that.”

If you’ve been in the power industry workforce for any significant length of time, you may have asked your supervisor at some point “Why am I doing this?” regarding a task that you were assigned, only to have them respond, “We’ve always done it this way.” That’s because the power industry has a reputation for being stuck in its ways of doing things. As long as a process is safe, reliable, and reasonably cost-effective, the feeling is often, “Why change?” But just because something works, doesn’t mean its efficient or the best practice. Sometimes you have to step back and consider, “Is there a better way?” And sometimes you have to spend money to make money. The old English saying goes, “Penny-wise and pound-foolish,” which is intended to keep people from being too careful with small amounts of money, while missing out on large windfalls. Implementing new technology typically requires an initial investment, which in many cases can seem substantial. For power companies, that often means justifying the expense to the purse-string holders. “If we think about the focus on operating expense [OpEx] versus capital, within the U.S. sector at least, looking at leveraging cloud or other SaaS [Software-as-a-Service] solutions that may come across as an unwelcome operating expense can definitely hinder the speed of adoption of some of these newer technologies,” Casey Werth, general manager for the Energy industry with IBM Technology, said as a guest on The POWER Podcast. “We work closely with a lot of our clients on how to address these and build out business cases that can show that even if you have an increase in OpEx, for instance, the downstream reduction of OpEx cost far outweighs the OpEx increase of the solution.” Werth offered an example based on IBM’s Vegetation Management solution, which he helped a transmission and distribution (T&D) customer implement. “Veg management is a massive operating expense on any T&D operator’s budget that can be optimized or improved upon to have a better outcome,” Werth said. IBM’s website touts Vegetation Management as an end-to-end solution that leverages artificial intelligence (AI), satellite images, Light Detection and Ranging (LiDAR), and more to regularly assess and monitor vegetation. It says the solution helps improve work prioritization and decision-making from planning all the way through work inspection and auditing. Werth said IBM has leveraged “advanced technology to better automate the identification of potential areas of risk due to foliage, and then helping better plan and then audit those veg processes to ensure the best outcome for our clients.” Texas-based Pedernales Electric Cooperative is reportedly a satisfied customer. It expects to reduce the number and severity of vegetation-related outages, improve safety and reliability, and cut overall vegetation management costs by having implemented the solution. Among other ways Werth said technology can improve operations is through “process mining.” The goal of process mining is to gain complete process transparency using data from a business’s own software systems, such as ERP (Enterprise Resource Planning) and CRM (Customer Relationship Management) software. Process mining also aims to pinpoint inefficiencies and prioritize automation by impact and expected return on investment to drive continuous process improvements. It does that by triggering corrective actions or generating Robotic Process Automation (RPA) bots. “If we could identify four or five steps of a discrete process that could be either automated or removed, the potential OpEx savings, or just operational efficiency from that process on the other side, has really powerful impacts,” said Werth. “But, if you can’t run the tools to find those wins, then that win sort of stays hidden.”

Cynics might argue that it’s impossible to operate the power grid economically with 100% renewable energy on an hourly basis, but a model developed by Peninsula Clean Energy, a community choice aggregation agency that serves San Mateo County and the City of Los Banos, California, suggests it’s possible. To prove it, Peninsula Clean Energy intends to do it by 2025. “Our default product, which all of our customers receive at this time, is 50% renewable, 100% clean,” Jan Pepper, CEO of Peninsula Clean Energy, said as a guest on The POWER Podcast. “Our goal is to have the power that we deliver by 2025 be 100% renewable, and matched on a time-coincident, hour-by-hour basis.” Under current California regulations, renewable energy percentages are matched on an annual basis. “For example, if we have a 3,700 gigawatt-hour load, for us to be 50% renewable, which we are right now, we procure 1,850 gigawatt-hours per year of renewables and 1,850 gigawatt-hours of additional clean resources, which for us is large hydro, and that meets our needs on an annual basis,” Pepper explained. That basically means there are times when Peninsula Clean Energy is supplying more than 50% renewable power to its customers and times when it’s supplying less, but over the course of the year, everything averages out so the agency hits its 50% renewable energy target. However, by 2025, the agency expects to match its supply with its load every hour of every day. “In order to do that, we’ll be adding a lot of storage,” said Pepper. Peninsula Clean Energy’s modeling tool, which it calls MATCH (which stands for Matching Around-The-Clock Hourly energy), was built, tested, and used over the past two years. The goal was for the agency to determine the optimal 24/7 renewable energy portfolio. Leaders wanted to know how much it would cost, the level of emission reduction benefits that could be achieved, and the impacts it might have on the broader energy system. A team of workers, which included Planning and Analytics Manager Mehdi Shahriari, Power Resources and Compliance Manager Sara Maatta, and Greg Miller from the University of California, Davis, started with an open-source model called the “Switch Power System Planning Model” and modified it significantly to create MATCH. Using the model, the team outlined in a 44-page white paper how matching customer electricity demand with renewable energy supply 99% of the time achieves the ideal balance of being cost-competitive, reducing portfolio risk, and reducing emissions. “We find that a ‘sweet spot’ goal of providing 100% renewable energy on a 99% time-coincident basis results in only a 2% cost increase relative to our baseline, while achieving critical emission reductions and providing other benefits to the grid,” the team wrote in the report’s executive summary. “We were pleasantly surprised,” said Pepper. However, while achieving the last 1% is doable, it’s not quite as practical. “Our model also found there are diminishing returns in trying to match the last 1% of customer demand, with a 10% increase in portfolio cost needed to go from 99% time-coincident to 100% time-coincident,” the report says. “We’re excited about what the future holds and being able to show that we can do this in a cost-effective way, so that we can all have a much more sustainable and clean energy future,” Pepper concluded.

Hydropower projects frequently face resistance from environmental groups for a variety of reasons. One of the more common objections to hydro is the high turbine-induced mortality of fish. However, Natel Energy, an Alameda, California–based hydro turbine developer and independent power producer, has shown that improving hydro turbine designs could be the ultimate answer to the problem. It has developed the Restoration Hydro Turbine (RHT), a compact hydroelectric turbine that couples high performance with safe through-turbine fish passage. “Our thesis was that if we can make it safe for fish to move through hydropower facilities in a straightforward and easy way, then we can support reimagining hydropower overall, in a bit more of a distributed approach, but one where these projects actually also help to maintain passage and river connectivity,” Gia Schneider, co-founder and CEO of Natel Energy, said as a guest on The POWER Podcast. “Core to making that vision possible is a fish-safe turbine.” The RHT is optimized for low head (from 2 meters to 20 meters) and doesn’t require fine fish screens. The design’s thick, slanted blades transport fish away from the leading edge into wide inter-blade regions and downstream to the outlet. The progressive slant of the blades from hub to tip also minimizes the likelihood of severe strike and eliminates the risk of entrapment between moving and stationary parts. Schneider understands the challenges presented by multiple projects in a watershed or river. “If you’re in a watershed where you, say, have 10 projects down a river, then that means you need to be greater than 99% safe through each individual passage—each individual turbine—in order to achieve [an acceptable] population survival dynamic,” Schneider said. “And so, core for us is we want to achieve greater than 99% safe passage. We’ve kind of set that as an overall target. [It] doesn’t need to be quite that strict if you have fewer projects on a river, but it’s a good rule-of-thumb metric to aim for. And, then, we also want to be highly efficient, so up to 94% efficient from a power generation perspective.” The results achieved during intense testing have been phenomenal. In a recently released, peer-reviewed paper, the findings from an eel passage study were documented. “We’ve been able to actually show 100% passage of eel through our turbines, and with some pretty extreme conditions,” Schneider said. “We’re talking eel that are basically as long as the diameter of the turbine that they are going through—so fairly large eel relative to the size of the turbine—and where that turbine is spinning at 600, 700 rpm.” Schneider said it’s really important to get that kind of data, because it helps substantiate the design with real results, showing it’s truly possible to design for high fish passage and high energy production at the same time. Natel has conducted several other studies, some with the Pacific Northwest National Laboratory (PNNL), with similarly impressive results. Earlier this year, a Natel/PNNL test of 186 large rainbow trout—measuring up to 500 millimeters (19.7 inches) in length—found no meaningful difference between the fish passed through Natel’s 1.9-meter-diameter (roughly 6 feet) turbine and a control group, indicating that the RHT allows safe passage of some of the largest fish ever successfully passed through a compact hydro turbine. Earlier tests of smaller rainbow trout passed through Natel’s turbine demonstrated 100% survival.

Economic development can be a challenge for leaders in rural communities. Often, it’s hard to attract businesses to rural areas because the local workforce may not have the skills or numbers to meet companies’ needs. But opportunities that haven’t been widely available in the past exist today for rural communities due to the energy transition that is sweeping the nation. “The potential for rural communities is really enormous,” L. Michelle Moore, CEO of Groundswell (a nonprofit that builds community power by connecting solar and energy efficiency with economic development, affordability, and quality of life) and author of the book Rural Renaissance: Revitalizing America’s Hometowns through Clean Power, said as a guest on The POWER Podcast. For example, Moore explained that nearly $10 billion is available to rural electric cooperative utilities through the U.S. Department of Agriculture (USDA) to build clean energy projects. She also noted how rural communities can benefit from electric vehicle (EV) tax credits, and from credits designed to encourage installation of EV chargers in rural areas. There are also great incentives for energy efficiency improvements, such as for adding insulation to homes or installing more efficient heating and cooling systems. “The opportunities for rural America are really, really myriad,” Moore said. “And, you know what, you can’t offshore construction jobs. So, implementing both energy efficiency [improvements]—whether it’s insulation in the attic or the air conditioning system—those are all activities that are going to keep local people at work.” Moore is a strong supporter of rural electric cooperatives and believes they have a large role to play in economic development in rural communities. “So many people don’t know or have never experienced the tremendous power and potential of rural electric cooperatives,” she said. “The people who buy their electricity from rural electric cooperative utilities actually own the utility, and they also participate directly in its governance. The boards of rural electric cooperative utilities are meant to be democratically elected by co-op members. So, it’s really energy democracy in practice when co-ops are working at their best,” explained Moore. “There are more than 900 of them around the country, and they serve more than half of America’s landmass. And they serve tens of millions of customers as well. So, they really could be the heroes of local clean energy futures.” When asked where rural communities can get the biggest bang for their buck, Moore responded, “As unsexy as it can sound, energy efficiency is a really important place to start, and that is because rural energy burdens are so high. You know, a lot of rural housing just needs repairs, maintenance, and upgrades, much of which can be paid for with energy efficiency over time.” But Moore said there are other ways rural communities can benefit from the energy transition. “The second thing that I would really encourage rural communities to look at is solar and energy storage, which is going to help to increase the resilience of your community,” she said. “Today, those technologies are much more available, and the Inflation Reduction Act has all kinds of grant funding and tax credits and rebates that help to pay for them and help to get them out into communities, including rural towns that may not have the dollars in their pocket today to be able to invest in the technology that they need without some additional support coming in from other places.”

The Duquesne Light Co. (DLC) may not be among the best-known electric power companies in the U.S., but for its customers in Allegheny and Beaver counties in southwestern Pennsylvania, the company has been a steady presence in the community for more than a century. “We are a Pittsburgh-based utility company. We’ve been in operation for over 140 years, serving the Pittsburgh area,” Kevin Walker, CEO of DLC, said as a guest on The POWER Podcast. “We are very entwined with our community, doing a lot of community service and corporate giving. And since we’re a small but mighty utility, we know, live, and work with all of our customers. I see many customers in the supermarket and in the barber shop and those kinds of places. And so, I love to feel that we are really making an impact for the people we know and serve.” Pittsburgh was the site of the Global Clean Energy Action Forum (GCEAF) in late September. Delegates from around the world gathered at the event hosted by the U.S. Department of Energy and Carnegie Mellon University. It was the first time the GCEAF was held in the U.S. The three-day event featured high-level plenary sessions and topical roundtables with energy and science ministers, CEOs, and other experts and leaders (Figure 1). There were also various side events, technology demonstrations, and other activities throughout the week. Walker was a member of the host committee. “We’re still riding the high off of that event. It was so exciting to have people from across the globe, here in Pittsburgh, really, to showcase the evolution and continuing evolution of Pittsburgh,” Walker said. “It was a great knowledge share both ways. We learned things from around the globe, as well as sharing our wisdom with folks around the globe.” Walker said innovation and creativity are in Pittsburgh’s DNA, as is a willingness to collaborate. “I think that’s our secret sauce here as a region—we really collaborate well and there’s a low-to-no barrier to the folks helping each other,” he said. Walker felt the collaborative spirit extended to attendees from across the globe during the event and has continued even after the conference ended. DLC has collaborated with other power companies, too. In late July, for example, the company announced that Commonwealth Edison (ComEd), an Exelon Corporation unit, and Pacific Gas and Electric Co. (PG&E) had joined the first phase of DLC’s public crowdsourcing innovation challenge, called “Monitoring Electrical Cable Challenge: The Future of Underground Inspection.” The challenge was devoted to creating a more reliable and safer underground electric network in the Pittsburgh region. With a total prize of $750,000, the challenge was shared with entrepreneurs, researchers, scientists, students, and more, and it drew submissions from around the world. ComEd and PG&E are collaborating with DLC in two areas: guiding the challenge finalists on solution testing and evaluating the phase-one results. The winning solution is expected to strengthen the underground electrical grid and improve worker and public safety in DLC’s service territory, with the potential for further implementation in ComEd’s and PG&E’s networks. Yet, if you look at DLC’s website, the first thing listed under its “About Us” heading is “Community,” and Walker seems well-focused on that aspect. “We just really have this giving spirit and we want to be an important partner for our community,” he said. Part of that includes charitable giving, while addressing social and economic inequities, workforce development, and sustainable communities also play a role. DLC has also made efforts to improve supplier diversity and work with more local suppliers. “Oftentimes, we have national and even international diverse suppliers. That is good, but it doesn’t put money back into our community. So, we’re happy and proud with the advancements we’ve made there,” Walker said.

Bitcoin mining is the process used to generate new coins and verify new transactions. The process involves vast, decentralized networks of computers around the world that verify and secure blockchains, the virtual ledgers that document cryptocurrency transactions. In return for contributing their computing power, miners are rewarded with new coins. The process ultimately requires a lot of energy to perform, which is where power companies come in. “Bitcoin mining can help the energy sector,” Andrew Webber, founder and CEO of Digital Power Optimization (DPO), said as a guest on The POWER Podcast. “Instead of just selling power to third-party Bitcoin miners, we suggest, that, in many circumstances, energy companies themselves are actually far better positioned to build their own Bitcoin mines and undertake this strategy and this activity for their own purposes in a vertically integrated way, where again, the energy company owns the Bitcoin mine. And by operating a Bitcoin mine, in conjunction with an energy asset, in an intelligent and thoughtful way, you can really optimize your generation assets in a way that you couldn’t really have done without a tool like Bitcoin mining to help you.” Webber said the idea came to him while reading a story in the newspaper. “I was reading [a Los Angeles Times] article about the state of California paying the state of Arizona $20 per megawatt-hour to get rid of all of its power. And I said, ‘What is going on? That seems absolutely crazy to me. I'll take all of it. You know? I'll set up a Bitcoin mine there, and just, any power you don’t want, just send it to me, I’ll take it for free,’ ” he said. Webber explained how Bitcoin mining can help power companies alleviate issues. “This is a mechanism that can go almost anywhere and soak up this excess available power where it’s produced, and then apply that value elsewhere across the globe in a way that actually solves these problems,” said Webber. “So, it’s quite an interesting tool for the energy sector once they get their heads around how this will help.” Bitcoin mining provides flexibility, too. If power is needed suddenly for customers, the power company can respond by simply shutting down the mining operation. “You can just turn it off, and so, it makes a really good tool to respond to sharp jumps in demand or transmission difficulties,” Webber said. “It’s sort of energy management infrastructure. And when you start thinking about an energy company building these things, it’s not really Bitcoin mining, you’re managing your energy assets in a different way, using a different system.” Setting up a Bitcoin mining operation is fairly simple. Webber said a 1-MW system fits in what looks like a standard shipping container—essentially, a 40-foot by 8-1/2-foot big metal box. Inside are racks, wiring, all the networking equipment, a filtration system, cooling fans, and 300 to 325 very specialized computers. The container is connected to a transformer supplied by 240-V or 277-V power, and mining can begin on whatever schedule works best for the power company including 24/7/365. In the end, however, Bitcoin mining is just one tool in a power management toolbox. It can be used in combination with other solutions, including battery storage and green hydrogen production. “All of these are things that need to be incorporated and thought about, not individually, but frankly, in concert with one another,” said Webber. “Right now, I think the energy sector has close to zero understanding that this is available to them, and that’s what we’re hoping to change. And I think it’ll be probably commonplace over the next decade or two.”

Aero-derivative gas turbines are widely used in the power industry. As the name implies, aero-derivative gas turbines evolved from innovations to proven technologies used in airplane jet engines. These gas turbines provide anywhere from 30 MW to 140 MW of efficient, reliable power, and deliver operational savings to energy providers worldwide. According to Harsh Shah, vice president of sales and business development with Mitsubishi Power Aero, there are four key areas where aero-derivative gas turbines are used. “The first is what we would call a traditional peaking application,” he said as a guest on The POWER Podcast. This is important when demand exceeds supply during certain periods of the day. “You basically want an asset that can cover the extra demand,” he said. Another application is what Shah called “reverse peaking.” This is when supply decreases quickly for some reason, such as cloud cover affecting solar output, a rapid decrease in wind generation, or some other supply disruption. “If supply drops below the demand, you can have solution like aero-derivatives to cover that in very, very, very short time,” said Shah. Shah said emergency and fast-track applications also provide regular opportunities for aero-derivatives. These can arise from weather-related events or other unforeseen activities. Sometimes, problems result from inadequate planning, or other political and social motivations that require quick deployment of power systems, which aero-derivatives are ideally suited to accommodate. “Last, but certainly not least, is distributed power and grid independent operations,” Shah said. Things like crypto-mining operations or hydraulic fracturing require significant power, and aero-derivative units can quickly fill the role and offer the mobility to change locations, if situations change. As mentioned, aero-derivatives fill an important role in support of renewables, and that is likely to increase as more renewable energy resources are added to the grid. “Renewables growth and its impact on grid dynamics is, I believe, one of the key challenges that the power sector faces as it aims to decarbonize over the next 20 or 30 years,” Shah said. Power producers worldwide strive to supply reliable power to all customers 100% of the time. That requires dispatchable assets that can provide power as needed, which intermittent renewable resources are not capable of without energy storage or immense overbuild. “On-demand, aero-derivative power, we believe, is an ideal way to bridge this capacity and reliability gap effectively, and more importantly, very affordably,” said Shah. “Such peaker plants would offer, in our view, a clearest path to complementing the rise in renewables while still maintaining grid stability and reliability.” Aero-derivative gas turbines are very effective because of their inherent fast-start and flexible design. “The units are designed for five-minute starts from a complete cold condition,” Shah explained. Mobile units are highway compatible and can provide emergency power in nine days or less upon arrival. With modular designs, quick-disconnect cables, factory assembled modules, and pre-fabricated field piping, aero-derivative gas turbines are designed to minimize setup time and promptly begin generating the precise power needed for almost any situation.

Countries throughout the world have set carbon emission reduction targets in an effort to limit the effects of climate change. Many are striving to achieve net zero in coming decades. Yet, governments also want to maintain, or even improve, living standards for their citizens, which means keeping power affordable and reliable. This poses some potentially conflicting priorities. “I think one of the most important topics we’re dealing with right now is how fast can we decarbonize the power generation and the electricity generation in the societies around us,” Karim Amin, executive board member with Siemens Energy, said as a guest on The POWER Podcast. “But on the other hand side, we also see the importance of security of supply. I mean, the world needs reliable electricity. It’s very important not only for the economic development, but for the very same life that we have.” Amin acknowledged that adding more renewable energy is important. “There is no doubt that we need more and more and faster deployment of renewables,” he said. “Important, of course, is to realize and understand that renewables also have challenges.” Amin suggested energy storage will play a big role in future power systems, as will gas turbines. “We are transiting from, as I said, fossil-based into renewable, but we need to resolve the issue of intermittence and storage,” he said. “There are a few technological solutions that could also help to bring the CO2 footprint of the gas turbines down by almost two-thirds through hydrogen co-firing or through carbon capture technologies. So, there are ways that the world is looking at right now and really implementing to use the gas turbines in the time where the storage capacity in terms of maturity of technology is not yet there.” Coal-fired power plants are a significant source of CO2 emissions worldwide. A couple of years ago, Siemens Energy chose to stop participating in new coal power projects. However, the company still provides service to the existing coal fleet. “Actually, the service helps existing units that are running in any case to be upgraded, and to bring their CO2 level down. So, we actually contribute in this regard,” said Amin. Siemens Energy invests a lot, about €1 billion every year, in research and development (R&D). “A big part of that—more than 20% of that, and it’s increasing year on year—is really going into new technologies that would help accelerate the energy transition,” Amin said. Still, there is a delicate balance that must be maintained, which is to put as much effort as possible into renewables while still finding a way to keep the system “reliable, stable, and affordable.” At the same time, Siemens Energy is putting its money where its mouth is, so to speak. The company has committed to using only electricity supplied by renewable energy resources by 2023. It has also committed to becoming climate neutral in its own operations by 2030, which includes reducing absolute scope 1 and 2 greenhouse gas emissions by 46% by 2030, compared to 2019. Amin said that climate change is “the biggest challenge” that we have right now, and one that must be dealt with. “The problem is sophisticated. It’s not as simple as putting renewables and pulling the plug on gas, for example, because in the end of the day, you need to keep the day to day life running—critical infrastructure running—and renewable does not solve this issue on its own. It’s a solution that needs to happen, taking a number of elements into consideration and working as fast as possible through this transition process,” he said.

Lofty goals have been established in the U.S. for the offshore wind industry. The U.S. Department of Energy, Department of the Interior, and Department of Commerce announced a national goal in March 2021 to deploy 30 GW of offshore wind capacity by 2030. That would mark a significant increase from the 42 MW of offshore wind energy currently operating in the states. Meanwhile, the California Energy Commission (CEC) adopted a report yesterday establishing offshore wind goals. It seeks to develop 2 GW to 5 GW of offshore wind by 2030, and 25 GW by 2045. California has no offshore wind installed today. Other states also have individual goals. The challenges to reaching these goals are many. “From my perspective, looking at where we are now, there are some significant challenges that the U.S. has to face,” Chris Cowland, vice president of Global Offshore Wind with Worley, said as a guest on The POWER Podcast. Cowland, who is based in the UK and has spent the last 22 years working in the offshore sector, said the timeline is a “huge challenge,” noting that adding 30 GW of capacity by 2030 will not be easy. “There’s going to be a lot of pressure on governments to look at different policies—how they can accelerate. There’s going to be pressure on fabrication yards and supply chains, the whole remit of how are we actually going to get things to market much, much quicker,” he said. “So, that’s going to be a significant challenge, particularly just taking, as it stands at the moment, about eight years to get from auction to first power.” The lack of local content poses an obstacle too. Cowland said local content is “absolutely fundamental.” Yet, even as he touted his support for developing local resource markets, Cowland said that local content could adversely affect costs, because developed regions such as the U.S. have difficulty competing against suppliers in Asia and other low-wage areas of the world. While shipping costs are lower for local suppliers, other costs can outweigh the benefits, resulting in competitive advantages for foreign suppliers. “The U.S. needs to think slightly differently on that, in terms of: How are we going to drive local content? How are we going to drive lowest possible cost? And I think the answer there is looking at innovation, digitally enabled platforms, and things like that,” said Cowland. The area that Cowland believes the U.S. has perhaps the greatest potential to exploit revolves around standardization. “If we want to hit the ambitions of our governments, you need to stop reengineering and actually start driving standardization into the sector,” Cowland said. “Once you’ve got that standardization, that really then allows us to start to think about how do you scale-up the infrastructure to really support the development of these wind farms, whether it’s new port facilities—What sort of deep-water access do we need? What are the laydown areas that we need? What sort of O&M [operations and maintenance] hubs do we need? And there’s going to be a lot of supply bases that we’re going to need around us to support these facilities,” said Cowland. “Investment isn’t the obstacle here. It’s actually how do you get the investment into the supply chain as quickly as we need it,” he said.

Community Choice Aggregation (CCA) programs have become quite prominent in communities across California, and have begun to spring up in other states including Illinois, Massachusetts, and Ohio. Through CCA, communities can purchase electricity on behalf of residents and businesses, in place of investor-owned utilities such as Pacific Gas & Electric (PG&E), San Diego Gas & Electric, and Southern California Edison. The California Community Choice Association claims local governments in more than 200 towns, cities, and counties across California have chosen to participate in CCA to “meet climate action goals, provide residents and businesses with more energy options, ensure local transparency and accountability, and drive economic development.” The association says there are currently 24 operational CCA programs in California serving more than 11 million customers, and it expects those numbers to continue growing. One of the places where CCA is providing benefits is in the San Francisco Bay area. East Bay Community Energy (EBCE), a not-for-profit public agency, operates a CCA program for Alameda County and 14 incorporated cities, serving more than 1.7 million residential and commercial customers in the area. EBCE initiated service in June 2018 and expanded to the cities of Pleasanton, Newark, and Tracy in April 2021. As a guest on The POWER Podcast, Nick Chaset, CEO of EBCE, explained some of the benefits his agency provides to customers. “There are three categories of benefits that we really focus on. One is cost savings. So, since we started operations in 2018, we have delivered upwards of $30 million in bill savings to our customers, relative to what the cost of electricity from PG&E would have been, if they had stayed on that service,” he said. “The second is clean energy. So, we have delivered higher levels of renewables over the course of our operations, on average. Since we started operating in 2018, I believe we’re somewhere in that 5–7% more renewable range—and that can be more or less than that average depending on how much renewable energy PG&E ends up actually buying—but on average, it’s been in that 5–7% more renewable.” The third thing Chaset said really differentiates EBCE from not only incumbent utilities, but also from some other community energy agencies is its emphasis and focus on investing in clean energy locally. In September 2021, EBCE commenced commercial operation of the Scott Haggerty Wind Energy Center, a 57-MW facility with 23 wind turbines located in Livermore, California, a community EBCE serves. It expects the wind farm to power more than 47,000 homes in its district. Beyond that, EBCE is doing several other projects to enhance local energy systems. “We are also building virtual power plant projects that integrate just over 1,000 residential solar and storage systems to provide consumers both clean energy and resiliency, and provide us with batteries that we can use to meet our broader customer base’s electricity demand,” Chaset said. “And we’re also investing in programs like electric vehicle charging stations. So, we have two large, fast-charging stations that we’re currently working to build and have plans to build a broader network of fast-charging stations across the 15 communities that we operate in.” Chaset suggested the nation could learn from California’s experience. Specifically, he said policies created in California could be applied at a federal level. “Policy is a critical lever to supporting the clean energy transition,” he said. “I would focus today on federal actions that can have really significant impacts in accelerating not just renewable energy, but really accelerating cost-effective energy. And I say that because today solar power and wind power are the cheapest sources of electricity generation out there. And so, we want more clean and cheap electricity, and we have the opportunity to accelerate that through a handful of actions.”

People around the world are searching for ways to decarbonize, and green hydrogen is a fuel that can help in that effort. Green hydrogen is produced through electrolysis using renewable energy, such as wind and solar power. Although most hydrogen produced today is made from natural gas, often referred to as gray hydrogen, new capacity is being added regularly to increase the amount of green hydrogen available to consumers. “We’re in the process of a major transformation in energy, and I think many people—people like Goldman and Bloomberg—believe that we’re going to be helping reduce the carbon footprint of the world by 20% by using hydrogen,” Andy Marsh, CEO of Plug Power, said as a guest on The POWER Podcast. Although talk of a hydrogen economy may seem to some observers to be a relatively new development, Marsh noted that Plug Power has been in the fuel cell and hydrogen business for a quarter century. “What we’re kind of renowned for is that we created the first market for fuel cells,” Marsh explained. “We ended up putting fuel cells into forklift trucks for people like Walmart or Amazon.” However, the energy transition is the driving force behind recent growth. “All these activities have a lot to do with job creation. Over the past two and a half years, Plug has created over 2,300 jobs. Now, we have 3,000 employees,” said Marsh. “When I sit back and look at it, about 20% of our employees made the transition from the oil and gas fossil fuel industry to a clean energy. And finally, with everything going on in Ukraine, everybody’s beginning to realize that it’s so important for folks in the free world to be able to strive for energy independence. And I think hydrogen—the fact that you can create green hydrogen from green electricity that can be locally sourced—really is unique and can be used in such a wide variety of applications.” Marsh suggested the best use of green hydrogen today is as a substitute for gray hydrogen used in the steel and fertilizer industries. The switch would be a big step toward cleaning up these hard-to-decarbonize sectors. “That’s the biggest opportunity in the near term,” he said. Delivery van applications, such as for Amazon, UPS, FedEx, and others, offer another opportunity for hydrogen. While Marsh admitted there’s going to be a lot of electric vehicles operated as delivery vans, he suggested fuel cells offer a more attractive option in some cases. Referencing a study conducted by DHS, Marsh said when going greater than 150 miles and as van sizes increase, fuel cells make good sense. In early 2021, Plug and Renault launched a joint venture (JV) in France. The partners are targeting a 30% share of the fuel cell–powered light commercial vehicle market in Europe. When it comes to transporting hydrogen, Marsh suggested pipelines are vital. He offered an example to make his point, saying hydrogen could be moved a certain distance through a pipeline for roughly 3¢ to 4¢ per kilogram (kg), whereas, moving it the same distance as liquid hydrogen might cost 20¢/kg and in gaseous form via trucks might cost 80¢/kg. “For this to be cost-effective, pipelines are really important,” he said.

“Wyoming is the energy state,” Scott Quillinan, senior director of research for the School of Energy Resources at the University of Wyoming, said as a guest on The POWER Podcast. “Our mission here at the School of Energy Resources is energy-driven economic development for the state of Wyoming. … We support the energy industry here through academic programs, research programs, and outreach and engagement.” One of the School of Energy Resources’ flagship projects is the Wyoming Integrated Test Center (ITC) located at Basin Electric Power Cooperative’s Dry Fork Station, about seven miles north of Gillette. “They have five small test bays and one large test bay,” Quillinan explained. “There you can test some things like amine capture. You can test membrane capture. You can test things like using carbon dioxide to make cement or to make other products,” he said. Next to the ITC is a project called the Wyoming CarbonSAFE, which stands for Carbon Storage Assurance Facility Enterprise. It is one of 13 original carbon capture, utilization, and storage (CCUS) project sites in the U.S. funded by the Department of Energy with the ultimate goal of ensuring carbon storage complexes will be ready for integrated CCUS system deployment. “Wyoming CarbonSAFE is looking at the commercial feasibility of carbon storage directly below Dry Fork station,” said Quillinan. “This project is looking at storing at least 2 million tons of CO2 per year in a stack storage complex directly below this facility. And that project is run out of our office here at the School of Energy Resources. So, eventually, all said and done, we’ll have the newest, cleanest coal-fired power plant in the United States, a research and development center looking at carbon capture and utilization, and a field laboratory looking at carbon storage. So, it’s really, really neat how it’s all coming together.” The school is also focused on diversifying the state’s coal-based economy. It’s doing that by developing novel and marketable products derived from coal. “We like to take a piece of coal, break it all the way down to its different components, and build it back up into some value-added product,” Quillinan explained. Some examples include agricultural soil amendments, asphalt and paving materials, and roofing and construction materials including coal-based bricks. “Today on campus, we’re currently building a demonstration house completely out of coal-based bricks,” said Quillinan. “Right next door to it, we’re building a demonstration house out of conventional materials so that we can test the performance from one house to the other—things like toxicity, fire performance, sound absorption, heat absorption. So, it’s a really neat program.” In addition to the carbon capture and storage, and carbon engineering product programs, the third pillar of the university’s carbon-based research involves rare earth elements and critical mineral extractions from coal seams. “It turns out the Powder River Basin coal seams have elevated concentrations of rare earth elements, and in some cases, that elevated concentration lies in the two to three feet of overburden directly above or below some of the coal seams,” Quillinan explained. Rare earth elements and critical minerals are used in many electronics components, non-reflective glass, batteries, and renewable energy technologies, among other things. About 90% of rare earth elements and critical minerals used today are mined overseas, many of them in China. With the current state of world affairs, having domestic supplies for these vital materials could be important to national security. “We’re pretty excited about this program and what it can do to bring some of that market back domestically, but to Wyoming specifically,” Quillinan said.